Fortis Inc.
TSX : FTS

Fortis Inc.

February 04, 2010 07:00 ET

Fortis Earns $262 Million in 2009 Delivers Record Earnings for 10th Consecutive Year

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwire - Feb. 4, 2010) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) delivered net earnings applicable to common shares of $262 million in 2009, up $17 million from earnings of $245 million in 2008. Earnings per common share were $1.54 compared to $1.56 in 2008.

"For the 10th consecutive year, Fortis delivered record earnings," says Stan Marshall, President and Chief Executive Officer, Fortis Inc. "The global economic downturn and the busiest regulatory calendar in the history of Fortis made 2009 a challenging year. Strong performance from our regulated utilities in western Canada was tempered by the expiry of the water rights of the Rankine hydroelectric generating facility in Ontario and ongoing regulatory challenges in Belize."

The Rankine water rights expired in April at the end of its 100-year term. Earnings from the Rankine hydroelectric generating facility were $3.5 million in 2009 compared to approximately $16 million in 2008.

Fortis has raised its annual dividend to common shareholders for 37 consecutive years, the longest record of any public corporation in Canada. Dividends paid per common share grew to $1.04 in 2009, up 4 per cent from $1.00 paid per common share in the previous year. In January 2010, Fortis announced an increase in its quarterly common share dividend to 28 cents from 26 cents, commencing with the first quarter dividend payable on March 1, 2010, which translates into an annualized dividend of $1.12.

Fortis utilities continue to make the investments necessary to provide customers with safe, reliable energy at the lowest reasonable cost.

"Our capital program surpassed $1 billion in 2009, making it the largest annual capital program ever undertaken in the Corporation's history," says Marshall. Approximately 75 per cent of the capital investment occurred at the Corporation's regulated utilities in western Canada. Work continued on a number of significant projects including construction of the approximate $200 million liquefied natural gas storage facility at Terasen Gas (Vancouver Island) and the ongoing installation of automated meter technology at FortisAlberta under its multi-year $155 million capital initiative. FortisBC began construction of its $110 million Okanagan Transmission Reinforcement Project, the largest capital initiative ever to be undertaken by that utility.

The US$53 million 19-megawatt hydroelectric generating facility at Vaca in Belize will be commissioned in the first quarter of 2010. No further investment in Belize is planned.

During the fourth quarter of 2009, regulatory decisions were received increasing the allowed rate of return on common equity ("ROE") and/or equity component of total capital structure ("equity component") at the Corporation's four largest utilities. At FortisAlberta, the allowed ROE and equity component increased to 9.0 per cent and 41 per cent, respectively, effective January 1, 2009. At Terasen Gas ("TGI"), the allowed ROE and equity component increased to 9.5 per cent and 40 per cent, respectively, effective July 1, 2009 and January 1, 2010, respectively. TGI also received regulatory approval of a Negotiated Settlement Agreement ("NSA") for its 2010-2011 revenue requirements. A previous agreement had provided for the sharing of earnings above or below the allowed ROE with customers. The recently approved NSA does not include an earnings' sharing mechanism. At FortisBC, the allowed ROE increased to 9.9 per cent, effective January 1, 2010. FortisBC also received regulatory approval of an NSA for its 2010 revenue requirements. Newfoundland Power received regulatory approval for its 2010 revenue requirements and the Company's allowed ROE has been set at 9.0 per cent for 2010.

Earnings for the fourth quarter were $81 million, or $0.48 per common share, compared to $76 million, or $0.48 per common share, for the same quarter in 2008. Fourth quarter results for 2009 reflected the approximate $10 million favourable cumulative retroactive impact associated with the increase in the allowed ROEs for 2009 at FortisAlberta and TGI and the increased equity component at FortisAlberta. Earnings were also favourably impacted by a one-time $3 million corporate tax adjustment at FortisOntario but were unfavourably impacted by increased costs of approximately $5 million after tax associated with the conversion of Whistler customer appliances from propane to natural gas (the "Whistler Pipeline Conversion Project"). Regulatory approval is being sought to include the additional conversion costs in rate base.

The Terasen Gas companies delivered earnings of $117 million compared to $118 million for 2008. Results for 2009 were constrained by the increased costs related to the Whistler Pipeline Conversion Project. Results for 2008 were favourably impacted by an approximate $5.5 million tax reduction related to the settlement of historical corporate tax matters. Excluding these two items, earnings were $9.5 million higher year over year, mainly due to the impact of the higher allowed ROE, effective July 1, 2009, and lower effective corporate taxes.

Earnings at Canadian Regulated Electric Utilities were $149 million, up $23 million from $126 million for 2008. Excluding the favourable one-time corporate tax adjustment at FortisOntario in 2009 and a $2 million one-time charge at FortisOntario associated with the repayment of an interconnection agreement-related refund during 2008, earnings were $18 million higher year over year. Results were driven by the higher allowed ROE and increased equity component at FortisAlberta combined with rate base growth at FortisAlberta and FortisBC.

FortisOntario acquired Great Lakes Power Distribution Inc., subsequently renamed Algoma Power Inc., in October 2009 for an aggregate purchase price of approximately $75 million. Algoma Power Inc. serves approximately 12,000 customers located in the District of Algoma in northern Ontario.

Earnings at Caribbean Regulated Electric Utilities were $27 million compared to $17 million for 2008. Results for 2008 reflected a $13 million reduction in earnings related to a June 2008 regulatory decision at Belize Electricity but included $1.5 million of additional earnings from Caribbean Utilities related to a change in the utility's fiscal year end in 2008. Excluding these two items, earnings were $1.5 million lower year over year. The decrease was mainly due to the impact of a lower allowed rate of return on rate base assets at Belize Electricity for the entire year in 2009 compared to half a year in 2008 and higher operating costs. The decrease was partially offset by the favourable impact of a change in the methodology for calculating the cost of fuel recoverable from customers and a change in depreciation estimates at Fortis Turks and Caicos and the favourable impact of foreign currency translation. Results reflected slower electricity sales growth as a result of the negative impact of the economic downturn on electricity demand. Annualized electricity sales growth was approximately 2 per cent for 2009 compared to 6 per cent for 2008.

Earnings at Non-Regulated Fortis Generation were $16 million compared to $30 million for 2008. The decrease was mainly due to lower contributions from the Rankine hydroelectric generating facility combined with lower average wholesale market energy prices and lower production in Upper New York State.

Earnings at Fortis Properties were $24 million, up $1 million from 2008. Contributions from recently acquired hotels and the Real Estate Division and lower finance charges were partially offset by generally lower occupancies at the remainder of the Company's hotels due to the economic downturn.

Corporate and other expenses were $71 million compared to $69 million for 2008. Excluding a $1 million favourable corporate tax adjustment in 2009 and a $2 million tax reduction associated with the settlement of historical corporate tax matters at Terasen in 2008, corporate and other expenses were $1 million higher year over year. The increase was mainly due to higher preference share dividends related to the issuance of First Preference Shares, Series G during the second quarter of 2008, partially offset by lower operating expenses and finance charges.

In September 2009, Standard & Poor's confirmed its credit rating for Fortis at A- (stable outlook), reflecting the diversity of the Corporation's regulated utility operations, stability and predictability of the utilities' cash flows and the Corporation's focused, well-executed growth strategy.

"Notwithstanding the severe global economic downturn and capital market volatility, Fortis and its utilities have raised approximately $1.3 billion in the capital markets since late 2008, demonstrating the financial strength of our core utility business," says Marshall.

In December 2008, Fortis completed a $300 million common share issue. In 2009, financings included 30-year $200 million 6.51% unsecured debentures at Fortis, 30-year $105 million 6.10% unsecured debentures at FortisBC, 15-year US$40 million 7.50% unsecured notes at Caribbean Utilities, 30-year $65 million 6.606% first mortgage bonds at Newfoundland Power, 30-year $100 million 6.55% unsecured debentures at TGI, and 30-year $100 million 7.06% and 30-year $125 million 5.37% unsecured debentures at FortisAlberta. In January 2010, Fortis issued $250 million five-year fixed rate reset preference shares.

At December 31, 2009, Fortis had consolidated credit facilities of approximately $2.2 billion, of which approximately $1.4 billion was unused, including $476 million unused under the Corporation's $600 million committed revolving credit facility. Approximately $2.0 billion of the total credit facilities are committed facilities, the majority of which having maturities between 2011 and 2013.

"Our 2010 capital program of more than $1 billion is well underway," says Marshall. "Over the next five years, capital expenditures are expected to approach $5 billion, driven by ongoing investment in infrastructure at our regulated utilities in western Canada," says Marshall.

"We will continue to build our business profitably through continued investment in existing operations and strategic acquisitions," concludes Marshall.



FINANCIAL HIGHLIGHTS
For the three and twelve months ended December 31, 2009
Dated February 4, 2010


The following fourth quarter 2009 media release should be read in conjunction with the Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") and audited consolidated financial statements for the year ended December 31, 2008 included in the Corporation's 2008 Annual Report. Financial information in this fourth quarter 2009 media release has been prepared in accordance with Canadian generally accepted accounting principles and is presented in Canadian dollars unless otherwise specified.

Fortis includes forward-looking information in this fourth quarter 2009 media release 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 management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the expected increase in average annual energy production from the Macal River in Belize by the Vaca hydroelectric generating facility and the expected timing of the commissioning of the facility; the expected timing of regulatory decisions; consolidated forecasted gross capital expenditures for 2010 and in total over the five-year period from 2010 through 2014; the nature, timing and amount of certain capital projects; the expected impacts on Fortis of the economic downturn; negligible electricity sales growth is expected at the Corporation's regulated utilities in the Caribbean for 2010; organic revenue growth at Fortis Properties' Hospitality Division is expected to continue to be challenged in 2010; no expected significant decrease in annual consolidated operating cash flows in 2010 as a result of any continuation of the economic downturn; the subsidiaries expect to be able to source the cash required to fund their 2010 capital expenditure programs; the Corporation and its utilities expect to continue to have reasonable access to capital in the near to medium terms; no material increase in consolidated interest expense and/or fees associated with renewed and extended credit facilities is expected in 2010; no material adverse credit rating actions are expected in the near term; the expectation that counterparties to the Terasen Gas companies' gas derivative contracts will continue to meet their obligations; and the expectation of an increase in consolidated defined benefit net pension costs for 2010.
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 operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major event; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no significant decline in capital spending in 2010; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the commodity cost of natural gas and energy supply costs in customer rates; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas commodity prices; no significant variability in interest rates; 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 supply; the continued ability to fund defined benefit pension plans; the absence of significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; no material decrease in market energy sales prices; 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; operating and maintenance risks; economic conditions; capital resources and liquidity risk; weather and seasonality; commodity price risk; derivative financial instruments and hedging; interest rate risk; counterparty risk; competitiveness of natural gas; natural gas supply; defined benefit pension plan performance and funding requirements; risks related to the development of the Terasen Gas (Vancouver Island) Inc. franchise; the Government of British Columbia's Energy Plan; environmental risks; insurance coverage risk; loss of licences and permits; loss of service area; market energy sales prices; changes in current assumptions and expectations associated with the transition to International Financial Reporting Standards; changes in tax legislation; maintenance of information technology infrastructure; an ultimate resolution of the expropriation of the assets of the Exploits River Hydro Partnership that differs from what is currently expected by management; an unexpected outcome of any legal proceedings currently against the Corporation; relations with First Nations; labour relations; and human resources. 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 year ended December 31, 2008 and for the three and nine months ended September 30, 2009, and as otherwise disclosed in this fourth quarter 2009 media release.

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.

COMPANY OVERVIEW AND FINANCIAL HIGHLIGHTS

Fortis is the largest investor-owned distribution utility in Canada, serving approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns non-regulated generation assets across Canada and in Belize and Upper New York State and hotels and commercial real estate in Canada. In 2009, the Corporation's electricity distribution systems met a combined peak electricity demand of 5,983 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,234 terajoules ("TJ"). For additional information on the Corporation's business segments, refer to Note 1 of the Corporation's interim unaudited consolidated financial statements for the three and nine months ended September 30, 2009 and to the Corporation's audited consolidated financial statements for the year ended December 31, 2008 included in the Corporation's 2008 Annual Report.

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 to customers at the lowest reasonable rates, and conduct business in an environmentally responsible manner. The Corporation's core utility business is highly regulated. It is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. Key financial highlights, including earnings by reportable segment, for the fourth quarters and years ended December 31, 2009 and December 31, 2008, are provided in the table below.



