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Fortis Earns $45 Million in Third Quarter

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwire - Nov. 1, 2012) - Fortis Inc. ("Fortis" or the "Corporation") (FTS.TO) achieved third quarter net earnings attributable to common equity shareholders of $45 million, or $0.24 per common share, compared to $56 million, or $0.30 per common share, for the third quarter of 2011. Year-to-date net earnings attributable to common equity shareholders were $228 million, or $1.20 per common share, compared to $229 million, or $1.28 per common share, for the same period last year.

In 2012 earnings for the third quarter and year to date were reduced by $3.5 million and $10 million, respectively, related to foreign exchange and CH Energy Group, Inc. ("CH Energy Group") acquisition-related expenses. In 2011 earnings for the third quarter and year to date were favourably impacted by a one-time $11 million after-tax merger termination fee paid to Fortis and $2.5 million of foreign exchange.

Excluding the above impacts, improved performance at the western Canadian regulated electric utilities for the quarter was partially offset by decreased non-regulated hydroelectric generation and a higher loss incurred at the regulated gas utilities.

Canadian Regulated Electric Utilities, led by FortisAlberta and FortisBC Electric, contributed earnings of $54 million, up $11 million from the third quarter of 2011. At FortisAlberta, higher net transmission revenue, growth in energy infrastructure investment and timing of operating expenses during 2012 were partially offset by a lower allowed rate of return on common shareholder's equity. At FortisBC Electric, performance was driven by growth in energy infrastructure investment, higher pole-attachment revenue and lower-than-expected finance charges.

FortisBC Electric has offered to purchase the City of Kelowna's electrical utility assets for approximately $55 million. FortisBC Electric has operated and maintained the City of Kelowna's electrical utility assets, which currently serve approximately 15,000 customers, since 2000. Closing of the transaction is subject to certain conditions and receipt of certain approvals, including regulatory approval. FortisBC Electric and the City of Kelowna are working towards closing the transaction by the end of the first quarter of 2013.

Canadian Regulated Gas Utilities incurred a loss of $6 million compared to a loss of $4 million for the third quarter of 2011. The third quarter is normally a period of lower customer demand due to warmer temperatures. The higher loss largely related to the unfavourable impact of the difference in the timing of recognition of revenue associated with seasonal gas consumption and certain increased regulator-approved expenses in 2012, lower capitalized allowance for funds used during construction, and lower-than-expected customer additions in 2012. The above items were partially offset by higher gas transportation volumes to industrial customers and the timing of certain operating and maintenance expenses during 2012.

Year-to-date 2012, regulatory decisions have been received for: (i) 2012-2013 revenue requirements at the FortisBC Energy companies; (ii) 2012 distribution revenue requirements at FortisAlberta; and (iii) 2012-2013 revenue requirements at FortisBC Electric. The Alberta Utilities Commission issued a generic decision in September 2012 on its Performance-Based Regulation ("PBR") Initiative, outlining the PBR framework applicable to distribution utilities in Alberta for a five-year term commencing January 1, 2013. FortisAlberta will file the required PBR-compliance application in November 2012. A Generic Cost of Capital ("GCOC") Proceeding to finalize 2013 cost of capital for distribution utilities in Alberta is expected to commence late 2012 or early 2013. In British Columbia, the GCOC Proceeding to determine cost of capital, effective January 1, 2013, continues with an oral hearing scheduled for December 2012. Newfoundland Power filed a general rate application in September 2012 for 2013 customer rates and cost of capital.

Caribbean Regulated Electric Utilities contributed $7 million of earnings, compared to $6 million for the third quarter of 2011. Fortis Turks and Caicos acquired Turks and Caicos Utilities Limited ("TCU") in August 2012 for an aggregate purchase price of approximately $13 million (US$13 million), inclusive of debt assumed. TCU serves more than 2,000 customers on Grand Turk and Salt Cay with a diesel-fired generating capacity of approximately 9 megawatts ("MW"). The utility currently operates pursuant to a 50-year licence that expires in 2036.

Non-Regulated Fortis Generation contributed $5 million to earnings compared to $8 million for the same quarter last year. The decrease mainly related to lower production in Belize due to lower rainfall.

Fortis Properties delivered earnings of $8 million, compared to $9 million for the third quarter of 2011, reflecting lower occupancy at hotel operations in Atlantic Canada and central Canada, partially offset by earnings contribution from the Hilton Suites Winnipeg Airport hotel, which was acquired in October 2011. In October 2012 Fortis Properties acquired the 126-room StationPark All Suite Hotel in London, Ontario for approximately $13 million.

