Fortis Inc.
TSX : FTS

Fortis Inc.

April 30, 2009 07:00 ET

Fortis Earns $92 Million in First Quarter of 2009

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwire - April 30, 2009) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved first quarter net earnings applicable to common shares of $92 million, or $0.54 per common share, compared to earnings of $91 million, or $0.58 per common share, for the first quarter of 2008.

"An increase in earnings at Regulated Electric Utilities in western Canada was partially offset by lower earnings at Caribbean Regulated Utilities and Fortis Properties," explains Stan Marshall, President and Chief Executive Officer, Fortis Inc.

The Terasen Gas companies contributed earnings of $58 million, comparable to the first quarter of 2008. Due to the seasonality of the business, virtually all of the earnings of the Terasen Gas companies are generated in the first and fourth quarters.

Canadian Regulated Electric Utilities contributed earnings of $37 million, up $4 million from the first quarter of 2008, driven by growth in electrical infrastructure investment and customers at the utilities in western Canada.

The allowed rate of return on common shareholders' equity ("ROE") for 2009 has been set for Terasen Gas Inc., Terasen Gas (Vancouver Island) Inc., FortisBC and Maritime Electric, decreasing slightly to 8.47 per cent, 9.17 per cent, 8.87 per cent and 9.75 per cent, respectively. The allowed ROE at Newfoundland Power remains unchanged at 8.95 per cent. Interim customer rates for 2009 at FortisAlberta have been set using the utility's 2007 allowed ROE of 8.51 per cent, pending the outcome of the Generic Cost of Capital Proceeding underway in Alberta.

Caribbean Regulated Electric Utilities contributed $6 million to earnings compared to $7 million in the first quarter of 2008. Excluding one-time gains of approximately $2 million at Fortis Turks and Caicos, earnings were $3 million lower quarter over quarter. The decrease resulted from reduced electricity sales attributable to cooler weather and the impact of the global economic downturn on energy demand combined with the lower allowed rate of return on rate base assets at Caribbean Utilities and Belize Electricity. The decrease was partially mitigated by the favourable impact of foreign exchange rates associated with the strengthening US dollar quarter over quarter.

Non-Regulated Fortis Generation contributed $6 million to earnings, comparable to the first quarter of 2008. The favourable impact of foreign exchange rates and increased hydroelectric production in Belize were offset by lower production and lower average wholesale market energy prices in Upper New York State and Ontario quarter over quarter.

Fortis Properties contributed earnings of $2 million compared to $3 million in the first quarter of 2008. Results were reduced by one-time transitional operating costs associated with the Sheraton Hotel Newfoundland, acquired in November 2008, and the impact of lower hotel occupancies.

Corporate and other expenses were $17 million compared to $16 million for the same quarter in 2008. The increase in corporate and other costs was mainly due to higher preference share dividends related to the issuance of First Preference Shares, Series G during the second quarter of 2008.

Consolidated capital expenditures, before customer contributions, were approximately $219 million in the first quarter of 2009. Much of the Corporation's consolidated capital expenditure program is being driven by Regulated Utilities in western Canada and the Caribbean.

In February, FortisAlberta and Terasen Gas Inc. each raised $100 million of 30-year unsecured debentures at 7.06 per cent and 6.55 per cent, respectively.

Common shareholders of Fortis received a dividend of 26 cents per common share in the first quarter of 2009, up from 25 cents in the fourth quarter of 2008. The 4 per cent increase in the quarterly common share dividend translates into an annualized dividend of $1.04 and extends the Corporation's record of annual common share dividend increases to 36 consecutive years, the longest record of any public corporation in Canada. Effective March 1, 2009, the Corporation's Dividend Reinvestment and Share Purchase Plan provides a 2 per cent discount on the purchase of common shares, issued from treasury, with reinvested dividends.

Cash flow from operating activities was $229 million for the quarter, up $36 million from the same quarter last year, driven by increased cash flows at FortisAlberta.

In December 2008, Fortis completed a $300 million common share issue, the net proceeds of which were primarily used to repay short-term debt incurred to repay maturing debt at Terasen.

"The equity issue has strengthened the consolidated balance sheet of Fortis and improved liquidity," says Marshall.

As at March 31, 2009, Fortis had consolidated credit facilities of $2.2 billion, of which approximately $1.6 billion was unused, including $544 million unused under the Corporation's $600 million committed revolving credit facility. Approximately $2 billion of the total credit facilities are committed facilities, the majority of which have maturities between 2011 and 2013.

"Notwithstanding the current economic recession, Fortis anticipates strong organic growth. The Corporation is focused on executing its 2009 consolidated capital expenditure program, estimated at $1 billion. Major capital projects underway include the approximate $200 million liquefied natural gas storage facility at Terasen Gas (Vancouver Island), the $161 million four-year Automated Meter Infrastructure Project at FortisAlberta, the $139 million Okanagan Transmission Reinforcement Project at FortisBC and the US$53 million 19-megawatt hydroelectric generating facility in Belize," concludes Marshall.



Interim Management Discussion and Analysis
For the three months ended March 31, 2009
Dated April 30, 2009


The following analysis should be read in conjunction with the Fortis Inc. ("Fortis" or the "Corporation") interim unaudited consolidated financial statements and notes thereto for the three months ended March 31, 2009 and the 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. This material has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations relating to MD&As. Financial information in this release has been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") and is presented in Canadian dollars unless otherwise specified.

Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the "safe harbour" provisions of applicable Canadian securities legislation. The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs and is based on information currently available to the Corporation's management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the expected timing of regulatory decisions; consolidated forecasted gross capital expenditures for 2009 and in total over the next five years; the nature, timing and amount of certain capital projects; the expected impacts on Fortis of the downturn in the global economy; the electricity sales growth rate expected at the Corporation's regulated utilities in the Caribbean in 2009; no significant decrease in annual consolidated operating cash flows is expected in 2009; the subsidiaries expect to be able to source the cash required to fund their 2009 capital expenditure programs; the Corporation and its subsidiaries expect to continue to have reasonable access to long-term capital in the near to medium terms; expected long-term debt maturities and repayments on average annually over the next five years; no material increase in interest expense and/or fees associated with renewed and extended credit facilities is expected in 2009; 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 no material increase in defined benefit pension expense in 2009.
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 2009; 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; an ultimate resolution of the expropriation of the assets of the Exploits River Hydro Partnership that differs from what is currently expected by management; 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; an unexpected outcome of legal proceedings currently against the Corporation; licences and permits; loss of service area; market energy sales prices; transition to International Financial Reporting Standards; changes in tax legislation; First Nations' lands; 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 three months ended March 31, 2009 and for the year ended December 31, 2008.

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 more than 2,000,000 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 and operates non-regulated generation assets across Canada and in Belize and Upper New York State and hotels and commercial real estate in Canada. Year-to-date March 31, 2009, the Corporation's electric utilities met a combined peak electricity demand of approximately 5,661 megawatts ("MW") and its gas utility met a peak day demand of 1,234 terajoules ("TJ"). For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 2009.

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 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 first quarters ended March 31, 2009 and March 31, 2008 are provided in the following table.



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Financial Highlights (Unaudited)
Quarter Ended March 31
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($ millions, except earnings
per common share and common
shares outstanding) 2009 2008 Variance
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Revenue 1,201 1,146 55
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Cash flow from operating activities 229 193 36
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Net earnings applicable to common
shares 92 91 1
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Basic earnings per common share ($) 0.54 0.58 (0.04)
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Diluted earnings per common share ($) 0.52 0.55 (0.03)
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Weighted average number of common
shares outstanding (millions) 169.4 156.6 12.8
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Segmented Net Earnings
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Regulated Gas Utilities - Canadian
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Terasen Gas Companies (1) 58 58 -
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Regulated Electric Utilities - Canadian
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FortisAlberta 12 11 1
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FortisBC (2) 14 12 2
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Newfoundland Power 6 6 -
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Other Canadian (3) 5 4 1
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37 33 4
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Regulated Electric Utilities -
Caribbean (4) 6 7 (1)
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Non-Regulated - Fortis Generation (5) 6 6 -
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Non-Regulated - Fortis Properties (6) 2 3 (1)
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Corporate and Other (7) (17) (16) (1)
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Net Earnings Applicable to Common
Shares 92 91 1
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(1) Comprised of Terasen Gas Inc., Terasen Gas (Vancouver Island) Inc. and
Terasen Gas (Whistler) Inc.
(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 and Cornwall Electric.
(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 57 per cent
controlling interest; and wholly owned Fortis Turks and Caicos.
Previously, Caribbean Utilities had an April 30 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 31. The change in Caribbean Utilities' fiscal year
end eliminates the previous two-month lag in consolidating Caribbean
Utilities' 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 195 MW, mainly
hydroelectric. Prior to February 13, 2009, the financial results of
the hydroelectric generation operations in central Newfoundland were
consolidated in the financial statements of Fortis. Subsequent to that
date, the financial results of the generation operations in central
Newfoundland have been recorded in the financial statements of Fortis
on an equity basis, due to the Corporation no longer having significant
influence over the generation operations as a result of expropriation
legislation promulgated by the Government of Newfoundland and Labrador.
The change in the method of accounting did not have a material impact
on segmented or consolidated earnings. For a further discussion of
this matter, refer to the "Critical Accounting Estimates -
Contingencies" section of this MD&A.
(6) Including a hotel acquired in Ontario in April 2009, Fortis Properties
owns 21 hotels with more than 4,000 rooms in eight Canadian provinces
and approximately 2.8 million square feet of commercial real estate
primarily in Atlantic Canada.
(7) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen Inc. corporate-related activities and the financial results of
Terasen Inc.'s 30 per cent ownership interest in CustomerWorks Limited
Partnership and of Terasen Inc.'s non-regulated wholly owned subsidiary
Terasen Energy Services Inc.
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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)
Quarter Ended March 31
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2009 2008 Variance
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Gas Volumes (TJ) 77,970 78,184 (214)
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($ millions)
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Revenue 669 635 34
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Energy Supply Costs 468 437 31
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Operating Expenses 67 61 6
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Amortization 25 24 1
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Finance Charges 32 33 (1)
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Corporate Taxes 19 22 (3)
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Earnings 58 58 -
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Gas volumes: Gas volumes at the Terasen Gas companies decreased 214 TJ, or 0.3 per cent, quarter over quarter. The decrease was mainly due to lower sales volumes to customers under fixed-price contracts and lower transportation volumes to customers sourcing their own gas supplies, partially offset by increased sales volumes to residential customers as a result of higher consumption due to cooler weather quarter over quarter and customer growth.

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 regulatory deferral mechanisms approved by the British Columbia Utilities Commission ("BCUC"), changes in consumption levels and energy supply costs, from those forecasted to set gas distribution rates, do not materially impact earnings.

During the first quarter of 2009, net customer additions at Terasen Gas Inc. ("TGI") and Terasen Gas (Vancouver Island) Inc. ("TGVI") totalled 2,256, bringing the total customer count at the Terasen Gas companies to approximately 934,000 as at March 31, 2009. 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 slower customer growth during the first quarter of 2009 compared to the same quarter in 2008.

Revenue: Revenue was $34 million higher quarter over quarter. Revenue during the first quarter of 2009 reflected increased residential customer consumption and higher basic customer delivery rates compared to the same quarter in 2008.

Effective January 1, 2009, basic customer delivery rates at TGI increased approximately 6 per cent while basic customer delivery rates at TGVI increased from zero to 5 per cent based on rate class. Basic rates for 2009, however, reflect the impact of a decrease in the allowed rate of return on common shareholder's equity ("ROE") 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.

Earnings: Earnings were comparable quarter over quarter. The impact of the increase in basic customer delivery rates, customer growth and a lower effective corporate income tax rate was offset by higher operating expenses driven by increased labour and employee-benefit costs. The decrease in the effective tax rate was primarily due to lower enacted federal and provincial corporate income tax rates.

For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Terasen Gas companies, refer to the "Regulatory Highlights" section of this MD&A.



REGULATED ELECTRIC UTILITIES - CANADIAN

FortisAlberta

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FortisAlberta
Financial Highlights (Unaudited)
Quarter Ended March 31
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2009 2008 Variance
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Energy Deliveries (GWh) 4,152 4,138 14
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($ millions)
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Revenue 79 73 6
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Operating Expenses 34 33 1
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Amortization 22 20 2
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Finance Charges 11 9 2
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Earnings 12 11 1
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Energy Deliveries: Energy deliveries at FortisAlberta increased 14 gigawatt hours ("GWh"), or 0.3 per cent, quarter over quarter, mainly due to residential, commercial and irrigation customer growth and the impact of colder-than-normal weather.

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 do not directly correlate with changes in revenues.

Revenue: Revenue was $6 million higher quarter over quarter, mainly due to an 8.6 per cent increase in customer distribution rates, effective January 1, 2009, and the impact of load and customer growth. Customer distribution rates for 2009 reflect the impact of ongoing investment in electrical infrastructure and collection from customers in 2009 of the increase in the allowed ROE for 2008 that was accrued in 2008. Rates for 2009 reflect an interim allowed ROE of 8.51 per cent compared to an allowed ROE of 8.75 per cent for 2008.

Earnings: Earnings were $1 million higher quarter over quarter. The impact of the increase in customer distribution rates and load and customer growth was partially offset by: (i) increased operating expenses mainly due to higher labour, employee-benefit and contracted manpower costs, partially offset by lower general operating costs; (ii) increased amortization costs associated with continued investment in capital assets; and (iii) 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.

For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to FortisAlberta, refer to the "Regulatory Highlights" section of this MD&A.



FortisBC

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FortisBC
Financial Highlights (Unaudited)
Quarter Ended March 31
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2009 2008 Variance
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Electricity Sales (GWh) 903 875 28
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($ millions)
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Revenue 72 66 6
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Energy Supply Costs 22 21 1
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Operating Expenses 17 16 1
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Amortization 10 9 1
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Finance Charges 7 7 -
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Corporate Taxes 2 1 1
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Earnings 14 12 2
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Electricity Sales: Electricity sales at FortisBC increased 28 GWh, or 3.2 per cent, quarter over quarter, primarily due to residential, general service and wholesale customer growth and increased consumption due to colder-than-normal weather.

Revenue: Revenue was $6 million higher quarter over quarter. The increase was driven by a 4.6 per cent increase in electricity rates, effective January 1, 2009, and electricity sales growth. Electricity rates for 2009 reflect 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 were $2 million higher quarter over quarter. The impact of the increase in electricity rates and customer growth was partially offset by: (i) higher energy supply costs associated with increased electricity sales and a higher proportion of purchased power versus energy generated from Company-owned hydroelectric generating plants, partially offset by the impact of lower market prices for purchased power; (ii) higher operating expenses mainly due to the timing of maintenance projects, higher labour costs and general inflationary cost increases; and (iii) increased amortization costs associated with continued investment in capital assets.

For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to FortisBC, refer to the "Regulatory Highlights" section of this MD&A.



Newfoundland Power

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Newfoundland Power
Financial Highlights (Unaudited)
Quarter Ended March 31
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2009 2008 Variance
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Electricity Sales (GWh) 1,763 1,716 47
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($ millions)
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Revenue 169 164 5
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Energy Supply Costs 127 122 5
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Operating Expenses 14 14 -
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Amortization 11 10 1
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Finance Charges 8 8 -
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Corporate Taxes 3 4 (1)
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Earnings 6 6 -
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Electricity Sales: Electricity sales at Newfoundland Power increased 47 GWh, or 2.7 per cent, quarter over quarter due to customer growth and higher average consumption driven by increased use of electric heating.

Revenue: Revenue was $5 million higher quarter over quarter, driven by electricity sales growth. The allowed ROE of 8.95 per cent for 2009 remains unchanged from 2008 and, consequently, there has been no change in basic customer rates for 2009.

Earnings: Newfoundland Power's earnings were comparable quarter over quarter. The impact of electricity sales growth was offset largely by the impact of higher demand charges from Newfoundland and Labrador Hydro Corporation ("Newfoundland Hydro"), associated with meeting peak load requirements during the winter season, and increased amortization costs associated with continued investment in capital assets.

For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to Newfoundland Power, refer to the "Regulatory Highlights" section of this MD&A.



Other Canadian Electric Utilities

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Other Canadian Electric Utilities (Unaudited) (1)
Financial Highlights
Quarter Ended March 31
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2009 2008 Variance
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Electricity Sales (GWh) 616 599 17
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($ millions)
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Revenue 70 70 -
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Energy Supply Costs 47 49 (2)
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Operating Expenses 7 7 -
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Amortization 4 4 -
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Finance Charges 5 4 1
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Corporate Taxes 2 2 -
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Earnings 5 4 1
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(1) Includes Maritime Electric and FortisOntario
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Electricity Sales: Electricity sales at Other Canadian Electric Utilities increased 17 GWh, or 2.8 per cent, quarter over quarter, driven by higher average consumption mainly due to colder-than-normal weather experienced in Ontario and on Prince Edward Island.

Revenue: Revenue was comparable quarter over quarter. The impact of increased electricity sales and a 1.8 per cent increase in basic electricity rates at Maritime Electric, effective April 1, 2008, and an average 1.1 per cent increase in basic electricity distribution rates at FortisOntario, effective May 1, 2008, were offset by the flow through to customers of lower energy supply costs at FortisOntario.

Earnings: Earnings were $1 million higher quarter over quarter. The impact of higher basic electricity rates and electricity sales was partially offset by higher finance charges associated with increased borrowings and the higher cost of borrowing associated with the $60 million bonds issued by Maritime Electric in April 2008.

In October 2008, FortisOntario entered into a definitive agreement to acquire a 10 per cent strategic ownership interest in the electricity distribution business of Grimsby Power Inc. The transaction is pending approval from the Ontario Ministry of Finance, which is expected during the second quarter of 2009.

For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to Maritime Electric and FortisOntario, refer to the "Regulatory Highlights" section of this MD&A.