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Financial Highlights (Unaudited)
Periods Ended December 31
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Quarter Annual
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($ millions, except
earnings per common
share and common shares
outstanding) 2009 2008 Variance 2009 2008 Variance
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Revenue 1,018 1,181 (163) 3,637 3,903 (266)
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Cash flow from
operating activities 70 208 (138) 637 661 (24)
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Net earnings applicable
to common shares 81 76 5 262 245 17
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Basic earnings per
common share ($) 0.48 0.48 - 1.54 1.56 (0.02)
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Diluted earnings per
common share ($) 0.46 0.46 - 1.51 1.52 (0.01)
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Weighted average number
of common shares
outstanding (millions) 170.9 158.9 12.0 170.2 157.4 12.8
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Segmented Net Earnings
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Quarter Annual
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2009 2008 Variance 2009 2008 Variance
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Regulated Gas Utilities
- Canadian
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Terasen Gas
Companies (1) 48 47 1 117 118 (1)
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Regulated Electric
Utilities - Canadian
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FortisAlberta 15 11 4 60 46 14
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FortisBC (2) 8 7 1 37 34 3
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Newfoundland Power 8 8 - 32 32 -
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Other Canadian (3) 6 3 3 20 14 6
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37 29 8 149 126 23
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Regulated Electric
Utilities - Caribbean (4) 7 8 (1) 27 17 10
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Non-Regulated - Fortis
Generation (5) 3 8 (5) 16 30 (14)
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Non-Regulated - Fortis
Properties (6) 5 4 1 24 23 1
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Corporate and Other (7) (19) (20) 1 (71) (69) (2)
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Net Earnings Applicable
to Common Shares 81 76 5 262 245 17
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(1) Comprised of Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island)
Inc. ("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI")
(2) Includes the regulated operations of FortisBC Inc. and operating,
maintenance and management services related to the Waneta, Brilliant
and Arrow Lakes hydroelectric generating plants and the distribution
system owned by the City of Kelowna. Excludes the non-regulated
generation operations of FortisBC Inc.'s wholly owned partnership,
Walden Power Partnership.
(3) Includes Maritime Electric and FortisOntario. FortisOntario includes
Canadian Niagara Power, Cornwall Electric and, from October 2009,
Algoma Power Inc.
(4) Includes Belize Electricity, in which Fortis holds an approximate 70
per cent controlling interest; Caribbean Utilities on Grand Cayman,
Cayman Islands, in which Fortis holds an approximate 59 per cent
controlling interest, and wholly owned Fortis Turks and Caicos.
Previously, Caribbean Utilities had an April 30th fiscal year end
whereby, up to and including the third quarter of 2008, its financial
statements were consolidated in the financial statements of Fortis on
a two-month lag basis. In 2008, Caribbean Utilities changed its
fiscal year end to December 31st, which has eliminated the previous
two-month lag in consolidating its financial results.
(5) Includes the operations of non-regulated generating assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York
State, with a combined generating capacity of 120 MW, mainly
hydroelectric. Prior to May 1, 2009, the Corporation's financial
results reflected earnings' contribution associated with the
Corporation's 75-MW water-right entitlement on the Niagara River in
Ontario under the Niagara Exchange Agreement related to the Rankine
hydroelectric generating facility. The Niagara Exchange Agreement
expired on April 30, 2009, at the end of its 100-year term.
Additionally, prior to February 12, 2009, the financial results of the
hydroelectric generation operations in central Newfoundland were
consolidated in the financial statements of Fortis. As of February
12, 2009, the Corporation discontinued the consolidation method of
accounting for the generation operations in central Newfoundland due
to the Corporation no longer having control over the generation
operations and cash flows as a result of the expropriation of the
assets of the Exploits River Hydro Partnership ("Exploits
Partnership") by the Government of Newfoundland and Labrador. For a
further discussion of this matter, refer to "Non-Regulated Fortis
Generation - Exploits Partnership" section of this MD&A.
(6) Fortis Properties owns 21 hotels with more than 4,000 rooms in eight
Canadian provinces and approximately 2.8 million square feet of
commercial office and real estate primarily in Atlantic Canada.
(7) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen Inc. ("Terasen") corporate-related activities and the
financial results of Terasen's 30 per cent ownership interest in
CustomerWorks Limited Partnership ("CWLP") and of Terasen's non-
regulated wholly owned subsidiary Terasen Energy Services Inc. ("TES")
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SEGMENTED RESULTS OF OPERATIONS

REGULATED GAS UTILITIES - CANADIAN

Terasen Gas Companies

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Terasen Gas Companies
Financial Highlights (Unaudited)
Periods Ended December 31
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Quarter Annual
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2009 2008 Variance 2009 2008 Variance
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Gas Volumes (TJ) 55,579 66,816 (11,237) 192,428 221,122 (28,694)
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($ millions)
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Revenue 497 606 (109) 1,663 1,902 (239)
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Energy Supply Costs 300 418 (118) 1,022 1,268 (246)
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Operating Expenses 79 71 8 268 253 15
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Amortization 26 24 2 102 97 5
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Finance Charges 30 33 (3) 121 129 (8)
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Corporate Taxes 14 13 1 33 37 (4)
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Earnings 48 47 1 117 118 (1)
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Gas Volumes: Gas volumes at the Terasen Gas companies decreased 11,237 TJ, or 16.8 per cent, quarter over quarter and decreased 28,694 TJ, or 13.0 per cent, year over year. The following is a breakdown of gas volumes by major customer category.



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Terasen Gas Companies
Gas Volumes by Major Customer Category (Unaudited)
Periods Ended December 31
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Quarter Annual
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(TJ) 2009 2008 Variance 2009 2008 Variance
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Core - residential and
commercial 39,275 45,007 (5,732) 120,512 132,867 (12,355)
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Industrial 876 1,597 (721) 4,839 6,337 (1,498)
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Total sales volumes 40,151 46,604 (6,453) 125,351 139,204 (13,853)
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Transportation volumes 15,178 15,930 (752) 57,532 63,572 (6,040)
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Throughput under fixed
revenue contracts 250 4,282 (4,032) 9,545 18,346 (8,801)
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Total volumes 55,579 66,816 (11,237) 192,428 221,122 (28,694)
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The decrease in gas volumes to core customers was mainly due to lower average consumption as a result of warmer temperatures experienced in the cooler months in 2009 compared to in 2008. The decrease in gas volumes for all other customers was mainly due to the negative impact of the economic downturn.

The Terasen Gas companies earn approximately the same margin regardless of whether a customer contracts for the purchase of natural gas or for the transportation of natural gas only.

As a result of the operation of regulator-approved deferral mechanisms, changes in consumption levels and energy supply costs from those forecasted to set gas distribution rates do not materially affect earnings.

During the fourth quarter of 2009, combined net customer additions at the Terasen Gas companies totalled approximately 7,400, bringing the total customer count to approximately 939,600 as at December 31, 2009. During 2009, net customer additions were approximately 8,200 compared to net customer additions of approximately 12,800 during 2008. Continued weakening housing and construction markets, due to slowing economic growth, and growth in multi-family housing, where natural gas use is less prevalent compared to single-family housing, has resulted in lower customer growth year over year.

Revenue: Revenue was $109 million lower quarter over quarter and $239 million lower year over year. The decreases were largely due to the lower commodity cost of natural gas charged to customers and lower consumption, partially offset by higher basic customer delivery rates and the rate revenue accrual related to the cumulative retroactive impact during the fourth quarter of 2009 of an increase, effective July 1, 2009, in the allowed rate of return on common shareholder's equity ("ROE") for the Terasen Gas companies.

The allowed ROE was increased to 9.50 per cent from 8.47 per cent for Terasen Gas Inc. ("TGI") and increased to 10.00 per cent from 9.17 per cent for Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas Whistler Inc. ("TGWI").

Effective January 1, 2009, basic customer delivery rates at TGI increased approximately 6 per cent while basic customer delivery rates at TGVI increased up to 5 per cent based on customer rate class. The basic customer delivery rates, however, reflected the impact of a decrease in the allowed ROE effective for the first half of 2009, to 8.47 per cent from 8.62 per cent for TGI and to 9.17 per cent from 9.32 per cent for TGVI and TGWI.

Earnings: Earnings increased $1 million quarter over quarter, driven by the $6 million after-tax impact of the rate revenue accrual related to the increase in the allowed ROEs, effective July 1, 2009, as discussed above, higher basic customer delivery rates and lower finance charges, partially offset by higher operating expenses and increased amortization costs. Operating expenses were higher driven by increased costs of approximately $6 million ($5 million after tax) associated with the conversion of Whistler customer appliances from propane to natural gas. Amortization costs increased due to continued investment in capital assets.

Excluding a $5.5 million tax reduction during the third quarter of 2008 associated with the settlement of historical corporate tax matters and the $5 million after-tax costs associated with the conversion of customer appliances as discussed above, earnings were approximately $9.5 million higher year over year. The increase was mainly due to the $6 million after-tax impact of the rate revenue accrual related to the increase in the allowed ROEs, effective July 1, 2009, as discussed above, higher basic customer delivery rates, lower finance charges and a lower effective corporate income tax rate, partially offset by higher operating expenses due to increased labour and employee-benefit costs, and increased amortization costs, for the reason described above for the quarter. The decrease in the effective corporate income tax rate was primarily due to higher deductions taken for tax purposes compared to accounting purposes.

As reflected in basic customer delivery rates for 2009, finance charges were lower quarter over quarter and year over year due to decreased borrowing rates and lower borrowings under credit facilities.

In February 2009, TGI issued 30-year $100 million 6.55% unsecured debentures, the net proceeds of which were used to repay credit facility borrowings and repay $60 million of 10.75% unsecured debentures that matured in June 2009.

For an update on material regulatory decisions and applications pertaining to the Terasen Gas companies for the fourth quarter of 2009, refer to "Regulatory Highlights".



REGULATED ELECTRIC UTILITIES - CANADIAN

FortisAlberta

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FortisAlberta
Financial Highlights (Unaudited)
Periods Ended December 31
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Quarter Annual
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2009 2008 Variance 2009 2008 Variance
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Energy Deliveries (GWh) 4,129 4,068 61 15,865 15,722 143
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($ millions)
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Revenue 86 78 8 331 300 31
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Operating Expenses 34 34 - 132 130 2
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Amortization 24 22 2 94 85 9
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Finance Charges 14 12 2 50 42 8
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Corporate Tax Recovery (1) (1) - (5) (3) (2)
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Earnings 15 11 4 60 46 14
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Energy Deliveries: Energy deliveries at FortisAlberta increased 61 gigawatt hours ("GWh"), or 1.5 per cent, quarter over quarter, mainly due to an increase in residential, commercial and farm customers, partially offset by a slight decrease in oilfield customers. Energy deliveries increased 143 GWh, or 0.9 per cent, year over year, mainly due to an increase in residential, commercial, farm and irrigation customers, partially offset by a decrease in oilfield customers. Annual energy deliveries also increased due to the impact of cooler-than-normal temperatures during the first quarter of 2009.

As a significant portion of the Company'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 revenues.

Revenue: Revenue was $8 million higher quarter over quarter and $31 million higher year over year, mainly due to an 8.6 per cent increase in customer distribution rates, effective January 1, 2009, reflecting the impact of ongoing investment in electrical infrastructure, and the impact of load and customer growth. Revenue also increased due to the rate revenue accrual of the approximate $4 million cumulative retroactive impact during the fourth quarter of 2009 of an increase, effective January 1, 2009, in the allowed ROE for 2009 to 9.00 per cent from an interim allowed ROE of 8.51 per cent and the increase in the deemed equity component of the total capital structure to 41 per cent from 37 per cent for 2009.

The increase in distribution rate revenue for the quarter was partially offset by a decrease in net transmission revenue and lower other revenue arising from changes in regulatory deferral balances. FortisAlberta assumes volume risk on actual transmission costs relative to those charged to customers, which are based on forecast volumes and prices.

Earnings: Earnings were $4 million higher quarter over quarter. The impact of the increase in revenue was partially offset by increased amortization costs associated with continued investment in capital assets, and increased finance charges due to higher debt levels in support of the Company's significant capital expenditure program, partially offset by the impact of lower interest rates on credit facility borrowings.

Earnings were $14 million higher year over year. The impact of the increase in revenue and higher corporate tax recoveries was partially offset by higher amortization costs and finance charges, for the reasons described above for the quarter, combined with higher operating expenses. Corporate tax recoveries were higher due to higher future income tax recoveries associated with an increase in regulatory deferrals subject to future income tax recoveries. Operating expenses increased mainly due to higher labour and employee-benefit costs associated with increased salaries and number of employees, partially offset by lower general operating costs.

FortisAlberta issued 30-year $100 million 7.06% unsecured debentures in February 2009 and 30-year $125 million 5.37% unsecured debentures in October 2009, the net proceeds of which were used to repay committed credit facility borrowings and for general corporate purposes.

For an update on material regulatory decisions and applications pertaining to FortisAlberta for the fourth quarter of 2009, refer to "Regulatory Highlights".



FortisBC

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FortisBC
Financial Highlights (Unaudited)
Periods Ended December 31
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Quarter Annual
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2009 2008 Variance 2009 2008 Variance
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Electricity Sales (GWh) 859 842 17 3,157 3,087 70
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($ millions)
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Revenue 69 66 3 253 237 16
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Energy Supply Costs 22 23 (1) 72 68 4
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Operating Expenses 19 18 1 70 67 3
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Amortization 9 9 - 37 34 3
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Finance Charges 9 7 2 32 28 4
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Corporate Taxes 2 2 - 5 6 (1)
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Earnings 8 7 1 37 34 3
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Electricity Sales: Electricity sales at FortisBC increased 17 GWh, or 2.0 per cent, quarter over quarter and increased 70 GWh, or 2.3 per cent, year over year, primarily due to growth in residential, general service and indirect wholesale customers, partially offset by a decrease in the number of industrial customers. Cooler-than-normal temperatures in the first quarter of 2009 also favourably impacted electricity sales for the year.

Revenue: Revenue was $3 million higher quarter over quarter and $16 million higher year over year. The increases were driven by: (i) a 4.6 per cent increase in customer electricity rates, effective January 1, 2009; (ii) a 2.2 per cent increase in customer electricity rates, effective September 1, 2009, as a result of the flow through to customers of increased power purchase costs from BC Hydro; and (iii) electricity sales growth, partially offset by a decrease in other revenue driven by an increase in performance-based rate setting ("PBR") incentive adjustments owing to customers. Customer electricity rates for 2009 reflected the impact of ongoing investment in electrical infrastructure and an allowed ROE of 8.87 per cent compared to 9.02 per cent for 2008.

Earnings: FortisBC's earnings increased $1 million quarter over quarter. The impact of the increase in customer electricity rates and customer growth was partially offset by: (i) increased operating expenses due to higher labour costs and general inflationary cost increases, higher property taxes and water fees; and (ii) higher finance charges reflecting increased debt levels in support of the Company's capital expenditure program.