Corporate and other expenses were $23 million compared to $6 million for the third quarter of 2011. Excluding the $11 million after-tax termination fee paid to Fortis in July 2011, corporate and other expenses increased quarter over quarter, mainly as a result of a $3 million after-tax foreign exchange loss recognized in the third quarter of 2012 compared to a $2.5 million after-tax net foreign exchange gain recognized in the same quarter last year. Acquisition-related expenses associated with the CH Energy Group transaction were approximately $0.5 million after-tax for the third quarter of 2012.

Consolidated capital expenditures, before customer contributions, were approximately $794 million year-to-date 2012. At FortisBC Gas, the Customer Care Enhancement Project came into service at the beginning of January 2012. Construction of the $900 million, 335-MW Waneta Expansion hydroelectric generating facility ("Waneta Expansion") in British Columbia continues on time and on budget. Approximately $380 million in total has been spent on the Waneta Expansion since construction began in late 2010.

Cash flow from operating activities was $804 million year-to-date 2012, up $120 million from the same period last year, driven by favourable changes in regulatory deferral accounts and receivables and the collection of increased depreciation and amortization expense in customer rates.

Fortis announced in February 2012 that it had entered into an agreement to acquire CH Energy Group for an aggregate purchase price of approximately US$1.5 billion, including the assumption of approximately US$500 million of debt on closing. CH Energy Group's main business, Central Hudson Gas & Electric Corporation ("Central Hudson"), serves approximately 375,000 electric and gas customers in New York State's Mid-Hudson River Valley. The transaction received CH Energy Group shareholder approval in June 2012 and regulatory approval from the Federal Energy Regulatory Commission and the Committee on Foreign Investment in the United States in July 2012. The waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired in October 2012, satisfying another condition necessary for consummation of the transaction. The transaction remains subject to approval by the New York State Public Service Commission ("NYSPSC"). The acquisition is expected to close by the end of the first quarter of 2013 and be immediately accretive to earnings per common share of Fortis, excluding acquisition-related expenses.

Fortis raised gross proceeds of approximately $601 million in June 2012, upon issuance of 18,500,000 Subscription Receipts at $32.50 each, to finance a portion of the purchase price of CH Energy Group. The proceeds are being held by an escrow agent, pending satisfaction of closing conditions, including receipt of regulatory approvals, contained in the agreement to acquire CH Energy Group. Each Subscription Receipt will entitle the holder thereof to receive, on satisfaction of the closing conditions, one common share of Fortis.

In October 2012 FortisAlberta raised $125 million 40-year 3.98% unsecured debentures, largely in support of its capital expenditure program.

Fortis corporate debt is rated A- by Standard & Poor's and A(low) by DBRS.

Fortis retroactively adopted accounting principles generally accepted in the United States ("US GAAP"), effective January 1, 2012, with the restatement of prior periods. The adoption of US GAAP did not have a material impact on the Corporation's earnings per common share for the third quarter of 2012 or 2011.

"Our utilities are focused on completing their remaining capital projects for 2012. Our capital expenditures for the year are expected to reach $1.3 billion," says Stan Marshall, President and Chief Executive Officer, Fortis Inc. "Over the five-year period to 2016, our capital program is expected to total $5.5 billion; Central Hudson's capital program from 2013 through 2016 will add a further approximate $0.5 billion," he explains.

"Our largest utilities are busy with significant regulatory processes, including those related to the determination of 2013 allowed returns," says Marshall.

"Also on the regulatory front, we are focused on closing the CH Energy Group transaction by the end of the first quarter of 2013. Approval of the transaction by the NYSPSC is the one remaining significant regulatory matter," concludes Marshall.

Interim Management Discussion and Analysis

For the three and nine months ended September 30, 2012

Dated November 1, 2012


FORWARD-LOOKING STATEMENT

The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. Financial information for 2012 and comparative periods contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") and is presented in Canadian dollars unless otherwise specified. The MD&A should be read in conjunction with the following: (i) the interim unaudited consolidated financial statements and notes thereto for the three and nine months ended September 30, 2012, prepared in accordance with US GAAP; (ii) the audited consolidated financial statements and notes thereto for the year ended December 31, 2011, prepared in accordance with US GAAP and voluntarily filed on the System for Electronic Document Analysis and Retrieval ("SEDAR") by Fortis on March 16, 2012; (iii) the audited consolidated financial statements and notes thereto for the year ended December 31, 2011, prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"); (iv) the "Supplemental Interim Consolidated Financial Statements for the Year Ended December 31, 2011 (Unaudited)" contained in the above-noted voluntary filing, which provides a detailed reconciliation between the Corporation's interim unaudited consolidated 2011 Canadian GAAP financial statements and interim unaudited consolidated 2011 US GAAP financial statements; and (v) the MD&A for the year ended December 31, 2011 included in the Corporation's 2011 Annual Report.

