Fortis Inc.
TSX : FTS

Fortis Inc.

May 04, 2011 07:00 ET

Fortis Inc. Earns $117 Million in First Quarter

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwire - May 4, 2011) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved first quarter net earnings attributable to common equity shareholders of $117 million, or $0.67 per common share, compared to $100 million, or $0.58 per common share, for the first quarter of 2010.

Performance for the quarter was driven by the Corporation's regulated utilities in western Canada.

Canadian Regulated Gas Utilities contributed earnings of $76 million, up $3 million from the first quarter of 2010. The improvement reflected growth in utility infrastructure investment, reduced amortization costs and higher capitalized finance charges, partially offset by the timing of and increase in operating expenses. Due to the seasonality of the business, most of the earnings of the gas utilities are realized in the first and fourth quarters. FortisBC's gas business expects to file its 2012-2013 rate application this month.

"We are excited about the heightened focus on natural gas in North America, especially regarding its potential use in the transportation sector," says Stan Marshall, President and Chief Executive Officer, Fortis Inc.

Canadian Regulated Electric Utilities contributed earnings of $53 million, up $13 million from the first quarter of 2010, mainly related to FortisAlberta and FortisBC's electricity business. Earnings increased at FortisAlberta due to growth in utility infrastructure investment, the timing of recording in 2010 the cumulative impact of the 2010-2011 regulatory rate decision, a $1 million gain on the sale of property and higher energy deliveries. The cumulative impact of the 2010-2011 regulatory rate decision was recorded during the third quarter of 2010 when the decision was received. Earnings at FortisBC's electricity business improved mainly as a result of growth in utility infrastructure investment and higher electricity sales. Electricity sales during the first quarter of 2010 were lower than average due to warmer temperatures during that period. With regard to regulatory matters, in March FortisAlberta filed its 2012-2013 rate application, which includes proposed gross capital expenditures of more than $775 million over the two-year period. FortisBC's electricity business expects to file its 2012-2013 rate application this summer.

Caribbean Regulated Electric Utilities contributed $4 million, consistent with earnings for the first quarter of 2010. There was no earnings' contribution from Belize Electricity during the first quarter of 2011. In March the Supreme Court of Belize dismissed Belize Electricity's appeal of the regulator's June 2008 Final Rate Decision. The Company is in the process of filing an appeal of the trial judgment with the Belize Court of Appeal.

Non-Regulated Fortis Generation contributed $3 million to earnings, up $1 million from the first quarter of 2010 due to contribution from the Vaca hydroelectric generating facility in Belize, which was commissioned in late March 2010.

Fortis Properties delivered earnings of $1 million compared to $2 million for the first quarter of 2010, reflecting lower occupancies at hotel operations in western Canada and increased amortization costs due to ongoing capital investment.

Corporate and other expenses were $20 million, $1 million lower quarter over quarter mainly due to reduced operating expenses. Higher operating expenses incurred in the first quarter of 2010 related to business development costs.

Common shareholders of Fortis received a dividend of 29 cents per common share on March 1, 2011, up from 28 cents in the fourth quarter of 2010. The 3.6% increase in the quarterly common share dividend translates to an annualized dividend of $1.16 and extends the Corporation's record of annual common share dividend increases to 38 consecutive years, the longest record of any public corporation in Canada.

Consolidated capital expenditures, before customer contributions, were approximately $233 million in the first quarter of 2011. Much of the Corporation's consolidated capital expenditure program is being driven by the regulated utilities in western Canada and the non-regulated Waneta hydroelectric generation expansion project in British Columbia, in which Fortis holds a 51% controlling interest. At FortisBC's gas business, construction of the liquefied natural gas storage facility on Vancouver Island, at an estimated cost of $214 million, is expected to be completed in the next several weeks, with the facility to be filled later in the year. The $110 million project to bring all gas customer-care functions in-house with company-owned call centres and a new customer information system should be in place by January 2012. FortisBC's electricity business expects to substantially complete its $106 million Okanagan Transmission Reinforcement Project in 2011. FortisAlberta has substantially completed its $126 million Automated Meter Project, which involved the replacement of approximately 466,000 conventional meters. Work continues on the $900 million Waneta Expansion Project, which is expected to be completed in spring 2015.

Cash flow from operating activities was $299 million for the quarter, up $98 million from the same quarter last year, driven by higher earnings, the collection from customers of higher amortization costs and favourable changes in working capital and regulatory deferral accounts.

"The most recent regulatory decisions received by our Canadian utilities provide continuing stability in 2011," says Marshall. "Our utilities are focused on operations and meeting the energy needs of customers. Our five-year capital program, including the Waneta Expansion Project, is expected to total $5.5 billion, driving growth in earnings and dividends," he explains.

"Fortis continues to pursue acquisitions for profitable growth, focusing on electric and gas utilities in the United States and Canada," concludes Marshall.

Interim Management Discussion and Analysis
For the three months ended March 31, 2011
Dated May 4, 2011

FORWARD-LOOKING STATEMENT

The following Management Discussion and Analysis ("MD&A") should be read in conjunction with the Fortis Inc. ("Fortis" or the "Corporation") interim unaudited consolidated financial statements and notes thereto for the three months ended March 31, 2011 and the MD&A and audited consolidated financial statements for the year ended December 31, 2010 included in the Corporation's 2010 Annual Report. The MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. Financial information in the MD&A 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 filing of regulatory applications and of receipt of regulatory decisions; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of cash from operations, borrowings under credit facilities, equity injections from Fortis and long-term debt issues; the expected timing of the close of the sale of the joint-use poles at Newfoundland Power; consolidated forecast gross capital expenditures for 2011 and in total over the five-year period 2011 through 2015; the expectation that the Corporation's significant capital program should drive growth in earnings and dividends; expected consolidated long-term debt maturities and repayments on average annually over the next five years; 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 2011; no expected material adverse credit rating actions in the near term; the expectation that Fortis will become a U.S. Securities and Exchange Commission Issuer by December 31, 2011;

and the expected impact of the transition to United States generally accepted accounting principles. 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 material capital project and financing cost overrun related to the construction of the Waneta hydroelectric generation expansion project; no significant decline in capital spending in 2011; 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 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;

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; capital project budget overrun, completion and financing risk in the Corporation's non-regulated business; 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 FortisBC Energy (Vancouver Island) Inc. franchise; environmental risks; insurance coverage risk; loss of licences and permits; loss of service area; the risk of transition to new accounting standards that do not recognize the impact of rate-regulation; 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; relations with First Nations; labour relations; and human resources. For additional information with respect to the Corporation's risk factors, reference should be made to the Corporation's continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and to the heading "Business Risk Management" in the MD&A for the three months ended March 31, 2011 and for the year ended December 31, 2010.

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.

CORPORATE OVERVIEW

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, Canada. Fortis owns non-regulated generation assets, primarily hydroelectric, 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 March 31, 2011, the Corporation's electricity distribution systems met a combined peak demand of approximately 5,014 megawatts ("MW") and its gas distribution system met a peak day demand of 1,210 terajoules ("TJ"). For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 2011 and to the Corporate Overview section of the MD&A for the year ended December 31, 2010.

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 at the lowest reasonable cost and conduct business in an environmentally responsible manner. The Corporation's main business, utility operations, is highly regulated and the earnings of the Corporation's regulated utilities are primarily determined under cost of service ("COS") regulation.

Generally under COS regulation, the respective regulatory authority sets customer gas and electricity rates to permit a reasonable opportunity for the utility to recover, on a timely basis, estimated costs of providing service to customers, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). Generally, the ability of a regulated utility to recover prudently incurred costs of providing service and to earn the regulatory approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") depends on the utility achieving the forecasts established in the rate-setting processes. As such, earnings of regulated utilities are generally impacted by: (i) changes in the regulator-approved allowed ROE or ROA; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) timing differences, within an annual financial reporting period, between when actual expenses are incurred and when they are recovered from customers in rates. When forward test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible for deferral account treatment. In addition, the Corporation's regulated utilities, where applicable, are permitted by their respective regulatory authority to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through customer rates and/or the use of rate stabilization and other mechanisms.

Effective March 1, 2011, the Terasen Gas companies were renamed to commence operating under a common brand identity with FortisBC in British Columbia, Canada. As a result, Terasen Gas Inc. is now FortisBC Energy Inc. ("FEI"), Terasen Gas (Vancouver Island) Inc. is now FortisBC Energy (Vancouver Island) Inc. ("FEVI") and Terasen Gas (Whistler) Inc. is now FortisBC Energy (Whistler) Inc. ("FEWI"), now collectively referred to as the FortisBC Energy companies.

FINANCIAL HIGHLIGHTS

Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. The Corporation's business is segmented by franchise area and, depending on regulatory requirement, by the nature of the assets. Key financial highlights for the first quarters ended March 31, 2011 and March 31, 2010 are provided in the following table.


Consolidated Financial Highlights (Unaudited)
Quarter Ended March 31
($ millions, except for share data)20112010Variance
Revenue1,1641,07391
Energy Supply Costs60355251
Operating Expenses21320211
Amortization103949
Finance Charges9090-
Corporate Taxes30282
Net Earnings12510718
Net Earnings Attributable to:
Non-Controlling Interests11-
Preference Equity Shareholders761
Common Equity Shareholders11710017
12510718
Basic Earnings per Common Share ($)0.670.580.09
Diluted Earnings per Common Share ($)0.650.560.09
Weighted Average Number of Common Shares Outstanding (millions)175.0171.63.4
Cash Flow from Operating Activities29920198

Factors Contributing to Revenue Variance

Favourable

  • Gas and energy sales growth, mainly due to weather-related increases in consumption, and growth in the number of customers mainly at FortisAlberta
  • The timing of recording in 2010 the cumulative impact of revenue requirements decisions received in 2010 at FortisAlberta and FEWI. The impacts of the rate decisions were recorded during the third quarter of 2010 when the decisions were received.
  • An increase in gas delivery rates and the base component of electricity rates at several of the utilities, reflecting ongoing investment in utility capital assets and higher regulator-approved expenses recoverable from customers
  • The flow through in customer electricity rates of higher energy supply costs
  • An approximate $1 million gain on sale of property
  • Higher non-regulated hydroelectric generation in Belize

Unfavourable

  • Approximately $4 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 quarter over quarter

Factors Contributing to Energy Supply Costs Variance

Unfavourable

  • Gas and energy sales growth
  • Higher energy supply costs associated with increased fuel costs, and the operation of the Energy Cost Adjustment Mechanism ("ECAM") regulatory deferral account at Maritime Electric

Favourable

  • Approximately $3 million associated with favourable foreign currency translation

Factors Contributing to Operating Expenses Variance

Unfavourable

  • Higher operating expenses at Newfoundland Power, mainly due to the regulatory approved change in the accounting treatment for other post-employment benefit ("OPEB") costs and increased maintenance costs, due to higher capital work performed in the first quarter of 2010
  • Wage and general inflationary increases
  • The timing of and a regulatory approved increase in certain operating expenses at the FortisBC Energy companies

Favourable

  • Higher corporate operating expenses incurred in the first quarter of 2010 related to business development costs

Factors Contributing to Amortization Costs Variance

Unfavourable

  • Higher amortization rates at FortisAlberta, due to the timing of recording in 2010 the cumulative impact of the revenue requirements decision received in 2010. The impacts of the rate decision were recorded during the third quarter of 2010 when the decision was received.
  • Continued investment in utility capital assets and income producing properties

Favourable

  • Reduced amortization costs during the first quarter of 2011 at the FortisBC Energy companies due to the retirement late in 2010 of certain general plant assets
  • Increased amortization costs during the first quarter of 2010 at Newfoundland Power due to an approximate $1 million adjustment, as approved by the regulator, related to an amortization study

Factors Contributing to Finance Charges Variance

Favourable

  • The refinancing of maturing corporate debt at a lower rate
  • Higher capitalized allowance for funds used during construction

Unfavourable

  • Higher debt levels in support of the utilities' capital expenditure programs

Factors Contributing to Corporate Taxes Variance

Unfavourable

  • Higher earnings before corporate taxes

Favourable

  • Lower effective corporate income tax rate, driven by an overall increase in deductible expenses for income tax purposes compared to accounting purposes and lower statutory income tax rates

Factors Contributing to Earnings Variance

Favourable

  • The approximate $4.5 million earnings impact of rate base growth, mainly at the regulated utilities in western Canada, due to continued investment in utility capital assets
  • Higher energy sales, driven by FortisBC Electric and FortisAlberta
  • The timing of recording in 2010 the cumulative impact of revenue requirements decisions received in 2010 at FortisAlberta and FEWI. The impacts of the rate decisions were recorded during the third quarter of 2010 when the decisions were received.
  • Higher corporate operating expenses incurred in the first quarter of 2010 related to business development costs
  • A $1 million gain on the sale of property
  • Higher non-regulated hydroelectric generation in Belize

Unfavourable

  • The timing of and a regulatory approved increase in certain operating expenses at the FortisBC Energy companies

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)Quarter Ended March 31
($ millions)20112010Variance
Regulated Gas Utilities - Canadian
FortisBC Energy Companies76733
Regulated Electric Utilities - Canadian
FortisAlberta21147
FortisBC Electric19145
Newfoundland Power77-
Other Canadian651
534013
Regulated Electric Utilities - Caribbean44-
Non-Regulated - Fortis Generation321
Non-Regulated - Fortis Properties12(1)
Corporate and Other(20)(21)1
Net Earnings Attributable to Common Equity Shareholders11710017

For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Corporation's regulated utilities, refer to the "Regulatory Highlights" section of this MD&A. A discussion of the financial results of the Corporation's reporting segments is as follows.