Earnings were $3 million higher year over year. The impact of the increase in customer electricity rates and customer growth and a lower effective corporate income tax rate was partially offset by: (i) higher energy supply costs associated with increased electricity sales and the impact of higher average prices for purchased power, combined with a higher proportion of purchased power versus energy generated from Company-owned hydroelectric generating plants and the receipt of $0.6 million of insurance proceeds during the second quarter of 2008 associated with a turbine failure in 2006; (ii) higher operating expenses, mainly for the reasons described above for the quarter; (iii) increased amortization costs associated with continued investment in capital assets; and (iv) higher finance charges, due to the reason described above for the quarter, combined with increased credit facility renewal fees, partially offset by lower interest rates on credit facility borrowings.

The decrease in the effective corporate income tax rate was due to higher deductions taken for tax purposes compared to accounting purposes in 2009 compared to 2008, combined with a lower statutory income tax rate.

In June 2009, FortisBC issued 30-year $105 million 6.10% unsecured debentures, under a short-form base shelf prospectus filed in May 2009 for the issuance of up to $300 million in debentures from time to time during the 25-month life of the shelf prospectus. The net proceeds from the debenture offering were used to repay committed credit facility borrowings, for general corporate purposes and help repay $50 million of 6.75% debentures that matured on July 31, 2009.

For an update on material regulatory decisions and applications pertaining to FortisBC for the fourth quarter of 2009, refer to "Regulatory Highlights".



Newfoundland Power

-------------------------------------------------------------------------
-------------------------------------------------------------------------
Newfoundland Power
Financial Highlights (Unaudited)
Periods Ended December 31
-------------------------------------------------------------------------
Quarter Annual
-------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Electricity Sales (GWh) 1,474 1,412 62 5,299 5,208 91
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 146 139 7 527 517 10
-------------------------------------------------------------------------
Energy Supply Costs 99 94 5 346 337 9
-------------------------------------------------------------------------
Operating Expenses 13 12 1 52 50 2
-------------------------------------------------------------------------
Amortization 12 12 - 46 45 1
-------------------------------------------------------------------------
Finance Charges 9 8 1 34 33 1
-------------------------------------------------------------------------
Corporate Taxes 4 4 - 16 19 (3)
-------------------------------------------------------------------------
Non-Controlling Interest 1 1 - 1 1 -
-------------------------------------------------------------------------
Earnings 8 8 - 32 32 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Electricity Sales: Electricity sales at Newfoundland Power increased 62 GWh, or 4.4 per cent, quarter over quarter and increased 91 GWh, or 1.7 per cent, year over year, primarily due to the impact of customer growth and higher average consumption.

Revenue: Revenue increased $7 million quarter over quarter and increased $10 million year over year, driven by increased electricity sales and higher other revenue, partially offset by lower amortization to revenue of certain regulatory liabilities, in accordance with prescribed regulatory orders. The allowed ROE of 8.95 per cent for 2009 remained unchanged from 2008 and, consequently, did not impact customer electricity rates for 2009.

Earnings: Newfoundland Power's earnings were comparable quarter over quarter. Higher electricity sales were offset mainly by: (i) the impact of higher demand charges from Newfoundland and Labrador Hydro ("Newfoundland Hydro"), associated with meeting peak load requirements during the winter season; (ii) higher operating expenses, driven by wage, inflationary and regulatory cost increases and an increase in regulator assessment costs due to the timing of the recognition of these costs in 2008, partially offset by the timing of vegetation management costs; and (iii) higher finance charges reflecting increased debt levels in support of the Company's capital expenditure program, partially offset by the impact of lower interest rates on credit facility borrowings.

Earnings were comparable year over year. Higher electricity sales, an increase in other revenue and a lower effective corporate income tax rate were offset mainly by: (i) the impact of higher demand charges from Newfoundland Hydro for the same reason described above for the quarter; (ii) higher operating expenses, driven by wage, inflationary and regulatory cost increases and an increase in regulator assessment costs, for the same reason described above for the quarter, partially offset by a reduction in insurance costs; (iii) increased amortization costs driven by the impact of continued investment in capital assets; and (iv) higher finance charges for the same reason described above for the quarter.

The decrease in the effective corporate income tax rate was primarily due to higher deductions taken for tax purposes compared to accounting purposes in 2009 compared to 2008 and a lower statutory income tax rate.

In May 2009, Newfoundland Power privately placed 30-year $65 million 6.606% first mortgage sinking fund bonds, the net proceeds of which were used to repay committed credit facility borrowings and for general corporate purposes.

For an update on material regulatory decisions and applications pertaining to Newfoundland Power for the fourth quarter of 2009, refer to "Regulatory Highlights".



Other Canadian Electric Utilities

-------------------------------------------------------------------------
-------------------------------------------------------------------------
Other Canadian Electric Utilities (1)
Financial Highlights (Unaudited)
Periods Ended December 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Quarter Annual
-------------------------------------------------------------------------
2009(2) 2008 Variance 2009(2) 2008 Variance
-------------------------------------------------------------------------
Electricity Sales (GWh) 582 543 39 2,195 2,182 13
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 77 65 12 279 262 17
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Energy Supply Costs 50 44 6 183 177 6
-------------------------------------------------------------------------
Operating Expenses 11 7 4 32 28 4
-------------------------------------------------------------------------
Amortization 5 5 - 19 18 1
-------------------------------------------------------------------------
Finance Charges 6 5 1 19 18 1
-------------------------------------------------------------------------
Corporate Taxes (1) 1 (2) 6 7 (1)
-------------------------------------------------------------------------
Earnings 6 3 3 20 14 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
(2) FortisOntario includes financial results of Algoma Power Inc. from
October 8, 2009


In October 2009, FortisOntario acquired Great Lakes Power Distribution Inc., subsequently renamed Algoma Power Inc. ("Algoma Power"), for an aggregate purchase price of approximately $75 million. Algoma Power is a regulated electric distribution utility serving approximately 12,000 customers in the District of Algoma in northern Ontario.

Electricity Sales: Electricity sales at Other Canadian Electric Utilities increased 39 GWh, or 7.2 per cent, quarter over quarter and increased 13 GWh, or 0.6 per cent, year over year.

Excluding electricity sales at Algoma Power, electricity sales decreased 7 GWh, or 1.3 per cent, quarter over quarter and decreased 33 GWh, or 1.5 per cent, year over year. The decrease quarter over quarter reflected the impact of the temporary shutdown of two commercial potato-processing plants on Prince Edward Island in December 2009 and lower average consumption due to the impact of the economic downturn. The decrease year over year was driven by lower average consumption, mainly due to the impact of the economic downturn and the unfavourable impact on consumption due to more moderate temperatures experienced in Ontario in the second and third quarters of 2009, compared to the same periods in 2008, partially offset by the favourable impact on consumption due to cooler temperatures experienced in Ontario in the first quarter of 2009 compared to the same quarter in 2008.

Revenue: Revenue increased $12 million quarter over quarter, $8 million of which related to Algoma Power. The remaining increase in revenue was driven by the impact of: (i) an average 5.3 per cent increase in customer electricity rates at Maritime Electric, effective April 1, 2009; (ii) a 5.1 per cent, 11.7 per cent and 8.4 per cent increase in customer electricity distribution rates in Fort Erie, Gananoque and Port Colbourne, respectively, effective May 1, 2009; and (iii) the flow through to customers of higher energy supply costs at FortisOntario, partially offset by the impact of lower electricity sales. The higher customer electricity rates at Maritime Electric reflected an increase in the base amount of energy-related costs being expensed and collected from customers and recorded in revenue through the basic rate component of customer billings.

Revenue increased $17 million year over year. Excluding the impact of an approximate $3 million ($2 million after tax) one-time charge at FortisOntario associated with the repayment, during the second quarter of 2008, of a refund received during the fourth quarter of 2007 associated with cross-border transmission interconnection agreements, revenue increased $14 million, $8 million of which related to Algoma Power. The remaining increase in revenue year over year was due to the impact of increases in customer electricity rates at Maritime Electric and FortisOntario, as described above for the quarter, partially offset by the impact of lower electricity sales and the flow through to customers of lower energy supply costs at FortisOntario.

Earnings: Earnings increased $3 million quarter over quarter driven by a one-time favourable adjustment to future income taxes related to prior periods during the fourth quarter of 2009.

Earnings increased $6 million year over year. Excluding the one-time $3 million favourable adjustment to future income taxes during the fourth quarter of 2009 and the $2 million after-tax one-time charge at FortisOntario associated with the repayment, during the second quarter of 2008, of the interconnection agreement-related refund, earnings increased $1 million year over year. The increase reflected lower operating expenses at FortisOntario due to the timing of maintenance expenses and a focus on capital projects. Algoma Power contributed $0.1 million to earnings in 2009.

In June 2009, FortisOntario acquired a 10 per cent interest in Grimsby Power Inc. ("Grimsby Power") for approximately $1 million. Grimsby Power is a regulated electric distribution utility serving approximately 10,000 customers in a service territory in close proximity to FortisOntario's operations in Fort Erie.

For an update on material regulatory decisions and applications pertaining to Maritime Electric and FortisOntario for the fourth quarter of 2009, refer to "Regulatory Highlights".



REGULATED ELECTRIC UTILITIES - CARIBBEAN

-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulated Electric Utilities - Caribbean (1)
Financial Highlights (Unaudited)
Periods Ended December 31
-------------------------------------------------------------------------
Quarter Annual
-------------------------------------------------------------------------
2009 2008(2) Variance 2009 2008(2) Variance
-------------------------------------------------------------------------
Average US:CDN Exchange
Rate (3) 1.06 1.21 (0.15) 1.13 1.08 0.05
-------------------------------------------------------------------------
Electricity Sales (GWh) 290 364 (74) 1,140 1,203 (63)
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 85 159 (74) 339 408 (69)
-------------------------------------------------------------------------
Energy Supply Costs 50 109 (59) 192 273 (4) (81)
-------------------------------------------------------------------------
Operating Expenses 13 20 (7) 54 55 (1)
-------------------------------------------------------------------------
Amortization 8 13 (5) 37 36 1
-------------------------------------------------------------------------
Finance Charges 3 5 (2) 16 16 -
-------------------------------------------------------------------------
Corporate Taxes 1 1 - 2 2 -
-------------------------------------------------------------------------
Non-Controlling Interest 3 3 - 11 9 2
-------------------------------------------------------------------------
Earnings 7 8 (1) 27 17 10
-------------------------------------------------------------------------
(1) Includes Belize Electricity, Caribbean Utilities and Fortis Turks
and Caicos
(2) During 2008, Caribbean Utilities changed its fiscal year end from
April 30th to December 31st resulting in the Corporation consolidating
five months of electricity sales and financial results of Caribbean
Utilities for the fourth quarter of 2008 and 14 months of electricity
sales and financial results of Caribbean Utilities for the year ended
December 31, 2008. Prior to the fourth quarter of 2008, Fortis was
consolidating the financial results of Caribbean Utilities on a two-
month lag basis. During 2009, the financial reporting periods of the
Corporation coincided with the financial reporting periods of
Caribbean Utilities.
(3) The reporting currency of Belize Electricity is the Belizean dollar,
which is pegged to the US dollar at BZ$2.00 equals US$1.00. The
reporting currency of Caribbean Utilities and Fortis Turks and Caicos
is the US dollar.
(4) Energy supply costs during the second quarter of 2008 included an $18
million (BZ$36 million) charge as a result of a regulatory rate
decision by the Public Utilities Commission in Belize in June 2008.
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Electricity Sales: Regulated Electric Utilities - Caribbean electricity sales decreased 74 GWh, or 20.3 per cent, quarter over quarter and decreased 63 GWh, or 5.2 per cent, year over year. Electricity sales and financial results for the segment for the fourth quarter of 2008, however, included electricity sales and financial results of Caribbean Utilities for the five months ended December 31, 2008, and electricity sales and financial results for the segment for the year ended December 31, 2008 included electricity sales and financial results of Caribbean Utilities for the 14 months ended December 31, 2008, due to a change in the utility's fiscal year end in 2008. When comparing electricity sales for the period October through December 2009 to the same three-month period in 2008 and for the period January to December 2009 to the same twelve-month period in 2008 for Caribbean Utilities, electricity sales for the segment increased approximately 10 per cent for the fourth quarter and 2 per cent for the year. The increase for the quarter reflected warmer average temperatures experienced in the region compared to the same quarterly period in 2008. The increase in electricity sales for the quarter and the year also reflected the loss of electricity sales during the third and fourth quarters of 2008 at Fortis Turks and Caicos as a result of Hurricane Ike, including the delayed re-opening for the fall 2008 tourist season of several large hotels on the Turks and Caicos Islands. Hurricane Ike struck the Turks and Caicos Islands in early September 2008. Tempering electricity sales growth quarter over quarter and year over year, however, was the negative impact of the economic downturn on consumption by residential customers and activities in the tourism, oil, construction and related industries.

Excluding the two additional months of contribution from Caribbean Utilities in 2008, annualized electricity sales growth in 2008 was approximately 6 per cent.

Revenue: Revenue decreased $74 million quarter over quarter. Excluding the approximate $12 million unfavourable impact of foreign exchange associated with the translation of foreign currency-denominated revenue, due to the weakening of the US dollar relative to the Canadian dollar quarter over quarter, revenue decreased approximately $62 million. The decrease was mainly due to the flow through to customers of lower energy supply costs at Caribbean Utilities and two additional months of contribution from Caribbean Utilities in 2008, i.e., August and September 2008. Partially offsetting the above factors was the impact of a 2.4 per cent increase in basic customer electricity rates at Caribbean Utilities, effective June 1, 2009, and the approximate 10 per cent increase in electricity sales quarter over quarter.