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 Corporation's consolidated forecast gross capital expenditures for 2012 and in total over the five-year period 2012 through 2016; the nature, timing and amount of certain capital projects and their expected costs and time to complete; the expectation that the Corporation's significant capital expenditure program should support continuing growth in earnings and dividends; forecast midyear rate base; 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 offerings; the expected consolidated long-term debt maturities and repayments on average annually over the next five years; except for debt at the Exploits River Hydro Partnership ("Exploits Partnership"), the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout the remainder of 2012; the expected timing of filing regulatory applications and of receipt of regulatory decisions; the expected timing of the closing of the acquisition of CH Energy Group, Inc. ("CH Energy Group") by Fortis and the expectation that the acquisition will be immediately accretive to earnings per common share, excluding acquisition-related expenses; an expected favourable impact on the Corporation's earnings in future periods upon final enactment of legislative changes to Part VI.1 taxes; the expectation of greater risk under Performance-Based Regulation ("PBR") that FortisAlberta's earnings may be negatively impacted; and the expectation that FortisBC Electric and the City of Kelowna will work towards closing the proposed acquisition of the City of Kelowna's electrical utility assets by FortisBC Electric by the end of the first quarter of 2013.

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 variability in interest rates; 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 events; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; no material capital project and financing cost overrun related to the construction of the Waneta Expansion hydroelectric generating facility; sufficient liquidity and capital resources; the expectation that the Corporation will receive appropriate compensation from the Government of Belize ("GOB") for fair value of the Corporation's investment in Belize Electricity that was expropriated by the GOB; the expectation that Belize Electric Company Limited ("BECOL") will not be expropriated by the GOB; the expectation that the Corporation will receive fair compensation from the Government of Newfoundland and Labrador related to the expropriation of the Exploits Partnership's hydroelectric assets and water rights; 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 foreign exchange rates, natural gas commodity prices and fuel prices; 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, fuel and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the receipt of regulatory approval from the New York State Public Service Commission, absent material conditions imposed, required in connection with the acquisition of CH Energy Group; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; the absence of significant changes in government energy plans and environmental laws that may materially negatively 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; the ability to report under US GAAP beyond 2014 or the adoption of International Financial Reporting Standards ("IFRS") after 2014 that allows for the recognition of regulatory assets and liabilities; the continued tax-deferred treatment of earnings from the Corporation's Caribbean operations; continued maintenance of information technology ("IT") infrastructure; continued 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, including increased risk at FortisAlberta associated with the adoption of PBR under a five-year term commencing in 2013; interest rate risk, including the uncertainty of the impact a continuation of a low interest rate environment may have on allowed rates of return on common shareholders' equity of the Corporation's regulated utilities; operating and maintenance risks; risk associated with changes in economic conditions; capital project budget overrun, completion and financing risk in the Corporation's non-regulated business; capital resources and liquidity risk; risk associated with the amount of compensation to be paid to Fortis for its investment in Belize Electricity that was expropriated by the GOB; the timeliness of the receipt of the compensation and the ability of the GOB to pay the compensation owing to Fortis; risk that the GOB may expropriate BECOL; an ultimate resolution of the expropriation of the hydroelectric assets and water rights of the Exploits Partnership that differs from that which is currently expected by management; weather and seasonality risk; commodity price risk; the continued ability to hedge foreign exchange risk; counterparty risk;

Competitiveness of natural gas; natural gas, fuel and electricity supply risk; risk associated with the continuation, renewal, replacement and/or regulatory approval of power supply and capacity purchase contracts; risks relating to the ability to close the acquisition of CH Energy Group, the timing of such closing and the realization of the anticipated benefits of the acquisition; risk of having to raise alternative capital to finance the acquisition of CH Energy Group if the closing of the acquisition occurs subsequent to June 30, 2013; the risk associated with defined benefit pension plan performance and funding requirements; risks related to FortisBC Energy (Vancouver Island) Inc.; environmental risks; insurance coverage risk; risk of loss of licences and permits; risk of loss of service area; risk of not being able to report under US GAAP beyond 2014 or risk that IFRS does not have an accounting standard for rate-regulated entities by the end of 2014 allowing for the recognition of regulatory assets and liabilities; risks related to changes in tax legislation; risk of failure of IT infrastructure; risk of not being able to access First Nations lands; labour relations risk; human resources risk; and risk of unexpected outcomes of legal proceedings currently against the Corporation. For additional information with respect to the Corporation's risk factors, reference should be made to the Corporation's continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and to the heading "Business Risk Management" in the MD&A for the three and nine months ended September 30, 2012 and for the year ended December 31, 2011.

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 more than 2,000,000 gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and two 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 Upstate New York, and hotels and commercial office and retail space in Canada. Year-to-date September 30, 2012, the Corporation's electricity distribution systems met a combined peak demand of approximately 5,225 megawatts ("MW") and its gas distribution system met a peak day demand of 1,335 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 and nine months ended September 30, 2012 and to the "Corporate Overview" section of the 2011 Annual MD&A.

