Fortis Inc. Earns $55 Million in Second Quarter

08/04/2010 07:00 EST

View PDF

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved second quarter net earnings attributable to common equity shareholders of $55 million, or $0.32 per common share, up $2 million from $53 million, or $0.31 per common share, for the second quarter of 2009. Year-to-date net earnings attributable to common equity shareholders were $155 million, or $0.90 per common share, up $10 million from earnings of $145 million, or $0.85 per common share, for the same period last year.

Performance for the quarter was driven by the Terasen Gas companies and FortisBC, partially offset by higher corporate expenses.

The Terasen Gas companies contributed earnings of $17 million, up $3 million from the second quarter of 2009, mainly due to an increase in the allowed rate of return on common equity ("ROE") and an increase to the common equity component of total capital structure ("equity component") at Terasen Gas Inc. ("TGI"). Due to the seasonality of the business, earnings of the Terasen Gas companies are highest in the first and fourth quarters.

Canadian Regulated Electric Utilities contributed earnings of $40 million, up $1 million from the second quarter of 2009. The increase related to the higher contribution from FortisBC as a result of a higher allowed ROE and growth in electrical infrastructure investment, partially offset by lower electricity sales due to cooler weather experienced in June 2010. Earnings at FortisAlberta were comparable quarter over quarter. The impact of FortisAlberta's higher allowed ROE and equity component, compared to those reflected in earnings for the second quarter of 2009, combined with growth in electrical infrastructure investment and customers, was mainly offset by lower corporate income tax recoveries and lower net transmission revenue.

Caribbean Regulated Electric Utilities contributed $7 million to earnings, comparable to earnings for the second quarter of 2009. Excluding the approximate $1 million unfavourable impact of foreign exchange rates associated with the weakening of the US dollar quarter over quarter, earnings were approximately $1 million higher quarter over quarter. The increase was mainly associated with electricity sales growth, due to warmer weather, customer growth and improving tourism in the Turks and Caicos Islands, partially offset by higher business taxes at Belize Electricity and increased finance charges.

Non-Regulated Fortis Generation contributed $3 million to earnings, comparable to earnings for the second quarter of 2009. Excluding the approximate $1 million unfavourable impact of foreign exchange rates, earnings were approximately $1 million higher quarter over quarter. The increase in earnings was mainly attributable to higher hydroelectric production in Belize quarter over quarter, driven by the Vaca hydroelectric generating facility commissioned in March 2010, and lower finance charges.

Fortis Properties delivered earnings of $8 million, consistent with earnings for the second quarter of 2009.

Corporate and other expenses were $20 million compared to $18 million for the same quarter in 2009. The increase was mainly due to dividends associated with the First Preference Shares, Series H issued in January 2010 and higher business development costs, partially offset by higher interest income related to increased inter-company lending.

Proceeds from the $250 million five-year fixed rate reset preference shares issued in January 2010 were used to repay borrowings under the Corporation's committed credit facility and to fund an equity injection into TGI to repay borrowings under the Company's credit facilities.

In April, Terasen Inc. redeemed in full for cash its $125 million 8.0% Capital Securities.

Consolidated capital expenditures, before customer contributions, were approximately $432 million for the first half of 2010.

Cash flow from operating activities was $453 million year to date compared to $504 million for the same period last year. The decrease was driven by changes in working capital at the Terasen Gas companies, partially offset by higher earnings period over period.

As at June 30, 2010, Fortis had consolidated credit facilities of approximately $2.1 billion, of which $1.4 billion was unused, including $403 million unused under the Corporation's $600 million committed revolving credit facility. Approximately $2.0 billion of the total credit facilities are committed facilities, the majority of which currently have maturities between 2011 and 2013.

In April, FortisBC obtained an extension to the maturity of its $150 million unsecured committed credit facility with $100 million now maturing in May 2013 and $50 million now maturing in May 2011. In May, Terasen Gas (Vancouver Island) Inc. ("TGVI") entered into a two-year $300 million unsecured committed credit facility replacing its former $350 million credit facility due to mature in January 2011.

During the second quarter, Standard & Poor's and DBRS confirmed the Corporation's existing debt credit ratings at A-(stable) and BBB(high), respectively.

"Our subsidiaries are focused on completing their capital projects for 2010, estimated to exceed $1 billion," says Stan Marshall, President and Chief Executive Officer, Fortis Inc. "Much of this investment is occurring at our utilities in western Canada. The largest projects well underway include construction of the liquefied natural gas storage facility at TGVI, the installation of automated meters at FortisAlberta and the Okanagan Transmission Reinforcement Project at FortisBC," he explains.

"The priority of Fortis is to meet our obligation to serve customers," says Marshall. "We will continue to build our business profitably through ongoing investment in existing operations and the pursuit of strategic acquisitions of regulated electric and gas utilities in the United States, Canada and the Caribbean," concludes Marshall.

FORWARD-LOOKING STATEMENT

The following analysis should be read in conjunction with the Fortis Inc. ("Fortis" or the "Corporation") interim unaudited consolidated financial statements and notes thereto for the three and six months ended June 30, 2010 and the Management Discussion and Analysis ("MD&A") and audited consolidated financial statements for the year ended December 31, 2009 included in the Corporation's 2009 Annual Report. This material has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations relating to MD&As. Financial information in this release has been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") and is presented in Canadian dollars unless otherwise specified.

Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the "safe harbour" provisions of applicable Canadian securities legislation. The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs and is based on information currently available to the Corporation's management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the expected timing of the recording of the effects of the regulatory decision on FortisAlberta's 2010 and 2011 revenue requirements application; the expected decrease in the total costs of FortisAlberta's automated meter reading technology project; expected consolidated forecasted gross capital expenditures for 2010 and in total over the five-year period from 2010 through 2014; the expectation that the Corporation's significant capital program should drive growth in earnings and dividends; the expected increase in average annual energy production from the Macal River in Belize by the Vaca hydroelectric generating facility; expected consolidated long-term debt maturities and repayments on average annually over the next five years; the expectation of no material adverse credit rating actions in the near term; expected sources of financing for the subsidiaries' capital expenditure programs; the expectation that Fortis will elect to defer the adoption of IFRS until 2013; and except for debt at Belize Electricity and Exploits River Hydro Partnership ("Exploits Partnership"), the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2010.

The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major event; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no significant decline in capital spending in 2010; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the commodity cost of natural gas and energy supply costs in customer rates; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas commodity prices; no significant variability in interest rates; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas supply; the continued ability to fund defined benefit pension plans; the absence of significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; no material decrease in market energy sales prices; maintenance of information technology infrastructure; favourable relations with First Nations; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.

The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations include, but are not limited to: regulatory risk; operating and maintenance risks; economic conditions; capital resources and liquidity risk; weather and seasonality; commodity price risk; derivative financial instruments and hedging; interest rate risk; counterparty risk; competitiveness of natural gas; natural gas supply; defined benefit pension plan performance and funding requirements; risks related to the development of the Terasen Gas (Vancouver Island) Inc. franchise; the Government of British Columbia's Energy Plan; environmental risks; insurance coverage risk; loss of licences and permits; loss of service area; market energy sales prices; changes in the current assumptions and expectations associated with the transition to International Financial Reporting Standards; changes in tax legislation; information technology infrastructure; an ultimate resolution of the expropriation of the assets of the Exploits Partnership that differs from what is currently expected by management; an unexpected outcome of legal proceedings currently against the Corporation; relation with First Nations; labour relations; and human resources. For additional information with respect to the Corporation's risk factors, reference should be made to the Corporation's continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and to the heading "Business Risk Management" in the MD&A for the three and six months ended June 30, 2010 and for the year ended December 31, 2009.

All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.

COMPANY OVERVIEW AND FINANCIAL HIGHLIGHTS

Fortis is the largest investor-owned distribution utility in Canada, serving approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State, and hotels and commercial office and retail space primarily in Atlantic Canada. Year-to-date June 30, 2010, the Corporation's electricity distribution systems met a combined peak demand of approximately 5,033 megawatts ("MW") and its gas distribution system met a peak day demand of 1,006 terajoules. For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's 2009 annual audited consolidated financial statements.

The key goals of the Corporation's regulated utilities are to operate sound gas and electricity distribution systems, deliver gas and electricity safely and reliably to customers at the lowest reasonable cost and conduct business in an environmentally responsible manner. The Corporation's main business, utility operations, is highly regulated. It is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets.

Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. Key financial highlights, including earnings by reportable segment, for the second quarter and year-to-date periods ended June 30, 2010 and June 30, 2009 are provided in the following tables.

Financial Highlights (Unaudited)
Periods Ended June 30	Quarter				Year-to-date
	2010	2009	Variance		2010	2009	Variance
Revenue ($ millions)	836	756	80		1,912	1,958	(46	)
Cash Flow from Operating Activities ($ millions)	204	275	(71	)	453	504	(51	)
Net Earnings Attributable to Common Equity Shareholders ($ millions)	55	53	2		155	145	10
Basic Earnings per Common Share ($)	0.32	0.31	0.01		0.90	0.85	0.05
Diluted Earnings per Common Share ($)	0.32	0.31	0.01		0.88	0.83	0.05
Weighted Average Number of Common Shares Outstanding (millions)	172.4	170.0	2.4		172.0	169.7	2.3


Segmented Net Earnings Attributable to Common Equity Shareholders (Unaudited)
Periods Ended June 30		Quarter						Year-to-date
($ millions)		2010		2009		Variance		2010		2009		Variance
Regulated Gas Utilities - Canadian
	Terasen Gas Companies ⁽¹⁾	17		14		3		90		72		18
Regulated Electric Utilities – Canadian
	FortisAlberta	17		17		-		32		30		2
	FortisBC ⁽²⁾	8		7		1		22		21		1
	Newfoundland Power	11		11		-		18		17		1
	Other Canadian ⁽³⁾	4		4		-		9		9		-
		40		39		1		81		77		4
Regulated Electric - Caribbean ⁽⁴⁾		7		7		-		11		13		(2	)
Non-Regulated - Fortis Generation ⁽⁵⁾		3		3		-		5		9		(4	)
Non-Regulated - Fortis Properties ⁽⁶⁾		8		8		-		10		10		-
Corporate and Other ⁽⁷⁾		(20	)	(18	)	(2	)	(42	)	(36	)	(6	)
Net Earnings Attributable to Common Equity Shareholders		55		53		2		155		145		10

(1)Comprised of Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas (Whistler) Inc.("TGWI")

(2)Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants and the distribution system owned by the City of Kelowna. Excludes the non-regulated generation operations of FortisBC Inc.'s wholly owned partnership, Walden Power Partnership

(3)Includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and, from October 2009, Algoma Power Inc. ("Algoma Power")

(4)Includes Belize Electricity, in which Fortis holds an approximate 70 per cent controlling interest; Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 59 per cent controlling interest; and wholly owned Fortis Turks and Caicos

(5)Includes the financial results of non-regulated generating assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New York State, with a combined generating capacity of 139 megawatts ("MW"), mainly hydroelectric. Prior to May 1, 2009, the financial results of Fortis reflected earnings' contribution associated with the Corporation's 75-MW water-right entitlement on the Niagara River in Ontario related to the Rankine hydroelectric generating facility. The water rights expired on April 30, 2009, at the end of a 100-year term. Additionally, prior to February 12, 2009, the financial results of the hydroelectric generation operations in central Newfoundland were consolidated in the financial statements of Fortis. Effective February 12, 2009, the Corporation discontinued the consolidation method of accounting for the generation operations in central Newfoundland due to the Corporation no longer having control over the operations and cash flows, as a result of the expropriation of the assets of the Exploits River Hydro Partnership by the Government of Newfoundland and Labrador. For a further discussion of this matter, refer to the "Critical Accounting Estimates - Contingencies" section of the MD&A for the year ended December 31, 2009.

(6)Fortis Properties owns and operates 21 hotels, comprised of more than 4,100 rooms, in eight Canadian provinces and approximately 2.8 million square feet of commercial office and retail space primarily in Atlantic Canada.

(7)Includes Fortis net corporate expenses, net expenses of non-regulated Terasen Inc. ("Terasen") corporate-related activities and the financial results of Terasen's 30 per cent ownership interest in CustomerWorks Limited Partnership ("CWLP") and of Terasen's non-regulated wholly owned subsidiary Terasen Energy Services Inc. ("TES")

SEGMENTED RESULTS OF OPERATIONS

REGULATED GAS UTILITIES - CANADIAN

TERASEN GAS COMPANIES

Gas Volumes by Major Customer Category (Unaudited)
Periods Ended June 30		Quarter				Year-to-date
(Terajoules)		2010	2009	Variance		2010	2009	Variance
Core – Residential and Commercial		23,827	20,075	3,752		64,258	70,487	(6,229	)
Industrial		1,193	1,307	(114	)	2,868	3,617	(749	)
	Total Sales Volumes	25,020	21,382	3,638		67,126	74,104	(6,978	)
Transportation Volumes		14,170	12,485	1,685		30,580	32,734	(2,154	)
Throughput under Fixed Revenue Contracts		3,458	2,584	874		8,126	7,583	543
Total Gas Volumes		42,648	36,451	6,197		105,832	114,421	(8,589	)

Factors Contributing to Net Positive Quarterly

Gas Volumes Variance

Favourable

Higher average consumption by residential and commercial customers as a result of cooler weather
Higher transportation volumes as a result of cooler weather and the favourable impact of improving economic conditions in the second quarter of 2010 on the forestry sector

Factors Contributing to Net Negative Year-to-Date

Gas Volumes Variance

Unfavourable

Lower average consumption by residential and commercial customers as a result of warmer weather during the first quarter of 2010, partially offset by the impact of cooler weather during the second quarter of 2010
Lower transportation volumes as a result of warmer weather during the first quarter of 2010, partially offset by the impact of cooler weather during the second quarter of 2010 and the impact of unfavourable economic conditions negatively affecting the forestry sector year-to-date

Net customer additions were 1,829 during the first half of 2010 compared to 1,068 during the first half of 2009. Gross customer additions increased period over period due to increased building activity, while customer disconnections were lower period over period due to cooler weather. Growth in multi-family housing, however, where natural gas use is less prevalent compared to single-family housing, has tempered customer growth period over period.

Because of natural gas consumption patterns, earnings of the Terasen Gas companies are highest in the first and fourth quarters. As a result of seasonality, interim earnings are not indicative of annual earnings.

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

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

Financial Highlights (Unaudited)
Periods Ended June 30	Quarter			Year-to-date
($ millions)	2010	2009	Variance	2010	2009	Variance
Revenue	337	289	48	866	958	(92	)
Energy Supply Costs	191	156	35	496	624	(128	)
Operating Expenses	65	62	3	135	129	6
Amortization	29	26	3	59	51	8
Finance Charges	29	29	-	56	61	(5	)
Corporate Taxes	6	2	4	30	21	9
Earnings	17	14	3	90	72	18

Factors Contributing to Positive Quarterly Revenue Variance

Favourable

Higher average gas consumption per customer
Higher commodity cost of natural gas charged to customers
Increased customer delivery rates, effective January 1, 2010, which included the impact of the increase in the allowed rate of return on common shareholder's equity ("ROE") to 9.50 per cent from 8.47 per cent for Terasen Gas Inc. ("TGI") and to 10.00 per cent from 9.17 per cent for Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas Whistler Inc. ("TGWI"), and the increase in the deemed common equity component of the total capital structure ("equity component") for TGI to 40 per cent from 35 per cent

Factors Contributing to Net Negative Year-to-Date Revenue Variance

Unfavourable

Lower average gas consumption per customer
Lower commodity cost of natural gas charged to customers

Favourable

The increase in customer delivery rates, effective January 1, 2010, as discussed above for the quarter

Factors Contributing to Net Positive Quarterly Earnings Variance

Favourable

The increase in customer delivery rates, effective January 1, 2010, as discussed above

Unfavourable

Higher operating expenses driven by: (i) increased labour and employee-benefit costs; (ii) the expensing of asset removal costs to operating expenses, effective January 1, 2010, as a result of regulator-approved Negotiated Settlement Agreements ("NSAs") related to 2010 and 2011 revenue requirements; and (iii) lower capitalized overhead costs, due to a reduction in the capitalization rate, also as a result of the NSAs. The asset removal costs and expensed overhead costs are being collected in current customer delivery rates. Prior to 2010, asset removal costs were recorded against accumulated amortization.
Increased amortization cost due to higher amortization rates period over period and the amortization of contributions in aid of construction ("CIACs") to revenue, beginning January 1, 2010, compared to the amortization of CIACs against amortization cost in prior periods, as a result of the NSAs. The new depreciation rates were determined and approved by the regulator upon review of a current depreciation study. The increase in amortization is being collected in current customer delivery rates.
A lower effective corporate income tax rate in 2009, primarily due to higher deductions taken for tax purposes compared to accounting purposes

Factors Contributing to Net Positive Year-to-Date Earnings Variance

Favourable

The increase in customer delivery rates, effective January 1, 2010, as discussed above
Lower finance charges, as reflected in current customer delivery rates, due to lower average credit facility borrowings period over period

Unfavourable

The same factors as discussed above for the quarter

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

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

Financial Highlights (Unaudited)
Periods Ended June 30	Quarter					Year-to-date
	2010	2009		Variance		2010	2009		Variance
Energy Deliveries (gigawatt hours ("GWh"))	3,724	3,765		(41	)	7,833	7,917		(84	)
($ millions)
Revenue	92	81		11		180	161		19
Operating Expenses	36	31		5		71	65		6
Amortization	25	23		2		49	45		4
Finance Charges	14	13		1		28	24		4
Corporate Tax Recovery	-	(3	)	3		-	(3	)	3
Earnings	17	17		-		32	30		2

Factors Contributing to Net Negative Quarterly

Energy Deliveries Variance

Unfavourable

Decreased energy deliveries to residential, farm and irrigation customers, mainly due to lower average consumption resulting from relatively milder temperatures, were partially offset by increased energy deliveries to commercial and other industrial customers. Energy deliveries to irrigation customers were also negatively impacted by heavy rainfall during the second quarter of 2010.

Favourable

Customer growth with the total number of customers increasing by approximately 20,000 quarter over quarter

Factors Contributing to Net Negative Year-to-Date

Energy Deliveries Variance

Unfavourable

Decreased energy deliveries to residential, farm and irrigation, and other industrial customers, due to the same reasons as discussed above for the quarter, were partially offset by increased energy deliveries to commercial and oil and gas customers.

Favourable

Customer growth as discussed above for the quarter

As a significant portion of FortisAlberta's distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue.