REGULATED GAS UTILITIES - CANADIAN

FORTISBC ENERGY COMPANIES (1)

Gas Volumes by Major Customer Category (Unaudited)Quarter Ended March 31
(TJ)20112010Variance
Core – Residential and Commercial50,44840,43110,017
Industrial1,8881,675213
Total Sales Volumes52,33642,10610,230
Transportation Volumes20,48416,4104,074
Throughput under Fixed Revenue Contracts4764,392(3,916)
Total Gas Volumes73,29662,90810,388
(1) Formerly referred to as the Terasen Gas companies, the FortisBC Energy companies are comprised of FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI").

Factors Contributing to Gas Volumes Variance

Favourable

  • Higher average consumption by residential and commercial customers as a result of cooler weather
  • Higher transportation volumes reflecting improving economic conditions which is favourably affecting the forestry sector

Unfavourable

  • Lower volumes under fixed revenue contracts, mainly due to higher precipitation, which made it more cost efficient for a large customer to not utilize its natural gas-powered generating facility during the first quarter of 2011

Net customer additions were 1,373 during the first quarter of 2011 compared to 1,566 during the same quarter of 2010. Gross customer additions decreased due to lower building activity during 2011.

Seasonality has a material impact on the earnings of the FortisBC Energy companies as a major portion of the gas distributed is used for space heating. Most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters.

The FortisBC Energy companies earn approximately the same margin regardless of whether a customer contracts for the purchase and delivery 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 forecast to set gas rates do not materially affect earnings.

Financial Highlights (Unaudited)Quarter Ended March 31
($ millions)20112010Variance
Revenue57552649
Earnings76733

Factors Contributing to Revenue Variance

Favourable

  • Higher average gas consumption
  • An increase in the delivery component of customer rates, mainly due to ongoing investment in utility capital assets and higher regulatory approved operating expenses recoverable from customers

Factors Contributing to Earnings Variance

Favourable

  • Rate base growth, due to continued investment in utility capital assets
  • The timing of recording in 2010 the cumulative impact of a revenue requirements decision received in 2010 at FEWI. The impacts of the decision were recorded during the third quarter of 2010 when the decision was received.
  • Reduced amortization costs during the first quarter of 2011 due to the retirement late in 2010 of certain general plant assets
  • Higher capitalized allowance for funds used during construction related to the construction of the Mount Hayes liquefied natural gas ("LNG") storage facility

Unfavourable

  • The timing of and a regulatory approved increase in operating expenses, driven by labour and benefits costs and consulting expenses

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

Financial Highlights (Unaudited)Quarter Ended March 31
20112010Variance
Energy Deliveries (gigawatt hours ("GWh"))4,4024,109293
Revenue ($ millions)1038716
Earnings ($ millions)21147

Factors Contributing to Energy Deliveries Variance

Favourable

  • Increased average consumption due to cooler-than-normal temperatures, and increased activity in the oil and gas sector due to improved market prices for oil
  • Customer growth, with the total number of customers increasing by approximately 10,800 quarter over 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. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.

Factors Contributing to Revenue Variance

Favourable

  • A 4.7% increase in base customer electricity distribution rates over final approved 2010 rates, effective January 1, 2011, associated with the 2010-2011 regulatory rate decision. The increase in base rates was primarily due to ongoing investment in utility capital assets and higher regulator-approved finance charges recoverable from customers.
  • Revenue for the first quarter of 2010 reflected a 7.5% interim customer rate increase whereas revenue for the first quarter of 2011 reflected the full impact of approved rate increases as provided in the 2010-2011 regulatory rate decision. The cumulative impact from January 1, 2010 of the rate decision was recorded during the third quarter of 2010 when the decision was received. The final approved customer rate increase for 2010 was 20.1%.
  • An approximate $1 million gain on sale of property
  • Growth in the number of customers

Factors Contributing to Earnings Variance

Favourable

  • Rate base growth, due to continued investment in utility capital assets
  • The timing of recording in 2010 the cumulative impact of the 2010-2011 regulatory rate decision, as discussed above
  • The $1 million gain on the sale of property
  • Higher energy deliveries

FORTISBC ELECTRIC (1)


Financial Highlights (Unaudited)
Quarter Ended March 31
20112010Variance
Electricity Sales (GWh)90582085
Revenue ($ millions)837211
Earnings ($ millions)19145
(1) Formerly referred to as FortisBC, and 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.

Factors Contributing to Electricity Sales Variance

Favourable

  • Lower average consumption during the first quarter of 2010 due to warmer-than-normal temperatures experienced during that period
  • Growth in the number of residential and general service customers

Factors Contributing to Revenue Variance

Favourable

  • The 10.4% increase in electricity sales
  • A 6.6% increase in customer electricity rates, effective January 1, 2011, mainly reflecting ongoing investment in utility capital assets and the higher cost of capital
  • A 2.9% increase in customer electricity rates, effective September 1, 2010, as a result of the flow through to customers of increased purchased power costs charged by BC Hydro

Unfavourable

  • Increased performance-based rate-setting ("PBR") incentive adjustments owing to customers
  • Lower pole attachment revenue, partially offset by higher wheeling revenue

Factors Contributing to Earnings Variance

Favourable

  • Electricity sales growth
  • Rate base growth, due to continued investment in utility capital assets

NEWFOUNDLAND POWER


Financial Highlights (Unaudited)
Quarter Ended March 31
20112010Variance
Electricity Sales (GWh)1,8341,79539
Revenue ($ millions)1831785
Earnings ($ millions)77-

Factors Contributing to Electricity Sales Variance

Favourable

  • Growth in the number of customers and higher average consumption

Factors Contributing to Revenue Variance

Favourable

  • The 2.2% increase in electricity sales
  • An overall average 0.8% increase in customer electricity rates, effective January 1, 2011, mainly reflecting higher OPEB costs, partially offset by a decrease in the allowed ROE to 8.38% for 2011, down from 9.00% for 2010

Factors Contributing to Earnings Variance

Unfavourable

  • The decrease in the allowed ROE, as reflected in customer rates
  • Higher maintenance costs as a result of higher capital work performed in the first quarter of 2010, due to an early start of the capital program and restoration work related to an ice storm in March 2010
  • Timing of labour costs in 2011, as a significant portion of certain employee initiatives were completed during the first quarter of 2011

Favourable

  • Electricity sales growth

OTHER CANADIAN ELECTRIC UTILITIES (1)


Financial Highlights (Unaudited)
Quarter Ended March 31
20112010Variance
Electricity Sales (GWh)65463222
Revenue ($ millions)91829
Earnings ($ millions)651
(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and Algoma Power.

Factors Contributing to Electricity Sales Variance

Favourable

  • Higher average consumption, reflecting colder temperatures in Ontario and on Prince Edward Island ("PEI")

Factors Contributing to Revenue Variance

Favourable

  • The 3.5% increase in electricity sales
  • An increase in the recovery from customers of the ECAM regulatory deferral account
  • An average 3.8% increase in customer electricity rates at Algoma Power, effective December 1, 2010, reflecting an increase in the allowed ROE to 9.85% for 2011 from 8.57% for 2010 and the use of a forward test year for rate setting
  • Increases in the base component of customer electricity distribution rates at Fort Erie, Gananoque and Port Colborne in Ontario, effective May 1, 2010

Unfavourable

  • A 14% decrease in customer rates, effective March 1, 2011, reflecting the impact of the PEI Energy Accord (the "Accord") with the Government of PEI, including the flow through to customers of lower purchased power costs as a result of a new five-year purchase power agreement between Maritime Electric and New Brunswick Power ("NB Power")

Factors Contributing to Earnings Variance

Favourable

  • A higher allowed ROE at Algoma Power, as reflected in customer rates
  • Electricity sales growth
  • A deferred start to the vegetation management program in 2011

REGULATED ELECTRIC UTILITIES - CARIBBEAN(1)


Financial Highlights (Unaudited)
Quarter Ended March 31
20112010Variance
Average US:CDN Exchange Rate (2)0.991.04(0.05)
Electricity Sales (GWh)2572561
Revenue ($ millions)7676-
Earnings ($ millions)44-
(1) Includes Belize Electricity, in which Fortis holds an approximate 70% controlling interest; Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 59% controlling interest; and wholly owned 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 Electricity Sales Variance

Favourable

  • Warmer and drier weather conditions experienced on Grand Cayman, which increased air conditioning load
  • Growth in the number of customers on Grand Cayman

Unfavourable

  • Cooler weather conditions experienced in the Turks and Caicos Islands, which decreased air conditioning load
  • The loss at Belize Electricity of a large industrial customer that began generating its own electricity
  • Tempered growth due to continuing challenging economic conditions in the region

Factors Contributing to 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
  • Increased electricity sales on Grand Cayman
  • Higher miscellaneous revenue at Fortis Turks and Caicos

Unfavourable

  • Approximately $4 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 quarter over quarter

Factors Contributing to Earnings Variance

Favourable

  • Increased electricity sales on Grand Cayman
  • Lower operating maintenance expenses at Caribbean Utilities, due to various capital upgrade projects occurring during the first quarter of 2011
  • Higher miscellaneous revenue
  • Ongoing efforts to reduce costs and improve efficiencies to temper the impact of continuing challenging economic conditions in the region

Unfavourable

  • Higher provision for bad debts at Belize Electricity due to a large industrial customer entering into receivership in the fourth quarter of 2010
  • Higher finance charges at Belize Electricity due to interest expense on regulatory liabilities

NON-REGULATED - FORTIS GENERATION(1)


Financial Highlights (Unaudited)
Quarter Ended March 31
20112010Variance
Energy Sales (GWh)76679
Revenue ($ millions)752
Earnings ($ millions)321
(1) Includes the financial results of non-regulated generation assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New York State, with a combined generating capacity of 139 megawatts, mainly hydroelectric. Results reflect contribution from the Vaca hydroelectric generating facility in Belize from late March 2010 when the facility was commissioned.

Factors Contributing to Energy Sales Variance

Favourable

  • Increased production driven by the Vaca hydroelectric generating facility in Belize, which was commissioned in late March 2010

Factors Contributing to Revenue Variance

Favourable

  • Higher production in Belize
  • Higher average energy sales rate per megawatt hour in Ontario of $72.59 for the first quarter of 2011 compared to $33.85 for the same period in 2010. Effective May 1, 2010, energy produced in Ontario is being sold under a fixed-price contract. Previously, energy was sold at market rates.

Factors Contributing to Earnings Variance

Favourable

  • Higher production in Belize
  • Higher average energy sales rates in Ontario

Unfavourable

  • Higher finance charges as a result of lower interest revenue associated with inter-company lending to regulated operations in Ontario

NON-REGULATED - FORTIS PROPERTIES (1)


Financial Highlights (Unaudited)
Quarter Ended March 31
($ millions)20112010Variance
Hospitality Revenue3333-
Real Estate Revenue17161
Total Revenue50491
Earnings12(1)
(1) Fortis Properties owns and operates 21 hotels, comprised of more than 4,100 rooms, in eight Canadian provinces and approximately 2.7 million square feet of commercial office and retail space primarily in Atlantic Canada.

