Fortis Inc.
TSX : FTS

Fortis Inc.

August 04, 2006 07:00 ET

Fortis Earns $37.9 Million in Second Quarter

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(CCNMatthews - Aug. 4, 2006) - Fortis Inc. (TSX:FTS) reported net earnings applicable to common shares of $37.9 million, or $0.37 per common share, for the second quarter of 2006 compared to earnings of $38.2 million, or $0.37 per common share, for the second quarter of 2005. Year-to-date net earnings applicable to common shares were $74.5 million, or $0.72 per common share, compared to earnings of $77.4 million, or $0.77 per common share, for the same period last year.

Earnings for the second quarter last year included a $7.0 million positive after-tax adjustment to FortisAlberta's earnings driven largely by the resolution of tax-related matters pertaining to prior years. Earnings for the second quarter last year also included a $1.1 million positive adjustment to equity income from Caribbean Utilities related to a change in accounting practice for recognizing unbilled revenue. Excluding these items, the Corporation's earnings were $7.8 million higher in the second quarter of 2006 compared to the second quarter of 2005. The increase was driven by lower corporate income taxes largely at FortisAlberta, improved hydroelectric production in Belize, higher earnings at Fortis Properties and a foreign exchange gain on the translation of US dollar-denominated corporate debt. The increase was partially offset by lower earnings at Newfoundland Power related to the shifting of revenue from the first half of 2006 to the second half of 2006, upon the adoption of the accrual method of recognizing revenue, effective January 1, 2006. On an annual basis, Newfoundland Power's earnings are expected to remain comparable with the prior year. The Corporation's earnings were also tempered by the recording of the cumulative impact of the regulator-approved Negotiated Settlement Agreements during the second quarter of 2006 at FortisAlberta and FortisBC.

Non-regulated Fortis Generation contributed $6.7 million to earnings for the second quarter compared to $3.2 million for the second quarter last year. The increase was driven by increased hydroelectric production in Belize, partially offset by lower average wholesale prices in Ontario. During the second quarter of 2006, the average wholesale energy price per megawatt hour in Ontario was $45.32 compared to $60.24 for the same quarter last year.

"Our Chalillo and downstream Mollejon hydroelectric facilities in Belize generated almost five times more electricity this quarter compared to the second quarter last year," explains Stan Marshall, President and Chief Executive Officer, Fortis Inc. "As of July 31, 2006, the Chalillo reservoir is at full supply level and our Belize hydroelectric facilities have generated approximately 80 gigawatt hours year to date compared to 68 gigawatt hours for all of 2005," he adds. The Chalillo reservoir at full supply level contains the equivalent of 45 gigawatt hours of hydroelectric production.

Canadian Regulated Utilities contributed $25.4 million to earnings for the second quarter of 2006 compared to $34.8 million for the same quarter last year. Excluding the favourable earnings adjustment at FortisAlberta in the second quarter of 2005, earnings were $2.4 million lower quarter over quarter. Higher earnings associated with increased electricity sales at the western utilities, increased electricity rates at FortisBC and lower corporate income taxes, principally at FortisAlberta, were more than offset by the quarterly shift of revenue at Newfoundland Power and the impact of recording in the second quarter of 2006 the cumulative effects of the Negotiated Settlement Agreements at the western utilities, including a 1.9 per cent electricity rate reduction at FortisAlberta.

"It was a busy period for our utilities on the regulatory front, with four of our five Canadian regulated utilities receiving regulatory rate approvals," says Marshall. "FortisAlberta and FortisBC both reached Negotiated Settlement Agreements with their customers and stakeholders, which were approved by the utilities' respective regulators, thereby eliminating the need for full-scale hearings. At FortisBC, a new multi-year performance-based rate-setting mechanism was also approved."

Caribbean Regulated Utilities delivered earnings of $4.4 million compared to $5.0 million for the second quarter of 2005. Excluding the positive adjustment to second quarter 2005 equity income from Caribbean Utilities, earnings were $0.5 million higher quarter over quarter, primarily due to an 11 per cent overall increase in electricity rates at Belize Electricity, effective July 1, 2005.

"Throughout the quarter, Fortis utilities remained focused on completing capital work initiatives to meet the needs of existing and new customers and to enhance the reliability of electricity systems," says Marshall. "Fortis plans to invest almost $450 million in its consolidated capital expenditure program in 2006, almost half of which has been invested to date. Most of this capital investment is being driven by the robust customer growth being experienced by our utilities in western Canada," he adds.

Fortis Properties contributed $8.1 million to earnings for the second quarter compared to $4.8 million for the same quarter last year. Results were higher primarily due to a $1.6 million after-tax gain on the sale of the Days Inn Sydney hotel and reduced corporate income taxes.

"Going forward, Fortis expects continued strong performance from its regulated businesses, particularly FortisAlberta and FortisBC, and from its non-regulated hydroelectric generation and properties businesses," concludes Marshall.



Fortis Inc.

Interim Management Discussion and Analysis

For the 3 and 6 months ended June 30, 2006 Dated August 4, 2006

The following analysis should be read in conjunction with the Fortis Inc. ("Fortis" or the "Corporation") interim unaudited consolidated financial statements for the 3 and 6 months ended June 30, 2006 and the Management Discussion and Analysis and audited consolidated financial statements for the year ended December 31, 2005 included in the Corporation's 2005 Annual Report. This material has been prepared in accordance with National Instrument 51-102 relating to Management Discussion and Analysis. 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 statements in this material. By their very nature, forward-looking statements are based on underlying assumptions and are subject to inherent risks and uncertainties surrounding future expectations generally. Such events include, but are not limited to, general economic, market and business conditions, regulatory developments, weather and competition. Fortis cautions readers that should certain events or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from those expected. For additional information with respect to certain of these risks or factors, reference should be made to the Corporation's continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. The Corporation disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Fortis is principally a diversified, international electric utility holding company with investments primarily in regulated electric distribution utilities in Canada and the Caribbean region, serving more than 1,000,000 electricity customers and meeting a peak demand of approximately 5,000 megawatts ("MW"). The Corporation also owns and operates non-regulated generation assets, commercial real estate and hotels.

The key goals of the Corporation's regulated utilities are to operate sound electricity systems and deliver safe, reliable electricity to customers at reasonable, prudently incurred costs. The Corporation's core business of electricity distribution is highly regulated and Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. The operating and reporting segments of the Corporation are (i) Regulated Utilities - Canadian, (ii) Regulated Utilities - Caribbean, (iii) Non-Regulated - Fortis Generation, (iv) Non-Regulated - Fortis Properties, and (v) Corporate. The Corporation's Canadian regulated utilities operate in 5 provinces, making Fortis the leader in its business segment. The utility operations comprising the Corporation's Regulated Utilities - Canadian operating segment are FortisAlberta, FortisBC, Newfoundland Power, FortisOntario and Maritime Electric on Prince Edward Island ("PEI"). The Corporation's Regulated Utilities - Caribbean operating segment is comprised of Belize Electricity, in which Fortis holds a 70.1 per cent controlling interest, and Caribbean Utilities, the sole provider of electricity on Grand Cayman, in which Fortis holds a 37.4 per cent equity interest. The earnings of the Corporation's regulated utilities are primarily determined under traditional cost of service and rate of return methodologies; however, the earnings are generally exposed to changes in interest rates associated with the rate-setting mechanisms.

The Corporation's non-regulated generation assets, operating in 3 countries, are mainly hydroelectric with a combined generating capacity of 195 MW. The Corporation, through its non-regulated subsidiary Fortis Properties, owns and operates 14 hotels with over 2,800 rooms in 6 provinces in Canada and 2.7 million square feet of commercial real estate in Atlantic Canada.

Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. Key financial highlights, including segmented earnings, for the second quarter and year-to-date periods ended June 30th are provided in the following table.



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Financial Highlights (Unaudited)
Period Ended June 30th
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Quarter Year-to-date
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($ millions, except
earnings per
common share
amounts) 2006 2005 Variance 2006 2005 Variance
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Revenue and
equity income 345.9 365.0 (19.1) 736.7 746.7 (10.0)
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Cash flow from
operations 57.8 49.9 7.9 107.2 129.2 (22.0)
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Net earnings
applicable to
common shares 37.9 38.2 (0.3) 74.5 77.4 (2.9)
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Basic earnings
per common
share ($) (1) 0.37 0.37 - 0.72 0.77 (0.5)
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Diluted earnings
per common
share ($) (1) 0.35 0.34 0.1 0.69 0.70 (0.1)
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Segmented Net Earnings
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Quarter Year-to-date
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2006 2005 Variance 2006 2005 Variance
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FortisAlberta 11.3 14.7 (3.4) 20.8 22.6 (1.8)
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FortisBC (2) 3.4 5.4 (2.0) 15.3 14.3 1.0
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Newfoundland
Power 8.0 11.5 (3.5) 18.7 24.5 (5.8)
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Maritime Electric 2.2 2.3 (0.1) 4.3 4.4 (0.1)
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FortisOntario (3) 0.5 0.9 (0.4) 1.4 2.0 (0.6)
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Regulated
Utilities -
Canadian 25.4 34.8 (9.4) 60.5 67.8 (7.3)
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Belize
Electricity 2.3 1.9 0.4 3.8 2.8 1.0
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Caribbean
Utilities -
Equity Income 2.1 3.1 (1.0) 3.7 5.6 (1.9)
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Regulated
Utilities -
Caribbean 4.4 5.0 (0.6) 7.5 8.4 (0.9)
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Total Regulated
Utilities 29.8 39.8 (10.0) 68.0 76.2 (8.2)
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Non-Regulated -
Fortis
Generation (4) 6.7 3.2 3.5 12.1 13.2 (1.1)
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Non-Regulated -
Fortis
Properties 8.1 4.8 3.3 9.6 6.4 3.2
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Corporate (6.7) (9.6) 2.9 (15.2) (18.4) 3.2
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Net earnings
applicable to
common shares 37.9 38.2 (0.3) 74.5 77.4 (2.9)
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(1) Earnings per common share data for 2005 have been restated to
reflect the 4-for-1 stock split completed in October 2005.

(2) Includes the regulated operations of FortisBC Inc. and non-
regulated operating, maintenance and management services related
to the Waneta, Brilliant and the Arrows Lake hydroelectric plants
and the distribution system owned by the City of Kelowna. Also
includes Princeton Light and Power Company, Limited ("PLP"), but
excludes the non-regulated generation operations of FortisBC
Inc.'s wholly owned partnership, Walden Power Partnership.
Financial results for PLP are included in the FortisBC segmented
results from May 31, 2005, the date of acquisition of PLP by
Fortis, through an indirect wholly owned subsidiary.

(3) FortisOntario includes Canadian Niagara Power Inc. ("Canadian
Niagara Power") and Cornwall Street Railway, Light and Power
Company, Limited ("Cornwall Electric").

(4) Includes the operations of non-regulated generating assets in
central Newfoundland, Ontario, Belize, British Columbia and Upper
New York State.


OVERVIEW OF CONSOLIDATED RESULTS

Net earnings applicable to common shares were $37.9 million, or $0.37 per common share, for the second quarter of 2006 compared to earnings of $38.2 million, or $0.37 per common share, for the second quarter of 2005. Earnings for the second quarter last year included a $7.0 million positive after-tax adjustment to FortisAlberta's earnings driven largely by the resolution of tax-related matters pertaining to prior years, which favourably impacted revenue. Earnings for the second quarter last year also included a $1.1 million positive adjustment to equity income from Caribbean Utilities related to a change in accounting practice for recognizing unbilled revenue. Excluding these items, the Corporation's earnings were $7.8 million higher in the second quarter of 2006 compared to the second quarter of 2005. The increase was driven by lower corporate income taxes largely at FortisAlberta, improved hydroelectric production in Belize, higher earnings at Fortis Properties and a foreign exchange gain on the translation of US dollar-denominated corporate debt. The increase was partially offset by lower earnings at Newfoundland Power related to the shifting of revenue from the first half of 2006 to the second half of 2006, upon adopting the accrual method of recognizing revenue, effective January 1, 2006, and the impact of recording the cumulative effects of the regulator-approved Negotiated Settlement Agreements during the second quarter of 2006 at FortisAlberta and FortisBC.

Net earnings for the first half of 2006 were $74.5 million, or $0.72 per common share, compared to $77.4 million, or $0.77 per common share, for the first half of 2005. Excluding the one-time items included in the second quarter of 2005 as described above and the $7.9 million after-tax gain resulting from the settlement of contractual matters ("Ontario Settlement") between FortisOntario and Ontario Power Generation Inc. ("OPGI"), in the first quarter of 2005, earnings for the first half of 2006 were $13.1 million higher compared to the first half of 2005. The increase was primarily due to the factors described for the quarter, in addition to the favourable impact of the 11 per cent overall increase in electricity rates at Belize Electricity, effective July 1, 2005, partially offset by the impact of lower equity income from Caribbean Utilities associated with the timing of expensing of previously deferred fuel costs.



REGULATED UTILITIES - CANADIAN
FortisAlberta

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FortisAlberta
Financial Highlights (Unaudited)
Period Ended June 30th
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Quarter Year-to-date
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2006 2005 Variance 2006 2005 Variance
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Electricity
Sales (GWh) 3,538 3,402 136 7,292 7,087 205
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($ millions)
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Revenue 58.6 75.7 (17.1) 120.4 134.3 (13.9)
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Operating Expenses 26.9 27.9 (1.0) 55.6 54.8 0.8
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Amortization 18.5 16.9 1.6 34.2 30.7 3.5
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Finance Charges 7.5 5.8 1.7 14.3 11.8 2.5
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Corporate Taxes (5.6) 10.4 (16.0) (4.5) 14.4 (18.9)
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Earnings 11.3 14.7 (3.4) 20.8 22.6 (1.8)
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Regulation: On June 29, 2006, FortisAlberta received approval from the Alberta Energy and Utilities Board ("AEUB") of the 2006/2007 Negotiated Settlement Agreement associated with the Company's 2006/2007 Distribution Access Tariff Application filed on December 12, 2005. The 2006/2007 Negotiated Settlement Agreement, effective January 1, 2006 and based on an allowed rate of return on common equity ("ROE") of 8.93 per cent, resulted in distribution revenue requirements, excluding miscellaneous revenue and adjustment riders, of $217.1 million and $228.2 million for 2006 and 2007, respectively. This translates into a 1.9 per cent electricity rate reduction in 2006 and a 0.7 per cent electricity rate increase in 2007. The revenue requirements reflect a forecast level of operating expenses of $100.8 million and $100.1 million for 2006 and 2007, respectively. Additional operating expenses of $13.0 million and $13.5 million in 2006 and 2007, respectively, will be collected by separate rate riders during those years. The revenue requirement also reflects capital expenditures, before customer contributions, of approximately $400 million over the 2 years with capital expenditures of $184.5 million forecast in 2006, before forecast customer contributions of $23.3 million. Additionally, FortisAlberta expects to make contributions of $10.7 million to Alberta Electric System Operator ("AESO") capital projects in 2006. The Company was previously on interim rates, effective January 1, 2006, as approved by the AEUB.

During the second quarter of 2006, FortisAlberta recorded the cumulative impact of the AEUB approved 2006/2007 Negotiated Settlement Agreement. This resulted in a $2.1 million reduction in revenue as a result of providing for the difference between interim rates and those in the 2006/2007 Negotiated Settlement Agreement, which will be refunded to customers in 2007. The approved 2006/2007 Negotiated Settlement Agreement also resulted in changes in depreciation rates and pension and income tax methodologies.

Earnings: FortisAlberta's earnings were $3.4 million and $1.8 million lower quarter over quarter and year to date compared to the same period last year, respectively. Earnings for the second quarter of 2005 included a $7.0 million positive after-tax adjustment driven largely by the resolution of tax-related matters pertaining to prior years. Excluding this adjustment, earnings were $3.6 million and $5.2 million higher quarter over quarter and year to date over the same period last year, respectively, primarily due to lower corporate income taxes and electricity sales growth, partially offset by a 1.9 per cent decrease in electricity rates as a result of the 2006/2007 Negotiated Settlement Agreement.

Electricity Sales: Electricity sales were 136 gigawatts ("GWh"), or 4.0 per cent, higher quarter over quarter, and 205 GWh, or 2.9 per cent, higher year to date over the same period last year. The increase was primarily due to growth in consumption and the number of customers in the residential, commercial, industrial, and oil and gas sectors as a result of a strong provincial economy.

Revenue: Revenue was $17.1 million lower quarter over quarter. Revenue for the second quarter of 2005 included $13.8 million largely related to the resolution of tax-related matters pertaining to prior years. During the second quarter of 2005, revenue was favourably adjusted by $1.0 million, relating to the first quarter of 2005, due to the recognition of the cumulative impact of the 2.1 per cent electricity rate increase as a result of the 2005 Negotiated Settlement Agreement. The recognition during the second quarter of 2006 of a 1.9 per cent electricity rate decrease, effective January 1, 2006, as a result of the 2006/2007 Negotiated Settlement Agreement, decreased revenue by $2.1 million quarter over quarter. This included $1.0 million relating to the first quarter of 2006. Revenue also decreased $1.1 million as a result of a reduction of inter-company billings quarter over quarter. The decrease in revenue was partially offset by the impact of electricity sales growth.

Revenue was $13.9 million lower year to date compared to the same period last year. Revenue for the first half of 2005 included $13.4 million largely related to the resolution of tax-related matters pertaining to prior years. Revenue also decreased as a result of the 1.9 per cent electricity rate decrease, effective January 1, 2006, and a $1.2 million reduction of inter-company billings. The decrease was partially offset by the impact of electricity sales growth, the recognition of $1.0 million of revenue during the first quarter of 2006 upon approval of the Company's 2004 AESO charges deferral account application, and increased franchise fee revenue of $0.5 million.

Expenses: Operating expenses were $1.0 million lower quarter over quarter, primarily due to an increase in the volume and level of labour and overhead charged to capital expenditures as a result of FortisAlberta's intensive capital expenditure program.

Year to date over the same period last year, operating expenses were $0.8 million higher primarily due to higher labour, employee benefit and contracted manpower costs, partially offset by an increase in labour and overhead charged to capital projects.

Amortization costs were $1.6 million and $3.5 million higher quarter over quarter and year to date over the same period last year, respectively, primarily due to an increase in the depreciable asset base as a result of load growth within FortisAlberta's service territory, combined with higher overall depreciation rates as approved by the AEUB in the 2006/2007 Negotiated Settlement Agreement.

Finance charges were $1.7 million and $2.5 million higher quarter over quarter and year to date over the same period last year, respectively, primarily due to higher debt levels arising from increased drawings under the Company's long-term credit facility and the issuance of long-term debt to finance capital projects required to satisfy FortisAlberta's obligations to serve its customers. On April 21, 2006, FortisAlberta issued $100 million unsecured debentures bearing interest at 5.40% per annum, due April 21, 2036. The net proceeds of the offering were used primarily to repay existing indebtedness on FortisAlberta's long-term credit facility.

Corporate taxes were $16.0 million and $18.9 million lower quarter over quarter and year to date compared to the same period last year, respectively. The decrease was due to lower earnings before income taxes and increased deductions taken for income tax purposes in excess of amounts for accounting purposes in 2006 as compared to 2005, including the impact of increased capital cost allowance ("CCA") rates for income tax deduction purposes related to specific asset classes. In addition, in 2006 these timing differences are accounted for entirely on the taxes payable method compared to the use in 2005 of the tax liability method for federal income taxes and the taxes payable method for provincial income taxes. The change in the income tax methodology has resulted in the cessation of recognizing future income tax expense for federal income tax which would have partially offset the effects of these timing differences.

In May 2006, FortisAlberta announced its intention to build a new office facility in Airdrie for approximately $22.0 million to accommodate approximately 250 FortisAlberta employees, pending receipt of permits and regulatory approval, with occupancy of the building expected prior to the spring of 2008.