Factors Contributing to Net Positive Quarterly and Year-to-Date

Revenue Variance

Favourable

An interim 7.5 per cent average increase in base customer electricity distribution rates, effective January 1, 2010, combined with a rate revenue accrual for the second quarter and first half of 2010 for future collection from customers relating to certain approved deferral account items. Approval of FortisAlberta's 2010 and 2011 revenue requirements was received in July 2010, the effects of which are expected to be reflected in the third quarter of 2010.
A rate revenue accrual of approximately $1 million and $2 million for the second quarter and first half of 2010, respectively, to reflect an allowed ROE of 9.00 per cent, compared to an interim allowed ROE of 8.51 per cent as reflected in revenue during the first half of 2009, and an increase in the equity component to 41 per cent from 37 per cent as reflected in revenue during the first half of 2009
Customer growth
Higher franchise fee revenue
Higher miscellaneous revenue for the quarter

Unfavourable

Lower net transmission revenue

Factors Contributing to Net Positive Quarterly and Year-to-date

Earnings Variance

Favourable

The increase in customer electricity distribution rate revenue, for the reasons discussed above

Unfavourable

Increased operating expenses, mainly due to higher labour costs and general operating expenses, partially offset by lower contracted labour costs
Increased amortization cost associated with continued investment in utility capital assets, partially offset by the impact of the commencement in 2010 of the capitalization of amortization for vehicles and tools used in the construction of other assets, as approved by the regulator
Increased finance charges, due to higher debt levels in support of the Company's significant capital expenditure program, partially offset by the impact of lower interest rates on lower average credit facility borrowings
Lower net transmission revenue
Lower corporate tax recovery, due to a favourable adjustment to current income taxes of approximately $2 million during the second quarter of last year, combined with lower future income tax recoveries associated with changes in net customer deferrals subject to future income tax recoveries

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

FORTISBC

Financial Highlights (Unaudited)
Periods Ended June 30	Quarter				Year-to-date
	2010	2009	Variance		2010	2009	Variance
Electricity Sales (GWh)	670	675	(5	)	1,490	1,578	(88	)
($ millions)
Revenue	59	55	4		131	127	4
Energy Supply Costs	13	13	-		34	35	(1	)
Operating Expenses	19	17	2		36	34	2
Amortization	11	9	2		21	19	2
Finance Charges	8	8	-		16	15	1
Corporate Taxes	-	1	(1	)	2	3	(1	)
Earnings	8	7	1		22	21	1

Factors Contributing to Net Negative Quarterly

Electricity Sales Variance

Unfavourable

Lower average consumption due to cooler temperatures in June 2010 which decreased air-conditioning load

Favourable

Residential and general service customer growth
Increased industrial customer loads

Factors Contributing to Net Negative Year-to-Date

Electricity Sales Variance

Unfavourable

The same factor as discussed above for the quarter, combined with lower average consumption in the first quarter of 2010, due to warmer temperatures experienced during the first quarter of 2010 compared to cooler temperatures experienced during the first quarter of 2009

Favourable

The same factors as discussed above for the quarter

Factors Contributing to Net Positive Quarterly and Year-to-Date

Revenue Variance

Favourable

A 6.0 per cent increase in customer electricity rates, effective January 1, 2010, reflecting an increase in the allowed ROE to 9.90 per cent for 2010, up from 8.87 per cent for 2009, and ongoing investment in electrical infrastructure
Increased performance-based rate-setting ("PBR") incentive adjustments receivable from customers and higher pole-attachment revenue
Higher revenue contribution from non-regulated operating, maintenance and management services

Unfavourable

The 0.7 per cent and 5.6 per cent decrease in electricity sales for the quarter and year-to-date, respectively, compared to the same periods last year.

Factors Contributing to Net Positive Quarterly Earnings Variance

Favourable

The 6.0 per cent increase in customer electricity rates, effective January 1, 2010
Increased PBR incentive adjustments and pole-attachment revenue, as discussed above

Unfavourable

Higher operating expenses, due to the timing of operating and maintenance projects in 2010 and their related expenditures, combined with increased property taxes and water fees
Increased amortization cost associated with continued investment in utility capital assets
Decreased electricity sales

Factors Contributing to Net Positive Year-to-Date Earnings Variance

Favourable

The same factors as discussed above for the quarter
Lower energy supply costs associated with decreased electricity sales and a lower proportion of purchased power versus energy generated from Company-owned hydroelectric generating facilities, partially offset by the impact of higher average prices for purchased power

Unfavourable

Increased property taxes and water fees, partially offset by a decrease in certain other operating expenses due to the timing of operating and maintenance projects in 2010 and their related expenditures
Increased amortization cost, for the same reason as discussed above for the quarter
Higher finance charges, due to higher debt levels in support of the Company's capital expenditure program, and higher fees and interest rates on credit facility borrowings
Decreased electricity sales

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

NEWFOUNDLAND POWER

Financial Highlights (Unaudited)
Periods Ended June 30	Quarter				Year-to-date
	2010	2009	Variance		2010	2009	Variance
Electricity Sales (GWh)	1,220	1,177	43		3,015	2,940	75
($ millions)
Revenue	126	119	7		304	288	16
Energy Supply Costs	75	70	5		206	197	9
Operating Expenses	15	13	2		31	27	4
Amortization	12	11	1		23	22	1
Finance Charges	9	9	-		18	17	1
Corporate Taxes	4	5	(1	)	8	8	-
Earnings	11	11	-		18	17	1

Factors Contributing to Positive Quarterly and Year-to-Date

Electricity Sales Variance

Favourable

Customer growth and higher average consumption

Factors Contributing to Net Positive Quarterly and Year-to-Date

Revenue Variance

Favourable

An average 3.5 per cent increase in customer electricity rates, effective January 1, 2010, reflecting an increase in the allowed ROE to 9.00 per cent for 2010, up from 8.95 per cent for 2009, and higher rate base and operating expenses, including pension costs
A 3.7 per cent and 2.6 per cent increase in electricity sales for the quarter and year to date, respectively, compared to the same periods last year

Unfavourable

Revenue during the second quarter of 2009 included a gain on sale of property

Factors Contributing to Net Positive Quarterly and Year-to-Date

Earnings Variance

Favourable

The average 3.5 per cent increase in customer electricity rates, effective January 1, 2010
Increased electricity sales
Lower than expected operating labour costs due to the timing of capital projects. Good weather conditions during the first half of 2010 allowed for an early start to capital projects and there was also an increase in capital work associated with an ice storm in March 2010.
A lower effective corporate income tax rate primarily due to a reduction in the statutory tax rate and an increase in deductions taken for tax purposes compared to accounting purposes

Unfavourable

Higher pension costs, wage and inflationary cost increases and increased conservation costs
Higher retirement and severance expenses year to date
Increased amortization cost associated with continued investment in utility capital assets
Higher finance charges year to date associated with interest expense on the $65 million 6.606% bonds issued in May 2009, partially offset by the impact of lower average credit facility borrowings
The gain on sale of property during the second quarter of 2009

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

OTHER CANADIAN ELECTRIC UTILITIES

Financial Highlights (Unaudited)⁽¹⁾
Periods Ended June 30	Quarter			Year-to-date
	2010	2009	Variance	2010	2009	Variance
Electricity Sales (GWh)	535	483	52	1,167	1,099	68
($ millions)
Revenue	75	65	10	157	136	21
Energy Supply Costs	46	40	6	99	87	12
Operating Expenses	11	9	2	22	17	5
Amortization	6	5	1	11	9	2
Finance Charges	5	4	1	11	9	2
Corporate Taxes	3	3	-	5	5	-
Earnings	4	4	-	9	9	-

⁽¹⁾Includes Maritime Electric and FortisOntario. FortisOntario includes financial results of Algoma Power from October 8, 2009, the date of acquisition.

Factors Contributing to Positive Quarterly

Electricity Sales Variance

Favourable

Electricity sales at Algoma Power Inc. ("Algoma Power") of 38 gigawatt hours ("GWh") during the second quarter of 2010. Algoma Power was acquired by FortisOntario in October 2009. Excluding electricity sales at Algoma Power, electricity sales increased 2.9 per cent quarter over quarter
Higher average consumption due to warmer weather conditions experienced in Ontario

Factors Contributing to Net Positive Year-to-date

Electricity Sales Variance

Favourable

Electricity sales at Algoma Power of 92 GWh during the first half of 2010. Excluding electricity sales at Algoma Power, electricity sales decreased 2.2 per cent period over period

Unfavourable

Lower average consumption, due to more moderate temperatures experienced on Prince Edward Island and in Ontario during the first quarter of 2010, combined with the impact of conservation initiatives and the economic downturn, partially offset by higher average consumption in Ontario during the second quarter of 2010 for the reason discussed above for the quarter.

Factors Contributing to Positive Quarterly Revenue Variance

Favourable

Revenue contribution of approximately $9 million from Algoma Power during the second quarter of 2010
The 2.9 per cent increase in electricity sales, excluding electricity sales at Algoma Power

Factors Contributing to Net Positive Year-to-Date Revenue Variance

Favourable

Revenue contribution of approximately $19 million from Algoma Power during the first half of 2010
The flow through in customer electricity rates of higher energy supply costs at FortisOntario
An average 5.3 per cent increase in customer electricity rates at Maritime Electric, effective April 1, 2009, which reflects an increase in the base amount of energy-related costs being expensed and collected from customers and recorded in revenue through the basic rate component of customer billings
The increases in the base component of customer electricity distribution rates at Fort Erie, Gananoque and Port Colborne in Ontario effective May 1, 2009 and May 1, 2010

Unfavourable

The 2.2 per cent decrease in electricity sales, excluding electricity sales at Algoma Power

Factors Contributing to Quarterly and Year-to-Date Earnings Variance

Favourable

Algoma Power contributed less than $0.1 million to earnings for the second quarter of 2010 and approximately $0.5 million to earnings for the first half of 2010.

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

REGULATED ELECTRIC UTILITIES - CARIBBEAN

Financial Highlights (Unaudited)⁽¹⁾
Periods Ended June 30	Quarter				Year-to-date
	2010	2009	Variance		2010	2009	Variance
Average US:CDN Exchange Rate ⁽²⁾	1.03	1.17	(0.14	)	1.03	1.20	(0.17	)
Electricity Sales (GWh)	307	290	17		563	537	26
($ millions)
Revenue	83	82	1		159	165	(6	)
Energy Supply Costs	47	44	3		92	90	2
Operating Expenses	11	14	(3	)	23	28	(5	)
Amortization	9	10	(1	)	18	20	(2	)
Finance Charges	4	4	-		9	8	1
Corporate Taxes	2	-	2		2	1	1
	10	10	-		15	18	(3	)
Non-Controlling Interests	3	3	-		4	5	(1	)
Earnings	7	7	-		11	13	(2	)

⁽¹⁾Includes Belize Electricity, Caribbean Utilities and Fortis Turks and Caicos

⁽²⁾The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00. The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar.

Factors Contributing to Positive Quarterly and Year-to-Date

Electricity Sales Variance

Favourable

Warmer weather conditions experienced in the region, which increased air-conditioning load
Overall customer growth for the segment, including a new system-connected medical facility and condominium complex in the Turks and Caicos Islands
Improving tourism activity in the Turks and Caicos Islands which is favourably impacting large hotel electricity sales
In June 2010, Caribbean Utilities and Fortis Turks and Caicos achieved new record peak loads of 102 MW and 30 MW, respectively

Factors Contributing to Net Positive Quarterly Revenue Variance

Favourable

The flow through in customer electricity rates of higher energy supply costs at Caribbean Utilities, due to an increase in the cost of fuel
A 5.9 per cent increase in electricity sales
A 2.4 per cent increase in basic customer electricity rates at Caribbean Utilities, effective June 1, 2009

Unfavourable

Approximately $9 million unfavourable foreign exchange associated with the translation of foreign currency-denominated revenue, due to the weakening of the US dollar relative to the Canadian dollar period over period

Factors Contributing to Net Negative Year-to-Date Revenue Variance

Unfavourable

Approximately $24 million associated with unfavourable foreign currency translation
Revenue during the first quarter of 2009 included approximately $1 million associated with a favourable appeal judgment at Fortis Turks and Caicos related to a customer rate classification matter.

Favourable

The flow through in customer electricity rates of higher energy supply costs at Caribbean Utilities, for the reason discussed above for the quarter
The 2.4 per cent increase in basic customer electricity rates at Caribbean Utilities, effective June 1, 2009
A 4.8 per cent increase in electricity sales

Factors Contributing to Quarterly Earnings Variance

Favourable

Increased electricity sales
The 2.4 per cent increase in basic customer electricity rates at Caribbean Utilities, effective June 1, 2009

Unfavourable

Approximately $1 million associated with unfavourable foreign currency translation
Higher corporate tax expense at Belize Electricity, due to an increase in the business tax rate to 6.5 per cent from 1.75 per cent, effective April 1, 2010
Higher finance charges, excluding the impact of foreign exchange, mainly associated with interest expense on the US$40 million 7.5% unsecured notes issued in May and July 2009 at Caribbean Utilities, and lower capitalized allowance for funds using during construction

Factors Contributing to Net Negative Year-to-Date Earnings Variance

Unfavourable

Approximately $2 million associated with unfavourable foreign currency translation
Higher corporate tax expense at Belize Electricity, for the reason discussed above for the quarter
Higher finance charges, for the reasons discussed above for the quarter, combined with higher interest expense on regulatory liabilities at Belize Electricity
The favourable impact on energy supply costs during the first quarter of 2009, due to a change in the methodology for calculating the cost of fuel recoverable from customers at Fortis Turks and Caicos
Revenue during the first quarter of 2009 included approximately $1 million associated with the favourable appeal judgment at Fortis Turks and Caicos.

Favourable

Increased electricity sales
The 2.4 per cent increase in basic customer electricity rates at Caribbean Utilities, effective June 1, 2009
Lower operating expenses, excluding the impact of foreign exchange, due to higher capitalized general and administrative expenses and efforts to control discretionary costs at Caribbean Utilities, partially offset by increased legal, employee and contractor costs at Belize Electricity

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

NON-REGULATED - FORTIS GENERATION

Financial Highlights (Unaudited)⁽¹⁾
Periods Ended June 30	Quarter					Year-to-date
	2010	2009⁽²	⁾	Variance		2010	2009⁽²	⁾	Variance
Energy Sales (GWh)	90	141		(51	)	154	398		(244	)
($ millions)
Revenue	8	9		(1	)	13	25		(12	)
Energy Supply Costs	1	1		-		1	2		(1	)
Operating Expenses	2	2		-		4	6		(2	)
Amortization	1	2		(1	)	2	4		(2	)
Finance Charges	-	1		(1	)	-	2		(2	)
Corporate Taxes	1	-		1		1	2		(1	)
Earnings	3	3		-		5	9		(4	)

⁽¹⁾Includes the results of non-regulated generating assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New York State

⁽²⁾Results reflect contribution from the Rankine hydroelectric generating facility in Ontario until April 30, 2009. On April 30, 2009, the Rankine water rights expired at the end of a 100-year term.

Factors Contributing to Net Negative Quarterly and Year-to-Date

Energy Sales Variance

Unfavourable

The expiration on April 30, 2009 of the water rights of the Rankine hydroelectric generating facility in Ontario. Energy sales for the second quarter and first half of 2009 included approximately 54 GWh and 215 GWh, respectively, related to Rankine.
Lower production in Upper New York State due to lower rainfall
Lower energy sales year to date related to central Newfoundland operations. Energy sales for the first quarter of 2009 included 19 GWh related to central Newfoundland operations up until February 12, 2009, at which point the consolidation method of accounting for these operations was discontinued necessitated by the actions of the Government of Newfoundland and Labrador related to expropriation of the assets of the Exploits River Hydro Partnership (the "Exploits Partnership").

Favourable

The new Vaca hydroelectric generating facility was commissioned in March 2010. The facility is expected to increase average annual energy production from the Macal River in Belize by approximately 80 GWh. Production by the facility was 16 GWh and 20 GWh for the second quarter and first half of 2010, respectively. Production in Belize, however, was tempered by the impact of low rainfall earlier in 2010.

Factors Contributing to Net Negative Quarterly and Year-to-Date

Revenue Variance

Unfavourable

The loss of revenue subsequent to the expiration of the Rankine water rights in April 2009
The discontinuance of the consolidation method of accounting for the financial results of the Exploits Partnership in 2009 and timing differences related to the change in the method of accounting for the Exploits Partnership
Approximately $1 million and $2 million unfavourable foreign exchange for the quarter and year to date period, respectively, associated with the translation of US dollar-denominated revenue, due to the weakening of the US dollar relative to the Canadian dollar compared to the same periods last year

Favourable

Higher production in Belize, for the reason discussed above for the quarter

Factors Contributing to Net Negative Quarterly and Year-to-Date

Earnings Variance

Unfavourable

The expiration of the Rankine water rights. Earnings' contribution associated with the Rankine hydroelectric generating facility was approximately $0.2 million for the second quarter of 2009 and $3.5 million for the first half of 2009.
Approximately $1 million for each of the quarter and year to date period associated with unfavourable foreign currency translation
Timing differences related to the change in the method of accounting for the Exploits Partnership in 2009

Favourable

Higher production in Belize
Reduced finance charges, excluding the impact of foreign exchange, as a result of higher interest revenue associated with inter-company lending to regulated operations in Ontario, partially offset by higher interest expense associated with inter-company lending to finance the construction of the Vaca hydroelectric generating facility. Coincident with the commissioning of the facility in March 2010, capitalization of interest expense during construction ended.

NON-REGULATED - FORTIS PROPERTIES

Financial Highlights (Unaudited)
Periods Ended June 30	Quarter			Year-to-date
($ millions)	2010	2009	Variance	2010	2009	Variance
Hospitality Revenue	44	42	2	76	73	3
Real Estate Revenue	16	16	-	33	32	1
Total Revenue	60	58	2	109	105	4
Operating Expenses	39	38	1	75	72	3
Amortization	4	4	-	8	8	-
Finance Charges	6	5	1	12	11	1
Corporate Taxes	3	3	-	4	4	-
Earnings	8	8	-	10	10	-

Factors Contributing to Net Positive Quarterly Revenue Variance

Favourable

Overall higher revenue contribution from hotel properties in Atlantic and central Canada, partially offset by overall lower revenue contribution from hotel properties in western Canada
Revenue growth at the Newfoundland and Nova Scotia regions of the Real Estate Division, mainly due to rent increases and higher operating expense recoveries, tempered by revenue decreases in New Brunswick and Saskatchewan
A 0.8 per cent increase in revenue per available room ("RevPAR") at the Hospitality Division to $83.77 for the second quarter of 2010 from $83.15 for the same quarter in 2009. RevPAR increased due to an overall 2.6 per cent increase in average room rates, partially offset by an overall 1.8 per cent decrease in hotel occupancy, mainly at operations in western Canada. Average room rates at operations in western and Atlantic Canada increased, while rates at operations in central Canada decreased.

Unfavourable

A decrease in the occupancy rate at the Real Estate Division to 94.8 per cent as at June 30, 2010 from 95.9 per cent as at June 30, 2009

Factors Contributing to Net Positive Year-to-Date Revenue Variance

Favourable

Revenue contribution from the Holiday Inn Select Windsor, acquired in April 2009, combined with overall higher revenue contribution from hotel properties in Atlantic and central Canada, partially offset by overall lower revenue contribution from hotel properties in western Canada
Revenue growth at the Newfoundland and Nova Scotia regions of the Real Estate Division, mainly due to rent increases and higher operating expense recoveries
A $0.2 million gain on sale of land in central Newfoundland during the first quarter of 2010

Unfavourable

A 0.8 per cent decrease in RevPAR at the Hospitality Division to $73.45 for the first half of 2010 from $74.03 for the first half of 2009. RevPAR decreased due to an overall 3.0 per cent decrease in hotel occupancy, mainly at operations in western Canada, partially offset by an overall 2.3 per cent increase in average room rates. Average room rates at operations in western and Atlantic Canada increased, while rates at operations in central Canada decreased.

Factors Contributing to Quarterly Earnings Variance

Improved performance at the Real Estate Division and improved performance from hotel operations in Atlantic and central Canada were mostly offset by the unfavourable impact of lower occupancies at hotel operations in western Canada, driven by the continued impact of the economic downturn.