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/or 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"). The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-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 and/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 was estimated, other than for certain prescribed costs that are eligible to be deferred on the balance sheet. 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 base customer rates and/or the use of rate stabilization and other mechanisms.

SIGNIFICANT ITEMS

Pending Acquisition of CH Energy Group, Inc.: In February 2012 Fortis announced that it had entered into an agreement to acquire CH Energy Group, Inc. ("CH Energy Group") for US$65.00 per common share in cash, for an aggregate purchase price of approximately US$1.5 billion, including the assumption of approximately US$500 million of debt on closing. CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New York. Its main business, Central Hudson Gas & Electric Corporation, is a regulated transmission and distribution ("T&D") utility serving approximately 300,000 electric and 75,000 natural gas customers in eight counties of New York State's Mid-Hudson River Valley. The transaction received CH Energy Group shareholder approval in June 2012 and regulatory approval from the Federal Energy Regulatory Commission and the Committee on Foreign Investment in the United States in July 2012. In addition, the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired in October 2012, satisfying another condition necessary for consummation of the transaction.

The transaction remains subject to approval by the New York State Public Service Commission ("NYSPSC") and satisfaction of customary closing conditions. The application for approval of the transaction by the NYSPSC was jointly filed by Fortis and CH Energy Group in April 2012. The acquisition is expected to close by the end of the first quarter of 2013 and be immediately accretive to earnings per common share, excluding acquisition-related expenses.

During the third quarter and year-to-date 2012, the Corporation's earnings were reduced by $0.5 million and $7.5 million, respectively, associated with CH Energy Group after-tax acquisition-related expenses.

Subscription Receipts Offering: In June 2012, to finance a portion of the pending acquisition of CH Energy Group, Fortis sold 18,500,000 Subscription Receipts at $32.50 each through a bought-deal offering underwritten by a syndicate of underwriters led by CIBC World Markets Inc., Scotia Capital Inc. and TD Securities Inc., realizing gross proceeds of approximately $601 million. The gross proceeds from the sale of the Subscription Receipts are being held by an escrow agent, pending satisfaction of closing conditions, including receipt of regulatory approvals, included in the agreement to acquire CH Energy Group (the "Release Conditions"). The Subscription Receipts began trading on the Toronto Stock Exchange on June 27, 2012 under the symbol "FTS.R".

Each Subscription Receipt will entitle the holder thereof to receive, on satisfaction of the Release Conditions and without payment of additional consideration, one common share of Fortis and a cash payment equal to the dividends declared on Fortis common shares to holders of record during the period from June 27, 2012 to the date of issuance of the common shares in respect of the Subscription Receipts.

If the Release Conditions are not satisfied by June 30, 2013, or if the agreement and plan of merger relating to the acquisition of CH Energy Group is terminated prior to such time, holders of Subscription Receipts shall be entitled to receive from the escrow agent an amount equal to the full subscription price thereof plus their pro rata share of the interest earned on such amount.

For further information on the pending acquisition and the related Subscription Receipts offering, refer to the "Business Risk Management" section of this MD&A.

Receipt of Regulatory Decisions: Year-to-date 2012, regulatory decisions have been received for 2012-2013 revenue requirements at the FortisBC Energy companies, 2012 distribution revenue requirements at FortisAlberta and, recently in August, for 2012-2013 revenue requirements at FortisBC Electric. The Alberta Utilities Commission ("AUC") issued a generic decision in September 2012 on its Performance-Based Regulation ("PBR") Initiative outlining the PBR framework applicable to distribution utilities in Alberta, including FortisAlberta, for a five-year term commencing January 1, 2013. For further information on these regulatory decisions, refer to the "Regulatory Highlights" and "Business Risk Management" sections of this MD&A.

Part VI.1 Tax: Under the terms of the Corporation's first preference shares, the Corporation is subject to tax under Part VI.1 of the Income Tax Act (Canada) associated with dividends on its first preference shares. For corporations subject to Part VI.1 tax, there is an equivalent Part I tax deduction. As permitted under the Income Tax Act (Canada), a corporation may allocate its Part VI.1 tax liability and equivalent Part I tax deduction to its related subsidiaries. In the past, Fortis has allocated these items to Maritime Electric, Newfoundland Power and FortisOntario.