Revenue decreased $69 million year over year. Excluding the approximate $13 million favourable impact of foreign exchange associated with the translation of foreign currency-denominated revenue, due to the strengthening of the US dollar relative to the Canadian dollar year over year, revenue decreased approximately $82 million. The decrease was driven by the flow through to customers of lower energy supply costs at Caribbean Utilities and Fortis Turks and Caicos and two additional months of contribution from Caribbean Utilities in 2008, i.e., November and December 2007. Partially offsetting the above factors was the impact of: (i) a 2.4 per cent increase in basic customer electricity rates at Caribbean Utilities, effective June 1, 2009; (ii) an increase in the cost of power component of the average customer electricity rate at Belize Electricity, effective July 1, 2008; (iii) $1 million associated with a favourable appeal judgment at Fortis Turks and Caicos related to a customer rate classification matter; and (iv) the approximate 2 per cent increase in annualized electricity sales. Tempering revenue growth was the impact of: (i) a decrease in the value-added delivery component of the average customer electricity rate at Belize Electricity, effective July 1, 2008, due to a decrease in the allowed rate of return on rate base assets ("ROA"); and (ii) a change in the methodology at Belize Electricity for recording customer installation fees and the impact of refunding certain installation fees previously collected. Customer installation fees at Belize Electricity are now recorded as a capital contribution on the balance sheet rather than as revenue on the statement of earnings.

Earnings: Earnings' contribution was $1 million lower quarter over quarter. The decrease was driven by two additional months of contribution from Caribbean Utilities in 2008, i.e., August and September 2008, of $2 million, and approximately $1 million associated with unfavourable foreign currency translation for the fourth quarter of 2009. Excluding the above items, earnings were $2 million higher quarter over quarter, mainly due to a change in depreciation estimates at Fortis Turks and Caicos favourably impacting depreciation expense by approximately $1.5 million during the fourth quarter of 2009, combined with the approximate 10 per cent increase in electricity sales and the 2.4 per cent basic customer electricity rate increase at Caribbean Utilities, partially offset by higher finance charges, excluding foreign exchange impacts.

Earnings' contribution was $10 million higher year over year. Excluding: (i) a $13 million reduction in earnings during the second quarter of 2008, representing the Corporation's approximate 70 per cent share of $18 million of disallowed previously incurred fuel and purchased power costs as a result of the June 2008 regulatory rate decision at Belize Electricity; (ii) two additional months of contribution from Caribbean Utilities in 2008, i.e., November and December 2007, of approximately $1.5 million; and (iii) approximately $1 million associated with favourable foreign currency translation, earnings' contribution decreased $2.5 million year over year. Factors decreasing earnings' contribution included: (i) the lower allowed ROA at Belize Electricity, effective July 1, 2008; (ii) higher operating expenses, excluding foreign exchange impacts, driven by increased employee, legal and regulatory costs and bad debt expense, partially offset by an increase in capitalized general and administrative expenses, as prescribed under Caribbean Utilities' transmission and distribution ("T&D") licence, effective April 2008; and (iii) the favourable impact on energy supply costs in 2008 associated with a change in the fuel cost recovery mechanism at Caribbean Utilities. Included in Caribbean Utilities' T&D licence is a new mechanism for the flow through to customers of the cost of fuel and oil, which eliminates favourable or adverse timing differences in fuel and oil cost recovery for reporting periods subsequent to April 30, 2008. The above factors were partially offset by: (i) the approximate $1.5 million favourable impact of a change in depreciation estimates at Fortis Turks and Caicos; (ii) approximately $1 million associated with a favourable appeal judgment at Fortis Turks and Caicos, as described above; and (iii) the favourable impact on energy supply costs in 2009 due to a change in the methodology for calculating the cost of fuel recoverable from customers at Fortis Turks and Caicos in 2009. Earnings were also favourably impacted by the 2.4 per cent basic customer electricity rate increase at Caribbean Utilities and the approximate 2 per cent increase in annualized electricity sales.

Caribbean Utilities met a record peak of 97.5 MW in August 2009 and Fortis Turks and Caicos met a record peak of 29.6 MW in July 2009. In May 2009, Fortis Turks and Caicos commissioned two diesel-generating units, increasing the Company's generating capacity by 6 MW to 54 MW. Fortis Turks and Caicos has also entered into an agreement with a supplier to purchase two diesel-generating engines with a combined capacity of approximately 18 MW for approximately US$12 million (CDN$13 million) for delivery in mid-2010 and early 2011.

In November 2009, the Comision Federal de Electricidad ("CFE") of Mexico cancelled the guaranteed power supply contract for firm energy with Belize Electricity, citing force majeure reasons. The contract was to mature in December 2010. CFE has stated that its generating capacity has been significantly limited as a result of problems with gas availability, generation equipment and shortfall in hydroelectric production. CFE is proposing to negotiate a new contract to provide up to 50 MW of economic and emergency energy to Belize Electricity. CFE continues to supply Belize Electricity with power when available. There is sufficient in-country generation to meet energy demand in Belize without supply from CFE.

Caribbean Utilities privately placed 15-year US$40 million 7.50% senior unsecured notes, with US$30 million and US$10 million placed in May and July 2009, respectively. The net proceeds of the debt offering were used to repay short-term borrowings and finance capital expenditures.

In July 2009, Fortis acquired, through a wholly owned subsidiary, 768,200 Class A Ordinary Shares of Caribbean Utilities at a price of US$8.00 per share. The shares were acquired by Fortis pursuant to a private agreement which resulted in Fortis increasing its controlling ownership in Caribbean Utilities by 2.7 per cent to approximately 59 per cent held as at December 31, 2009.

For an update on material regulatory decisions and applications pertaining to Belize Electricity and Caribbean Utilities for the fourth quarter of 2009, refer to "Regulatory Highlights".



NON-REGULATED - FORTIS GENERATION


-------------------------------------------------------------------------
-------------------------------------------------------------------------
Non-Regulated - Fortis Generation (1)
Financial Highlights (Unaudited)
Periods Ended December 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Quarter Annual
-------------------------------------------------------------------------
2009(2) 2008 Variance 2009(2) 2008 Variance
-------------------------------------------------------------------------
Energy Sales (GWh) 87 312 (225) 583 1,217 (634)
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 5 20 (15) 39 82 (43)
-------------------------------------------------------------------------
Energy Supply Costs - 1 (1) 2 7 (5)
-------------------------------------------------------------------------
Operating Expenses 3 3 - 11 14 (3)
-------------------------------------------------------------------------
Amortization 1 2 (1) 5 10 (5)
-------------------------------------------------------------------------
Finance Charges (1) 2 (3) 2 8 (6)
-------------------------------------------------------------------------
Corporate Taxes - 3 (3) 3 10 (7)
-------------------------------------------------------------------------
Non-Controlling Interest (1) 1 (2) - 3 (3)
-------------------------------------------------------------------------
Earnings 3 8 (5) 16 30 (14)
-------------------------------------------------------------------------
(1) Includes the operations of non-regulated generation assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York
State
(2) Results reflect contribution from the Rankine hydroelectric
generating facility in Ontario until April 30, 2009. On April 30,
2009, the Rankine power-for-water exchange agreement expired at the
end of its 100-year term.
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Energy Sales: Non-Regulated - Fortis Generation energy sales decreased 225 GWh, or 72.1 per cent, quarter over quarter and decreased 634 GWh, or 52.1 per cent, year over year. As anticipated, 164 GWh and 440 GWh of the total decrease in energy sales for the quarter and the year, respectively, was due to the expiration on April 30, 2009, at the end of its 100-year term, of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility in Ontario. In addition, 46 GWh and 158 GWh of the total decrease in energy sales for the quarter and the year, respectively, related to generation operations in central Newfoundland. Energy sales for 2009 included sales related to central Newfoundland operations for only 11/2 months compared to the entire year in 2008, due to the discontinuance of the consolidation method of accounting for these operations in February 2009, necessitated by the actions of the Government of Newfoundland and Labrador related to its expropriation of the assets of the Exploits Hydro River Partnership ("Exploits Partnership") (See "Non-Regulated Fortis Generation - Exploits Partnership" section of this MD&A). The remaining decrease in total energy sales quarter over quarter and year over year was mainly due to lower production in Belize and Upper New York State. Production levels were primarily a function of rainfall levels, in addition to the impact of maintenance downtime at one unit at the Chalillo hydroelectric generating facility in Belize for about 11/2 months during the third quarter of 2009.

The new Vaca hydroelectric generating facility will be commissioned in the first quarter of 2010. The facility is expected to increase average annual energy production from the Macal River in Belize by approximately 80 GWh to 240 GWh.

Revenue: Revenue was $15 million lower quarter over quarter. The primary factors decreasing revenue were: (i) the loss of revenue subsequent to the expiration of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility, as described above; (ii) the impact of the discontinuance of the consolidation method of accounting for the financial results of the hydroelectric generation operations in central Newfoundland during the first quarter of 2009, as described above; (iii) lower average wholesale market energy prices per megawatt hour ("MWh") in Upper New York State, which were US$40.66 for the fourth quarter of 2009 compared to US$56.86 for the same quarter in 2008 and US$38.40 for 2009 compared to US$71.10 for 2008; (iv) decreased production in Upper New York State and Belize; and (v) the approximate $0.5 million unfavourable impact of foreign currency translation.

Revenue was $43 million lower year over year. The primary factors decreasing revenue were the same as those described in (i) to (iii) above for the quarter combined with decreased production in Upper New York State. Revenue also decreased year over year due to lower average wholesale market energy prices per MWh in Ontario related to revenue earned under the Rankine power-for-water exchange agreement. The average prices were $36.83 for January through April in 2009 compared to $49.70 for the same period in 2008. The above factors were partially offset by the approximate $2 million favourable impact of foreign currency translation.

Earnings: Earnings decreased $5 million quarter over quarter, primarily related to the expiration of the Rankine power-for-water exchange agreement, lower average wholesale market energy prices in Upper New York State, decreased production in Upper New York State and Belize and the approximate $0.5 million unfavorable impact of foreign currency translation. The decrease in earnings was partially offset by higher interest revenue associated with inter-company lending from non-regulated to regulated operations in Ontario, which reduced finance charges.

Earnings decreased $14 million year over year driven by the expiration of the Rankine power-for-water exchange agreement, lower average wholesale market energy prices in Upper New York State and Ontario and the impact of lower production in Upper New York State. The decrease in earnings was partially offset by lower finance charges for the reason described above for the quarter, and the approximate $1 million favourable impact of foreign currency translation. Earnings' contribution associated with the Rankine hydroelectric generating facility were nil for the fourth quarter 2009 and $3.5 million for 2009 compared to approximately $4 million and $16 million for the respective periods in 2008.



NON-REGULATED - FORTIS PROPERTIES

-------------------------------------------------------------------------
-------------------------------------------------------------------------
Non-Regulated - Fortis Properties
Financial Highlights (Unaudited)
Periods Ended December 31
-------------------------------------------------------------------------
Quarter Annual
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Hospitality Revenue 37 36 1 154 144 10
-------------------------------------------------------------------------
Real Estate Revenue 16 16 - 64 63 1
-------------------------------------------------------------------------
Total Revenue 53 52 1 218 207 11
-------------------------------------------------------------------------
Operating Expenses 37 36 1 146 135 11
-------------------------------------------------------------------------
Amortization 4 4 - 16 15 1
-------------------------------------------------------------------------
Finance Charges 5 6 (1) 22 24 (2)
-------------------------------------------------------------------------
Corporate Taxes 2 2 - 10 10 -
-------------------------------------------------------------------------
Earnings 5 4 1 24 23 1
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Revenue: Hospitality revenue was $1 million higher quarter over quarter and $10 million higher year over year, driven by revenue contribution from the Sheraton Hotel Newfoundland, which was acquired in November 2008, and the Holiday Inn Select Windsor, in Ontario, which was acquired in April 2009, partially offset by decreased revenue in all regions related to the remainder of the Company's hotel operations due to the economic downturn.

Revenue per available room ("REVPAR") was $68.87 for the fourth quarter compared to $72.86 for the same quarter in 2008 and $76.55 for the year compared to $80.39 for 2008. The decrease in annual REVPAR was mainly due to lower hotel occupancies in all of the Company's operating regions, the most significant of which were experienced in western Canada and Ontario.

Real Estate revenue was comparable quarter over quarter and $1 million higher year over year. The increase reflected growth in all operating regions. The occupancy rate of the Real Estate Division was 96.2 per cent as at December 31, 2009 compared to 96.8 per cent as at December 31, 2008. The decrease in the occupancy rate was primarily associated with a property in rural Newfoundland.

Earnings: Earnings were $1 million higher quarter over quarter and year over year. Contributions from the Sheraton Hotel Newfoundland and the Holiday Inn Select Windsor combined with increased contribution from the Real Estate Division and lower finance charges were partially offset by the impact of generally lower occupancies at the remainder of the Company's hotel operations. Finance charges decreased mainly due to lower external debt balances resulting from regularly scheduled debt repayments.

Operating expenses were $1 million higher quarter over quarter, driven by the Holiday Inn Select Windsor. Operating expenses were $11 million higher year over year primarily related to the Sheraton Hotel Newfoundland, including non-recurring transitional operating costs incurred during the first quarter of 2009, and the Holiday Inn Select Windsor. The increases quarter over quarter and year over year were partially offset by overall cost reductions realized in the balance of the Hospitality Division and lower operating expenses incurred at the Real Estate Division. The decrease in operating expenses incurred at the Real Estate Division mainly related to the reclassification to amortization costs during 2009 of certain major operating expenses recoverable from tenants, which were previously deferred and amortized to operating expenses.