Factors Contributing to Year-to-Date Earnings Variance

The same factors as discussed above for the quarter, combined with contribution from the Holiday Inn Select Windsor from April 2009

CORPORATE AND OTHER

Financial Highlights (Unaudited)⁽¹⁾
Periods Ended June 30	Quarter						Year-to-date
($ millions)	2010		2009		Variance		2010		2009		Variance
Revenue	9		7		2		15		13		2
Operating Expenses	6		4		2		10		7		3
Amortization	1		2		(1	)	4		5		(1	)
Finance Charges ⁽²⁾	18		18		-		38		37		1
Corporate Tax Recovery	(4	)	(4	)	-		(9	)	(9	)	-
	(12	)	(13	)	1		(28	)	(27	)	(1	)
Preference Share Dividends	8		5		3		14		9		5
Net Corporate and Other Expenses	(20	)	(18	)	(2	)	(42	)	(36	)	(6	)

⁽¹⁾ Includes Fortis net corporate expenses, net expenses of non-regulated Terasen corporate-related activities and the financial results of Terasen's 30 per cent ownership interest in CWLP and of Terasen's non-regulated wholly owned subsidiary TES

⁽²⁾Includes dividends on preference shares classified as long-term liabilities

Factors Contributing to Net Negative Quarterly and Year-to-Date

Net Corporate and Other Expenses Variance

Unfavourable

Higher preference share dividends, due to the issuance of First Preference Shares, Series H in January 2010. For additional information, see the "Liquidity and Capital Resources" section of this MD&A.
Higher operating expenses primarily due to higher business development costs, partially offset by higher recovery of costs from subsidiary companies
Higher finance charges, excluding the impact of foreign exchange, driven by interest expense on the 30-year $200 million 6.51% unsecured debentures issued in July 2009 and higher average credit facility borrowings, partially offset by lower interest rates charged on those credit facility borrowings and the repayment of higher interest-bearing debt. In April 2010, Terasen redeemed its $125 million 8.0% Capital Securities with proceeds from borrowings under the Corporation's committed credit facility.

Favourable

Increased revenue due to interest income on higher inter-company lending to Fortis Properties to finance maturing debt
A favourable foreign exchange impact of approximately $1 million and $2 million for the quarter and year to date, respectively, associated with the translation of US dollar-denominated interest expense, due to the weakening of the US dollar relative to the Canadian dollar compared to the same periods last year

REGULATORY HIGHLIGHTS

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

Nature of Regulation
			Allowed Returns (%)			Supportive Features
Regulated Utility	Regulatory Authority	Allowed Common Equity (%)	2008	2009	2010	Future or Historical Test Year Used to Set Customer Rates
				ROE
TGI	British Columbia Utilities Commission ("BCUC")	40 ⁽¹⁾	8.62	8.47 ⁽²⁾/ 9.50 ⁽³⁾	9.50	Cost of Service ("COS")/ROE TGI: Prior to January 1, 2010, 50/50 sharing of earnings above or below the allowed ROE under a PBR mechanism that expired on December 31, 2009

TGVI	BCUC	40	9.32	9.17 ⁽²⁾/ 10.00 ⁽³⁾	10.00	ROEs established by the BCUC, effective July 1, 2009, as a result of a cost of capital decision in the fourth quarter of 2009. Previously, the allowed ROEs were set using an automatic adjustment formula tied to long-term Canada bond yields.
						Future Test Year
FortisBC	BCUC	40	9.02	8.87	9.90	COS/ROE PBR mechanism for 2009 through 2011: 50/50 sharing of earnings above or below the allowed ROE up to an achieved ROE that is 200 basis points above or below the allowed ROE – excess to deferral account ROE established by the BCUC, effective January 1, 2010, as a result of a cost of capital decision in 2009. Previously, the allowed ROE was set using an automatic adjustment formula tied to long-term Canada bond yields.
						Future Test Year
Fortis Alberta	Alberta Utilities Commission ("AUC")	41 ⁽⁴⁾	8.75	9.00	9.00	COS/ROE ROE established by the AUC, effective January 1, 2009, as a result of a generic cost of capital decision in the fourth quarter of 2009. Previously, the allowed ROE was set using an automatic adjustment formula tied to long-term Canada bond yields.
						Future Test Year
Newfoundland Power	Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB")	45	8.95 +/- 50 bps	8.95 +/- 50 bps	9.00 +/- 50 bps	COS/ROE ROE for 2010 established by the PUB. Except for 2010, the allowed ROE is set using an automatic adjustment formula tied to long-term Canada bond yields.
						Future Test Year
Maritime Electric	Island Regulatory and Appeals Commission ("IRAC")	40	10.00	9.75	9.75	COS/ROE
						Future Test Year
FortisOntario	Ontario Energy Board ("OEB") Canadian Niagara Power	40 ⁽⁵⁾	9.00	8.01	8.01	Canadian Niagara Power - COS/ROE

	Algoma Power Franchise Agreement Cornwall Electric	50	N/A	8.57	8.57/ 9.85⁽⁶⁾	Algoma Power – COS/ROE and subject to Rural Rate Protection Subsidy program Cornwall Electric - Price cap with commodity cost flow through
						Canadian Niagara Power – 2004 historical test year for 2008; 2009 test year for 2009 and 2010 Algoma Power – 2007 historical test year for 2009; 2010 test year for 2010
				ROA ⁽⁷⁾
Belize Electricity	Public Utilities Commission ("PUC")	N/A	^10.00	^10.00	^{- (8)}	Four-year COS/ ROA agreements Additional costs in the event of a hurricane would be deferred and the Company may apply for future recovery in customer rates.
						Future Test Year
Caribbean Utilities	Electricity Regulatory Authority ("ERA")	N/A	9.00 - 11.00	9.00 -11.00	7.75 – 9.75	COS/ROA Rate-cap adjustment mechanism ("RCAM") based on published consumer price indices Under the new transmission and distribution licence, the Company may apply for a special additional rate to customers in the event of a disaster, including a hurricane.
						Historical Test Year
Fortis Turks and Caicos	Utilities make annual filings with the Government	N/A	17.50 ⁽⁹⁾	17.50 ⁽⁹⁾	17.50 ⁽⁹⁾	COS/ROA If the actual ROA is lower than the allowed ROA, due to additional costs resulting from a hurricane or other event, the Company may apply for an increase in customer rates in the following year.
						Future Test Year

⁽¹⁾Effective January 1, 2010. For 2008 and 2009, the allowed deemed equity component of the capital structure was 35 per cent.

⁽²⁾Pre-July 1, 2009

⁽³⁾Effective July 1, 2009

⁽⁴⁾Effective January 1, 2009. For 2008, the allowed deemed equity component of the capital structure was 37 per cent.

⁽⁵⁾Effective May 1, 2010. For 2009, effective May 1, the allowed deemed equity component of the capital structure was 43.3 per cent.

⁽⁶⁾Proposed at 9.85 per cent effective July 1, 2010, subject to regulatory approval

⁽⁷⁾Rate of return on rate base assets

⁽⁸⁾Allowed ROA to be settled once regulatory matters are resolved

⁽⁹⁾Amount provided under licence. Actual ROAs achieved in 2008 and 2009 were materially lower than the ROA allowed under the licence due to significant investment occurring at the utility.

Material Regulatory Decisions and Applications
Regulated Utility	Summary Description
TGI/TGVI	- TGI and TGVI review with the BCUC natural gas and propane commodity rates every three months and mid-stream rates annually in order to ensure the flow through rates charged to customers are sufficient to cover the cost of purchasing natural gas and propane and contracting for mid-stream resources, such as third-party pipeline or storage capacity. The commodity cost of natural gas and mid-stream costs are flowed through to customers without markup. Effective January 1, 2010, the BCUC approved an increase in mid-stream rates for natural gas and kept commodity rates for natural gas unchanged for customers in the Lower Mainland, Fraser Valley, Interior, North and the Kootenay service areas. The BCUC also approved a decrease in commodity rates for natural gas for customers in Whistler, effective January 1, 2010. Effective April 1, 2010, the BCUC approved an increase in commodity rates for natural gas for customers in the Lower Mainland, Fraser Valley, Interior, North and the Kootenay service areas, while rates for natural gas customers on Vancouver Island and in Whistler and Fort Nelson remained unchanged. Effective July 1, 2010, the BCUC approved decreases in commodity rates for natural gas and propane customers in the Lower Mainland, Fraser Valley, Interior, North and the Kootenay service areas while rates for natural gas customers on Vancouver Island and in Whistler and Fort Nelson remain unchanged.
	- In November and December 2009, the BCUC approved: (i) NSAs pertaining to the 2010 and 2011 Revenue Requirements Applications for TGI and TGVI; (ii) an increase in TGI's equity component, effective January 1, 2010, to 40 per cent from 35 per cent; (iii) an increase in TGI's allowed ROE, effective July 1, 2009, to 9.50 per cent from 8.47 per cent; and (iv) an increase in the allowed ROE to 10.00 per cent, effective July 1, 2009, from 9.17 per cent for each of TGVI and TGWI. In its decision on the Return on Equity and Capital Structure Application, the BCUC maintained TGI as a benchmark utility for calculating the allowed ROE for certain utilities regulated by the BCUC. The BCUC also determined that the former automatic adjustment formula used to establish the ROE annually will no longer apply and the allowed ROEs as determined in the BCUC decision will apply until reviewed further by the BCUC. The BCUC-approved NSA for TGI did not include a provision to allow the continued use of a PBR mechanism after the expiry, on December 31, 2009, of TGI's previous PBR agreement. The approved mid-year rate base at TGI is $2,540 million for 2010 and $2,634 million for 2011, and the approved mid-year rate base at TGVI is approximately $555 million for 2010 and $729 million for 2011. The impact of the approved NSAs, increase in the allowed ROEs, and higher equity component at TGI resulted in an increase in customer rates, effective January 1, 2010. Customer rates for TGVI's sales customers, however, will remain unchanged for the two-year period beginning January 1, 2010, as provided in the BCUC-approved NSA for TGVI.
	- In February 2010, the BCUC approved TGI's application for the in-sourcing of core elements of its customer care services and implementation of a new customer information system, upon the Company accepting a cost risk-sharing condition, whereby TGI would share equally with customers any costs or savings outside a band of plus or minus 10 per cent of the approved total project cost of approximately $116 million, including deferral of certain operating and maintenance expenses.
FortisBC	- In December 2009, the BCUC approved an NSA pertaining to FortisBC's 2010 Revenue Requirements Application. The result was a general customer electricity rate increase of 6.0 per cent, effective January 1, 2010. The rate increase was primarily the result of the Company's ongoing investment in infrastructure, increasing energy supply costs and the higher cost of capital. FortisBC's allowed ROE has increased to 9.90 per cent, effective January 1, 2010, from 8.87 per cent in 2009 as a result of the BCUC decision to increase the allowed ROE of TGI, the benchmark utility in British Columbia. The BCUC-approved NSA assumes a mid-year rate base of approximately $975 million for 2010.
	- In June 2010, FortisBC applied to the BCUC for approval of the Company's 2011 Capital Expenditure Plan totalling approximately $114 million, before customer contributions of approximately $11 million, and including approximately $6 million associated with Demand Side Management programs.
FortisAlberta	- In June 2009, FortisAlberta filed a comprehensive two-year Distribution Tariff Application ("DTA") for 2010 and 2011. The DTA forecasts a mid-year rate base of approximately $1,538 million for 2010 and $1,724 million for 2011. The DTA proposed an average increase in base customer electricity distribution rates of 13.3 per cent for 2010 and 14.9 per cent for 2011, before considering the impact of the increase in the allowed ROE and equity component, as per the AUC 2009 Generic Cost of Capital Decision (the "2009 GCOC Decision") as described below. The proposed rate increases are primarily driven by the Company's ongoing investment in infrastructure to support customer growth and maintain and upgrade the electricity system.
	- In December 2009, FortisAlberta provided the AUC with an update to the proposed forecast revenue requirements for 2010 and 2011, primarily to reflect the 2009 GCOC Decision. The 2009 GCOC Decision established a generic allowed ROE of 9.00 per cent for each of 2009 and 2010 for all Alberta utilities regulated by the AUC. This allowed ROE is up from the interim allowed ROE of 8.51 per cent that was applicable to FortisAlberta in 2009. The ROE automatic adjustment formula will no longer apply until reviewed further by the AUC. The AUC also increased FortisAlberta's equity component to 41 per cent from 37 per cent, effective January 1, 2009. The $4.1 million favourable 2009 annual impact of the 2009 GCOC Decision was accrued as revenue in the fourth quarter of 2009 and is expected to be collected in customer electricity rates in 2011.
	- In December 2009, the AUC approved, on an interim basis, a 7.5 per cent average increase in FortisAlberta's base customer electricity distribution rates, effective January 1, 2010. A decision on the DTA was received in July 2010. While the decision was largely as anticipated, approval of the updated forecast of the capital cost of the automated metering project is pending negotiation with customer groups. A compliance re-filing application will be filed by the Company with the AUC by August 30, 2010 and the impacts of the decision are expected to be incorporated in the Company's third quarter financial results.
	- The AUC has initiated a process to reform utility rate regulation in Alberta. The AUC has expressed its intention to apply a PBR formula to distribution service rates as early as July 1, 2012. FortisAlberta is currently assessing PBR and will participate fully in the AUC process.
Newfoundland Power	- In December 2009, the PUB issued a decision on Newfoundland Power's 2010 General Rate Application ("2010 GRA"), resulting in an overall average increase in customer electricity rates of approximately 3.5 per cent, effective January 1, 2010. The rate increase reflects the impact of an increase in the allowed ROE to 9.00 per cent from 8.95 per cent in 2009, as set by the PUB for 2010, and higher rate base and operating expenses, including pension costs. The PUB decision assumes a mid-year rate base of approximately $869 million for 2010. The PUB also ordered that Newfoundland Power's allowed ROE for each of 2011 and 2012 be determined using the ROE automatic adjustment formula.
	- In April 2010, the PUB approved the Company's application, as filed, to change the existing ROE automatic adjustment formula. Consensus Forecasts will now be used in determining the risk-free rate for calculating the forecast cost of equity to be used in the formula for 2011 and 2012. The previous approach used a ten-day observation of long-term Canada Bond yields as the forecast risk-free rate.
	- Under the terms of a Joint Use Facilities Partnership Agreement ("JUFPA") between Newfoundland Power and Bell Aliant (previously, Aliant Telecom Inc.), Newfoundland Power received notice in June 2010 of Bell Aliant's intention to not renew the JUFPA with Newfoundland Power, which expires December 31, 2010, and to repurchase 40 per cent of all joint-use poles from Newfoundland Power for a book-based value. Under the JUFPA, Newfoundland Power acquired approximately 70,000 joint-use distribution poles from Bell Aliant in 2001 for a book-based value of approximately $40 million. Bell Aliant has been renting space on these poles from Newfoundland Power since 2001. Any disposition of joint-use poles back to Bell Aliant will require regulatory approval. Upon purchase of the poles, Bell Aliant will also have the obligation to install and maintain 40 per cent of the jointly used poles on an ongoing basis. Once the final terms and conditions have been negotiated between Newfoundland Power and Bell Aliant, Newfoundland Power will be able to assess the impact of the above transaction on its future results of operations, cash flows and financial position.
	- Newfoundland Power submitted a proposal to the PUB in June 2010 relating to the accounting for, and recovery of, other post-employment benefits ("OPEB") costs. The Company recommends that it: (i) adopt the accrual method of accounting for OPEB costs effective January 1, 2011; (ii) recover the transitional balance, or regulatory asset, associated with adoption of accrual accounting over a 15-year period; and (iii) adopt a deferral account to capture differences in OPEB costs arising from changes in assumptions associated with the valuation of OPEB obligations. The regulatory asset was approximately $47 million as at December 31, 2009. The proposal is currently under review by the PUB.
	- In July 2010, Newfoundland Power filed an application with the PUB requesting approval for its 2011 Capital Expenditure Plan totaling approximately $73 million.
	- Effective July 1, 2010, there was an overall average increase in electricity rates charged to Newfoundland Power customers of approximately 1.7 per cent. The increase was a result of the normal annual operation of the Rate Stabilization Plan of Newfoundland and Labrador Hydro ("Newfoundland Hydro"). Variances in the cost of fuel used to generate the electricity that Newfoundland Hydro sells to Newfoundland Power are captured and flowed through to Newfoundland Power customers through the operation of the Rate Stabilization Plan. The increase in customer rates will have no impact on earnings of Newfoundland Power.
	- Newfoundland Power is currently assessing the requirement to file an application with the PUB to recover expected increased costs in 2011.
Maritime Electric	- In July 2010, IRAC approved Maritime Electric's 2010/2011 Rate Application providing for: (i) an increase in the reference cost of energy in basic electricity rates, effective August 1, 2010; (ii) the amortization of the replacement energy costs incurred during the refurbishment of the New Brunswick Power Point Lepreau Nuclear Generating Station ("Point Lepreau") over a period of 25 years, representing the extended life of the unit; and (iii) an allowed ROE of 9.75 per cent for both 2010 and 2011, unchanged from 2009.
FortisOntario	- In April 2010, FortisOntario received Decisions and Orders from the OEB with respect to Third-Generation Incentive Rate Mechanism ("IRM") electricity distribution rate applications for harmonized rates for Fort Erie and Gananoque and rates for Port Colborne, effective May 1, 2010. In non-rebasing years, customer electricity rates are set using inflationary factors less an efficiency target under the OEB's Third-Generation IRM. The resulting increase in base electricity rates, effective May 1, 2010, was minimal, with an inflationary increase of 1.3 per cent partially offset by a 1.12 per cent efficiency target. The approved electricity rates were also based on a deemed capital structure containing 40 per cent equity and reflect an allowed ROE of 8.01 per cent.
	- In June 2010, FortisOntario filed a new cost of service electricity distribution rate application for Algoma Power for rates effective July 1, 2010 and January 1, 2011, based on 2010 and 2011 test years, respectively. The application proposes an approximate 14.6 per cent increase in electricity delivery rates in 2010 and an approximate 7.4 per cent increase in rates in 2011. The application is based on a deemed capital structure containing 40 per cent equity and a currently estimated allowed ROE of 9.85 per cent.
	- In the second half of 2010, FortisOntario expects to file electricity distribution rate applications for harmonized rates for Fort Erie and Gananoque and rates for Port Colborne, effective January 1, 2011, using 2011 as a forward test year.
Belize Electricity	- Changes made in electricity legislation by the Government of Belize and the PUC, and the PUC's June 2008 Final Decision on Belize Electricity's 2008/2009 Rate Application and the PUC's amendment to the June 2008 Final Decision, which were based on the changed legislation, have been judicially challenged by Belize Electricity in several proceedings. The judicial process is ongoing with interim rulings, judgments and appeals. The timing or likely final outcome of the proceedings is indeterminable at this time. In response to an application from Belize Electricity, the Supreme Court of Belize issued an order in June 2010 prohibiting the PUC from carrying out any rate-setting review proceedings, changing any rates and taking any enforcement or penal steps against Belize Electricity until further order of the Supreme Court.
Caribbean Utilities	- In February 2010, the ERA approved Caribbean Utilities' 2010-2014 Capital Investment Plan at US$98 million for non-generation expansion expenditures. Additional generation needs are subject to a competitive bid process.
	- In May 2010, Caribbean Utilities submitted its annual RCAM calculations to the ERA as set out in the utility's transmission and distribution licence. The RCAM, which permits base electricity rates to move with inflation, yielded no rate adjustment that otherwise would have been in effect as of June 1, 2010, as the slight inflation in the US price index was offset by deflation in the Cayman Islands price index for calendar year 2009.
Fortis Turks and Caicos	- In March 2010, Fortis Turks and Caicos submitted its 2009 annual regulatory filing outlining the Company's performance in 2009 and its capital expansion plans for 2010.
	- In March 2010, Fortis Turks and Caicos filed an Electricity Rate Review with the Ministry of Works, Housing and Utilities of the Government of the Turks and Caicos Islands in accordance with Section 34 of the Electricity Ordinance. The filing requested an average 7 per cent increase in base customer electricity rates, effective May 31, 2010. The rate increase would have been the first rate increase implemented by Fortis Turks and Caicos since its inception. The objectives of the Electricity Rate Review included setting rates for the various classes of customers through an Allocated Cost of Service Study, introducing uniformity in the rate structure throughout the service territory of Fortis Turks and Caicos and enabling the utility to start to recover its December 31, 2009 accumulated regulatory shortfall in achieving its allowable profit.
	- In June 2010, Fortis Turks and Caicos received notice from the Governor of the Turks and Caicos Islands that the Company's Electricity Rate Review filing was not accepted because of concern of the impact that the proposed rate increase might have on key sectors of the Islands' economy. Fortis Turks and Caicos is continuing discussions with the Government and has requested the Governor to appoint an outside, independent consultant to review the filing and the current rate setting mechanism and make recommendations regarding both.