Upon transition to US GAAP, the Corporation reduced its consolidated opening 2012 retained earnings by $20 million to reflect the impact of differences between enacted and substantively enacted tax legislation associated with prior assessments and payments of Part VI.1 taxes, and the recovery of Part I taxes. The adjustment was done as US GAAP requires tax provisions to be based on enacted legislation versus substantively enacted legislation. A number of legislative amendments to Part VI.1 tax in Canada have yet to be enacted. The above-noted transitional US GAAP adjustment will reverse through the Corporation's earnings in future periods when the legislation is finally enacted, which is expected in 2013, or as reassessment of corporate taxation years, upon which the enacted versus the substantively enacted rates were used to calculate taxes payable under US GAAP, become statute barred. The statute-barred reversals will occur between 2012 and 2016 and will increase earnings during these years. During the third quarter of 2012, Newfoundland Power recorded a favourable $2.5 million adjustment to income taxes associated with statute-barred Part VI.1 taxes.

Purchase of the Electricity Distribution Assets in Port Colborne: In April 2012 FortisOntario exercised its option to purchase all of the assets previously leased by the Company under an operating lease agreement with the City of Port Colborne for the purchase option price of approximately $7 million. The exercise of the purchase option, which qualifies as a business combination, provides ownership and legal title to all of the assets, including equipment, real property and distribution assets, which constitute the electricity distribution system in Port Colborne.

Acquisition of Turks and Caicos Utilities Limited: In August 2012 Fortis Turks and Caicos acquired Turks and Caicos Utilities Limited ("TCU") for an aggregate purchase price of approximately $13 million (US$13 million), inclusive of debt assumed of $5 million (US$5 million). TCU is a regulated electric utility operating pursuant to a 50-year licence expiring in 2036. The utility serves more than 2,000 residential and commercial customers on Grand Turk and Salt Cay with a diesel-fired generating capacity of approximately 9 MW.

Hotel Acquisition: In October 2012 Fortis Properties acquired the 126-room StationPark All Suite Hotel ("StationPark Hotel") in London, Ontario for approximately $13 million.

Pending Acquisition of the Electrical Utility Assets from the City of Kelowna: FortisBC Electric has offered to purchase the City of Kelowna's electrical utility assets, which currently serve approximately 15,000 customers, for approximately $55 million. FortisBC Electric provides the City of Kelowna with electricity under a wholesale tariff and has operated and maintained the City of Kelowna's electrical utility assets since 2000. Closing of the transaction is subject to certain conditions and receipt of certain approvals, including regulatory approval. The parties are working towards closing the transaction by the end of the first quarter of 2013.

Expropriation of Shares in Belize Electricity: The Government of Belize ("GOB") expropriated the Corporation's common share ownership in Belize Electricity in June 2011. The Corporation is challenging the legality of the expropriation in the Belize Courts. Although the GOB initiated contact with Fortis, there have been no settlement negotiations to date on the fair value compensation owing to Fortis as a result of the expropriation. For further information, refer to the "Business Risk Management" section of this MD&A.

Transition to US GAAP: Effective January 1, 2012, Fortis retroactively adopted US GAAP with the restatement of comparative reporting periods. For further information, refer to the "New Accounting Standards and Policies" section of this MD&A.

Re-Organization of Non-Regulated Generation Operations: Effective July 1, 2012, the legal ownership of the six small non-regulated hydroelectric generating facilities in eastern Ontario, with a combined generating capacity of 8 MW, was transferred from Fortis Properties to a limited partnership directly held by Fortis. FortisBC Holdings Inc. ("FHI") assumed management responsibility for the operations of the above-noted facilities, as well as for the four non-regulated hydroelectric generating facilities in Upstate New York, with a combined generating capacity of 23 MW, owned by FortisUS Energy Corporation ("FortisUS Energy").

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 requirements, by the nature of the assets. Key financial highlights for the third quarter and year-to-date periods ended September 30, 2012 and September 30, 2011 are provided in the following table.

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Consolidated Financial Highlights (Unaudited)

Periods Ended

September 30 Quarter Year-to-Date

($ millions, except

for common share

data) 2012 2011 Variance 2012 2011 Variance

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Revenue 714 699 15 2,655 2,704 (49)

Energy Supply Costs 235 246 (11) 1,092 1,207 (115)

Operating Expenses 203 200 3 621 619 2

Depreciation and

Amortization 118 104 14 351 309 42

Other Income

(Expenses), Net 1 22 (21) (2) 34 (36)

Finance Charges 93 89 4 276 274 2

Income Taxes 7 12 (5) 44 59 (15)

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Net Earnings 59 70 (11) 269 270 (1)

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Net Earnings

Attributable to:

Non-Controlling

Interests 3 3 - 7 7 -

Preference Equity

Shareholders 11 11 - 34 34 -

Common Equity

Shareholders 45 56 (11) 228 229 (1)

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Net Earnings 59 70 (11) 269 270 (1)

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Basic Earnings per

Common Share ($) 0.24 0.30 (0.06) 1.20 1.28 (0.08)