CORPORATE AND OTHER

-------------------------------------------------------------------------
-------------------------------------------------------------------------
Corporate and Other (1)
Financial Highlights (Unaudited)
Periods Ended December 31
-------------------------------------------------------------------------
Quarter Annual
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Revenue 6 6 - 27 26 1
-------------------------------------------------------------------------
Operating Expenses 5 8 (3) 14 16 (2)
-------------------------------------------------------------------------
Amortization 1 2 (1) 8 8 -
-------------------------------------------------------------------------
Finance Charges (2) 21 20 1 79 80 (1)
-------------------------------------------------------------------------
Corporate Tax Recovery (6) (8) 2 (21) (23) 2
-------------------------------------------------------------------------
Preference Share Dividends 4 4 - 18 14 4
-------------------------------------------------------------------------
Net Corporate and Other
Expenses (19) (20) 1 (71) (69) (2)
-------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses and the net expenses of non-
regulated Terasen corporate-related activities and the financial
results of Terasen's 30 per cent ownership interest in CWLP and of
Terasen's non-regulated wholly owned subsidiary TES
(2) Includes dividends on preference shares classified as long-term
liabilities
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Revenue: Revenue was comparable quarter over quarter and $1 million higher year over year. The increase was driven by higher inter-company interest revenue due to increased inter-company lending, partially offset by lower revenue contributions from CustomerWorks Limited Partnership ("CWLP") due to the impact of a decrease in the number of customer contracts.

Net Corporate and Other Expenses: Net corporate and other expenses were $1 million lower quarter over quarter. An increase in finance charges was more than offset by lower operating expenses due to decreased business development costs at Fortis, partially offset by higher corporate legal and consulting fees and employee-benefit costs at Terasen.

Net corporate and other expenses were $2 million higher year over year. Excluding a $1 million favourable corporate tax adjustment at Fortis during the third quarter of 2009 and a $2 million tax reduction recorded in the third quarter of 2008, associated with the settlement of historical corporate tax matters at Terasen, net corporate and other expenses were $1 million higher year over year. The increase was due to higher preference share dividends, due to the issuance of First Preference Shares, Series G during the second quarter of 2008, and lower earnings' contribution from CWLP, partially offset by decreased operating expenses for the same reasons described above for the quarter, and lower finance charges.

Finance charges increased quarter over quarter due to interest costs associated with the $200 million 6.51% unsecured debentures issued in July 2009, partially offset by lower interest rates charged on credit facility borrowings and the favourable impact of foreign exchange associated with the translation of US dollar-denominated interest expense. Finance charges decreased year over year as a result of lower average credit facility borrowings in 2009 compared to 2008 and lower interest rates charged on those facility borrowings. The decrease was partially offset by interest costs associated with the $200 million 6.51% unsecured debentures and the unfavourable impact of foreign exchange associated with the translation of US dollar-denominated interest expense.

In January 2010, Fortis completed a $250 million five-year fixed rate reset preference share offering, the net proceeds of approximately $242 million were used to repay borrowings under its committed credit facility and to fund an equity injection into TGI to repay borrowings under the utility's credit facilities in support of working capital and capital expenditure requirements.


REGULATORY HIGHLIGHTS

An update on material regulatory decisions and applications for the Corporation's regulated utilities for the fourth quarter of 2009 is as follows:



-------------------------------------------------------------------------
-------------------------------------------------------------------------
Material Regulatory Decisions and Applications
-------------------------------------------------------------------------
Regulated Utility Summary Description
-------------------------------------------------------------------------
TGI/TGVI - Every three months TGI and TGVI review natural gas and
propane commodity rates with the British Columbia
Utilities Commission ("BCUC") in order to ensure the
flow-through rates charged to customers are sufficient
to cover the cost of purchasing natural gas and
propane, while mid-stream rates are reviewed by the
BCUC annually in December. Effective October 1, 2009,
the BCUC approved a decrease in commodity rates for
natural gas for customers in the Lower Mainland,
Fraser Valley and Interior service areas. Effective
January 1, 2010, the BCUC approved an increase in mid-
stream rates for natural gas and kept commodity rates
for natural gas unchanged for customers in the Lower
Mainland, Fraser Valley, Interior, North and the
Kootenay service areas. The BCUC also approved an
increase in commodity rates for propane for customers
in Revelstoke, an increase in commodity rates for
natural gas for customers in Fort Nelson and a
decrease in commodity rates for natural gas for
customers in Whistler, effective January 1, 2010.
- In November and December 2009, the BCUC approved: (i)
Negotiated Settlement Agreements ("NSAs") pertaining
to the 2010 and 2011 Revenue Requirements Applications
for TGI and TGVI; (ii) an increase in the deemed
equity component of TGI's total capital structure,
effective January 1, 2010, to 40 per cent from 35 per
cent; (iii) an increase in TGI's allowed ROE,
effective July 1, 2009, to 9.50 per cent from 8.47 per
cent; and (iii) an increase in the allowed ROE to
10.00 per cent, effective July 1, 2009, from 9.17 per
cent for each of TGVI and TGWI. In its decision on
the Return on Equity and Capital Structure
Application, the BCUC maintained TGI as a benchmark
for calculating the allowed ROE for certain utilities
regulated by the BCUC. The BCUC also determined that
the former automatic adjustment mechanism used to
establish the ROE annually will no longer apply and
the allowed ROEs as determined in the BCUC decision
will apply until reviewed further by the BCUC. The
BCUC-approved NSA for TGI did not include a provision
to allow the continued use of a PBR mechanism after
the expiry, on December 31, 2009, of TGI's previous
PBR agreement. The NSAs assume a mid-year rate base
at TGI of approximately $2,534 million for 2010 and
$2,599 million for 2011, and a mid-year rate base at
TGVI of approximately $554 million for 2010 and $729
million for 2011. The overall impact on customer
rates, including the effect of changes in the
commodity and/or mid-stream rates for natural gas
and/or propane, effective January 1, 2010, was: (i) an
increase of approximately 10 per cent for residential
customers in the Lower Mainland, Fraser Valley,
Interior, North and the Kootneys; (ii) an increase of
approximately 16 per cent for residential customers in
Revelstoke; (iii) a decrease of approximately 12 per
cent for customers in Whistler; and (iv) an increase
of approximately 8 per cent for customers in Fort
Nelson. Customer rates for TGVI's sales customers
will remain unchanged for the two-year period
beginning January 1, 2010, as provided in the BCUC-
approved NSA for TGVI.
- In June 2009, TGI filed an application with the BCUC
requesting the in-sourcing of core elements of its
customer care services and implementation of a new
customer information system. Two new call centres and
the customer information system are expected to be in
place effective January 2012 at a total expected
project cost of approximately $113 million, before
deferral of certain operating and maintenance
expenses.
-------------------------------------------------------------------------
FortisBC - In December 2009, the BCUC approved an NSA pertaining
to FortisBC's 2010 Revenue Requirements Application.
The result was a general customer electricity rate
increase of 6.0 per cent, effective January 1, 2010.
The rate increase was primarily the result of the
Company's ongoing investment in infrastructure,
increasing power supply costs and the higher cost of
capital. FortisBC's allowed ROE has increased to 9.90
per cent, effective January 1, 2010, from 8.87 per
cent in 2009 as a result of the BCUC decision to
increase the allowed ROE of TGI, the benchmark utility
in British Columbia. The BCUC-approved NSA assumes a
mid-year rate base of approximately $975 million for
2010.
-------------------------------------------------------------------------
FortisAlberta - In November 2009, the Alberta Utilities Commission
("AUC") issued its decision on the 2009 Generic Cost of
Capital Proceeding, establishing a generic allowed ROE
for all Alberta utilities it regulates of 9.00 per
cent for each of 2009 and 2010. The allowed ROE of
9.00 per cent is up from 8.61 per cent that the former
ROE automatic adjustment formula would have provided
for FortisAlberta in 2009. The ROE automatic
adjustment mechanism will no longer apply until
reviewed further by the AUC. The AUC also increased
the deemed equity component of FortisAlberta's total
capital structure to 41 per cent from 37 per cent,
effective January 1, 2009. Two hundred basis points
of the increase in the equity component of the capital
structure reflected the effects of FortisAlberta
having become a non-taxable utility for rate-setting
purposes. The AUC also ordered that the generic
allowed ROE for Alberta utilities that it regulates,
including FortisAlberta, be established on an interim
basis for 2011 at 9.00 per cent. The establishment of
an interim ROE level was chosen because the AUC was
not prepared to re-impose an adjustment formula
without the opportunity to assess changes in the
capital markets and to reconsider the types of factors
that should be built into a formula.
- In June 2009, FortisAlberta filed a comprehensive two-
year Distribution Revenue Requirements Application for
2010 and 2011. The application forecasts a mid-year
rate base of approximately $1,538 million for 2010 and
$1,724 million for 2011. The expected impact on the
distribution component of customer rates is an average
increase of 13.3 per cent for 2010 and 14.9 per cent
for 2011, before considering the impact of the
increase in the allowed ROE and the deemed equity
component of the total capital structure, as per the
AUC Generic Cost of Capital Decision. The incremental
effect of the final approved 2009 ROE and capital
structure is expected to be collected in customer
electricity rates in 2010. New customer electricity
rates to be established for 2010 will reflect an
allowed ROE of 9.00 per cent on a deemed equity level
of 41 per cent. FortisAlberta anticipates a
regulatory decision by the AUC to be received in
spring 2010 with final customer electricity rates
anticipated to take effect in late 2010 or early 2011.
An interim approval of customer electricity rates by
the AUC has resulted in an overall 7.5 per cent
average increase in base customer electricity
distribution rates at FortisAlberta, effective January
1, 2010.
-------------------------------------------------------------------------
Newfoundland - In December 2009, the Newfoundland and Labrador Board
Power of Commissioners of Public Utilities ("PUB") issued a
decision on Newfoundland Power's 2010 General Rate
Application resulting in an overall average increase
in basic customer electricity rates of approximately
3.5 per cent, effective January 1, 2010, including the
impact of an increase in the allowed ROE to 9.00 per
cent from 8.95 per cent in 2009, as set by the PUB for
2010. The PUB decision assumes a mid-year rate base
of approximately $869 million for 2010. The PUB also
ordered that Newfoundland Power's allowed ROE for each
of 2011 and 2012 be determined using the ROE automatic
adjustment formula. The ROE automatic adjustment
formula is subject to a review in the first quarter of
2010.
- In November 2009, the Company's 2010 Capital Budget
Application totalling approximately $65 million was
approved by the PUB.
-------------------------------------------------------------------------
Maritime Electric - In January 2010, Maritime Electric filed an
application with the Island Regulatory and Appeals
Commission: (i) providing a report on the impact of
the rebasing of the Energy Cost Adjustment Mechanism
("ECAM") deferral account in 2009 and requesting the
rebasing of the ECAM from 7.7 cents per kilowatt hour
("kWh") to 9.4 cents per kWh, effective April 1, 2010,
and from 9.4 cents per kWh to 9.6 cents per kWh,
effective April 1, 2011; (ii) requesting that the
replacement energy costs incurred during the
refurbishment of the New Brunswick Power Point Lepreau
Nuclear Generating Station ("Point Lepreau") be
amortized over a period of 25 years, representing the
extended life of the unit; and (iii) requesting an
allowed ROE of 9.75 per cent for both 2010 and 2011,
unchanged from 2009.
- In October 2009, Maritime Electric received regulatory
approval, as filed, of its 2010 Capital Budget
totalling $22 million, before customer contributions.
- In October 2009, Maritime Electric received regulatory
approval of the extension of its energy purchase
agreement with New Brunswick Power to December 31,
2010. The agreement, originally entered into in April
2008, was set to expire in September 2009 when Point
Lepreau was to return to service. Delays in the
refurbishment and resulting return to service date of
Point Lepreau required an extension of the energy
purchase agreement.
-------------------------------------------------------------------------
FortisOntario - FortisOntario expects to file a new electricity rate
application for Algoma Power during the first quarter
of 2010 for rates effective July 1, 2010, using 2010
as a forward test year and an allowed ROE of 9.75 per
cent.
- In September and October 2009, the Ontario Energy
Board ("OEB") held a stakeholder conference to
determine whether current economic and financial
market conditions warranted an adjustment to any cost
of capital. In December 2009, the OEB issued its
Report of the Board on the Cost of Capital for
Ontario's Regulated Utilities. Based on current
economic indicators, the preliminary allowed ROE has
been set at 9.75 per cent for utilities in Ontario
regulated by the OEB. The ROE formula has been
refined to reduce sensitivity to changes in long-term
Canada bond yields and includes an additional factor
for utility bond spreads. The updated allowed ROE
will come into effect for the setting of customer
rates beginning in 2010 by way of a cost-of-service
application.
- In October and November 2009, FortisOntario filed
Third-Generation Incentive Rate Mechanism ("IRM")
electricity distribution rate applications for
harmonized rates for Fort Erie and Gananoque and rates
for Port Colborne, effective May 1, 2010, based on a
deemed capital structure containing 40 per cent
equity. In non-rebasing years, customer electricity
rates are set using inflationary factors less an
efficiency target under the OEB's Third-Generation
IRM.
- In October 2009, the OEB issued its Rate Order for
Port Colborne, approving final electricity rate
increases using 2009 as a forward test year, effective
May 1, 2009, of 8.4 per cent, with impact on customer
billings commencing November 1, 2009. The Rate Order
confirmed a deemed capital structure containing 43.3
per cent equity and approved an allowed ROE of 8.01
per cent for 2009.
-------------------------------------------------------------------------
Belize - Changes made in electricity legislation by the
Electricity Government of Belize and the Public Utilities
Commission in Belize ("PUC"), and the PUC's June 2008
Final Decision and the PUC's February 2009 amendment
of the June 2008 Final Decision (the "Amendment"),
which were based on the changed legislation, have been
judicially challenged by Belize Electricity in several
proceedings. The judicial process is ongoing with
interim rulings, judgments and appeals. The timing or
likely final outcome of the proceedings is
indeterminable at this time. The Supreme Court of
Belize issued an injunction against the Amendment
until Belize Electricity's appeal of the June 2008
Final Decision has been heard in court. The court
appeal of the June 2008 Final Decision was called in
early October 2009 but, after considering some
preliminary matters, the trial judge postponed the
case for a date to be determined. In addition, Belize
Electricity's appeal of the Supreme Court of Belize's
previous decision to uphold certain changes made in
electricity legislation by the Government of Belize
and the PUC was dismissed in June 2009.
- In June 2009, the Government of Belize issued a
statutory instrument purporting to declare providers
of electricity generation and water services,
including Belize Electric Company Limited, as public
utility providers within the meaning of the Public
Utilities Commission Act as of May 1, 2009. Fortis
continues to assess the statutory instrument and its
impact on previously negotiated and PUC-approved power
purchase agreements.
-------------------------------------------------------------------------
Caribbean - In October 2009, Caribbean Utilities submitted a Five-
Utilities Year Capital Plan totalling US$157 million for the
period 2010 through 2014 to the Electricity Regulatory
Authority ("ERA").
- In April 2009, Caribbean Utilities submitted its bid
to install 16 MW of generation in May 2012 and another
16 MW of generation in May 2013. There was one other
bidder for the 32 MW of generation. In September
2009, based on economic conditions and revised medium-
term future load growth projections by Caribbean
Utilities, the ERA cancelled its 32 MW capacity-
expansion solicitation. Caribbean Utilities and the
ERA will continue to monitor growth indicators and
revise forecasts as necessary. A new solicitation may
occur at such time there are indicators of a future
need for additional capacity. Caribbean Utilities'
capital investment plan for 2010 through 2014 reflects
the Company's lower growth projections and delay of
the 32 MW of new generating capacity.
-------------------------------------------------------------------------
-------------------------------------------------------------------------