REGULATED ELECTRIC UTILITIES - CARIBBEAN

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Regulated Electric Utilities - Caribbean (1)
Financial Highlights (Unaudited)
Quarter Ended March 31
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2009 2008(2) Variance
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Average US:CDN Exchange Rate (3) 1.25 1.01 0.24
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Electricity Sales (GWh) 247 258 (11)
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($ millions)
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Revenue 83 75 8
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Energy Supply Costs 46 40 6
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Operating Expenses 14 11 3
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Amortization 11 7 4
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Finance Charges 4 5 (1)
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Corporate Taxes - 1 (1)
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Non-Controlling Interest 2 4 (2)
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Earnings 6 7 (1)
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(1) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(2) Electricity sales and financial results for 2008 associated with
Caribbean Utilities relate to the utility's quarter ended January 31,
2008. Up to and including the third quarter of 2008, Caribbean
Utilities' 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 from April 30 to December 31,
eliminating the previous two-month lag in consolidating Caribbean
Utilities' financial results. Therefore, electricity sales and
financial results for the first quarter of 2009 associated with
Caribbean Utilities relate to the utility's first quarter ended March
31, 2009.
(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.
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Electricity Sales: Regulated Electric Utilities - Caribbean electricity sales decreased 11 GWh, or 4.3 per cent, quarter over quarter. The decrease was primarily due to cooler-than-normal weather conditions which reduced air conditioning load on Grand Cayman and the Turks and Caicos Islands, combined with the negative impact of global economic conditions on residential customer consumption and activities in the tourism, oil, construction and related industries.

Revenue: Revenue increased $8 million quarter over quarter. Revenue for the first quarter of 2009 was favourably impacted by approximately $1 million associated with a favourable appeal judgment at Fortis Turks and Caicos related to a customer rate classification matter. Excluding the above one-item item and the approximate $16 million favourable impact of foreign exchange associated with the translation of foreign currency-denominated revenue, due to the strengthening of the US dollar against the Canadian dollar, revenue decreased approximately $9 million quarter over quarter. Factors decreasing revenue included: (i) lower electricity sales; (ii) a 3.25 per cent reduction in basic electricity rates reflecting a lower allowed rate of return on rate base assets ("ROA") at Caribbean Utilities and the elimination of the utility's hurricane cost recovery surcharge, under the terms of the Company's new transmission and distribution licence, effective January 1, 2008; (iii) a decrease in the value-added ("VAD") component of the average electricity rate at Belize Electricity, effective July 1, 2008, reflecting a lower allowed ROA as a result of the regulator's June 2008 Final Decision; and (iv) a change in the methodology at Belize Electricity for recording customer installation fees and the impact of refunding certain installation fees previously collected. The decrease was partially offset by the favourable impact on revenue of an increase in the cost of power component of the average electricity rate at Belize Electricity, effective July 1, 2008. 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. Earnings for the first quarter of 2009 included approximately $1 million associated with the favourable appeal judgment at Fortis Turks and Caicos, as described above, and an approximate $1 million one-time favourable adjustment to energy supply costs associated with a change in the methodology for accruing unbilled fuel factor revenue at Fortis Turks and Caicos. Excluding the impact of the above favourable one-time items and $1 million associated with favourable foreign currency translation, earnings' contribution decreased $4 million quarter over quarter. The decline was mainly due to decreased electricity sales, a lower allowed ROA at Caribbean Utilities and Belize Electricity, effective January 1, 2008 and July 1, 2008, respectively, increased amortization costs and the favourable impact on energy supply costs during the first quarter of 2008 associated with the movement in deferred fuel costs at Caribbean Utilities, partially offset by lower finance charges.

Excluding foreign currency translation impacts, amortization costs increased quarter over quarter due to the impact of continued investment in capital assets.

Excluding foreign currency translation impacts, finance charges decreased quarter over quarter as a result of increased capitalized finance costs at Caribbean Utilities due to a change in the utility's methodology for capitalizing finance costs associated with capital assets under construction, as prescribed by the regulator.

For additional information on the nature of regulation and material regulatory decisions and applications pertaining to Belize Electricity, Caribbean Utilities and Fortis Turks and Caicos, refer to the "Regulatory Highlights" section of this MD&A.



NON-REGULATED - FORTIS GENERATION

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Non-Regulated - Fortis Generation (1)
Financial Highlights (Unaudited)
Quarter Ended March 31
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2009 2008 Variance
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Energy Sales (GWh) 257 288 (31)
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($ millions)
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Revenue 16 19 (3)
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Energy Supply Costs 1 2 (1)
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Operating Expenses 4 4 -
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Amortization 2 2 -
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Finance Charges 1 2 (1)
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Corporate Taxes 2 3 (1)
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Earnings 6 6 -
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(1) Includes the operations of non-regulated generating assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York
State. Prior to February 13, 2009, the financial results of the
hydroelectric generation operations in central Newfoundland were
consolidated in the financial statements of Fortis. Subsequent to that
date, the financial results of the generation operations in central
Newfoundland have been recorded in the financial statements of Fortis
on an equity basis, due to the Corporation no longer having significant
influence over the generation operations as a result of expropriation
legislation promulgated by the Government of Newfoundland and Labrador.
The change in the method of accounting did not have a material impact
on segmented or consolidated earnings. For a further discussion of
this matter, refer to the "Critical Accounting Estimates -
Contingencies" section of this MD&A.
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Energy Sales: Non-Regulated - Fortis Generation energy sales decreased 31 GWh, or 10.8 per cent, quarter over quarter. Energy sales for the first quarter of 2009, however, included energy sales associated with the generation operations in central Newfoundland for only 1 1/2 months compared to a full quarter in 2008, due to the change to the equity method of accounting for these operations in February 2009 necessitated by the actions of the Government of Newfoundland and Labrador related to expropriation of Newfoundland-based assets of AbitibiBowater Inc., formerly Abitibi-Consolidated Company of Canada ("Abitibi"). Energy sales also decreased due to lower production in Upper New York State and Ontario, partially offset by higher production in Belize. Production levels were primarily a function of rainfall levels. At the end of April 2009, the Chalillo reservoir in Belize was at approximately 40 per cent of its full-supply level, a normal level for this time of the year.

Revenue: Revenue was $3 million lower quarter over quarter. Factors decreasing revenue were: (i) the impact of changing to the equity method of accounting for the financial results of the hydroelectric generation operations in central Newfoundland during the first quarter of 2009, as described above; (ii) lower production in Upper New York State and Ontario; (iii) decreased average wholesale market energy prices per megawatt hour ("MWh") in Ontario, which were $42.98 during the first quarter of 2009 compared to $49.93 for the same quarter in 2008; and (iv) lower average wholesale market energy prices per MWh in Upper New York State, which were US$46.13 during the first quarter of 2009 compared to US$72.91 for the same quarter in 2008. Partially offsetting the above factors was the approximate $1 million favourable impact of foreign exchange associated with the translation of foreign currency-denominated revenue, due to the strengthening of the US dollar against the Canadian dollar quarter over quarter, and the impact of increased production in Belize.

Earnings: Earnings were comparable quarter over quarter. The approximate $0.5 million favourable earnings impact of foreign currency translation and higher earnings from hydroelectric generation operations in Belize related to increased production was offset by the impact of lower production and lower average wholesale market energy prices in Upper New York State and Ontario. Earnings' contribution associated with generation operations in central Newfoundland was comparable quarter over quarter.



NON-REGULATED - FORTIS PROPERTIES

--------------------------------------------------------------------------
--------------------------------------------------------------------------
Non-Regulated - Fortis Properties
Financial Highlights (Unaudited)
Quarter Ended March 31
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance
--------------------------------------------------------------------------
Hospitality Revenue 31 29 2
--------------------------------------------------------------------------
Real Estate Revenue 16 16 -
--------------------------------------------------------------------------
Total Revenue 47 45 2
--------------------------------------------------------------------------
Operating Expenses 34 31 3
--------------------------------------------------------------------------
Amortization 4 4 -
--------------------------------------------------------------------------
Finance Charges 6 6 -
--------------------------------------------------------------------------
Corporate Taxes 1 1 -
--------------------------------------------------------------------------
Earnings 2 3 (1)
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Revenue: Hospitality revenue was $2 million higher quarter over quarter, driven by revenue contribution from the Sheraton Hotel Newfoundland, which was acquired in November 2008, partially offset by decreased revenue from operations in Ontario and western Canada. Revenue per available room for the first quarter was $64.40 compared to $67.82 for the same quarter in 2008, mainly due to decreased hotel occupancy in all of the Company's operating regions, partially offset by an increase in average room rates driven mainly by operations in Atlantic Canada.

Real Estate revenue was comparable quarter over quarter. The occupancy rate of the Real Estate Division was 96.0 per cent as at March 31, 2009 compared to 96.6 per cent as at March 31, 2008.

Earnings: Earnings were $1 million lower quarter over quarter due to non-recurring transitional operating costs associated with the Sheraton Hotel Newfoundland combined with the impact of decreased hotel occupancies.

In April 2009, Fortis Properties purchased the 214-room Holiday Inn Select in Windsor, Ontario for $7 million.



CORPORATE AND OTHER

--------------------------------------------------------------------------
--------------------------------------------------------------------------
Corporate and Other (1)
Financial Highlights (Unaudited)
Quarter Ended March 31
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance
--------------------------------------------------------------------------
Revenue 7 7 -
--------------------------------------------------------------------------
Operating Expenses 3 3 -
--------------------------------------------------------------------------
Amortization 2 3 (1)
--------------------------------------------------------------------------
Finance Charges (2) 19 21 (2)
--------------------------------------------------------------------------
Corporate Tax Recovery (4) (5) 1
--------------------------------------------------------------------------
Preference share dividends 4 1 3
--------------------------------------------------------------------------
Net Corporate and Other Expenses (17) (16) (1)
--------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen Inc. corporate-related activities and the financial results of
Terasen Inc.'s 30 per cent ownership interest in CustomerWorks Limited
Partnership and of Terasen Inc.'s non-regulated wholly owned subsidiary
Terasen Energy Services Inc.
(2) Includes dividends on preference shares classified as long-term
liabilities
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Revenue and Net Corporate and Other Expenses: Revenue was comparable quarter over quarter while net corporate and other expenses were $1 million higher quarter over quarter. The increase in net corporate and other expenses was driven by higher preference share dividends due to the issuance of First Preference Shares, Series G during the second quarter of 2008, partially offset by lower finance charges. Finance charges decreased quarter over quarter as a result of lower credit facility borrowing levels and lower interest rates charged on the credit facility borrowings, partially offset by the unfavourable impact of foreign exchange associated with the translation of US dollar-denominated interest expense.

REGULATORY HIGHLIGHTS

The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated gas and electric utilities are summarized as follows:



---------------------------------------------------------------------------
---------------------------------------------------------------------------
Nature of Regulation
---------------------------------------------------------------------------
Supportive Features
Allowed --------------------
Common Allowed Returns (%) Future or Historical
Regulated Regulatory Equity ------------------ Test Year Used to
Utility Authority (%) 2007 2008 2009 Set Rates
---------------------------------------------------------------------------
ROE Cost of Service
------------------ ("COS")/ROE
TGI BCUC 35 8.37 8.62 8.47 Performance-based
rate-setting ("PBR")
mechanism through
2009: TGI: 50/50
sharing of earnings
above or below the
allowed ROE

TGVI BCUC 40 9.07 9.32 9.17 TGVI: 100 per cent
retention of
earnings from lower-
than-forecasted
operating and
maintenance costs
but no relief from
increased operating
and maintenance
costs

ROE automatic
adjustment formula
tied to long-term
Canada bond yields
--------------------
Future Test Year
---------------------------------------------------------------------------
FortisBC BCUC 40 8.77 9.02 8.87 COS/ROE

PBR mechanism for
2009 through 2011:
50/50 sharing of
earnings above or
below the allowed
ROE up to an
achieved ROE that is
200 basis points
above or below the
allowed ROE - excess
to deferral account

ROE automatic
adjustment formula
tied to long-term
Canada bond yields
--------------------
Future Test Year
---------------------------------------------------------------------------
Fortis Alberta 37 8.51 8.75 8.51 COS/ROE
Alberta Utilities (1) ROE automatic
Commission adjustment
("AUC") formula tied to
long-term Canada
bond yields
--------------------
Future Test Year
---------------------------------------------------------------------------
Newfound- Newfoundland 45 8.60 8.95 8.95 COS/ROE
land and Labrador +/- +/- +/- ROE automatic
Power Board of 50 bps 50 bps 50 bps adjustment formula
Commissioners tied to long-term
of Public Canada bond yields
Utilities --------------------
("PUB") Future Test Year
---------------------------------------------------------------------------
Maritime Island 40 10.25 10.00 9.75 COS/ROE
Electric Regulatory
and Appeals
Commission --------------------
("IRAC") Future Test Year
---------------------------------------------------------------------------
Fortis- Ontario 43.3 9.00 9.00 8.39 Canadian Niagara
Ontario Energy Power - COS/ROE
Board ("OEB")
(Canadian Cornwall Electric -
Niagara Power) Price cap with
commodity cost flow
Franchise through
Agreement --------------------
(Cornwall Future Test Year -
Electric) beginning in 2009
---------------------------------------------------------------------------
Belize Public ROA Four-year
Electri- Utilities ------------------- COS/ROA agreements
city Commission N/A 10.00- 10.00 10.00
("PUC") 15.00 (2) Additional costs
in the event of a
hurricane would be
deferred and the
Company may apply
for future recovery
in customer rates.
--------------------
Future Test Year
---------------------------------------------------------------------------
Caribbean Electricity N/A 15.00 9.00- 9.00- COS/ROA
Utilities Regulatory 11.00 11.00 Rate-cap adjustment
Authority mechanism based
("ERA") on published
consumer price
indices

Under the new
licences, the
Company may apply
for a special
additional rate to
customers in the
event of a disaster,
including a
hurricane.
--------------------
Historical Test Year
---------------------------------------------------------------------------
Fortis Utility N/A 17.50 17.50 17.50 COS/ROA
Turks makes annual (3) (3) (3)
and filings with If the actual ROA
Caicos the Energy is lower than the
Commission allowed ROA, due to
additional costs
resulting from a
hurricane or other
event, the Company
may apply for an
increase in customer
rates in the
following year.
--------------------
Future Test Year
---------------------------------------------------------------------------
(1) Interim ROE pending the outcome of the AUC's 2009 Generic Cost of
Capital Proceeding
(2) Based on the June 2008 Final Decision related to Belize Electricity's
2008/2009 Rate Application
(3) Amount provided under licence. Actual ROAs achieved in 2007 and 2008
were lower than the ROA allowed under the licence due to significant
investment occurring at the utility.
---------------------------------------------------------------------------
---------------------------------------------------------------------------