Diluted Earnings per

Common Share ($) 0.24 0.30 (0.06) 1.19 1.27 (0.08)

Weighted Average

Number of Common

Shares Outstanding

(# millions) 190.2 186.5 3.7 189.6 179.5 10.1

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Cash Flow from

Operating

Activities 221 151 70 804 684 120

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Factors Contributing to Quarterly and Year-to-Date

Revenue Variances


Favourable

-- An increase in gas delivery rates and the base component of electricity

rates at most of the regulated utilities, consistent with rate

decisions, reflecting ongoing investment in energy infrastructure and

forecasted certain higher expenses recoverable from customers

-- Net transmission revenue of approximately $3.5 million recognized for

the quarter and $6.5 million recognized year to date at FortisAlberta,

as a result of the 2012 distribution revenue requirements decision

received in April 2012

-- Higher gas transportation volumes to industrial customers

-- Increased electricity sales at FortisBC Electric, Newfoundland Power,

Maritime Electric and Fortis Turks and Caicos for the quarter and year

to date and at FortisOntario for the quarter

-- The flow through in customer electricity rates of higher energy supply

costs, where applicable, at most of the regulated electric utilities

-- Growth in the number of customers, driven by FortisAlberta

-- Differences in the amount of PBR incentives refunded, and flow-through

adjustments owing, to FortisBC Electric's customers period over period

-- Higher Hospitality revenue at Fortis Properties, driven by revenue from

the Hilton Suites Winnipeg Airport hotel ("Hilton Suites Hotel"), which

was acquired in October 2011

-- Increased non-regulated hydroelectric production in Belize year to date,

due to higher rainfall

-- Approximately $1 million for the quarter and $5 million year to date of

favourable foreign exchange associated with the translation of US

dollar-denominated revenue, due to the strengthening of the US dollar

relative to the Canadian dollar period over period


Unfavourable

-- Lower commodity cost of natural gas charged to customers

-- The expropriation of Belize Electricity and the resulting discontinuance

of the consolidation method of accounting for the utility, effective

June 20, 2011, which reduced revenue year to date

-- The flow through in customer electricity rates of lower energy supply

costs at Caribbean Utilities for the quarter, due to a decrease in the

cost of fuel period over period

-- Lower average gas consumption by residential and commercial customers

year to date

-- Revenue at Newfoundland Power in 2011 reflected the favourable impact of

support structure arrangements with Bell Aliant Inc. ("Bell Aliant")

-- Decreased non-regulated hydroelectric production in Belize for the

quarter, due to lower rainfall

-- Decreased electricity sales at Caribbean Utilities for the quarter and

year to date and at FortisOntario year to date

Factors Contributing to Quarterly and Year-to-Date

Energy Supply Costs Variances


Favourable

-- Lower commodity cost of natural gas

-- The expropriation of Belize Electricity and the resulting discontinuance

of the consolidation method of accounting for the utility, effective

June 20, 2011, which reduced energy supply costs year to date

-- Lower average gas consumption by residential and commercial customers

year to date, which reduced natural gas purchases

-- Decreased fuel prices at Caribbean Utilities for the quarter

-- Decreased electricity sales at Caribbean Utilities for the quarter and

year to date and at FortisOntario year to date, which reduced fuel and

power purchases


Unfavourable

-- Increased fuel prices at Caribbean Utilities year to date and increased

purchased power costs at FortisBC Electric and FortisOntario for the

quarter and year to date

-- An increase in the base amount of energy supply costs expensed at

Maritime Electric in accordance with the operation of the Energy Cost

Adjustment Mechanism

-- Increased electricity sales at FortisBC Electric, Newfoundland Power,

Maritime Electric and Fortis Turks and Caicos for the quarter and year

to date and at FortisOntario for the quarter, which increased fuel and

power purchases

-- Approximately $1 million for the quarter and $3 million year to date

associated with unfavourable foreign currency translation

Factors Contributing to Quarterly and Year-to-Date

Operating Expenses Variances


Unfavourable

-- General inflationary and employee-related cost increases at the

Corporation's regulated utilities, and timing of certain expenses at

FortisBC Electric during 2012

-- Operating expenses associated with the Hilton Suites Hotel, which was

acquired in October 2011


Favourable

-- Reduced operating expenses at the FortisBC Energy companies during 2012,

mainly due to the accrual of non-asset retirement obligation ("non-ARO")

removal costs in depreciation, effective January 1, 2012, the timing of

certain expenditures during 2012 and lower customer care-related costs

as a result of insourcing the customer care function, effective January

1, 2012. Non-ARO removal costs were recorded in operating expenses in

2011.