FortisBC

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FortisBC
Financial Highlights(Unaudited)
Period Ended June 30th
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Quarter Year-to-date
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2006 2005 Variance 2006 2005 Variance
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Electricity
Sales (GWh) 662 642 20 1,502 1,474 28
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($ millions)
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Revenue 45.8 44.1 1.7 108.6 99.5 9.1
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Energy Supply Costs 13.9 12.0 1.9 33.1 30.6 2.5
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Operating Expenses 16.0 15.9 0.1 31.4 32.0 (0.6)
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Amortization 6.5 4.7 1.8 13.7 9.3 4.4
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Finance Charges 5.7 4.2 1.5 11.3 8.8 2.5
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Corporate Taxes 0.3 1.9 (1.6) 3.8 4.5 (0.7)
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Earnings 3.4 5.4 (2.0) 15.3 14.3 1.0
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Regulation: On May 23, 2006, FortisBC received approval from the British Columbia Utilities Commission ("BCUC") of the Negotiated Settlement Agreement associated with the Company's 2006 Revenue Requirements Application ("2006 Application") filed on November 24, 2005. The Negotiated Settlement Agreement, effective January 1, 2006 and based on an approved ROE of 9.20 per cent, resulted in a 5.9 per cent electricity rate increase, an increase in the Company's composite depreciation rate from 2.6 per cent to 3.2 per cent and an increase in the rate used for capitalizing overhead from approximately 9.0 per cent to 20.0 per cent of gross forecast operating and maintenance expenses. Additionally, a new performance-based rate-setting ("PBR") mechanism for the years 2007 and 2008, and optionally 2009, was approved whereby a 2 percentage point band has been set around the allowed ROE whereby all variances (adjusted for interest variances which flow through to customers) as a result of actual financial performance, positive or negative, will be shared equally between customers and the Company. If the variance exceeds the 2 percentage point band, the excess will be placed in a deferral account for review during the next rate-setting process. The 5.9 per cent electricity rate increase was largely driven by the Company's extensive capital expenditure program and was the same as the refundable interim electricity rate increase previously approved by the BCUC.

On April 12, 2006, the Canal Plant Agreement ("CPA") between BC Hydro, FortisBC, Teck Cominco and Columbia Power Corporation and Columbia Basin Trust became effective and continues in force until terminated by any of the parties by giving no less than 5 years notice at any time on or after December 31, 2030. The CPA governs the co-ordinated operations of 7 major hydroelectric plants owned by the 4 parties to the CPA.

In June 2005, a British Columbia utility applied to the BCUC for, among other things, a review of the current ROE mechanism applicable to regulated utilities in British Columbia. On March 2, 2006, the BCUC issued an order approving adjustments to the ROE mechanism, which resulted in the 2006 ROE for FortisBC increasing from 8.69 per cent to 9.20 per cent.

On January 31, 2006, FortisBC received approval from the BCUC for its 2006 Capital Plan of $111.7 million, net of customer contributions, of which approximately $27.0 million in projects is subject to further review and approval, which the Company is in the process of seeking.

Earnings: FortisBC's earnings were $2.0 million lower quarter over quarter, primarily due to higher energy supply costs, amortization costs and finance charges, and the impact of implementing the new PBR mechanism, partially offset by the 5.9 per cent electricity rate increase, electricity sales growth and the impact of a lower effective corporate income tax rate.

Year to date over the same period last year, earnings were $1.0 million higher, primarily due to electricity sales growth, the 5.9 per cent electricity rate increase and the impact of a lower effective corporate income tax rate, partially offset by higher amortization costs and finance charges, and the impact of implementing the new PBR mechanism.

Electricity Sales: Electricity sales were 20 GWh, or 3.1 per cent, higher quarter over quarter, and 28 GWh, or 1.9 per cent, higher year to date over the same period last year. Sales growth was primarily attributable to continued customer growth in the Okanagan area.

Revenue: Revenue was $1.7 million and $9.1 million higher quarter over quarter and year to date over the same period last year, respectively. The increase was primarily due to the 5.9 per cent electricity rate increase and customer growth, partially offset by an increase in PBR incentive adjustments owing to customers as a result of the new PBR mechanism approved by the BCUC. Revenue also increased year to date over the same period last year due to higher revenue contribution from Princeton Light and Power Company, Limited ("PLP") of $0.9 million. PLP was acquired on May 31, 2005.

Expenses: Energy supply costs were $1.9 million and $2.5 million higher quarter over quarter and year to date over the same period last year, respectively, primarily as a result of increased electricity sales and a higher proportion of purchased versus generated volumes. Energy supply costs represent the cost of purchasing energy and capacity from third parties. Hydroelectric facilities owned by FortisBC generate approximately 50 per cent of the energy and 30 per cent of the capacity necessary to meet existing customer demand. The majority of the additional energy and capacity required to meet existing customer demand is purchased under firm, long-term power purchase contracts. Any remaining energy and capacity required is purchased on the open market and is subject to fluctuations in market rates.

Operating expenses were comparable quarter over quarter. The favourable impact on operating expenses of an increase in the rate used for capitalizing overhead costs quarter over quarter, from approximately 9.0 per cent to 20.0 per cent, as a result of the Negotiated Settlement Agreement, was nearly offset by an unfavourable $0.9 million adjustment recorded in the second quarter of 2006. FortisBC's 2006 Application and first quarter 2006 financial statements were based on a capitalized overhead rate of approximately 27.5 per cent, effective January 1, 2006, whereas the rate in the Negotiated Settlement Agreement was approved at 20.0 per cent, resulting in the $0.9 million adjustment to operating expenses in the second quarter of 2006 to adjust for the lower approved capitalization rate, effective January 1, 2006. Operating expenses decreased $0.6 million year to date compared to the same period last year, primarily due to increased capitalized overhead of $2.5 million, partially offset by the impact of increased customer and system maintenance activities and general inflationary increases totaling approximately $0.5 million, higher PLP operating expenses of $0.6 million, increased expenses related to non-regulated operating, maintenance and management services of $0.3 million, and a $0.5 million B.C. capital tax appeal refund recorded during the second quarter of 2005.

Amortization costs were $1.8 million and $4.4 million higher quarter over quarter and year to date over the same period last year, respectively. The increase was primarily due to a higher composite depreciation rate and the impact of an increase in FortisBC's depreciable asset base due to its capital expenditure program. The composite depreciation rate increased from 2.6 per cent to 3.2 per cent, effective January 1, 2006, as a result of the Negotiated Settlement Agreement. Based on the results of a depreciation study undertaken to estimate the appropriate useful life over which FortisBC's property, plant and equipment should be amortized, FortisBC's 2006 Application and first quarter 2006 financial statements were based on a composite depreciation rate of 3.6 per cent. A favourable $0.4 million adjustment to reduce amortization costs was recorded in the second quarter of 2006 to adjust for the lower approved composite depreciation rate, effective January 1, 2006.

Finance charges were $1.5 million and $2.5 million higher quarter over quarter and year to date over the same period last year, respectively, primarily due to the cost of increased borrowings to finance the Company's capital expenditure program.

Corporate taxes decreased $1.6 million quarter over quarter, primarily due to lower earnings before corporate income taxes, the elimination of the Federal Large Corporations' Tax, effective January 1, 2006, and the impact of timing differences, including the impact of increased CCA rates for income tax deduction purposes. Corporate taxes decreased $0.7 million year to date compared to the same period last year primarily due to the elimination of the Federal Large Corporations' Tax, the impact of timing differences, including the impact of increased CCA rates, partially offset by increased earnings before corporate income taxes.



Newfoundland Power

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Newfoundland Power
Financial Highlights (Unaudited)
Period Ended June 30th
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Quarter Year-to-date
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2006 2005 Variance 2006 2005 Variance
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Electricity
Sales (GWh) 1,137 1,240 (103) 2,771 2,940 (169)
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($ millions)
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Revenue 97.3 105.7 (8.4) 229.1 241.1 (12.0)
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Energy Supply
Costs 57.7 57.5 0.2 140.3 140.6 (0.3)
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Operating Expenses 12.5 13.8 (1.3) 27.1 28.0 (0.9)
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Amortization 7.9 9.3 (1.4) 17.7 19.9 (2.2)
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Finance Charges 8.0 7.7 0.3 16.2 15.4 0.8
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Corporate Taxes 3.0 5.7 (2.7) 8.8 12.4 (3.6)
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Non-Controlling
Interest 0.2 0.2 - 0.3 0.3 -
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Earnings 8.0 11.5 (3.5) 18.7 24.5 (5.8)
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Regulation: In January 2006, Newfoundland Power received approval from the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB") of its final 2006 electricity rates, which remain unchanged from 2005. The rates are based on a range of rate of return on rate base of 8.50 per cent to 8.86 per cent, which includes an allowed ROE of 9.24 per cent, also unchanged from 2005.

Effective January 1, 2006, the Company changed its revenue recognition policy from the billed basis to the accrual basis, as approved by the PUB on December 23, 2005. The accrual method for recognizing revenue is consistent with other Canadian utilities. In conjunction with the change in the revenue recognition policy, the PUB approved a one-time revenue accrual of $3.1 million in 2006. This amount represents that portion of unbilled revenue, as at December 31, 2005, of $23.6 million, required to offset the income tax effects to be incurred in 2006 relating to the change to the accrual basis of revenue recognition. The disposition of the remaining 2005 unbilled revenue balance has been deferred until the Company's next general rate application. The PUB also ordered that the Company defer recovery of a $5.8 million increase in 2006 amortization costs. The deferral increases earnings in 2006 and establishes a regulatory asset to be recovered in future customer rates. During the second quarter and year to date, $1.4 million and $3.1 million, respectively, of the $5.8 million deferral was recognized which offset what would otherwise have been an increase in amortization costs during these periods.

Electricity rates charged to customers increased by an average rate of 4.8 per cent, effective July 1, 2006. The increase resulted from the normal annual operation of the Rate Stabilization Plan of Newfoundland and Labrador Hydro ("Newfoundland Hydro"). Variances in the cost of fuel used by Newfoundland Hydro to generate the electricity it sells to Newfoundland Power are captured and flowed through to Newfoundland Power's customers through the operation of the Rate Stabilization Plan. The increase in customer rates will have no direct impact on Newfoundland Power's earnings.

Earnings: Newfoundland Power's earnings were $3.5 million and $5.8 million lower quarter over quarter and year to date compared to the same period last year, respectively. The decrease was primarily due to the change in the Company's revenue recognition policy, which reduced earnings by $3.2 million and $5.2 million quarter over quarter and year to date compared to the same period last year, respectively.

The transition to recording revenue on the accrual basis, while having no material impact on annual earnings, results in a shift in 2006 quarterly earnings compared to 2005. Earnings in the first and second quarters have been reduced compared to the same quarters in 2005, while earnings in the third and fourth quarters are expected to increase by a similar amount. Additionally, earnings were lower quarter over quarter and year to date compared to the same period last year due to higher finance charges and lower interest revenue, partially offset by lower corporate income taxes and operating expenses. During the second quarter of 2005, $1.4 million in after-tax interest revenue was recorded as a result of an income tax settlement with Canada Revenue Agency ("CRA").

Electricity Sales: Electricity sales were 103 GWh, or 8.3 per cent, lower quarter over quarter, and 169 GWh, or 5.7 per cent, lower year to date compared to the same period last year. Electricity sales during the second quarter and year to date were 94 GWh and 151 GWh lower, respectively, due to the change in revenue recognition policy. Prior to 2006, revenue was recorded as bills were rendered to customers based on meter reading dates. As a result, approximately one-half of the total value of electricity service delivered to customers during a month was not recognized as revenue until billed in the following month. Effective January 1, 2006, under the accrual basis of recognizing revenue, the unbilled revenue is accrued in the same month in which electricity service is delivered. The 94 GWh decrease in electricity sales quarter over quarter represented the difference between electricity delivered to customers during the latter half of March 2006 and the latter half of June 2006. The 151 GWh decrease in electricity sales year to date compared to the same period last year represented the difference between electricity delivered to customers during the latter half of December 2005 and the latter half of June 2006. Sales to be accrued in the latter half of 2006 are expected to offset this reduction. Annual electricity sales for 2006 are not expected to be materially different from 2005 as a result of the change in the revenue recognition policy. The remaining 9 GWh, or 0.7 per cent, decrease in electricity sales quarter over quarter and 18 GWh, or 0.6 per cent, decrease year to date compared to the same period last year was due to a reduction in average consumption by both residential and commercial customers. Average consumption decreased due to rising electricity prices and a general slowdown in economic activity.

Revenue: Revenue was $8.4 million and $12.0 million lower quarter over quarter and year to date compared to the same period last year, respectively, primarily due to the change in the revenue recognition policy. Additionally, revenue during the second quarter of 2005 included interest revenue of $2.1 million that resulted from the settlement of an income tax issue with CRA. The change to the accrual basis for recognizing revenue resulted in a $6.4 million and $10.7 million reduction in revenue quarter over quarter and year to date compared to the same period last year, respectively. The decreases are expected to reverse with the accrual of higher sales and associated revenue in the latter half of 2006. Lower average consumption also contributed to a decrease in revenue; however, the decrease was partially offset by the recognition of $0.7 million and $1.6 million during the second quarter and year to date, respectively, of the one-time $3.1 million revenue accrual approved by the PUB, and an increase in fixed customer charge revenue due to customer growth of 1.1 per cent.

Expenses: Energy supply costs were comparable quarter over quarter. Energy supply costs decreased $0.3 million year to date compared to the same period last year, primarily due to lower average consumption. Production from the Company's own generating facilities during the second quarter of 2006 resulted in a $0.5 million decrease in energy supply costs compared to the same quarter last year and a $0.1 million increase year to date over the same period last year.

Operating expenses were $1.3 million and $0.9 million lower quarter over quarter and year to date compared to the same period last year, respectively, primarily due to reduced labour costs resulting from a 2005 early retirement program and the Company's ongoing focus on cost control and operating expense reduction initiatives.

Amortization costs decreased $1.4 million and $2.2 million quarter over quarter and year to date compared to the same period last year, respectively, due to a difference in the quarterly allocation of amortization based on net margin, partially offset by the impact of continued investment in the Company's capital assets. Annual amortization of capital assets continues to be allocated quarterly based on net margin. Therefore, as a result of lower net margins, amortization was reduced by $1.6 million and $2.8 million quarter over quarter and year to date compared to the same period last year, respectively. This decrease is expected to reverse through increased amortization in the latter half of 2006.

Finance charges were $0.3 million and $0.8 million higher quarter over quarter and year to date over the same period last year, respectively, due to the replacement of $60 million of lower-cost short-term borrowings with a new series of 5.441%, 30-year first mortgage sinking fund bonds in August 2005.

Corporate taxes decreased $2.7 million and $3.6 million quarter over quarter and year to date compared to the same period last year, respectively, due to lower earnings before taxes, the elimination of the Federal Large Corporations' Tax, effective January 1, 2006, and increased CCA rates.



Maritime Electric

---------------------------------------------------------------------
Maritime Electric
Financial Highlights (Unaudited)
Period Ended June 30th
---------------------------------------------------------------------
Quarter Year-to-date
---------------------------------------------------------------------
2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Electricity
Sales (GWh) 241 241 - 496 497 (1)
---------------------------------------------------------------------
($ millions)
---------------------------------------------------------------------
Revenue 29.2 28.3 0.9 59.0 57.6 1.4
---------------------------------------------------------------------
Energy Supply
Costs 17.2 17.0 0.2 35.5 35.1 0.4
---------------------------------------------------------------------
Operating Expenses 3.3 3.1 0.2 6.4 6.2 0.2
---------------------------------------------------------------------
Amortization 2.6 2.4 0.2 5.1 4.8 0.3
---------------------------------------------------------------------
Finance Charges 2.6 2.0 0.6 4.9 4.2 0.7
---------------------------------------------------------------------
Corporate Taxes 1.3 1.5 (0.2) 2.8 2.9 (0.1)
---------------------------------------------------------------------
Earnings 2.2 2.3 (0.1) 4.3 4.4 (0.1)
---------------------------------------------------------------------
---------------------------------------------------------------------


Regulation: On June 27, 2006, the Island Regulatory and Appeals Commission ("IRAC") issued its Order with respect to Maritime Electric's general rate application filed on January 31, 2006, approving an overall average decrease in customer electricity rates of 1.2 per cent, effective July 1, 2006. The 1.2 per cent decrease is the result of the impact of the refund to customers of energy-related costs associated with the operation of the energy cost adjustment mechanism ("ECAM"), partially offset by a 3.35 per cent increase in basic electricity rates. IRAC also approved Maritime Electric's maximum allowed ROE at 10.25 per cent and approved continuation of the amortization of the $20.8 million in deferred costs recoverable from customers accumulated as at December 31, 2003 in the amount of $1.5 million in 2006. IRAC also ordered the continuation of the interim and transitional ECAM currently in effect, with the amortization period contained in the ECAM to decrease from 18 months to 12 months, effective January 1, 2007.

On April 6, 2006, Maritime Electric filed with IRAC an Application for approval of a 39-MW Wind Power Purchase Agreement ("Agreement") with the Government of PEI. If approved, the Agreement will take effect on January 1, 2007. Recent legislation proclaimed by the Government of PEI will require Maritime Electric to obtain at least 15 per cent of its annual energy requirements from renewable sources such as wind-powered energy by 2010. This Agreement will help the Company reach this 15 per cent target.

Earnings: Maritime Electric's earnings of $2.2 million and $4.3 million for the second quarter and year to date, respectively, were comparable to the same periods last year.

Electricity Sales: Electricity sales of 241 GWh and 496 GWh for the second quarter and year to date, respectively, were comparable to the same periods last year. A decrease in residential sales due to a milder-than-normal winter and spring was offset by increased commercial sales, primarily due to higher consumption by customers in the general service sector.

Revenue: Revenue increased $0.9 million and $1.4 million quarter over quarter and year to date over the same period last year, respectively, as a result of a 2.0 per cent basic electricity rate increase, effective July 1, 2005, and a decrease in the amortization of pre-2004 deferred costs recoverable from customers of $0.3 million and $0.5 million quarter over quarter and year to date compared to the same period last year, respectively.

Expenses: Energy supply costs (adjusted for the ECAM) for the second quarter and year to date were slightly higher compared to the same periods last year. Gross energy supply costs before ECAM adjustments, however, were $1.1 million and $1.8 million lower than for the same quarter and year to date period last year, respectively, primarily due to lower-than-anticipated curtailable energy costs and the favourable impact of foreign exchange. Maritime Electric pays for the majority of its energy supply costs in US dollars. During the first half of 2006 and 2005, Maritime Electric purchased the majority of its energy from New Brunswick Power Corporation ("NB Power") under several energy purchase agreements.

Operating expenses were $0.2 million higher quarter over quarter and year to date over the same period last year, primarily due to the timing of line maintenance activities.

Amortization costs increased slightly over the same periods last year, reflecting the addition of the 50-MW combustion turbine generating facility.

Finance charges increased $0.6 million and $0.7 million quarter over quarter and year to date over the same period last year, respectively, primarily due to financing associated with the new 50-MW combustion turbine generating facility and a reduction in the amount of interest capitalized during construction.