Factors Contributing to Revenue Variance

Favourable

  • A $0.5 million gain on the sale of the Viking Mall in Newfoundland during the first quarter of 2011
  • Revenue growth at all regions of the Real Estate Division, mainly due to rent increases
  • A 0.6% increase in revenue per available room ("RevPAR") at the Hospitality Division to $63.29 for the first quarter of 2011 from $62.93 for the same quarter in 2010. RevPAR increased due to an overall 1.6% increase in the average room rate, partially offset by an overall 1% decrease in hotel occupancy. The average room rate increased in all regions, lead by operations in Atlantic Canada. Hotel occupancy at operations in western Canada decreased, while occupancy at operations in Atlantic Canada and central Canada increased.

Unfavourable

  • A decrease in the occupancy rate at the Real Estate Division to 94.3% as at March 31, 2011 from 95.8% as at March 31, 2010

Factors Contributing to Earnings Variance

Unfavourable

  • Lower performance at hotel operations, primarily due to the continued unfavourable impact of the economic downturn
  • Higher amortization costs due to capital investment in both the Hospitality and Real Estate Divisions

Favourable

  • Improved performance at real estate operations, primarily due to the gain on sale of the Viking Mall

CORPORATE AND OTHER(1)

Financial Highlights (Unaudited)Quarter Ended March 31
($ millions)20112010Variance
Revenue77-
Operating Expenses24(2)
Amortization23(1)
Finance Charges (2)1920(1)
Corporate Tax Recovery(3)(5)2
(13)(15)2
Preference Share Dividends761
Net Corporate and Other Expenses(20)(21)1
(1) Includes Fortis net corporate expenses, net expenses of non-regulated FortisBC Holdings Inc. ("FHI") (formerly Terasen Inc.) corporate-related activities and the financial results of FHI's 30% ownership interest in CustomerWorks Limited Partnership and of FHI's non-regulated wholly owned subsidiary FortisBC Alternative Energy Services Inc. (formerly Terasen Energy Services Inc.)
(2) Includes dividends on preference shares classified as long-term liabilities

Factors Contributing to Net Corporate and Other Expenses Variance

Favourable

  • Reduced operating expenses. Operating expenses were higher during the first quarter of 2010 due to business development costs incurred during that period.
  • Lower finance charges driven by the redemption of $125 million 8.0% Capital Securities in April 2010, partially offset by higher average credit facility borrowings combined with higher interest rates charged on those credit facility borrowings
  • Lower amortization costs, due to the retirement of some assets at CustomerWorks Limited Partnership during 2010

Unfavourable

  • Lower corporate tax recovery, mainly due to a lower net loss for income tax purposes
  • Higher preference share dividends, due to the issuance of First Preference Shares, Series H on January 18, 2010

REGULATORY HIGHLIGHTS

The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated gas and electric utilities for the first quarter of 2011 are summarized as follows:



NATURE OF REGULATION
Regulated
Utility
Regulatory
Authority
Allowed Common Equity
(%)
Allowed Returns (%)Supportive Features
200920102011Future or Historical Test Year Used to Set Customer Rates
ROECOS/ROE
FEI


British Columbia Utilities Commission ("BCUC")



40 (1)



8.47
(2)
/9.50
(3)


9.50




9.50


FEI: 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 with a two-year phase-out
FEVIBCUC409.17
(2)
/10.00
(3)
10.0010.00
ROEs established by the BCUC, effective July 1, 2009, as a result of a cost of capital decision in the fourth quarter of 2009.
FEWIBCUC408.97
(2)
/10.00
(3)
10.0010.00Previously, the allowed ROEs were set using an automatic adjustment formula tied to long-term Canada bond yields.
Future Test Year
FortisBC ElectricBCUC408.879.909.90COS/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 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
FortisAlbertaAlberta Utilities Commission ("AUC")419.009.009.00 (4)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 PowerNewfoundland and Labrador Board of Commissioners of Public Utilities ("PUB")458.95
+/-
50 bps
9.00
+/-
50 bps
8.38
+/-
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 ElectricIsland Regulatory and Appeals Commission ("IRAC")409.759.759.75COS/ROE
Future Test Year
ROE
Fortis
Ontario
Ontario Energy Board ("OEB")
Canadian Niagara
Power
40 (5)
8.018.01
8.01Canadian Niagara Power - COS/ROE
Algoma Power50 (6)
/40 (7)
8.578.579.85 (7)Algoma Power – COS/ROE and subject to Rural and Remote Rate Protection ("RRRP") Program
Franchise Agreement
Cornwall Electric
Cornwall Electric – Price cap with commodity cost flow through
Canadian Niagara Power – 2009 test year for 2009, 2010 and 2011
Algoma Power – 2007 historical test year for 2009 and 2010; 2011 test year for 2011
ROA
Belize ElectricityPublic Utilities CommissionN/A

- (8)- (8)- (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 UtilitiesElectricity Regulatory Authority ("ERA")N/A9.00 - 11.007.75 –
9.75
7.75 –
9.75
COS/ROA

Rate-cap adjustment mechanism ("RCAM") based on published consumer price indices

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 CaicosUtilities make annual filings to the GovernorN/A17.50
(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 2009, the allowed common equity component of capital structure was 35%.
(2) Pre-July 1, 2009
(3) Effective July 1, 2009
(4) Interim pending finalization by the AUC
(5) Effective May 1, 2010. For 2009, effective May 1, the allowed common equity component of capital structure was 43.3%.
(6) Pre-December 1, 2010
(7) Effective December 1, 2010
(8) Allowed ROA to be settled once regulatory matters are resolved.
(9) Amount provided under licence. ROA achieved in 2009 and 2010 was materially lower than the ROA allowed under the licence. Fortis Turks and Caicos had requested a review of its rates in 2010.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
Regulated UtilitySummary Description
FEI/FEVI/FEWI- FEI and FEWI review natural gas and propane commodity and mid-stream rates with the BCUC every three months 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 propane and mid-stream costs are flowed through to customers without markup. The delivery rate charged to FEVI customers includes a component to recover approved gas costs and is set annually. In order to ensure that the balances in the Commodity Cost Reconciliation Account and Mid-stream Cost Reconciliation Account are recovered on a timely basis, FEI and FEWI prepare and file quarterly calculations with the BCUC to determine whether customer rate adjustments are needed to reflect prevailing market prices for natural gas. These rate adjustments ignore the temporal effect of derivative valuation adjustments on the balance sheet and, instead, reflect the forward forecast of gas costs over the recovery period.

- Effective January 1, 2011, rates for residential customers in the Lower Mainland, Fraser Valley, Interior, North and Kootenay service areas decreased by approximately 6%, as approved by the BCUC, to reflect net changes in delivery, commodity and mid-stream costs. Rates remained unchanged as of April 1, 2011.

- In December 2010 FEI filed an application with the BCUC to provide fuelling services through FEI-owned and operated compressed natural gas and LNG fuelling stations. If the application is approved, commercial customers will be able to safely and economically refuel their fleet vehicles on their own premises, at rates regulated by the BCUC, using stations provided by FEI.

- FEI, FEVI and FEWI are considering an amalgamation of the three companies. An amalgamation would require an application to be approved by the BCUC and consent of the Government of British Columbia. The companies are expecting to bring forth an application during 2011.

- In January 2011 FEI filed its review of the Price Risk Management Plan ("PRMP") objectives with the BCUC related to its gas commodity hedging plan and also submitted a 2011-2014 PRMP. On a partial basis, the BCUC has approved FEI to implement portions of its 2011-2014 PRMP. FEVI plans to file an updated PRMP by June 2011.

- The FortisBC Energy companies expect to file 2012-2013 Revenue Requirements Applications in May 2011.
FortisBC Electric- In December 2010 the BCUC approved a Negotiated Settlement Agreement ("NSA") pertaining to FortisBC Electric's 2011 Revenue Requirements Application. The result was a general customer electricity rate increase of 6.6%, effective January 1, 2011. The rate increase was primarily the result of the Company's ongoing investment in utility capital assets and the higher cost of capital.

- FortisBC Electric expects to file a 2012-2013 Revenue Requirements Application in summer 2011.
FortisAlberta- In December 2010 the AUC issued its decision on FortisAlberta's August 2010 Compliance Filing, which incorporated the AUC's decision, received in July 2010, on the Company's 2010 and 2011 Distribution Tariff Application ("DTA"). The December 2010 decision approved the Company's distribution revenue requirements of $368 million for 2011. Final distribution electricity rates and rate riders were also approved, effective January 1, 2011.

- During the first quarter of 2011, the AUC initiated its proceeding to finalize the allowed ROE for 2011, review capital structure and consider whether a return to a formula-based approach for annually setting the allowed ROE, beginning in 2012, is warranted. In the absence of a formula-based approach, the AUC is expected to consider how the allowed ROE will be set for 2012. A hearing on the proceeding is expected to commence in the second quarter of 2011.

- In March 2011 FortisAlberta filed its 2012 and 2013 DTA. The Company has requested approval of revenue requirements of $410 million for 2012 and $447 million for 2013, for rate increases of 8.2% and 6.9%, respectively. The DTA also proposes approximately $776 million in gross capital expenditures over the two-year period. The rate increases are driven primarily by rate base growth associated with capital expenditures, which results in increased amortization costs and interest expense. The Company has proposed a schedule for the DTA proceeding that would include a hearing in late October 2011 with a final decision expected in the first quarter of 2012.

- The AUC has initiated a proceeding in respect of FortisAlberta's Review and Variance Application to determine the prudence of the additional capital expenditures above $104 million related to the Company's Advanced Metering Project. The total project cost is expected to be approximately $126 million. A decision by the AUC is expected in the second quarter of 2011.

- In October 2010 the Central Alberta Rural Electrification Association ("CAREA") filed an application with the AUC seeking a declaration that, effective January 1, 2012, CAREA be entitled to service any new customer wishing to obtain electricity for use on property within CAREA's service area and that FortisAlberta be restricted to serving only those customers that are not being provided service by CAREA. FortisAlberta has intervened in the proceeding.
- 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 electricity rates. FortisAlberta is currently assessing PBR and will participate fully in the AUC process.
Newfoundland
Power
- In November 2010 the PUB approved Newfoundland Power's application to defer the recovery of expected increased costs of $2.4 million, due to expiring regulatory amortizations, in 2011.

- In December 2010 the PUB approved Newfoundland Power's application to: (i) adopt the accrual method of accounting for OPEB costs, effective January 1, 2011; (ii) recover the transitional regulatory asset balance of approximately $53 million, associated with adoption of accrual accounting, over a 15-year period; and (iii) adopt an OPEB cost-variance deferral account to capture differences between OPEB expense calculated in accordance with Canadian GAAP and OPEB expense approved by the PUB for rate-setting purposes.

- In December 2010 Newfoundland Power received approval from the PUB for an overall average 0.8% increase in customer electricity rates, effective January 1, 2011, mainly resulting from the PUB's approval for the Company to change its accounting for OPEB costs, as described above, partially offset by the impact of the decrease in the allowed ROE for 2011.

- On January 1, 2011, new support structure arrangements with Bell Aliant went into effect. Bell Aliant will buy back 40% of all joint-use poles and related infrastructure owned by Newfoundland Power for approximately $46 million. The support structure arrangements are subject to certain conditions, including PUB approval of the sale of 40% of the Company's joint-use poles, which must be met by both parties by June 30, 2011, or either party may choose to terminate. In the event of termination, the rights and recourses under the original Joint-Use Facilities Partnership Agreement will remain in effect for both parties. Newfoundland Power filed an application with the PUB in February 2011 requesting approval of the transaction and expects the transaction to close in 2011. Newfoundland Power anticipates the proceeds from the sale of the poles will be used to pay down credit facility borrowings and maintain the utility's capital structure at 45% common equity.

- The Company is currently assessing the requirement for it to file an application with the PUB to recover expected increased costs in 2012.

- In April 2011 the PUB approved Newfoundland Power's application requesting an optional seasonal rate for domestic customers effective July 1, 2011. This optional seasonal rate charges a higher price for electricity consumed during the months of December through April and a lower rate during the months of May through November. The PUB also approved the use of an Optional Rates Revenue and Cost Recovery Account that provides for the deferral of annual cost and revenue effects associated with implementing optional seasonal rates.