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between June 30, 2010 and December 31, 2009.

Significant Changes in the Consolidated Balance Sheets (Unaudited) between June 30, 2010 and December 31, 2009
Balance Sheet Account	Increase/ (Decrease)($ millions)	Explanation
Accounts receivable	(78)	The decrease was primarily due to the impact of a seasonal decrease in sales, driven by the Terasen Gas companies.
Regulatory assets - current and long-term	69	The increase was driven by deferrals at the Terasen Gas companies associated with: (i) a $38 million change in the fair market value of the natural gas derivatives; and (ii) the drawdown of the Commodity Cost Reconciliation Account, as amounts are being refunded to customers in current commodity rates, partially offset by a reduction in the Midstream Cost Reconciliation Account, as amounts collected in customer rates were in excess of actual mid-stream gas-delivery costs.
Inventories	(34)	The decrease was driven by the normal seasonal reduction of gas in storage at the Terasen Gas companies, due to higher consumption during the winter months.
Utility capital assets	242	The increase primarily related to $413 million invested in electricity and gas systems and the impact of foreign exchange on the translation of foreign currency-denominated utility capital assets, partially offset by amortization and customer contributions for the six months ended June 30, 2010.
Short-term borrowings	(196)	The decrease was driven by the repayment of short-term borrowings by TGI with proceeds from an equity injection from Fortis, lower borrowings at the Terasen Gas companies due to seasonality of its operations and the reclassification of $70 million borrowed under TGVI's credit facility to long-term debt upon renegotiation of the Company's committed credit facility. Partially offsetting the decrease was higher borrowings at Maritime Electric, to finance $15 million of maturing long-term debt, and at Caribbean Utilities, to finance capital expenditures.
Accounts payable and accrued charges	(47)	The decrease was driven by lower amounts owing for purchased natural gas at the Terasen Gas companies and purchased power at Newfoundland Power due to seasonality of operations, partially offset by a $38 million change in the fair market value of the natural gas derivatives at the Terasen Gas companies.
Dividends payable	49	The increase was due to the timing of the declaration of common share dividends for the first quarter of 2010 and an increase in the quarterly common share dividend declared from $0.26 per share to $0.28 per share.
Regulatory liabilities – current and long-term	23	The increase was mainly due to an increase in the Rate Stabilization Deferral Account at TGVI, reflecting the accumulation of over-recovered costs of providing service to customers year-to-date 2010, partially offset by a reduction in the Revenue Stabilization Adjustment Mechanism account at TGI, as natural gas consumption volumes were lower than forecast during the first half of 2010.
Long-term debt and capital lease obligations (including current portion)	23	The increase was driven by a net $157 million increase in committed credit facility borrowings classified as long-term, the reclassification of $70 million of committed credit facility borrowings by TGVI from short-term borrowings and the impact of foreign exchange on the translation of foreign currency-denominated long-term debt. The increase was partially offset by regularly scheduled debt repayments, including the repayment of maturing $15 million 12% debentures at Maritime Electric with proceeds from short-term borrowings, and the redemption of the $125 million 8.0% Capital Securities at Terasen with proceeds from borrowings under the Corporation's committed credit facility.
Shareholders' equity	302	The increase was driven by the issuance of $250 million five-year fixed rate reset preference shares in January 2010. The remainder of the increase was due to net earnings attributable to common equity shareholders for the six months ended June 30, 2010, less common share dividends, and the issuance of common shares under the Corporation's share purchase, dividend reinvestment and stock option plans.

LIQUIDITY AND CAPITAL RESOURCES

Summary of Consolidated Cash Flows: The table below outlines the Corporation's consolidated sources and uses of cash for the three and six months ended June 30, 2010, as compared to the same periods in 2009, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows (Unaudited)
Periods Ended June 30		Quarter						Year-to-date
($ millions)		2010		2009		Variance		2010		2009		Variance
Cash, Beginning of Period		92		94		(2	)	85		66		19
Cash Provided by (Used in):
	Operating Activities	204		275		(71	)	453		504		(51	)
	Investing Activities	(229	)	(272	)	43		(405	)	(482	)	77
	Financing Activities	3		41		(38	)	(62	)	50		(112	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		1		(1	)	2		-		(1	)	1
Cash, End of Period		71		137		(66	)	71		137		(66	)

Operating Activities: Cash flow from operating activities, after working capital adjustments, was $71 million lower quarter over quarter driven by unfavourable working capital changes at the Terasen Gas companies, reflecting differences in the commodity cost of natural gas and the cost of natural gas charged to customers period over period and the differing effects of seasonality.

Cash flow from operating activities, after working capital adjustments, was $51 million lower year to date compared to the same period in 2009, driven by unfavourable working capital changes partially offset by higher earnings. The unfavourable working capital changes were driven by the Terasen Gas companies for the reasons discussed above for the quarter, partially offset by: (i) favourable changes in the Alberta Electric System Operator ("AESO") charges deferral account at FortisAlberta; (ii) the timing of property tax and other payments at FortisBC; (iii) a decrease in the amount of corporate taxes paid at the Terasen Gas companies and Newfoundland Power; (iv) and the timing of the declaration of common share dividends for the first quarter of 2010.

Investing Activities: Cash used in investing activities was $43 million lower quarter over quarter and $77 million lower year to date compared to the same period in 2009. The decrease was driven by lower gross capital expenditures at FortisAlberta, mainly due to lower demand for new residential services, irrigation and farm services and lower spending related to equipment, facilities and AESO transmission capital projects. Lower gross capital expenditures at the Regulated Electric Utilities – Caribbean, Fortis Generation and the Terasen Gas companies were partially offset by higher gross capital expenditures at FortisBC.

Financing Activities: Cash provided by financing activities was $3 million during the second quarter of 2010 compared to $41 million during the same quarter in 2009. Cash used in financing activities was $62 million year to date compared to cash provided by financing activities of $50 million during the same period in 2009. Quarter over quarter and year to date compared to the same period last year, lower proceeds from long-term debt, higher repayments of long-term debt and higher common and preference share dividends were partially offset by favourable variances in short-term borrowings, higher proceeds from net borrowings under committed credit facilities and higher proceeds from the issuance of common shares. Proceeds from the issuance of preference shares were also higher year to date compared to the same period in 2009.

Net proceeds from short-term borrowings were $55 million during the second quarter of 2010 compared to net repayments of short-term borrowings of $89 million during the same quarter in 2009. Net repayments of short-term borrowings were $126 million year to date compared to $239 million during the same period in 2009. The changes in short-term borrowings for the second quarter and year-to-date periods of 2010 were driven by the Terasen Gas companies. In January 2010, TGI repaid short-term borrowings using proceeds from an equity injection by the Corporation.

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

Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended June 30		Quarter					Year-to-date
($ millions)		2010	2009		Variance		2010	2009		Variance
Terasen Gas Companies		-	-		-		-	99 ⁽¹	⁾	(99	)
FortisAlberta		-	-		-		-	99 ⁽²	⁾	(99	)
	FortisBC	-	104 ⁽³	⁾	(104	)	-	104 ⁽³	⁾	(104	)
	Newfoundland Power	-	65 ⁽⁴	⁾	(65	)	-	65 ⁽⁴	⁾	(65	)
	Caribbean Utilities	-	34 ⁽⁵	⁾	(34	)	-	34 ⁽⁵	⁾	(34	)
Total		-	203		(203	)	-	401		(401	)

(1)	Issued February 2009, 30-year $100 million 6.55% unsecured debentures by TGI. The net proceeds were used to repay credit facility borrowings and repay $60 million 10.75% unsecured debentures that matured in June 2009.
(2)	Issued February 2009, 30-year $100 million 7.06% unsecured debentures. The net proceeds were used to repay committed credit facility borrowings and for general corporate purposes.
(3)	Issued June 2009, 30-year $105 million 6.10% unsecured debentures. The net proceeds were used to repay committed credit facility borrowings, for general corporate purposes, including financing capital expenditures and working capital requirements, and help repay $50 million 6.75% debentures that matured in July 2009.
(4)	Issued May 2009, 30-year $65 million 6.606% first mortgage sinking fund bonds. The net proceeds were used to repay committed credit facility borrowings and for general corporate purposes, including financing capital expenditures.
(5)	Issued May 2009, 15-year US$30 million 7.50% unsecured notes. The net proceeds were used to repay short-term borrowings and finance capital expenditures.

Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Periods Ended June 30	Quarter						Year-to-date
($ millions)	2010		2009		Variance		2010		2009		Variance
Terasen Gas companies	(1	)	(63	)	62		(1	)	(63	)	62
Maritime Electric	(15	)	-		(15	)	(15	)	-		(15	)
Caribbean Utilities	(15	)	(16	)	1		(15	)	(16	)	1
Fortis Properties	(38	)	(3	)	(35	)	(52	)	(5	)	(47	)
Corporate - Terasen	(125)⁽¹	⁾	-		(125	)	(125)⁽¹	⁾	-		(125	)
Other	(2	)	(3	)	1		(4	)	(7	)	3
Total	(196	)	(85	)	(111	)	(212	)	(91	)	(121	)
(1) In April 2010, Terasen redeemed in full for cash its $125 million 8.0% Capital Securities with proceeds from borrowings under the Corporation's committed credit facility.

Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Periods Ended June 30	Quarter					Year-to-date
($ millions)	2010	2009		Variance		2010	2009		Variance
FortisAlberta	20	55		(35	)	60	1		59
FortisBC	21	(36	)	57		12	(31	)	43
Newfoundland Power	2	(57	)	59		13	(27	)	40
Corporate	143	90		53		72	114		(42	)
Total	186	52		134		157	57		100

Borrowings under credit facilities by the utilities are primarily in support of their capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt issues are used to repay borrowings under the Corporation's committed credit facility.

Proceeds from the issuance of common shares increased $5 million quarter over quarter and $15 million year to date compared to the same period in 2009, reflecting the impact of the participation by shareholders in the Corporation's enhanced Dividend Reinvestment and Share Purchase Plan. The plan provides participating common shareholders a 2 per cent discount on the purchase of common shares, issued from treasury, with reinvested dividends.

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

Common share dividends were $49 million for the second quarter, up $5 million from the same quarter in 2009, due mainly to an increase in the quarterly common share dividend declared. Common share dividends were $145 million year to date, up $57 million from the same period in 2009. The increase was primarily due to the timing of the declaration of common share dividends for the first quarter of 2010 and an increase in the quarterly common share dividends declared. The dividend declared per common share in each of the first and second quarters of 2010 was $0.28, while the dividend declared per common share in each of the first and second quarters of 2009 was $0.26.

Preference share dividends increased $3 million quarter over quarter and $5 million year to date compared to the same period in 2009, as a result of the dividends associated with the 10 million preference shares that were issued in January 2010.

Contractual Obligations: Consolidated contractual obligations of Fortis over the next five years and for periods thereafter, as of June 30, 2010, are outlined in the following table. A detailed description of the nature of the obligations is provided below and in the MD&A for the year ended December 31, 2009.

Contractual Obligations (Unaudited)
As at June 30, 2010 ($ millions)		Total	Due within 1 year	Due in years 2 and 3	Due in years 4 and 5	Due after 5 years
Long-term debt		5,523	156	561	773	4,033
Brilliant Terminal Station		61	3	5	5	48
Gas purchase contract obligations ⁽¹⁾		620	277	222	121	-
Power purchase obligations
	FortisBC ⁽²⁾	2,917	44	89	82	2,702
	FortisOntario	486	47	96	169	174
	Maritime Electric	60	41	2	2	15
	Belize Electricity	317	29	67	59	162
Capital cost		410	26	33	32	319
Joint-use asset and share service agreements		61	3	6	6	46
Office lease – FortisBC		18	1	3	3	11
Operating lease obligations		140	17	30	26	67
Equipment purchase – Fortis Turks and Caicos		5	5	-	-	-
Defined benefit pension funding contributions ⁽³⁾		38	16	16	4	2
Other ⁽⁴⁾		22	5	9	6	2
Total		10,678	670	1,139	1,288	7,581

(1)	Based on index prices as at June 30, 2010

(2)	During the first quarter of 2010, FortisBC entered into a contract with Powerex Corp., a wholly owned subsidiary of BC Hydro, for fixed-price winter capacity purchases through to February 2016 in an aggregate amount of approximately US$16 million. If FortisBC brings any new resources, such as capital or contractual projects, on-line prior to the expiry of this agreement, FortisBC may terminate this contract any time after July 1, 2013 with a minimum of three-months' written notice to Powerex Corp.

(3)	Consolidated defined benefit pension funding contributions include current service, solvency and special funding amounts. The contributions are based on estimates provided under the latest completed actuarial valuations, which generally provide funding estimates for a period of three to five years from the date of the valuations. As a result, actual pension funding contributions may be higher than the above estimated amounts pending completion of the next actuarial valuations for funding purposes, which are expected to be performed as of the following dates for the larger defined benefit pension plans:

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

(4)	Other contractual obligations include capital lease obligations, operating building leases, and asset retirement obligations at FortisBC.

Other Contractual Obligations:

In prior years, TGVI received non-interest bearing repayable loans from the federal and provincial governments of $50 million and $25 million, respectively, in connection with the construction and operation of the Vancouver Island natural gas pipeline. As approved by the BCUC, these loans have been recorded as government grants and have reduced the amounts reported for utility capital assets. The government loans are repayable in any fiscal year prior to 2012 under certain circumstances and subject to the ability of TGVI to obtain non-government subordinated debt financing on reasonable commercial terms. As the loans are repaid and replaced with non-government loans, utility capital assets and long-term debt will increase in accordance with TGVI's approved capital structure, as will TGVI's rate base, which is used in determining customer rates. The repayment criteria were met in 2009 and TGVI made an approximate $4 million repayment on the loans during the second quarter of 2010. As at June 30, 2010, the outstanding balance of the repayable government loans was approximately $49 million, with approximately $4 million classified as current portion of long-term debt. Repayments of the government loans are not included in the contractual obligations table above as the amount and timing of the repayments are dependent upon the ability of TGVI to replace the government loans with non-government subordinated debt financing on reasonable commercial terms. TGVI, however, estimates making payments under the loans of $20 million in 2012, $14 million over 2013 and 2014 and $15 million thereafter.

Caribbean Utilities has a primary fuel supply contract with a major supplier and is committed to purchase 80 per cent of the Company's fuel requirements from this supplier for the operation of Caribbean Utilities' diesel-powered generating plant. The initial contract was for three years and terminated in April 2010. CUC continues to operate within the terms of the initial contract. The contract contains an automatic renewal clause for years 2010 through 2012. Should any party choose to terminate the contract within that two-year period, notice must be given a minimum of one year in advance of the desired termination date. No such termination notice has been given by either party to date. As such, the contract is effectively renewed until 2011. The quantity of fuel to be purchased under the contract for 2010 is approximately 25 million imperial gallons.

Fortis Turks and Caicos has a renewable contract with a major supplier for all of its diesel fuel requirements associated with the generation of electricity. The approximate fuel requirements under this contract are 12 million imperial gallons per annum.

Capital Structure: The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40 per cent equity, including preference shares, and 60 per cent debt, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in the utilities' customer rates.

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

Capital Structure (Unaudited)	As at
	June 30, 2010		December 31, 2009
	($ millions)	(%)	($ millions)	(%)
Total debt and capital lease obligations (net of cash) ⁽¹⁾	5,671	57.7	5,830	60.2
Preference shares ⁽²⁾	912	9.3	667	6.9
Common shareholders' equity	3,248	33.0	3,193	32.9
Total ⁽³⁾	9,831	100.0	9,690	100.0
⁽¹⁾Includes long-term debt and capital lease obligations, including current portion, and short-term borrowings, net of cash
⁽²⁾Includes preference shares classified as both long-term liabilities and equity
⁽³⁾Excludes amounts related to non-controlling interests

The change in the capital structure was driven by the issuance of $250 million preference shares in January 2010; increased common shares outstanding, reflecting the impact of the Corporation's enhanced Dividend Reinvestment and Share Purchase Plan; and the repayment of credit facility borrowings with proceeds from the preference share issue.

Credit Ratings: The Corporation's credit ratings are as follows:

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

In May 2010, S&P confirmed its existing debt credit rating for Fortis at A-(stable). In June 2010, DBRS confirmed its existing debt credit rating for Fortis at BBB(high), but changed the trend to 'Positive' from 'Stable'. The above credit ratings and recent trend change by DBRS reflect the Corporation's low business risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, management's commitment to maintaining low levels of debt at the holding company level and the significant reduction in external debt at Terasen, the Corporation's strong credit metrics, and the Corporation's demonstrated ability and continued focus of acquiring and integrating stable regulated utility businesses financed on a conservative basis.

Capital Program: The Corporation's principal businesses of regulated gas and electricity distribution are capital intensive. Capital investment in infrastructure is required to ensure continued and enhanced performance, reliability and safety of the gas and electricity systems and to meet customer growth. All costs considered to be maintenance and repairs are expensed as incurred. Costs related to replacements, upgrades and betterments of capital assets are capitalized as incurred.

During the first half of 2010, gross consolidated capital expenditures were $432 million. A breakdown of gross capital expenditures by segment for the first half of 2010 is provided in the following table.

Gross Capital Expenditures (Unaudited) ⁽¹⁾Year-to-date June 30, 2010 ($ millions)
Tera- sen Gas Compa- nies	Fortis Alber- ta ⁽²⁾	Fortis- BC	New- found- land Power	Other Regu- lated Elec- tric Utili- ties - Cana- dian	Total Regu- lated Utili- ties - Cana- dian	Regu- lated Elec- tric Utili- ties -Carib- bean	Non- Regu- lated - Utili- ty ⁽³⁾	Fortis Proper- ties	Total
110	153	63	36	21	383	36	4	9	432

(1)	Relates to utility capital assets, income producing properties and intangible assets and includes capital expenditures associated with assets under construction. Includes asset removal and site restoration expenditures, net of salvage proceeds, for those utilities where such expenditures are permissible in rate base in 2010. Excludes capitalized amortization and non-cash equity component of the allowance for funds used during construction
(2)	Includes payments made to AESO for investment in transmission capital projects
(3)	Includes non-regulated generation and corporate capital expenditures

There has been no material change in forecast gross consolidated capital expenditures for 2010 from the approximate $1.1 billion forecast as was disclosed in the MD&A for the year ended December 31, 2009. Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts.