FortisOntario

---------------------------------------------------------------------
FortisOntario
Financial Highlights (Unaudited)
Period Ended June 30th
---------------------------------------------------------------------
Quarter Year-to-date
---------------------------------------------------------------------
2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Electricity
Sales (GWh) 259 272 (13) 584 603 (19)
---------------------------------------------------------------------
($ millions)
---------------------------------------------------------------------
Revenue 32.9 32.0 0.9 66.2 70.2 (4.0)
---------------------------------------------------------------------
Energy
Supply Costs 24.8 24.9 (0.1) 50.6 55.5 (4.9)
---------------------------------------------------------------------
Operating Expenses 3.9 3.0 0.9 7.2 6.2 1.0
---------------------------------------------------------------------
Amortization 1.3 1.3 - 2.7 2.5 0.2
---------------------------------------------------------------------
Finance Charges 1.3 1.3 - 2.5 2.6 (0.1)
---------------------------------------------------------------------
Corporate Taxes 1.1 0.6 0.5 1.8 1.4 0.4
---------------------------------------------------------------------
Earnings 0.5 0.9 (0.4) 1.4 2.0 (0.6)
---------------------------------------------------------------------
---------------------------------------------------------------------


Regulation: On April 28, 2006, the Ontario Energy Board ("OEB") issued its Decision and Order concerning Canadian Niagara Power's application for new electricity rates to become effective May 1, 2006. The Decision and Order also approved the final recovery from customers of regulatory assets including the transitional costs incurred in preparation of the open market in May 2002. The impact of the Decision and Order, on a typical residential customer in Fort Erie, Port Colbourne and Gananoque with average monthly consumption of 1,000 kilowatt hours ("kWh") was an increase in customer rates, effective May 1, 2006, of 17.5 per cent, 17.5 per cent, and 10.8 per cent, respectively. The rate increases included the impact associated with the flow through to specified low volume customers of increased power prices paid to the Independent Electricity System Operator as set under the OEB's Regulated Price Plan ("RPP"). The new electricity distribution rates are based on 2004 costs using a deemed capital structure at 50 per cent long-term debt and 50 per cent common equity, with an allowed ROE of 9.0 per cent.

Earnings: Earnings were $0.4 million and $0.6 million lower quarter over quarter and year to date compared to the same period last year, respectively. The decrease was primarily due to higher corporate income taxes.

Electricity Sales: Electricity sales were 13 GWh, or 4.8 per cent, lower quarter over quarter, and 19 GWh, or 3.2 per cent, lower year to date compared to the same period last year. The decrease was primarily due to the impact of moderate weather conditions in the first half of 2006 compared to the same period last year and the loss in December 2005 of an industrial customer.

Revenue: Revenue was $0.9 million higher quarter over quarter, primarily due to higher customer electricity rates, effective May 1, 2006, partially offset by decreased market energy costs billed to customers and reduced electricity sales.

Revenue decreased $4.0 million year to date compared to the same period last year, primarily due to decreased market energy costs billed to customers and reduced electricity sales, partially offset by higher customer electricity rates, effective May 1, 2006.

Expenses: Energy supply costs decreased $0.1 million and $4.9 million quarter over quarter and year to date compared to the same period last year, respectively, primarily due to lower market energy prices and decreased electricity sales, partially offset by the RPP rate increase, effective May 1, 2006.

Operating expenses were $0.9 million higher quarter over quarter, primarily due to a $0.3 million increase in the allocation of shared-service costs from non-regulated Ontario generation operations, increased payroll and benefit costs driven by the transferring of certain Rankine Generating Station employees to Canadian Niagara Power and the impact of timing of expenditures between the first and second quarters of 2006. Year to date over the same period last year, operating expenses were $1.0 million higher primarily driven by a $0.6 million increase in the allocation of shared-service costs from non-regulated Ontario generation operations and an increase in payroll and benefit costs as a result of transferring certain Rankine Generating Station employees to Canadian Niagara Power.

Corporate taxes were $0.5 million and $0.4 million higher quarter over quarter and year to date over the same period last year, respectively, primarily due to the reduction of future income tax asset balances resulting from the recently enacted future Federal income tax rate reductions.



REGULATED UTILITIES - CARIBBEAN
Belize Electricity

---------------------------------------------------------------------
Belize Electricity
Financial Highlights (Unaudited)
Period Ended June 30th
---------------------------------------------------------------------
Quarter Year-to-date
---------------------------------------------------------------------
2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Average US:CDN
Exchange Rate 1.12 1.24 (0.12) 1.14 1.24 (0.10)
---------------------------------------------------------------------
Electricity
Sales (GWh) 93 92 1 173 168 5
---------------------------------------------------------------------
($ millions)
---------------------------------------------------------------------
Revenue 22.7 18.7 4.0 42.8 34.1 8.7
---------------------------------------------------------------------
Energy
Supply Costs 13.4 10.0 3.4 25.1 18.1 7.0
---------------------------------------------------------------------
Operating Expenses 2.7 2.9 (0.2) 5.4 5.7 (0.3)
---------------------------------------------------------------------
Amortization 1.4 1.6 (0.2) 2.8 3.3 (0.5)
---------------------------------------------------------------------
Finance Charges 1.3 1.4 (0.1) 2.9 2.8 0.1
---------------------------------------------------------------------
Foreign Exchange
Loss (Gain) 0.2 (0.2) 0.4 0.3 (0.4) 0.7
---------------------------------------------------------------------
Corporate Taxes
and Non-Controlling
Interest 1.4 1.1 0.3 2.5 1.8 0.7
---------------------------------------------------------------------
Earnings 2.3 1.9 0.4 3.8 2.8 1.0
---------------------------------------------------------------------
---------------------------------------------------------------------


Regulation: Belize Electricity's base electricity rates are comprised of 2 components. The first component is Value Added Delivery ("VAD") and the second is the cost of fuel and purchased power ("COP"), including the variable cost of generation, which is a flow through in customer rates.

On July 14, 2005, the Public Utilities Commission of Belize ("PUC") approved a new 4-year tariff setting agreement, resulting in an 11 per cent overall increase in electricity rates, inclusive of the recovery of rate stabilization account balances, to BZ39.0 cents per kWh from BZ34.9 cents per kWh, effective July 1, 2005. The VAD component of electricity rates increased to BZ16.2 cents per kWh from BZ14.0 cents per kWh while the COP component increased to BZ21.0 cents per kWh from BZ17.5 cents per kWh. The component related to the recovery of excess fuel costs deferred to the Cost of Power Rate Stabilization Account ("CPRSA") was reduced from BZ3.4 cents per kWh to BZ1.8 cents per kWh.

On December 31, 2005, the PUC approved a BZ0.6 cent per kWh, or 1.5 per cent, increase in electricity rates associated with the recovery of the excess deferrals to the CPRSA and a BZ4.5 cents per kWh, or 11.5 per cent, increase in electricity rates related to COP. There was no increase in the VAD component of rates. The result was an overall 13 per cent increase in electricity rates to BZ44.1 cents per kWh from BZ39.0 cents per kWh, effective January 1, 2006.


This increase in electricity rates was the result of the PUC's Final Decision on Belize Electricity's Threshold Event Review Application filed on December 20, 2005 and had no impact on Belize Electricity's earnings due to the flow through of cost of power to customers.

On May 9, 2006, the PUC issued its Final Decision approving, as filed, Belize Electricity's Annual Tariff Review Application for the annual tariff period July 1, 2006 through June 30, 2007. The Final Decision confirmed that the average mean electricity rate, at BZ44.1 cents per kWh, and its components remain unchanged from those in effect from January 1, 2006. The tariff can only be revisited before June 30, 2007 by way of a Threshold Event Review Proceeding based on fluctuations in the cost of power and fuel.

Earnings: Belize Electricity's earnings were $0.4 million (BZ$1.1 million) and $1.0 million (BZ$2.2 million) higher quarter over quarter and year to date over the same period last year, respectively. The increase was driven by the 11 per cent overall increase in electricity rates, effective July 1, 2005, as a result of the new 4-year tariff agreement, and higher electricity sales, partially offset by the foreign exchange impact associated with the Company's Euro and Canadian dollar-denominated debt. Earnings contribution from Belize Electricity was also unfavourably impacted by the weakening of the US dollar against the Canadian dollar compared to the same periods last year.

Electricity Sales: Electricity sales were 1 GWh, or 1.1 per cent, higher quarter over quarter, and 5 GWh, or 3.0 per cent, higher year to date over the same period last year, primarily due to increased sales in both the residential and commercial sectors driven by economic growth. The increase in energy sales quarter over quarter was moderate due to a slowdown in economic growth.

Revenue: Revenue was $4.0 million (BZ$10.4 million) and $8.7 million (BZ$20.1 million) higher quarter over quarter and year to date over the same period last year, respectively. Excluding foreign exchange impacts, revenue increased 34.7 per cent and 36.5 per cent over the same quarter and year-to-date period last year, respectively. The increase was driven by the increase in the VAD and COP components of electricity rates, effective July 1, 2005, the increase in the COP component of electricity rates, effective January 1, 2006, and electricity sales growth.

Expenses: Energy supply costs were $3.4 million (BZ$7.7 million) and $7.0 million (BZ$14.8 million) higher quarter over quarter and year to date over the same period last year, respectively. Excluding foreign exchange impacts, energy supply costs increased 47.8 per cent and 50.5 per cent over the same quarter and year-to-date period last year, respectively. The increase was primarily due to increases in the COP component of electricity rates, effective July 1, 2005 and January 1, 2006, and electricity sales growth.

Excluding foreign exchange impacts, operating expenses were BZ$0.2 million and BZ$0.4 million higher quarter over quarter and year to date over the same period last year, respectively, primarily due to higher employee costs and general increases in the cost of goods and services.

Amortization costs were slightly lower quarter over quarter and year to date compared to the same period last year primarily due to the recovery of all generation equipment depreciation through cost of power, as a result of the July 1, 2005 Final Tariff Decision, and the impact of foreign exchange, partially offset by increased amortization costs due to capital asset growth.

The foreign exchange losses and gains primarily related to foreign currency exchange rate fluctuations associated with Belize Electricity's Euro and Canadian dollar-denominated debt. Net foreign exchange losses for the second quarter of 2006 were $0.2 million (BZ$0.4 million) compared to a net foreign exchange gain of $0.2 million (BZ$0.4 million) for the second quarter of 2005. Year to date, net foreign exchange losses were $0.3 million (BZ$0.5 million) compared to a net foreign exchange gain of $0.4 million (BZ$0.7 million) for the same period last year. The US dollar weakened relative to the Euro and Canadian dollar during the second quarter and year to date compared to the same periods last year.

In June 2006, Belize Electricity received gross proceeds of approximately $37.2 million (BZ$66.8 million) upon the closing of a share purchase offering in which approximately 97 per cent of share purchase rights issued were exercised. Under the offering, Belize Electricity issued a right to acquire one Ordinary Share of the Company at par value BZ$2.00 for every Ordinary Share issued and outstanding.

The ownership level of Belize Electricity by Fortis increased slightly from 68.5 per cent to 70.1 per cent as a result of Fortis purchasing all of the Ordinary Shares on which it had rights, in addition to shares acquired under rights purchased from other shareholders. The result was a $26.8 million increase in the Corporation's investment in Belize Electricity. The proceeds from the rights offering enabled Belize Electricity to repay certain trade payables, loan commitments and overdraft facilities incurred primarily to finance the CPRSA for the cost of power and fuel. Additionally, it will allow the Company to continue with capital projects to improve service reliability and meet growing energy demand.



Caribbean Utilities

---------------------------------------------------------------------
Caribbean Utilities
Financial Highlights (Unaudited)
Period Ended June 30th
---------------------------------------------------------------------
Quarter Year-to-date
---------------------------------------------------------------------
2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Average US:CDN
Exchange Rate (1) 1.15 1.23 (0.08) 1.16 1.22 (0.06)
---------------------------------------------------------------------
---------------------------------------------------------------------
Equity Income 2.1 3.1 (1.0) 3.7 5.6 (1.9)
---------------------------------------------------------------------

(1) Quarterly and year-to-date equity income for 2006 and 2005 were
translated at the average US:CDN exchange rate during the 3-month
and 6-month periods ended April 30, 2006 and 2005, respectively,
as equity income is recorded on a lag basis.


Fortis accounts for its 37.4 per cent interest in Caribbean Utilities on an equity basis. Equity income is recorded on a lag basis and, as a result, the quarterly equity income noted above represents the Corporation's share of Caribbean Utilities' earnings for its fourth quarters ended April 30, 2006 and 2005.

Regulation: Licence negotiations between Caribbean Utilities and the Government of the Cayman Islands recommenced in November 2005. The Company's Licence remains in full force and effect until January 2011, or until replaced by a new Licence by mutual agreement.

Equity Income: In June 2006, customer numbers at Caribbean Utilities surpassed pre-Hurricane Ivan levels. At the end of July 2006, the Company's total owned generating capacity reached 120 MW compared to 123 MW pre-Hurricane Ivan.

Equity income recorded from Caribbean Utilities was $1.0 million lower quarter over quarter. Excluding the $1.1 million positive adjustment to equity earnings in the second quarter of 2005 related to a change in Caribbean Utilities' accounting practice for recognizing unbilled revenue, equity earnings were comparable quarter over quarter. Earnings growth due to post-Hurricane Ivan sales recovery, the impact of new development projects including the 365-room Ritz Carlton hotel, and revenue associated with the hurricane cost recovery surcharge ("CRS") implemented on August 1, 2005 was partially offset by higher leased costs associated with temporary generation, increased insurance premiums, insurance-related consulting fees and interest expenses in addition to higher amortization costs. Basic electricity sales at Caribbean Utilities increased 39 per cent during its fourth quarter ended April 30, 2006 over the same quarter last year. Amortization costs are expected to continue to increase as the Company's assets are brought back into service post-Hurricane Ivan and based on projected capital expenditures. In May 2006, Caribbean Utilities entered into a project agreement with its strategic alliance partner, MAN B&W Diesel AG of Germany, for the purchase of a 16-MW diesel generating unit and auxiliary equipment to be commissioned in the summer of 2007 for a total project cost of approximately US$22.2 million. Future lease costs are expected to decline as temporary leased generation is replaced with owned generation capacity.

During its fourth quarter, the Company recorded approximately US$1.0 million in revenue associated with the CRS, with approximately US$10.4 million, as of April 30, 2006, of direct uninsured Hurricane Ivan losses remaining to be collected from customers through the CRS. The CRS is expected to remain in place until 2008. Under its current Licence, Caribbean Utilities is entitled to a 2.0 per cent basic electricity rate increase, effective August 1, 2006, primarily the result of increased operating expenses and infrastructure investment. Caribbean Utilities will not implement this basic electricity rate increase, as it had agreed with the Government of the Cayman Islands that it would freeze basic rates during the period of the hurricane CRS.

During its fourth quarter ended April 30, 2006, Caribbean Utilities agreed to a settlement with the insurance underwriters in the net amount of US$31.1 million with respect to property and business interruption ("BI") insurance loss claims associated with damage from Hurricane Ivan. As at April 30, 2006, the Company received advance insurance payments of US$22.1 million with the final payment of US$9.0 million received in June 2006. The total BI insurance loss claim from the end of the deductible period on October 24, 2004 to April 30, 2006 was US$14.8 million with US$0.6 million recorded in the fourth quarter. There will be no further BI insurance loss claims related to Hurricane Ivan in Caribbean Utilities' future earnings. During the fourth quarter ended April 30, 2006, the Company recorded a US$1.2 million gain on disposal of assets associated with the insurance settlement compared to a US$1.5 million favourable adjustment associated with a reduction of Hurricane Ivan loss estimates during the same quarter in 2005.

Equity income was $1.9 million lower year to date compared to the same period last year due to factors described for the quarter, in addition to higher fuel expenses associated with the timing of expensing of previously deferred fuel, primarily during Caribbean Utilities' third quarter ended January 31, 2006. Under its current Licence, Caribbean Utilities recovers the cost of fuel above the base price from its customers through a monthly fuel factor adjustment on a 2-month delay basis and defers its recoverable fuel cost on a rolling 2-month deferral basis. Movement in the deferred fuel account is normal and dependent on fuel prices, fuel usage and energy sales. Large swings in this account, although normal, occur infrequently and, for any particular period, the impact is timing in nature. Equity income from Caribbean Utilities for the second quarter and year to date was also unfavorably impacted by the weakening of the US dollar against the Canadian dollar compared to the same periods last year.



NON-REGULATED - FORTIS GENERATION

---------------------------------------------------------------------
Non-Regulated - Fortis Generation
Financial Highlights (Unaudited)
Period Ended June 30th
---------------------------------------------------------------------
Quarter Year-to-date
---------------------------------------------------------------------
Energy Sales (GWh) 2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Central
Newfoundland 39 48 (9) 77 83 (6)
---------------------------------------------------------------------
Ontario 177 176 1 364 360 4
---------------------------------------------------------------------
Belize 33 7 26 60 14 46
---------------------------------------------------------------------
British Columbia 13 11 2 17 16 1
---------------------------------------------------------------------
Upper New
York State 28 16 12 57 33 24
---------------------------------------------------------------------
Total 290 258 32 575 506 69
---------------------------------------------------------------------
---------------------------------------------------------------------
Quarter Year-to-date
---------------------------------------------------------------------
($ millions) 2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Revenue 20.5 19.2 1.3 39.8 36.2 3.6
---------------------------------------------------------------------
Energy
Supply Costs 1.4 1.8 (0.4) 3.3 3.6 (0.3)
---------------------------------------------------------------------
Operating Expenses 3.9 4.4 (0.5) 7.9 9.3 (1.4)
---------------------------------------------------------------------
Amortization 2.6 2.5 0.1 5.3 5.1 0.2
---------------------------------------------------------------------
Finance Charges 2.6 4.0 (1.4) 5.2 7.9 (2.7)
---------------------------------------------------------------------
Gain on Settlement
of Contractual
Matters - - - - (10.0) 10.0
---------------------------------------------------------------------
Corporate Taxes 2.8 2.4 0.4 5.1 5.9 (0.8)
---------------------------------------------------------------------
Non-Controlling
Interest 0.5 0.9 (0.4) 0.9 1.2 (0.3)
---------------------------------------------------------------------
Earnings 6.7 3.2 3.5 12.1 13.2 (1.1)
---------------------------------------------------------------------
---------------------------------------------------------------------


Earnings: The earnings contribution from Non-Regulated - Fortis Generation increased $3.5 million quarter over quarter, driven by higher production, an insurance gain, and lower finance charges and operating costs, partially offset by the impact of lower average wholesale energy prices in Ontario. Year to date, the earnings contribution was down $1.1 million from the same period last year. Earnings for the first quarter last year included the $10.0 million ($7.9 million after-tax) Ontario Settlement.

Excluding the impact in the first quarter of 2005 of the Ontario Settlement, earnings were $6.8 million higher for the first half of 2006 compared to the same period last year due to the factors described for the quarter.

Energy Sales: Energy sales were 32 GWh, or 12.4 per cent, higher quarter over quarter, and 69 GWh, or 13.6 per cent, higher year to date over the same period last year, primarily due to higher hydroelectric production in Belize and Upper New York State, partially offset by lower production in central Newfoundland. Production in Belize was favourably impacted by higher rainfall levels and the operation of the Chalillo dam and hydroelectric generating facility. The Chalillo reservoir is currently at its full supply level which is equivalent to 45 GWh of hydroelectric production. Production in Upper New York State increased primarily due to nearly 6 months of operations of the Dolgeville plant in the first half of 2006 compared to 1 month in the first half of 2005 and higher production at the Moose River plant. In late January 2005, the Dolgeville plant went out of service as a result of flooding and did not resume production until October 2005. In late June 2006, the Dolgeville plant experienced another flood and is expected to be out of commission until late in the third quarter of 2006. Production was lower in central Newfoundland due to lower rainfall levels.

Revenue: Revenue was $1.3 million and $3.6 million higher quarter over quarter and year to date over the same period last year, respectively. The increase was driven by higher hydroelectric production in Belize and a $1.2 million ($0.7 million after-tax) gain on insurance, partially offset by the impact of lower average wholesale energy prices in Ontario. The insurance gain related to the Dolgeville plant in Upper New York State as a result of the 2005 flood. The gain represented the final balance of the cash proceeds received related to property damage and business interruption insurance claims. The average wholesale energy price per megawatt hour ("MWh") in Ontario was $45.32 compared to $60.24 for the same quarter last year, resulting in a decrease in revenue of approximately $2.4 million quarter over quarter. During the first half of 2006, the average wholesale energy price per MWh in Ontario was $48.14 compared to $58.13 for the first half of 2005, resulting in a decrease in revenue of approximately $3.2 million year to date.