---------------------------------------------------------------------------
---------------------------------------------------------------------------
Material Regulatory Decisions and Applications
---------------------------------------------------------------------------
Regulated Utility Summary Description
---------------------------------------------------------------------------
TGI/TGVI - Every three months, TGI and TGVI review natural gas and
propane commodity prices with the BCUC in order to
ensure the flow-through rates charged to customers are
sufficient to cover the cost of purchasing natural gas
and propane. As approved by the BCUC, the commodity
rate for natural gas was unchanged during the first
quarter of 2009 while the commodity rate for propane
decreased, effective January 1, 2009. Effective April
1, 2009, the BCUC approved decreases in the commodity
rates for natural gas and propane. The commodity cost
of natural gas and propane is flowed through to
customers without markup.
- In December 2008, the BCUC approved a basic customer
delivery rate increase of approximately 6 per cent at
TGI and approved customer delivery rate increases
ranging from zero to 5 per cent at TGVI based on rate
class. Basic customer delivery rates for 2009 reflect
the decrease in the allowed ROE for 2009 at TGI and
TGVI to 8.47 per cent and 9.17 per cent, respectively,
resulting from the application of automatic ROE
adjustment mechanisms. TGI filed an application with
the BCUC in the fourth quarter of 2008 requesting
approval to perform extensive rehabilitation of certain
underwater transmission pipeline crossings of the South
Arm of the Fraser River, serving Vancouver and
Richmond. In March 2009, TGI received regulatory
approval for this $27 million project, which is
anticipated to be completed in 2010.
- TGI and TGVI are currently preparing rate applications
related to 2010, which are anticipated to be filed with
the BCUC during the summer of 2009. The BCUC approval
of rates for 2010 and future years will be required as
the current PBR agreements expire at the end of 2009.
In addition, TGI and TGVI will be applying for a review
of the current generic ROE adjustment mechanisms and
the deemed equity component of their capital
structures.
- In April 2009, TGI received approval from the BCUC for
its new $41.5 million Energy Efficiency and
Conservation Program to provide customers with enhanced
tools and incentives to manage their natural gas
consumption, reduce their energy costs and lower their
greenhouse gas emissions. The program is expected to
begin in summer 2009.
---------------------------------------------------------------------------
FortisBC - In December 2008, the BCUC approved the Company's 2009
Revenue Requirements Application, resulting in a
general rate increase of 4.6 per cent, effective
January 1, 2009. The rate increase is primarily the
result of the Company's capital expenditure program and
higher power purchases driven by customer growth and
increased electricity demand. Rates for 2009 reflect
an allowed ROE of 8.87 per cent as a result of the
application of the automatic ROE adjustment mechanism.
The approval of the 2009 Revenue Requirements
Application also included an extension of the PBR
mechanism for the years 2009 through 2011 under terms
similar to the previous PBR agreement, except annual
gross operating and maintenance expenses, before
capitalized overhead, will be set by a formula
incorporating customer growth and inflation, i.e., the
consumer price index ("CPI") for British Columbia minus
a productivity improvement factor ("PIF") of 3 per cent
in 2009, 1.5 per cent in 2010 and 1.5 per cent in 2011.
Should inflation be in excess of 3 per cent, the excess
is to be added to the PIF, which effectively caps the
CPI at 3 per cent.
- In February 2009, the BCUC issued its decision on
FortisBC's 2009 and 2010 Capital Expenditure Plan.
Total gross capital expenditures of $165 million and
$156 million were approved for 2009 and 2010,
respectively. An additional $16 million of capital
expenditures is subject to further regulatory
processes.
---------------------------------------------------------------------------
FortisAlberta - In June 2008, the AUC ruled that a review of ROE
levels, adjustment mechanisms and utility capital
structures in a generic proceeding would be
appropriate. In July 2008, the AUC issued its notice
of application, preliminary scoping document and
minimum filing requirements for the 2009 Generic Cost
of Capital Proceeding. The proceeding applies to all
gas, electric and pipeline utilities in Alberta that
are regulated by the AUC.
- In November 2008, FortisAlberta submitted its evidence
with respect to the 2009 Generic Cost of Capital
Proceeding as requested by the AUC. A hearing is
scheduled for the second quarter of 2009.
- In December 2008, FortisAlberta received regulatory
approval for its 2009 distribution rates to recover
approved distribution costs. The result was a
distribution rate increase of 8.6 per cent, effective
January 1, 2009. The rate increase was slightly higher
than the rate increase of 7.3 per cent contemplated in
the 2008/2009 Negotiated Settlement Agreement ("NSA"),
due to the deferred recovery in customer rates in 2009
of the increase in the allowed ROE to 8.75 per cent in
2008. The approved rates for 2009 also reflect the
impact of the Company's union agreement, which was
settled after the 2008/2009 NSA was approved. As
directed by the AUC, the Company is to continue using
the 2007 allowed ROE of 8.51 per cent for 2009, pending
the outcome of the 2009 Generic Cost of Capital
Proceeding.
- FortisAlberta currently plans to file a comprehensive
application dealing with its future revenue requirement
during the second quarter of 2009.
---------------------------------------------------------------------------
Newfoundland - In November 2008, the PUB approved, as filed, the
Power Company's 2009 Capital Budget Application for
approximately $62 million, with approximately half of
the proposed capital expenditures relating to replacing
aged and deteriorated components of the electricity
system.
- The Company's allowed ROE of 8.95 per cent remains
unchanged for 2009 and, consequently, there has been no
change in basic customer rates for 2009.
- Effective July 1, 2009, subject to regulatory approval,
customer electricity rates are expected to decrease by
6 per cent on average, reflecting the flow through to
customers, by operation of the rate stabilization
account, of variances in the cost of fuel used to
generate electricity that Newfoundland Hydro sells to
Newfoundland Power. The decrease in customer rates
will have no impact on Newfoundland Power's earnings in
2009.
- Newfoundland Power expects to file an application
during 2009 to recover increased costs expected in
2010.
---------------------------------------------------------------------------
Maritime Electric - In March 2009, IRAC approved Maritime Electric's 2009
Rate Application, which resulted in an increase in the
amount of energy-related costs being collected from
customers through the basic rate component of customer
billings, effective April 1, 2009. The increase in the
reference cost of energy in basic rates from 6.73 cents
per kilowatt hour ("kWh") to 7.7 cents per kWh results
in a decrease in the amount of energy costs to be
collected from customers through the operation of the
Energy Cost Adjustment Mechanism ("ECAM").
Additionally, IRAC approved the deferral of Point
Lepreau Nuclear Generating Station replacement energy
costs for 2009 and an increase in the amortization
period of the ECAM to 12 months, effective April 1,
2009. IRAC also approved, as filed, a maximum allowed
ROE of 9.75 per cent for 2009, down from an allowed ROE
of 10.00 per cent for 2008. The overall impact on
residential customer rates for 2009 is an increase of
5.3 per cent based on average consumption of 650 kWh
per month.
---------------------------------------------------------------------------
FortisOntario - In August 2008, Canadian Niagara Power filed a 2009
Cost of Service Application requesting the rebasing of
distribution rates using 2009 as a forward test year.
The application assumes a deemed capital structure of
56.7 per cent debt and 43.3 per cent equity and, as
required by the OEB, reflects a preliminary ROE of 8.39
per cent. The application proposes distribution rate
increases of 4.9 per cent, 9.4 per cent and 7.1 per
cent for Fort Erie, Gananoque and Port Colborne,
respectively, effective May 1, 2009. The proposed
increases are primarily driven by the impact of
distribution system upgrades. The hearing process
associated with the application commenced during the
fourth quarter of 2008.
- In March 2009, the OEB announced that it is initiating
a consultative process with utilities in Ontario that
it regulates to help it determine whether current
economic and financial market conditions warrant an
adjustment to any cost of capital parameter values
determined in accordance with current established
methodology.
- In April 2009, the OEB issued an Interim Rate Order
declaring Canadian Niagara Power's current distribution
electricity rates to continue as interim rates,
effective May 1, 2009.
---------------------------------------------------------------------------
Belize - In June 2008, the PUC issued its Final Decision on
Electricity Belize Electricity's 2008/2009 Rate Application which
rejected most of the recommendations of a PUC-appointed
Independent Expert, engaged to review the PUC's Initial
Decision on Belize Electricity's 2008/2009 Rate
Application, and failed to increase the overall average
electricity rate as requested in the application. The
PUC also ordered a BZ$36 million retroactive adjustment
associated with Belize Electricity's prior years'
financial results. The adjustment, in substance,
represented the disallowance of previously incurred
fuel and purchased power costs. The PUC also reduced
Belize Electricity's targeted allowed ROA to 10 per
cent from 12 per cent through a reduction in the VAD
component of the average electricity rate. As a direct
result of the June 2008 Final Decision, Belize
Electricity recorded an $18 million (BZ$36 million)
charge ($13 million of which was the Corporation's
share) to energy supply costs during the second quarter
of 2008. The Final Decision does not impact the
Corporation's non-regulated generation operations in
Belize.
- The Final Decision also proposed the use of an
automatic mechanism, to be finalized by the PUC, to
adjust monthly, on a two-month lag basis, the cost of
power component of the rate to reflect actual costs of
power. The automatic adjustment mechanism, which was
retroactive effective September 1, 2008, allows for the
collection from, or rebate to, customers of actual
costs of power which vary from a reference cost of
power by more than a threshold of 10 per cent.
- In February 2009, the PUC amended the Final Decision on
Belize Electricity's 2008/2009 Rate Application (the
"Amendment"), effective for the period from January 1,
2009 through June 30, 2009. The Amendment provides for
an increase in the VAD component of the average
electricity rate to allow Belize Electricity to earn a
targeted allowed ROA of 12 per cent but reduces the
reference cost of power component of the average
electricity rate, due to an overall decline in the cost
of power. The Amendment, therefore, allows for an
overall decrease in the average electricity rate from
BZ44.1 cents per kWh to BZ37.5 cents per kWh. The
Amendment also provides for a lower regulated asset
value upon which the allowed ROA is calculated, while
increasing operating expenses by the same amount, and
reduces depreciation, taxes and fees and the related
revenue requirement.
- Changes made in electricity legislation by the
Government of Belize and the PUC, and the June 2008
Final Decision and 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. However, the Supreme Court of Belize has approved
an injunction against the Amendment until Belize
Electricity's appeal of the June 2008 Final Decision is
heard in court.
- In April 2009, Belize Electricity filed its Annual
Tariff Review Application for the annual tariff period
from July 1, 2009 to June 30, 2010 ("2009/2010 Rate
Application") proposing a 6 per cent decrease in the
average electricity rate, as well as a reversal of the
BZ$36 million charge, described above. The PUC has not
accepted the 2009/2010 Rate Application on the grounds
that an Annual Tariff Review Proceeding is not in
effect.
---------------------------------------------------------------------------
Caribbean - In January 2009, a revised Five-Year Capital Investment
Utilities Plan ("CIP") totalling US$246 million was submitted to
the ERA. In March 2009, the ERA approved the Company's
2009 CIP of US$48 million. Capital investment relating
to 2010-2013 is still under review by the ERA.
- In January 2009, Caribbean Utilities announced a
customer-owned renewable energy program. The program
allows customers on Grand Cayman to connect renewable
energy systems to the Company's distribution system and
to generate their own power from renewable energy while
remaining connected to Caribbean Utilities' grid. The
Company has received a number of interested enquiries.
- In April 2009, Caribbean Utilities submitted a report
to the ERA indicating an allowable 2.4 per cent
increase in customer electricity rates, effective June
1, 2009, in accordance with the rate adjustment
mechanism provided under the utility's licence.
---------------------------------------------------------------------------
Fortis Turks - In March 2009, Fortis Turks and Caicos submitted its
and Caicos 2008 annual regulatory filing outlining the Company's
performance in 2008 and its capital expansion plans for
2009.
---------------------------------------------------------------------------
---------------------------------------------------------------------------



CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated
balance sheets between March 31, 2009 and December 31, 2008.

---------------------------------------------------------------------------
---------------------------------------------------------------------------
Fortis Inc.
Significant Changes in the Consolidated Balance Sheets (Unaudited)
between March 31, 2009 and December 31, 2008
---------------------------------------------------------------------------
Increase/
(Decrease)
Balance Sheet Account ($ millions) Explanation
---------------------------------------------------------------------------
Accounts receivable 54 The increase was primarily due to the
impact of a seasonal increase in sales
driven by the Terasen Gas companies and
Newfoundland Power, partially offset by
the impact of lower fuel factor
billings at Caribbean Utilities and
Fortis Turks and Caicos associated with
a decline in fuel prices.
---------------------------------------------------------------------------
Regulatory assets - 608 The increase was primarily due to
current and long- the result of recording $534 million
term in regulatory assets as at March 31,
2009 associated with the recognition of
future income taxes upon adoption of
amended Section 3465, Income Taxes,
effective January 1, 2009. The
remainder of the increase was mainly
due to the regulatory deferral
associated with the change in the fair
market value of the gas commodity swap
and option contracts at the Terasen Gas
companies.
---------------------------------------------------------------------------
Inventories (138) The decrease was driven by the normal
seasonal reduction of gas in storage at
the Terasen Gas companies.
---------------------------------------------------------------------------
Future income tax assets 31 The increase was due to the recognition
- current and long-term of future income taxes upon adoption of
amended Section 3465, Income Taxes,
effective January 1, 2009.
---------------------------------------------------------------------------
Other assets (64) The decrease was driven by a net $61
million reduction associated with the
change to the equity method of
accounting of the Corporation's
interest in the Exploits River Hydro
Partnership ("Exploits Partnership"),
effective February 13, 2009.
Previously, the financial results of
the Exploits Partnership were
consolidated in the financial
statements of the Corporation. Refer
to the "Critical Accounting Estimates -
Contingencies" section of this MD&A for
a further discussion of the Exploits
Partnership.
---------------------------------------------------------------------------
Utility capital assets 144 The increase primarily related to $210
million invested in electricity and gas
systems combined with the impact of
foreign exchange on the translation of
foreign currency-denominated utility
capital assets. The increase was
partially offset by amortization and
customer contributions for the three
months ended March 31, 2009.
---------------------------------------------------------------------------
Goodwill 12 The increase related to the impact of
foreign exchange on the translation of
US dollar-denominated goodwill combined
with an adjustment to goodwill at the
Terasen Gas companies associated with
the adoption of amended Section 3465,
Income Taxes, effective January 1,
2009.
---------------------------------------------------------------------------
Short-term borrowings (149) The decrease was driven by the
repayment of short-term borrowings by
TGI with proceeds from the issuance of
long-term debt combined with lower
borrowings at the Terasen Gas
companies due to seasonality of its
operations.
---------------------------------------------------------------------------
Income taxes payable (29) The decrease was mainly due to the
timing of income tax payments at the
Terasen Gas companies and Newfoundland
Power.
---------------------------------------------------------------------------
Regulatory liabilities - 127 The increase was primarily due to
current and long-term the result of recording $56 million in
regulatory liabilities as at March 31,
2009 associated with the recognition of
future income taxes upon adoption of
amended Section 3465, Income Taxes,
effective January 1, 2009. The
remainder of the increase was due to
the lower commodity cost of natural gas
at the Terasen Gas companies and the
lower cost of fuel and purchased power
at Belize Electricity during the first
quarter of 2009 compared to amounts
collected in customer rates during the
same time period.
---------------------------------------------------------------------------
Future income tax 471 The increase was primarily due to the
liabilities - current and recognition of future income taxes upon
long-term adoption of amended Section 3465,
Income Taxes, effective January 1,
2009.
---------------------------------------------------------------------------
Deferred credits 19 The increase was primarily due to the
reclassification of $19 million to
future income taxes upon adoption of
amended Section, 3465, Income Taxes,
effective January 1, 2009, that were
previously netted against other post-
employment benefit obligations at the
Terasen Gas companies.
---------------------------------------------------------------------------
Long-term debt and 162 The increase was primarily due to the
capital lease issuance of long-term debt and the
obligations (including impact of foreign exchange on the
current portion) translation of foreign currency-
denominated debt, partially offset by a
$61 million decrease associated with
the change to the equity method of
accounting of the Corporation's
interest in the Exploits Partnership,
effective February 13, 2009.
Previously, the financial results of
the Exploits Partnership were
consolidated in the financial
statements of the Corporation. Refer
to the "Critical Accounting Estimates -
Contingencies" section of this MD&A for
a further discussion of the Exploits
Partnership.

In February 2009, TGI issued $100
million of 30-year unsecured
debentures, the net proceeds of which
were used to repay short-term
borrowings. In February 2009,
FortisAlberta also issued $100 million
of 30-year debentures, the net proceeds
of which were used to repay committed
credit facility borrowings and for
general corporate purposes. A decrease
in committed credit facility
borrowings at FortisAlberta was offset
by increased committed credit facility
borrowings at Newfoundland Power and
the Corporation.
---------------------------------------------------------------------------
Shareholders' equity 70 The increase was mainly due to net
earnings applicable to common shares
reported for the three months ended
March 31, 2009, less common share
dividends. The remainder of the
increase related to the issuance of
common shares under the Corporation's
share purchase, dividend reinvestment
and stock option plans and a decrease
in accumulated other comprehensive
loss.
---------------------------------------------------------------------------
---------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

The table below outlines the Corporation's consolidated sources and uses of cash for the first quarter of 2009, as compared to the first quarter of 2008, followed by a discussion of the nature of the variances in cash flows quarter over quarter.



--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Summary of Consolidated Cash Flows (Unaudited)
Quarter Ended March 31
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance
--------------------------------------------------------------------------
Cash, beginning of period 66 58 8
--------------------------------------------------------------------------
Cash provided by (used in)
--------------------------------------------------------------------------
Operating activities 229 193 36
--------------------------------------------------------------------------
Investing activities (210) (148) (62)
--------------------------------------------------------------------------
Financing activities 9 (36) 45
--------------------------------------------------------------------------
Cash, end of period 94 67 27
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Operating Activities: Cash flow from operating activities, after working capital adjustments, was $229 million, $36 million higher than $193 million for the same quarter last year. The increase was driven by FortisAlberta reflecting the impact of the timing of the payment of Alberta Electric System Operator ("AESO") transmission cost accruals in 2008.

Investing Activities: Cash used in investing activities was $62 million higher quarter over quarter. During the first quarter of 2008, TGI received approximately $14 million in proceeds associated with the sale of surplus land. Excluding the impact of the sale of surplus land in 2008, cash used in investing activities was $48 million higher quarter over quarter, driven by higher gross capital expenditures. Gross capital expenditures were $219 million for the first quarter of 2009, $45 million higher than for the same quarter last year. The increase was driven by utility capital asset spending at FortisAlberta, the Terasen Gas companies and Caribbean Utilities.

Financing Activities: Cash provided by financing activities was $9 million during the quarter compared to cash used in financing activities of $36 million during the same quarter in 2008.

Net repayments of short-term borrowings were $150 million during the first quarter of 2009, $117 million higher than net repayments of $33 million during the same quarter in 2008. The net repayments during the first quarter of 2009 were driven by TGI with net proceeds from the issuance of $100 million of unsecured debentures.

Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease obligations and net borrowings (repayments) under committed credit facilities for the first quarter of 2009 compared to the same quarter in 2008 are summarized in the following tables.



--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Quarter Ended March 31
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance
--------------------------------------------------------------------------
Terasen Gas Companies 99 (1) 248 (2) (149)
--------------------------------------------------------------------------
FortisAlberta 99 (3) - 99
--------------------------------------------------------------------------
Other - 2 (2)
--------------------------------------------------------------------------
Total 198 250 (52)
--------------------------------------------------------------------------
(1) Issued February 2009, $100 million 6.55% Unsecured Note Debentures by
TGI, due February 2039. The net proceeds are being used to repay
credit facility borrowings and to repay $60 million of unsecured
debentures that mature in June 2009.
(2) Issued February 2008, $250 million 6.05% Senior Unsecured Debentures by
TGVI, due February 2038. The net proceeds were used to repay committed
credit facility borrowings.
(3) Issued February 2009, $100 million 7.06% Senior Unsecured Debentures,
due February 2039. The net proceeds were used to repay committed
credit facility borrowings and for general corporate purposes.
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Fortis Inc.
Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Quarter Ended March 31
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance
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Fortis Properties (2) (3) 1
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Other (4) (2) (2)
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Total (6) (5) (1)
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Fortis Inc.
Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)
Quarter Ended March 31
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance
--------------------------------------------------------------------------
Terasen Gas Companies - (265) 265
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FortisAlberta (54) 72 (126)
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FortisBC 5 - 5
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Newfoundland Power 30 20 10
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Corporate 24 (38) 62
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Total 5 (211) 216
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Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt issues are used to repay borrowings under the Corporation's committed credit facility.

Proceeds from the issuance of common shares increased $7 million quarter over quarter, reflecting the impact, effective March 1, 2009, of the Corporation's Amended and Restated Dividend Reinvestment and Share Purchase Plan. The plan provides participating common shareholders a 2 per cent discount on the purchase of common shares, issued from treasury, with reinvested dividends.

Common share dividends were $44 million during the first quarter of 2009, up $5 million from the same quarter last year. The increase was primarily due to an increase in the number of common shares outstanding, primarily as a result of the public issuance of 11.7 million common shares in December 2008 and a higher dividend declared per common share compared to the same quarter last year. The dividend declared per common share in the first quarter of 2009 was $0.26, while the dividend declared per common share in the first quarter of 2008 was $0.25.

Preference share dividends increased $3 million quarter over quarter as a result of the dividends associated with the 9.2 million First Preference Shares, Series G that were issued during the second quarter of 2008.

Contractual Obligations: Consolidated contractual obligations of Fortis over the next five years and for periods thereafter, as of March 31, 2009, are outlined in the following table. A detailed description of the nature of the obligations is provided in the MD&A for the year ended December 31, 2008.



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Fortis Inc.
Contractual Obligations (Unaudited)
As at March 31, 2009
--------------------------------------------------------------------------
Total Less than greater greater
or equals than than
($ millions) 1 year 1-3 years 4-5 years 5 years
--------------------------------------------------------------------------
Long-term debt 5,286 234 300 309 4,443
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Brilliant Terminal
Station 62 2 5 5 50
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Gas purchase contract
obligations (based
on index prices as
at March 31, 2009) 265 227 38 - -
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Power purchase
obligations
FortisBC 2,819 39 77 77 2,626
FortisOntario 543 43 94 98 308
Maritime Electric 53 33 2 2 16
Belize Electricity
(1) 297 14 31 32 220
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Capital cost 396 17 40 40 299
--------------------------------------------------------------------------
Joint-use asset and
shared service
agreements 62 3 6 6 47
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Office lease -
FortisBC 19 1 4 2 12
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Operating lease
obligations 162 18 34 28 82
--------------------------------------------------------------------------
Equipment purchase
commitment - Caribbean
Utilities 21 21 - - -
--------------------------------------------------------------------------
Other 18 4 8 5 1
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Total 10,003 656 639 604 8,104
--------------------------------------------------------------------------
(1) Includes a new 15-year power purchase agreement with Belize Aquaculture
Limited ("BAL"). The agreement provides for the supply of up to 15 MW
of capacity by BAL and expires in April 2024.

