Fortis Inc. Earns $55 Million in Second Quarter

08/04/2010 07:00 EST

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:

  1. 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. 
  2. 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.
  3. 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. 
  4. 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
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:

  1. 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.
  1. 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"). 
  1. 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 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 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:

  1. 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. 

  2. 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.

  3. 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. 

  4. 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. 

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.

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. 

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 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.

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.

4. USE OF ESTIMATES

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

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

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

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.

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 1st 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 1st 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