CAPITAL STRUCTURE

The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow the utilities to fund the maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level in support of infrastructure investment to ensure regulatory transparency, tax efficiency and financing flexibility. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40 per cent equity, including preference shares, and 60 per cent 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 the utilities' customer rates.

The consolidated capital structure of Fortis as at December 31, 2009 compared to December 31, 2008 is presented in the following table.



-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Capital Structure (Unaudited)
As at December 31
-------------------------------------------------------------------------
2009 2008
-------------------------------------------------------------------------
($ millions) (%) ($ millions) (%)
-------------------------------------------------------------------------
Total debt and
capital lease
obligations (net
of cash) (1) 5,830 60.2 5,468 59.5
-------------------------------------------------------------------------
Preference shares (2) 667 6.9 667 7.3
-------------------------------------------------------------------------
Common shareholders'
equity 3,193 32.9 3,046 33.2
-------------------------------------------------------------------------
Total 9,690 100.0 9,181 100.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities
and equity


The slight change in the capital structure was driven by higher debt levels primarily in support of infrastructure investment and increased accumulated other comprehensive loss driven by unfavourable foreign exchange, partially offset by net earnings applicable to common shares, net of common share dividends, of $129 million and increased common shares outstanding reflecting the impact of the Corporation's enhanced Dividend Reinvestment and Share Purchase Plan.



The Corporation's credit ratings are as follows:

Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt
credit rating)
DBRS BBB(high) (unsecured debt credit rating)


In September 2009, S&P confirmed its credit rating for Fortis at A- (stable outlook). The credit ratings of Fortis reflect the diversity of the operations of Fortis, 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 and the continued focus of Fortis on pursuing the acquisition of stable regulated utilities.

CASH FLOW

The table below outlines the Corporation's 2009 fourth quarter and annual sources and uses of cash compared to the same periods in 2008.



-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Summary of Cash Flows (Unaudited)
Periods Ended December 31
-------------------------------------------------------------------------
Quarter Annual
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Cash, beginning of period 106 68 38 66 58 8
-------------------------------------------------------------------------
Cash provided by (used in)
-------------------------------------------------------------------------
Operating activities 70 208 (138) 637 661 (24)
-------------------------------------------------------------------------
Investing activities (312) (272) (40) (1,052) (852) (200)
-------------------------------------------------------------------------
Financing activities 222 59 163 438 196 242
-------------------------------------------------------------------------
Foreign currency impact
on cash balances (1) 3 (4) (4) 3 (7)
-------------------------------------------------------------------------
Cash, end of period 85 66 19 85 66 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Cash flow provided by operating activities, after working capital adjustments, decreased $138 million quarter over quarter. The decrease was mainly due to unfavourable working capital changes at the Terasen Gas companies reflecting differences in the commodity cost of natural gas and cost of natural gas charged to customers period over period, and the timing of the declaration of common share dividends. Annual cash flow provided by operating activities, after working capital adjustments, was $24 million lower than the previous year, due to the same reasons described above for the quarter, combined with the timing and an increase in the amount of corporate income taxes paid at Newfoundland Power, partially offset by favourable changes in the Alberta Electric System Operator ("AESO") charges deferral account at FortisAlberta.

Cash used in investing activities increased $40 million quarter over quarter, reflecting the acquisition of Algoma Power during the fourth quarter of 2009 for approximately $70 million, net of cash acquired, compared to the acquisition of the Sheraton Hotel Newfoundland during the fourth quarter of 2008 for approximately $22 million and lower contributions in aid of construction, partially offset by lower capital spending driven by the utilities in the Caribbean. Annual cash used in investing activities was $200 million higher than the previous year. Investing activities in 2009, however, reflected the acquisition of Algoma Power for approximately $70 million, net of cash acquired, the Holiday Inn Select Windsor for approximately $7 million and an additional 2.7 per cent ownership interest in Caribbean Utilities for approximately $7 million. Investing activities in 2008 reflected the acquisition of the Sheraton Hotel Newfoundland for approximately $22 million. Excluding the impact of business acquisitions in 2009 and 2008, annual cash used in investing activities increased year over year due to higher capital spending driven by FortisAlberta and the Terasen Gas companies, and lower contributions in aid of construction.

Cash provided by financing activities was $163 million higher quarter over quarter, primarily due to a net increase in debt during the fourth quarter of 2009 compared to a net decrease in debt during the fourth quarter of 2008, partially offset by lower proceeds from common share offerings. During the fourth quarter of 2008, Fortis issued $300 million in common shares. Annual cash provided by financing activities increased $242 million year over year. The increase was mainly due to a net increase in debt during 2009 compared to a net decrease in debt during 2008, partially offset by lower proceeds from common and preference share offerings. In addition to the $300 million common equity offering in 2008, the Corporation issued $230 million preference shares during the second quarter of 2008.

CAPITAL PROGRAM

The Corporation's principal businesses of regulated gas and electricity distribution are capital intensive. 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.

Gross consolidated capital expenditures for the year ended December 31, 2009 were over $1 billion. A breakdown of gross capital expenditures by segment for 2009 is provided in the following table.



--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross Capital Expenditures (Unaudited) (1)
Year Ended December 31, 2009
($ millions)
--------------------------------------------------------------------------
Other Total
Regula- Regu- Regu-
Tera- ted lated lated Non-
sen New- Utili- Utili- Utili- Regula-
Gas Fortis found- ties- ties- ties- ted- Fortis
Compa- Alberta Fortis- land Cana- Cana- Carib- Utility Proper-
nies (2) BC Power dian dian bean (3) ties Total
--------------------------------------------------------------------------
246 407 115 74 46 888 92 18 26 1,024
--------------------------------------------------------------------------
(1) Relates to utility capital assets, income producing properties and
intangible assets and includes expenditures associated with assets
under construction. Includes asset removal and site restoration
expenditures, net of salvage proceeds, for those utilities where such
expenditures are permissible in rate base in 2009. Excludes
capitalized non-cash equity component of the Allowance for Funds Used
During Construction ("AFUDC").
(2) Includes payments made to AESO for investment in transmission capital
projects
(3) Includes non-regulated utility and Corporate capital expenditures
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Actual gross consolidated capital expenditures for 2009 were comparable to those forecasted and disclosed in the MD&A for the year ended December 31, 2008. Planned capital expenditures are based on detailed forecasts of energy demand, weather and cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts. An increase in capital spending at FortisAlberta associated with higher than anticipated customer driven capital expenditures, including new customer connections, and the inclusion of AESO transmission capital expenditures in total capital expenditures was offset mainly by: (i) a shift from 2009 to 2010 of some capital spending related to the Vaca hydroelectric generating project and certain projects at the Terasen Gas companies and FortisBC; (ii) lower-than-forecasted capital spending at non-regulated TES; and (iii) lower spending at FortisBC associated with the Okanagan Transmission Reinforcement Project, as discussed below.

An update on significant capital projects for 2009 from December 31, 2008 is provided below.

FortisAlberta continued the replacement of conventional customer meters with new Automated Meter Infrastructure ("AMI") technology during 2009. In response to the direction of the Alberta Department of Energy on AMI capabilities, FortisAlberta has adjusted the scope of its planned AMI program, which is now expected to cost approximately $155 million, up from $124 million as disclosed in the MD&A for the year ended December 31, 2008. Additional capital costs may be incurred under this project, pending clarification of meter data reporting requirements by the appropriate government agencies. The final project cost is subject to regulatory approval.

TGVI's construction of the 50-kilometer Squamish-to-Whistler natural gas pipeline lateral was completed during spring 2009 with conversion of Whistler customer appliances completed in August 2009. The total project cost of the pipeline construction and conversion of the appliances is estimated at approximately $56 million, $8 million above the amount previously approved by the BCUC for this project. A provision for approximately $5 million after-tax related to the additional costs associated with the conversion of the appliances has been expensed to earnings in the fourth quarter of 2009. Applications, however, have been filed with the BCUC requesting inclusion in rate base of the total additional costs. The pipeline lateral and appliance conversion were required as part of the overall conversion of TGWI's propane distribution system to a natural gas distribution system.

The Fraser River South Bank South Arm Rehabilitation Project was approved by the BCUC in March 2009 and involves the installation and replacement of underwater transmission pipeline crossings that are at potential risk of failure from a major seismic event. The project is estimated to cost approximately $27 million and is expected to be in service in 2010.

In June 2009, TGI filed an application with the BCUC requesting the in-sourcing of core elements of its customer care services and for implementation of a new customer information system. Two new call centres and the customer information system are expected to be in place effective January 2012 at an expected project cost of approximately $113 million, before deferral of certain operating and maintenance expenses. The revised project cost compares to $145 million originally estimated and disclosed in the second quarter of 2009.

FortisBC began construction on the approximate $110 million Okanagan Transmission Reinforcement Project in July 2009, with completion expected in 2011. The total forecast cost of the project is down from the original estimate of $141 million as disclosed in the MD&A for the year ended December 31, 2008. The decrease in cost is mainly due to lower forecasted labour, equipment and commodity costs. The project relates to upgrading the existing overhead transmission lines from 161 kilovolts ("kV") to 230 kV between Penticton and Oliver and building a new 230-kV terminal in the Oliver area.

In 2009, Caribbean Utilities commissioned a 16-MW diesel generating unit for a total cost of approximately $35 million.

The US$53 million Vaca hydroelectric generating facility will be commissioned in the first quarter of 2010. The facility is expected to increase average annual energy production from the Macal River in Belize by approximately 80 GWh to 240 GWh.

Over the five-year period 2010 through 2014, consolidated gross capital expenditures are expected to approach $5 billion. Approximately 70 per cent of the capital spending is expected to be incurred at the Regulated Electric Utilities, driven by FortisAlberta and FortisBC. Approximately 27 per cent is expected to be incurred at the Regulated Gas Utilities and the remaining 3 per cent is expected to relate to non-regulated activities. Capital expenditures at the Regulated Utilities are subject to regulatory approval.

A breakdown of forecast gross capital expenditures by segment for 2010 is provided in the following table.



--------------------------------------------------------------------------
--------------------------------------------------------------------------
Forecast Gross Capital Expenditures (Unaudited) (1)
Year Ending December 31, 2010
($ millions)
--------------------------------------------------------------------------
Other Total
Regula- Regu- Regu-
Tera- ted lated lated Non-
sen New- Utili- Utili- Utili- Regula-
Gas Fortis found- ties- ties- ties- ted- Fortis
Compa- Alberta Fortis- land Cana- Cana- Carib- Utility Proper-
nies (2) BC Power dian dian bean (3) ties Total
--------------------------------------------------------------------------
327 363 168 69 47 974 82 16 26 1,098
--------------------------------------------------------------------------
(1) Relates to utility capital assets, income producing properties and
intangible assets and includes forecast expenditures associated with
assets under construction. Includes forecast asset removal and site
restoration expenditures, net of salvage proceeds, for those utilities
where such expenditures are permissible in rate base. Excludes
forecast capitalized non-cash equity component of AFUDC.
(2) Includes forecast payments to be made to AESO for investment in
transmission capital projects
(3) Includes forecast non-regulated utility and Corporate capital
expenditures
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Significant capital projects for 2010 include the continuation of the construction of the liquefied natural gas storage facility at TGVI; commencement of the customer care enhancement project at TGI, subject to regulatory approval; the continuation of the Okanagan Transmission Reinforcement project, transmission projects and generation asset upgrades at FortisBC; the continued implementation of AMI technology at FortisAlberta; and the completion of the Fraser River South Arm Rehabilitation project.