Other Contractual Obligations:
Caribbean Utilities has a primary fuel supply contract with a major
supplier and is committed to purchase 80 per cent of the Company's fuel
requirements from this supplier for the operation of Caribbean Utilities'
diesel-fired generating plant. The contract is for three years terminating
in April 2010. The remaining approximate quantities, in millions of
imperial gallons, per the contract on an annual basis by fiscal year are:
2009 - 27 and 2010 - 9. The contract contains an automatic renewal clause
for the years 2010 through to 2012. Should any party choose to terminate
the contract within that two-year period, notice must be given a minimum of
one year in advance of the desired termination date.

Fortis Turks and Caicos has a renewable contract with a major supplier for
all of its diesel fuel requirements associated with the generation of
electricity. The approximate fuel requirements under this contract are 12
million imperial gallons per annum.
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Based on the last completion of actuarial valuations, the Corporation's consolidated defined benefit pension plan funding contributions are expected to total approximately $18 million for 2009, $15 million for 2010, and $2 million for each of 2011, 2012 and 2013. These pension funding obligations reflect additional obligations determined under December 31, 2008 actuarial valuations, completed in the first quarter of 2009, associated with the defined benefit pension plans at Newfoundland Power and the Corporation, and under a December 31, 2007 actuarial valuation of a defined benefit pension plan at Terasen, also completed in the first quarter of 2009.

Pension funding obligations for 2010 and beyond may increase pending the next completion of actuarial valuations required as at December 31, 2009 and December 31, 2010 related to the defined benefit pension plans of the larger subsidiaries.

Capital Structure: The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. 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 its customer rates.

The consolidated capital structure of Fortis is presented in the following table.



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Fortis Inc.
Capital Structure (Unaudited)
As at
--------------------------------------------------------------------------
March 31, 2009 December 31, 2008
--------------------------------------------------------------------------
($ millions) (%) ($ millions) (%)
--------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash) (1) 5,453 59.1 5,468 59.5
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Preference shares (2) 667 7.2 667 7.3
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Common shareholders' equity 3,116 33.7 3,046 33.2
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Total 9,236 100.0 9,181 100.0
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(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
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The change in the capital structure was driven by net earnings applicable to common shares, net of common share dividends, of $48 million during the first quarter of 2009.

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)


The credit ratings 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.

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.

During the first quarter of 2009, gross consolidated capital expenditures were $219 million. A breakdown of gross capital expenditures by segment for the first quarter of 2009 is provided in the following table.



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Fortis Inc.
Gross Capital Expenditures (Unaudited) (1)
Quarter Ended March 31, 2009
($ millions)
--------------------------------------------------------------------------
Other
Regula- Total
Tera- ted Regula- Regula-
sen New- Utili- ted ted Non-
Gas Fortis found- ties Utili- Utili- Regula-
Compa- Alberta Fortis- land Cana- ties - ties ted- Fortis
nies (2) BC Power dian Cana- Carib- Utility Proper-
(2) (3) (2) (2) (2) dian bean (4) ties Total
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50 90 22 13 12 187 20 7 5 219
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(1) Relates to utility capital assets, income producing properties and
intangible assets and includes expenditures associated with assets
under construction
(2) Includes asset removal and site restoration expenditures, net of
salvage proceeds, which are permissible in rate base
(3) Includes payments made to the AESO for investment in transmission
capital projects
(4) Includes non-regulated generation, non-regulated gas utility and
Corporate capital expenditures
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Gross consolidated capital expenditures for 2009 are expected to be approximately $1 billion, unchanged from that disclosed in the MD&A for the year ended December 31, 2008. Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts.

There were no significant changes in the overall expected level, nature and timing of certain capital projects from those disclosed in the MD&A for the year ended December 31, 2008, except as described below for FortisAlberta.

FortisAlberta has revised its forecasted capital expenditures related to the replacement of conventional meters with new Automated Meter Infrastructure ("AMI") technology. 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 has contributed to an increase in the expected overall cost of the project to $161 million from $124 million as disclosed in the MD&A for the year ended December 31, 2008.

Over the next five years, consolidated gross capital expenditures are expected to total approximately $4.5 billion. Approximately $3.1 billion of the capital spending is expected to be incurred at the Regulated Electric Utilities, driven by FortisAlberta, FortisBC and the Corporation's regulated utility operations in the Caribbean. Approximately $1.2 billion is expected to be incurred at the Regulated Gas Utilities. Capital expenditures at the Regulated Utilities are subject to regulatory approval. Non-regulated capital expenditures are expected to total approximately $200 million over the same period.

Cash Flow Requirements: At the operating subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of subsidiary operating cash flows, with varying levels of residual cash flow available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, equity injections from Fortis and long-term debt issues.

The Corporation's ability to service its debt obligations and pay dividends on its common and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. Certain regulated subsidiaries may be subject to restrictions which may limit their ability to distribute cash to Fortis. Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation's committed credit facility and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed credit facility may be required from time to time to support the servicing of debt and payment of dividends.

Management expects consolidated long-term debt maturities and repayments to average approximately $170 million annually over the next five years. The combination of available credit facilities and low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing of access to the debt and equity capital markets.

Fortis and its subsidiaries, except for Belize Electricity, were in compliance with debt covenants as at March 31, 2009 and are expected to remain compliant throughout 2009.

As a result of the regulator's Final Decision on Belize Electricity's 2008/2009 Rate Application, Belize Electricity does not meet certain debt covenant financial ratios related to loans totalling $9 million (BZ$14 million), as at March 31, 2009, with the International Bank for Reconstruction and Development and the Caribbean Development Bank. The Company has informed the lenders of the defaults and has requested appropriate waivers. Belize Electricity is also in default of certain debt covenants, which has resulted in the utility being prohibited from incurring new indebtedness or declaring dividends.

As at March 31, 2009, the Corporation and its subsidiaries had consolidated authorized lines of credit of $2.2 billion, of which $1.6 billion was unused, including $544 million unused under the Corporation's $600 million committed revolving credit facility. 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 table outlines the credit facilities of the Corporation and its subsidiaries.



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Fortis Inc.
Credit Facilities (Unaudited)
--------------------------------------------------------------------------

Corporate Total as at Total as at
and Regulated Fortis March 31, December
($ millions) Other Utilities Properties 2009 31, 2008
--------------------------------------------------------------------------
Total credit
facilities 715 1,502 13 2,230 2,228
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Credit facilities
utilized:
--------------------------------------------------------------------------
Short-term
borrowings - (261) - (261) (410)
--------------------------------------------------------------------------
Long-term debt (56) (165) - (221) (224)
--------------------------------------------------------------------------
Letters of credit
outstanding (1) (102) (1) (104) (104)
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Credit facilities
available 658 974 12 1,644 1,490
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At March 31, 2009 and December 31, 2008, certain borrowings under the Corporation's and subsidiaries' credit facilities have been classified as long-term debt. These borrowings are under long-term committed credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.

Regulated Utilities

During the first quarter of 2009, FortisBC negotiated amendments to its $150 million unsecured committed revolving credit facility, including extending the maturity date of the $50 million portion of the facility to May 2012 from May 2011 and extending the maturity date of the $100 million portion of the facility to May 2010 from May 2009. The amended credit facility agreement is expected to be finalized during the second quarter of 2009.

In March 2009, Maritime Electric renegotiated its $50 million demand credit facility and had it converted into a 364-day revolving committed credit facility.

During the second quarter of 2009, Terasen Inc. expects to renegotiate its $100 million committed revolving credit facility that matures in May 2009.

FINANCIAL INSTRUMENTS

The carrying values of financial instruments included in current assets, current liabilities, other assets and deferred credits in the consolidated balance sheets of Fortis approximate their fair value, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments. The fair value of long-term debt is calculated by using quoted market prices when available. When quoted market prices are not available, the fair value is determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills, with similar terms to maturity, plus a market credit risk premium equal to that of issuers of similar credit quality. Since the Corporation does not intend to settle the long-term debt prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs. The fair value of the Corporation's preference shares is determined using quoted market prices.

The carrying and fair values of the Corporation's consolidated long-term debt and preference shares were as follows.



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Fortis Inc.
Financial Instruments (Unaudited)
--------------------------------------------------------------------------
As at March 31, 2009 As at December 31, 2008
--------------------------------------------------------------------------
Estimated Estimated
Carrying Fair Carrying Fair
($ millions) Value Value Value Value
--------------------------------------------------------------------------
Long-term debt, including
current portion (1) 5,251 5,239 5,088 4,959
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Preference shares,
classified as debt (2) 320 327 320 329
--------------------------------------------------------------------------
(1) Carrying value at March 31, 2009 is net of unamortized deferred
financing costs of $35 million (December 31, 2008 - $34 million).
(2) Preference shares classified as equity do not meet the definition of a
financial instrument; however, the estimated fair value of the
Corporation's $347 million preference shares classified as equity was
$303 million as at March 31, 2009 (December 31, 2008: carrying value
$347 million; fair value $268 million).
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Risk Management: The Corporation's earnings from, and net investment in, self-sustaining foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above exposure through the use of US dollar borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange loss or gain on the translation of the Corporation's foreign subsidiaries' earnings, which are denominated in US dollars or a currency pegged to the US dollar. Belize Electricity's reporting currency is the Belizean dollar, while the reporting currency of Caribbean Utilities, FortisUS Energy Corporation, Belize Electric Company Limited, and Fortis Turks and Caicos is the US dollar. The Belizean dollar is pegged to the US dollar at BZ$2.00 equals US$1.00. As at March 31, 2009, all of the Corporation's US$403 million corporately held long-term debt had been designated as a hedge of a portion of the Corporation's foreign net investments. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately held US dollar borrowings designated as hedges are recorded in other comprehensive income and serve to help offset unrealized foreign currency gains and losses on the foreign net investments, which are also recorded in other comprehensive income. As at March 31, 2009, the Corporation had approximately US$125 million in foreign net investments remaining to be hedged.

The Corporation and its subsidiaries also hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas prices through the use of derivative financial instruments. The Corporation and its subsidiaries do not hold or issue derivative financial instruments for trading purposes.

The following table summarizes the valuation of the Corporation's consolidated derivative financial instruments.



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Fortis Inc.
Derivative Financial Instruments (Unaudited)
--------------------------------------------------------------------------
As at March 31, 2009 As at December 31, 2008
--------------------------------------------------------------------------
Estimated Estimated
Term to Number Carrying Fair Carrying Fair
Asset maturity of Value ($ Value ($ Value ($ Value ($
(Liability) (years) Contracts millions) millions) millions) millions)
--------------------------------------------------------------------------
Interest rate less
swaps than 2 2 - - - -
--------------------------------------------------------------------------
Foreign
Exchange
Forward approx.
contract 2 1 8 8 7 7
--------------------------------------------------------------------------
Natural gas
derivatives:
Swaps and Up to
options 2.5 189 (172) (172) (84) (84)
--------------------------------------------------------------------------
Gas purchase
contract Up to
premiums 2.5 32 2 2 (8) (8)
--------------------------------------------------------------------------
--------------------------------------------------------------------------


The interest rate swaps are held by Fortis Properties and are designated as hedges of the cash flow risk related to floating-rate long-term debt and mature in July 2009 and October 2010. The effective portion of changes in the value of the interest rate swaps at Fortis Properties is recorded in other comprehensive income.

The foreign exchange forward contract is held by TGVI and is designated as a hedge of the cash flow risk related to approximately US$55 million required to be paid under a contract for the construction of a liquefied natural gas storage facility. The natural gas derivatives are held by the Terasen Gas companies and are used to fix the effective purchase price of natural gas as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The changes in the fair values of the foreign exchange forward contract and natural gas derivatives are deferred as a regulatory asset or liability, subject to regulatory approval, for recovery from, or refund to, customers in future rates. The fair value of the foreign exchange forward contract was recorded in accounts receivable as at March 31, 2009 and as at December 31, 2008. The fair values of the natural gas derivatives were recorded in accounts payable ($170 million) as at March 31, 2009 (December 31, 2008 - accounts payable $92 million).

The interest rate swaps are valued at the present value of future cash flows based on published forward future interest rate curves. The foreign exchange forward contract is valued using the present value of future cash flows based on published forward future foreign exchange market rate curves. The fair values of the natural gas derivatives reflect the estimated amounts, based on published forward curves, that the Terasen Gas companies would have to receive or pay if forced to settle all outstanding contracts at the balance sheet date.

The fair value of the Corporation's financial instruments, including derivatives, reflects a point-in-time estimate based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future earnings or cash flows.

OFF-BALANCE SHEET ARRANGEMENTS

As at March 31, 2009, the Corporation had no off-balance sheet arrangements such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.

BUSINESS RISK MANAGEMENT

A detailed discussion of the Corporation's significant business risks is provided in the MD&A for the year ended December 31, 2008. There were no changes in the Corporation's significant business risks during the first quarter of 2009 from those disclosed in the MD&A for the year ended December 31, 2008, except for that described below.

Labour Relations: The two collective agreements governing Newfoundland Power's unionized employees represented by the International Brotherhood of Electrical Workers, Local 1620, were ratified by the union in February and April 2009. The collective agreements are effective October 1, 2008 and expire on September 30, 2011.

Impacts of Global Economic Downturn

The significant impacts of the global economic downturn on the Corporation are provided below. The impacts are comparable with those disclosed in the MD&A for the year ended December 31, 2008.

Capital Expenditures: Gross consolidated capital expenditures are expected to be approximately $1 billion for 2009 and $4.5 billion over the next five years. Planned capital expenditures are based on detailed forecasts of customer 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 2009, as a result of the continued downturn in the global economy in 2009. The subsidiaries expect to be able to source the cash required to fund their 2009 capital expenditure programs.

Cost of and Access to Capital: The volatility in the global financial and capital markets may increase the cost of, and affect the timing of issuance of, long-term capital by the Corporation and its utilities in 2009. While the cost of borrowing is expected to increase, as new long-term debt is expected to be issued at higher rates due to an increase in credit spreads, the Corporation and its utilities expect to continue to have reasonable access to capital in the near to medium terms. In February 2009, FortisAlberta and TGI each raised $100 million of 30-year unsecured debentures at 7.06 percent and 6.55 per cent, respectively. The rates obtained were, on average, 100 basis points higher than what would have been obtained during the same period in 2008. 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 have a material financial impact on the Corporation and its utilities in 2009, 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 utilized at the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power have resulted in allowed ROEs that are not reflective of the increased cost of capital exhibited by deteriorating financial market conditions, the result of which may negatively impact the regulated utilities' financial condition, results of operations and cash flows. To address the above, TGI and TGVI will be applying for a review of the current generic ROE adjustment mechanisms and the deemed equity component of their capital structures in conjunction with the filing of their 2010 revenue requirements applications, expected during the summer of 2009. Certain Canadian regulators are starting to review the ROE adjustment mechanisms in light of current financial market conditions. FortisAlberta is currently engaged in a Generic Cost of Capital Proceeding with its regulator to review 2009 ROE calculations and capital structure levels for gas, electric and pipeline utilities in Alberta that are regulated by the AUC. The National Energy Board ("NEB") is also undertaking a review of cost of capital and ROE levels and recently issued a decision increasing the regulated total cost of capital of Trans Quebec & Maritimes Inc. ("TQM"), a Canadian regulated natural gas pipeline utility, which translated into an approximate 100 basis points increase in TQM's allowed ROE for 2008. 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. The NEB is an independent federal agency that regulates several parts of Canada's energy industry. In March 2009, the OEB announced that it is initiating a consultative process with utilities in Ontario that it regulates to help it determine whether current economic and financial market conditions warrant an adjustment to any cost of capital parameter values determined in accordance with current established methodology.

Results of Operations: Achieving organic revenue and earnings growth at Fortis Properties' Hospitality Division may prove challenging in 2009 as a result of the continued downturn in the global economy 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, influence 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. As a result, electricity sales growth at the Corporation's Regulated Caribbean Electric Utilities in 2009 is anticipated to be approximately 3 per cent, down slightly from approximately 4 per cent previously disclosed in the MD&A for the year ended December 31, 2008. Electricity sales growth was approximately 6 per cent for 2008. While tourist arrivals to, and related hotel occupancies in, the Caribbean region for 2009 are expected to be lower than last year, tourists to the region typically are of a high-income bracket and are less affected by a recessionary environment. Consequently, tourist arrivals are expected to persist in 2009; albeit diminished in quantity.

Higher energy prices can result in reduced consumption by 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 decreased approximately 14 per cent during 2008, mainly due to unfavourable market conditions. 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 pension expense. The decline in fair value of the pension plan assets is expected to have the impact of increasing the Corporation's consolidated defined benefit pension plan funding obligations. The full impact of the decrease in the fair value of the pension plan assets on future funding obligations is not determinable until the next completion of actuarial valuations. With the exception of the defined benefit pension plans at Newfoundland Power and the Corporation and one of the defined benefit pension plans at Terasen, the next scheduled actuarial valuations for funding purposes for defined benefit pension plans of the larger subsidiaries are not until December 31, 2009 and December 31, 2010. Based on actuarial valuations completed during the first quarter of 2009 for defined benefit pension plans at Newfoundland Power and the Corporation and one of the defined benefit pension plans at Terasen, consolidated pension funding obligations for 2009 and 2010 are expected to increase by approximately $1 million and $3 million, respectively, and to increase by approximately $2 million in each of 2011, 2012 and 2013 from what was disclosed in the MD&A for the year ended December 31, 2008. 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 discount rates used to determine defined benefit pension expense for 2009 have increased compared to rates used to determine defined benefit pension expense 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. Fortis expects no material increase in its consolidated pension expense for 2009 related to its defined benefit pension plans. The amortization of 2008 losses associated with the pension plan assets is expected to be largely offset by the impact of higher assumed discount rates. Consolidated defined benefit pension plan expense for 2009 will not be materially impacted by the outcome of the actuarial valuations completed for the defined benefit pension plans at Newfoundland Power and the Corporation and one of the defined benefit pension plans at Terasen during the first quarter of 2009.