- An application is expected to be filed by the Company in May 2011 seeking an increase in customer rates of approximately 8%, effective July 1, 2011. The proposed increase in rates is mainly due to 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 electricity that Newfoundland Hydro sells to Newfoundland Power are captured and flowed through to Newfoundland Power customers through the operation of Newfoundland Power's Rate Stabilization Account. The proposed increase in rates is principally due to increased fuel prices.
Maritime Electric- In November 2010 Maritime Electric signed the Accord with the Government of PEI. The Accord covers the period from March 1, 2011 through February 29, 2016. Under the terms of the Accord, the Government of PEI is assuming responsibility for the cost of replacement energy and the monthly operating and maintenance costs related to the NB Power Point Lepreau Nuclear Generating Station ("Point Lepreau"), effective March 1, 2011 until Point Lepreau is fully refurbished, which is expected by fall 2012. The Government of PEI is financing these costs, which will be recovered from customers beginning when Point Lepreau returns to service. In the event that Point Lepreau does not return to service by fall 2012, the Government of PEI reserves the right to cease the monthly payments. As permitted by IRAC, replacement energy costs incurred during the refurbishment of Point Lepreau up to the end of February 2011 were deferred by Maritime Electric and totalled approximately $47 million. The deferred costs are included in rate base and are, therefore, earning a return. The nature and timing of the recovery of the deferred costs is subject to further review by a commission to be established by the Government of PEI. The Accord also provides for the financing by the Government of PEI of costs associated with Maritime Electric's termination of the Dalhousie Unit Participation Agreement. The costs will be subsequently collected from customers over a period to be established by the Government of PEI. As a result of the Accord, including the favourable impact on purchased power costs of the new five-year power purchase agreement between Maritime Electric and NB Power, customer electricity rates decreased by approximately 14.0% effective March 1, 2011, at which time a two-year customer rate freeze commenced.
FortisOntario- In non-rebasing years, customer electricity distribution rates are set using inflationary factors less an efficiency target under the Third-Generation Incentive Rate Mechanism ("IRM") as prescribed by the OEB. In March 2011 the OEB published the applicable inflationary and efficiency targets, which resulted in minimal changes in base customer electricity distribution rates at FortisOntario's operations Fort Erie, Gananoque and Port Colborne.

- In November 2010 the OEB approved an NSA pertaining to Algoma Power's electricity distribution rate application for customer rates, effective December 1, 2010 through December 31, 2011, using a 2011 forward test year. The rates reflect an approved allowed ROE of 9.85% on a deemed equity component of capital structure of 40%. The overall impact of the OEB rate decision on an average customer's electricity bill was an increase of 3.8%, including rate riders and other charges.

- The present form of Third-Generation IRM will not accommodate Algoma Power's customer rate structure and the RRRP Program; therefore, Algoma Power has agreed to consult with interveners to develop a form of incentive rate-making that may be used between rebasing periods. Due to regulations in Ontario associated with the RRRP Program, customer electricity distribution rates at Algoma Power are tied to the average changes in rates of other electric utilities in Ontario. Pending these consultations, Algoma Power will file for incentive rate-making for customer electricity distribution rates, effective January 1, 2012.

- FortisOntario expects to file a COS Application in 2012 for harmonized electricity distribution rates in Fort Erie, Port Colborne and Gananoque, effective January 1, 2013, using a 2013 forward test year. The timing of the filing of the COS Application corresponds with the ending of the period that the current Third-Generation IRM applies to FortisOntario.
Belize Electricity - In March 2011 the Supreme Court of Belize dismissed Belize Electricity's appeal of the regulator's June 2008 Final Rate Decision. The Company is in the process of filing an appeal of the trial judgment with the Belize Court of Appeal and has filed an application to restrain the regulator from initiating any rate action pending the hearing and determination of the appeal.
Caribbean Utilities - In March 2011 after the requisite review, Caribbean Utilities confirmed to the ERA that the RCAM, as provided in the Company's transmission and distribution licence, yielded no customer rate adjustment effective June 1, 2011.

- In March 2011 the ERA approved US$134 million of proposed non-generation installation expenditures as requested by Caribbean Utilities in its 2011-2015 Capital Investment Plan ("CIP"). The 2011-2015 CIP was prepared upon the basis of the Company's application to the ERA for a delay in any new generation installation until there is more certainty in growth forecasts. The remaining US$85 million of the CIP relates to new generation installation, which would be subject to a competitive solicitation process with the next generating unit currently scheduled for installation in 2014.
Fortis Turks
and Caicos
- In March 2011 Fortis Turks and Caicos submitted its 2010 annual regulatory filing outlining the Company's performance in 2010. Included in the filing were the calculations, in accordance with the utility's licence, of rate base for 2010 of US$142 million and cumulative shortfall in achieving allowable profits as at December 31, 2010 of US$49 million.

- Fortis Turks and Caicos intends to submit a new Rate Variation Application in 2011, which takes into account changes in the utility's rate base and in the local business and regulatory environment since filing its 2010 application. The 2010 application was not accepted by the Governor of the Turks and Caicos Islands due to concern about the impact a proposed rate increase might have on key sectors of the local economy.

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between March 31, 2011 and December 31, 2010.

Significant Changes in the Consolidated Balance Sheets (Unaudited) between March 31, 2011 and December 31, 2010
Balance Sheet AccountIncrease/
(Decrease)
($ millions)

Explanation
Accounts receivable45The increase was primarily due to the impact of a seasonal increase in sales and the operation of the equal payment plans for customers mainly at the FortisBC Energy companies and Newfoundland Power, partially offset by the lower commodity cost of natural gas reflected in customer rates at the FortisBC Energy companies.
Inventories(80)The decrease was driven by the normal seasonal reduction of gas in storage at the FortisBC Energy companies, due to higher consumption during the winter months.
Utility capital assets149The increase primarily related to $219 million invested in electricity and gas systems, partially offset by amortization and customer contributions for the three months ended March 31, 2011.
Short-term borrowings(99)The decrease was driven by lower borrowings at the FortisBC Energy companies due to seasonality of operations.
Regulatory liabilities – current and long-term71The increase was driven by deferrals at the FortisBC Energy companies associated with an increase in the Rate Stabilization Deferral Account ("RSDA"), reflecting the accumulation of over-recovered costs of providing service to customers during the first quarter of 2011, and an increase in the Mid-stream Cost Reconciliation Account, as amounts collected in customer rates were in excess of actual mid-stream gas-delivery costs.
Shareholders' equity92The increase was due to net earnings attributable to common equity shareholders for the three months ended March 31, 2011, less common share dividends, and the issuance of common shares under the Corporation's share purchase, dividend reinvestment and stock option plans, partially offset by an increase in accumulated other comprehensive loss.

LIQUIDITY AND CAPITAL RESOURCES

The table below outlines the Corporation's consolidated sources and uses of cash for the first quarter of 2011, as compared to the first quarter of 2010, followed by a discussion of the nature of the variances in cash flows quarter over quarter.


Summary of Consolidated Cash Flows (Unaudited)
Quarter Ended March 31
($ millions)20112010Variance
Cash, Beginning of Period1098524
Cash Provided by (Used in):
Operating Activities29920198
Investing Activities(219)(176)(43)
Financing Activities(103)(17)(86)
Effect of Exchange Rate Changes on Cash and Cash Equivalents
-

(1
)
1
Cash, End of Period8692(6)

Operating Activities: Cash flow from operating activities, after working capital adjustments, was $98 million higher quarter over quarter. The increase was primarily due to: (i) higher earnings; (ii) the collection from customers of increased amortization costs, mainly at FortisAlberta, as approved by the regulator; and (iii) favourable changes in working capital and regulatory deferral accounts. The favourable working capital changes were driven by greater impacts of seasonality at the FortisBC Energy companies and higher Alberta Electric System Operator net transmission-related receipts and payments at FortisAlberta. The favourable changes in regulatory deferral accounts related mainly to the increase in the RSDA at the FortisBC Energy companies, due to the accumulation of over-recovered costs of providing service to customers during 2011.

Investing Activities: Cash used in investing activities was $43 million higher quarter over quarter, driven by capital spending related to the non-regulated Waneta hydroelectric generation expansion project (the "Waneta Expansion Project") and higher capital expenditures at FortisAlberta.

Financing Activities: Cash used in financing activities was $86 million higher quarter over quarter. Lower proceeds from the issuance of preference shares were partially offset by lower repayments of short-term borrowings and long-term debt, higher net borrowings under committed credit facilities and higher advances from non-controlling interests.

Net repayments of short-term borrowings were $83 million lower quarter over quarter. The net repayments during the first quarter of 2010 increased due to FEI using proceeds from an equity injection by the Corporation to reduce borrowings under the utility's credit facility.

Repayments of long-term debt and capital lease obligations and net borrowings (repayments) under committed credit facilities for the first quarter of 2011 compared to the same quarter of 2010 are summarized in the following tables.


Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Quarter Ended March 31
($ millions)20112010Variance
Fortis Properties(2)(14)12
Other(2)(2)-
Total(4)(16)12

Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Quarter Ended March 31
($ millions)20112010Variance
FortisAlberta1240(28)
FortisBC Electric-(9)9
Newfoundland Power13112
Corporate(10)(71)61
Total15(29)44

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.

Advances of approximately $17 million were received, during the first quarter of 2011, from non-controlling interests in the Waneta Expansion Limited Partnership ("Waneta Partnership") to finance capital expenditures related to the Waneta Expansion Project.

In January 2010 Fortis completed a $250 million offering of First Preference Shares, Series H. The net proceeds of approximately $242 million were used to repay borrowings under the Corporation's committed credit facility and fund an equity injection into FEI.

Common share dividends paid were $51 million during the first quarter of 2011, up $3 million from the same quarter of 2010. The increase was due to a higher quarterly dividend paid per common share and an increase in the number of common shares outstanding. The dividend paid per common share for the first quarter of 2011 was $0.29 compared to $0.28 for the first quarter of 2010. The weighted average number of common shares outstanding during the first quarter of 2011 was 175.0 million, compared to 171.6 million during the first quarter of 2010.

CONTRACTUAL OBLIGATIONS

Consolidated contractual obligations of Fortis over the next five years and for periods thereafter, as at March 31, 2011, are outlined in the following table. A detailed description of the nature of the obligations is provided in the MD&A for the year ended December 31, 2010 and below, where applicable.


Contractual Obligations (Unaudited)
As at March 31, 2011
($ millions)


Total
Due within 1 yearDue in years 2 and 3Due in years 4 and 5Due
after 5 years
Long-term debt5,658523897834,434
Brilliant Terminal Station5935546
Gas purchase contract obligations (1)46921819358-
Power purchase obligations
FortisBC Electric2,8964488812,683
FortisOntario4464597101203
Maritime Electric23155837815
Belize Electricity15514343770
Capital cost (2)443173234360
Joint-use asset and share service agreements6548746
Office lease – FortisBC Electric1823310
Operating lease obligations12018292746
Defined benefit pension funding contributions (3)69273813
Other183771
Total10,6475021,0061,2227,917
(1)Based on index prices as at March 31, 2011
(2)Maritime Electric has entitlement to approximately 4.7% of the output from Point Lepreau for the life of the unit. As part of its participation agreement, the Company is obligated to pay its share of capital and operating costs of the unit, which have been included in the table above. However, as a result of the Accord, the Government of PEI is assuming responsibility for the payment of the monthly operating and maintenance costs related to Point Lepreau, effective March 1, 2011 until Point Lepreau is fully refurbished, which is expected by fall 2012.
(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 these 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, 2010FortisBC Electric
December 31, 2011Newfoundland Power
December 31, 2012FortisBC Energy (covering non-unionized employees)
December 31, 2013FortisBC Energy (covering unionized employees)
The estimate of defined benefit pension funding contributions above includes the impact of the outcome of the December 31, 2010 actuarial valuation, completed during the first quarter of 2011, associated with the defined benefit pension plan at FortisBC Energy covering unionized employees, as well as other revised actuarial estimates.

Other contractual obligations, which are not reflected in the above table, did not change from that disclosed in the MD&A for the year ended December 31, 2010.

For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program, which is not included in the contractual obligations table above, refer to the "Capital Program" section of this MD&A.