-- The expropriation of Belize Electricity and the resulting discontinuance

of the consolidation method of accounting for the utility, effective

June 20, 2011, which decreased operating expenses year to date

Factors Contributing to Quarterly and Year-to-Date

Depreciation and Amortization Expense Variances


Unfavourable

-- Continued investment in energy infrastructure

-- Increased depreciation at the FortisBC Energy companies, mainly due to

the accrual of non-ARO removal costs in depreciation, effective January

1, 2012, as discussed above


Favourable

-- The expropriation of Belize Electricity and the resulting discontinuance

of the consolidation method of accounting for the utility, effective

June 20, 2011, which decreased depreciation year to date

-- Lower depreciation rates at FortisAlberta and FortisBC Electric,

effective January 1, 2012, as a result of the 2012 revenue requirements

decisions received in April 2012 and August 2012, respectively

Factors Contributing to Quarterly and Year-to-Date

Other Income (Expenses), Net Variances


Unfavourable

-- The favourable impact in 2011 of the $17 million (US$17.5 million) ($11

million after tax) fee paid to Fortis in July 2011 following the

termination of a Merger Agreement between Fortis and Central Vermont

Public Service Corporation ("CVPS")

-- Approximately $0.5 million ($0.5 million after tax) and $8.5 million

($7.5 million after tax) of costs incurred in the third quarter and

year-to-date 2012, respectively, related to the pending acquisition of

CH Energy Group

-- Foreign exchange losses of approximately $3 million and $2.5 million for

the third quarter and year-to-date 2012, respectively, associated with

the translation of the US dollar-denominated long-term other asset

representing the book value of the Corporation's expropriated investment

in Belize Electricity. A net foreign exchange gain of approximately $1.5

million ($2.5 million after tax) was recognized for the third quarter

and year-to-date 2011 related to the above item.

-- Lower capitalized equity component of allowance for funds used during

construction ("AFUDC"), mainly at the FortisBC Energy companies

-- An approximate $1 million gain on the sale of property at FortisAlberta

during the first quarter of 2011

Factors Contributing to Quarterly and Year-to-Date

Finance Charges Variances


Unfavourable

-- Higher long-term debt levels in support of the utilities' capital

expenditure programs

-- Lower capitalized debt component of AFUDC at the regulated utilities,

mainly at the FortisBC Energy companies


Favourable

-- Higher capitalized interest associated with the financing of the

construction of the Corporation's 51% controlling ownership interest in

the Waneta Expansion hydroelectric generating facility ("Waneta

Expansion")

-- The expropriation of Belize Electricity and the resulting discontinuance

of the consolidation method of accounting for the utility, effective

June 20, 2011, which decreased finance charges year to date

-- Lower short-term borrowings at the regulated utilities year to date,

driven by the FortisBC Energy companies

Factors Contributing to Quarterly and Year-to-Date

Income Taxes Variances


Favourable

-- Lower statutory corporate income tax rates and lower earnings before

income taxes

-- Differences in the deductions for income tax purposes compared to

accounting purposes period over period

Factors Contributing to Quarterly Earnings Variance


Unfavourable

-- Higher corporate expenses, due to the favourable impact in 2011 of the

$11 million after-tax fee paid to Fortis in July 2011 following the

termination of a Merger Agreement between Fortis and CVPS, and a foreign

exchange loss of approximately $3 million after tax recognized in the

third quarter of 2012 compared to a net foreign exchange gain of

approximately $2.5 million after tax recognized in the third quarter of

2011

-- Decreased non-regulated hydroelectric production in Belize, due to lower

rainfall

-- A higher loss at the FortisBC Energy companies, largely related to the

unfavourable impact of the difference in the timing of the recognition

of revenue associated with seasonal gas consumption and certain

increased regulator-approved expenses in 2012, lower capitalized AFUDC

and lower-than-expected customer additions in 2012. The above items were

partially offset by higher gas transportation volumes to industrial

customers and the timing of certain operating and maintenance expenses

during 2012.


Favourable

-- Increased earnings at FortisAlberta, mainly due to higher net

transmission revenue, rate base growth and the timing of operating

expenses during 2012, partially offset by a lower allowed ROE

-- Increased earnings at FortisBC Electric, due to rate base growth, higher

pole-attachment revenue and lower-than-expected finance charges in 2012

-- Increased earnings at Newfoundland Power, mainly due to lower effective

income taxes and a higher allowed ROE, partially offset by the impact of

the support structure arrangements with Bell Aliant during 2011

Factors Contributing to Year-to-Date Earnings Variance


Unfavourable

-- Higher corporate expenses due to: (i) the favourable impact in 2011 of

the $11 million after-tax fee paid to Fortis in July 2011 following the

termination of a Merger Agreement between Fortis and CVPS; (ii)

approximately $7.5 million, after tax, of costs incurred year-to-date

2012 related to the pending acquisition of CH Energy Group; and (iii) a

foreign exchange loss of approximately $2.5 million after tax recognized

year-to-date 2012 compared to a net foreign exchange gain of

approximately $2.5 million after tax recognized year-to-date 2011. The

increase in corporate expenses was partially offset by lower finance

charges, primarily due to higher capitalized interest associated with

financing of the construction of the Corporation's 51% controlling

ownership interest in the Waneta Expansion.