CREDIT FACILITIES

As at December 31, 2009, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.2 billion, of which approximately $1.4 billion was unused. The credit facilities are syndicated almost entirely with the seven largest Canadian banks, with no one bank holding more than 25 per cent of these facilities. Approximately $2.0 billion of the total credit facilities are committed facilities, the majority of which have maturities between 2011 and 2013.


The following summary outlines the credit facilities of the Corporation and its subsidiaries.



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--------------------------------------------------------------------------
Fortis Inc.
Credit Facilities (Unaudited)
--------------------------------------------------------------------------
Total as at Total as at
Corporate Regulated Fortis December December
($ millions) and Other Utilities Properties 31, 2009 31, 2008
--------------------------------------------------------------------------
Total credit
facilities 645 1,495 13 2,153 2,228
--------------------------------------------------------------------------
Credit facilities
utilized:
--------------------------------------------------------------------------
Short-term borrowings - (409) (6) (415) (410)
--------------------------------------------------------------------------
Long-term debt
(including current
portion) (125) (83) - (208) (224)
--------------------------------------------------------------------------
Letters of credit
outstanding (1) (98) (1) (100) (104)
--------------------------------------------------------------------------
Credit facilities
available 519 905 6 1,430 1,490
--------------------------------------------------------------------------
--------------------------------------------------------------------------


FortisBC expects to have its $100 million 364-day committed revolving credit facility, due to mature in May 2010, extended for a further 364 days.

Maritime Electric expects to have its $50 million 364-day committed revolving credit facility, due to mature in March 2010, extended for a further 364 days.

NON-REGULATED FORTIS GENERATION - EXPLOITS PARTNERSHIP

The Exploits Partnership is owned 51 per cent by Fortis Properties and 49 per cent by AbitibiBowater Inc. ("Abitibi"). The Exploits Partnership operated two non-regulated hydroelectric generation plants 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, a Crown corporation, as an agent for the Government of Newfoundland and Labrador with respect to expropriation matters. The loss of control over cash flows and operations has 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.

IMPACT OF THE ECONOMIC DOWNTURN

Capital Expenditures: Gross consolidated capital expenditures are expected to be approximately $1.1 billion for 2010, comparable to 2009, and approach $5 billion over the next five years. Planned capital expenditures are based on detailed forecasts of energy demand, weather and cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts. Significantly reduced energy demand in the Corporation's service territories, as a result of a severe and prolonged downturn in economic conditions, could reduce capital spending which would, in turn, impact rate base and earnings' growth.

Cash Flows: The Corporation does not expect any significant decrease in consolidated annual operating cash flows for 2010 as a result of any continuation of the economic downturn. The subsidiaries expect to be able to source the cash required to fund their 2010 capital expenditure programs.

Cost of and Access to Capital: Despite volatility in the global capital markets, the Corporation and its subsidiaries have been successful at raising long-term capital at reasonable rates. However, continued volatility in the global capital markets may increase the cost of, and affect the timing of, issuance of long-term capital by the Corporation and its utilities. While the cost of borrowing may increase, the Corporation and its utilities expect to continue to have reasonable access to capital in the near to medium terms. The cost of renewed and extended credit facilities may also increase going forward; however, any increased interest expense and/or fees are not expected to materially impact the Corporation's consolidated financial results in 2010, as the majority of the total committed credit facilities have maturities between 2011 and 2013. Due to the regulated nature of the Corporation's utilities, increased borrowing costs are eligible to be recovered in future customer rates.

Regulated Allowed Returns: The ROE adjustment mechanisms tied to long-term Canada bond yields used in recent years at the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power have resulted in lower allowed ROEs. Regulatory decisions received in the fourth quarter of 2009 have reduced the risk of further decreases in allowed ROEs. In December 2009, the BCUC issued a decision increasing the allowed ROE at TGI and FortisBC to 9.50 per cent and 9.90 per cent, respectively. The BCUC also determined that the previous ROE automatic adjustment mechanism will no longer apply and that the allowed ROE, as determined in the BCUC decision, will apply until reviewed further by the BCUC. In November 2009, the AUC issued its decision on the 2009 Generic Cost of Capital Proceeding. The decision increased the allowed ROE of utilities in Alberta that it regulates, including FortisAlberta, to 9.00 per cent and discontinued the use of the ROE automatic adjustment formula until reviewed further by the AUC. In December 2009, the OEB issued a report reviewing cost of capital for utilities in Ontario. The OEB increased the allowed ROE for utilities in Ontario that it regulates, including FortisOntario, to 9.75 per cent and refined the ROE formula to reduce sensitivity to changes in long-term Canada bond yields and included an additional factor for utility bond spreads. The National Energy Board ("NEB"), an independent federal agency that regulates several parts of Canada's energy industry, issued a decision in 2009 increasing the regulated total cost of capital of Trans Quebec & Maritimes Inc. ("TQM"), a Canadian regulated natural gas pipeline utility, which effectively established an approximate 100 basis points increase in TQM's allowed ROE for 2008 to 9.70 per cent on a 40 per cent equity ratio. The increase in the total cost of capital and allowed ROE was the result of a change in methodology which now takes into account financial market information which considers, among other things, changes that have impacted financial markets and economic conditions. In October 2009, the NEB also issued a decision stating that its 1994 multi-pipeline return on equity formula, used to determine the cost of capital for regulated pipeline companies, is no longer in effect, as there is doubt as to the ongoing correctness of using this formula. Instead, cost of capital will be determined by negotiations between the pipelines and their shippers or by the NEB.

Results of Operations: Same-hotel revenue declined at Fortis Properties' Hospitality Division in 2009 and organic revenue growth will continue to be challenged in 2010 as a result of the economic downturn and its impact on leisure and business travel and hotel stays. In the Caribbean, the level of, and fluctuations in, tourism and related activities, which are closely tied to economic conditions, influences electricity sales as it impacts electricity demand of the large hotels and condominium complexes that are serviced by the Corporation's regulated utilities in that region. Due to the impact of the economic downturn, annualized electricity sales growth at the Corporation's Regulated Caribbean Electric Utilities was only approximately 2 per cent for 2009 and is expected to be negligible for 2010.

Higher energy prices can result in reduced consumption by residential customers. Natural gas and crude oil exploration and production activities in certain of the Corporation's service territories are closely correlated with natural gas and crude oil prices. The level of these activities can influence energy demand, affecting local energy sales in some of the Corporation's service territories.

Defined Benefit Pension Plans: The fair value of the Corporation's consolidated defined benefit pension plan assets increased approximately 14 per cent, or $82 million, during 2009 commensurate with the recovery in the capital markets. This increase compares to a decrease of approximately 14 per cent, or $95 million, during 2008 mainly due to unfavourable market conditions during that year. Market-driven changes impacting the performance of pension plan assets and the discount rates may result in material changes in future pension funding requirements and/or net pension costs. The decline in fair value of the pension plan assets during 2008 did not materially affect the Corporation's consolidated defined benefit pension plan funding obligations for 2009. The discount rates used to determine defined benefit net pension costs for 2009 were higher than those used to determine defined benefit net pension costs for 2008, as a result of the impact of increased credit risk spreads on investment-grade corporate bonds due to volatility in the capital markets. For 2009, the amortization of 2008 losses associated with the pension plan assets was largely offset by the impact of higher assumed discount rates.

Consolidated defined benefit net pension costs for 2009 were not materially impacted by the outcome of the actuarial valuations, as at December 31, 2008 for defined benefit pension plans at Newfoundland Power and the Corporation, and as at December 31, 2007 for one of the defined benefit pension plans at Terasen, which were completed during the first quarter of 2009.

Consolidated defined benefit pension funding contributions, including current service, solvency and special funding amounts, were $21 million in 2009 and are expected to be $20 million in 2010, $8 million in 2011, $4 million in 2012 and $3 million in 2013. Fortis expects defined benefit pension plan funding requirements to be sourced primarily from a combination of cash generated from operations and amounts available for borrowing under existing credit facilities. The contributions above, however, are based on estimates provided under the latest completed actuarial valuations, which generally provide funding estimates for a period of only three to five years from the date of the valuations.

The date of the next actuarial valuations for the larger defined benefit pension plans are expected to be as follows:



December 31, 2009 Terasen (covering non-unionized employees)
December 31, 2010 Terasen (covering unionized employees) and FortisBC
December 31, 2011 Newfoundland Power


Consolidated defined benefit net pension costs for 2010 are expected to be higher than for 2009, driven mainly by decreases in discount rates assumed in the measurement of the pension obligations, due to decreased credit risk spreads on investment-grade corporate bonds, and the amortization of net actuarial losses that arose in prior years.

Any increase in future defined benefit pension funding requirements and/or net benefit costs at the regulated utilities may be recovered from, or refunded to, customers in future rates, subject to forecast risk. At the Terasen Gas companies, FortisBC, and Newfoundland Power beginning in 2010, however, actual pension expense above or below the forecast pension expense approved for recovery in customer rates for the year is subject to deferral account treatment for recovery from, or refund to, customers in future rates, subject to regulatory approval.

Counterparty Risk: The Terasen Gas companies are exposed to credit risk in the event of non-performance by counterparties to derivative financial instruments. The Terasen Gas companies are also exposed to significant credit risk on physical off-system sales. The Terasen Gas companies deal with high credit-quality institutions in accordance with established credit approval practices. Due to events in the capital markets over the past year, including significant government intervention in the banking system, the Terasen Gas companies have further limited the financial counterparties they transact with and have reduced available credit to, or taken additional security from, the physical off-system sales counterparties with which they transact. The Terasen Gas companies did not experience any counterparty defaults during 2009 and are not expecting any counterparties to fail to meet their obligations. As events over the past year have indicated, however, the credit quality of counterparties can change rapidly.

An extended decline in economic conditions could also impair the ability of customers to pay for gas and electricity consumed, thereby affecting the aging and collection of the utilities' trade receivables.

Credit Ratings: During 2009, the only changes in credit ratings for the Corporation's currently rated subsidiaries were for Newfoundland Power, TGI and Caribbean Utilities. In August 2009, Moody's upgraded the credit rating of Newfoundland Power's first mortgage bonds from Baa1 to A2 and of TGI's secured debentures from A2 to A1. In November 2009, S&P changed the outlook on Caribbean Utilities' issuer credit rating from A(stable) to A(negative) as a result of pressures facing the Cayman Island economy and concern that it could create a more difficult operating environment for Caribbean Utilities in the next few years. Fortis and its regulated utilities do not anticipate any material adverse rating actions by the credit rating agencies in the near term. However, the global financial crisis has placed increased scrutiny on rating agencies and rating agency criteria which may result in changes to credit rating practices and policies.

SUBSEQUENT EVENT

In January 2010, Fortis completed a $250 million five-year fixed rate reset preference share offering, the net proceeds of approximately $242 million were used to repay borrowings under its committed credit facility and to fund an equity injection into TGI to repay borrowings under the utility's credit facilities in support of working capital and capital expenditure requirements.

OUTLOOK

The Corporation's significant capital program, which is expected to approach $5 billion over the next five years, should drive growth in earnings and dividends.

The Corporation continues to pursue acquisitions for profitable growth, focusing on strategic opportunities to acquire regulated natural gas and electric utilities in the United States, Canada and the Caribbean. Fortis will also pursue growth in its non-regulated businesses in support of its regulated utility growth strategy.



FORTIS INC.

Consolidated Financial Statements
For the three and twelve months ended December 31, 2009 and 2008
(Unaudited)



Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at December 31
(in millions of Canadian dollars)

2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------

ASSETS

Current assets
Cash and cash equivalents $85 $66
Accounts receivable 595 681
Prepaid expenses 16 17
Regulatory assets 223 157
Inventories 178 229
Future income taxes 29 -
--------------------------------------------------------------------------
1,126 1,150

Other assets 174 230
Regulatory assets 758 203
Future income taxes 17 54
Utility capital assets 7,687 7,141
Income producing properties 559 540
Intangible assets 279 273
Goodwill 1,560 1,575
--------------------------------------------------------------------------

$12,160 $11,166
--------------------------------------------------------------------------
--------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
Short-term borrowings $415 $410
Accounts payable and accrued charges 852 874
Dividends payable 3 47
Income taxes payable 23 66
Regulatory liabilities 53 45
Current installments of long-term debt and
capital lease obligations 224 240
Future income taxes 24 15
--------------------------------------------------------------------------
1,594 1,697

Deferred credits 295 277
Regulatory liabilities 436 389
Future income taxes 576 61
Long-term debt and capital lease obligations 5,276 4,884
Non-controlling interest 123 145
Preference shares 320 320
--------------------------------------------------------------------------
8,620 7,773
--------------------------------------------------------------------------

Shareholders' equity
Common shares 2,497 2,449
Preference shares 347 347
Contributed surplus 11 9
Equity portion of convertible debentures 5 6
Accumulated other comprehensive loss (83) (52)
Retained earnings 763 634
--------------------------------------------------------------------------
3,540 3,393
--------------------------------------------------------------------------

$12,160 $11,166
--------------------------------------------------------------------------
--------------------------------------------------------------------------



Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars, except per share amounts)

Quarter Ended Year Ended
2009 2008 2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Revenue $1,018 $1,181 $3,637 $3,903
--------------------------------------------------------------------------

Expenses
Energy supply costs 520 685 1,799 2,112
Operating 212 208 773 743
Amortization 90 93 364 348
--------------------------------------------------------------------------
822 986 2,936 3,203
--------------------------------------------------------------------------