Expenses: Operating expenses were $0.5 million and $1.4 million lower quarter over quarter and year to date compared to the same period last year, respectively. Approximately $0.2 million of cost savings associated with the cessation of operations at the Rankine Generating Station, upon implementation of the Niagara Exchange Agreement ("NEA") in late 2005, were experienced in the second quarter of 2006 compared to the same quarter last year. Year to date, the costs savings associated with the Rankine Generating Station were approximately $0.6 million compared to the same period last year. The NEA assigns FortisOntario's water rights on the Niagara River to OPGI and facilitates the irrevocable exchange of 75 MW of wholesale hydroelectric power supply to FortisOntario from OPGI until April 30, 2009 in exchange for FortisOntario's agreement not to seek renewal of the water entitlement at that time. Operating expenses also decreased due to a reduction in the allocation of shared-service costs, and lower water right fees as a result of lower revenues. Additionally, business development costs in Ontario were $0.3 million lower in the first quarter of 2006 compared to the first quarter of 2005.

Finance charges were $1.4 million and $2.7 million lower quarter over quarter and year to date compared to the same period last year, respectively. The decrease was primarily due to a reduction of inter-company finance charges in the Belizean operations and the early repayment of a $22.5 million term loan in the second quarter of 2005 associated with the Ontario operations.



NON-REGULATED - FORTIS PROPERTIES

---------------------------------------------------------------------
Non-Regulated - Fortis Properties
Financial Highlights (Unaudited)
Period Ended June 30th
---------------------------------------------------------------------
Quarter Year-to-date
---------------------------------------------------------------------
($ millions) 2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Real Estate
Revenue 13.7 13.3 0.4 27.3 26.5 0.8
---------------------------------------------------------------------
Hospitality
Revenue 28.2 27.5 0.7 49.8 47.3 2.5
---------------------------------------------------------------------
Total Revenue 41.9 40.8 1.1 77.1 73.8 3.3
---------------------------------------------------------------------
Operating Expenses 26.3 25.2 1.1 50.9 48.1 2.8
---------------------------------------------------------------------
Amortization 2.9 2.8 0.1 5.7 5.3 0.4
---------------------------------------------------------------------
Finance Charges 5.0 4.7 0.3 10.1 9.6 0.5
---------------------------------------------------------------------
Gain on Sale
of Income
Producing
Property (2.1) - (2.1) (2.1) - (2.1)
---------------------------------------------------------------------
Corporate Taxes 1.7 3.3 (1.6) 2.9 4.4 (1.5)
---------------------------------------------------------------------
Earnings 8.1 4.8 3.3 9.6 6.4 3.2
---------------------------------------------------------------------
---------------------------------------------------------------------


Earnings: Fortis Properties' earnings were $3.3 million and $3.2 million higher quarter over quarter and year to date over the same period last year, respectively. The increase was primarily due to a $2.1 million ($1.6 million after-tax) gain on the sale of the Days Inn Sydney and lower corporate income taxes.

Revenue: Real estate revenue was $0.4 million and $0.8 million higher quarter over quarter and year to date over the same period last year, respectively, due to growth experienced in all of the Company's operating regions. The occupancy level in the Real Estate Division was 95.6 per cent at June 30, 2006, up from 95.3 per cent at June 30, 2005.

Hospitality revenue was $0.7 million higher quarter over quarter, primarily attributable to the expanded operations of the Delta St. John's Hotel. Hospitality revenue was $2.5 million higher year to date over the same period last year, primarily due to results for the first half of 2006 including the operations of the 3 Greenwood Inn hotels for 6 months compared to 5 months for the first half of 2005 and higher revenues associated with the expanded operations of the Delta St. John's Hotel. Revenue per available room ("REVPAR") for the second quarter of 2006 was $75.97 compared to $76.58 for the same quarter last year. The 0.8 per cent decrease in REVPAR was attributable to a decrease in average occupancy quarter over quarter, partially offset by an increase in average room rates.

Expenses: Operating expenses, amortization costs and finance charges were higher quarter over quarter, primarily due to the expanded operations of the Delta St. John's Hotel. Year to date over the same period last year, operating expenses, amortization costs and finance charges increased primarily due to the acquisition of the 3 Greenwood Inn hotels and the expanded operations of the Delta St. John's Hotel.

Corporate taxes were $1.6 million and $1.5 million lower quarter over quarter and year to date compared to the same period last year, respectively, primarily due to the reduction of future income tax liability balances resulting from the recently enacted future Federal income tax rate reductions and the elimination of the Federal Large Corporations' Tax, effective January 1, 2006. The decrease was partially offset by higher earnings before taxes compared to the same periods last year.

In May 2006, Fortis Properties completed the $7.7 million expansion of the Holiday Inn Sarnia which included a new 5-storey tower with 70 rooms and an additional 3,000-square feet of ballroom space. In June 2006, the Company also completed the $2.5 million 11,000-square foot expansion of the conference facilities at the Holiday Inn Kitchener-Waterloo and the $7.2 million 57,000-square foot expansion of the Blue Cross Centre in Moncton. Capital expenditures related to these projects were approximately $2.9 million in the second quarter of 2006 and $7.7 million year to date.



CORPORATE

---------------------------------------------------------------------
Corporate
Financial Highlights (Unaudited)
Period Ended June 30th
---------------------------------------------------------------------
Quarter Year-to-date
---------------------------------------------------------------------
($ millions) 2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Total Revenue 2.2 2.6 (0.4) 4.2 5.2 (1.0)
---------------------------------------------------------------------
Operating Expenses 3.2 3.1 0.1 5.5 5.3 0.2
---------------------------------------------------------------------
Amortization 0.8 0.7 0.1 1.5 1.4 0.1
---------------------------------------------------------------------
Finance Charges 5.5 5.6 (0.1) 10.9 11.6 (0.7)
---------------------------------------------------------------------
Foreign Exchange
(Gain) Loss (1.9) 1.2 (3.1) (1.7) 1.8 (3.5)
---------------------------------------------------------------------
Preference Share
Dividends 4.1 4.1 - 8.3 8.3 -
---------------------------------------------------------------------
Corporate Taxes (2.7) (2.4) (0.3) (5.0) (4.7) (0.3)
---------------------------------------------------------------------
Non-Controlling
Interest (0.1) (0.1) - (0.1) (0.1) -
---------------------------------------------------------------------
Net Corporate
Expenses (6.7) (9.6) 2.9 (15.2) (18.4) 3.2
---------------------------------------------------------------------
---------------------------------------------------------------------


The Corporate segment captures a number of expense and revenue items not specifically related to any operating segment. Included in the Corporate segment are finance charges related to debt incurred directly by Fortis, foreign exchange gains or losses, preference share dividends, other corporate expenses, net of recoveries from subsidiaries, interest and miscellaneous revenues, and corporate income taxes.

Net corporate expenses were $2.9 million lower quarter over quarter, primarily due to the recording of a $1.9 million ($1.6 million after-tax) net unrealized foreign exchange gain during the second quarter of 2006 compared to a $1.2 million ($1.0 million after-tax) net unrealized foreign exchange loss during the same quarter last year, in addition to a higher corporate income tax recovery, partially offset by a decrease in inter-company interest revenue. The foreign exchange gains and losses related to foreign currency exchange rate fluctuations associated with unhedged US dollar-denominated Corporate long-term debt. At June 30, 2006, unhedged US dollar-denominated debt was US$38 million compared to US$75 million at June 30, 2005; however, the US dollar weakened approximately 5 cents against the Canadian dollar during the second quarter of 2006 compared to approximately a 2-cent strengthening during the same quarter last year. The recovery of corporate income taxes was higher primarily due to the difference in the timing of recognition of certain items for income tax purposes compared to accounting purposes and the decrease of future income tax liability balances resulting from the recently enacted future Federal income tax rate reductions, partially offset by higher taxable income in 2006 compared to 2005. Operating expenses were comparable quarter over quarter. Higher business development costs were principally offset by lower pension and salary related costs. Finance charges were also comparable quarter over quarter. The impact of higher drawings on corporate credit facilities during the second quarter of 2006 compared to the same quarter last year was primarily offset by lower interest costs on US dollar-denominated debt as a result of the weakening of the US dollar against the Canadian dollar compared to a strengthening experienced during the same quarter last year.

Net corporate expenses were $3.2 million lower year to date compared to the same period last year, primarily due to the factors described for the quarter except that finance charges were lower in the first half of 2006 compared to the first half of 2005, primarily as a result of favourable foreign exchange rate impacts associated with interest expense on US dollar-denominated debt.

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between June 30, 2006 and December 31, 2005.



---------------------------------------------------------------------
Fortis Inc.
Significant Changes in the Consolidated Balance Sheets (Unaudited)
between June 30, 2006 and December 31, 2005
---------------------------------------------------------------------
Increase
($ millions) (Decrease) Explanation
---------------------------------------------------------------------
Deferred 12.0 The increase primarily related to the
charges undepreciated balanceof contributions
made by FortisAlberta to the AESO. These
assets are recovered in customer rates
through regulator-approved depreciation
rates.
---------------------------------------------------------------------
Future income (52.8) The decrease was primarily due to the
taxes conversion to the taxes payable method of
accounting for federal income taxes from the
tax liability method for regulatory purposes
at FortisAlberta. As a result, the future
income tax asset and the corresponding
offsetting regulatory liability at
FortisAlberta were drawn down to nil as at
June 30, 2006.
---------------------------------------------------------------------
Utility 100.5 The increase primarily related to $215.8
capital million invested in electricity systems,
assets less customer contributions and amortization
for the 6-month period.
---------------------------------------------------------------------
Short-term 19.2 The increase related to short-term borrowings
borrowings at Newfoundland Power, FortisBC and Maritime
Electric primarily to fund utility capital
expenditures and to fund the $5.9 million
corporate income tax deposit at Maritime
Electric. The increase was partially offset
by repayment of short-term borrowings at
Belize Electricity and Fortis Generation.
---------------------------------------------------------------------
Accounts (24.8) The decrease primarily related to the normal
payable seasonal reduction of purchased power costs
and accrued at Newfoundland Power, combined with the
charges timing of payments across the subsidiaries.
---------------------------------------------------------------------
Income taxes (22.8) The decrease primarily related to the payment
payable of income taxes at FortisAlberta,
FortisOntario and Maritime Electric during
the 6-month period.
---------------------------------------------------------------------
Regulatory (49.3) The decrease was primarily due to the
liabilities - conversion to the taxes payable method of
long-term accounting for federal income taxes from the
tax liability method for regulatory purposes
at FortisAlberta. As a result, both the
future income tax asset and the corresponding
offsetting regulatory liability at
FortisAlberta were drawn down to nil as at
June 30, 2006.
---------------------------------------------------------------------
Long-term debt 86.8 The increase primarily related to the
and capital issuance of $100 million unsecured public
lease debentures by FortisAlberta on April 21, 2006
obligations and increased drawings on long-term credit
(including facilities of $24.0 million and $4.0 million
current by the Corporation and FortisBC,
portion) respectively.

The increase was partially offset by a $20.9
million reduction of drawings on
FortisAlberta's long-term credit facilities
with proceeds from the $100 million debenture
issue, regular debt repayments during the 6-
month period, combined with the impact of the
translation of the Corporation's US dollar-
denominated debt at a lower foreign exchange
rate at June 30, 2006 compared to December
31, 2005.
---------------------------------------------------------------------
Shareholders' 46.7 The increase primarily related to the net
equity earnings reported for the 6-month period,
less common share dividends. The remainder of
the increase primarily related to the
issuance of common shares under the
Corporation's share purchase, dividend
reinvestment and stock option plans.
---------------------------------------------------------------------
---------------------------------------------------------------------



LIQUIDITY
The following table outlines the summary of cash flows.

---------------------------------------------------------------------
Fortis Inc.
Summary of Cash Flows (Unaudited)
Period Ended June 30th
---------------------------------------------------------------------
Quarter Year-to-
date
---------------------------------------------------------------------
($ millions) 2006 2005 Variance 2006 2005 Variance
---------------------------------------------------------------------
Cash, beginning
of period 21.5 64.2 (42.7) 33.4 37.2 (3.8)
---------------------------------------------------------------------
Cash provided by
(used in)
---------------------------------------------------------------------
Operating
activities 57.8 49.9 7.9 107.2 129.2 (22.0)
---------------------------------------------------------------------
Investing
activities (109.5) (97.7) (11.8) (211.2) (246.9) 35.7
---------------------------------------------------------------------
Financing
activities 58.0 10.4 47.6 98.4 107.2 (8.8)
---------------------------------------------------------------------
Foreign currency
impact on cash
balances (0.4) - (0.4) (0.4) 0.1 (0.5)
---------------------------------------------------------------------
Cash, end of
period 27.4 26.8 0.6 27.4 26.8 0.6
---------------------------------------------------------------------
---------------------------------------------------------------------


Operating Activities: Cash flow from operations, after working capital adjustments, increased $7.9 million quarter over quarter. The increase was largely driven by the impact of the payment of retiring allowances during the second quarter of 2005 and difference in the timing of payment of other accounts payable balances at Newfoundland Power, higher earnings at Belize Electric Company Limited ("BECOL") due to improved hydrology and the impact of the operation of the Chalillo dam, customer rate increases and the difference in the amount and timing of payment of accounts payables at Belize Electricity, partially offset by the impact of the payment by Maritime Electric of the corporate income tax deposit with CRA in June 2006.

Cash flow from operations, after working capital adjustments, decreased $22.0 million in the first half of 2006 from the first half of 2005. The decrease was primarily due to the receipt of the $10 million Ontario Settlement and favourable working capital adjustments in the first half of 2005 at FortisOntario, higher cash taxes paid in FortisAlberta and the payment of a $5.9 million corporate income tax deposit at Maritime Electric during the first half of 2006. The decrease was partially offset by favourable non-cash working capital adjustments and the impact of recovering through customer rates higher depreciation expense in the first half of 2006 at FortisBC, the impact of the payment of retiring allowances during the second quarter of 2005 and the difference in the timing of payment of other accounts payable balances at Newfoundland Power, customer rate increases and the difference in the amount and timing of payment of accounts payables at Belize Electricity, and improved earnings at BECOL for the reasons described for the quarter.

Investing Activities: Cash used in investing activities was $11.8 million higher quarter over quarter. The increase was primarily due to higher utility capital expenditures and an increase in deferred charges related to payments made by FortisAlberta to the AESO associated with capital projects, partially offset by increased proceeds from the sale of capital assets primarily associated with the sale of the Days Inn Sydney hotel in June 2006 and higher contributions in aid of construction. During the first half of 2006, cash used in investing activities was $35.7 million lower compared to the first half of 2005. The decrease was primarily due to lower capital expenditures associated with income producing properties combined with higher proceeds from the sale of capital assets primarily associated with the sale of the Days Inn Sydney hotel. The decrease was partially offset by higher utility capital expenditures and an increase in deferred charges at FortisAlberta related to payments made to the AESO associated with capital projects.

Gross utility capital expenditures were $111.5 million for the second quarter of 2006, $13.8 million higher than gross utility capital expenditures for the same quarter last year. Gross utility capital expenditures were $215.8 million for the first half of 2006, $26.7 million higher than gross utility capital expenditures for the first half of 2005. The increase in gross utility capital expenditures primarily related to capital spending at FortisAlberta, largely driven by customer growth, rising material and labour costs, capital upgrades and the timing of expenditures, partially offset by substantially decreased utility capital expenditures at Maritime Electric and BECOL, due to the completion, during 2005, of the construction of the 50-MW combustion turbine generating facility on PEI and the Chalillo Project in Belize, in addition to slightly lower capital expenditures at FortisBC.

Capital expenditures associated with income producing properties were $1.7 million lower quarter over quarter. The decrease was the result of capital expenditures primarily associated with the expansions of the Holiday Inn Sarnia, Holiday Inn Kitchener-Waterloo and Blue Cross Centre in Moncton during the second quarter of 2006 being less than capital expenditures associated with the completion of the expansion to the Delta St. John's Hotel during the second quarter of 2005. Year to date compared to the same period last year, capital expenditures associated with income producing properties were $62.4 million lower. The decrease was primarily related to the acquisition of 3 hotels in Alberta and Manitoba for approximately $63 million in February 2005.

Contributions received in aid of construction were $1.8 million and $0.5 million higher quarter over quarter and year to date over the same period last year, respectively, primarily due to increased contributions associated with FortisAlberta's capital expenditure program, partially offset by lower contributions at Belize Electricity.

Financing Activities: Cash provided from financing activities was $47.6 million higher quarter over quarter, primarily driven by a $91.1 million increase in proceeds received from long-term debt, a $27.6 million net increase in short-term borrowings and a $10.2 million increase in advances from non-controlling interests, partially offset by a $79.2 million increase in long-term debt and capital lease obligation repayments, and a $1.9 million increase in dividends on common shares. During the second quarter of 2006, FortisAlberta issued $100 million of unsecured public debentures bearing interest at 5.40%. This compares to proceeds of $12.3 million received during the second quarter of 2005 related to the financing of the acquisition of the Greenwood Inn Winnipeg. During the second quarter of 2006, proceeds from drawings under long-term credit facilities were $57.2 million compared to drawings of $54.8 million during the second quarter of 2005. Repayments of long-term debt during the second quarter of 2006, largely related to long-term credit facilities, were primarily funded by proceeds from FortisAlberta's $100 million debenture issue. During the second quarter of last year, debt repayments primarily related to the early repayment by FortisOntario of a $22.5 million term loan. Dividends on common shares increased quarter over quarter due to increased number of common shares outstanding and higher dividends paid per common share. During the second quarter of 2006, Belize Electricity completed a share purchase offering in which approximately 97 per cent of share purchase rights issued were exercised by the Company's shareholders. The share offering resulted in the receipt of $10.6 million of proceeds from Belize Electricity's non-controlling shareholders.

Cash provided from financing activities was $8.8 million lower during the first half of 2006 compared to the first half of 2005. The decrease was driven by a $124.5 million decrease in proceeds from the issue of common shares, primarily due to the public issue of 6.96 million common shares of the Corporation on March 1, 2005, a $3.8 million increase in dividends paid per common share and a $77.4 million increase in long-term debt and capital lease obligation repayments. The decrease was partially offset by a $112.6 million increase in proceeds from long-term debt, a $74.2 million net increase in short-term borrowings and a $10.1 million increase in advances from non-controlling interests. In addition to the factors described for the change in cash provided from financing activities quarter over quarter, proceeds from long-term debt in the first quarter of 2005 included a $29.6 million loan to finance the acquisition of the Edmonton and Calgary Greenwood Inns. Also, during the first quarter of 2005, proceeds from the March 1, 2005 common share issue were used, in part, to repay short-term borrowings associated with the acquisition of FortisAlberta and FortisBC. During the first half of 2006, proceeds from drawings under long-term credit facilities were $104.2 million compared to drawings of $54.8 million during the first half of 2005. The increased drawings under long-term credit facilities were largely used to fund FortisAlberta's extensive capital expenditure program and for general corporate purposes including funding for an equity injection into a subsidiary.

Contractual Obligations: The consolidated contractual obligations over the next 5 years and for periods thereafter, as at June 30, 2006, are outlined in the following table.