There are no significant updates in the overall expected level, nature and timing of the Corporation's significant capital projects from those disclosed in the MD&A for the year ended December 31, 2009, except as described below.

During 2010, FortisAlberta has continued with the replacement of conventional customer meters with automated meter reading technology. The total project cost, including the pilot program, is now expected to be approximately $141 million, a decrease from $155 million forecast at December 31, 2009. The capital cost of this project may be further updated, pending negotiation with customer groups and regulatory approval.

In May 2010, Fortis Turks and Caicos received delivery of one of two diesel-powered generating units with a combined generating capacity of approximately 18 MW. The first unit is expected to be commissioned in September 2010.

Over the five-year period 2010 through 2014, consolidated gross capital expenditures are expected to approach $5 billion. Approximately 71 per cent of the capital spending is expected to be incurred at the Regulated Electric Utilities, driven by FortisAlberta and FortisBC, and 27 per cent of the capital spending is expected to be incurred at the Regulated Gas Utilities. Approximately 2 per cent is expected to be incurred at the non-regulated operations. Capital expenditures at the Regulated Utilities are subject to regulatory approval.

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

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

As at June 30, 2010, management expects consolidated long-term debt maturities and repayments to average approximately $300 million annually over the next five years. The combination of available credit facilities and relatively low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

As a result of the regulator's Final Decision on Belize Electricity's 2008/2009 Rate Application in June 2008, Belize Electricity does not meet certain debt covenant financial ratios related to loans with the International Bank for Reconstruction and Development and the Caribbean Development Bank totalling $6 million (BZ$11 million) as at June 30, 2010.

As the hydroelectric assets and water rights of the Exploits Partnership had been provided as security for the Exploits Partnership term loan, the expropriation of such assets and rights by the Government of Newfoundland and Labrador constituted an event of default under the loan. The term loan is without recourse to Fortis and was approximately $58 million as at June 30, 2010 (December 31, 2009 - $59 million). The lenders of the term loan have not demanded accelerated repayment. The scheduled repayments under the term loan are being made by Nalcor Energy, a Crown corporation, acting as agent for the Government of Newfoundland and Labrador with respect to the expropriation matters.

Except for the debt at Belize Electricity and the Exploits Partnership, as discussed above, Fortis and its subsidiaries were in compliance with debt covenants as at June 30, 2010 and are expected to remain compliant throughout 2010.

Credit Facilities: As at June 30, 2010, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.1 billion, of which $1.4 billion was unused, including $403 million unused under the Corporation's $600 million committed revolving credit facility. The credit facilities are syndicated almost entirely with the seven largest Canadian banks, with no one bank holding more than 25 per cent of these facilities. Approximately $2.0 billion of the total credit facilities are committed facilities, the majority of which currently have maturities between 2011 and 2013.

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

Credit Facilities (Unaudited)								As at
($ millions)		Corporate and Other		Regulated Utilities		Fortis Properties		June 30, 2010		December 31, 2009
Total credit facilities		645		1,455		13		2,113		2,153
Credit facilities utilized:
	Short-term borrowings	-		(218	)	(1	)	(219	)	(415	)
	Long-term debt (including current portion)	(197	)	(225	)	-		(422	)	(208	)
Letters of credit outstanding		(1	)	(111	)	-		(112	)	(100	)
Credit facilities unused		447		901		12		1,360		1,430

As at June 30, 2010 and December 31, 2009, certain borrowings under the Corporation's and subsidiaries' credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.

In February 2010, Maritime Electric renewed its $50 million unsecured committed revolving credit facility, which matures annually in March. During the second quarter of 2010, Maritime Electric increased its unsecured committed revolving credit facility by $10 million.

In April 2010, FortisBC amended its credit facility agreement obtaining an extension to the maturity of its $150 million unsecured committed revolving credit facility with $100 million now maturing in May 2013 and $50 million now maturing in May 2011.

In May 2010, TGVI entered into a two-year $300 million unsecured committed revolving credit facility to replace its $350 million credit facility that was due to mature in January 2011. The terms of the new $300 million credit facility are substantially similar to the terms of the former $350 million credit facility, except for an increase in pricing.

In May 2010, Newfoundland Power exercised an option to extend its $100 million unsecured committed credit facility ("Amended Credit Facility") to August 2013 from August 2011. The Amended Credit Facility agreement is expected to reflect an increase in pricing but, otherwise, contain substantially similar terms and conditions as the current credit facility agreement. The amended agreement is expected to be finalized in August 2010.

FINANCIAL INSTRUMENTS

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

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

Financial Instruments (Unaudited)	As at
	June 30, 2010		December 31, 2009
($ millions)	Carrying Value	Estimated Fair Value	Carrying Value	Estimated Fair Value
Long-term debt, including current portion ⁽¹⁾	5,523	6,160	5,502	5,906
Preference shares, classified as debt ⁽²⁾	320	340	320	348
(1) Carrying value as at June 30, 2010 excludes unamortized deferred financing costs of $38 million (December 31, 2009 - $39 million) and capital lease obligations of $38 million (December 31, 2009 - $37 million).
(2) Preference shares classified as equity do not meet the definition of a financial instrument; however, the estimated fair value of the Corporation's $592 million preference shares classified as equity was $595 million as at June 30, 2010 (December 31, 2009 - carrying value $347 million; fair value $356 million).

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

As at June 30, 2010, all of the Corporation's corporately held US$390 million (December 31, 2009 – US$390 million) long-term debt had been designated as a hedge of a portion of the Corporation's foreign net investments. As at June 30, 2010, the Corporation had approximately US$187 million (December 31, 2009 – US$174 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately held US dollar borrowings designated as hedges are recorded in other comprehensive income and serve to help offset unrealized foreign currency gains and losses on the foreign net investments, which are also recorded in other comprehensive income.

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

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

Derivative Financial Instruments (Unaudited) As at
		June 30, 2010						December 31, 2009
Asset (Liability)		Term to Maturity (years)	Number of Contracts	Carrying Value ($ millions)		Estimated Fair Value($ millions)		Carrying Value ($ millions)		Estimated Fair Value($ millions)
Interest rate swap		<1	1	-		-		-		-
Foreign exchange forward contracts		1 to 2	2	1		1		-		-
Natural gas derivatives:
	Swaps and options	Up to 4	193	(156	)	(156	)	(119	)	(119	)
	Gas purchase contract premiums	Up to 3	47	(4	)	(4	)	(3	)	(3	)

The interest rate swap is held by Fortis Properties and is designated as a hedge of the cash flow risk related to floating-rate long-term debt and matures in October 2010. The effective portion of changes in the value of the interest rate swap at Fortis Properties is recorded in other comprehensive income.

The foreign exchange forward contracts are held by the Terasen Gas companies. During the first quarter of 2010, TGI entered into a foreign exchange forward contract to hedge the cash flow risk related to approximately US$12 million remaining to be paid under a contract for the implementation of a customer information system. TGVI also hedges the cash flow risk related to approximately US$4 million remaining to be paid under a contract for the construction of a liquefied natural gas storage facility.

The natural gas derivatives are held by the Terasen Gas companies and are used to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The price risk-management strategy of the Terasen Gas companies aims to improve the likelihood that natural gas prices remain competitive with electricity rates, temper gas price volatility on customer rates and reduce the risk of regional price discrepancies.

The changes in the fair values of the foreign exchange forward contracts and natural gas derivatives are deferred as a regulatory asset or liability, subject to regulatory approval, for recovery from, or refund to, customers in future rates. The fair values of the foreign exchange forward contracts were recorded in accounts receivable as at June 30, 2010 and as at December 31, 2009. The fair values of the natural gas derivatives were recorded in accounts payable as at June 30, 2010 and as at December 31, 2009.

The interest rate swap is valued at the present value of future cash flows based on published forward future interest rate curves. The foreign exchange forward contracts are valued using the present value of cash flows based on a market foreign exchange rate and the foreign exchange forward rate curve. The natural gas derivatives are valued using the present value of cash flows based on market prices and forward curves for the commodity cost of natural gas. The fair values of the foreign exchange forward contracts and natural gas derivatives are estimates of the amounts the Terasen Gas companies would have to receive or pay if forced to settle all outstanding contracts as at the balance sheet dates.

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

OFF-BALANCE SHEET ARRANGEMENTS

As at June 30, 2010, the Corporation had no off-balance sheet arrangements, such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities, that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.

BUSINESS RISK MANAGEMENT

A detailed discussion of the Corporation's significant business risks is provided in the MD&A for the year ended December 31, 2009. There were no changes in the Corporation's significant business risks during the first half of 2010 from those disclosed in the MD&A for the year ended December 31, 2009, except for those described below.

Regulatory Risk: In July 2010, the AUC issued its decision on FortisAlberta's 2010 and 2011 revenue requirements application, the effects of which are expected to be reflected in the third quarter of 2010. Maritime Electric also received a regulatory decision on its revenue requirements application for rates effective August 1, 2010 with an allowed ROE of 9.75 per cent approved for each of 2010 and 2011. See the "Regulatory Highlights – Material Regulatory Decisions and Applications" section of this MD&A.

Capital Resources and Liquidity Risk - Credit Ratings: Fortis and its regulated utilities do not anticipate any material adverse rating actions by the credit rating agencies in the near term.

Year-to-date 2010, Moody's has confirmed its existing debt credit ratings for TGI, TGVI, FortisAlberta and Newfoundland Power. Moody's, however, upgraded FortisBC's senior unsecured debt credit rating to Baa1 from Baa2. The credit rating upgrade for FortisBC reflects progress made by the Company in addressing issues previously identified as credit challenges. DBRS has confirmed its existing debt credit ratings for TGI, and its existing credit rating of the Corporation's unsecured debt at BBB(high) while changing the trend to 'Positive' from 'Stable'. See the "Liquidity and Capital Resources – Credit Ratings" section of this MD&A. S&P has also confirmed its existing debt credit ratings for FortisAlberta and the Corporation, and its existing corporate credit rating for Maritime Electric. S&P, however, lowered Maritime Electric's senior secured debt credit rating to A- from A and revised the recovery rating on the debt to '1' from '1+'. The revised recovery rating and lower senior secured debt credit rating reflects Maritime Electric's ratio of collateral relative to the maximum amount of first mortgage bonds allowed under the Company's indenture being less than 1.5 times.

Defined Benefit Pension Plan Performance and Funding Requirements: As at June 30, 2010, the fair value of the Corporation's consolidated defined benefit pension plan assets was $665 million, up $4 million, or 0.6 per cent, from $661 million as at December 31, 2009.

CHANGES IN ACCOUNTING POLICIES AND STANDARDS

Effective January 1, 2010, as required by the regulator, FortisAlberta began capitalizing to utility capital assets a portion of the amortization of utility capital assets, such as tools and vehicles, used in the construction of other assets. During the three and six months ended June 30, 2010, amortization of $1 million and $2 million, respectively, was capitalized.

Effective January 1, 2010, as a result of the BCUC-approved NSAs related to 2010 and 2011 revenue requirements, the Terasen Gas companies adopted the following new accounting policies:

Asset removal costs are now recorded in operating expenses on the consolidated statement of earnings. The annual amount of such costs approved for recovery in customer rates in 2010 is approximately $8 million. Actual costs incurred in excess of or below the approved amount are to be recorded in a regulatory deferral account for recovery from, or refund to, customers in future rates, beginning in 2012. Removal costs are direct costs incurred by the Terasen Gas companies in taking assets out of service, whether through actual removal of the assets or through the disconnection of the assets from the transmission or distribution system. For the three months ended June 30, 2010, actual asset removal costs of approximately $3 million were incurred, with $2 million recorded in operating expenses and $1 million deferred as a regulatory asset. For the six months ended June 30, 2010, actual asset removal costs of approximately $5 million were incurred, with approximately $4 million recorded in operating expenses and $1 million deferred as a regulatory asset. Prior to January 1, 2010, asset removal costs were recorded against accumulated amortization on the consolidated balance sheet.
CIACs are now amortized to revenue. During the three and six months ended June 30, 2010, CIACs of approximately $2 million and $5 million, respectively, were amortized to revenue on the consolidated statement of earnings. Prior to January 1, 2010, amortization of CIACs was recorded against amortization expense on the consolidated statement of earnings.
Gains and losses on the sale or disposal of utility capital assets are now recorded in a regulatory deferral account on the consolidated balance sheet for recovery from, or refund to, customers in future rates, subject to regulatory approval. During the three and six months ended June 30, 2010, losses of approximately $2 million and $5 million, respectively, were deferred and recorded as a regulatory asset on the consolidated balance sheet. Prior to January 1, 2010, gains and losses on the sale or disposal of utility capital assets were recorded against accumulated amortization on the consolidated balance sheet.
Amortization of utility capital assets and intangible assets now commences the month after the assets are available for use. Prior to January 1, 2010, amortization commenced the year following when the assets became available for use. During 2010, additional amortization expense of approximately $2 million is expected to be incurred, due to the change in commencement of amortization of utility capital assets and intangible assets.

Business Combinations

Effective January 1, 2010, the Corporation early adopted the new Canadian Institute of Chartered Accountants ("CICA") Handbook Section 1582, Business Combinations, together with Section 1601, Consolidated Financial Statements and Section 1602, Non-Controlling Interests. As a result of adopting Section 1582, changes in the determination of the fair value of the assets and liabilities of an acquiree in a business combination results in a different calculation of goodwill with respect to acquisitions on or after January 1, 2010. Such changes include the expensing of acquisition-related costs incurred during a business acquisition, rather than recording them as a capital transaction, and the disallowance of recording restructuring accruals by the acquirer. The adoption of Section 1582 did not have a material impact on the Corporation's interim unaudited consolidated financial statements in the first half of 2010.

Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 establishes standards for accounting for non-controlling interests in a subsidiary in consolidated financial statements subsequent to a business combination. The adoption of Sections 1601 and 1602 resulted in non-controlling interests being presented as components of equity, rather than as liabilities, on the consolidated balance sheet. Also, net earnings and components of other comprehensive income attributable to the owners of the parent company and to non-controlling interests are now separately disclosed on the consolidated statement of earnings and consolidated statement of comprehensive income.

FUTURE ACCOUNTING CHANGES

Transition to International Financial Reporting Standards

A detailed discussion of the Corporation's transition to International Financial Reporting Standards ("IFRS") is provided in the MD&A for the year ended December 31, 2009. The Corporation is still unable to fully determine the impact on its future financial position and results of operations of the transition to IFRS, particularly as it relates to the accounting for rate-regulated activities. Completion of the Rate-Regulated Activities Project by the International Accounting Standards Board ("IASB") has been delayed based on comments received in response to the IASB's July 2009 Exposure Draft on Rate-Regulated Activities and a decision by the IASB to conduct further research.

The IASB met in July 2010 and discussed the key issue of whether regulatory assets and liabilities can be recognized based on the current IFRS - Framework for the Preparation and Presentation of Financial Statements. As a result of those meetings, the IASB decided to continue with the project; however, no decision was made as to whether regulatory assets and liabilities can be recognized under IFRS. A final standard, if any, is still not anticipated before the latter half of 2011.

On July 23, 2010, the Canadian Accounting Standards Board ("AcSB") met to discuss the IASB's latest decisions with respect to the Rate-Regulated Activities Project. On July 28, 2010, the AcSB issued an Exposure Draft proposing that qualifying entities with rate-regulated activities be permitted, but not required, to continue applying the accounting standards in Part V of the CICA Handbook for an additional two years. A qualifying entity would be an entity that: (i) has activities subject to rate regulation meeting the definition of that term in Generally Accepted Accounting Principles, paragraph 1100.32B, in Part V of the CICA Handbook; and (ii) in accordance with Accounting Guideline AcG-19, Disclosures by Entities Subject to Rate Regulation, discloses that it has accounted for a transaction or event differently than it would have in the absence of rate regulation (i.e., that it has recognized regulatory assets and liabilities). The Exposure Draft also proposes that an entity choosing to defer its IFRS changeover date disclose that fact and when it will first present financial statements in accordance with IFRS.

The Exposure Draft provides a two-year deferral of the adoption of IFRS for qualifying entities, based on the expectation that the IASB will complete its project on Rate-Regulated Activities in 2011 or 2012, and gives qualifying entities sufficient time to meet the requirements of a new IFRS on rate-regulated activities in the event one is issued late in, or shortly following, what would otherwise be their year of IFRS adoption.

The Corporation is reviewing the AcSB's Exposure Draft and will provide comments, as requested, by August 31, 2010. The AcSB has indicated its intention to redeliberate the proposal based on comments received and expects to issue the proposed amendment by no later than December 2010.

While the Corporation's IFRS Conversion Project has proceeded as planned in preparation for the adoption of IFRS on January 1, 2011, Fortis and its rate-regulated subsidiaries do qualify for the proposed deferral option. If the Exposure Draft is approved, the Corporation will elect to defer the adoption of IFRS until 2013 and will, therefore, continue to prepare its consolidated financial statements in accordance with Part V of the CICA Handbook for all interim and annual periods ending on or before December 31, 2012.

CRITICAL ACCOUNTING ESTIMATES

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

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

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the first half of 2010 from those disclosed in the Corporation's MD&A for the year ended December 31, 2009, except for those described below.

Capital Asset Amortization: As a result of a recent depreciation study and BCUC-approved NSAs related to TGI and TGVI's 2010 and 2011 revenue requirements, annual amortization expense at the Terasen Gas companies is expected to increase in 2010, reflecting an increase in the composite depreciation rate to 2.79 per cent for 2010 from 2.63 per cent for 2009. The increase in amortization has been approved for recovery in current customer delivery rates.

Asset-Retirement Obligations: During the second quarter of 2010, FortisBC obtained sufficient information to determine an estimate of the fair value and timing of the estimated future expenditures associated with the removal of polychlorinated biphenyls ("PCB")-contaminated oil from its electrical equipment. All factors used in estimating the Company's asset-retirement obligation represent management's best estimate of the fair value of the costs required to meet existing legislation or regulations. It is reasonably possible that volumes of contaminated assets, inflation assumptions, cost estimates to perform the work and the assumed pattern of annual cash flows may differ significantly from the Company's current assumptions. In addition, in order to remove certain PCB-contaminated oil, the ability to take maintenance outages in critical facilities may impact the timing of expenditures. The asset-retirement obligation may change from period to period because of the changes in the estimation of these uncertainties. As at June 30, 2010, FortisBC has recognized approximately $3 million in asset-retirement obligations, which have been classified on the consolidated balance sheet as long-term other liabilities with the offset to utility capital assets.

Capitalized Overhead: As required by their regulator, the Terasen Gas companies capitalize overhead costs not directly attributable to specific capital projects but related to the overall capital program. Effective January 1, 2010, as provided in the BCUC-approved NSAs as described above, the percentage for calculating and capitalizing general overhead costs to utility capital assets at the Terasen gas companies has changed. The percentage of total general operating and maintenance costs being allocated and capitalized to utility capital assets has decreased from 16 per cent to 14 per cent. As a result of this change, operating expenses increased approximately $1 million for the second quarter and approximately $2 million year to date over the same periods in 2009, with corresponding decreases in utility capital assets. The resulting increase in operating expenses has been approved for recovery in current customer delivery rates.