Any increase in future pension funding requirements and/or pension expense at the regulated utilities is expected to be recovered from, or refunded to, customers in future rates, subject to forecast risk. At the Terasen Gas companies and FortisBC, 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 recent events in the capital markets, 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. To date, the Terasen Gas companies have not experienced any counterparty defaults and they do not expect any counterparties to fail to meet their obligations; however, the credit quality of counterparties, as recent events have indicated, 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: Fortis and its regulated utilities do not anticipate any material adverse rating actions by the credit rating agencies in the near term. However, the current 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. There were no changes in the credit ratings for the Corporation and its currently rated subsidiaries during the first quarter of 2009. During the first quarter of 2009, Moody's confirmed its existing credit ratings for TGVI, Newfoundland Power, FortisAlberta and FortisBC, and S&P confirmed its existing credit ratings for Maritime Electric and Caribbean Utilities.

CHANGES IN ACCOUNTING STANDARDS

Rate-Regulated Operations: Effective January 1, 2009, the Accounting Standards Board ("AcSB") amended: (i) Canadian Institute of Chartered Accountants ("CICA") Handbook Section 1100, Generally Accepted Accounting Principles, removing the temporary exemption providing relief to entities subject to rate regulation from the requirement to apply the Section to the recognition and measurement of assets and liabilities arising from rate regulation; and (ii) Section 3465, Income Taxes to require the recognition of future income tax liabilities and assets, as well as offsetting regulatory assets and liabilities by entities subject to rate regulation.

Effective January 1, 2009, with the removal of the temporary exemption in Section 1100, the Corporation must now apply Section 1100 to the recognition of assets and liabilities arising from rate regulation. Certain assets and liabilities arising from rate regulation continue to have specific guidance under a primary source of Canadian GAAP that applies only to the particular circumstances described therein, including those arising under Section 1600, Consolidated Financial Statements, Section 3061, Property, Plant and Equipment, Section 3465, Income Taxes, and Section 3475, Disposal of Long-Lived Assets and Discontinued Operations. The assets and liabilities arising from rate regulation, as described in Note 4 to the Corporation's 2008 annual audited consolidated financial statements, do not have specific guidance under a primary source of Canadian GAAP. Therefore, Section 1100 directs the Corporation to adopt accounting policies that are developed through the exercise of professional judgment and the application of concepts described in Section 1000, Financial Statement Concepts. In developing these accounting policies, the Corporation may consult other sources, including pronouncements issued by bodies authorized to issue accounting standards in other jurisdictions. Therefore, in accordance with Section 1100, the Corporation has determined that all of its regulatory assets and liabilities qualify for recognition under Canadian GAAP and this recognition is consistent with US Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. Therefore, there was no effect on the Corporation's consolidated financial statements as at January 1, 2009 due to the removal of the temporary exemption from Section 1100.

Effective January 1, 2009, Fortis retroactively recognized future income tax assets and liabilities and related regulatory liabilities and assets, without prior period restatement, for the amount of future income taxes expected to be refunded to, or recovered from, customers in future gas and electricity rates. Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power used the taxes payable method of accounting for income taxes. The effect on the Corporation's consolidated financial statements, as at January 1, 2009, of adopting amended Section 3465, Income Taxes included an increase in total future income tax liabilities and total future income tax assets of $487 million and $15 million, respectively; an increase in regulatory assets and regulatory liabilities of $531 million and $50 million, respectively; and a combined net $9 million increase in other assets, utility capital assets, goodwill, income taxes payable and deferred credits associated with the reclassification of future income taxes that were previously netted against these respective balance sheet items. Included in the future income tax assets and liabilities recorded are the future income tax effects of the subsequent settlement of the related regulatory assets and liabilities through customer rates.

Goodwill and Intangible Assets: Effective January 1, 2009, the Corporation retroactively adopted the new CICA Handbook Section 3064, Goodwill and Intangible Assets. This Section, which replaces Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. As at December 31, 2008, the impact of retroactively adopting Section 3064 was a reclassification of $260 million to intangible assets and related decreases of $258 million to utility capital assets, $1 million to income producing properties and $1 million to other assets, due to the reclassification of the net book value of land, transmission and water rights, computer software costs, franchise costs, customer contracts and other costs.

Credit Risk and the Fair Value of Financial Assets and Financial Liabilities: During the first quarter of 2009, the Corporation adopted the new Emerging Issues Committee ("EIC")-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities, which was issued on January 20, 2009. EIC-173 requires that the Corporation's own credit risk and the credit risk of its counterparties be taken into account in determining the fair value of a financial instrument. As at March 31, 2009, only the Corporation's derivative financial instruments were recorded at fair value, the majority of which were out-of-the-money and recorded as a liability. There was no material effect on the Corporation's interim unaudited consolidated financial statements as a result of adopting EIC-173.

FUTURE ACCOUNTING CHANGES

International Financial Reporting Standards ("IFRS"): In February 2008, the AcSB confirmed that the use of IFRS will be required in 2011 for publicly accountable enterprises in Canada. On June 27, 2008, the Canadian Securities Administrators ("CSA") issued Staff Notice 52-321, Early Adoption of IFRS which indicated that the CSA would be prepared to grant an exemption to allow Canadian financial statement issuers to adopt IFRS early, on a case-by-case basis, provided that they could demonstrate that they met certain conditions. Fortis is not planning to early adopt IFRS. In March 2009, the AcSB issued a second IFRS Omnibus Exposure Draft confirming that publicly accountable enterprises be required to apply IFRS, in full and without modification, on January 1, 2011.

The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by the Corporation for its year ended December 31, 2010 and of the opening balance sheet as at January 1, 2010. The AcSB proposes that CICA Handbook Section 1506, Accounting Changes, paragraph 30, which would require an entity to disclose information relating to a new primary source of GAAP that has been issued, but is not yet effective and that the entity has not applied, not be applied with respect to the IFRS Omnibus Exposure Drafts.

Fortis is continuing to assess the financial reporting impacts of the adoption of IFRS and, at this time, the impact on future financial position and results of operations is not reasonably determinable or estimable. Fortis does anticipate a significant increase in disclosure resulting from the adoption of IFRS and is continuing to assess the level of disclosure required as well as systems changes that may be necessary to gather and process the required information.

Fortis commenced its IFRS conversion project in 2007 and has established a formal project governance structure which includes the audit committees, senior management and project teams from each of the Corporation's subsidiaries. Overall project governance, management and support are coordinated by Fortis Inc. Regular reporting occurs to the Audit Committee of the Board of Directors of Fortis and of the subsidiaries, where appropriate. An external expert advisor has been engaged to assist in the IFRS conversion project.

The Corporation's IFRS conversion project consists of three phases: Scoping and Diagnostics, Analysis and Development, and Implementation and Review.

Phase One: Scoping and Diagnostics, which involved project planning and staffing and identification of differences between current Canadian GAAP and IFRS, has been completed. The resulting identified areas of accounting difference of highest potential impact to Fortis, based on existing IFRS, are rate-regulated accounting; property, plant and equipment; investment property; provisions and contingent liabilities; employee benefits; impairment of assets; income taxes; business combinations; and initial adoption of IFRS under the provisions of IFRS 1, First-Time Adoption of IFRS.

Phase Two: Analysis and Development is nearing completion and involves detailed diagnostics and evaluation of the financial impacts of various options and alternative methodologies provided for under IFRS; identification and design of operational and financial business processes; initial staff and audit committee training; analysis of IFRS 1 optional exemptions and mandatory exceptions to the general requirement for full retrospective application upon transition to IFRS; summarization of 2011 IFRS disclosure requirements; and development of required solutions to address identified issues.

The Corporation has completed a preliminary assessment of the impacts of adopting IFRS; however, a final assessment cannot be completed at this time pending the outcome of the project on rate-regulated activities that was recently added to the International Accounting Standard Board's ("IASB's") technical agenda. The IASB is expected to issue an exposure draft addressing rate-regulated activities during the third quarter of 2009.

It is anticipated that the adoption of IFRS will have an impact on information systems requirements. Each of the Corporation's subsidiaries is assessing the need for system upgrades or modifications to ensure an efficient conversion to IFRS. As part of Phase Two, information systems plans are being prepared for implementation in Phase Three. The extent of the impact on each of the subsidiary's information systems is not reasonably determinable at this time.

Several regulatory authorities with jurisdiction over the Corporation's regulated utilities have begun their own IFRS projects to determine the nature of any changes that should be made in regulatory accounting requirements in response to IFRS. The Corporation's regulated utilities have worked and will continue to work with their respective regulatory authorities to identify transitional issues and suggest how those issues might be addressed.

Phase Three: Implementation and Review, expected to commence mid-year 2009, will involve the execution of changes to information systems and business processes; completion of formal authorization processes to approve recommended accounting policy changes; and further training programs across the Corporation's finance and other affected areas, as necessary. It will culminate in the collection of financial information necessary to compile IFRS-compliant financial statements and reconciliations; embedding of IFRS in business processes and Audit Committee approval of IFRS-compliant financial statements.

Fortis will continue to review all proposed and continuing projects of the IASB, particularly the project on rate-regulated activities that was recently added to the IASB's technical agenda and proposed amendments to IFRS 1 for entities with operations subject to rate regulation, and will participate in any related processes as appropriate.

Business Combinations: In January 2009, the AcSB issued new CICA Handbook Section 1582, Business Combinations, together with Section 1601, Consolidated Financial Statements and Section 1602, Non-controlling Interests. These new standards are effective for fiscal years beginning on or after January 1, 2011. As a result of adopting Section 1582, changes in the determination of the fair value of the assets and liabilities of the acquiree will result in a different calculation of goodwill. Such changes include the expensing of acquisition-related costs incurred during a business acquisition, rather than recording them as a capital transaction, and the disallowance of recording restructuring accruals. Section 1582 will affect the recognition of business combinations completed by the Corporation on or after January 1, 2011 and, as a result, may have a material impact on the Corporation's consolidated earnings and financial position.

Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The adoption of Sections 1601 and 1602 will result in non-controlling interests being presented as a component of equity, rather than as a liability, on the consolidated balance sheet.

Also, net earnings and components of other comprehensive income attributable to the owners of the parent and to the non-controlling interests are required to be separately disclosed on the statement of earnings. The adoption of Sections 1601 and 1602 is not expected to have a material impact on the Corporation's consolidated earnings, cash flows or financial position.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Corporation's interim unaudited consolidated financial statements in accordance with Canadian GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period they become known.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2009 from those disclosed in the Corporation's MD&A for the year ended December 31, 2008, except for that described below related to the accounting for income taxes and contingencies.

Income Taxes: Income taxes are determined based on estimates of the Corporation's current income taxes and estimates of future income taxes resulting from temporary differences between the carrying value of assets and liabilities in the consolidated financial statements and their tax values. The use of estimation with respect to recording future income taxes has increased due to the adoption by the Corporation of amended CICA Handbook Section 3465, Income Taxes, effective January 1, 2009. A future income tax asset or liability is determined for each temporary difference based on the future tax rates that are expected to be in effect and management's assumptions regarding the expected timing of the reversal of such temporary differences. Future income tax assets are assessed for the likelihood that they will be recovered from future taxable income. To the extent recovery is not considered more likely than not, a valuation allowance is recorded and charged against earnings in the period that the allowance is created or revised. Estimates of the provision for income taxes, future income tax assets and liabilities and any related valuation allowance might vary from actual amounts incurred.

Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with ordinary course business operations. Management believes that the amount of liability, if any, from these actions would not have a material effect on the Corporation's financial position or results of operations. There were no material changes in the Corporation's contingent liabilities during the three months ended March 31, 2009 from those disclosed in the MD&A for the year ended December 31, 2008, except as disclosed below.

Exploits Partnership

Following the announcement by Abitibi of its intention to close its Grand Falls-Windsor newsprint mill on March 31, 2009, the Government of Newfoundland and Labrador expropriated most of the Newfoundland-based assets of Abitibi. The expropriated assets included the hydroelectric generating facility assets of the Exploits Partnership. The Exploits Partnership is owned 51 per cent by Fortis Properties and 49 per cent by Abitibi.

The Exploits Partnership had previously incurred a term loan from several lenders to finance its assets. As at December 31, 2008, approximately $61 million remained outstanding under this term loan. The term loan is without recourse to Fortis or Abitibi, as partners of the Exploits Partnership, and is secured by both the hydroelectric generating assets and related agreements regarding rights to operate and sell power to Newfoundland Hydro during the term of the loan. Although the expropriation has caused the Exploits Partnership to default on the term loan, to date the lenders have not demanded accelerated repayment of the term loan. The Exploits Partnership made the scheduled term loan payment for the quarter ended March 31, 2009. As at March 31, 2009, the balance outstanding under the term loan was approximately $60 million.

The generation and sale of electricity by the Exploits Partnership continued in the normal course until the newsprint mill closed on February 12, 2009, up to which point Newfoundland Hydro paid the Exploits Partnership for the energy produced on the same basis as the pre-expropriation power purchase agreement. Payment for all energy delivered since February 13, 2009 is currently outstanding from the Government of Newfoundland and Labrador pending resolution of expropriation matters. The day-to-day operations of the hydroelectric generating facilities have been assumed by Nalcor Energy, a crown corporation, as the agent for the Government of Newfoundland and Labrador with respect to this matter.

On March 24, 2009, the Government of Newfoundland and Labrador announced that Abitibi had discontinued discussions with Nalcor Energy regarding compensation for the expropriated assets. Abitibi, which was incorporated in the US, has also indicated that it intends to challenge the expropriation of its assets and seek compensation through the North American Free Trade Agreement.

Historically, the financial statements of the Exploits Partnership were consolidated in the financial statements of Fortis. Pending resolution of the above matters, deferred financing costs of $2 million and utility capital assets of $61 million related to the Exploits Partnership were reclassified to other assets and the $61 million term loan was reclassified as current on the consolidated balance sheet of Fortis as at December 31, 2008.

During the quarter, the combination of uncertainty created by the expropriation and the loss of control over cash flows of the Exploits Partnership has required Fortis to commence reporting its investment in the Exploits Partnership using the equity method of accounting, effective February 13, 2009. Consequently, the assets and liabilities of the Exploits Partnership are no longer consolidated in the accounts of Fortis. Equity earnings recognized during the first quarter of 2009 were equivalent to the amount that would have been recognized in the absence of the expropriation. This approach is consistent with the public statement of the Government of Newfoundland and Labrador that it is not its intention to adversely affect the business interests of lenders or independent partners of Abitibi.

QUARTERLY RESULTS

The following table sets forth unaudited quarterly information for each of the eight quarters ended June 30, 2007 through March 31, 2009. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements which, in the opinion of management, have been prepared in accordance with Canadian GAAP and as required by utility regulators. The timing of the recognition of certain assets, liabilities, revenue and expenses, as a result of regulation, may differ from that otherwise expected using Canadian GAAP for non-regulated entities. The differences and nature of regulation are disclosed in Notes 2 and 4 to the Corporation's 2008 annual audited consolidated financial statements. The quarterly operating results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.



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Fortis Inc.
Summary of Quarterly Results (Unaudited)
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Net Earnings
Applicable
to Common
Revenue Shares Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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March 31, 2009 1,201 92 0.54 0.52
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December 31, 2008 1,182 76 0.48 0.46
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September 30, 2008 727 49 0.31 0.31
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June 30, 2008 848 29 0.19 0.18
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March 31, 2008 1,146 91 0.58 0.55
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December 31, 2007 1,018 79 0.51 0.49
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September 30, 2007 651 31 0.20 0.20
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June 30, 2007 566 41 0.31 0.27
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A summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Given the diversified group of companies, seasonality may vary. Financial results from May 17, 2007 were impacted by the acquisition of Terasen. Virtually all of the annual earnings of the Terasen Gas companies are generated in the first and fourth quarters. Financial results for the second quarter ended June 30, 2008 reflected the $13 million unfavourable impact to Fortis of a charge recorded at Belize Electricity as a result of the June 2008 regulatory rate decision. Due to a shift in the quarterly distribution of annual purchased power expense at Newfoundland Power, the utility's earnings in 2008 were lower in the first and fourth quarters and higher in the second and third quarters compared to the same periods in 2007. Newfoundland Power's annual earnings were not impacted by the shift in the quarterly distribution of annual purchased power expense. Financial results from August 1, 2007 were impacted by the acquisition of the Delta Regina in Saskatchewan and from November 2008 were impacted by the acquisition of the Sheraton Hotel Newfoundland.

March 31, 2009/March 31, 2008 - Net earnings applicable to common shares were $92 million, or $0.54 per common share, for the first quarter of 2009, compared to earnings of $91 million, or $0.58 per common share, for the first quarter of 2008. Results were driven by growth in electrical infrastructure investment and customers at the Regulated Electric Utilities in western Canada, partially offset by lower earnings at the Caribbean Regulated Utilities and Fortis Properties. Excluding one-time gains of approximately $2 million at Fortis Turks and Caicos, earnings at the Caribbean Regulated Utilities were $3 million lower quarter over quarter, resulting from reduced electricity sales attributable to cooler weather and the impact of the global economic downturn on energy demand combined with the lower allowed ROAs at Caribbean Utilities and Belize Electricity. The decrease was partially mitigated by the favourable impact of foreign exchange rates associated with the strengthening US dollar quarter over quarter. Fortis Properties' results were reduced by one-time transitional operating costs associated with the Sheraton Hotel Newfoundland, acquired in November 2008, and the impact of lower hotel occupancies.

December 31, 2008/December 31, 2007 - Net earnings applicable to common shares were $76 million, or $0.48 per common share, for the fourth quarter of 2008 compared to earnings of $79 million, or $0.51 per common share, for the fourth quarter of 2007. Fourth quarter results for 2007 were favourably impacted by one-time items totalling approximately $13 million related to: (i) the sale of surplus land at TGI; (ii) the reduction of future income tax liability balances at Fortis Properties related to lower enacted corporate income tax rates; and (iii) an interconnection agreement-related refund at FortisOntario. Excluding these one-time items, earnings were $10 million higher quarter over quarter. The increase was driven by stronger performance and lower corporate taxes at FortisAlberta, lower corporate expenses and $1 million of additional earnings from Caribbean Utilities related to a change in the utility's fiscal year end. The increase was partially offset by the impact of: (i) a lower allowed ROA at Belize Electricity, effective July 1, 2008; (ii) an approximate $1 million loss of revenue at Fortis Turks and Caicos related to Hurricane Ike; and (iii) an approximate $2 million reduction in fourth quarter earnings at Newfoundland Power associated with a shift in the quarterly distribution of the utility's annual purchased power expense.