---------------------------------------------------------------------
Fortis Inc.
Contractual Obligations (Unaudited)
as at June 30, 2006
---------------------------------------------------------------------
less greater
than than
($ millions) Total 1 year 1-3 years 4-5 years 5 years
---------------------------------------------------------------------
Long-term debt 2,213.2 27.9 140.0 260.3 1,785.0
---------------------------------------------------------------------
Brilliant Terminal
Station ("BTS") (1) 69.4 2.6 5.1 5.1 56.6
---------------------------------------------------------------------
Power purchase
obligations
FortisBC (2) 2,898.3 36.7 73.0 72.1 2,716.5
FortisOntario (3) 312.7 22.4 67.4 46.9 176.0
Maritime
Electric (4) 1.6 1.6 - - -
---------------------------------------------------------------------
Capital cost (5) 443.7 19.5 49.4 36.5 338.3
---------------------------------------------------------------------
Joint-use asset
and shared service
agreements (6) 63.4 1.9 7.4 7.2 46.9
---------------------------------------------------------------------
Operating lease
obligations (7) 18.5 3.6 8.9 5.9 0.1
---------------------------------------------------------------------
Office lease -
FortisBC (8) 21.8 0.9 2.2 2.5 16.2
---------------------------------------------------------------------
Other 5.0 1.5 2.2 0.1 1.2
---------------------------------------------------------------------
Total 6,047.6 118.6 355.6 436.6 5,136.8
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) On July 15, 2003, FortisBC began operating the BTS under an
agreement, the term of which expires in 2056 (unless the Company
has earlier terminated the agreement by exercising its right, at
any time after the anniversary date of the agreement in 2029, to
give 36 months notice of termination). The BTS is jointly owned
by the Columbia Power Corporation and the Columbia Basin Trust
(the "Owners") and is used by the Company on its own behalf and
on behalf of the Owners. The agreement provides that FortisBC
will pay the Owners a charge related to the recovery of the
capital cost of the BTS and related operating costs.

(2) Power purchase obligations of FortisBC include the Brilliant
Power Purchase Agreement (the "BPPA") as well as the Power
Purchase Agreement with BC Hydro. On May 3, 1996, an Order was
granted by the BCUC approving a 60-year BPPA for the output of
the Brilliant hydroelectric plant located near Castlegar, British
Columbia. The BPPA requires monthly payments based on the
operation and maintenance costs and a return on capital for the
plant in exchange for the specified natural flow take-or-pay
amounts of power. The BPPA includes a market-related price
adjustment after 30 years of the 60-year term. The Power Purchase
Agreement with BC Hydro, which expires in 2013, provides for any
amount of supply up to a maximum of 200 MW, but includes a take-
or-pay provision based on a 5-year rolling nomination of the
capacity requirements.

(3) Power purchase obligations for FortisOntario primarily include a
long-term take-or-pay contract between Cornwall Electric and
Hydro-Quebec Energy Marketing for the supply of electricity and
capacity. The contract provides approximately 237 GWh of energy
per year and up to 45 MW of capacity at any one time. The
contract, which expires December 31, 2019, provides approximately
one-third of Cornwall Electric's load. Cornwall Electric also has
a 2-year contract in place with Hydro-Quebec Energy Marketing
which expires June 30, 2008. This take-or-pay contract provides
energy on an as-needed basis but charges for 100 MW of capacity
at $0.14 million per month.

(4) Maritime Electric has 1 take-or-pay contract for the purchase of
either capacity or energy. This contract totals approximately
$1.6 million through October 2006.

(5) Maritime Electric has entitlement to approximately 6.7 per cent
of the output from the NB Power Dalhousie Generating Station and
approximately 4.7 per cent from the NB Power Point Lepreau
Generating Station for the life of each unit. As part of its
participation agreement, Maritime Electric is required to pay its
share of the capital costs of these units.

(6) FortisAlberta and an Alberta transmission service provider have
entered into an agreement in consideration for joint attachments
of distribution facilities to the transmission system. The expiry
terms of this agreement state that the agreement remains in
effect until the Company no longer has attachments to the
transmission facilities. Due to the unlimited term of this
contract, the calculation of future payments after 2010 includes
payments to the end of 20 years. However, the payments under this
agreement may continue for an indefinite period of time.
FortisAlberta and an Alberta transmission service provider have
also entered into a number of service agreements to ensure
operational efficiencies are maintained through coordinated
operations. The service agreements have minimum expiry terms of 5
years from September 1, 2005 and are subject to extension based
on mutually agreeable terms.

(7) Operating lease obligations include certain office, vehicle and
equipment leases as well as the lease of electricity distribution
assets of Port Colborne Hydro Inc.

(8) Under a sale-leaseback agreement, on September 29, 1993, FortisBC
began leasing its Trail, British Columbia office building for a
term of 30 years. The terms of the agreement grant FortisBC
repurchase options at approximately year 20 and year 28 of the
lease term. On December 1, 2004, FortisBC also entered into a 5-
year lease for the Kelowna, British Columbia head office. The
terms of the lease allow for termination without penalty after 3
years.


CAPITAL RESOURCES

The Corporation's principal business of regulated electric utilities requires Fortis to have ongoing access to capital to allow it to build and maintain its electricity systems. In order to ensure access to capital is maintained, the Corporation targets a long-term capital structure that includes a minimum of 40 per cent equity and 60 per cent debt as well as investment grade credit ratings. The Corporation targets the equity component of its capital structure to consist of at least 75 per cent common share equity. The capital structure of Fortis is presented in the following table.



---------------------------------------------------------------------
Fortis Inc.
Capital Structure (Unaudited)
---------------------------------------------------------------------
June 30, 2006 December 31, 2005
---------------------------------------------------------------------
---------------------------------------------------------------------

($ millions) (%) ($ millions) (%)
---------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash) 2,294.5 59.2 2,182.5 58.7
---------------------------------------------------------------------
Preference shares 319.5 8.3 319.5 8.6
---------------------------------------------------------------------
Shareholders' equity 1,260.1 32.5 1,213.4 32.7
---------------------------------------------------------------------
Total 3,874.1 100.0 3,715.4 100.0
---------------------------------------------------------------------
---------------------------------------------------------------------


The change in the Corporation's capital structure is primarily the
result of increased total debt used to finance the consolidated
capital program of Fortis, combined with net earnings, less common
share dividends, of $41.5 million for the first 6 months of 2006.

As at June 30, 2006, the Corporation's unsecured debt credit ratings
were as follows:

Standard & Poors ("S&P") BBB
Dominion Bond Rating Service ("DBRS") BBB(high)


In December 2005, S&P confirmed its credit rating on the Corporation's unsecured debt at BBB and revised its outlook from negative to stable. The outlook was revised based on greater stability in the business and financial risk profiles of Fortis and reduced concerns surrounding the level of operational and funding risk involved with the Corporation's major capital expenditure program. In February 2006, DBRS confirmed the rating on the Corporation's unsecured debt at BBB(high).

Capital Program: The Corporation's principal business of regulated electric utilities is capital intensive. Gross consolidated capital expenditures of Fortis for 2006 are expected to be almost $450 million, of which $227.7 million has been incurred year to date. Approximately $300 million is expected to be invested by FortisAlberta and FortisBC.

The Corporation's total utility capital assets are expected to grow at an average annual rate of 6 per cent over the next 5 years. The significant capital programs at FortisAlberta and FortisBC are the primary drivers of this expected growth. The cash needed to complete the capital programs is expected to be supplied by a combination of long-term and short-term borrowings, internally generated funds and common share issuances. Fortis does not anticipate any difficulties with accessing the required capital.

Cash Flows: The Corporation's ability to service debt obligations as well as 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.

As outlined in the Fortis Inc. 2005 Annual Report, Belize Electricity remains non-compliant with its debt service coverage ratio of 1.5 times related to its $5.3 million (BZ$9.4 million) loan with the International Bank for Reconstruction and Development and its $9.2 million (BZ$16.4 million) loan with the Caribbean Development Bank. Fortis does not expect any change in the regular debt repayment schedule relating to these loans.

The Corporation and its subsidiaries had consolidated authorized lines of credit of $795.0 million, of which $573.8 million was unused at June 30, 2006. The following summary outlines the Corporation's credit facilities by reporting segments.



---------------------------------------------------------------------
Fortis Inc.
Credit Facilities (Unaudited)
---------------------------------------------------------------------
Total as
Regulated Fortis Fortis Total as at
Utili- Genera- Proper- at June December
($ millions) Corporate ties tion ties 30, 31,
2006 2005
---------------------------------------------------------------------
Total credit
facilities 210.0 566.9 5.6 12.5 795.0 747.1
---------------------------------------------------------------------
Credit facilities
utilized
---------------------------------------------------------------------
Short-term
borrowings (4.1) (73.4) - (1.5) (79.0) (59.9)
---------------------------------------------------------------------
Long-term debt (42.0) (39.9) - - (81.9) (74.8)
---------------------------------------------------------------------
Letters of credit
outstanding (4.5) (53.7) - (2.1) (60.3) (73.6)
---------------------------------------------------------------------
Credit facilities
available 159.4 399.9 5.6 8.9 573.8 538.8
---------------------------------------------------------------------
---------------------------------------------------------------------


At June 30, 2006 and December 31, 2005, certain borrowings under the Corporation's and subsidiaries' credit facilities have been classified as long-term debt. These borrowings are under long-term credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.

In January 2006, Newfoundland Power renegotiated its syndicated $100 million committed revolving term credit facility extending the term from 1 year to 3 years, with maturity now in January 2009.

In January 2006, Maritime Electric's $25 million non-revolving unsecured short-term bridge financing, in support of the construction of the 50-MW combustion turbine generating facility, was extended until July 2007.

In March 2006, FortisAlberta amended its term syndicated credit facility increasing the amount available to $200 million from $150 million and extending the maturity date from May 2008 to May 2010. In addition, the Company has the ability to request an increase in the limit of this credit facility by $50 million under the same terms of the existing credit facility.

In May 2006, the maturity date of FortisBC's $50 million operating credit facility was extended to May 2007.

In June 2006, Fortis renegotiated and amended its $145 million and $50 million unsecured term credit facilities extending the maturity dates of these facilities from May 2008 and January 2009 to May 2010 and January 2011, respectively. Additionally, in July 2006, the amount available under the $145 million facility was increased to $250 million. These credit facilities can be used for general corporate purposes, including acquisitions.

On April 21, 2006, FortisAlberta issued $100 million in unsecured debentures bearing interest at 5.40% per annum, payable semi-annually on April 21 and October 21, due April 21, 2036. The net proceeds of the offering were used primarily to repay existing indebtedness on FortisAlberta's long-term credit facility.

OFF-BALANCE SHEET ARRANGEMENTS

Disclosure is required of all 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. The Corporation had no such off-balance sheet arrangements as at June 30, 2006.

BUSINESS RISK MANAGEMENT

There were no material changes to the Corporation's significant business risks for the 6-month period ended June 30, 2006 from those disclosed in the Corporation's Management Discussion and Analysis for the year ended December 31, 2005, except for those described below.

Regulation: Rate applications that establish revenue requirements may be subject to negotiated settlement procedures as well as pursued through public hearing processes. During the second quarter of 2006, regulation risk for 2006 was reduced due to the receipt of regulatory approvals of rate applications at FortisAlberta, FortisBC, Maritime Electric, Canadian Niagara Power and Belize Electricity.

Labour Relations: The collective agreement between FortisBC and Local 213 of the International Brotherhood of Electrical Workers ("IBEW") expired on January 31, 2005. IBEW represents employees in specified occupations in the areas of generation, transmission and distribution. The Company and IBEW reached an agreement which was ratified in early January 2006. The agreement expires on January 31, 2008. The collective agreement between FortisBC and Local 378 of the Canadian Office and Professional Employees Union ("COPE") expired on January 31, 2006. COPE represents employees in office and professional occupations. The Company and COPE reached an agreement which was ratified in early July 2006. The agreement expires on January 31, 2011.

The majority of employees at FortisAlberta are represented by the United Utility Workers Association ("UUWA"). There were 2 collective agreements with UUWA. The Dispatch/Contact Centre Collective Agreement expired December 31, 2004 and the main collective agreement expired December 31, 2005. A new combined agreement was reached with UUWA during the second quarter of 2006. The new agreement expires on December 31, 2007.

Belize Electricity's collective agreement with the Belize Energy Workers Union was signed on November 29, 2000 and is to be reviewed every 5 years. Preparations are underway for union negotiations which are expected to commence in August 2006.

CHANGES IN ACCOUNTING POLICIES

Revenue Recognition: Effective January 1, 2006, Newfoundland Power prospectively changed its revenue recognition policy from a billed basis to an accrual basis, as approved by the PUB. The transition to recording revenue on an accrual basis, while having no material impact on Newfoundland Power's annual earnings, results in a shift in the Company's 2006 quarterly earnings compared to 2005. The PUB also approved a one-time revenue accrual of $3.1 million in 2006. This amount represents that portion of unbilled revenue, as at December 31, 2005, of $23.6 million, required to offset the income tax effects to be incurred in 2006 relating to the change to the accrual basis of revenue recognition. The disposition of the remaining 2005 unbilled revenue balance has been deferred until the Company's next general rate application.

Conditional Asset Retirement Obligations: On April 1, 2006, Fortis retroactively adopted EIC 159, Conditional Asset Retirement Obligations ("EIC 159"). EIC 159 requires an entity to recognize a liability for the fair value of an asset retirement obligation ("ARO") even though the timing and/or method of settlement are conditional on future events. While conditional AROs have been identified, no amounts have been recorded as they are immaterial to the Corporation's results of operations and financial position.

Corporate Income Taxes: Effective January 1, 2006, FortisAlberta is following the taxes payable method of accounting for federal income taxes. As prescribed by the 2006/2007 Negotiated Settlement Agreement, approved by the AEUB on June 29, 2006, corporate income tax expenses are now recovered through customer rates based only on income taxes that are currently payable for regulatory purposes. Therefore, current rates do not include the recovery of future income taxes related to certain temporary differences between the tax basis of assets and liabilities and their carrying amounts for regulatory purposes.

In 2005, FortisAlberta followed the taxes payable method of accounting for provincial income taxes and federal income tax expenses were recovered through customer rates based on a modified liability method. Under the modified liability method, customer rates included the recovery of future federal income taxes related to specified temporary differences between the tax basis of assets and liabilities and their carrying amounts for regulatory purposes. As a result of collecting a portion of future federal income taxes within customer rates in 2005, FortisAlberta previously recognized future federal income taxes within the 2005 financial statements and also set up a regulatory liability equal to the amount of future federal income taxes recognized that had not yet been reflected in customer rates. However, due to the 2006/2007 Negotiated Settlement Agreement, the future income tax asset and the offsetting regulatory liability are no longer recognized.

FUTURE ACCOUNTING PRONOUNCEMENTS

During the 6 months ended June 30, 2006, there were no changes to the Corporation's disclosure of future accounting pronouncements from those disclosed in the Corporation's Management Discussion and Analysis for the year ended December 31, 2005 except as described below:

Rate-Regulated Operations: The Canadian Accounting Standards Board ("AcSB") recently considered the effects on its rate-regulated operations project of its recently adopted Strategic Plan and decided that the project, as originally planned, should be discontinued. It further decided, subject to exposure of its proposals, that: (i) the temporary exemption in Section 1100 of the Canadian Institute of Chartered Accountants Handbook ("Handbook") 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 should be removed; (ii) the explicit guidance for rate-regulated operations provided in 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, should be removed; and (iii) Accounting Guideline 19, Disclosures by Entities Subject to Rate Regulation, should be retained as is. An Exposure Draft for public comment based on these preliminary decisions is expected during the third quarter of 2006. The AcSB also observed that relying on US Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation ("FAS 71"), as another source of GAAP in the absence of Handbook guidance addressing the specific circumstances of entities subject to rate regulation, is consistent with Section 1100 when the qualifying criteria of FAS 71 are met. The Corporation is following these developments closely and is in the process of assessing the potential impact on its financial statements.

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 assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates 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 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 to the Corporation's critical accounting estimates for the 6 months ended June 30, 2006 from those disclosed in the Corporation's Management Discussion and Analysis for the year ended December 31, 2005, except as discussed below.

Rates: On May 23, 2006 and June 29, 2006, FortisBC and FortisAlberta, respectively, received approval for final rates to be charged to customers in 2006 as a result of the respective regulators' approval of the Negotiated Settlement Agreements. At FortisBC, the 5.9 per cent interim electricity rate increase charged to customers, effective January 1, 2006, and the 2006 final approved rate increase at FortisBC were the same. At FortisAlberta, however, the AEUB approved a 1.9 per cent electricity rate reduction, effective January 1, 2006. FortisAlberta had been charging interim rates which were the same as those charged in 2005. The impact of the rate reduction at FortisAlberta, effective January 1, 2006, of $2.1 million was recorded as a reduction in revenue during the second quarter of 2006 and will be refunded to customers during 2007.

Amortization and Capitalized Overhead: FortisBC recently completed a depreciation study on the estimated useful life of its property, plant and equipment. The study recommended an increase in the Company's composite depreciation rate from 2.6 per cent to 3.6 per cent. FortisBC's 2006 Application and the Corporation's first quarter 2006 consolidated financial statements were based on the 3.6 per cent composite depreciation rate at FortisBC.

The 2006 Negotiated Settlement Agreement resulted in a composite depreciation rate of 3.2 per cent, effective January 1, 2006, which has been reflected in the Corporation's second quarter 2006 consolidated financial statements resulting in a $0.4 million reduction in amortization costs.

FortisBC also recently completed an analysis of its capitalized overhead allocation method. This analysis supported a change in the estimate of capitalized overhead. The changed estimate calculates capitalized overhead as a percentage of all corporate overhead, whereas previously the percentage was applied to a limited pool of corporate costs. FortisBC's 2006 Application and the Corporation's first quarter 2006 consolidated financial statements were based on a capitalized overhead percentage of approximately 27.5 per cent of gross operating and maintenance expenses compared to approximately 9.0 per cent used previously at FortisBC. The 2006 Negotiated Settlement Agreement resulted in a capitalized overhead rate of approximately 20.0 per cent of operating and maintenance expenses, effective January 1, 2006, which has been reflected in the Corporation's second quarter 2006 consolidated financial statements, resulting in a $0.9 million reduction in capitalized overhead costs and corresponding increase in operating expenses.

Year to date June 30, 2006, the increase in FortisBC's composite depreciation rate to 3.2 per cent from 2.6 per cent and the increase in the percentage of gross operating and maintenance expenses capitalized to approximately 20.0 per cent from 9.0 per cent resulted in increased amortization costs of $2.4 million and decreased operating costs of $2.3 million, respectively.

Contingencies: Fortis is a party to a number of disputes and lawsuits in the normal course of business. The Corporation's contingent liabilities are consistent with disclosures in the Corporation's 2005 annual audited consolidated financial statements except as noted below.

Maritime Electric

In April 2006, CRA reassessed Maritime Electric's 1997-2004 taxation years. The reassessment encompasses the Company's tax treatment, specifically the Company's timing of deductions, with respect to: (i) the ECAM in the 2001-2004 taxation years, (ii) customer rebate adjustments in the 2001-2003 taxation years, and (iii) the Company's payment of approximately $6 million on January 2, 2001 associated with a settlement with NB Power regarding its $450 million write down of the Point Lepreau Nuclear Generating Station in 1998.

Maritime Electric believes it has reported its tax position appropriately in all aspects of the reassessment and filed a Notice of Objection with the Chief of Appeals at CRA. Should the Company be unsuccessful in defending all aspects of the reassessment, the Company would be required to pay approximately $11.7 million in taxes and accrued interest. Year to date June 30, 2006, Maritime Electric has provided for, through future and current income taxes payable, approximately $11.0 million and, therefore, an additional liability of $0.7 million would arise. In this event, the Company would apply to IRAC to include this amount in the regulatory rate-making process. The provisions of the Income Tax Act require the Company to deposit one half of the assessment under objection with CRA and the Company made a payment on deposit of $5.9 million with CRA on June 29, 2006.

FortisAlberta

On March 24, 2006, Her Majesty the Queen in Right of Alberta filed a statement of claim in the Court of Queen's Bench of Alberta in the Judicial District of Edmonton against FortisAlberta. The Crown's claim is that the Company is responsible for a fire that occurred in October 2003 in an area of the Province of Alberta commonly referred to as "Poll Haven Community Pasture". The Crown is seeking approximately $2.7 million in fire-fighting and suppression costs and approximately $2.4 million in timber losses, as well as interest and other costs. Given the preliminary stage of the proceedings, FortisAlberta has not made any definitive assessment of potential liability with respect to the litigation. However, management does not believe that the Company contributed to, or is responsible for, the fire and, therefore, management is of the view that the allegations are without merit.