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. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt issues. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40% equity, including preference shares, and 60% 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
March 31, 2011December 31, 2010
($ millions)(%)($ millions)(%)
Total debt and capital lease obligations (net of cash) (1)5,82957.55,91458.4
Preference shares (2)9129.09129.0
Common shareholders' equity3,39733.53,30532.6
Total (3)10,138100.010,131100.0
(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 net earnings applicable to common shares, net of common share dividends, and lower short-term borrowings, combined with increased common shares outstanding mainly reflecting the impact of the Corporation's dividend reinvestment and stock option plans.

CREDIT RATINGS

The Corporation's credit ratings are as follows:

Standard & Poor'sA- (long-term corporate and unsecured debt credit rating)
DBRSA(low) (unsecured debt credit rating)

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

CAPITAL PROGRAM

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.

A breakdown of the $233 million in gross capital expenditures by segment for the first quarter of 2011 is provided in the following table.

Gross Consolidated Capital Expenditures (Unaudited) (1)
Quarter Ended March 31, 2011
($ millions)

FortisBC Energy Com-
panies
Fortis
Alber-
ta (2)
FortisBC ElectricNew-
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 -
Cari-
bbean
Non-
Regu-
lated -
Utility
(3)
Fortis Proper-
ties
Total
49853014818621233233

(1)Relates to cash payments to acquire or construct utility capital assets, income producing properties and intangible assets, as reflected in the consolidated statement of cash flows. Includes asset removal and site restoration expenditures, net of salvage proceeds, for those utilities where such expenditures are permissible in rate base in 2011. Excludes capitalized amortization and non-cash equity component of the allowance for funds used during construction.

(2)Includes payments made to the Alberta Electric System Operator for investment in transmission-related capital projects

(3)Includes non-regulated generation, mainly related to the Waneta Expansion Project, and corporate capital expenditures

There has been no material change in forecast gross consolidated capital expenditures for 2011 from the approximate $1.2 billion forecast as was disclosed in the MD&A for the year ended December 31, 2010. 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 material changes 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, 2010, except as described below.

In March 2011 Fortis Properties filed a development application to construct a 12-storey office building in St. John's, Newfoundland, subject to municipal government approval. The $50 million project will feature 145,000 square feet of Class A office space and include 183 parking spaces and is expected to be completed in 2013.

Over the five-year period 2011 through 2015, consolidated gross capital expenditures are expected to be approximately $5.5 billion. Approximately 63% of the capital spending is expected to be incurred at the regulated electric utilities, driven by FortisAlberta and FortisBC Electric. Approximately 20% and 17% of the capital spending is expected to be incurred at the regulated gas utilities and at the non-regulated operations, respectively. Capital expenditures at the regulated utilities are subject to regulatory approval.

CASH FLOW REQUIREMENTS

At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of 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 March 31, 2011, management expects consolidated long-term debt maturities and repayments to average approximately $250 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 continues to not meet certain debt covenant financial ratios related to loans with the International Bank for Reconstruction and Development and the Caribbean Development Bank totalling $4 million (BZ$8 million) as at March 31, 2011.

As the hydroelectric assets and water rights of the Exploits River Hydro Partnership ("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 $57 million as at March 31, 2011 (December 31, 2010 - $58 million). The lenders of the term loan have not demanded accelerated repayment. The scheduled repayments under the term loan are being made by Nalcor, a Crown corporation, acting as an agent for the Government of Newfoundland and Labrador with respect to the expropriation matters. For further information refer to Note 30 to the Corporation's 2010 annual audited consolidated financial statements.

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 March 31, 2011 and are expected to remain compliant throughout 2011.

CREDIT FACILITIES

As at March 31, 2011, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.1 billion, of which $1.5 billion was unused, including $445 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% of these facilities. Approximately $2.0 billion of the total credit facilities are committed facilities, the majority of which currently have maturities in 2012, 2013 and 2014.

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

Credit Facilities (Unaudited)As at
($ millions)Corporate and OtherRegulated UtilitiesFortis PropertiesMarch 31, 2011December 31, 2010
Total credit facilities6451,440132,0982,109
Credit facilities utilized:
Short-term borrowings-(255)(4)(259)(358)
Long-term debt (including current portion)(155)(79)-(234)(218)
Letters of credit outstanding(1)(122)-(123)(124)
Credit facilities unused48998491,4821,409

As at March 31, 2011 and December 31, 2010, 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 2011 Maritime Electric renewed its unsecured committed revolving credit facility, which matures annually in March. The unsecured committed revolving credit facility was reduced from $60 million to $50 million.

In April 2011 FortisBC Electric negotiated and finalized an amended credit facility agreement resulting in an extension to the maturity of the Company's $150 million unsecured committed revolving credit facility with $100 million now maturing in May 2014 and $50 million now maturing in May 2012.

FINANCIAL INSTRUMENTS

The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows:

Financial Instruments (Unaudited)As at
March 31, 2011December 31, 2010
($ millions)Carrying ValueEstimated
Fair Value
Carrying
Value
Estimated
Fair Value
Waneta Partnership promissory note43414240
Long-term debt, including current portion (1)5,6586,2785,6696,431
Preference shares, classified as debt (2)320343320344
(1) Carrying value as at March 31, 2011 excludes unamortized deferred financing costs of $41 million (December 31, 2010 - $42 million) and capital lease obligations of $39 million (December 31, 2010 - $38 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 $612 million as at March 31, 2011 (December 31, 2010 – $615 million).

The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note, 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 or promissory note 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.

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

As at March 31, 2011, all of the Corporation's US$590 million (December 31, 2010 – US$590 million) corporately held long-term debt had been designated as a hedge of a significant portion of the Corporation's foreign net investments. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately held US dollar borrowings designated as hedges are recognized in other comprehensive income and help offset unrealized foreign currency gains and losses on the foreign net investments, which are also recognized in other comprehensive income. As at March 31, 2011, 98% of the Corporation's foreign net investments were hedged (December 31, 2010 – 99%).

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 derivative financial instruments.

Derivative Financial Instruments (Unaudited)As at
March 31, 2011December 31, 2010

Liability
Term to Maturity (years)Number
of Con-
tracts
Carrying Value
($ milli-
ons)
Estimated
Fair Value
($ milli-
ons)
Carrying Value
($ milli-
ons)
Estimated
Fair Value
($ milli-
ons)
Foreign exchange forward contracts< 1.52----
Natural gas derivatives:
Swaps and optionsUp to 4123(121)(121)(162)(162)
Gas purchase contract premiumsUp to 330(2)(2)(5)(5)

The foreign exchange forward contracts are held by the FortisBC Energy companies. During 2010 FEI entered into a foreign exchange forward contract to hedge the cash flow risk related to approximately US$7 million remaining to be paid under a contract for the implementation of a customer information system. FEVI also hedges the cash flow risk related to approximately US$1 million remaining to be paid under a contract for the construction of an LNG storage facility.

The natural gas derivatives are held by the FortisBC Energy 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 FortisBC Energy 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 and the natural gas derivatives were recorded in accounts payable as at March 31, 2011 and as at December 31, 2010.

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 FortisBC Energy companies would have to receive or pay to terminate the 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

With the exception of letters of credit outstanding of $123 million, as at March 31, 2011, 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

There were no changes in the Corporation's significant business risks during the first quarter of 2011 from those disclosed in the MD&A for the year ended December 31, 2010, except for those described below.

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. During the first quarter of 2011, DBRS confirmed its existing credit rating for Newfoundland Power.

Defined Benefit Pension Plan Performance: As at March 31, 2011, the fair value of the Corporation's consolidated defined benefit pension plan assets was $746 million, up $19 million, or 2.6%, from $727 million as at December 31, 2010.

Labour Relations: The collective agreement between FortisBC Electric and Local 378 of the Canadian Office and Professional Employees Union ("COPE") expired January 31, 2011. The Company and COPE were exploring the amalgamation of FortisBC Electric and FEI's collective agreements with COPE. The parties have agreed to terminate discussions and proceed with negotiations to renew the COPE collective agreement for FortisBC Electric. In the interim, the current collective agreement remains in full effect until such time as the parties negotiate and ratify a new agreement.

CHANGE IN ACCOUNTING TREATMENT

Effective January 1, 2011, as approved by the regulator, the cost of OPEB plans at Newfoundland Power is being expensed and recovered in customer rates based on the accrual method of accounting for OPEBs. The Company's transitional regulatory OPEB asset of $53 million as at December 31, 2010 is being amortized on a straight-line basis over 15 years. During the three months ended March 31, 2011, operating expenses increased by approximately $2 million as a result of this change in accounting treatment. Prior to January 1, 2011, the cost of OPEB plans at Newfoundland Power was being expensed and recovered in customer rates based on the cash payments made.

FUTURE ACCOUNTING CHANGES

Adoption of New Accounting Standards: Due to the continued uncertainty around the timing and adoption of a rate-regulated accounting standard by the International Accounting Standards Board, Fortis has evaluated the option of adopting United States generally accepted accounting principles ("US GAAP"), as opposed to International Financial Reporting Standards ("IFRS"), effective January 1, 2012. Canadian rules allow a reporting issuer to prepare and file its financial statements in accordance with US GAAP by qualifying as a U.S. Securities and Exchange Commission ("SEC") Issuer. An SEC Issuer is defined under the Canadian rules as an issuer that: (i) has a class of securities registered with the SEC under Section 12 of the U.S. Securities Exchange Act of 1934, as amended (the "Exchange Act"); or (ii) is required to file reports under Section 15(d) of the Exchange Act. The Corporation has developed and initiated a plan to become an SEC Issuer by December 31, 2011. As an SEC Issuer, Fortis will then be permitted to prepare and file its consolidated financial statements in accordance with US GAAP. Barring a change that will provide certainty as to the Corporation's ability to recognize regulatory assets and liabilities under IFRS, Fortis expects to prepare its consolidated financial statements in accordance with US GAAP for all interim and annual periods beginning on or after January 1, 2012. Several other Canadian investor-owned rate-regulated utilities are also expected to take a similar approach to possible adoption of US GAAP in 2012.

The adoption of US GAAP in 2012 is expected to result in fewer significant changes to the Corporation's accounting policies as compared to accounting policy changes that may have resulted from the adoption of IFRS. The Corporation's application of Canadian GAAP currently relies on US GAAP for guidance on accounting for rate-regulated activities, which allows the economic impact of rate-regulated activities to be recognized in the consolidated financial statements in a manner consistent with the timing by which amounts are reflected in customer rates. Fortis believes that the continued application of rate-regulated accounting, and the associated recognition of regulatory assets and liabilities under US GAAP, more accurately reflects the impact that rate regulation has on the Corporation's consolidated financial position and results of operations. Should the Corporation not be successful in becoming an SEC Issuer by December 31, 2011, Fortis will be required to adopt IFRS effective January 1, 2012.

The Corporation has developed a three-phase plan to adopt US GAAP effective January 1, 2012. The following is an overview of the activities under each phase and their current status.

Phase I - Scoping and Diagnostics: This phase consists of project initiation and awareness; project planning and resourcing; identification of high-level differences between US GAAP and Canadian GAAP to highlight areas where detailed analysis is needed to determine and conclude as to the nature and extent of impacts; and identification of SEC registration procedures and subsequent reporting requirements. External accounting and legal advisors were engaged during this phase to assist the Corporation's internal US GAAP conversion team and to provide technical input and expertise as required. Phase I commenced in the fourth quarter of 2010 and is now substantially complete. All remaining Phase I activities are scheduled for completion by mid-2011.

Phase II - Analysis and Development: This phase consists of detailed diagnostics and evaluation of the financial impacts of adopting US GAAP based on the high-level assessment conducted under Phase I; the registration of securities as required to achieve SEC Issuer status; identification and design of any new operational or financial business processes; and development of required solutions to address identified issues. Phase II also includes an assessment of ongoing requirements of the US Sarbanes-Oxley Act ("SOX"), including auditor attestation of internal controls over financial reporting, and a comparison of the requirements under SOX to those required in Canada under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings.

Phase II of the plan commenced in January 2011. Based on the research and analysis completed to date, and the Corporation's continued ability to apply rate-regulated accounting policies under US GAAP, the differences between US GAAP and Canadian GAAP are not expected to have a material impact on consolidated earnings and are expected to be mostly limited to changes in balance sheet classifications and additional disclosure requirements. The impact on information systems is also expected to be minimal.