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

Terasen

TGI has been disputing a $7 million assessment of British Columbia Social Services Tax representing additional Provincial Sales Tax and interest on the Southern Crossing Pipeline, which was completed in 2000. The amount was paid in full in 2006 to avoid the accrual of further interest and is recorded as a long-term regulatory deferral asset. TGI was successful in its appeal to the Supreme Court of British Columbia in June 2009. The Province of British Columbia was granted leave to appeal the decision to the British Columbia Court of Appeal in October 2009. The hearing took place in May 2010 and the British Columbia Court of Appeal was unanimous in dismissing the Province of British Columbia's appeal.

On July 16, 2009, Terasen was named, along with other defendants, in an action related to damages to property and chattels, including contamination to sewer lines and costs associated with remediation, related to the rupture in July 2007 of an oil pipeline owned and operated by Kinder Morgan. Terasen has filed a statement of defence but the claim is in its early stages. During the second quarter of 2010, Terasen was added as a third party in all of the related actions and all claims are expected to be tried at the same time. The amount and outcome of the actions are indeterminable at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

Maritime Electric

In June 2010, Maritime Electric reached a Settlement Agreement with Canada Revenue Agency related to the reassessment of the Company's 1997-2004 taxation years. In the Settlement Agreement, Maritime Electric's treatment of the Energy Cost Adjustment Mechanism was accepted; however, the reassessments with respect to customer rebate adjustments and the Company's settlement payment to New Brunswick Power regarding the write-down of Point Lepreau would stand. The Company has provided for the entire amount of the reassessment and expects final reassessments with respect to all affected taxation years by the end of 2010.

SUMMARY OF QUARTERLY RESULTS

The following table sets forth unaudited quarterly information for each of the eight quarters ended September 30, 2008 through June 30, 2010. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements which, in the opinion of management, have been prepared in accordance with Canadian GAAP and as required by utility regulators. The timing of the recognition of certain assets, liabilities, revenue and expenses, as a result of regulation, may differ from that otherwise expected using Canadian GAAP for non-regulated entities. The differences and nature of regulation are disclosed in Notes 2 and 4 to the Corporation's 2009 annual audited consolidated financial statements. The quarterly financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.

Summary of Quarterly Results (Unaudited)
Quarter Ended	Revenue ($ millions)	Net Earnings Attributable to Common Equity Shareholders ($ millions)	Earnings per Common Share
Quarter Ended	Revenue ($ millions)		Basic($)	Diluted ($)
June 30, 2010	836	55	0.32	0.32
March 31, 2010	1,076	100	0.58	0.56
December 31, 2009	1,020	81	0.48	0.46
September 30, 2009	665	36	0.21	0.21
June 30, 2009	756	53	0.31	0.31
March 31, 2009	1,202	92	0.54	0.52
December 31, 2008	1,181	76	0.48	0.46
September 30, 2008	727	49	0.31	0.31

A summary of the past eight quarters reflects the Corporation's continued organic growth and growth from acquisitions, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel and purchased power and the commodity and mid-stream cost of natural gas, which are flowed through to customers without markup. Given the diversified nature of the Fortis subsidiaries, seasonality may vary. Because of natural gas consumption patterns, the earnings of the Terasen Gas companies are highest in the first and fourth quarters. Financial results from May 1, 2009 have been impacted, as expected, by the loss of revenue and earnings subsequent to the expiration, in April 2009, of the water rights of the Rankine hydroelectric generating facility in Ontario. Financial results for the fourth quarter ended December 31, 2009 reflected the favourable cumulative retroactive impact associated with an increase in the allowed ROEs for 2009 for FortisAlberta and TGI, and an increase in the equity component at FortisAlberta. Financial results for the fourth quarter ended December 31, 2008 included two additional months of contribution from Caribbean Utilities, resulting from a change in the utility's fiscal year end. To a lesser degree, financial results from November 2008 were impacted by the acquisition of the Sheraton Hotel Newfoundland, from April 2009 by the acquisition of the Holiday Inn Select Windsor and from October 2009 by the acquisition of Algoma Power.

June 2010/June 2009 - Net earnings attributable to common equity shareholders were $55 million, or $0.32 per common share, for the second quarter of 2010 compared to earnings of $53 million, or $0.31 per common share, for the second quarter of 2009. The increase in earnings was driven by the Terasen Gas companies and FortisBC, partially offset by higher corporate expenses. The increase in earnings at the Terasen Gas companies related to higher allowed ROEs and equity component. The improvement in earnings at FortisBC was the result of a higher allowed ROE and growth in electrical infrastructure investment, partially offset by lower electricity sales due to cooler weather experienced in June 2010. The increase in corporate expenses was mainly due to higher business development costs and preference share dividends, partially offset by higher interest income related to increased inter-company lending. Earnings at FortisAlberta were comparable quarter over quarter. The impact of a higher allowed ROE and equity component, compared to those reflected in FortisAlberta's earnings for the second quarter of 2009, combined with growth in electrical infrastructure investment and customers was mainly offset by lower corporate income tax recoveries and lower net transmission revenue.

March 2010/March 2009 - Net earnings attributable to common equity shareholders were $100 million, or $0.58 per common share, for the first quarter of 2010 compared to earnings of $92 million, or $0.54 per common share, for the first quarter of 2009. The increase in earnings was led by the Terasen Gas companies associated with an increase in the allowed ROEs and equity component. Results also reflected: (i) improved performance at FortisAlberta, associated with an increase in the allowed ROE and equity component combined with growth in electrical infrastructure investment and customers; and (ii) increased earnings at Newfoundland Power, mainly due to growth in electrical infrastructure investment, increased electricity sales and timing differences favourably impacting operating expenses during the quarter. Earnings' growth was tempered by: (i) lower earnings' contribution from non-regulated hydroelectric generation operations due to loss of earnings subsequent to the expiration of the Rankine water rights in April 2009; (ii) lower contribution from Caribbean Regulated Electric Utilities associated with the unfavourable impact of foreign exchange translation, and earnings in the first quarter of 2009 including an approximate $1 million one-time gain; and (iii) higher preference share dividends.

December 2009/December 2008 - Net earnings attributable to common equity shareholders were $81 million, or $0.48 per common share, for the fourth quarter of 2009 compared to earnings of $76 million, or $0.48 per common share, for the fourth quarter of 2008. Fourth quarter results for 2009 were favourably impacted by a one-time $3 million adjustment to future income taxes related to prior periods at FortisOntario and were unfavourably impacted by a one-time $5 million after-tax provision for additional costs related to the conversion of Whistler customer appliances from propane to natural gas. Fourth quarter results for 2008 included two additional months of earnings' contribution from Caribbean Utilities (August and September 2008) of approximately $2 million due to a change in the utility's fiscal year end. Excluding the above one-time items, earnings increased $9 million quarter over quarter. The increase was driven by: (i) the approximate $10 million cumulative retroactive impact in the fourth quarter of 2009 associated with the increase in the allowed ROEs for 2009 for FortisAlberta and TGI, and an increase in the equity component at FortisAlberta; and (ii) a change in depreciation estimates at Fortis Turks and Caicos, which favourably impacted amortization expense for the fourth quarter of 2009. The increase was partially offset by lower earnings' contribution from non-regulated hydroelectric generation operations due to loss of earnings subsequent to the expiration of the Rankine water rights in April 2009.

September 2009/September 2008 - Net earnings attributable to common equity shareholders were $36 million, or $0.21 per common share, for the third quarter of 2009 compared to earnings of $49 million, or $0.31 per common share, for the third quarter of 2008. Third quarter 2008 results included a tax reduction of approximately $7.5 million associated with the settlement of historical corporate tax matters at Terasen and a $4.5 million recovery of future income taxes, which was previously expensed during the first half of 2008 at FortisAlberta. Earnings were $1 million lower quarter over quarter, excluding the above one-time tax reductions. The impact of lower effective corporate income taxes at the Terasen Gas companies and growth in electrical infrastructure investment and higher net transmission revenue at FortisAlberta was more than offset by lower earnings from non-regulated hydroelectric generation and lower earnings at Newfoundland Power. The decrease in earnings from non-regulated hydroelectric generation operations was primarily associated with the loss of earnings subsequent to the expiration of the Rankine water rights in April 2009. Lower earnings at Newfoundland Power were largely associated with higher operating expenses and amortization costs.

OUTLOOK

The Corporation's significant capital program, which is expected to be approximately $1.1 billion in 2010 and approach $5 billion over the five-year period from 2010 through 2014, should drive growth in earnings and dividends.

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

OUTSTANDING SHARE DATA

As at August 3, 2010, the Corporation had issued and outstanding 172.9 million common shares; 5.0 million First Preference Shares, Series C; 8.0 million First Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; and 10.0 million First Preference Shares, Series H. Only the common shares of the Corporation have voting rights.

The number of common shares of Fortis that would be issued if all outstanding stock options, convertible debt and First Preference Shares, Series C and E were converted as at August 3, 2010 is as follows:

Potential Conversion of Securities into Common Shares (Unaudited) As at August 3, 2010Security	Number of Common Shares(millions)
Stock Options	5.2
Convertible Debt	1.4
First Preference Shares, Series C	4.4
First Preference Shares, Series E	7.2
Total	18.2

Additional information, including the Fortis 2009 Annual Information Form, Management Information Circular and Annual Report, is available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.

FORTIS INC.

Interim Consolidated Financial Statements

For the three and six months ended June 30, 2010 and 2009

(Unaudited)





Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
	June 30,		December 31,
	2010		2009
			(Notes 2 & 21)
ASSETS

Current assets
Cash and cash equivalents	$	71	$	85
Accounts receivable		517		595
Prepaid expenses		15		16
Regulatory assets (Note 5)		256		223
Inventories (Note 6)		144		178
Future income taxes		17		29
		1,020		1,126

Other assets		170		174
Regulatory assets (Note 5)		783		747
Future income taxes		23		17
Utility capital assets		7,939		7,697
Income producing properties		560		559
Intangible assets		272		282
Goodwill		1,562		1,560

	$	12,329	$	12,162

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
Short-term borrowings (Note 19)	$	219	$	415
Accounts payable and accrued charges		805		852
Dividends payable		52		3
Income taxes payable		20		23
Regulatory liabilities (Note 5)		46		53
Current installments of long-term debt and capital lease obligations (Note 7)		158		224
Future income taxes		8		24
		1,308		1,594

Other liabilities		306		295
Regulatory liabilities (Note 5)		474		444
Future income taxes		591		570
Long-term debt and capital lease obligations (Note 7)		5,365		5,276
Preference shares		320		320
		8,364		8,499

Shareholders' equity
Common shares (Note 8)		2,537		2,497
Preference shares (Note 9)		592		347
Contributed surplus		12		11
Equity portion of convertible debentures		5		5
Accumulated other comprehensive loss (Note 11)		(79)		(83)
Retained earnings		773		763
		3,840		3,540
Non-controlling interests		125		123
		3,965		3,663

	$	12,329	$	12,162

Contingent liabilities and commitments (Note 20)

See accompanying Notes to Interim Consolidated Financial Statements

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

		Quarter Ended						Six Months Ended
		2010			2009			2010			2009
					(Note 2)						(Note 2)

Revenue		$	836		$	756		$	1,912		$	1,958

Expenses
	Energy supply costs		367			319			919			1,026
	Operating		202			189			404			382
	Amortization		98			92			195			183
			667			600			1,518			1,591

Operating income			169			156			394			367


Finance charges (Note 13)			88			88			178			176

Earnings before corporate taxes			81			68			216			191

Corporate taxes (Note 14)			15			7			43			32

Net earnings		$	66		$	61		$	173		$	159

Net earnings attributable to:
	Non-controlling interests	$	3		$	3		$	4		$	5
	Preference equity shareholders		8			5			14			9
	Common equity shareholders		55			53			155			145
		$	66		$	61		$	173		$	159

Earnings per common share (Note 8)
	Basic	$	0.32		$	0.31		$	0.90		$	0.85
	Diluted	$	0.32		$	0.31		$	0.88		$	0.83


See accompanying Notes to Interim Consolidated Financial Statements




Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)

			Quarter Ended						Six Months Ended
			2010			2009			2010			2009
						(Note 2	)					(Note 2	)

Balance at beginning of period		$	767		$	682		$	763		$	634
Net earnings attributable to common and preference equity shareholders			63			58			169			154
			830			740			932			788

Dividends on common shares			(49	)		(44	)		(145	)		(88	)
Dividends on preference shares classified as equity			(8	)		(5	)		(14	)		(9	)

Balance at end of period		$	773		$	691		$	773		$	691

See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)

		Quarter Ended						Six Months Ended
		2010			2009			2010			2009
					(Note 2)						(Note 2)

Net earnings		$	66		$	61		$	173		$	159

Other comprehensive income (loss)
Unrealized foreign currency translation gains (losses) on net investments in self-sustaining foreign operations			28			(52	)		8			(28	)
(Losses) gains on hedges of net investments in self-sustaining foreign operations			(19	)		40			(5	)		22
Corporate tax recovery (expense)			3			(6	)		1			(3	)
Unrealized foreign currency translation gains (losses), net of hedging activities and tax (Note 11)			12			(18	)		4			(9	)

Gain on derivative instruments designated as cash flow hedges, net of tax (Note 11)			-			1			-			1

Comprehensive income		$	78		$	44		$	177		$	151

Comprehensive income attributable to:
	Non-controlling interests	$	3		$	3		$	4		$	5
	Preference equity shareholders		8			5			14			9
	Common equity shareholders		67			36			159			137
		$	78		$	44		$	177		$	151


See accompanying Notes to Interim Consolidated Financial Statements

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

			Quarter Ended						Six Months Ended
			2010			2009			2010			2009
						(Note 2)						(Note 2)
Operating activities
	Net earnings		$	66		$	61		$	173		$	159
	Items not affecting cash:
		Amortization - utility capital assets and income producing properties		88			81			174			160
		Amortization - intangible assets		9			9			20			20
		Amortization - other		1			2			1			3
		Future income taxes		2			4			(1	)		7
		Other		(2	)		(4	)		(3	)		(7	)
	Change in long-term regulatory assets and liabilities			(4	)		14			-			23
				160			167			364			365
	Change in non-cash operating working capital			44			108			89			139
				204			275			453			504

Investing activities
	Change in other assets and other liabilities			1			2			3			(5	)
	Capital expenditures - utility capital assets			(234	)		(264	)		(413	)		(474	)
	Capital expenditures - income producing properties			(3	)		(6	)		(9	)		(11	)
	Capital expenditures - intangible assets			(7	)		(7	)		(10	)		(11	)
	Contributions in aid of construction			14			10			24			26
	Business acquisition			-			(7	)		-			(7	)
				(229	)		(272	)		(405	)		(482	)

Financing activities
	Change in short-term borrowings			55			(89	)		(126	)		(239	)
	Proceeds from long-term debt, net of issue costs			-			203			-			401
	Repayments of long-term debt and capital lease obligations			(196	)		(85	)		(212	)		(91	)
	Net borrowings under committed credit facilities			186			52			157			57
	Advances from non-controlling interests			1			-			1			-
	Issue of common shares, net of costs			16			11			39			24
	Issue of preference shares, net of costs			-			-			242			-
	Dividends
		Common shares		(49	)		(44	)		(145	)		(88	)
		Preference shares		(8	)		(5	)		(14	)		(9	)
		Subsidiary dividends paid to non-controlling interests		(2	)		(2	)		(4	)		(5	)
				3			41			(62	)		50

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

Change in cash and cash equivalents				(21	)		43			(14	)		71

Cash and cash equivalents, beginning of period				92			94			85			66

Cash and cash equivalents, end of period			$	71		$	137		$	71		$	137

Supplementary Information to Consolidated Statements of Cash Flows (Note 16)

See accompanying Notes to Interim Consolidated Financial Statements

FORTIS INC.

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

For the three and six months ended June 30, 2010 and 2009 (unless otherwise stated)

(Unaudited)

1. DESCRIPTION OF THE BUSINESS

Nature of Operations

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

The following outlines each of the Corporation's reportable segments and is consistent with the basis of segmentation as disclosed in the Corporation's 2009 annual audited consolidated financial statements.

REGULATED UTILITIES

The Corporation's interests in regulated gas and electric utilities in Canada and the Caribbean are as follows:

Regulated Gas Utilities – Canadian: Consists of the Terasen Gas companies, including Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas (Whistler) Inc.

Regulated Electric Utilities – Canadian: Consists of FortisAlberta; FortisBC; Newfoundland Power; and Other Canadian Electric Utilities, which includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power Inc., Cornwall Street Railway, Light and Power Company, Limited and, as of October 2009, Algoma Power Inc. ("Algoma Power").

Regulated Electric Utilities – Caribbean: Consists of Belize Electricity, in which Fortis holds an approximate 70 per cent controlling ownership interest; Caribbean Utilities, in which Fortis holds an approximate 59 per cent controlling ownership interest; and wholly owned Fortis Turks and Caicos, which includes P.P.C. Limited and Atlantic Equipment & Power (Turks and Caicos) Ltd.

NON-REGULATED - FORTIS GENERATION

Fortis Generation includes the financial results of non-regulated generating assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New York State.

NON-REGULATED - FORTIS PROPERTIES

Fortis Properties owns and operates 21 hotels, comprised of more than 4,100 rooms, in eight Canadian provinces and approximately 2.8 million square feet of commercial office and retail space primarily in Atlantic Canada.

CORPORATE AND OTHER

The Corporate and Other segment includes Fortis net corporate expenses, net expenses of non-regulated Terasen Inc. ("Terasen") corporate-related activities, and the financial results of Terasen's 30 per cent ownership interest in CustomerWorks Limited Partnership and of Terasen's non-regulated wholly owned subsidiary Terasen Energy Services Inc.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These interim consolidated financial statements do not include all of the information and disclosures required in the annual consolidated financial statements, and should be read in conjunction with the Corporation's 2009 annual audited consolidated financial statements. Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Because of natural gas consumption patterns, earnings of the Terasen Gas companies are highest in the first and fourth quarters. Given the diversified group of companies, seasonality may vary.

All amounts are presented in Canadian dollars unless otherwise stated.

These interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") for interim financial statements, following the same accounting policies and methods as those used in preparing the Corporation's 2009 annual audited consolidated financial statements, except as described below.

Effective January 1, 2010, as a result of the British Columbia Utilities Commission ("BCUC")-approved Negotiated Settlement Agreements ("NSAs") related to 2010 and 2011 revenue requirements, the Terasen Gas companies adopted the following new accounting policies:

Asset removal costs are now recorded in operating expenses on the consolidated statement of earnings. The annual amount of such costs approved for recovery in customer rates in 2010 is approximately $8 million. Actual costs incurred in excess of or below the approved amount are to be recorded in a regulatory deferral account for recovery from, or refund to, customers in future rates, beginning in 2012. Removal costs are direct costs incurred by the Terasen Gas companies in taking assets out of service, whether through actual removal of the assets or through the disconnection of the assets from the transmission or distribution system. For the three months ended June 30, 2010, actual asset removal costs of approximately $3 million were incurred, with $2 million recorded in operating expenses and $1 million deferred as a regulatory asset. For the six months ended June 30, 2010, actual asset removal costs of approximately $5 million were incurred, with approximately $4 million recorded in operating expenses and $1 million deferred as a regulatory asset. Prior to January 1, 2010, asset removal costs were recorded against accumulated amortization on the consolidated balance sheet.
Contributions in aid of construction ("CIACs") are now amortized to revenue. During the three and six months ended June 30, 2010, CIACs of approximately $2 million and $5 million, respectively, were amortized to revenue on the consolidated statement of earnings. Prior to January 1, 2010, amortization of CIACs was recorded against amortization expense on the consolidated statement of earnings.
Gains and losses on the sale or disposal of utility capital assets are now recorded in a regulatory deferral account on the consolidated balance sheet for recovery from, or refund to, customers in future rates, subject to regulatory approval. During the three and six months ended June 30, 2010, losses of approximately $2 million and $5 million, respectively, were deferred and recorded as a regulatory asset on the consolidated balance sheet. Prior to January 1, 2010, gains and losses on the sale or disposal of utility capital assets were recorded against accumulated amortization on the consolidated balance sheet.
Amortization of utility capital assets and intangible assets now commences the month after the assets are available for use. Prior to January 1, 2010, amortization commenced the year following when the assets became available for use. During 2010, additional amortization expense of approximately $2 million is expected to be incurred, due to the change in commencement of amortization of utility capital assets and intangible assets.