FortisBC

FortisBC has received correspondence and met with the B.C. Ministry of Forests (the "Ministry") to discuss the possibility of an invoice being issued to the Company for costs incurred by the Ministry in 2003 in relation to a forest fire near Vaseux Lake. The Ministry has alleged breaches of the Forest Practices Code and negligence and has filed and served a writ, on or about June 6, 2006, and statement of claim against FortisBC. FortisBC is currently communicating with the Ministry and its insurers. In addition, FortisBC has become aware of 2 writs and statements of claim filed, but not served, by private land owners in relation to the same matter.

The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

QUARTERLY RESULTS

The following table sets forth unaudited quarterly information for each of the 8 quarters ended September 30, 2004 through June 30, 2006. 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, revenues and expenses as a result of regulation may differ from that otherwise expected using Canadian GAAP for non-regulated entities. These differences are disclosed in the Notes to the Corporation's 2005 annual audited consolidated financial statements. These 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
Revenue and Applicable to Earnings per
Equity Income Common Shares Common Share
Quarter Ended ($ thousands) ($ thousands) Basic ($) Diluted ($)

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June 30, 2006 345,851 37,946 0.37 0.35
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March 31, 2006 390,827 36,605 0.35 0.34
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December 31, 2005 353,084 22,263 0.22 0.21
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September 30, 2005 341,650 37,450 0.36 0.33
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June 30, 2005 364,948 38,188 0.37 0.34(1)
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March 31, 2005 381,789 39,196 0.40 0.36(1)
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December 31, 2004 337,170 21,176 0.22 0.21(1)
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September 30, 2004 303,653 25,452 0.26 0.25(1)
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(1) Earnings per common share data have been restated to reflect the
4-for-1 stock split completed in October 2005.
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A summary of the past 8 quarters reflects the Corporation's continued growth as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity demand and water flows as well as the timing and recognition of regulatory decisions. Given the diversified group of companies, seasonality may vary. Most of the Corporation's utility investments produce their highest earnings in the first quarter. The Corporation's non-utility investment, Fortis Properties, generally produces its highest earnings in the second and third quarters. Financial results from February 1, 2005 were impacted by the acquisition of 3 Greenwood Inn hotels. Also, the comparability of 2006 and 2005 quarterly earnings and revenue has been somewhat impacted by the shift in reported revenue at Newfoundland Power resulting from the change to the accrual basis of revenue recognition from the billed basis. The comparability of 2005 and 2004 quarterly earnings was somewhat impacted by the seasonality effect of the new purchased power rate structure at Newfoundland Power, effective January 1, 2005. Each of the comparative quarterly earnings, except for the comparative quarters ended March 31, 2006 and March 31, 2005 and comparative quarters ended June 30, 2006 and June 30, 2005, has increased as a result of both the Corporation's acquisition strategy and improved operating earnings at most subsidiaries. Results for the first quarter of 2005 included the $7.9 million after-tax Ontario Settlement.

June 2006/June 2005 - Net earnings applicable to common shares were $37.9 million, or $0.37 per common share, for the second quarter of 2006 compared to earnings of $38.2 million, or $0.37 per common share, for the second quarter of 2005. Earnings for the second quarter last year included a $7.0 million positive after-tax adjustment to FortisAlberta's earnings, driven largely by the resolution of tax-related matters pertaining to prior years, which favourably impacted revenue. Earnings for the second quarter last year also included a $1.1 million positive adjustment to equity income from Caribbean Utilities related to a change in accounting practice for recognizing unbilled revenue. Excluding these items, the Corporation's earnings were $7.8 million higher in the second quarter of 2006 compared to the second quarter of 2005. The increase was driven by lower corporate income taxes largely at FortisAlberta, improved hydroelectric production in Belize, higher earnings at Fortis Properties and a foreign exchange gain on the translation of US dollar-denominated corporate debt.

The increase was partially offset by lower earnings at Newfoundland Power related to the shifting of revenue from the first half of 2006 to the second half of 2006 upon adopting the accrual method of recognizing revenue, effective January 1, 2006, and the impact of recording the cumulative effects of the regulator approved Negotiated Settlement Agreements during the second quarter of 2006 at FortisAlberta and FortisBC.

March 2006/March 2005 - Net earnings applicable to common shares were $36.6 million, or $0.35 per common share, for the first quarter of 2006 compared to earnings of $39.2 million, or $0.40 per common share, for the first quarter of 2005. Earnings for the first quarter last year included the $7.9 million after-tax Ontario Settlement. Excluding the Ontario Settlement in 2005, earnings increased quarter over quarter primarily due to higher earnings at FortisBC and FortisAlberta, and increased non-regulated hydroelectric production in Belize. The increase in earnings was also due to an 11 per cent overall increase in electricity rates, effective July 1, 2005, and higher electricity sales at Belize Electricity. Partially offsetting the earnings increase was an anticipated decline in earnings at Newfoundland Power as a result of a change in the Company's revenue recognition policy, a decrease in equity income from Caribbean Utilities, driven by higher fuel costs, and the impact of lower average wholesale energy prices in Ontario. Earnings per common share for the first quarter of 2006 were impacted by the dilution created by the $130 million issue of common shares on March 1, 2005.

December 2005/December 2004 - Net earnings applicable to common shares for the fourth quarter of 2005 were $22.3 million, or $0.22 per common share, compared to $21.2 million, or $0.22 per common share, for the same quarter last year. Higher earnings from Non-Regulated - Fortis Generation, largely driven by higher average wholesale energy prices in Ontario and Upper New York State and increased production, was partially offset by decreased earnings from Regulated Utilities and higher Corporate expenses. The decrease in earnings from Regulated Utilities was primarily driven by lower earnings at FortisAlberta and FortisBC, partially offset by higher equity income from Caribbean Utilities. FortisAlberta's earnings for the fourth quarter of 2005 were reduced by a one-time adjustment of approximately $3.0 million, largely related to the implementation of the Negotiated Settlement Agreement reached on May 23, 2005. Additionally, during the fourth quarter of 2004, FortisBC recorded a $3.7 million after-tax increase to earnings related to the refinement of the process of estimating unbilled electricity revenue. Also, equity income in the fourth quarter of 2004 included an $8.2 million charge associated with the damage from Hurricane Ivan. Earnings per common share for the fourth quarter of 2005 were impacted by the dilution created by the $130 million issue of common shares on March 1, 2005.

September 2005/September 2004 - Net earnings applicable to common shares for the third quarter of 2005 were $37.4 million, or $0.36 per common share, compared to $25.5 million, or $0.26 per common share, for the same quarter last year. Earnings for the third quarter were $11.9 million higher than for the same quarter in 2004 primarily due to higher average wholesale energy prices in Ontario, a $3.1 million, net of tax, unrealized foreign exchange gain associated with the translation of US$60 million of unhedged corporate long-term debt and increased earnings at Belize Electricity, Caribbean Utilities and Fortis Properties. Earnings from Canadian Regulated Utilities were comparable quarter over quarter. The net impact of several adjustments at FortisAlberta, FortisBC and FortisOntario and higher earnings at Maritime Electric helped offset lower quarterly earnings at Newfoundland Power related to the new purchase power rate structure and higher finance charges at the utilities in western Canada. Growth in earnings per common share quarter over quarter was partially offset by the dilution created by the $130 million issue of common shares on March 1, 2005.

OUTLOOK

The Corporation's principal business of regulated electric utilities is capital intensive and Fortis expects that most of its capital expenditures for the next 5 years will relate primarily to FortisAlberta and FortisBC. Gross consolidated capital expenditures for 2006 are expected to be almost $450 million, approximately $425 million of which is expected to be invested in Regulated Utilities.

Fortis also expects to focus its capital on funding further acquisitions of utility assets. Fortis will continue to pursue acquisition opportunities in Canada, the Caribbean and the United States. Fortis will also pursue growth in its non-regulated businesses of hydroelectric generation, hotels and real estate.

OUTSTANDING SHARE DATA

At August 3, 2006, the Corporation had issued and outstanding 103,604,068 Common Shares, 5,000,000 First Preference Shares Series C and 7,993,500 First Preference Shares Series E. The number of Common Shares, as at June 30, 2006, that would be issued upon conversion of convertible debt and the First Preference Shares Series C and Series E is described in the Notes to the 2005 Fortis annual audited consolidated financial statements. The number of Common Shares, as at June 30, 2006, that would be issued upon conversion of share options is described in the Notes to the interim unaudited consolidated financial statements for the 3 and 6 months ended June 30, 2006.



FORTIS INC.

Interim Consolidated Financial Statements
For the three and six months ended June 30, 2006 and 2005
(Unaudited)



Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in thousands)

June 30 December 31
2006 2005
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(Note 15)
ASSETS

Current assets
Cash and cash equivalents $ 27,365 $ 33,416
Accounts receivable 194,473 204,169
Prepaid expenses 13,389 9,786
Regulatory assets 31,780 33,289
Materials and supplies 21,791 18,614
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288,798 299,274

Corporate income tax deposit (Note 14 (a)) 5,922 -
Deferred charges 160,116 148,140
Regulatory assets 88,710 82,315
Future income taxes 5,968 58,815
Utility capital assets 2,719,972 2,619,480
Income producing properties 418,190 414,608
Investments 169,249 167,393
Intangibles, net of amortization 11,923 14,027
Goodwill 512,139 512,139
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$ 4,380,987 $ 4,316,191
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LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
Short-term borrowings (Note 5) $ 79,019 $ 59,868
Accounts payable and accrued charges 240,403 265,223
Dividends payable 17,947 17,924
Income taxes payable - 22,785
Regulatory liabilities 18,545 19,392
Current instalments of long-term debt and
capital lease obligations 29,165 31,392
Future income taxes 1,746 6,714
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386,825 423,298

Deferred credits 70,559 64,261
Regulatory liabilities 37,487 86,780
Future income taxes 44,185 44,718
Long-term debt and capital
lease obligations (Note 5) 2,213,701 2,124,674
Non-controlling interest 48,607 39,555
Preference shares 319,492 319,492
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3,120,856 3,102,778
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Shareholders' equity
Common shares (Note 6) 819,227 813,304
Contributed surplus 3,892 3,179
Equity portion of convertible debentures 1,440 1,500
Foreign currency translation adjustment (17,639) (16,312)
Retained earnings 453,211 411,742
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1,260,131 1,213,413
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$ 4,380,987 $ 4,316,191
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Contingent liabilities and commitments (Note 14)
See accompanying notes to interim consolidated financial statements.



Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended June 30
(in thousands, except per share amounts)

Quarter Ended Six Months Ended
2006 2005 2006 2005
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Operating revenues $ 343,768 $ 361,887 $ 732,976 $ 741,165
Equity income 2,083 3,061 3,702 5,572
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345,851 364,948 736,678 746,737
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Expenses
Operating 221,829 219,845 475,097 473,158
Amortization 44,458 42,155 88,625 82,331
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266,287 262,000 563,722 555,489
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Operating income 79,564 102,948 172,956 191,248
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Finance charges (Note 9) 35,547 35,155 73,017 71,053
Preference share dividends 4,151 4,151 8,303 8,303
Gain on sale of income
producing property (Note 10) (2,088) - (2,088) -
Gain on settlement of
contractual matters (Note 11) - - - (10,000)
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37,610 39,306 79,232 69,356
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Earnings before income
taxes 41,954 63,642 93,724 121,892

Corporate income
taxes (Note 12) 2,381 23,643 16,329 41,845
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Net earnings before
non-controlling interest 39,573 39,999 77,395 80,047

Non-controlling interest 1,627 1,811 2,844 2,663
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Net earnings applicable
to common shares $ 37,946 $ 38,188 $ 74,551 $ 77,384
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Weighted average common
shares outstanding (Note 6) 103,422 102,865 103,354 100,435
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Earnings per common
share (Note 6)
Basic $ 0.37 $ 0.37 $ 0.72 $ 0.77
Diluted $ 0.35 $ 0.34 $ 0.69 $ 0.70
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Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended June 30
(in thousands)

Quarter Ended Six Months Ended
2006 2005 2006 2005
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Balance at beginning
of period $ 431,815 $ 361,566 $ 411,742 $ 337,013

Net earnings applicable
to common shares 37,946 38,188 74,551 77,384
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469,761 399,754 486,293 414,397

Dividends on common shares (16,550) (14,643) (33,082) (29,286)
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Balance at end of period $ 453,211 $ 385,111 $ 453,211 $ 385,111
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See accompanying notes to interim consolidated financial statements.



Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended June 30
(in thousands)

Quarter Ended Six Months Ended
2006 2005 2006 2005
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Operating Activities
Net earnings applicable
to common shares $ 37,946 $ 38,188 $ 74,551 $ 77,384
Items not affecting cash
Amortization - capital
assets, net of
contributions in
aid of construction 41,698 39,537 83,366 77,199
Amortization - intangibles 1,052 921 2,104 1,842
Amortization - other 1,708 1,697 3,155 3,290
Future income taxes (880) 10,624 (4,379) 9,435
Accrued employee
future benefits (1,954) (527) (1,752) (1,028)
Equity income,
net of dividends (311) (1,187) (141) (1,243)
Stock-based compensation 386 403 772 790
Unrealized foreign
exchange (gain) loss on
long-term debt (Note 9) (1,760) 962 (1,439) 1,359
Non-controlling interest 1,627 1,811 2,844 2,663
Gain on sale of income
producing property (2,088) - (2,088) -
Other (721) 407 (642) 294
Increase in corporate
income tax deposit (5,922) - (5,922) -
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70,781 92,836 150,429 171,985
Change in non-cash
operating working capital (13,022) (42,950) (43,272) (42,761)
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57,759 49,886 107,157 129,224
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Investing Activities
Change in deferred
charges and credits (10,296) (1,742) (10,828) (3,301)
Purchase of utility
capital assets (111,541) (97,781) (215,847) (189,152)
Purchase of income
producing properties (5,169) (6,825) (11,807) (74,217)
Contributions in
aid of construction 13,588 11,804 23,199 22,681
Proceeds on sale of
capital assets 5,416 136 5,909 354
Increase in investments (1,506) (3,248) (1,893) (3,248)
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(109,508) (97,656) (211,267) (246,883)
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Financing Activities
Change in short-
term borrowings 10,546 (17,079) 19,500 (54,737)
Proceeds from
long-term debt 158,815 67,620 210,587 98,016
Repayment of long-term
debt and capital
lease obligations (105,493) (26,339) (112,675) (35,243)
Advances from (to)
non-controlling interest 8,803 (1,367) 9,050 (1,064)
Issue of common shares 2,279 2,626 5,864 130,314
Dividends
Common shares (16,550) (14,643) (33,082) (29,286)
Subsidiary dividends
paid to non-
controlling interest (400) (378) (810) (789)
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58,000 10,440 98,434 107,211
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Effect of exchange
rate changes on cash (409) (27) (375) 92
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Change in cash
and cash equivalents 5,842 (37,357) (6,051) (10,356)

Cash and cash equivalents,
beginning of period 21,523 64,204 33,416 37,203
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Cash and cash equivalents,
end of period $ 27,365 $ 26,847 $ 27,365 $ 26,847
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See accompanying notes to interim consolidated financial statements.


FORTIS INC.

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

For the three and six months ended June 30, 2006 and 2005 (unless otherwise stated) (Unaudited)

1. DESCRIPTION OF THE BUSINESS

Fortis Inc. ("Fortis" or the "Corporation") is principally a diversified, international electric 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 separate segments. The operating 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 operating segment operates as an autonomous unit, assumes profit and loss responsibility and is accountable for its own resource allocation.

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

Regulated Utilities - Canadian

The following summary describes the Corporation's interest in Regulated Utilities in Canada by utility:

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 4 hydroelectric generation plants with a combined total capacity of 235 megawatts ("MW"). Included with the FortisBC component of the Regulated Utilities - Canadian segment are the non-regulated operating, maintenance and management services relating to the 450-MW Waneta hydroelectric generating facility owned by Teck Cominco, the 149-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. Commencing May 31, 2005, the FortisBC component of Regulated Utilities - Canadian segment also includes Princeton Light and Power Company, Limited ("PLP"). On May 31, 2005, Fortis, through an indirect wholly owned subsidiary, acquired all issued common and preference shares of PLP. PLP is an electric utility serving customers, mainly in Princeton, British Columbia. PLP presently purchases its wholesale power from FortisBC Inc. under a Power Purchase Agreement ("PPA").

c. Newfoundland Power: Newfoundland Power is the principal distributor of electricity in Newfoundland. Newfoundland Power also has an installed generating capacity of 146 MW of which 95 MW is hydroelectric generation.

d. Maritime Electric: Maritime Electric is the principal distributor of electricity on Prince Edward Island. Maritime Electric also maintains on-Island generating facilities at Charlottetown and Borden-Carleton with a combined total capacity of 150 MW.

e. FortisOntario: FortisOntario provides an integrated electric utility service to customers in Fort Erie, Cornwall, Gananoque and Port Colborne in Ontario. FortisOntario operations include Canadian Niagara Power Inc. ("Canadian Niagara Power") 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 10-year lease agreement, entered into in April 2002. FortisOntario also owns a 10 per cent interest in each of Westario Power Holdings Inc. and Rideau St. Lawrence Holdings Inc., 2 regional electrical distribution companies formed in 2000.

Regulated Utilities - Caribbean

The following summary describes the Corporation's interest in Regulated Utilities in the Caribbean by utility:

a. Belize Electricity: Belize Electricity is the principal distributor of electricity in Belize, Central America. The Corporation holds a 70.1 per cent controlling interest in the Company.

b. Caribbean Utilities Company, Ltd. ("Caribbean Utilities"): Caribbean Utilities is the sole provider of electricity on Grand Cayman, Cayman Islands. Fortis holds a 37.4 per cent equity interest in the Company.

Non-Regulated - Fortis Generation

The following summary describes the Corporation's non-regulated generation assets by location:

a. Central Newfoundland: Through the Exploits River Hydro Partnership ("Exploits Partnership"), a partnership between the Corporation, through an indirect wholly owned subsidiary, CNE Energy Inc., and Abitibi-Consolidated Company of Canada ("Abitibi-Consolidated"), 36 MW of additional capacity was developed and installed at 2 of Abitibi-Consolidated's hydroelectric plants in central Newfoundland. The Corporation holds an indirect 51 per cent interest in the Exploits Partnership and Abitibi-Consolidated holds the remaining 49 per cent interest. The Exploits Partnership sells its output to Newfoundland and Labrador Hydro Corporation under a 30-year PPA.

b. Ontario: Includes 75 MW of water right entitlement associated with the Niagara Exchange Agreement, the 5-MW Cornwall District Heating cogeneration plant and 6 small hydroelectric generating stations in eastern Ontario with a combined capacity of 8 MW. Non-regulated generating operations in Ontario are conducted through FortisOntario Inc. and the former FortisOntario Generation Corporation. In January 2006, FortisOntario Generation Corporation was amalgamated with CNE Energy Inc.

c. Belize: Operations consist of the 25-MW Mollejon and 7-MW Chalillo hydroelectric facilities in Belize. All of the electricity output is sold to Belize Electricity under a 50-year PPA. Hydroelectric generation operations in Belize are conducted through the Corporation's wholly owned indirect subsidiary, Belize Electric Company Limited ("BECOL"), under a Franchise Agreement with the Government of Belize.

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. Hydroelectric generating operations in British Columbia are conducted through the Walden Power Partnership, a wholly owned partnership of FortisBC Inc.

e. Upper New York State: Includes the operations of 4 hydroelectric generating stations in Upper New York State with a combined capacity of 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.