Phase II, including the quantification of differences between US GAAP and Canadian GAAP and reconciliation of the Corporation's financial statements from Canadian GAAP to US GAAP for 2009 and 2010, is scheduled for completion by September 30, 2011.

Phase III - Implementation and Review: This phase involves implementation of the changes required by the Corporation to prepare and file its consolidated financial statements based on US GAAP beginning in 2012 and communication of the associated impacts. Phase III will commence in the second quarter of 2011. Beginning with the first quarter of 2012, the Corporation's unaudited interim consolidated financial statements are expected to be prepared in accordance with US GAAP. Phase III will essentially conclude when the Corporation issues its first annual audited US GAAP consolidated financial statements for the year ending 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 quarter of 2011 from those disclosed in the MD&A for the year ended December 31, 2010.

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 contingent liabilities from those disclosed in the MD&A for the year ended December 31, 2010.

SUMMARY OF QUARTERLY RESULTS

The following table sets forth unaudited quarterly information for each of the eight quarters ended June 30, 2009 through March 31, 2011. 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, 3 and 5 to the Corporation's 2010 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
($) Diluted ($)
March 31, 20111,1641170.670.65
December 31, 20101,036850.490.47
September 30, 2010720450.260.26
June 30, 2010835550.320.32
March 31, 20101,0731000.580.56
December 31, 20091,020810.480.46
September 30, 2009665360.210.21
June 30, 2009756530.310.31

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 cost of natural gas, which are flowed through to customers without markup. Given the diversified nature of the Fortis subsidiaries, seasonality may vary. Most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters. Financial results for the fourth quarter ended December 31, 2009 reflected the favourable cumulative retroactive impact, from January 1, 2009, associated with an increase in the allowed ROE and equity component for FortisAlberta. The commissioning of the Vaca hydroelectric generating facility in March 2010 has favourably impacted financial results since that date. Financial results for the third quarter ended September 30, 2010 reflected the favourable cumulative retroactive impact associated with a 2010-2011 regulatory rate decision for FortisAlberta. To a lesser degree, financial results from October 2009 have been favourably impacted by the acquisition of Algoma Power.

March 2011/March 2010: Net earnings attributable to common equity shareholders were $117 million, or $0.67 per common share, for the first quarter of 2011 compared to earnings of $100 million, or $0.58 per common share, for the first quarter of 2010. A discussion of the variances between the financial results for the first quarter of 2011 and the first quarter of 2010 is provided in the "Financial Highlights" section of this MD&A.

December 2010/December 2009: Net earnings attributable to common equity shareholders were $85 million, or $0.49 per common share, for the fourth quarter of 2010 compared to earnings of $81 million, or $0.48 per common share, for the fourth quarter of 2009. The increase was mainly due to improved performance at Canadian Regulated Electric Utilities, non-regulated hydroelectric generation operations in Belize and lower effective corporate income taxes at Fortis Properties, partially offset by lower earnings from the FortisBC Energy companies and Caribbean Regulated Electric Utilities. Improved performance at Canadian Regulated Electric Utilities was driven by overall growth in electrical infrastructure investment, combined with customer growth at FortisAlberta and the higher allowed ROE at FortisBC Electric. Earnings were lower quarter over quarter at the FortisBC Energy companies, as a result of higher regulator-approved operating expenses and the timing of the recognition of these increased expenses, and at Caribbean Regulated Electric Utilities, mainly due to lower electricity sales associated with cooler-than-normal temperatures experienced in the region and the inability of Belize Electricity to earn a fair and reasonable return due to regulatory challenges. Earnings for the fourth quarter of 2009 were reduced by $5 million related to the expensing of the project cost overrun associated with the conversion Whistler customer appliances from propane to natural gas, but were favourably impacted by a one-time $3 million tax adjustment at FortisOntario.

September 2010/September 2009: Net earnings attributable to common equity shareholders were $45 million, or $0.26 per common share, for the third quarter of 2010 compared to earnings of $36 million, or $0.21 per common share, for the third quarter of 2009. The increase in earnings was mainly due to improved performance at the regulated electric utilities in western Canada and non-regulated hydroelectric generation operations, partially offset by a higher loss incurred at the FortisBC Energy companies and higher corporate expenses. Improved performance at the regulated electric utilities in western Canada was due to higher allowed ROEs and/or equity component of capital structure, growth in electrical infrastructure investment combined with an increase in the number of customers at FortisAlberta, partially offset by a weather-related decrease in electricity sales at FortisBC Electric and lower net transmission revenue at FortisAlberta. The increase in earnings' contribution from non-regulated hydroelectric generation operations was the result of increased production in Belize, driven by higher rainfall and the commissioning of the Vaca hydroelectric generating facility in March 2010, and lower finance charges. The higher loss at the FortisBC Energy companies quarter over quarter largely related to increased operating and maintenance expenses at FEI that were approved by the BCUC as part of the recent NSA. The loss in the third quarter of 2010, however, was reduced by $4 million (after tax) related to the BCUC-approved reversal of most of the project cost overrun previously expensed in the fourth quarter of 2009 associated with the conversion of Whistler customer appliances from propane to natural gas. The increase in corporate expenses was associated with higher preference share dividends, partially offset by lower finance charges.

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 FortisBC Energy companies and FortisBC Electric, partially offset by higher corporate expenses. The increase in earnings at the FortisBC Energy companies related to higher allowed ROEs and equity component of capital structure. The improvement in earnings at FortisBC Electric 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 business development costs incurred in 2010 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 of capital structure, compared to those reflected in FortisAlberta's earnings for the second quarter of 2009, combined with growth in electrical infrastructure investment and an increase in customers, was mainly offset by lower corporate income tax recoveries and lower net transmission revenue.

OUTLOOK

The Corporation's significant capital program, which is expected to be $5.5 billion over the next five years, should drive growth in earnings and dividends.

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

OUTSTANDING SHARE DATA

As at May 3, 2011, the Corporation had issued and outstanding 175.5 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 May 3, 2011 is as follows:

Conversion of Securities into Common Shares(Unaudited)
As at May 3, 2011
SecurityNumber of Common
Shares
(millions)
Stock Options5.0
Convertible Debt1.4
First Preference Shares, Series C4.1
First Preference Shares, Series E6.5
Total17.0

Additional information, including the Fortis 2010 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 months ended March 31, 2011 and 2010

(Unaudited)

Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
March 31,December 31,
20112010
ASSETS
Current assets
Cash and cash equivalents$ 86$ 109
Accounts receivable (Note 18)700655
Prepaid expenses1817
Regulatory assets (Note 5)201241
Inventories (Note 6)88168
Future income taxes1614
1,1091,204
Assets held for sale4545
Other assets166168
Regulatory assets (Note 5)866831
Future income taxes1016
Utility capital assets8,3518,202
Income producing properties556560
Intangible assets325324
Goodwill1,5491,553
$ 12,977$ 12,903
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 18)$ 259$ 358
Accounts payable and accrued charges942953
Dividends payable5554
Income taxes payable4230
Regulatory liabilities (Note 5)8960
Current installments of long-term debt and capital lease obligations (Note 7)5556
Future income taxes36
1,4451,517
Other liabilities309308
Regulatory liabilities (Note 5)509467
Future income taxes629623
Long-term debt and capital lease obligations (Note 7)5,6015,609
Preference shares320320
8,8138,844
Shareholders' equity
Common shares (Note 8)2,6072,578
Preference shares592592
Contributed surplus1212
Equity portion of convertible debentures55
Accumulated other comprehensive loss (Note 10)(97)(94)
Retained earnings870804
3,9893,897
Non-controlling interests175162
4,1644,059
$ 12,977$ 12,903
Contingent liabilities and commitments (Note 19)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars, except per share amounts)
Quarter Ended
20112010
Revenue$ 1,164$ 1,073
Expenses
Energy supply costs603552
Operating213202
Amortization10394
919848
Operating income245225
Finance charges (Note 12)9090
Earnings before corporate taxes155135
Corporate taxes (Note 13)3028
Net earnings$ 125$ 107
Net earnings attributable to:
Non-controlling interests$ 1$ 1
Preference equity shareholders76
Common equity shareholders117100
$ 125$ 107
Earnings per common share (Note 8)
Basic$ 0.67$ 0.58
Diluted$ 0.65$ 0.56
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
20112010
Balance at beginning of period$ 804$ 763
Net earnings attributable to common and preference equity shareholders124106
928869
Dividends on common shares(51)(96)
Dividends on preference shares classified as equity(7)(6)
Balance at end of period$ 870$ 767
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
20112010
Net earnings$ 125$ 107
Other comprehensive (loss) income
Unrealized foreign currency translation losses on net investments in self-sustaining foreign operations(15)(20)
Gains on hedges of net investments in self-sustaining foreign operations1414
Corporate tax expense(2)(2)
Unrealized foreign currency translation losses, net of hedging activities and tax(Note 10)(3)(8)
Comprehensive income$ 122$ 99
Comprehensive income attributable to:
Non-controlling interests$ 1$ 1
Preference equity shareholders76
Common equity shareholders11492
$ 122$ 99
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
20112010
(Note 20)
Operating activities
Net earnings$125$107
Items not affecting cash:
Amortization - utility capital assets and income producing properties9483
Amortization - intangible assets1011
Amortization - other(1)-
Future income taxes(2)(3)
Other(2)2
Change in long-term regulatory assets and liabilities184
242204
Change in non-cash operating working capital57(3)
299201
Investing activities
Change in other assets and other liabilities(3)2
Capital expenditures - utility capital assets(219)(179)
Capital expenditures - income producing properties(3)(6)
Capital expenditures - intangible assets(11)(3)
Contributions in aid of construction1210
Proceeds on sale of utility capital assets and income producing properties5-
(219)(176)
Financing activities
Change in short-term borrowings(98)(181)
Repayments of long-term debt and capital lease obligations(4)(16)
Net borrowings (repayments) under committed credit facilities15(29)
Advances from non-controlling interests17-
Issue of common shares, net of costs2723
Issue of preference shares, net of costs-242
Dividends
Common shares(51)(48)
Preference shares(7)(6)
Subsidiary dividends paid to non-controlling interests(2)(2)
(103)(17)
Effect of exchange rate changes on cash and cash equivalents-(1)
Change in cash and cash equivalents(23)7
Cash and cash equivalents, beginning of period10985
Cash and cash equivalents, end of period$86$92
Supplementary Information to Consolidated Statements of Cash Flows (Note 15)
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three months ended March 31, 2011 and 2010
(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 long-term objectives of Fortis. 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 2010 annual audited consolidated financial statements.

REGULATED UTILITIES

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

  1. Regulated Gas Utilities – Canadian: Includes the FortisBC Energy companies, which is comprised of FortisBC Energy Inc. ("FEI") (formerly Terasen Gas Inc.), FortisBC Energy (Vancouver Island) Inc. ("FEVI") (formerly Terasen Gas (Vancouver Island) Inc.) and FortisBC Energy (Whistler) Inc. (formerly Terasen Gas (Whistler) Inc.).
  1. Regulated Electric Utilities – Canadian: Includes FortisAlberta; FortisBC Electric (formerly referred to as 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 Algoma Power Inc.
  1. Regulated Electric Utilities – Caribbean: Includes Belize Electricity, in which Fortis holds an approximate 70% controlling ownership interest; Caribbean Utilities, in which Fortis holds an approximate 59% 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 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 2.7 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 FortisBC Holdings Inc. ("FHI") (formerly Terasen Inc.) corporate-related activities, and the financial results of FHI's 30% ownership interest in CustomerWorks Limited Partnership and of FHI's non-regulated wholly owned subsidiary FortisBC Alternative Energy Services Inc. (formerly Terasen Energy Services Inc.).

2. SUMMARY OF SIGNIFICANT ACCOUNTINGPOLICIES

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 2010 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, most of the earnings of the FortisBC Energy companies are realized 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 2010 annual audited consolidated financial statements, except as described below.

Effective January 1, 2011, as approved by the regulator, the cost of other post-employment benefit ("OPEB") plans at Newfoundland Power is being expensed and recovered in customer rates based on the accrual method of accounting for OPEBs. The Company's transitional regulatory OPEB asset of $53 million as at December 31, 2010 is being amortized on a straight-line basis over 15 years. During the three months ended March 31, 2011, operating expenses increased by approximately $2 million as a result of this change in accounting treatment. Prior to January 1, 2011, the cost of OPEB plans at Newfoundland Power was being expensed and recovered in customer rates based on the cash payments made.