September 30, 2008/September 30, 2007 - Net earnings applicable to common shares were $49 million, or $0.31 per common share, for the third quarter of 2008 compared to earnings of $31 million, or $0.20 per common share, for the third quarter of 2007. Third quarter 2008 results included a tax reduction of approximately $7.5 million associated with the settlement of historical corporate tax matters at Terasen. Excluding the tax reduction at Terasen, earnings for the third quarter of 2008 were $41.5 million or $0.26 per common share. Excluding the above one-time item, growth in earnings quarter over quarter was mainly due to higher earnings at Newfoundland Power associated with a shift in the quarterly distribution of annual purchased power expense, higher non-regulated hydroelectric production, increased earnings at FortisBC primarily due to lower energy supply costs and higher earnings at FortisAlberta mainly due to higher corporate tax recoveries. The increase was partially offset by lower earnings at Caribbean Regulated Utilities driven by a 3.25 per cent reduction in basic electricity rates at Caribbean Utilities, a lower allowed ROA at Belize Electricity and a loss of revenue at Fortis Turks and Caicos due to the impact of Hurricane Ike.

June 30, 2008/June 30, 2007 - Net earnings applicable to common shares were $29 million, or $0.19 per common share, for the second quarter of 2008 compared to earnings of $41 million, or $0.31 per common share, for the second quarter of 2007. Second quarter 2008 results included a $13 million, or $0.08 per common share, charge representing the Corporation's approximate 70 per cent share of disallowed previously incurred fuel and purchased power costs at Belize Electricity, as well as a $2 million one-time charge at FortisOntario associated with repayment of interconnection-agreement related amounts received in the fourth quarter of 2007. Excluding the above one-time items, earnings for the second quarter of 2008 were $44 million compared to $41 million for the second quarter of 2007. Earnings were favourably impacted by a full quarter of earnings' contribution from the Terasen Gas companies, higher earnings at Newfoundland Power associated with a shift in the quarterly distribution of annual purchased power expense, increased non-regulated hydroelectric production and improved performance at Fortis Properties. Partially offsetting those items were lower earnings at FortisAlberta associated with higher corporate income taxes and higher corporate financing costs associated with the Terasen acquisition.

OUTLOOK

Gross consolidated capital expenditures are estimated to be approximately $1 billion in 2009 and approximately $4.5 billion over the next five years. The Corporation's capital program is expected to drive growth in earnings and dividends.

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

OUTSTANDING SHARE DATA

As at April 29, 2009, the Corporation had issued and outstanding 169.8 million common shares; 5.0 million First Preference Shares, Series C; 8.0 million First Preference Shares, Series E; 5.0 million First Preference Shares, Series F; and 9.2 million First Preference Shares, Series G. Only the common shares of the Corporation have voting rights.

The number of common shares of Fortis that would be issued if all outstanding stock options, convertible debt and First Preference Shares, Series C and E were converted as at April 29, 2009 is as follows:



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Fortis Inc.
Conversion of Securities into Common Shares (Unaudited)
As at April 29, 2009
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Security Number of Common Shares (millions)
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Stock Options 5.1
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Convertible Debt 1.4
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First Preference Shares, Series C 5.8
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First Preference Shares, Series E 9.2
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Total 21.5
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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 website at www.fortisinc.com.



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

March 31 December 31
2009 2008
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(Note 2)
ASSETS

Current assets
Cash and cash equivalents $94 $66
Accounts receivable 735 681
Prepaid expenses 15 17
Regulatory assets (Note 5) 232 157
Inventories (Note 6) 91 229
Future income taxes (Note 14) 34 -
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1,201 1,150

Other assets 166 230
Regulatory assets (Note 5) 736 203
Future income taxes (Note 14) 51 54
Utility capital assets 7,301 7,157
Income producing properties 544 540
Intangible assets (Note 7) 262 269
Goodwill 1,587 1,575
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$11,848 $11,178
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LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
Short-term borrowings (Note 19) $261 $410
Accounts payable and accrued charges 870 874
Dividends payable 47 47
Income taxes payable 37 66
Regulatory liabilities (Note 5) 101 45
Current installments of long-term debt and capital
lease obligations (Note 8) 236 240
Future income taxes (Note 14) 16 15
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1,568 1,697

Deferred credits 296 277
Regulatory liabilities (Note 5) 472 401
Future income taxes (Note 14) 531 61
Long-term debt and capital lease obligations
(Note 8) 5,050 4,884
Non-controlling interest 148 145
Preference shares 320 320
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8,385 7,785
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Shareholders' equity
Common shares (Note 9) 2,462 2,449
Preference shares 347 347
Contributed surplus 9 9
Equity portion of convertible debentures 6 6
Accumulated other comprehensive loss (Note 11) (43) (52)
Retained earnings 682 634
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3,463 3,393
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$11,848 $11,178
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Contingent liabilities and commitments (Note 20)

See accompanying Notes to interim consolidated financial statements.



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

Quarter Ended
2009 2008
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Revenue $1,201 $1,146
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Expenses
Energy supply costs 707 668
Operating 192 179
Amortization 91 83
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990 930
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Operating income 211 216

Finance charges (Note 13) 88 91
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Earnings before corporate taxes and non-controlling
interest 123 125

Corporate taxes (Note 14) 25 29
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Net earnings before non-controlling interest 98 96

Non-controlling interest 2 4
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Net earnings 96 92

Preference share dividends 4 1
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Net earnings applicable to common shares $92 $91
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Earnings per common share (Note 9)
Basic $0.54 $0.58
Diluted $0.52 $0.55
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See accompanying Notes to interim consolidated financial statements.



Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)

Quarter Ended
2009 2008
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Balance at beginning of period $634 $551

Net earnings applicable to common shares 92 91
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726 642

Dividends on common shares (44) (39)
-------------------------------------------------------------------------

Balance at end of period $682 $603
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See accompanying Notes to interim consolidated financial statements.



Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)

Quarter Ended
2009 2008
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Net earnings $96 $92
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Other comprehensive income
Unrealized foreign currency translation gains on
net investments in self-sustaining foreign operations 24 16
Losses on hedges of net investments in self-sustaining
foreign operations (18) (14)
Corporate tax recovery 3 2
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Change in unrealized foreign currency translation
gains, net of hedging activities and tax (Note 11) 9 4
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Comprehensive income $105 $96
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See accompanying Notes to interim consolidated financial statements.



Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)

Quarter Ended
2009 2008
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Operating activities
Net earnings $96 $92
Items not affecting cash
Amortization - utility capital assets and
income producing properties 79 74
Amortization - intangible assets 11 9
Amortization - other 1 -
Future income taxes (Note 14) 3 3
Non-controlling interest 2 4
Other (3) (5)
Change in long-term regulatory assets and liabilities 9 9
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198 186
Change in non-cash operating working capital 31 7
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229 193
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Investing activities
Change in other assets and deferred credits (7) (1)
Capital expenditures - utility capital assets (210) (165)
Capital expenditures - income producing properties (5) (3)
Capital expenditures - intangible assets (4) (6)
Contributions in aid of construction 16 12
Proceeds on sale of capital assets - 15
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(210) (148)
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Financing activities
Change in short-term borrowings (150) (33)
Proceeds from long-term debt, net of issue costs 198 250
Repayments of long-term debt and capital lease
obligations (6) (5)
Net borrowings (repayments) under committed credit
facilities 5 (211)
Issue of common shares, net of costs 13 6
Dividends
Common shares (44) (39)
Preference shares (4) (1)
Subsidiary dividends paid to non-controlling
interest (3) (3)
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9 (36)
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Change in cash and cash equivalents 28 9

Cash and cash equivalents, beginning of period 66 58
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Cash and cash equivalents, end of period $94 $67
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Supplementary information to consolidated statements of cash flows (Note
16)

See accompanying Notes to interim consolidated financial statements.



FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three months ended March 31, 2009 and 2008
(unless otherwise stated)
(Unaudited)


1. DESCRIPTION OF THE BUSINESS

Nature of Operations

Fortis Inc. ("Fortis" or the "Corporation") is principally an international distribution utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated generation, and commercial real estate and hotels, which are treated as two separate segments. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the Corporation's long-term objectives. Each reporting segment operates as an autonomous unit, assumes profit and loss responsibility and is accountable for its own resource allocation.

The following summary describes the operations included in each of the Corporation's reportable segments.

REGULATED UTILITIES

The following summary describes the Corporation's interests in regulated gas and electric utilities in Canada and the Caribbean by utility:

Regulated Gas Utilities - Canadian

Terasen Gas Companies: Includes Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island) Inc. ("TGVI"), and Terasen Gas (Whistler) Inc. ("TGWI").

TGI is the largest distributor of natural gas in British Columbia, serving primarily residential, commercial and industrial customers in a service area that extends from Vancouver to the Fraser Valley and the interior of British Columbia.

TGVI owns and operates the natural gas transmission pipeline from the Greater Vancouver area across the Georgia Strait to Vancouver Island and the distribution system on Vancouver Island and along the Sunshine Coast of British Columbia, serving primarily residential, commercial and industrial customers.

In addition to providing transmission and distribution services to customers, TGI and TGVI also obtain natural gas supplies on behalf of most residential and commercial customers. Gas supplies are sourced primarily from northeastern British Columbia and, through TGI's Southern Crossing Pipeline, from Alberta.

TGWI owns and operates the propane distribution system in Whistler, British Columbia, providing service to mainly residential and commercial customers.

Regulated Electric Utilities - Canadian

a. FortisAlberta: FortisAlberta owns and operates the electricity distribution system in a substantial portion of southern and central Alberta.

b. FortisBC: Includes FortisBC Inc., an integrated electric utility operating in the southern interior of British Columbia. FortisBC Inc. owns four hydroelectric generating facilities with a combined capacity of 223 megawatts ("MW"). Included with the FortisBC component of the Regulated Electric Utilities - Canadian segment are the operating, maintenance and management services relating to the 450-MW Waneta hydroelectric generating facility owned by Teck Cominco Metals Ltd., the 269-MW Brilliant Hydroelectric Plant owned by Columbia Power Corporation and the Columbia Basin Trust ("CPC/CBT"), the 185-MW Arrow Lakes Hydroelectric Plant owned by CPC/CBT and the distribution system owned by the City of Kelowna.

c. Newfoundland Power: Newfoundland Power is the principal distributor of electricity in Newfoundland. Newfoundland Power has an installed generating capacity of 140 MW, of which 97 MW is hydroelectric generation.

d. Other Canadian: Includes Maritime Electric and FortisOntario. Maritime Electric is the principal distributor of electricity on Prince Edward Island. Maritime Electric also maintains on-Island generating facilities with a combined capacity of 150 MW. FortisOntario provides integrated electric utility service to customers in Fort Erie, Cornwall, Gananoque and Port Colborne in Ontario. FortisOntario's operations primarily include Canadian Niagara Power Inc. and Cornwall Street Railway, Light and Power Company, Limited. Included in Canadian Niagara Power's accounts is the operation of the electricity distribution business of Port Colborne Hydro Inc., which has been leased from the City of Port Colborne under a ten-year lease agreement that expires in April 2012.

Regulated Electric Utilities - Caribbean

a. Belize Electricity: Belize Electricity is the principal distributor of electricity in Belize, Central America. The Company has an installed generating capacity of 34 MW. Fortis holds an approximate 70 per cent controlling ownership interest in Belize Electricity.

b. Caribbean Utilities: Caribbean Utilities is the sole provider of electricity on Grand Cayman, Cayman Islands. The Company has an installed generating capacity of 137 MW. Fortis has an approximate 57 per cent controlling ownership interest in Caribbean Utilities. Caribbean Utilities is a public company traded on the Toronto Stock Exchange (TSX:CUP.U). Previously, Caribbean Utilities had an April 30 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 31. The change in Caribbean Utilities' fiscal year end eliminates the previous two-month lag in consolidating Caribbean Utilities' financial results.

c. Fortis Turks and Caicos: Includes P.P.C. Limited and Atlantic Equipment & Power (Turks and Caicos) Ltd. Fortis Turks and Caicos is the principal distributor of electricity on the Turks and Caicos Islands. The Company has a combined diesel-fired generating capacity of 51 MW.

NON-REGULATED - FORTIS GENERATION

a. Belize: Operations consist of the 25-MW Mollejon and 7-MW Chalillo hydroelectric generating facilities in Belize. All of the output of these facilities is sold to Belize Electricity under a 50-year power purchase agreement expiring in 2055. The hydroelectric generation operations in Belize are conducted through the Corporation's indirect wholly owned subsidiary Belize Electric Company Limited ("BECOL") under a franchise agreement with the Government of Belize.

b. Ontario: Includes 75 MW of water-right entitlement associated with the Niagara Exchange Agreement, which expires April 30, 2009; a 5-MW gas-fired cogeneration plant in Cornwall; and six small hydroelectric generating stations in eastern Ontario with a combined capacity of 8 MW.

c. Central Newfoundland: Through the Exploits River Hydro Partnership ("Exploits Partnership"), a partnership between the Corporation, through its wholly owned subsidiary Fortis Properties, and AbitibiBowater Inc., formerly Abitibi-Consolidated Company of Canada ("Abitibi"), 36 MW of additional capacity was developed and installed at two of Abitibi's hydroelectric generating plants in central Newfoundland. Fortis Properties holds directly a 51 per cent interest in the Exploits Partnership and Abitibi holds the remaining 49 per cent interest. The Exploits Partnership sells its output to Newfoundland and Labrador Hydro Corporation ("Newfoundland Hydro") under a 30-year power purchase agreement expiring in 2033. Effective February 13, 2009, Fortis commenced accounting for its investment in the Exploits Partnership using the equity method of accounting. Previously, the Corporation consolidated the financial results of the Exploits Partnership in its financial statements (Note 20).

d. British Columbia: Includes the 16-MW run-of-river Walden hydroelectric power plant near Lillooet, British Columbia. This plant sells its entire output to BC Hydro under a long-term contract expiring in 2013.

e. Upper New York State: Includes the operations of four hydroelectric generating stations in Upper New York State, with a combined capacity of approximately 23 MW, operating under licences from the US Federal Energy Regulatory Commission. Hydroelectric generation operations in Upper New York State are conducted through the Corporation's indirect wholly owned subsidiary FortisUS Energy Corporation ("FortisUS Energy").

NON-REGULATED - FORTIS PROPERTIES

Including a hotel acquired in Ontario in April 2009, Fortis Properties owns 21 hotels with more than 4,000 rooms in eight Canadian provinces and approximately 2.8 million square feet of commercial real estate primarily in Atlantic Canada.

CORPORATE AND OTHER

The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment. This segment primarily includes finance charges, including interest on debt incurred directly by Fortis and Terasen Inc. ("Terasen") and dividends on preference shares classified as long-term liabilities; dividends on preference shares classified as equity; other corporate expenses, including Fortis and Terasen corporate operating costs, net of recoveries from subsidiaries; interest and miscellaneous revenues; and corporate income taxes.

Also included in the Corporate and Other segment are the financial results of CustomerWorks Limited Partnership ("CWLP"). CWLP is a non-regulated shared-services business in which Terasen holds a 30 per cent interest. CWLP operates in partnership with Enbridge Inc. and provides customer service contact, meter reading, billing, credit, and support and collection services to the Terasen Gas companies and several smaller third parties. CWLP's financial results are recorded using the proportionate consolidation method of accounting. While currently not significant, financial results of Terasen Energy Services Inc. ("TES") are also reported in the Corporate and Other segment. TES is a non-regulated wholly owned subsidiary of Terasen that provides alternative energy solutions.


2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These interim consolidated financial statements should be read in conjunction with the Corporation's 2008 annual audited consolidated financial statements. Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Virtually all of the annual earnings of the Terasen Gas companies are generated in the first and fourth quarters due to seasonality of the business. Given the diversified group of companies, seasonality may vary.

All amounts are presented in Canadian dollars unless otherwise stated.

These interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") for interim financial statements, following the same accounting policies and methods as those used in preparing the Corporation's 2008 annual audited consolidated financial statements, except as described below.

Effective January 1, 2009, the Corporation adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA").

Rate-Regulated Operations

Effective January 1, 2009, the Accounting Standards Board of Canada ("AcSB") amended: (i) CICA Handbook Section 1100, Generally Accepted Accounting Principles, removing the temporary exemption providing relief to entities subject to rate regulation from the requirement to apply the Section to the recognition and measurement of assets and liabilities arising from rate regulation; and (ii) Section 3465, Income Taxes to require the recognition of future income tax liabilities and assets, as well as offsetting regulatory assets and liabilities by entities subject to rate regulation.

Effective January 1, 2009, with the removal of the temporary exemption in Section 1100, the Corporation must now apply Section 1100 to the recognition of assets and liabilities arising from rate regulation. Certain assets and liabilities arising from rate regulation continue to have specific guidance under a primary source of Canadian GAAP that applies only to the particular circumstances described therein, including those arising under Section 1600, Consolidated Financial Statements, Section 3061, Property, Plant and Equipment, Section 3465, Income Taxes, and Section 3475, Disposal of Long-Lived Assets and Discontinued Operations. The assets and liabilities arising from rate regulation, as described in Note 4 to the Corporation's 2008 annual audited consolidated financial statements, do not have specific guidance under a primary source of Canadian GAAP. Therefore, Section 1100 directs the Corporation to adopt accounting policies that are developed through the exercise of professional judgment and the application of concepts described in Section 1000, Financial Statement Concepts. In developing these accounting policies, the Corporation may consult other sources, including pronouncements issued by bodies authorized to issue accounting standards in other jurisdictions. Therefore, in accordance with Section 1100, the Corporation has determined that all of its regulatory assets and liabilities qualify for recognition under Canadian GAAP and this recognition is consistent with US Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. Therefore, there was no effect on the Corporation's consolidated financial statements as at January 1, 2009 due to the removal of the temporary exemption from Section 1100.

Effective January 1, 2009, Fortis retroactively recognized future income tax assets and liabilities and related regulatory liabilities and assets, without prior period restatement, for the amount of future income taxes expected to be refunded to, or recovered from, customers in future gas and electricity rates. Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power used the taxes payable method of accounting for income taxes. The effect on the Corporation's consolidated financial statements, as at January 1, 2009, of adopting amended Section 3465, Income Taxes included an increase in total future income tax liabilities and total future income tax assets of $487 million and $15 million, respectively; an increase in regulatory assets and regulatory liabilities of $531 million and $50 million, respectively; and a combined net $9 million increase in other assets, utility capital assets, goodwill, income taxes payable and deferred credits associated with the reclassification of future income taxes that were previously netted against these respective balance sheet items. Included in the future income tax assets and liabilities recorded are the future income tax effects of the subsequent settlement of the related regulatory assets and liabilities through customer rates.