Operating income 196 195 701 700

Finance charges 93 93 360 363
--------------------------------------------------------------------------

Earnings before corporate
taxes and non-controlling
interest 103 102 341 337

Corporate taxes 15 17 49 65
--------------------------------------------------------------------------

Net earnings before non-
controlling interest 88 85 292 272

Non-controlling interest 3 5 12 13
--------------------------------------------------------------------------

Net earnings 85 80 280 259

Preference share dividends 4 4 18 14
--------------------------------------------------------------------------

Net earnings applicable
to common shares $81 $76 $262 $245
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Earnings per common share
Basic $0.48 $0.48 $1.54 $1.56
Diluted $0.46 $0.46 $1.51 $1.52
--------------------------------------------------------------------------
--------------------------------------------------------------------------



Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)


Quarter Ended Year Ended
2009 2008 2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Balance at beginning
of period $682 $602 $634 $551

Net earnings applicable
to common shares 81 76 262 245
--------------------------------------------------------------------------
763 678 896 796

Dividends on common shares - (44) (133) (162)
--------------------------------------------------------------------------

Balance at end of period $763 $634 $763 $634
--------------------------------------------------------------------------
--------------------------------------------------------------------------



Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)

Quarter Ended Year Ended
2009 2008 2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Net earnings $85 $80 $280 $259
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Other comprehensive
income
Unrealized
foreign currency
translation (losses)
gains on net investments
in self-sustaining
foreign operations (11) 80 (90) 115
Gains (losses) on hedges
of net investments in
self-sustaining foreign
operations 8 (64) 67 (92)
Corporate tax (expense)
recovery (1) 9 (9) 13
--------------------------------------------------------------------------
Change in unrealized
foreign currency
translation (losses)
gains, net of hedging
activities and tax (4) 25 (32) 36
--------------------------------------------------------------------------

Gain on derivative
instruments designated
as cash flow hedges,
net of tax - - 1 -
--------------------------------------------------------------------------

Comprehensive income $81 $105 $249 $295
--------------------------------------------------------------------------
--------------------------------------------------------------------------



Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)

Quarter Ended Year Ended
2009 2008 2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Operating Activities
Net earnings $85 $80 $280 $259
Items not affecting
cash
Amortization - utility
capital assets and
income producing
properties 79 83 317 308
Amortization -
intangibles assets 11 9 43 37
Amortization - other - 1 4 3
Future income taxes (4) (3) 5 14
Non-controlling
interest 3 5 12 13
Write-down of deferred
power costs - Belize
Electricity - - - 18
Other 1 (1) (8) (7)
Change in long-term
regulatory assets and
liabilities (5) (20) 25 (23)
--------------------------------------------------------------------------
170 154 678 622
Change in non-cash
operating working
capital (100) 54 (41) 39
--------------------------------------------------------------------------
70 208 637 661
--------------------------------------------------------------------------

Investing Activities
Change in other assets
and deferred credits 3 14 (1) 5
Capital expenditures -
utility capital assets (241) (263) (966) (872)
Capital expenditures -
income producing
properties (11) (3) (26) (14)
Capital expenditures -
intangible assets (9) (23) (32) (49)
Contributions in aid of
construction 16 25 56 85
Proceeds on sale of
utility capital assets - - 1 15
Business acquisitions,
net of cash acquired (70) (22) (84) (22)
--------------------------------------------------------------------------
(312) (272) (1,052) (852)
--------------------------------------------------------------------------

Financing Activities
Change in short-term
borrowings 79 (33) 8 (69)
Proceeds from long-
term debt, net of
issue costs 119 3 729 662
Repayments of long-
term debt and capital
lease obligations (24) (211) (172) (431)
Net borrowings
(repayments) under
committed credit
facilities 40 65 (14) (309)
Advances (to) from
non-controlling
interest - (1) 2 3
Issue of common shares,
net of costs 14 292 46 308
Issue of preference
shares, net of costs - - - 223
Dividends
Common shares - (44) (133) (162)
Preference shares (4) (4) (18) (14)
Subsidiary dividends
paid to non-
controlling interest (2) (8) (10) (15)
--------------------------------------------------------------------------
222 59 438 196
--------------------------------------------------------------------------

Effect of exchange rate
changes on cash and
cash equivalents (1) 3 (4) 3
--------------------------------------------------------------------------

Change in cash and cash
equivalents (21) (2) 19 8

Cash and cash equivalents,
beginning of period 106 68 66 58
--------------------------------------------------------------------------

Cash and cash equivalents,
end of period $85 $66 $85 $66
--------------------------------------------------------------------------
--------------------------------------------------------------------------



SEGMENTED INFORMATION (Unaudited)
Information by reportable segment is as follows:


REGULATED
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gas Utilities Electric Utilities
--------------------------------------------------------------------------
Quarter Terasen
ended Gas Total
December Companies- Fortis Fortis NF Other Electric Electric
31, 2009 Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 497 86 69 146 77 378 85
Energy supply
costs 300 - 22 99 50 171 50
Operating
expenses 79 34 19 13 11 77 13
Amortization 26 24 9 12 5 50 8
--------------------------------------------------------------------------
Operating
income 92 28 19 22 11 80 14
Finance charges 30 14 9 9 6 38 3
Corporate
taxes
(recoveries) 14 (1) 2 4 (1) 4 1
Non-controlling
interest - - - 1 - 1 3
--------------------------------------------------------------------------
Net earnings
(loss) 48 15 8 8 6 37 7
Preference
share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 48 15 8 8 6 37 7
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Goodwill 908 227 221 - 63 511 141
Identifiable
assets 4,084 1,892 1,141 1,188 631 4,852 799
--------------------------------------------------------------------------
Total assets 4,992 2,119 1,362 1,188 694 5,363 940
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures
(3) 70 92 36 22 13 163 15
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter ended
December 31,
2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 606 78 66 139 65 348 159
Energy supply
costs 418 - 23 94 44 161 109
Operating
expenses 71 34 18 12 7 71 20
Amortization 24 22 9 12 5 48 13
--------------------------------------------------------------------------
Operating
income 93 22 16 21 9 68 17
Finance charges 33 12 7 8 5 32 5
Corporate taxes
(recoveries) 13 (1) 2 4 1 6 1
Non-controlling
interest - - - 1 - 1 3
--------------------------------------------------------------------------
Net earnings
(loss) 47 11 7 8 3 29 8
Preference
share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 47 11 7 8 3 29 8
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Goodwill 903 227 221 - 63 511 161
Identifiable
assets 3,721 1,574 978 1,001 520 4,073 867
--------------------------------------------------------------------------
Total assets 4,624 1,801 1,199 1,001 583 4,584 1,028
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures
(3) 68 88 36 20 18 162 45
--------------------------------------------------------------------------
--------------------------------------------------------------------------


NON-REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Quarter ended Corporate Inter-
December 31, 2009 Fortis Fortis and segment
($ millions) Generation Properties Other eliminations Consolidated
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 5 53 6 (6) 1,018
Energy supply
costs - - - (1) 520
Operating expenses 3 37 5 (2) 212
Amortization 1 4 1 - 90
---------------------------------------------------------------------------
Operating income 1 12 - (3) 196
Finance charges (1) 5 21 (3) 93
Corporate taxes
(recoveries) - 2 (6) - 15
Non-controlling
interest (1) - - - 3
---------------------------------------------------------------------------
Net earnings (loss) 3 5 (15) - 85
Preference share
dividends - - 4 - 4
---------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 3 5 (19) - 81
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Goodwill - - - - 1,560
Identifiable assets 252 576 130 (93) 10,600
---------------------------------------------------------------------------
Total assets 252 576 130 (93) 12,160
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures (3) - 10 3 - 261
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Quarter ended
December 31, 2008
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 20 52 6 (10) 1,181
Energy supply costs 1 - - (4) 685
Operating expenses 3 36 8 (1) 208
Amortization 2 4 2 - 93
---------------------------------------------------------------------------
Operating income 14 12 (4) (5) 195
Finance charges 2 6 20 (5) 93
Corporate taxes
(recoveries) 3 2 (8) - 17
Non-controlling
interest 1 - - - 5
---------------------------------------------------------------------------
Net earnings (loss) 8 4 (16) - 80
Preference share
dividends - - 4 - 4
---------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 8 4 (20) - 76
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Goodwill - - - - 1,575
Identifiable assets 285 559 126 (40) 9,591
---------------------------------------------------------------------------
Total assets 285 559 126 (40) 11,166
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures (3) 6 3 5 - 289
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1) Includes Maritime Electric and FortisOntario
(2) Includes Belize Electricity, Caribbean Utilities and Fortis Turks
and Caicos
(3) Relates to utility capital assets, including amounts for AESO
transmission capital projects, and income producing properties
and intangible assets



REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gas Utilities Electric Utilities
---------------------------------------------------------------------------
Terasen
Annual Gas Total
December Companies- Fortis Fortis NF Other Electric Electric
31, 2009 Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 1,663 331 253 527 279 1,390 339
Energy supply
costs 1,022 - 72 346 183 601 192
Operating
expenses 268 132 70 52 32 286 54
Amortization 102 94 37 46 19 196 37
---------------------------------------------------------------------------
Operating
income 271 105 74 83 45 307 56
Finance charges 121 50 32 34 19 135 16
Corporate taxes
(recoveries) 33 (5) 5 16 6 22 2
Non-controlling
interest - - - 1 - 1 11
---------------------------------------------------------------------------
Net earnings
(loss) 117 60 37 32 20 149 27
Preference
share dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 117 60 37 32 20 149 27
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Goodwill 908 227 221 - 63 511 141
Identifiable
assets 4,084 1,892 1,141 1,188 631 4,852 799
---------------------------------------------------------------------------
Total assets 4,992 2,119 1,362 1,188 694 5,363 940
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures
(3) 246 407 115 74 46 642 92
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Annual
December 31,
2008
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 1,902 300 237 517 262 1,316 408
Energy supply
costs 1,268 - 68 337 177 582 273
Operating
expenses 253 130 67 50 28 275 55
Amortization 97 85 34 45 18 182 36
---------------------------------------------------------------------------
Operating
income 284 85 68 85 39 277 44
Finance charges 129 42 28 33 18 121 16
Corporate taxes
(recoveries) 37 (3) 6 19 7 29 2
Non-controlling
interest - - - 1 - 1 9
---------------------------------------------------------------------------
Net earnings
(loss) 118 46 34 32 14 126 17
Preference
share dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 118 46 34 32 14 126 17
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Goodwill 903 227 221 - 63 511 161
Identifiable
assets 3,721 1,574 978 1,001 520 4,073 867
---------------------------------------------------------------------------
Total assets 4,624 1,801 1,199 1,001 583 4,584 1,028
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures
(3) 220 333 117 67 46 563 110
---------------------------------------------------------------------------
---------------------------------------------------------------------------


NON-REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Annual Corporate Inter-
December 31, 2009 Fortis Fortis and segment
($ millions) Generation Properties Other eliminations Consolidated
---------------------------------------------------------------------------
Revenue 39 218 27 (39) 3,637
Energy supply costs 2 - - (18) 1,799
Operating expenses 11 146 14 (6) 773
Amortization 5 16 8 - 364
---------------------------------------------------------------------------
Operating income 21 56 5 (15) 701
Finance charges 2 22 79 (15) 360
Corporate taxes
(recoveries) 3 10 (21) - 49
Non-controlling
interest - - - - 12
---------------------------------------------------------------------------
Net earnings (loss) 16 24 (53) - 280
Preference share
dividends - - 18 - 18
---------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 16 24 (71) - 262
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Goodwill - - - - 1,560
Identifiable assets 252 576 130 (93) 10,600
---------------------------------------------------------------------------
Total assets 252 576 130 (93) 12,160
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures (3) 14 26 4 - 1,024
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Annual
December 31, 2008
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 82 207 26 (38) 3,903
Energy supply costs 7 - - (18) 2,112
Operating expenses 14 135 16 (5) 743
Amortization 10 15 8 - 348
---------------------------------------------------------------------------
Operating income 51 57 2 (15) 700
Finance charges 8 24 80 (15) 363
Corporate taxes
(recoveries) 10 10 (23) - 65
Non-controlling
interest 3 - - - 13
---------------------------------------------------------------------------
Net earnings (loss) 30 23 (55) - 259
Preference share
dividends - - 14 - 14
---------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 30 23 (69) - 245
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Goodwill - - - - 1,575
Identifiable assets 285 559 126 (40) 9,591
---------------------------------------------------------------------------
Total assets 285 559 126 (40) 11,166
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures (3) 19 14 9 - 935
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1) Includes Maritime Electric and FortisOntario
(2) Includes Belize Electricity, Caribbean Utilities and Fortis Turks
and Caicos
(3) Relates to utility capital assets, including amounts for AESO
transmission capital projects, and income producing properties and
intangible assets


CORPORATE INFORMATION

Fortis Inc. is the largest investor-owned distribution utility in Canada. With more than $12 billion in assets and $3.6 billion in annual revenues, the Corporation serves approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns non-regulated generation assets across Canada and in Belize and Upper New York State. It also owns hotels and commercial real estate across Canada. Fortis Inc. shares are listed on the Toronto Stock Exchange and trade under the symbol FTS.



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
E: service@computershare.com
W: www.computershare.com/fortisinc


Additional information, including the Fortis 2008 Annual Information Form, Management Information Circular and Annual Report, is available on SEDAR at www.sedar.com and on the Corporation's web site at www.fortisinc.com.

Contact Information

  • Fortis Inc.
    Barry V. Perry
    Vice President Finance and Chief Financial Officer
    709-737-2822