3. FUTURE ACCOUNTING CHANGES

Effective January 1, 2012, the Corporation will be required to adopt a new set of accounting standards. Publicly accountable enterprises in Canada were required to adopt International Financial Reporting Standards ("IFRS") effective January 1, 2011; however, qualifying entities with rate-regulated activities were granted an optional one-year deferral for the adoption of IFRS, due to the continued uncertainty around the timing and adoption of a rate-regulated accounting standard by the International Accounting Standards Board ("IASB"). As a qualifying entity with rate-regulated activities, Fortis has elected to opt for the one-year deferral and, therefore, will continue to prepare its consolidated financial statements in accordance with Part V of the Canadian Institute of Chartered Accountants Handbook for all interim and annual periods ending on or before December 31, 2011.

Due to the continued uncertainty around the timing and adoption of a rate-regulated accounting standard by the IASB, Fortis has evaluated the option of adopting United States generally accepted accounting principles ("US GAAP"), as opposed to IFRS, effective January 1, 2012. Canadian rules allow a reporting issuer to prepare and file its financial statements in accordance with US GAAP by qualifying as a U.S. Securities and Exchange Commission ("SEC") Issuer. An SEC Issuer is defined under the Canadian rules as an issuer that: (i) has a class of securities registered with the SEC under Section 12 of the U.S. Securities Exchange Act of 1934, as amended (the "Exchange Act"); or (ii) is required to file reports under Section 15(d) of the Exchange Act. The Corporation has developed and initiated a plan to become an SEC Issuer by December 31, 2011. As an SEC Issuer, Fortis will then be permitted to prepare and file its consolidated financial statements in accordance with US GAAP. Barring a change that will provide certainty as to the Corporation's ability to recognize regulatory assets and liabilities under IFRS, Fortis expects to prepare its consolidated financial statements in accordance with US GAAP for all interim and annual periods beginning on or after January 1, 2012.

The adoption of US GAAP in 2012 is expected to result in fewer significant changes to the Corporation's accounting policies as compared to accounting policy changes that may have resulted from the adoption of IFRS. The Corporation's application of Canadian GAAP currently relies on US GAAP for guidance on accounting for rate-regulated activities, which allows the economic impact of rate-regulated activities to be recognized in the consolidated financial statements in a manner consistent with the timing by which amounts are reflected in customer rates. Fortis believes that the continued application of rate-regulated accounting, and the associated recognition of regulatory assets and liabilities under US GAAP, more accurately reflects the impact that rate regulation has on the Corporation's consolidated financial position and results of operations. Should the Corporation not be successful in becoming an SEC Issuer by December 31, 2011, Fortis will be required to adopt IFRS effective January 1, 2012.

4. USE OF ESTIMATES

The preparation of 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 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 in which they become known.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2011.

5. REGULATORY ASSETS AND LIABILITIES

A summary of the Corporation's regulatory assets and liabilities is provided below. A detailed description of the nature of the Corporation's regulatory assets and liabilities is provided in Note 5 to the Corporation's 2010 annual audited consolidated financial statements.

As at
($ millions)March 31,
2011
December 31,
2010
Regulatory assets
Future income taxes583568
Rate stabilization accounts - FortisBC Energy companies112146
Rate stabilization accounts - electric utilities4944
Regulatory OPEB plan assets6666
Point Lepreau (1) replacement energy deferral4744
2010 accrued distribution revenue adjustment rider2736
Deferred energy management costs2423
Deferred losses on disposal of utility capital assets1916
Income taxes recoverable on OPEB plans1818
Alberta Electric System Operator ("AESO") charges deferral1719
Deferred operating costs1411
Deferred development costs for capital1111
Deferred costs - smart meters88
Deferred lease costs66
Deferred pension costs55
Other regulatory assets6151
Total regulatory assets1,0671,072
Less: current portion(201)(241)
Long-term regulatory assets866831
(1) New Brunswick Power Point Lepreau Nuclear Generating Station
As at
($ millions)March 31,
2011
December 31,
2010
Regulatory liabilities
Asset removal and site restoration provision343339
Rate stabilization accounts - FortisBC Energy companies11960
Rate stabilization accounts - electric utilities5045
AESO charges deferral129
Deferred interest87
Performance-based rate-setting incentive liabilities78
Southern Crossing Pipeline deferral75
Unrecognized net gains on disposal of utility capital assets68
Unbilled revenue liability65
2010 FEI revenue surplus57
Other regulatory liabilities3534
Total regulatory liabilities598527
Less: current portion(89)(60)
Long-term regulatory liabilities509467

6. INVENTORIES

As at
($ millions)March 31,
2011
December 31,
2010
Gas in storage65148
Materials and supplies2320
88168

During the three months ended March 31, 2011, inventories of $344 million were expensed and reported in energy supply costs on the interim consolidated statement of earnings ($305 million for the three months ended March 31, 2010). Inventories expensed to operating expenses were $3 million for the three months ended March 31, 2011 ($3 million for the three months ended March 31, 2010), which included $2 million for food and beverage costs at Fortis Properties ($2 million for the three months ended March 31, 2010).

7. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

As at
($ millions)March 31,
2011
December 31,
2010
Long-term debt and capital lease obligations5,4635,489
Long-term classification of committed credit facilities (Note 18)234218
Deferred debt financing costs(41)(42)
Total long-term debt and capital lease obligations5,6565,665
Less: Current installments of long-term debt and capital
lease obligations
(55)(56)
5,6015,609

8. COMMON SHARES

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

As at
Issued and OutstandingMarch 31, 2011December 31, 2010
Number of Shares
(in thousands)

Amount
($ millions)
Number of Shares
(in thousands)

Amount
($ millions)
Common shares175,4222,607174,3932,578
Common shares issued during the period were as follows:
Quarter Ended
March 31, 2011
Number of
Shares
(in thousands)

Amount
($ millions)
Balance, beginning of period174,3932,578
Dividend Reinvestment Plan51517
Consumer Share Purchase Plan131
Stock Option Plans50111
Balance, end of period175,4222,607

Earnings per Common Share

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

Diluted EPS was calculated using the treasury stock method for options and the "if-converted" method for convertible securities.

EPS were as follows:

Quarter Ended March 31
20112010
WeightedWeighted
AverageAverage
EarningsSharesEarningsShares
($ millions)(in millions)EPS($ millions)(in millions)EPS
Basic EPS117175.0$0.67100171.6$0.58
Effect of potential dilutive securities:
Stock Options-1.2-1.0
Preference Shares (Note 12)410.1411.9
Convertible Debentures11.411.4
Diluted EPS122187.7$0.65105185.9$0.56

9. STOCK-BASED COMPENSATION PLANS

In January 2011 27,070 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 ("DSU") represents a unit with an underlying value equivalent to the value of one common share of the Corporation. In March 2011 31,821 DSUs were paid out as a result of the death of one of the members of the Board of Directors of Fortis at $33.06 per DSU, for a total of approximately $1.1 million.

In March 2011 45,000 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 2011 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 the achievement of payment requirements. In March 2011 37,079 PSUs were paid out to the President and CEO of the Corporation at $33.11 per PSU, for a total of approximately $1.2 million. The payout was made upon the three-year maturation period in respect of the PSU grant made in February 2008 and the President and CEO satisfying the payment requirements, as determined by the Human Resources Committee of the Board of Directors.

In March 2011 the Corporation granted 828,512 options to purchase common shares under its 2006 Stock Option Plan at the five-day volume weighted average trading price of $32.95 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 $4.57 per option.

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

Dividend yield (%)3.68
Expected volatility (%)23.1
Risk-free interest rate (%)2.00
Weighted average expected life (years)4.5

As at March 31, 2011, 5.0 million stock options were outstanding and 2.7 million stock options were vested.

10. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss includes unrealized foreign currency translation gains and losses, net of hedging activities, and gains and losses on discontinued cash flow hedging activities as described in Note 3 to the Corporation's 2010 annual audited consolidated financial statements.

Quarter Ended March 31
20112010
($ millions)Opening
balance
January 1
Net changeEnding
balance
March 31
Opening balance
January 1
Net
change
Ending balance
March 31
Unrealized foreign currency translation losses, net of hedging activities and tax(90)(3)(93)

(78
)

(8
)

(86
)
Net losses on derivative instruments previously discontinued as cash flow hedges, net of tax


(4
)


-



(4
)


(5
)


-



(5
)
Accumulated other
comprehensive loss
(94)(3)(97)
(83
)
(8
)
(91
)

11. 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 $15 million for the three months ended March 31, 2011 ($9 million for the three months ended March 31, 2010). The cost of providing the defined contribution arrangements and group RRSPs for the three months ended March 31, 2011 was $4 million ($4 million for the three months ended March 31, 2010).

12. FINANCE CHARGES

Quarter Ended
March 31
($ millions)20112010
Interest- Long-term debt and capital lease obligations9088
- Short-term borrowings and other42
Interest charged during construction(8)(4)
Dividends on preference shares classified as debt (Note 8)44
9090

13. 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
March 31
($ millions, except as noted)20112010
Combined Canadian federal and provincial statutory income tax rate30.5 %32.0 %
Statutory income tax rate applied to earnings before corporate taxes4743
Preference share dividends11
Difference between Canadian statutory rate and rates applicable to
foreign subsidiaries

(2
)
(2
)
Difference in Canadian provincial statutory rates applicable to
subsidiaries in different Canadian jurisdictions

(6
)
(4
)
Items capitalized for accounting purposes but expensed for income
tax purposes

(16
)
(12
)
Difference between capital cost allowance and amounts claimed for
accounting purposes

3

-
Other32
Corporate taxes3028
Effective tax rate19.4 %20.7 %

As at March 31, 2011, the Corporation had approximately $97 million (December 31, 2010 - $101 million) in non-capital and capital loss carryforwards, of which $18 million (December 31, 2010 - $18 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2014 and 2031.

14. SEGMENTED INFORMATION

Information by reportable segment is as follows:

REGULATEDNON-REGULATED
Gas UtilitiesElectric Utilities
Quarter Ended
March 31, 2011
($ millions)
FortisBC Energy
Companies -
Canadian

Fortis
Alberta

FortisBC
Electric

New-foundland
Power

Other
Cana-
dian
Total
Electric
Canadian

Electric
Carib-
bean

Fortis
Gene-ration(1)

Fortis
Properties

Corporate
and Other
Inter-
segment
eliminations


Consolidated
Revenue5751038318391460767507(11)1,164
Energy supply costs344-231346021746---(4)603
Operating expenses773518201285113372(2)213
Amortization263311106609152-103
Operating income128353119139810383(5)245
Finance charges2913995365-619(5)90
Corporate tax expense (recovery)2313329--1(3)-30
Net earnings (loss)7621197653531(13)-125
Non-controlling interests------1----1
Preference share dividends---------7-7
Net earnings (loss) attributable to
common equity shareholders
7621197653431(20)-117
Goodwill908227221-63511130----1,549
Identifiable assets4,2502,1811,2851,2236475,336774402575483(392)11,428
Total assets5,1582,4081,5061,2237105,847904402575483(392)12,977
Gross capital expenditures (2)49853014813721233--233
Quarter Ended
March 31, 2010
($ millions)
Revenue526877217882419765497(9)1,073
Energy supply costs305-211315320545---(3)552
Operating expenses703517161179122364(1)202
Amortization272410115509143-94
Operating income12428242013851029-(5)225
Finance charges2714896375-620(5)90
Corporate tax expense (recovery)24-2428--1(5)-28
Net earnings (loss)7314147540522(15)-107
Non-controlling interests------1----1
Preference share dividends---------6-6
Net earnings (loss) attributable to
common equity shareholders
7314147540422(21)-100
Goodwill908227221-63511136----1,555
Identifiable assets4,1301,9221,1571,2086204,907781183607518(421)10,705
Total assets5,0382,1491,3781,2086835,418917183607518(421)12,260
Gross capital expenditures (2)5064261781151715--188
(1) Results reflect contribution from the Vaca hydroelectric generating facility in Belize, which was commissioned in March 2010, and the Waneta Partnership, which was established in October 2010.
(2)Relates to cash payments to acquire or construct utility capital assets, including amounts for AESO transmision-related capital projects, income producing properties and intangible assets, as reflected on the consolidated statement of cash flows