Goodwill and Intangible Assets

Effective January 1, 2009, the Corporation retroactively adopted the new CICA Handbook Section 3064, Goodwill and Intangible Assets. This Section, which replaces Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. As at December 31, 2008, the impact of retroactively adopting Section 3064 was a reclassification of $260 million to intangible assets and related decreases of $258 million to utility capital assets, $1 million to income producing properties and $1 million to other assets due to the reclassification of the net book value of land, transmission and water rights, computer software costs, franchise costs, customer contracts and other costs.

Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

During the first quarter of 2009, the Corporation adopted the new Emerging Issues Committee ("EIC")-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities, which was issued on January 20, 2009. EIC-173 requires that the Corporation's own credit risk and the credit risk of its counterparties be taken into account in determining the fair value of a financial instrument. As at March 31, 2009, only the Corporation's derivative financial instruments were recorded at fair value, the majority of which were out-of-the-money and recorded as a liability. There was no material effect on the Corporation's interim consolidated financial statements as a result of adopting EIC-173.


3. FUTURE ACCOUNTING CHANGES

International Financial Reporting Standards ("IFRS")

In February 2008, the AcSB confirmed that the use of IFRS will be required in 2011 for publicly accountable enterprises in Canada. In March 2009, the AcSB issued a second Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to apply IFRS, in full and without modification, on January 1, 2011. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by the Corporation for its year ended December 31, 2010 and of the opening balance sheet as at January 1, 2010. The AcSB proposes that CICA Handbook Section 1506, Accounting Changes, paragraph 30, which would require an entity to disclose information relating to a new primary source of GAAP that has been issued but is not yet effective and that the entity has not applied, not be applied with respect to this Exposure Draft. Fortis is continuing to assess the financial reporting impacts of the adoption of IFRS, including monitoring any International Accounting Standards Board ("IASB") initiatives with the potential to impact rate-regulated accounting under IFRS. The IASB is expected to issue an exposure draft addressing rate-regulated activities during the third quarter of 2009. At this time, the impact on future financial position and results of operations is not reasonably determinable or estimable. Fortis does anticipate a significant increase in disclosure resulting from the adoption of IFRS and is continuing to assess the level of disclosure required, as well as system changes that may be necessary to gather and process the information.

Business Combinations

In January 2009, the AcSB issued new CICA Handbook Section 1582, Business Combinations, together with Section 1601, Consolidated Financial Statements and Section 1602, Non-controlling Interests. These new standards are effective for fiscal years beginning on or after January 1, 2011. As a result of adopting Section 1582, changes in the determination of the fair value of the assets and liabilities of the acquiree will result in a different calculation of goodwill. Such changes include the expensing of acquisition-related costs incurred during a business acquisition, rather than recording them as a capital transaction, and the disallowance of recording restructuring accruals. Section 1582 will affect the recognition of business combinations completed by the Corporation on or after January 1, 2011 and, as a result, may have a material impact on the Corporation's consolidated earnings and financial position.

Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The adoption of Sections 1601 and 1602 will result in non-controlling interests being presented as a component of equity, rather than as a liability, on the consolidated balance sheet.

Also, net earnings and components of other comprehensive income attributable to the owners of the parent and to the non-controlling interests are required to be separately disclosed on the statement of earnings. The adoption of Sections 1601 and 1602 is not expected to have a material impact on the Corporation's consolidated earnings, cash flows or financial position.


4. USE OF ESTIMATES

The preparation of the Corporation's interim consolidated financial statements in accordance with Canadian GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances.

Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period they become known.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates, including that related to contingencies, during the three months ended March 31, 2009 except for those described in Notes 14 and 20 to these interim consolidated financial statements.


5. REGULATORY ASSETS AND LIABILITIES

A summary of the Corporation's regulatory assets and liabilities is provided below. A description of the nature of the regulatory assets and liabilities is provided in Note 4 to the Corporation's 2008 annual audited consolidated financial statements.



As at As at
March 31, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulatory Assets
Future income taxes (Note 2) 534 -
Rate stabilization accounts - Terasen Gas companies 139 76
Rate stabilization accounts - electric utilities 76 78
Alberta Electric System Operator ("AESO") charges
deferral 70 64
Regulatory other post-employment benefit ("OPEB")
plan asset 54 51
Income taxes recoverable on OPEB plans 18 18
Deferred capital asset amortization 7 8
Deferred pension costs 7 7
Southern Crossing Pipeline tax reassessment 7 7
Energy management costs 7 7
Residential unbundling 5 7
Other regulatory assets 44 37
-------------------------------------------------------------------------
Total regulatory assets 968 360
Less: current portion (232) (157)
-------------------------------------------------------------------------
Long-term regulatory assets 736 203
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at As at
March 31, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulatory Liabilities
Future asset removal and site restoration provision 340 337
Rate stabilization accounts - Terasen Gas companies 89 32
Rate stabilization accounts - electric utilities 15 9
Future income taxes (Note 2) 56 -
Unbilled revenue liability 15 15
Performance-based rate-setting incentive liabilities 15 13
Fair value of the foreign exchange forward contract 8 7
Southern Crossing Pipeline deferral 6 9
Pension deferral 4 4
Other regulatory liabilities 25 20
-------------------------------------------------------------------------
Total regulatory liabilities 573 446
Less: current portion (101) (45)
-------------------------------------------------------------------------
Long-term regulatory liabilities 472 401
-------------------------------------------------------------------------
-------------------------------------------------------------------------


6. INVENTORIES

As at As at
March 31, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gas in storage 73 212
Materials and supplies 18 17
-------------------------------------------------------------------------
91 229
-------------------------------------------------------------------------
-------------------------------------------------------------------------


During the quarter ended March 31, 2009, inventories of $468 million (quarter ended March 31, 2008 - $437 million) were expensed and reported in energy supply costs in the interim consolidated statement of earnings. Inventories expensed to operating expenses during the quarter ended March 31, 2009 were $3 million (quarter ended March 31, 2008 - $3 million), which included $2 million (quarter ended March 31, 2008 - $2 million) for food and beverage costs at Fortis Properties.



7. INTANGIBLE ASSETS

As at March 31, 2009 As at December 31, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Net
Accumulated Book Accumulated Book
($ millions) Cost Amortization Value Cost Amortization Value
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Computer software 314 (152) 162 310 (142) 168
Land, transmission
and water rights 128 (37) 91 127 (36) 91
Franchise fees,
customer contracts
and other 15 (6) 9 15 (5) 10
-------------------------------------------------------------------------
457 (195) 262 452 (183) 269
-------------------------------------------------------------------------
-------------------------------------------------------------------------


There was no impairment of intangible assets for the quarter ended March 31, 2009 and for the year ended December 31, 2008. Amortization of intangible assets is recorded on a straight-line method basis using amortization rates ranging from 1 per cent to 22 per cent.

Included in the cost of land, transmission and water rights is a total of $57 million (December 31, 2008 - $57 million) not subject to amortization.

8. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS



As at As at
March 31, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long-term debt and capital lease obligations 5,100 4,934
Long-term classification of committed credit
facilities (Note 19) 221 224
Deferred debt financing costs (35) (34)
-------------------------------------------------------------------------
Total long-term debt and capital lease obligations 5,286 5,124
Less: Current installments of long-term debt and
capital lease obligations (236) (240)
-------------------------------------------------------------------------
5,050 4,884
-------------------------------------------------------------------------
-------------------------------------------------------------------------


In February 2009, FortisAlberta issued $100 million of 30-year 7.06% unsecured debentures under a short-form base shelf prospectus that was filed in December 2008.

In February 2009, TGI issued $100 million of 30-year 6.55% unsecured debentures.

During the first quarter of 2009, Fortis began accounting for its investment in the Exploits Partnership using the equity method of accounting (Note 20). As a result, the Exploits Partnership term loan of $61 million classified as current as at December 31, 2008 is no longer being consolidated in the financial statements of Fortis, effective February 13, 2009.


9. COMMON SHARES

Authorized: an unlimited number of common shares without nominal or par value.




As at As at
Issued and Outstanding March 31, 2009 December 31, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares 169,759 2,462 169,191 2,449
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Common shares issued during the period were as follows:

Quarter Ended March 31, 2009
Number of
Shares Amount
(in thousands) ($ millions)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Balance, beginning of period 169,191 2,449
Consumer Share Purchase Plan 15 1
Dividend Reinvestment Plan 370 8
Employee Share Purchase Plan 134 3
Stock Option Plans 49 1
-------------------------------------------------------------------------
Balance, end of period 169,759 2,462
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Effective March 1, 2009, the Corporation's Amended and Restated Dividend Reinvestment and Share Purchase Plan provides a 2 per cent discount on the purchase of common shares, issued from treasury, with reinvested dividends.

Earnings per Common Share

The Corporation calculates earnings per common share on the weighted average number of common shares outstanding. The weighted average number of common shares outstanding was 169.4 million and 156.6 million for the quarters ended March 31, 2009 and March 31, 2008, respectively.

Diluted earnings per common share are calculated using the treasury stock method for options and the "if-converted" method for convertible securities.

Earnings per common share are as follows:



Quarter Ended March 31
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2009 2008
---------------------------------------------------------------------------
Weighted Weighted
Average Earnings Average Earnings
Earnings Shares per Earnings Shares per
($ (in Common ($ (in Common
millions) millions) Share millions) millions) Share
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Basic Earnings
per Common
Share 92 169.4 $0.54 91 156.6 $0.58
---------------------------------------------------------------------------
Effect of
potential
dilutive
securities:
Stock options - 0.7 - 1.2
Preference
shares
(Note 13) 4 13.9 4 12.8
Convertible
debentures 1 1.4 - 1.7
---------------------------------------------------------------------------
Diluted Earnings
per Common
Share 97 185.4 $0.52 95 172.3 $0.55
---------------------------------------------------------------------------
---------------------------------------------------------------------------


10. STOCK-BASED COMPENSATION PLANS

In January 2009, 22,980 Deferred Share Units ("DSUs") were granted to the Corporation's Board of Directors representing the equity component of their annual compensation and their annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation. In January 2009, 3,632 DSUs were paid out to a retired member of the Board of Directors of Fortis at $23.74 per DSU for a total of approximately $0.1 million.

In March 2009, 31,353 Performance Share Units ("PSUs") were paid out to the President and Chief Executive Officer ("CEO") of the Corporation at $23.39 per PSU as determined by the Human Resources Committee of the Board of Directors of Fortis for a total of approximately $0.7 million. The payout was made upon the three-year maturation period in respect of the PSU grant made in March 2006, and the President and CEO satisfying the payment requirements. In March 2009, 40,000 PSUs were granted to the President and CEO of the Corporation. Each PSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation.

In March 2009, the Corporation granted 1,037,156 options to purchase common shares under its 2006 Stock Option Plan at the five-day volume weighted average trading price of $22.29 immediately preceding the date of grant. The options vest evenly over a four-year period on each anniversary of the date of grant. The options expire seven years after the date of grant. The fair value of each option granted was $4.10 per option.

The fair value was estimated on the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:



Dividend yield (%) 3.19
Expected volatility (%) 24.3
Risk-free interest rate (%) 3.75
Weighted average expected life (years) 4.5


11. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss includes unrealized foreign currency translation gains and losses, net of hedging activities, gains and losses on cash flow hedging activities and gains and losses on discontinued cash flow hedging activities.



Quarter Ended
March 31, 2009
-------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) January 1 change March 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized foreign currency
translation (losses) gains,
net of hedging activities and
tax (46) 9 (37)
Losses on derivative instruments
designated as cash flow hedges,
net of tax (1) - (1)
Net losses on derivative instruments
previously discontinued as cash flow
hedges, net of tax (5) - (5)
-------------------------------------------------------------------------
Accumulated Other Comprehensive
(Loss) Income (52) 9 (43)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Quarter Ended
March 31, 2008
-------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) January 1 change March 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized foreign currency
translation (losses) gains,
net of hedging activities and
tax (82) 4 (78)
Losses on derivative instruments
designated as cash flow hedges,
net of tax (1) - (1)
Net losses on derivative instruments
previously discontinued as cash flow
hedges, net of tax (5) - (5)
-------------------------------------------------------------------------
Accumulated Other Comprehensive
(Loss) Income (88) 4 (84)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


12. EMPLOYEE FUTURE BENEFITS

The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, defined contribution pension plans and group registered retirement savings plans ("RRSPs") for its employees. The cost of providing the defined benefit arrangements was $6 million for the quarter ended March 31, 2009 (quarter ended March 31, 2008 - $7 million). The cost of providing the defined contribution arrangements and group RRSPs for the quarter ended March 31, 2009 was $4 million (quarter ended March 31, 2008 - $3 million).


13. FINANCE CHARGES



Quarter Ended March 31
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest - Long-term debt and capital lease
obligations 83 81
- Short-term borrowings 5 9
Interest charged to construction (4) (2)
Interest earned - (1)
Dividends on preference shares classified as debt
(Note 9) 4 4
-------------------------------------------------------------------------
88 91
-------------------------------------------------------------------------
-------------------------------------------------------------------------


14. CORPORATE TAXES

Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power used the taxes payable method of accounting for income taxes. The effect on the Corporation's consolidated financial statements, as at January 1, 2009, of adopting amended Section 3465, Income Taxes included an increase in total future income tax liabilities and total future income tax assets of $487 million and $15 million, respectively; an increase in regulatory assets and regulatory liabilities of $531 million and $50 million, respectively; and a combined net $9 million increase in other assets, utility capital assets, goodwill, income taxes payable and deferred credits associated with the reclassification of future income taxes that were previously netted against these respective balance sheet items.

Included in the future income tax assets and liabilities recorded are the future income tax effects of the subsequent settlement of the related regulatory assets and liabilities through customer rates and the separate disclosure of future income tax assets and liabilities that previously were not recognized.

Future income taxes are provided for temporary differences. Future income tax assets and liabilities are comprised of the following:



As at As at
March 31, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future income tax liability (asset)
Utility capital assets 472 17
Income producing properties 26 26
Regulatory assets 24 35
Intangible assets 7 3
Other assets 25 2
Deferred credits (42) (14)
Loss carryforwards (31) (28)
Share issue and debt financing costs (8) (14)
Unrealized foreign currency translation losses on
long-term debt (7) (5)
Regulatory liabilities (4) -
-------------------------------------------------------------------------
Net future income tax liability 462 22
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Current future income tax asset (34) -
Current future income tax liability 16 15
Long-term future income tax asset (51) (54)
Long-term future income tax liability 531 61
-------------------------------------------------------------------------
Net future income tax liability 462 22
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The adoption of amended Section 3465, Income Taxes on January 1, 2009 also resulted in additional future income tax expense of $17 million for the quarter ended March 31, 2009 and an offsetting regulatory adjustment to future income expense for the same amount. The regulatory adjustment represents the difference between the future income tax expense recognized under amended Section 3465, Income Taxes and that recovered from customers in rates during the quarter ended March 31, 2009.

The components of the provision for corporate taxes are as follows:



Quarter Ended March 31
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current taxes - Canadian 22 26
-------------------------------------------------------------------------

Future income taxes - Canadian 20 3
Less: Regulatory adjustment (17) -
-------------------------------------------------------------------------
3 3
-------------------------------------------------------------------------
Corporate taxes 25 29
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Corporate taxes differ from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory tax rate to earnings before corporate taxes and non-controlling interest. The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.



Quarter Ended March 31
($ millions, except as noted) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Combined Canadian federal and provincial statutory
income tax rate 33.0% 33.5%
-------------------------------------------------------------------------
Statutory income tax rate applied to earnings before
corporate taxes and non-controlling interest 41 42
Preference share dividends 1 1
Difference between Canadian statutory rate and rates
applicable to foreign subsidiaries (3) (3)
Difference in Canadian provincial statutory rates
applicable to subsidiaries in different Canadian
jurisdictions (3) (2)
Items capitalized for accounting but expensed for
income tax purposes (10) (10)
Pension costs (1) (1)
Other - 2
-------------------------------------------------------------------------
Corporate taxes 25 29
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Effective tax rate 20.3% 23.2%
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at March 31, 2009, the Corporation had approximately $116 million (December 31, 2008 - $104 million) in non-capital and capital loss carryforwards of which $12 million (December 31, 2008 - $12 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2009 and 2029.