Non-Regulated - Fortis Properties

Fortis Properties owns and operates hotels in 6 provinces in Canada and commercial real estate in Atlantic Canada. Its holdings include 14 hotels with more than 2,800 rooms and approximately 2.7 million square feet of commercial real estate.

Corporate

Corporate includes finance charges related to debt incurred directly by Fortis, foreign exchange gains or losses, preference share dividends, other corporate expenses, net of recoveries from subsidiaries, interest and miscellaneous revenues, and corporate income taxes.

2. BASIS OF PRESENTATION

These interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") for interim financial statements and do not include all of the disclosures normally found in the Corporation's annual consolidated financial statements. These interim consolidated financial statements should be read in conjunction with the Corporation's 2005 annual audited consolidated financial statements. Interim results will fluctuate due to the seasonal nature of electricity demand and water flows as well as the timing and recognition of regulatory decisions. Given the diversified group of companies, seasonality may vary. Most of the Corporation's utility investments produce their highest earnings in the first quarter. The Corporation's non-utility investment, Fortis Properties, generally produces its highest earnings in the second and third quarters.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These interim consolidated financial statements have been prepared in accordance with Canadian GAAP, including selected accounting treatments that differ from those used by entities not subject to rate regulation. The timing of the recognition of certain assets, liabilities, revenues and expenses, as a result of regulation, may differ from that otherwise expected using Canadian GAAP for entities not subject to rate regulation. These differences and nature of regulation are disclosed in Notes 2 and 4 to the Corporation's 2005 annual audited consolidated financial statements. These interim consolidated financial statements have been prepared following the same accounting policies and methods as those used in preparing the Corporation's 2005 annual audited consolidated financial statements except as described below. All amounts are presented in Canadian dollars unless otherwise stated.

Revenue Recognition

Effective January 1, 2006, Newfoundland Power prospectively changed its revenue recognition policy from a billed basis to an accrual basis, as approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB"). The transition to recording revenue on an accrual basis, while having no material impact on Newfoundland Power's annual earnings, results in a shift in the Company's 2006 quarterly earnings compared to 2005. The change in the revenue recognition policy resulted in a $6.4 million and $10.7 million decrease in revenue quarter over quarter and year to date compared to the same period last year, respectively. The PUB also approved a one-time revenue accrual of $3.1 million in 2006. This amount represents that portion of unbilled revenue, as at December 31, 2005, of $23.6 million, required to offset the income tax effects to be incurred in 2006 relating to the change to the accrual basis of revenue recognition. A total of $0.7 million and $1.6 million of the one-time revenue accrual was recognized during the second quarter and year to date, respectively. The disposition of the remaining 2005 unbilled revenue balance has been deferred until the Company's next general rate application. The change in the revenue recognition policy, including the impact of the recognition of a portion of the one-time revenue accrual, resulted in a decrease in earnings of $3.2 million and $5.2 million quarter over quarter and year to date compared to the same period last year, respectively.

Conditional Asset Retirement Obligations

On April 1, 2006, Fortis retroactively adopted EIC 159, Conditional Asset Retirement Obligations ("EIC 159"). EIC 159 requires an entity to recognize a liability for the fair value of an asset retirement obligation ("ARO") even though the timing and/or method of settlement are conditional on future events. While conditional AROs have been identified, no amounts have been recorded as they are immaterial to the Corporation's results of operations and financial position.

Corporate Income Taxes

Effective January 1, 2006, FortisAlberta is following the taxes payable method of accounting for federal income taxes. As prescribed by the 2006/2007 Negotiated Settlement Agreement, approved by the Alberta Electric Utility Board ("AEUB") on June 29, 2006, income tax expenses are now recovered through customer rates based only on income taxes that are currently payable for regulatory purposes. The cumulative impact of the change in the income tax methodology was recorded by the Corporation during the second quarter of 2006. Under the new methodology, current rates do not include the recovery of future income taxes related to certain temporary differences between the tax basis of assets and liabilities and their carrying amounts for regulatory purposes, as these taxes are expected to be collected in rates when they become payable. Accordingly, FortisAlberta no longer recognizes income taxes deferred to future years as a result of the specified temporary differences. The Company only recognizes future income taxes for certain deferral amounts where the future income taxes will not be collected in future customer rates.

In 2005, FortisAlberta followed the taxes payable method of accounting for provincial income taxes and federal income tax expenses were recovered through customer rates based on a modified liability method. Under the modified liability method, customer rates included the recovery of future federal income taxes related to specified temporary differences between the tax basis of assets and liabilities and their carrying amounts for regulatory purposes. As a result of collecting a portion of future federal income taxes within customer rates in 2005, FortisAlberta previously recognized future federal income taxes within the 2005 financial statements and also set up a regulatory liability equal to the amount of future federal income taxes recognized that had not yet been reflected in customer rates. However, due to the 2006/2007 Negotiated Settlement Agreement, the future income tax asset and offsetting regulatory liability are no longer recognized which resulted in a $50.7 million reduction in the Corporation's future income tax assets and regulatory liabilities during the second quarter of 2006.

Had FortisAlberta accounted for its regulated operations using the liability method in 2006, the Company would have had additional future income tax assets of approximately $64.3 million at June 30, 2006 and would have recognized additional future income tax expense of approximately $12.6 million for the year-to-date period ended June 30, 2006 (Note 12).

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 assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates 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 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 to the Corporation's critical accounting estimates during the 6 months ended June 30, 2006 from those disclosed in the Corporation's Management Discussion and Analysis for the year ended December 31, 2005 except as discussed below and as described in Note 14 to these interim consolidated financial statements.

Rates

On May 23, 2006 and June 29, 2006, FortisBC and FortisAlberta, respectively, received approval for final rates to be charged to customers in 2006 as a result of the respective regulators' approval of the Negotiated Settlement Agreements. At FortisBC, the 5.9 per cent interim electricity rate increase charged to customers, effective January 1, 2006, and the 2006 final approved rate increase at FortisBC were the same. At FortisAlberta, however, the AEUB approved a 1.9 per cent electricity rate reduction, effective January 1, 2006. FortisAlberta had been charging interim rates which were the same as those charged in 2005. The impact of the rate reduction at FortisAlberta, effective January 1, 2006, of $2.1 million was recorded as a reduction in revenue during the second quarter of 2006 and will be refunded to customers during 2007.

Amortization and Capitalized Overhead

FortisBC recently completed a depreciation study on the estimated useful life of its property, plant and equipment. The study recommended an increase in the Company's composite depreciation rate from 2.6 per cent to 3.6 per cent. FortisBC's 2006 Application and the Corporation's first quarter 2006 consolidated financial statements were based on the 3.6 per cent composite depreciation rate at FortisBC. The 2006 Negotiated Settlement Agreement resulted in a composite depreciation rate of 3.2 per cent, effective January 1, 2006, which has been reflected in the Corporation's second quarter 2006 consolidated financial statements resulting in a $0.4 million reduction in amortization costs.

FortisBC also recently completed an analysis of its capitalized overhead allocation method. This analysis supported a change in the estimate of capitalized overhead. The changed estimate calculates capitalized overhead as a percentage of all corporate overhead, whereas previously the percentage was applied to a limited pool of corporate costs. FortisBC's 2006 Application and the Corporation's first quarter 2006 consolidated financial statements were based on a capitalized overhead percentage of approximately 27.5 per cent of gross operating and maintenance expenses compared to approximately 9.0 per cent used previously at FortisBC. The 2006 Negotiated Settlement Agreement resulted in a capitalized overhead rate of approximately 20.0 per cent of gross operating and maintenance expenses, effective January 1, 2006, which has been reflected in the Corporation's second quarter 2006 consolidated financial statements, resulting in a $0.9 million reduction in capitalized overhead costs and corresponding increase in operating expenses.

Year to date June 30, 2006, the increase in FortisBC's composite depreciation rate to 3.2 per cent from 2.6 per cent and the increase in the percentage of gross operating and maintenance expenses capitalized to approximately 20.0 per cent from 9.0 per cent resulted in increased amortization costs of $2.4 million and decreased operating costs of $2.3 million, respectively.

5. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

The Corporation and its subsidiaries had consolidated authorized lines of credit of $795.0 million, of which $573.8 million was unused at June 30, 2006. The following summary outlines the Corporation's credit facilities by reporting segments.



Credit Facilities Regulated Fortis
($ millions) Corporate Utilities Generation
----------------------------------------------------------------
Total credit facilities 210.0 566.9 5.6
Credit facilities utilized
Short-term borrowings (4.1) (73.4) -
Long-term debt (42.0) (39.9) -
Letters of credit outstanding (4.5) (53.7) -
----------------------------------------------------------------
Credit facilities available 159.4 399.9 5.6
----------------------------------------------------------------
----------------------------------------------------------------

--------------------------------------------------------------------
Total Total
as at as at
Credit Facilities Fortis June 30, December 31,
($ millions) Properties 2006 2005
-----------------------------------------------------------------
Total credit facilities 12.5 795.0 747.1
Credit facilities utilized
Short-term borrowings (1.5) (79.0) (59.9)
Long-term debt - (81.9) (74.8)
Letters of credit outstanding (2.1) (60.3) (73.6)
-----------------------------------------------------------------
Credit facilities available 8.9 573.8 538.8
-----------------------------------------------------------------
-----------------------------------------------------------------


At June 30, 2006 and December 31, 2005, certain borrowings under the Corporation's and subsidiaries' credit facilities have been classified as long-term debt. These borrowings are under long-term credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.

In January 2006, Newfoundland Power renegotiated its syndicated $100 million committed revolving term credit facility extending the term from 1 year to 3 years, with maturity now in January 2009.

In January 2006, Maritime Electric's $25 million non-revolving unsecured short-term bridge financing, in support of the construction of the 50-MW combustion turbine generating facility, was extended until July 2007.

In March 2006, FortisAlberta amended its term syndicated credit facility increasing the amount available to $200 million from $150 million and extending the maturity date from May 2008 to May 2010. In addition, the Company has the ability to request an increase in the limit of this credit facility by $50 million under the same terms of the existing credit facility.

In May 2006, the maturity date of FortisBC's $50 million operating credit facility was extended to May 2007.

In June 2006, Fortis renegotiated and amended its $145 million and $50 million unsecured term credit facilities extending the maturity dates of these facilities from May 2008 and January 2009 to May 2010 and January 2011, respectively. Additionally, in July 2006, the amount available under the $145 million facility was increased to $250 million. These credit facilities can be used for general corporate purposes, including acquisitions.

On April 21, 2006, FortisAlberta issued $100 million in unsecured debentures bearing interest at 5.40% per annum, payable semi-annually on April 21 and October 21, due April 21, 2036. The net proceeds of the offering were used primarily to repay existing indebtedness on FortisAlberta's long-term credit facility.



6. COMMON SHARES

Authorized: an unlimited number of Common Shares without nominal
or par value.
June 30, 2006 December 31, 2005
------------------------------------------------------------------
Number of Amount Number of Amount
a) Issued and Shares (in Shares (in
Outstanding thousands) thousands)
------------------------------------------------------------------
Common Shares 103,489,080 $819,227 103,203,981 $813,304
------------------------------------------------------------------
------------------------------------------------------------------


Common Shares issued during the period were as follows:
--------------------------------------------------------------------
Quarter Ended Year-to-date
June 30, 2006 June 30, 2006
--------------------------------------------------------------------
Number of Amount Number of Amount
Shares (in Shares (in
thousands) thousands)
--------------------------------------------------------------------
Opening balance 103,384,041 $816,914 103,203,981 $813,304
Consumer Share
Purchase Plan 20,179 465 41,567 958
Dividend
Reinvestment Plan 46,260 1,066 91,248 2,102
Employee Share
Purchase Plan 21,929 505 90,415 2,083
Directors' and
Executive Stock
Option Plans 16,671 277 61,869 780
--------------------------------------------------------------------
103,489,080 $819,227 103,489,080 $819,227
-------------------------------------------------
-------------------------------------------------


At June 30, 2006, 11,561,368 Common Shares remained reserved for issue under the terms of the above-noted share purchase, dividend reinvestment and stock option plans.

Earnings per Common Share

The Corporation calculates earnings per common share on the weighted average number of common shares outstanding. The year-to-date weighted average number of common shares outstanding were 103,354,401 and 100,434,916 at June 30, 2006 and June 30, 2005, respectively. The weighted average number of common shares outstanding were 103,421,531 and 102,865,172 for the quarters ended June 30, 2006 and June 30, 2005, respectively.

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



b) Earnings per Common Share
Earnings per common share are as follows:

Quarter Ended June 30
-----------------------------------------
2006
-----------------------------------------
Weighted Earnings
Average per
Earnings Shares Common
(in thousands) (in thousands) Share
-----------------------------------------------------------------
Earnings $37,946
Weighted average
shares outstanding 103,422
-----------------------------------------------------------------
Basic Earnings per
Common Share $0.37
-----------------------------------------------------------------
Effect of dilutive
securities:
Stock options - 1,246
Preference Shares 4,151 14,096
Convertible debentures 257 1,925
-----------------------------------------------------------------
Diluted Earnings per
Common Share $42,354 120,689 $0.35
-----------------------------------------------------------------
(1) The share information has been restated to reflect the 4-for-1
stock split completed in October 2005.

Quarter Ended June 30
------------------------------------------
2005
------------------------------------------
Weighted Earnings
Average per
Earnings Shares(1) Common
(in thousands) (in thousands) Share(1)
------------------------------------------------------------------
Earnings $38,188
Weighted average
shares outstanding 102,865
------------------------------------------------------------------
Basic Earnings per
Common Share $0.37
------------------------------------------------------------------
Effect of dilutive
securities:
Stock options - 810
Preference Shares 4,151 19,689
Convertible debentures 283 1,925
------------------------------------------------------------------
Diluted Earnings per
Common Share $42,622 125,289 $0.34
------------------------------------------------------------------
(1) The share information has been restated to reflect the 4-for-1
stock split completed in October 2005.

Year-to-date June 30
--------------------------------------
2006
--------------------------------------
Weighted Earnings
Average per
Earnings Shares Common
(in thousands) (in thousands) Share
--------------------------------------------------------------
Earnings $74,551
Weighted average
shares outstanding 103,354
--------------------------------------------------------------
Basic Earnings per
Common Share $0.72
--------------------------------------------------------------
Effect of dilutive
securities:
Stock options - 1,246
Preference Shares 8,303 14,096
Convertible debentures 519 1,925
--------------------------------------------------------------
Diluted Earnings per
Common Share $83,373 120,621 $0.69
--------------------------------------------------------------
--------------------------------------------------------------

(1) The share information has been restated to reflect the
4-for-1 stock split completed in October 2005.

Year-to-date June 30
--------------------------------------------
2005
------------------------------------------
Weighted Earnings
Average per
Earnings Shares(1) Common
(in thousands) (in thousands) Share(1)
------------------------------------------------------------------
Earnings $77,384
Weighted average
shares outstanding 100,435
--------------------------------------------------------------------
Basic Earnings per
Common Share $0.77
--------------------------------------------------------------------
Effect of dilutive
securities:
Stock options - 810
Preference Shares 8,303 19,689
Convertible debentures 563 1,925
--------------------------------------------------------------------
Diluted Earnings per
Common Share $86,250 122,859 $0.70
--------------------------------------------------------------------
--------------------------------------------------------------------

(1) The share information has been restated to reflect the
4-for-1 stock split completed in October 2005.


7. STOCK OPTIONS

The Corporation is authorized to grant certain key employees and directors of Fortis Inc. and its subsidiaries options to purchase Common Shares of the Corporation. At June 30, 2006, the Corporation had the following stock-based compensation plans: Executive Stock Option Plan, 2002 Stock Option Plan and 2006 Stock Option Plan. The 2002 Stock Option Plan was adopted at the Annual and Special General Meeting on May 15, 2002 to ultimately replace the Executive and the former Directors' Stock Option Plans. The Executive Stock Option Plan will cease to exist when all outstanding options are exercised or expire in or before 2011. A new 2006 Stock Option Plan ("2006 Plan") was approved at the May 2, 2006 Annual Meeting at which Special Business was conducted. The 2006 Plan will ultimately replace the Executive Stock Option Plan and 2002 Stock Option Plan. The Corporation will cease to grant options under the 2002 Stock Option Plan and all new options to be granted by Fortis will be granted under the 2006 Stock Option Plan. Options granted under the 2006 Plan will have a maximum term of 7 years, which is reduced from 10 years under the 2002 Stock Option Plan, and will expire no later than 3 years after the termination, death or retirement of the optionee compared to no later than 1 year under the 2002 Stock Option Plan. Directors are not eligible to receive grants of options under the 2006 Plan.



Quarter Ended Year-to-date
June 30, 2006 June 30, 2006
-----------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Price Options Price
-----------------------------------------
Options outstanding at
beginning of period 4,003,439 $15.60 3,421,876 $14.18
Granted - $ - 626,761 $22.94
Cancelled - $ - - $ -
Exercised (16,671) $14.62 (61,869) $11.66
-----------------------------------------
Options outstanding at
end of period 3,986,768 $15.60 3,986,768 $15.60
-----------------------------------------
-----------------------------------------

Details of stock options Number of Exercise Expiry
outstanding are as follows: Options Price Date
-----------------------------------
417,992 $9.57 2011
627,744 $12.03 2012
698,525 $12.81 2013
707,060 $15.28 2014
12,000 $15.23 2014
68,557 $14.55 2014
766,389 $18.40 2015
28,000 $18.11 2015
33,740 $20.82 2015
626,761 $22.94 2016
----------
3,986,768
----------
----------
Options vested at end of period 2,125,140
----------
----------


Stock-Based Compensation

On February 28, 2006, the Corporation granted 626,761 options on common shares under its 2002 Stock Option Plan at the 5-day average trading price immediately preceding the date of grant of $22.94. These options vest evenly over a 4-year period on each anniversary of the date of grant. The options expire 10 years after the date of grant. The fair market value of each option granted was $3.90 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:




February 28, 2006
Dividend yield (%) 3.02
Expected volatility (%) 16.7
Risk-free interest rate (%) 4.12
Weighted-average expected life (years) 7.5



The Corporation records compensation expense upon the issuance of stock options under its 2002 and 2006 Stock Option Plans. Using the fair value method, the compensation expense is amortized over the 4-year vesting period of the options. Under the fair value method, $0.4 million and $0.8 million were recorded as compensation expense for the quarter and 6 months ended June 30, 2006, respectively ($0.4 million and $0.8 million for the quarter and 6 months ended June 30, 2005, respectively).

8. EMPLOYEE FUTURE BENEFITS

The Corporation provides pension arrangements and other post-employment benefits to qualified employees through both defined contribution and defined benefit arrangements. The cost of providing the defined benefit arrangements was $4.1 million and $9.5 million for the quarter and 6 months ended June 30, 2006 ($4.8 million and $8.3 million for the quarter and 6 months ended June 30, 2005, respectively). The cost of providing the defined contribution arrangements for the quarter and 6 months ended June 30, 2006 was $0.7 million and $1.6 million, respectively ($0.7 million and $1.5 million for the quarter and 6 months ended June 30, 2005, respectively).

9. FINANCE CHARGES



Quarter Ended Year-to-date
June 30 June 30
--------------------------------------
(in thousands) 2006 2005 2006 2005
-------------------------------------------------------------------
Amortization of debt and
stock issue expenses $162 $94 $309 $346
Interest - Long-term debt
and capital lease
obligations 37,880 35,442 75,338 70,635
- Short-term borrowings 1,259 1,377 3,012 3,367
Interest charged to
construction (980) (1,478) (2,097) (2,668)
Interest earned (1,014) (1,242) (2,106) (1,986)
Unrealized foreign exchange
(gain) loss on long-term
debt (1,760) 962 (1,439) 1,359
-------------------------------------------------------------------
$35,547 $35,155 $73,017 $71,053
--------------------------------------
--------------------------------------


10. GAIN ON SALE OF INCOME PRODUCING PROPERTY

On June 28, 2006, Fortis Properties sold the Days Inn Sydney for gross proceeds of $4.5 million resulting in a gain of $2.1 million ($1.6 million after-tax).