Inter-segment transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The significant inter-segment transactions primarily related to the sale of energy from Fortis Generation to Belize Electricity, electricity sales from Newfoundland Power to Fortis Properties and finance charges on inter-segment borrowings. The significant inter-segment transactions for the three months ended March 31, 2011 and 2010 were as follows:

Significant Inter-Segment TransactionsQuarter Ended
March 31
($ millions)20112010
Sales from Fortis Generation to Regulated Electric Utilities – Caribbean43
Sales from Newfoundland Power to Fortis Properties11
Inter-segment finance charges on borrowings from:
Corporate to Regulated Electric Utilities – Caribbean11
Corporate to Fortis Generation11
Corporate to Fortis Properties32

The significant inter-segment asset balances were as follows:

As at March 31
($ millions)20112010
Inter-segment borrowings from:
Corporate to Regulated Electric Utilities - Canadian5075
Corporate to Regulated Electric Utilities - Caribbean5846
Corporate to Fortis Generation5058
Corporate to Fortis Properties222223
Other inter-segment assets1219
Total inter-segment eliminations392421

15. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

Quarter Ended
March 31
($ millions)20112010
Interest paid8181
Income taxes paid2424

16. CAPITAL MANAGEMENT

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

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

As at
March 31, 2011December 31, 2010
($ millions)(%)($ millions)(%)
Total debt and capital lease obligations (net of cash) (1)5,82957.55,91458.4
Preference shares (2)9129.09129.0
Common shareholders' equity3,39733.53,30532.6
Total (3)10,138100.010,131100.0
(1)Includes long-term debt and capital lease obligations, including current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities and equity
(3)Excludes amounts related to non-controlling interests

Certain of the Corporation's long-term debt obligations have covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70% of the Corporation's consolidated capital structure, as defined by the long-term debt agreements. In addition, one of the Corporation's long-term debt obligations contains a covenant which provides that Fortis shall not declare or pay any dividends, other than stock dividends or cumulative preferred dividends on preference shares not issued as stock dividends, or make any other distribution on its shares or redeem any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would be in excess of 75% of its total consolidated capitalization.

As at March 31, 2011, the Corporation and its subsidiaries, except for certain debt at Belize Electricity and the Exploits River Hydro Partnership ("Exploits Partnership"), as described below, were in compliance with their debt covenants.

As a result of the regulator's Final Decision on Belize Electricity's 2008/2009 Rate Application in June 2008, Belize Electricity continues to not meet certain debt covenant financial ratios related to loans with the International Bank for Reconstruction and Development and the Caribbean Development Bank totalling $4 million (BZ$8 million) as at March 31, 2011.

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 $57 million as at March 31, 2011 (December 31, 2010 - $58 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 expropriation matters. For further information refer to Note 30 to the Corporation's 2010 annual audited consolidated financial statements.

The Corporation's credit ratings and consolidated credit facilities are discussed further under "Liquidity Risk" in Note 18.

17. FINANCIAL INSTRUMENTS

Fair Values

There has been no change during the three months ended March 31, 2011 in the designation of the Corporation's financial instruments from that disclosed in the Corporation's 2010 annual audited consolidated financial statements.

The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows:

As at
March 31, 2011December 31, 2010

($ millions)
Carrying ValueEstimated
Fair Value
Carrying ValueEstimated
Fair Value
Waneta Partnership promissory note (1) (2)43414240
Long-term debt, including current portion (3) (4)5,6586,2785,6696,431
Preference shares, classified as debt (3) (5)320343320344
(1) Included in other liabilities on the consolidated balance sheet
(2) Carrying value is a discounted present value.
(3) Carrying value is measured at amortized cost using the effective interest rate method.
(4) Carrying value as at March 31, 2011 excludes unamortized deferred financing costs of $41 million (December 31, 2010 - $42 million) and capital lease obligations of $39 million (December 31, 2010 - $38 million).
(5) 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 $612 million as at March 31, 2011 (December 31, 2010 – $615 million).

The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note, 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 or promissory note 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.

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.

As at
March 31, 2011December, 31, 2010
LiabilityTerm to
Maturity
(years)
Number of
Contracts
Carrying Value
($ milli-
ons)
Estimated Fair
Value
($ milli-
ons)
Carrying Value
($ milli-
ons)
Estimated Fair
Value
($ milli-
ons)
Foreign exchange forward contracts (1) (2)< 1.52--
-

-
Natural gas derivatives: (1) (3)
Swaps and optionsUp to 4123(121)(121)(162)(162)
Gas purchase contract premiumsUp to 330
(2
)
(2
)
(5
)
(5
)
(1)The fair value measurements are Level 2, based on the three levels that distinguish the level of pricing observability utilized in measuring fair value.
(2) The fair values of the foreign exchange forward contracts were recorded in accounts payable as at March 31, 2011 and as at December 31, 2010.
(3) The fair values of the natural gas derivatives were recorded in accounts payable as at March 31, 2011 and as at December 31, 2010.

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.

18. FINANCIAL RISK MANAGEMENT

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

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

Credit Risk

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

FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at March 31, 2011, its gross credit risk exposure was approximately $125 million, representing the projected value of retailer billings over a 60-day period. The Company has reduced its exposure to approximately $5 million by obtaining from the retailers either a cash deposit, bond, letter of credit or an investment-grade credit rating from a major rating agency, or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.

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

The aging analysis of the Corporation's consolidated trade and other accounts receivable, net of an allowance for doubtful accounts of $18 million as at March 31, 2011 (December 31, 2010 - $16 million; March 31, 2010 - $17 million) was as follows:


($ millions)
As at
March 31,
2011
December 31,
2010
March 31,
2010
Not past due601584518
Past due 0-30 days765663
Past due 31-60 days15914
Past due 61 days and over869
700655604

As at March 31, 2011, other long-term receivables of $14 million (included in other assets) will be received over the next five years and thereafter, with $1 million expected to be received in year 1, $3 million over years 2 and 3, $1 million over years 4 and 5 and $9 million due after 5 years.

Liquidity Risk

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

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

The Corporation's committed credit facility is available for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at March 31, 2011, average annual consolidated long-term debt maturities and repayments over the next five years are expected to be approximately $250 million. The combination of available credit facilities and relatively low annual debt maturities and repayments will provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

As at March 31, 2011, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.1 billion, of which $1.5 billion was unused. The credit facilities are syndicated almost entirely with the seven largest Canadian banks, with no one bank holding more than 25% of these facilities.

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

As at
($ millions)Corporate
and Other
Regulated
Utilities
Fortis
Properties
March 31,
2011
December
31,
2010
Total credit facilities6451,440132,0982,109
Credit facilities utilized:
Short-term borrowings-(255)(4)(259)(358)
Long-term debt (Note 7) (1)(155)(79)-(234)(218)
Letters of credit outstanding(1)(122)-(123)(124)
Credit facilities unused48998491,4821,409
(1) As at March 31, 2011, credit facility borrowings classified as long-term included $16 million (December 31, 2010 - $16 million) that was included in current installments of long-term debt and capital lease obligations on the consolidated balance sheet.

As at March 31, 2011 and December 31, 2010, 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 2011 Maritime Electric renewed its unsecured committed revolving credit facility, which matures annually in March. The unsecured committed revolving credit facility was reduced from $60 million to $50 million.

In April 2011 FortisBC Electric negotiated and finalized an amended credit facility agreement resulting in an extension to the maturity of the Company's $150 million unsecured committed revolving credit facility with $100 million now maturing in May 2014 and $50 million now maturing in May 2012.

The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at March 31, 2011, the Corporation's credit ratings were as follows:

Standard & Poor'sA- (long-term corporate and unsecured debt credit rating)
DBRSA(low) (unsecured debt credit rating)

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

The following is an analysis of the contractual maturities of the Corporation's consolidated financial liabilities as at March 31, 2011.

Financial Liabilities
($ millions)
Due
within 1 year
Due in years
2 and 3
Due in years
4 and 5
Due after
5 years


Total
Short-term borrowings259---259
Trade and other accounts payable819---819
Natural gas derivatives (1)71388-117
Foreign exchange forward contracts (2)61--7
Dividends payable55---55
Customer deposits (3)-3126
Waneta Partnership promissory note (4)---7272
Long-term debt, including current portion (5)523897834,4345,658
Interest obligations on long-term debt3466786094,9846,617
Preference shares, classified as debt-123-197320
Dividend obligations on preference shares,
classified as finance charges
173019571
1,6251,2621,4209,69414,001
(1) Amounts disclosed are on a gross cash flow basis. The derivatives were recorded in accounts payable at fair value as at March 31, 2011 at $123 million.
(2) Amounts disclosed are on a gross cash flow basis. The contracts were recorded in accounts payable at fair value as at March 31, 2011 at less than $1 million.
(3) Customer deposits were recorded in other liabilities as at March 31, 2011.
(4) Amounts disclosed are on a gross cash flow basis.The promissory note was recorded in other liabilities at present value as at March 31, 2011 at $43 million.
(5) Excludes deferred financing costs of $41 million and capital lease obligations of $39 million

Market Risk

Foreign Exchange Risk

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

As at March 31, 2011, all of the Corporation's US$590 million (December 31, 2010 - US$590 million) corporately held long-term debt had been designated as a hedge of a significant portion of the Corporation's foreign net investments. As at March 31, 2011, the Corporation had approximately US$14 million (December 31, 2010 – US$7 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 recognized in other comprehensive income and help offset unrealized foreign currency exchange gains and losses on the foreign net investments, which are also recognized in other comprehensive income.

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

Interest Rate Risk

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

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

Commodity Price Risk

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

The price risk-management strategy of the FortisBC Energy 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. On an annual basis, FEI and FEVI each file a Price Risk-Management Plan ("PRMP") that seeks approval for the natural gas commodity hedging plan for the next three years for FEI and the next five years for FEVI. During the third quarter of 2010, the BCUC denied the PRMP application filed by the FortisBC Energy companies earlier in 2010 and directed the Companies to undertake a review of the primary objectives of the PRMP. In January 2011 the FortisBC Energy companies reviewed the PRMP objectives with the BCUC related to their gas commodity hedging plan and FEI submitted a 2011–2014 PRMP. On a partial basis, the BCUC has approved FEI to implement portions of its 2011-2014 PRMP. FEVI plans to file an updated PRMP by June 2011.

19. CONTINGENT LIABILITIES AND COMMITMENTS

Contingent Liabilities

The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with ordinary course business operations. Management believes that the amount of liability, if any, from these actions would not have a material effect on the Corporation's consolidated financial position or results of operations. There were no material changes in the Corporation's contingencies from those disclosed in the Corporation's 2010 annual audited consolidated financial statements.

Commitments

There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2010 annual audited consolidated financial statements, except as described below.

During the first quarter of 2011, the actuarial valuation of the defined benefit pension plan at FortisBC Energy, covering unionized employees, was completed. As a result of the actuarial valuation and other revised actuarial estimates, the total estimate of consolidated defined benefit pension funding contributions over the next five years has increased approximately $37 million from that disclosed in the Corporation's 2010 annual audited consolidated financial statements.

20. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period classifications. The most significant changes related to a $48 million decrease in cash from operating activities associated with changes in non-cash operating working capital and a corresponding decrease in cash used in financing activities associated with dividends on common shares.

CORPORATE INFORMATION

Fortis Inc. is the largest investor-owned distribution utility in Canada, with total assets of approximately $13 billion and fiscal 2010 revenue totalling approximately $3.7 billion. The Corporation serves approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State. It also owns hotels and commercial office and retail space primarily in Atlantic Canada.

The Common Shares, First Preference Shares, Series C; First Preference Shares, Series E; First Preference Shares, Series F; First Preference Shares, Series G; and First Preference Shares, Series H of Fortis are traded on the Toronto Stock Exchange under the symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F, FTS.PR.G and FTS.PR.H, respectively.

Share Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.computershare.com/fortisinc

Additional information, including the Fortis 2010 Annual Information Form, Management Information Circular and Annual Report, are available on SEDAR at www.sedar.com and on the Corporation's web site at www.fortisinc.com.

Contact Information

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