15. SEGMENTED INFORMATION

Information by reportable segment is as follows:



REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gas Utilities Electric Utilities
---------------------------------------------------------------------------
Quarter Terasen
ended Gas Total
March Companies- Fortis Fortis NF Other Electric Electric
31, 2009 Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 669 79 72 169 70 390 83
Energy supply
costs 468 - 22 127 47 196 46
Operating
expenses 67 34 17 14 7 72 14
Amortization 25 22 10 11 4 47 11
---------------------------------------------------------------------------
Operating income 109 23 23 17 12 75 12
Finance charges 32 11 7 8 5 31 4
Corporate taxes
(recovery) 19 - 2 3 2 7 -
Non-controlling
interest - - - - - - 2
---------------------------------------------------------------------------
Net earnings
(loss) 58 12 14 6 5 37 6
Preference
share
dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 58 12 14 6 5 37 6
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Goodwill 908 227 221 - 63 511 168
Identifiable
assets 4,057 1,661 1,079 1,166 527 4,433 888
---------------------------------------------------------------------------
Total assets 4,965 1,888 1,300 1,166 590 4,944 1,056
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures
(3) 50 90 22 13 12 137 20
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Quarter ended
March 31, 2008
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 635 73 66 164 70 373 75
Energy supply
costs 437 - 21 122 49 192 40
Operating
expenses 61 33 16 14 7 70 11
Amortization 24 20 9 10 4 43 7
---------------------------------------------------------------------------
Operating
income 113 20 20 18 10 68 17
Finance charges 33 9 7 8 4 28 5
Corporate taxes
(recovery) 22 - 1 4 2 7 1
Non-controlling
interest - - - - - - 4
---------------------------------------------------------------------------
Net earnings
(loss) 58 11 12 6 4 33 7
Preference
share dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 58 11 12 6 4 33 7
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Goodwill 907 227 221 - 63 511 131
Identifiable
assets 3,509 1,340 929 1,006 494 3,769 681
---------------------------------------------------------------------------
Total assets 4,416 1,567 1,150 1,006 557 4,280 812
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures
(3) 40 72 24 13 7 116 11
---------------------------------------------------------------------------
---------------------------------------------------------------------------


NON-REGULATED
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter ended Corporate Inter-
March 31, 2009 Fortis Fortis and segment
($ millions) Generation Properties Other eliminations Consolidated
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 16 47 7 (11) 1,201
Energy supply costs 1 - - (4) 707
Operating expenses 4 34 3 (2) 192
Amortization 2 4 2 - 91
--------------------------------------------------------------------------
Operating income 9 9 2 (5) 211
Finance charges 1 6 19 (5) 88
Corporate taxes
(recovery) 2 1 (4) - 25
Non-controlling
interest - - - - 2
--------------------------------------------------------------------------
Net earnings (loss) 6 2 (13) - 96
Preference share
dividends - - 4 - 4
--------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 6 2 (17) - 92
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Goodwill - - - - 1,587
Identifiable assets 223 562 131 (33) 10,261
--------------------------------------------------------------------------
Total assets 223 562 131 (33) 11,848
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 7 5 - - 219
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter ended
March 31, 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 19 45 7 (8) 1,146
Energy supply costs 2 - - (3) 668
Operating expenses 4 31 3 (1) 179
Amortization 2 4 3 - 83
--------------------------------------------------------------------------
Operating income 11 10 1 (4) 216
Finance charges 2 6 21 (4) 91
Corporate taxes
(recovery) 3 1 (5) - 29
Non-controlling
interest - - - - 4
--------------------------------------------------------------------------
Net earnings (loss) 6 3 (15) - 92
Preference share
dividends - - 1 - 1
--------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 6 3 (16) - 91
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Goodwill - - - - 1,549
Identifiable assets 244 537 110 (23) 8,827
--------------------------------------------------------------------------
Total assets 244 537 110 (23) 10,376
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 3 3 1 - 174
--------------------------------------------------------------------------
--------------------------------------------------------------------------

(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
transmision capital projects, and to income producing properties and
intangible assets


Inter-segment transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The significant inter-segment transactions primarily related to the sale of energy from Fortis Generation to Belize Electricity, electricity sales from Newfoundland Power to Fortis Properties and finance charges on inter-segment borrowings. The significant inter-segment transactions for the three months ended March 31, 2009 and 2008 were as follows.



Significant Inter-Segment Transactions Quarter Ended March 31
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sales from Fortis Generation to
Regulated Electric Utilities - Caribbean 4 3
Sales from Newfoundland Power to Fortis Properties 1 1
Inter-segment finance charges on borrowings from:
Corporate to Regulated Electric Utilities - Caribbean 2 -
Corporate to Fortis Generation - 1
Corporate to Fortis Properties 2 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------


16. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

Quarter Ended March 31
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest paid 85 79
Income taxes paid 65 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------


17. CAPITAL MANAGEMENT

The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital in order to allow the utilities to fund the maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level 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. Fortis generally finances a significant portion of acquisitions with proceeds from common and preference share issuances.

The consolidated capital structure of Fortis is presented in the following table.



As at As at
March 31, 2009 December 31, 2008
($ millions) (%) ($ millions) (%)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total debt and
capital lease
obligations
(net of cash) (1) 5,453 59.1 5,468 59.5
Preference
shares (2) 667 7.2 667 7.3
Common
shareholders'
equity 3,116 33.7 3,046 33.2
-------------------------------------------------------------------------
Total 9,236 100.0 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


Certain of the Corporation's long-term debt obligations have covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70 per cent of the Corporation's consolidated capital structure, as defined by the long-term debt agreements. As at March 31, 2009, the Corporation and its subsidiaries, except for Belize Electricity, were in compliance with their debt covenants.

As a result of the regulator's Final Decision on Belize Electricity's 2008/2009 Rate Application, Belize Electricity does not meet certain debt covenant financial ratios related to loans totalling $9 million (BZ$14 million) as at March 31, 2009. The Company has informed the lenders of the defaults and has requested appropriate waivers. Belize Electricity is also in default of certain debt covenants which have resulted in the utility being prohibited from incurring new indebtedness or declaring dividends.

The Corporation's consolidated credit facilities are discussed further under "Liquidity Risk" in Note 19.


18. FINANCIAL INSTRUMENTS

Fair Values

There has been no change during the three months ended March 31, 2009 in the designation of the Corporation's financial instruments from that disclosed in the Corporation's 2008 annual audited consolidated financial statements. The carrying values of the Corporation's financial instruments included in current assets, current liabilities, other assets and deferred credits in the consolidated balance sheets of Fortis approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or the nature of these instruments. The carrying values and fair values of the Corporation's long-term debt and preference shares are as follows:



As at As at
March 31, 2009 December 31, 2008
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long-term debt,
including current
portion (1) (2) 5,251 5,239 5,088 4,959
Preference shares,
classified as
debt (1) (3) 320 327 320 329
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Carrying value is measured at amortized cost using the effective
interest rate method.
(2) Carrying value at March 31, 2009 is net of unamortized deferred
financing costs of $35 million (December 31, 2008 - $34 million).
(3) Preference shares classified as equity are excluded from the
requirements of the CICA Handbook Section 3855, Financial Instrument,
Recognition and Measurement; however, the estimated fair value of the
Corporation's $347 million preference shares classified as equity was
$303 million as at March 31, 2009 (December 31, 2008 - carrying value
$347 million; fair value $268 million).


The fair value of long-term debt is calculated by using quoted market prices, when available. When quoted market prices are not available, the fair value is determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills, with similar terms to maturity, plus a market credit risk premium equal to that of issuers of similar credit quality. Since the Corporation does not intend to settle the long-term debt prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs. The fair value of the Corporation's preference shares is determined using quoted market prices.

The Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas prices through the use of derivative financial instruments. The Corporation does not hold or issue derivative financial instruments for trading purposes. The following table summarizes the valuation of the Corporation's derivative financial instruments.



As at As at
March 31, 2009 December, 31, 2008
Term to Number Carrying Estimated Carrying Estimated
maturity of Value Fair Value Value Fair Value
Asset (years) Contracts ($ ($ ($ ($
(Liability) millions) millions) millions) millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Interest
rate less
swaps (1) than 2 2 - - - -
Foreign
exchange
forward approx.
contract 2 1 8 8 7 7
Natural gas
derivatives:
(2)
Swaps and Up to
options 2.5 189 (172) (172) (84) (84)
Gas
purchase
contract Up to
premiums 2.5 32 2 2 (8) (8)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Interest rate swap contracts mature in July 2009 and October 2010.
The contracts have the effect of fixing the rate of interest on the
non-revolving credit facilities of Fortis Properties at 6.16 per cent
and 5.32 per cent, respectively.
(2) The fair values of the natural gas derivatives were recorded in
accounts payable as at March 31, 2009 and December 31, 2008.


The fair value of the Corporation's financial instruments, including derivatives, reflects a point-in-time estimate based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future earnings or cash flows.


19. FINANCIAL RISK MANAGEMENT

The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.



Credit risk Risk that a third party to a financial instrument might
fail to meet its obligations under the terms of the
financial instrument.

Liquidity risk Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.

Market risk Risk that the fair value or future cash flows of a
financial instrument will fluctuate due to changes in
market prices. The Corporation is exposed to the following
market risks:

- Foreign exchange risk
- Interest rate risk
- Commodity price risk


Credit Risk

For cash and cash equivalents, trade and other accounts receivable, and other receivables due from customers, the Corporation's credit risk is limited to the carrying value on the balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk and these include requiring customer deposits and credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts.

FortisAlberta has a concentration of credit risk as a result of its distribution-service billings being to a relatively small group of retailers and, as at March 31, 2009, its gross credit risk exposure was approximately $87 million, representing the projected value of retailer billings over a 60-day period. The Company has reduced its exposure to less than $5 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.

The Terasen Gas companies are exposed to credit risk in the event of non-performance by counterparties to derivative financial instruments, including natural gas derivatives. The Terasen Gas companies are also exposed to significant credit risk on physical off-system sales. To mitigate credit risk, the Terasen Gas companies deal with high credit-quality institutions, in accordance with established credit-approval practices. The counterparties with which the Terasen Gas companies have significant transactions are A-rated entities or better. The Company uses netting arrangements to reduce credit risk and net settles payments with counterparties where net settlement provisions exist.

The aging analysis of the Corporation's consolidated trade and other accounts receivable is as follows:



As at As at As at
March 31, December 31, March 31,
($ millions) 2009 2008 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Not past due 610 587 600
Past due 0-30 days 93 70 95
Past due 31-60 days 23 14 22
Past due 61 days and over 20 19 22
-------------------------------------------------------------------------
746 690 739
Less: allowance for doubtful accounts (19) (16) (14)
-------------------------------------------------------------------------
727 674 725
-------------------------------------------------------------------------
-------------------------------------------------------------------------


As at March 31, 2009, other receivables due from customers of $8 million and the receivable associated with the foreign exchange forward contract of $8 million will be received over the next five years, with $9 million expected to be received in 2009, $4 million over 2010 and 2011, $1 million over 2012 and 2013 and $2 million in 2014.

Liquidity Risk

The Corporation's financial position could be adversely affected if it, or its operating subsidiaries, fail to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the results of operations and financial position of the Corporation and its subsidiaries, conditions in the capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.

To mitigate liquidity risk, the Corporation and its larger regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures and seasonal working capital requirements.

Committed credit facilities at Fortis are available for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed credit facility may be required from time to time to support the servicing of debt and payment of dividends. Over the next five years, average consolidated annual long-term debt maturities and repayments are expected to be approximately $170 million. The combination of available credit facilities and low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing and access to capital markets.

As at March 31, 2009, the Corporation and its subsidiaries had consolidated credit facilities of $2.2 billion, of which $1.6 billion was unused. The credit facilities are almost entirely syndicated with the seven largest Canadian chartered banks with no one bank holding more than 25 per cent of these facilities.

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



Total Total
as at as at
Corporate Regulated Fortis March 31, December 31,
($ millions) and Other Utilities Properties 2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total credit
facilities 715 1,502 13 2,230 2,228
Credit facilities
utilized:
Short-term
borrowings - (261) - (261) (410)
Long-term debt
(Note 8) (56) (165) - (221) (224)
Letters of credit
outstanding (1) (102) (1) (104) (104)
--------------------------------------------------------------------------
Credit facilities
available 658 974 12 1,644 1,490
--------------------------------------------------------------------------
--------------------------------------------------------------------------


As at March 31, 2009 and December 31, 2008, certain borrowings under the Corporation's and its subsidiaries' credit facilities have been classified as long-term debt. These borrowings are under long-term committed credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.

During the first quarter of 2009, FortisBC negotiated amendments to its $150 million unsecured committed revolving credit facility, including extending the maturity date of the $50 million portion of the facility to May 2012 from May 2011 and the maturity date of the $100 million portion of the facility to May 2010 from May 2009. The amended credit facility agreement is expected to be finalized during the second quarter of 2009.

In March 2009, Maritime Electric renegotiated its $50 million demand credit facility and had it converted into a 364-day revolving committed credit facility.

The following is an analysis of the contractual maturities of the Corporation's financial liabilities as at March 31, 2009.

Financial Liabilities



less than greater greater
or equal to than 4-5 than
($ millions) 1 year 1-3 years years 5 years Total
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Short-term borrowings 261 - - - 261
Trade and other accounts payable 700 - - - 700
Natural gas derivatives 130 40 - - 170
Dividends payable 47 - - - 47
Customer deposits 1 2 2 2 7
Long-term debt, including current
portion (1) 234 300 309 4,443 5,286
Interest obligations on
long-term debt 324 632 590 4,472 6,018
Preference shares, classified
as debt - - - 320 320
---------------------------------------------------------------------------
1,697 974 901 9,237 12,809
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Excluding deferred financing costs of $35 million included in the
carrying value as per Note 8


Market Risk

Foreign Exchange Risk

The Corporation's earnings from, and net investment in, its self-sustaining foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above exposure through the use of US dollar borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange loss or gain on the translation of the Corporation's foreign subsidiaries' earnings, which are denominated in US dollars or in a currency pegged to the US dollar. Belize Electricity's reporting currency is the Belizean dollar while the reporting currency of Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy and BECOL is the US dollar. The Belizean dollar is pegged to the US dollar at BZ$2.00 equals US$1.00.

As at March 31, 2009, all of the Corporation's corporately held US$403 million of long-term debt had been designated as a hedge of a portion of the Corporation's foreign net investments. As at March 31, 2009, the Corporation had approximately US$125 million in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately held US dollar borrowings that are designated as hedges are recorded in other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the foreign net investments, which are also recorded in other comprehensive income.

TGVI's US dollar payments under a contract for the construction of a liquefied natural gas storage facility expose TGVI to fluctuations in the US dollar-to-Canadian dollar exchange rate. TGVI has entered into a foreign exchange forward contract to hedge this exposure. TGVI has regulatory approval to defer any increase or decrease in the fair value of the foreign exchange forward contract for recovery from, or refund to, customers in future rates.

Interest Rate Risk

The Corporation and its subsidiaries are exposed to interest rate risk associated with short-term borrowings and floating-rate debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk and, during the first quarter of 2009, Fortis Properties was party to interest rate swap agreements that effectively fixed the interest rates on their variable-rate borrowings. The Terasen Gas companies and FortisBC have regulatory approval to defer any increase or decrease in interest expense resulting from fluctuations in interest rates associated with variable-rate debt for recovery from, or refund to, customers in future rates.

Commodity Price Risk

The Terasen Gas companies are exposed to commodity price risk associated with changes in the market price of natural gas. This risk is minimized by entering into natural gas derivatives that effectively fix the price of natural gas purchases. The natural gas derivatives are recorded on the balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, subject to regulatory approval, for recovery from, or refund to, customers in future rates.


20. CONTINGENT LIABILITIES AND COMMITMENTS

Contingent liabilities

The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with ordinary course business operations. Management believes that the amount of liability, if any, from these actions would not have a material effect on the Corporation's consolidated financial position or results of operations. The Corporation's contingent liabilities are consistent with disclosures in the Corporation's 2008 annual audited consolidated financial statements, except for that described below.

Exploits Partnership

Following Abitibi's announcement of its intention to close its Grand Falls-Windsor newsprint mill on March 31, 2009, the Government of Newfoundland and Labrador expropriated most of the Newfoundland-based assets of Abitibi. The expropriated assets included the hydroelectric generating facility assets of the Exploits Partnership. The Exploits Partnership is owned 51 per cent by Fortis Properties and 49 per cent by Abitibi.

The Exploits Partnership had previously incurred a term loan from several lenders to finance its assets. As at December 31, 2008, approximately $61 million remained outstanding under this term loan. The loan is without recourse to Fortis or Abitibi, as partners of the Exploits Partnership, and is secured by both the hydroelectric generating assets and related agreements regarding rights to operate and sell power to Newfoundland Hydro during the term of the loan. Although the expropriation has caused the Exploits Partnership to default on the term loan, to date the lenders have not demanded accelerated repayment of the term loan. The Exploits Partnership made the scheduled term loan payment for the quarter ended March 31, 2009. As at March 31, 2009, the balance outstanding under the term loan was approximately $60 million.

The generation and sale of electricity by the Exploits Partnership continued in the normal course until the newsprint mill closed on February 12, 2009, up to which point Newfoundland and Labrador Hydro paid the Exploits Partnership for the energy produced on the same basis as the pre-expropriation power purchase agreement. Payment for all energy delivered since February 13, 2009 is currently outstanding from the Government of Newfoundland and Labrador pending resolution of expropriation matters. The day-to-day operations of the hydroelectric generating facilities have been assumed by Nalcor Energy, a crown corporation, as the agent for the Government of Newfoundland and Labrador with respect to this matter.

On March 24, 2009, the Government of Newfoundland and Labrador announced that Abitibi had discontinued discussions with Nalcor Energy regarding compensation for the expropriated assets. Abitibi, which was incorporated in the US, has also indicated that it intends to challenge the expropriation of its assets and seek compensation through the North American Free Trade Agreement.

Historically, the financial statements of the Exploits Partnership were consolidated in the financial statements of Fortis. Pending resolution of the above matters, deferred financing costs of $2 million and utility capital assets of $61 million related to the Exploits Partnership were reclassified to other assets and the $61 million term loan was reclassified as current on the consolidated balance sheet of Fortis as at December 31, 2008.

During the quarter, the combination of uncertainty created by the expropriation and the loss of control over cash flows of the Exploits Partnership has required Fortis to commence reporting its investment in the Exploits Partnership using the equity method of accounting, effective February 13, 2009. Consequently, the assets and liabilities of the Exploits Partnership are no longer consolidated in the accounts of Fortis. Equity earnings recognized during the first quarter of 2009 were equivalent to the amount that would have been recognized in the absence of the expropriation. This approach is consistent with the public statement of the Government of Newfoundland and Labrador that it is not its intention to adversely affect the business interests of lenders or independent partners of Abitibi.

Commitments

There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2008 annual audited consolidated financial statements, except for those described below.

Belize Electricity has entered into a new 15-year power purchase agreement with Belize Aquaculture Limited ("BAL"). The agreement provides for the supply of up to 15 MW of capacity by BAL and expires in April 2024. The agreement totals approximately $279 million to 2024.

Based on the last completion of actuarial valuations, the Corporation's consolidated defined benefit pension plan funding contributions are expected to total approximately $18 million for 2009, $15 million for 2010 and $2 million for each of 2011, 2012 and 2013. These pension funding obligations reflect additional obligations determined under December 31, 2008 actuarial valuations, completed in the first quarter for 2009, associated with defined benefit pension plans at Newfoundland Power and the Corporation, and under a December 31, 2007 actuarial valuation of a defined benefit pension plan at Terasen, also completed in the first quarter of 2009.


21. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period classifications the most significant of which was the reclassification of $48 million from other assets to utility capital assets on the consolidated balance sheet as at December 31, 2008 related to the net book value of amounts paid to AESO for transmission capital projects at FortisAlberta.

CORPORATE INFORMATION

Fortis Inc. is the largest investor-owned distribution utility in Canada. With total assets approaching $12 billion and annual revenues totalling $3.9 billion, the Corporation serves more than 2,000,000 gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State. It also owns hotels and commercial 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
W: www.computershare.com/fortisinc


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

Contact Information

  • Fortis Inc.
    Barry V. Perry
    Vice President Finance and Chief Financial Officer
    709-737-2800