11. GAIN ON SETTLEMENT OF CONTRACTUAL MATTERS

In the first quarter of 2005, Fortis recorded a $10.0 million ($7.9 million after-tax) gain resulting from the settlement of contractual matters between FortisOntario and Ontario Power Generation Inc.

12. CORPORATE INCOME TAXES

Corporate incomes taxes differ from the amount that would be expected by applying the enacted Canadian federal and provincial statutory income tax rates to earnings before income taxes. The following is a reconciliation of the consolidated statutory income tax rate to the consolidated effective income tax rate:



Quarter Ended Year-to-date
June 30 June 30
--------------------------------
(%) 2006 2005 2006 2005
--------------------------------------------------------------------
Statutory income tax rate 35.5 35.2 35.2 35.4
Preference share dividends 3.6 2.4 3.2 2.5
Large corporations' and provincial
capital tax (2.0) 2.1 0.4 2.4
Differences between Canadian
statutory rates and those
applicable to foreign subsidiaries (6.1) (2.2) (4.6) (1.9)
Items capitalized for accounting
but expensed for income
tax purposes (17.8) (1.6) (13.2) (2.0)
Impact of reduction in tax rates on
future income tax balances (5.0) - (3.5) -
Change in revenue recognition
policy at Newfoundland
Power (Note 3) 1.0 - 1.1 -
Maritime Electric tax reassessment
(Note 14) 1.9 - 1.7 -
Pension costs (0.7) (0.3) (0.8) (1.0)
Timing differences (3.7) 2.0 (1.4) 0.6
Other (1.0) (0.5) (0.7) (1.7)
--------------------------------------------------------------------
Effective income tax rate 5.7 37.1 17.4 34.3
--------------------------------
--------------------------------


During the second quarter of 2006, FortisAlberta recorded the impact associated with the first and second quarters of 2006, relating to the June 29, 2006 AEUB approved 2006/2007 Negotiated Settlement Agreement, effective January 1, 2006. The approved 2006/2007 Negotiated Settlement Agreement resulted in a change in the income tax methodology whereby future income tax expense for federal income tax, associated with specified timing differences, is no longer being recognized. The effect of the change in income tax methodology has been a decrease in income tax expense during the quarter and year to date, primarily associated with the timing of recognition for income tax purposes of those items capitalized for accounting purposes (Note 3).

13. SEGMENTED INFORMATION

a) Information by reportable segment is as follows



Quarter ended
(in thousands of dollars)
June 30, 2006 Regulated Utilities
---------------------------------------------------------------------
Fortis Fortis Nfld Maritime Fortis Total Total
Alberta BC Power Electric Ontario Canadian Caribbean
---------------------------------------------------------------------
---------------------------------------------------------------------
Operating
revenues 58,601 45,827 97,359 29,161 32,927 263,875 22,694
Equity
income - - - - - - 2,083
Energy
supply
costs - 13,920 57,667 17,209 24,792 113,588 13,366
Operating
expenses 26,910 16,009 12,563 3,314 3,921 62,717 2,730
Amorti-
-zation 18,485 6,556 7,890 2,548 1,340 36,819 1,369
----------------------------------------------------------
Operating
income 13,206 9,342 19,239 6,090 2,874 50,751 7,312
Finance
charges 7,517 5,668 8,037 2,569 1,254 25,045 1,495
Preference
share
dividends - - - - - - -
Gain on
sale
of income
producing
property - - - - - - -
Corporate
income
taxes (5,653) 267 3,013 1,319 1,153 99 400
Non-control
-ling
interest - - 147 - - 147 1,039
----------------------------------------------------------
----------------------------------------------------------
Net
earnings
(loss) 11,342 3,407 8,042 2,202 467 25,460 4,378
----------------------------------------------------------
Goodwill 228,615 220,719 - 19,858 42,947 512,139 -
Identi-
-fiable
assets 796,889 744,789 848,150 277,742 117,883 2,785,453 212,776
Equity
investment
assets - - - - - - 166,721
----------------------------------------------------------
Total
assets 1,025,504 965,508 848,150 297,600 160,830 3,297,592 379,497
----------------------------------------------------------
----------------------------------------------------------
Capital
expendi-
-tures 61,519 22,552 15,002 4,900 1,859 105,832 3,331
----------------------------------------------------------
----------------------------------------------------------

June 30, 2005
---------------------------------------------------------------------
Operating
revenues 75,734 44,107 105,654 28,304 32,014 285,813 18,709
Equity
income - - - - - - 3,061
Energy
supply
costs - 12,050 57,494 16,963 24,935 111,442 10,010
Operating
expenses 27,868 15,903 13,818 3,168 3,035 63,792 2,861
Amorti-
-zation 16,889 4,707 9,270 2,419 1,244 34,529 1,625
----------------------------------------------------------
----------------------------------------------------------
Operating
income 30,977 11,447 25,072 5,754 2,800 76,050 7,274
Finance
charges 5,841 4,200 7,721 1,968 1,288 21,018 1,161
Preference
share
dividends - - - - - - -
Gain on
settlement
of
contractual
matters - - - - - - -
Corporate
income
taxes 10,371 1,874 5,696 1,510 615 20,066 325
Non-control-
-ling
interest - - 147 - - 147 837
----------------------------------------------------------
Net
earnings
(loss) 14,765 5,373 11,508 2,276 897 34,819 4,951
----------------------------------------------------------
----------------------------------------------------------
Goodwill 229,097 220,694 - 19,858 45,577 515,226 -
Identi-
-fiable
assets 690,237 656,944 829,321 257,467 123,770 2,557,739 208,330
Equity
investment
assets - - - - - - 162,480
----------------------------------------------------------
----------------------------------------------------------
Total
assets 919,334 877,638 829,321 277,325 169,347 3,072,965 370,810
----------------------------------------------------------
Capital
expendi-
-tures 33,121 28,187 11,475 12,483 1,988 87,254 2,677
----------------------------------------------------------


Quarter ended
(in thousands
of dollars) Non-Regulated
--------------------------------------------
Inter-
segment
Fortis Fortis elimi Consoli-
Generation Properties Corporate -nations -dated

June 30, 2006
-------------------------------------------------------------------
Operating
revenues 20,564 41,927 2,183 (7,475) 343,768
Equity
income - - - - 2,083
Energy
supply
costs 1,436 - - (4,119) 124,271
Operating
expenses 3,893 26,314 3,150 (1,246) 97,558
Amortization 2,631 2,893 746 - 44,458
-------------------------------------------------------------------
Operating
income 12,604 12,720 (1,713) (2,110) 79,564
Finance
charges 2,590 4,972 3,555 (2,110) 35,547
Preference
share
dividends - - 4,151 - 4,151
Gain on
sale
of income
producing
property - (2,088) - - (2,088)
Corporate
income
taxes 2,845 1,698 (2,661) - 2,381
Non-control-
-ling
interest 482 - (41) - 1,627
-------------------------------------------------------------------
Net
earnings
(loss) 6,687 8,138 (6,717) - 37,946
-------------------------------------------------------------------
Goodwill - - - - 512,139
Identi-
-fiable
assets 242,930 436,868 40,043 (15,943) 3,702,127
Equity
investment
assets - - - - 166,721
-------------------------------------------------------------------
Total
assets
242,930 436,868 40,043 (15,943) 4,380,987
-------------------------------------------------------------------
Capital
expendi-
-tures 1,732 5,169 646 - 116,710
-------------------------------------------------------------------
-------------------------------------------------------------------

June 30, 2005
-------------------------------------------------------------------
Operating
revenues 19,211 40,789 2,631 (5,266) 361,887
Equity
income - - - - 3,061
Energy
supply
costs 1,768 - - (1,750) 121,470
Operating
expenses 4,408 25,235 3,080 (1,001) 98,375
Amortiza-
tion 2,550 2,751 700 - 42,155
-------------------------------------------------------------------
Operating
income 10,485 12,803 (1,149) (2,515) 102,948
Finance
charges 4,016 4,689 6,786 (2,515) 35,155
Preference
share
dividends - - 4,151 - 4,151
Gain on
settlement
of
contractual
matters - - - - -
Corporate
income
taxes 2,383 3,268 (2,399) - 23,643
Non-control-
-ling
interest 868 - (41) - 1,811
-------------------------------------------------------------------
Net earnings
(loss) 3,218 4,846 (9,646) - 38,188
-------------------------------------------------------------------
-------------------------------------------------------------------
Goodwill - - - - 515,226
Identi-
-fiable
assets 268,536 426,391 50,236 (29,439) 3,481,793
Equity
investment
assets - - - - 162,480
-------------------------------------------------------------------
Total
assets 268,536 426,391 50,236 (29,439) 4,159,499
-------------------------------------------------------------------
-------------------------------------------------------------------
Capital
expendi-
-tures 7,693 6,825 157 - 104,606
-------------------------------------------------------------------


Year to date
(in thousands
of dollars)
June 30, 2006 Regulated Utilities
---------------------------------------------------------------------
Fortis Fortis Nfld Maritime Fortis Total Total
Alberta BC Power Electric Ontario Canadian Caribbean
---------------------------------------------------------------------
---------------------------------------------------------------------
Operating
revenues 120,404 108,557 229,151 59,041 66,167 583,320 42,779
Equity
income - - - - - - 3,702
Energy
supply
costs - 33,151 140,329 35,486 50,548 259,514 25,098
Operating
expenses 55,611 31,377 27,123 6,462 7,184 127,757 5,436
Amorti-
-zation 34,200 13,682 17,674 5,095 2,674 73,325 2,790
----------------------------------------------------------
Operating
income 30,593 30,347 44,025 11,998 5,761 122,724 13,157
Finance
charges 14,266 11,267 16,173 4,968 2,490 49,164 3,149
Preference
share
dividends - - - - - - -
Gain on
sale of
income
producing
property - - - - - - -
Corporate
income
taxes (4,505) 3,821 8,857 2,763 1,815 12,751 746
Non-control-
-ling
interest - - 295 - - 295 1,730
----------------------------------------------------------
----------------------------------------------------------
Net
earnings
(loss) 20,832 15,259 18,700 4,267 1,456 60,514 7,532
----------------------------------------------------------
----------------------------------------------------------
Goodwill 228,615 220,719 - 19,858 42,947 512,139 -
Identi-
-fiable
assets 796,889 744,789 848,150 277,742 117,883 2,785,453 212,776
Equity
investment
assets - - - - - - 166,721
----------------------------------------------------------
----------------------------------------------------------
Total
assets 1,025,504 965,508 848,150 297,600 160,830 3,297,592 379,497
----------------------------------------------------------
Capital
expendi-
-tures 116,109 48,159 27,025 10,604 3,742 205,639 6,757
----------------------------------------------------------
June 30,
2005
---------------------------------------------------------------------
Operating
revenues 134,329 99,481 241,090 57,590 70,174 602,664 34,096
Equity
income - - - - - - 5,572
Energy
supply
costs - 30,605 140,592 35,106 55,559 261,862 18,144
Operating
expenses 54,789 31,946 28,019 6,166 6,178 127,098 5,645
Amorti-
-zation 30,735 9,342 19,857 4,818 2,487 67,239 3,237
----------------------------------------------------------
Operating
income 48,805 27,588 52,622 11,500 5,950 146,465 12,642
Finance
charges 11,811 8,741 15,413 4,182 2,576 42,723 2,401
Preference
share
dividends - - - - - - -
Gain on
settlement
of
contractual
matters - - - - - - -
Corporate
income
taxes 14,383 4,526 12,457 2,924 1,372 35,662 540
Non-control-
-ling
interest - - 292 - - 292 1,277
----------------------------------------------------------
Net
earnings
(loss) 22,611 14,321 24,460 4,394 2,002 67,788 8,424
----------------------------------------------------------
----------------------------------------------------------
Goodwill 229,097 220,694 - 19,858 45,577 515,226 -
Identi-
-fiable
assets 690,237 656,944 829,321 257,467 123,770 2,557,739 208,330
Equity
investment
assets - - - - - - 162,480
----------------------------------------------------------
Total
assets 919,334 877,638 829,321 277,325 169,347 3,072,965 370,810
----------------------------------------------------------
Capital
expendi-
-tures 66,946 51,114 26,015 21,441 2,932 168,448 5,140
----------------------------------------------------------


Year to date
(in thousands
of dollars)
June 30, 2006 Non-Regulated
--------------------------------------------
Inter-
segment
Fortis Fortis elimi Consoli-
Generation Properties Corporate -nations -dated
----------------------------------------------------------------------
Operating
revenues 39,847 77,064 4,205 (14,239) 732,976
Equity
income - - - - 3,702
Energy
supply
costs 3,345 - - (7,613) 280,344
Operating
expenses 7,922 50,867 5,521 (2,750) 194,753

Amorti-
-zation 5,282 5,735 1,493 - 88,625
---------------------------------------------------------
Operating
income 23,298 20,462 (2,809) (3,876) 172,956
Finance
charges 5,227 10,122 9,231 (3,876) 73,017
Preference
share
dividends - - 8,303 - 8,303
Gain on
sale of
income
producing
property - (2,088) - - (2,088)
Corporate
income
taxes 5,064 2,812 (5,044) - 16,329
Non-control-
-ling
interest 902 - (83) - 2,844

---------------------------------------------------------
---------------------------------------------------------
Net
earnings
(loss) 12,105 9,616 (15,216) - 74,551
---------------------------------------------------------
---------------------------------------------------------
Goodwill - - - - 512,139

Identi-
-fiable
assets 242,930 436,868 40,043 (15,943) 3,702,127
Equity
investment
assets - - - - 166,721
---------------------------------------------------------
---------------------------------------------------------
Total
assets
242,930 436,868 40,043 (15,943) 4,380,987
---------------------------------------------------------
Capital
expendi-
-tures 2,478 11,807 973 - 227,654
---------------------------------------------------------
---------------------------------------------------------

June 30, 2005
--------------------------------------------------------------------
Operating
revenues 36,181 73,827 5,203 (10,806) 741,165
Equity
income - - - - 5,572
Energy
supply
costs 3,628 - - (3,632) 280,002
Operating
expenses 9,254 48,066 5,293 (2,200) 193,156
Amorti-
-zation 5,105 5,351 1,399 - 82,331
---------------------------------------------------------
Operating
income 18,194 20,410 (1,489) (4,974) 191,248
Finance
charges 7,891 9,613 13,399 (4,974) 71,053
Preference
share
dividends - - 8,303 - 8,303
Gain on
settlement
of
contractual
matters (10,000) - - - (10,000)
Corporate
income
taxes 5,918 4,450 (4,725) - 41,845
Non-control-
-ling
interest 1,176 - (82) - 2,663
---------------------------------------------------------
Net
earnings
(loss) 13,209 6,347 (18,384) - 77,384
---------------------------------------------------------
---------------------------------------------------------
Goodwill - - - - 515,226
Identi-
-fiable
assets 268,536 426,391 50,236 (29,439) 3,481,793
Equity
investment
assets - - - - 162,480
---------------------------------------------------------
Total
assets 268,536 426,391 50,236 (29,439) 4,159,499
---------------------------------------------------------
---------------------------------------------------------
Capital
expendi-
-tures 14,266 74,217 1,298 - 263,369
---------------------------------------------------------
---------------------------------------------------------


b) Inter-Company Transactions

Inter-company 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-company transactions primarily related to the sale of energy from BECOL to Belize Electricity, electricity sales from Newfoundland Power to Fortis Properties and finance charges on inter-company borrowings. The significant inter-company transactions for the second quarter and year-to-date periods ended June 30, 2006 and 2005 are detailed below.



Inter-company transactions Quarter Ended Year-to-date
(in thousands) June 30 June 30
------------------------------
2006 2005 2006 2005
----------------------------------------------------------------
Sales from BECOL to Belize
Electricity $3,848 $883 $6,996 $1,778
Sales from Newfoundland Power to
Fortis Properties 834 886 1,925 1,821
Inter-company finance charges on
borrowings from:
Corporate to Fortis Properties 1,135 881 2,068 1,951
Corporate to BECOL - 775 - 1,425
BECOL to Belize Electricity 337 456 742 922
----------------------------------------------------------------


14. CONTINGENT LIABILITIES AND COMMITMENTS

Contingent liabilities and commitments are consistent with disclosures in the Fortis annual audited consolidated financial statements for the year ended December 31, 2005, except as described below.

(a) Maritime Electric

In April 2006, Canada Revenue Agency ("CRA") reassessed Maritime Electric's 1997-2004 taxation years. The reassessment encompasses the Company's tax treatment, specifically the Company's timing of deductions, with respect to: (i) the ECAM in the 2001-2004 taxation years, (ii) customer rebate adjustments in the 2001-2003 taxation years, and (iii) the Company's payment of approximately $6 million on January 2, 2001 associated with a settlement with New Brunswick Power regarding its $450 million write down of the Point Lepreau Nuclear Generating Station in 1998.

Maritime Electric believes it has reported its tax position appropriately in all aspects of the reassessment and filed a Notice of Objection with the Chief of Appeals at CRA. Should the Company be unsuccessful in defending all aspects of the reassessment, Maritime Electric would be required to pay approximately $11.7 million in taxes and accrued interest. Year to date June 30, 2006, the Company has provided for, through future and current income taxes payable, approximately $11.0 million and, therefore, an additional liability of $0.7 million would arise. In this event, the Company would apply to the Island Regulatory and Appeals Commission to include this amount in the regulatory rate-making process. The provisions of the Income Tax Act require the Company to deposit one half of the assessment under objection with CRA and the Company made a payment on deposit of $5.9 million with CRA on June 29, 2006.

(b) FortisAlberta

On March 24, 2006, Her Majesty the Queen in Right of Alberta filed a statement of claim in the Court of Queen's Bench of Alberta in the Judicial District of Edmonton against FortisAlberta. The Crown's claim is that the Company is responsible for a fire that occurred in October 2003 in an area of the Province of Alberta commonly referred to as "Poll Haven Community Pasture". The Crown is seeking approximately $2.7 million in fire fighting and suppression costs and approximately $2.4 million in timber losses, as well as interest and other costs. Given the preliminary stage of the proceedings, FortisAlberta has not made any definitive assessment of potential liability with respect to the litigation. However, management does not believe that the Company contributed to, or is responsible for, the fire and, therefore, management is of the view that the allegations are without merit.

(C) FortisBC

FortisBC has received correspondence and met with the B.C. Ministry of Forests (the "Ministry") to discuss the possibility of an invoice being issued to the Company for costs incurred by the Ministry in 2003 in relation to a forest fire near Vaseux Lake. The Ministry has alleged breaches of the Forest Practices Code and negligence and has filed and served a writ, on or about June 6, 2006, and statement of claim against FortisBC. FortisBC is currently communicating with the Ministry and its insurers. In addition, FortisBC has become aware of 2 writs and statements of claim filed, but not served, by private land owners in relation to the same matter. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

15. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period classifications.

CORPORATE INFORMATION

Fortis Inc. is primarily a diversified, international electric utility holding company with assets exceeding $4.3 billion and annual revenues of more than $1.4 billion. The Corporation holds investments in regulated electric utilities, non-regulated generation operations and a non-utility company with investments in real estate and hotels. The Common Shares, First Preference Shares Series C and First Preference Shares Series E of Fortis Inc. are traded on the Toronto Stock Exchange under the symbols FTS, FTS.PR.C, and FTS.PR.E, respectively. Fortis Inc. information can be accessed at www.fortisinc.com.



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
E: service@computershare.com


For the quarter ended June 30, 2006, Fortis Inc. will be filing the Certification of Interim Filings (Form 52-109F2) on SEDAR. Additional information including the Fortis 2005 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.
    Mr. Barry V. Perry
    Vice President Finance and Chief Financial Officer
    (709) 737-2800