Effective January 1, 2010, the Corporation adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA").

Business Combinations

Effective January 1, 2010, the Corporation early adopted the new CICA Handbook Section 1582, Business Combinations, together with Section 1601, Consolidated Financial Statements and Section 1602, Non-Controlling Interests. As a result of adopting Section 1582, changes in the determination of the fair value of the assets and liabilities of an acquiree in a business combination results in a different calculation of goodwill with respect to acquisitions on or after January 1, 2010. Such changes include the expensing of acquisition-related costs incurred during a business acquisition, rather than recording them as a capital transaction, and the disallowance of recording restructuring accruals by the acquirer. The adoption of Section 1582 did not have a material impact on the Corporation's interim consolidated financial statements for the three and six months ended June 30, 2010.

3. FUTURE ACCOUNTING CHANGES

International Financial Reporting Standards

In October 2009, the Canadian Accounting Standards Board ("AcSB") re-confirmed that publicly accountable enterprises in Canada will be required to apply International Financial Reporting Standards ("IFRS"), in full and without modification, beginning January 1, 2011. An IFRS transition date of January 1, 2011 would require the restatement, for comparative purposes, of amounts reported on the Corporation's consolidated opening IFRS balance sheet as at January 1, 2010 and amounts reported by the Corporation for the year ended December 31, 2010.

Fortis is continuing to assess the financial reporting impacts of adopting IFRS. In July 2009, the International Accounting Standards Board ("IASB") issued the Exposure Draft - Rate-Regulated Activities. Based on the Exposure Draft, regulatory assets and liabilities arising from activities subject to cost of service regulation would be recognized under IFRS when certain conditions are met. The ability to record regulatory assets and liabilities, as proposed in the Exposure Draft, should reduce the earnings' volatility at the Corporation's regulated utilities that may otherwise result under IFRS in the absence of an accounting standard for rate-regulated activities, but will result in the requirement to provide enhanced balance sheet presentation and note disclosures. Completion of the IASB's Rate-Regulated Activities Project has been delayed based on comments received in response to the Exposure Draft and a decision by the IASB to conduct further research.

On July 23, 2010, the AcSB met to discuss the IASB's latest decisions with respect to the Rate-Regulated Activities Project. On July 28, 2010, the AcSB issued an Exposure Draft proposing that qualifying entities with rate-regulated activities be permitted, but not required, to continue applying the accounting standards in Part V of the CICA Handbook for an additional two years.

A qualifying entity would be an entity that: (i) has activities subject to rate regulation meeting the definition of that term in Generally Accepted Accounting Principles, paragraph 1100.32B, in Part V of the Handbook; and (ii) in accordance with Accounting Guideline AcG-19, Disclosures by Entities Subject to Rate Regulation, discloses that it has accounted for a transaction or event differently than it would have in the absence of rate regulation (i.e., that it has recognized regulatory assets and liabilities). The Exposure Draft also proposes that an entity choosing to defer its IFRS changeover date disclose that fact and when it will first present financial statements in accordance with IFRS.

The Exposure Draft provides a two-year deferral of the adoption of IFRS for qualifying entities based on the expectation that the IASB will complete its project on rate-regulated activities in 2011 or 2012, and gives qualifying entities sufficient time to meet the requirements of a new IFRS on rate-regulated activities in the event one is issued late in, or shortly following, what would otherwise be their year of IFRS adoption.

4. USE OF ESTIMATES

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

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the six months ended June 30, 2010, except for that described below and in Note 20 as it relates to contingencies.

5. REGULATORY ASSETS AND LIABILITIES

A summary of the Corporation's regulatory assets and liabilities is provided below. A full description of the nature of the regulatory assets and liabilities is provided in Note 4 to the Corporation's 2009 annual audited consolidated financial statements.

	As at
($ millions)	June 30, 2010		December 31, 2009
			(Note 21)
Regulatory Assets
Future income taxes	567		545
Rate stabilization accounts - Terasen Gas companies	127		82
Rate stabilization accounts - electric utilities	63		68
Alberta Electric System Operator ("AESO") charges deferral	59		80
Regulatory other post-employment benefit ("OPEB") plan asset asasset	62		59
Point Lepreau ⁽¹⁾ replacement energy deferral	34		23
Income taxes recoverable on OPEB plans	18		18
Energy management costs	17		14
Deferred development costs for capital	7		7
Southern Crossing Pipeline tax reassessment	7		7
Deferred pension costs	6		6
Lease costs	6		6
Other regulatory assets	66		55
Total Regulatory Assets	1,039		970
Less: Current Portion	(256	)	(223	)
Long-Term Regulatory Assets	783		747

⁽¹⁾ New Brunswick Power Point Lepreau Nuclear Generating Station

	As at
($ millions)	June 30, 2010		December 31, 2009
			(Note 21)
Regulatory Liabilities
Future asset removal and site restoration provision	329		326
Future income taxes	34		35
Rate stabilization accounts - Terasen Gas companies	59		44
Rate stabilization accounts - electric utilities	28		21
Performance-based rate-setting incentive liabilities	10		15
Unbilled revenue liability	9		10
Unrecognized net gains on disposal of utility capital assets ⁽¹⁾	8		8
Southern Crossing Pipeline deferral	8		9
Deferred interest	7		7
Other regulatory liabilities	28		22
Total Regulatory Liabilities	520		497
Less: Current Portion	(46	)	(53	)
Long-Term Regulatory Liabilities	474		444

⁽¹⁾Relates to amounts accumulated at the Terasen Gas companies prior to January 1, 2010 and, as approved by the regulator, reallocated from accumulated amortization for future settlement with customers (Note 2 (iii))

6. INVENTORIES

	As at
($ millions)	June 30, 2010	December 31, 2009
Gas in storage	124	159
Materials and supplies	20	19
	144	178

During the three and six months ended June 30, 2010, inventories of $191 million and $496 million, respectively, were expensed and reported in energy supply costs in the interim consolidated statement of earnings ($156 million and $624 million for the three and six months ended June 30, 2009, respectively). Inventories expensed to operating expenses were $4 million and $7 million for the three and six months ended June 30, 2010, respectively ($4 million and $7 million for the three and six months ended June 30, 2009, respectively). Included in inventories expensed to operating expenses was food and beverage costs at Fortis Properties of $3 million and $5 million for the three and six months ended June 30, 2010, respectively ($2 million and $4 million for the three and six months ended June 30, 2009, respectively).

7. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

		As at
($ millions)		June 30, 2010		December 31, 2009
Long-term debt and capital lease obligations		5,139		5,331
Long-term classification of committed credit facilities (Note 19)		422		208
Deferred debt financing costs		(38	)	(39	)
Total long-term debt and capital lease obligations		5,523		5,500
Less:	Current installments of long-term debt and capital lease obligations	(158	)	(224	)
		5,365		5,276

In April 2010, Terasen redeemed in full for cash its $125 million 8.0% Capital Securities with proceeds from borrowings under the Corporation's committed credit facility.

8. COMMON SHARES

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

	As at
Issued and Outstanding	June 30, 2010		December 31, 2009
	Number of Shares (in thousands)	Amount ($ millions)	Number of Shares (in thousands)	Amount($ millions)
Common shares	172,865	2,537	171,256	2,497





Common shares issued during the period were as follows:

		Quarter Ended June 30, 2010		Year-to-Date June 30, 2010
		Number of Shares (in thousands)	Amount ($ millions)	Number of Shares(in thousands)	Amount ($ millions)
Balance, beginning of period		172,169	2,520	171,256	2,497
	Consumer Share Purchase Plan	14	1	28	1
	Dividend Reinvestment Plan	503	13	1,071	28
	Employee Share Purchase Plan	65	1	193	5
	Stock Option Plans	114	2	317	6
Balance, end of period		172,865	2,537	172,865	2,537

Earnings per Common Share

The Corporation calculates earnings per common share on the weighted average number of common shares outstanding.

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

Earnings per common share were as follows:

		Quarter Ended June 30
		2010					2009
		Earnings ($ millions)		Weighted Average Shares (in millions)		Earnings per Common Share	Earnings ($ millions)		Weighted Average Shares (in millions)		Earnings per Common Share
Basic Earnings per Common Share		55		172.4		$0.32	53		170.0		$0.31
Effect of potential dilutive securities:
	Stock options	-		0.9			-		0.7
	Preference shares (Note 13)	4		11.9			4		13.9
	Convertible debentures	1		1.4			1		1.4
		60		186.6			58		186.0
Deduct anti-dilutive impacts:
	Preference shares	(4	)	(11.9	)		(2	)	(5.3	)
	Convertible debentures	(1	)	(1.4	)		(1	)	(1.4	)
Diluted Earnings per Common Share		55		173.3		$0.32	55		179.3		$0.31





		Year-to-Date June 30
		2010			2009
		Earnings ($ millions)	Weighted Average Shares (in millions)	Earnings per Common Share	Earnings ($ millions)		Weighted Average Shares (in millions)		Earnings per Common Share
Basic Earnings per Common Share		155	172.0	$0.90	145		169.7		$0.85
Effect of potential dilutive securities:
	Stock options	-	0.9		-		0.7
	Preference shares (Note 13)	8	11.9		8		13.9
	Convertible debentures	1	1.4		1		1.4
		164	186.2		154		185.7
Deduct anti-dilutive impacts:
Convertible debentures		-	-		(1	)	(1.4	)
Diluted Earnings per Common Share		164	186.2	$0.88	153		184.3		$0.83

9. PREFERENCE SHARES

In January 2010, the Corporation issued 10 million Cumulative Five-Year Fixed Rate Reset First Preference Shares, Series H ("First Preference Shares, Series H"). The First Preference Shares, Series H were issued at $25.00 per share. The shares are entitled to receive fixed cumulative preferential cash dividends at a rate of $1.0625 per share per annum for each year up to but excluding June 1, 2015. For each five-year period after that date, the holders of First Preference Shares, Series H are entitled to receive reset fixed cumulative preferential cash dividends. The reset annual dividends per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 1.45 per cent.

On each First Preference Shares, Series H Conversion Date, being June 1, 2015 and June 1^st every five years thereafter, the Corporation has the option to redeem for cash all or any part of the outstanding First Preference Shares, Series H, at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. On each Series H Conversion Date, the holders of First Preference Shares, Series H, have the option to convert any or all of their First Preference Shares, Series H into an equal number of cumulative redeemable floating rate First Preference Shares, Series I.

The holders of First Preference Shares, Series I will be entitled to receive floating rate cumulative preferential cash dividends in the amount per share determined by multiplying the applicable floating quarterly dividend rate by $25.00. The floating quarterly dividend rate will be equal to the sum of the average yield expressed as a percentage per annum on three-month Government of Canada Treasury Bills plus 1.45 per cent.

On each First Preference Shares, Series I Conversion Date, being June 1, 2020 and June 1^st every five years thereafter, the Corporation has the option to redeem for cash all or any part of the outstanding First Preference Shares, Series I at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. On any date after June 1, 2015, that is not a Series I Conversion Date, the Corporation has the option to redeem for cash all or any part of the outstanding First Preference Shares, Series I at a price of $25.50 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. On each Series I Conversion Date, the holders of First Preference Shares, Series I, have the option to convert any or all of their First Preference Shares, Series I into an equal number of First Preference Shares, Series H.

On any Series H Conversion Date, if the Corporation determines that there would be less than 1 million First Preference Shares, Series H outstanding, such remaining First Preference Shares, Series H will automatically be converted into an equal number of First Preference Shares, Series I. On any Series I Conversion Date, if the Corporation determines that there would be less than 1 million First Preference Shares, Series I outstanding, such remaining First Preference Shares, Series I will automatically be converted into an equal number of First Preference Shares, Series H. However, if such automatic conversions would result in less than 1 million Series I First Preference Shares or less than 1 million Series H First Preference Shares outstanding, then no automatic conversion would take place.

As the First Preference Shares, Series H are not redeemable at the option of the shareholder, they are classified as equity.

10. STOCK-BASED COMPENSATION PLANS

In January 2010, 24,426 Deferred Share Units were granted to the Corporation's Board of Directors, representing the equity component of the Directors' annual compensation and, where opted, their annual retainers in lieu of cash. Each Deferred Share Unit represents a unit with an underlying value equivalent to the value of one common share of the Corporation.

In March 2010, 60,000 Performance Share Units were granted to the President and Chief Executive Officer ("CEO") of the Corporation. Each Performance Share Unit ("PSU") represents a unit with an underlying value equivalent to the value of one common share of the Corporation. The maturation period of the March 2010 PSU grant is three years, at which time a cash payment may be made to the President and CEO after evaluation by the Human Resources Committee of the Board of Directors of Fortis of the achievement of payment requirements. In May 2010, 21,742 PSUs were paid out to the President and CEO of the Corporation at $27.48 per PSU, for a total of approximately $0.6 million. The payout was made upon the three-year maturation period in respect of the PSU grant made in May 2007 and the President and CEO satisfying the payment requirements, as determined by the Human Resources Committee of the Board of Directors of Fortis.

In March 2010, the Corporation granted 892,744 options to purchase common shares under its 2006 Stock Option Plan at the five-day volume weighted average trading price of $27.36 immediately preceding the date of grant. The options vest evenly over a four-year period on each anniversary of the date of grant. The options expire seven years after the date of grant. The fair value of each option granted was $4.41 per option.

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

	Dividend yield (%)	3.66
	Expected volatility (%)	25.1
	Risk-free interest rate (%)	2.54
	Weighted average expected life (years)	4.5

As at June 30, 2010, 5.2 million stock options were outstanding and 3.0 million stock options were vested.

11. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss includes unrealized foreign currency translation gains and losses, net of hedging activities, gains and losses on cash flow hedging activities and gains and losses on discontinued cash flow hedging activities as described in Note 2 to the Corporation's 2009 annual audited consolidated financial statements.

	Quarter Ended June 30
	2010					2009
($ millions)	Opening balance April 1		Net change	Ending balance June 30		Opening balance April 1		Net change		Ending balance June 30
Unrealized foreign currency translation (losses) gains, net of hedging activities and tax	(86	)	12	(74	)	(37	)	(18	)	(55	)
(Losses) gains on derivative instruments designated as cash flow hedges, net of tax	-		-	-		(1	)	1		-
Net losses on derivative instruments previously discontinued as cash flow hedges, net of tax	(5	)	-	(5	)	(5	)	-		(5	)
Accumulated Other Comprehensive (Loss) Income	(91	)	12	(79	)	(43	)	(17	)	(60	)





	Year-to-Date June 30
	2010					2009
($ millions)	Opening balance January 1		Net change	Ending balance June 30		Opening balance January 1		Net change		Ending balance June 30
Unrealized foreign currency translation (losses) gains, net of hedging activities and tax	(78	)	4	(74	)	(46	)	(9	)	(55	)
(Losses) gains on derivative instruments designated as cash flow hedges, net of tax	-		-	-		(1	)	1		-
Net losses on derivative instruments previously discontinued as cash flow hedges, net of tax	(5	)	-	(5	)	(5	)	-		(5	)
Accumulated Other Comprehensive (Loss) Income	(83	)	4	(79	)	(52	)	(8	)	(60	)

12. EMPLOYEE FUTURE BENEFITS

The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, OPEB plans, defined contribution pension plans and group registered retirement savings plans ("RRSPs") for its employees. The cost of providing the defined benefit arrangements was $10 million for the quarter ended June 30, 2010 ($7 million for the quarter ended June 30, 2009) and $20 million year-to-date June 30, 2010 ($13 million year-to-date June 30, 2009). The cost of providing the defined contribution arrangements and group RRSPs for the quarter ended June 30, 2010 was $3 million ($2 million for the quarter ended June 30, 2009) and $7 million year-to-date June 30, 2010 ($6 million year-to-date June 30, 2009).

13. FINANCE CHARGES

		Quarter Ended June 30				Year-to-Date June 30
($ millions)		2010		2009		2010		2009
Interest	- Long-term debt and capital lease obligations	88		86		176		170
	- Short-term borrowings and other	1		2		3		6
Interest charged to construction		(5	)	(4	)	(9	)	(8	)
Dividends on preference shares classified as debt (Note 8)		4		4		8		8
		88		88		178		176

14. CORPORATE TAXES

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

	Quarter Ended June 30				Year-to-Date June 30
($ millions, except as noted)	2010		2009		2010		2009
Combined Canadian federal and provincial statutory income tax rate	32.0	%	33.0	%	32.0	%	33.0	%
Statutory income tax rate applied to earnings before corporate taxes	26		22		69		63
Preference share dividends	2		2		3		3
Difference between Canadian statutory rate and rates applicable to foreign subsidiaries	(5	)	(4	)	(7	)	(7	)
Difference in Canadian provincial statutory rates applicable to subsidiaries in different Canadian jurisdictions	(2	)	(1	)	(6	)	(4	)
Items capitalized for accounting but expensed for income tax purposes	(8	)	(10	)	(20	)	(20	)
Pension costs	1		-		1		(1	)
Other	1		(2	)	3		(2	)
Corporate taxes	15		7		43		32
Effective tax rate	18.5	%	10.3	%	19.9	%	16.8	%

As at June 30, 2010, the Corporation had approximately $143 million (December 31, 2009 - $122 million) in non-capital and capital loss carryforwards, of which $13 million (December 31, 2009 - $16 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2014 and 2030.

15. SEGMENTED INFORMATION

Information by reportable segment is as follows:

	REGULATED								NON-REGULATED
	Gas Uti- lities	Electric Utilities
Quarter Ended	Tera- sen Gas						Total						Inter-
June 30, 2010	Compa- nies -	Fortis		Fortis	NF	Other	Elec- tric	Elec- tric	Fortis	Fortis	Corpo- rate		seg- ment
($ millions)	Cana- dian	Alber- ta		BC	Power	Cana- dian ⁽¹⁾	Cana- dian	Carib- bean	Gene- ration ⁽²⁾	Proper- ties	and Other		elimi-nations		Conso- lidated
Revenue	337	92		59	126	75	352	83	8	60	9		(13	)	836
Energy supply costs	191	-		13	75	46	134	47	1	-	-		(6	)	367
Operating expenses	65	36		19	15	11	81	11	2	39	6		(2	)	202
Amortization	29	25		11	12	6	54	9	1	4	1		-		98
Operating income	52	31		16	24	12	83	16	4	17	2		(5	)	169
Finance charges	29	14		8	9	5	36	4	-	6	18		(5	)	88
Corporate taxes (recoveries)	6	-		-	4	3	7	2	1	3	(4	)	-		15
Net earnings (loss)	17	17		8	11	4	40	10	3	8	(12	)	-		66
Non-controlling interests	-	-		-	-	-	-	3	-	-	-		-		3
Preference share dividends	-	-		-	-	-	-	-	-	-	8		-		8
Net earnings (loss) attributable to common equity shareholders	17	17		8	11	4	40	7	3	8	(20	)	-		55

Goodwill	908	227		221	-	63	511	143	-	-	-		-		1,562
Identifiable assets	4,073	1,977		1,189	1,192	630	4,988	828	195	581	122		(20	)	10,767
Total assets	4,981	2,204		1,410	1,192	693	5,499	971	195	581	122		(20	)	12,329
Gross capital expenditures ⁽³⁾	60	89		37	19	13	158	19	2	4	1		-		244

Quarter Ended
June 30, 2009
($ millions)
Revenue	289	81		55	119	65	320	82	9	58	7		(9	)	756
Energy supply costs	156	-		13	70	40	123	44	1	-	-		(5	)	319
Operating expenses	62	31		17	13	9	70	14	2	38	4		(1	)	189
Amortization	26	23		9	11	5	48	10	2	4	2		-		92
Operating income	45	27		16	25	11	79	14	4	16	1		(3	)	156
Finance charges	29	13		8	9	4	34	4	1	5	18		(3	)	88
Corporate taxes (recoveries)	2	(3	)	1	5	3	6	-	-	3	(4	)	-		7
Net earnings (loss)	14	17		7	11	4	39	10	3	8	(13	)	-		61
Non-controlling interests	-	-		-	-	-	-	3	-	-	-		-		3
Preference share dividends	-	-		-	-	-	-	-	-	-	5		-		5
Net earnings (loss) attributable to common equity shareholders	14	17		7	11	4	39	7	3	8	(18	)	-		53

Goodwill	908	227		221	-	63	511	154	-	-	-		-		1,573
Identifiable assets	3,838	1,767		1,137	1,156	526	4,586	847	192	577	141		(17	)	10,164
Total assets	4,746	1,994		1,358	1,156	589	5,097	1,001	192	577	141		(17	)	11,737
Gross capital expenditures ⁽³⁾	64	116		27	19	11	173	30	4	5	1		-		277

(1) Includes Algoma Power from October 2009, the date of acquisition by FortisOntario
(2) Results reflect the expiry, on April 30, 2009, at the end of a 100-year term, of the 75 MW of water-right entitlement associated with the Rankine hydroelectric generating facility at Niagara Falls.
(3) Relates to utility capital assets, including amounts for AESO transmision capital projects, and to income producing properties and intangible assets, as reflected in the consolidated statement of cash flows





	REGULATED								NON-REGULATED
	Gas Uti- lities	Electric Utilities
Year-to-Date	Tera- sen Gas						Total						Inter-
June 30, 2010	Compa- nies -	Fortis		Fortis	NF	Other	Elec- tric	Elec- tric	Fortis	Fortis	Corpo- rate		seg- ment
($ millions)	Cana- dian	Alber- ta		BC	Power	Cana- dian⁽¹⁾	Cana- dian	Carib- bean	Gene- ration⁽²⁾	Proper- ties	and Other		elimina- tions		Conso- lidated
Revenue	866	180		131	304	157	772	159	13	109	15		(22	)	1,912
Energy supply costs	496	-		34	206	99	339	92	1	-	-		(9	)	919
Operating expenses	135	71		36	31	22	160	23	4	75	10		(3	)	404
Amortization	59	49		21	23	11	104	18	2	8	4		-		195
Operating income	176	60		40	44	25	169	26	6	26	1		(10	)	394
Finance charges	56	28		16	18	11	73	9	-	12	38		(10	)	178
Corporate taxes (recoveries)	30	-		2	8	5	15	2	1	4	(9	)	-		43
Net earnings (loss)	90	32		22	18	9	81	15	5	10	(28	)	-		173
Non-controlling interests	-	-		-	-	-	-	4	-	-	-		-		4
Preference share dividends	-	-		-	-	-	-	-	-	-	14		-		14
Net earnings (loss) attributable to common equity shareholders	90	32		22	18	9	81	11	5	10	(42	)	-		155

Goodwill	908	227		221	-	63	511	143	-	-	-		-		1,562
Identifiable assets	4,073	1,977		1,189	1,192	630	4,988	828	195	581	122		(20	)	10,767
Total assets	4,981	2,204		1,410	1,192	693	5,499	971	195	581	122		(20	)	12,329
Gross capital expenditures ⁽³⁾	110	153		63	36	21	273	36	3	9	1		-		432

Year-to-Date
June 30, 2009
($ millions)
Revenue	958	161		127	288	136	712	165	25	105	13		(20	)	1,958
Energy supply costs	624	-		35	197	87	319	90	2	-	-		(9	)	1,026
Operating expenses	129	65		34	27	17	143	28	6	72	7		(3	)	382
Amortization	51	45		19	22	9	95	20	4	8	5		-		183
Operating income	154	51		39	42	23	155	27	13	25	1		(8	)	367
Finance charges	61	24		15	17	9	65	8	2	11	37		(8	)	176
Corporate taxes (recoveries)	21	(3	)	3	8	5	13	1	2	4	(9	)	-		32
Net earnings (loss)	72	30		21	17	9	77	18	9	10	(27	)	-		159
Non-controlling interests	-	-		-	-	-	-	5	-	-	-		-		5
Preference share dividends	-	-		-	-	-	-	-	-	-	9		-		9
Net earnings (loss) attributable to common equity shareholders	72	30		21	17	9	77	13	9	10	(36	)	-		145

Goodwill	908	227		221	-	63	511	154	-	-	-		-		1,573
Identifiable assets	3,838	1,767		1,137	1,156	526	4,586	847	192	577	141		(17	)	10,164
Total assets	4,746	1,994		1,358	1,156	589	5,097	1,001	192	577	141		(17	)	11,737
Gross capital expenditures ⁽³⁾	114	206		49	32	23	310	50	11	10	1		-		496

⁽¹⁾ Includes Algoma Power from October 2009, the date of acquisition by FortisOntario
⁽²⁾Results reflect the expiry, on April 30, 2009, at the end of a 100-year term, of the 75 MW of water-right entitlement associated with the Rankine hydroelectric generating facility at Niagara Falls.
⁽³⁾Relates to utility capital assets, including amounts for AESO transmision capital projects, and to income producing properties and intangible assets, as reflected in the consolidated statement of cash flows

Inter-segment transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The significant inter-segment transactions primarily related to the sale of energy from Fortis Generation to Belize Electricity and FortisOntario, electricity sales from Newfoundland Power to Fortis Properties and finance charges on inter-segment borrowings. The significant inter-segment transactions for the three and six months ended June 30, 2010 and 2009 were as follows.

Significant Inter-Segment Transactions		Quarter Ended June 30		Year-to-date June 30
($ millions)		2010	2009	2010	2009
Sales from Fortis Generation to Regulated Electric Utilities – Caribbean		5	4	8	8
Sales from Fortis Generation to Other Canadian Electric Utilities		1	1	1	1
Sales from Newfoundland Power to Fortis Properties		1	1	2	2
Inter-segment finance charges on borrowings from:
	Corporate to Regulated Electric Utilities – Canadian	-	-	-	1
	Corporate to Regulated Electric Utilities – Caribbean	1	-	2	1
	Corporate to Fortis Generation	1	1	2	2
	Corporate to Fortis Properties	3	2	5	4

16. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

	Quarter Ended June 30		Year-to-date June 30
($ millions)	2010	2009	2010	2009
Interest paid	104	99	194	184
Income taxes paid	13	15	37	80

17. CAPITAL MANAGEMENT

The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow the utilities to fund the maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions with proceeds from common and preference share issuances. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40 per cent equity, including preference shares, and 60 per cent debt, as well as investment-grade credit ratings.

Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in the utilities' customer rates.

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

	As at
	June 30, 2010		December 31, 2009
	($ millions)	(%)	($ millions)	(%)
Total debt and capital lease obligations (net of cash) ⁽¹⁾	5,671	57.7	5,830	60.2
Preference shares ⁽²⁾	912	9.3	667	6.9
Common shareholders' equity	3,248	33.0	3,193	32.9
Total ⁽³⁾	9,831	100.0	9,690	100.0
(1) Includes long-term debt and capital lease obligations, including current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities and equity
(3) Excludes amounts related to non-controlling interests

Certain of the Corporation's long-term debt obligations have covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70 per cent of the Corporation's consolidated capital structure, as defined by the long-term debt agreements. As at June 30, 2010, the Corporation and its subsidiaries, except for certain debt at Belize Electricity and the Exploits Partnership, as described below, were in compliance with their debt covenants.

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

18. FINANCIAL INSTRUMENTS

Fair Values

There has been no change during the six months ended June 30, 2010 in the designation of the Corporation's financial instruments from that disclosed in the Corporation's 2009 annual audited consolidated financial statements. The carrying values of financial instruments included in current assets, current liabilities, other assets and other liabilities in the consolidated balance sheets of Fortis approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or the nature of these instruments. The carrying and fair values of the Corporation's consolidated long-term debt and preference shares were as follows:

	As at
	June 30, 2010		December 31, 2009
($ millions)	Carrying Value	Estimated Fair Value	Carrying Value	Estimated Fair Value
Long-term debt, including current portion ^{(1) (2)}	5,523	6,160	5,502	5,906
Preference shares, classified as debt ^{(1) (3)}	320	340	320	348

(1) Carrying value is measured at amortized cost using the effective interest rate method.

(2) Carrying value as at June 30, 2010 excludes unamortized deferred financing costs of $38 million (December 31, 2009 - $39 million) and capital lease obligations of $38 million (December 31, 2009 - $37 million).

(3) Preference shares classified as equity are excluded from the requirements of the CICA Handbook Section 3855, Financial Instrument, Recognition and Measurement; however, the estimated fair value of the Corporation's $592 million preference shares classified as equity was $595 million as at June 30, 2010 (December 31, 2009 – carrying value $347 million; fair value $356 million).

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

		As at
		June 30, 2010						December, 31, 2009
Asset (Liability)		Term to Maturity (years)	Number of Contracts	Carrying Value ($ millions)		Estimated Fair Value ($ millions)		Carrying Value ($ millions)		Estimated Fair Value ($ millions)
Interest rate swap ^{(1) (2)}		<1	1	-		-		-		-
Foreign exchange forward contracts ^{(3) (4)}		1 to 2	2	1		1		-		-
Natural gas derivatives: ^{(3) (5)}
	Swaps and options	Up to 4	193	(156	)	(156	)	(119	)	(119	)
	Gas purchase contract premiums	Up to 3	47	(4	)	(4	)	(3	)	(3	)

(1) Interest rate swap contract matures in October 2010.

(2) The contract has the effect of fixing the rate of interest on the non-revolving credit facilities of Fortis Properties at 5.32 per cent. The fair value measurements are Level 1, based on the three levels that distinguish the level of pricing observability utilized in measuring fair value.

(3) The fair value measurements are Level 2, based on the three levels that distinguish the level of pricing observability utilized in measuring fair value.

(4) The fair values of the foreign exchange forward contracts were recorded in accounts receivable as at June 30, 2010 and as at December 31, 2009.

(5) The fair values of the natural gas derivatives were recorded in accounts payable as at June 30, 2010 and as at December 31, 2009.

19. FINANCIAL RISK MANAGEMENT

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

Credit risk	Risk that a third party to a financial instrument might fail to meet its obligations under the terms of the financial instrument.
Liquidity risk	Risk that an entity will encounter difficulty in raising funds to meet commitments associated with financial instruments.
Market risk	Risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices. The Corporation is exposed to foreign exchange risk, interest rate risk and commodity price risk.

Credit Risk

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

FortisAlberta has a concentration of credit risk as a result of its distribution-service billings being to a relatively small group of retailers and, as at June 30, 2010, its gross credit risk exposure was approximately $98 million, representing the projected value of retailer billings over a 60-day period. The Company has reduced its exposure to approximately $3 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.

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

The aging analysis of the Corporation's consolidated trade and other accounts receivable, net of an allowance for doubtful accounts of $17 million as at June 30, 2010 (March 31, 2010 - $17 million; December 31, 2009 - $17 million; June 30, 2009 - $18 million), excluding derivative financial instruments recorded in accounts receivable, was as follows:

($ millions)	As at
($ millions)	June 30, 2010	March 31, 2010	December 31, 2009	June 30, 2009
Not past due	442	518	527	366
Past due 0-30 days	49	63	52	51
Past due 31-60 days	14	14	8	18
Past due 61 days and over	11	9	8	10
	516	604	595	445

As at June 30, 2010, other receivables due from customers of $6 million (included in other assets) will be received over the next five years and, thereafter, with $1 million expected to be received in year 1, $3 million over years 2 and 3, $1 million over years 4 and 5 and $1 million due after 5 years.

Liquidity Risk

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

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

The Corporation's committed credit facility is available for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at June 30, 2010, average annual consolidated long-term debt maturities and repayments over the next five years are expected to be approximately $300 million. The combination of available credit facilities and relatively low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

As at June 30, 2010, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.1 billion, of which $1.4 billion was unused. The credit facilities are syndicated almost entirely with the seven largest Canadian banks, with no one bank holding more than 25 per cent of these facilities.

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

($ millions)								As at
($ millions)		Corporate and Other		Regulated Utilities		Fortis Properties		June 30, 2010		December 31, 2009
Total credit facilities		645		1,455		13		2,113		2,153
Credit facilities utilized:
	Short-term borrowings	-		(218	)	(1	)	(219	)	(415	)
	Long-term debt (including current portion) (Note 7)	(197	)	(225	)	-		(422	)	(208	)
Letters of credit outstanding		(1	)	(111	)	-		(112	)	(100	)
Credit facilities unused		447		901		12		1,360		1,430

The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at June 30, 2010, the Corporation's credit ratings were as follows.

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

The credit ratings reflect the Corporation's low business risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, management's commitment to maintaining low levels of debt at the holding company level and the significant reduction in external debt at Terasen, the Corporation's strong credit metrics, and the Corporation's demonstrated ability and continued focus of acquiring and integrating stable regulated utility businesses financed on a conservative basis.

The following is an analysis of the contractual maturities of the Corporation's consolidated financial liabilities as at June 30, 2010.

Financial Liabilities($ millions)	Due within 1 year	Due in years 2 and 3	Due in years 4 and 5	Due after 5 years	Total
Short-term borrowings	219	-	-	-	219
Trade and other accounts payable	645	-	-	-	645
Natural gas derivatives ⁽¹⁾	102	44	8	-	154
Foreign exchange forward contracts ⁽²⁾	12	5	-	-	17
Dividends payable	52	-	-	-	52
Customer deposits ⁽³⁾	2	2	1	2	7
Long-term debt, including current portion ⁽⁴⁾	156	561	773	4,033	5,523
Interest obligations on long-term debt	330	641	597	4,576	6,144
Preference shares, classified as debt	-	-	123	197	320
Preference share dividend obligations classified as finance charges	17	33	21	11	82
	1,535	1,286	1,523	8,819	13,163

(1)	Amounts disclosed are on a gross cash flow basis. The derivatives were recorded in accounts payable at fair value as at June 30, 2010 at $160 million.
(2)	Amounts disclosed are on a gross cash flow basis. The contracts were recorded in accounts receivable at fair value as at June 30, 2010 at $1 million.
(3)	Customer deposits were recorded in other liabilities as at June 30, 2010.
(4)	Excludes deferred financing costs of $38 million and capital lease obligations of $38 million

Market Risk

Foreign Exchange Risk

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

As at June 30, 2010, the Corporation's corporately held US$390 million (December 31, 2009 - US$390 million) long-term debt had been designated as a hedge of a portion of the Corporation's foreign net investments.

As at June 30, 2010, the Corporation had approximately US$187 million (December 31, 2009 – US$174 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately held US dollar borrowings that are designated as hedges are recorded in other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the foreign net investments, which are also recorded in other comprehensive income.

TGI and TGVI's US dollar payments under contracts for the implementation of a customer information system and the construction of a liquefied natural gas storage facility, respectively, expose the utilities to fluctuations in the US dollar-to-Canadian dollar exchange rate. TGI and TGVI have entered into foreign exchange forward contracts to hedge this exposure and any increase or decrease in the fair value of the foreign exchange forward contracts is deferred for recovery from, or refund to, customers in future rates, subject to regulatory approval.

Interest Rate Risk

The Corporation and its subsidiaries are exposed to interest rate risk associated with short-term borrowings and floating-rate debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk.

As at June 30, 2010, Fortis Properties was party to one interest rate swap agreement that effectively fixed the interest rate on variable-rate borrowings.

The Terasen Gas companies and FortisBC have regulatory approval to defer any increase or decrease in interest expense resulting from fluctuations in interest rates associated with variable-rate debt for recovery from, or refund to, customers in future rates.

Commodity Price Risk

The Terasen Gas companies are exposed to commodity price risk associated with changes in the market price of natural gas. This risk is minimized by entering into natural gas derivatives that effectively fix the price of natural gas purchases. The price risk-management strategy of the Terasen Gas companies aims to improve the likelihood that natural gas prices remain competitive with electricity rates, temper gas price volatility on customer rates and reduce the risk of regional price discrepancies. The natural gas derivatives are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, subject to regulatory approval, for recovery from, or refund to, customers in future rates.

20. CONTINGENT LIABILITIES AND COMMITMENTS

Contingent Liabilities

The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with ordinary course business operations. Management believes that the amount of liability, if any, from these actions would not have a material effect on the Corporation's consolidated financial position or results of operations. There were no material changes in the Corporation's contingencies from those disclosed in the Corporation's 2009 annual audited consolidated financial statements, except as described below.

Terasen

The Province of British Columbia was granted leave to appeal the decision to the British Columbia Court of Appeal in October 2009. The hearing took place in May 2010 and the British Columbia Court of Appeal was unanimous in dismissing the Province of British Columbia's appeal.

Maritime Electric

Commitments

There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2009 annual audited consolidated financial statements, except for that described below.

During the first quarter of 2010, FortisBC entered into a contract with Powerex Corp., a wholly owned subsidiary of BC Hydro, for fixed-price winter capacity purchases through to February 2016 in an aggregate amount of approximately US$16 million. If FortisBC brings any new resources, such as capital or contractual projects, on-line prior to the expiry of this agreement, FortisBC may terminate this contract any time after July 1, 2013 with a minimum of three-months' written notice to Powerex Corp.

21. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period classifications, the most significant of which related to the Terasen Gas companies and included an $11 million decrease in long-term regulatory assets, a $10 million increase in utility capital assets, a $3 million increase in intangible assets, an $8 million increase in long-term regulatory liabilities, and a $6 million decrease in long-term future income tax liabilities.

CORPORATE INFORMATION

Fortis Inc. is the largest investor-owned distribution utility in Canada. With total assets exceeding $12 billion and fiscal 2009 revenue totalling $3.6 billion, the Corporation serves approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State. It also owns and operates hotels and commercial office and retail space primarily in Atlantic Canada. Fortis Inc. shares are listed on the Toronto Stock Exchange and trade under the symbol FTS.

Share Transfer Agent and Registrar:

Computershare Trust Company of Canada

9^th Floor, 100 University Avenue

Toronto, ON M5J 2Y1

T: 514.982.7555 or 1.866.586.7638

F: 416.263.9394 or 1.888.453.0330

W: www.computershare.com/fortisinc

Additional information, including the Fortis 2009 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.

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

Fortis Inc. Earns $55 Million in Second Quarter

CONTACT