Favourable

-- Increased earnings at FortisAlberta, due to rate base growth, higher net

transmission revenue, the timing of operating expenses during 2012,

lower effective income taxes and lower-than-expected finance charges,

partially offset by a lower allowed ROE and an approximate $1 million

gain on the sale of property during the first quarter of 2011

-- Increased earnings at Newfoundland Power, for the same reasons discussed

above for the quarter, in addition to increased electricity sales year

to date

-- Increased earnings at the FortisBC Energy companies, mainly due to rate

base growth, higher gas transportation volumes to industrial customers

and timing of certain operating and maintenance expenses during 2012,

partially offset by lower-than-expected customer additions in 2012,

lower capitalized AFUDC and the unfavourable impact of the difference in

the timing of recognition of revenue associated with seasonal gas

consumption and certain increased regulator-approved expenses in 2012

-- Increased non-regulated hydroelectric production in Belize, due to

higher rainfall


SEGMENTED RESULTS OF OPERATIONS

----------------------------------------------------------------------------

Segmented Net Earnings Attributable to Common Equity Shareholders

(Unaudited)

Periods Ended September 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Regulated Gas Utilities -

Canadian

FortisBC Energy

Companies (6) (4) (2) 89 86 3

----------------------------------------------------------------------------

Regulated Electric

Utilities -

Canadian

FortisAlberta 26 19 7 73 58 15

FortisBC Electric 13 10 3 38 38 -

Newfoundland Power 9 8 1 28 24 4

Other Canadian Electric

Utilities 6 6 - 18 18 -

----------------------------------------------------------------------------

54 43 11 157 138 19

----------------------------------------------------------------------------

Regulated Electric

Utilities - Caribbean 7 6 1 16 16 -

Non-Regulated - Fortis

Generation 5 8 (3) 15 13 2

Non-Regulated - Fortis

Properties 8 9 (1) 17 18 (1)

Corporate and Other (23) (6) (17) (66) (42) (24)

----------------------------------------------------------------------------

Net Earnings Attributable

to Common Equity

Shareholders 45 56 (11) 228 229 (1)

----------------------------------------------------------------------------

----------------------------------------------------------------------------


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)

----------------------------------------------------------------------------

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended September

30 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Gas Volumes (petajoules

("PJ")) 26 23 3 138 140 (2)

Revenue ($ millions) 192 197 (5) 1,004 1,090 (86)

(Loss) Earnings ($

millions) (6) (4) (2) 89 86 3

----------------------------------------------------------------------------

----------------------------------------------------------------------------

(1) Includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver

Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI")

Factors Contributing to Quarterly Gas Volumes Variance


Favourable

-- Higher gas transportation volumes to industrial customers, due to

certain customers switching to natural gas from alternative sources of

fuel as a result of lower natural gas prices

Factors Contributing to Year-to-Date Gas Volumes Variance


Unfavourable

-- Lower average gas consumption by residential and commercial customers,

driven by overall warmer temperatures


Favourable

-- Higher gas transportation volumes to industrial customers, for the same

reason discussed above for the quarter


With the implementation of the new Customer Care Enhancement Project on January 1, 2012, the FortisBC Energy companies changed their definition of a customer. As a result of this change, the FortisBC Energy companies adjusted their combined customer count downwards by approximately 18,000, effective January 1, 2012. As at September 30, 2012, the total number of customers served by the FortisBC Energy companies was approximately 938,000.

The FortisBC Energy companies earn approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulator-approved deferral mechanisms, changes in consumption levels and the commodity cost of natural gas from those forecast to set residential and commercial customer gas rates do not materially affect earnings.

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.

Factors Contributing to Quarterly Revenue Variance


Unfavourable

-- Lower commodity cost of natural gas charged to customers

-- Lower-than-expected customer additions in 2012


Favourable

-- A net increase in the delivery component of customer rates, effective

January 1, 2012, mainly due to ongoing investment in energy

infrastructure and forecasted certain higher expenses recoverable from

customers as reflected in the 2012-2013 revenue requirements decision

received in April 2012

-- Higher gas transportation volumes to industrial customers

Factors Contributing to Year-to-Date Revenue Variance


Unfavourable

-- The same factors discussed above for the quarter

-- Lower average gas consumption by residential and commercial customers


Favourable

-- The same factors discussed above for the quarter

Factors Contributing to Quarterly Earnings Variance


Unfavourable

-- The difference in the timing of recognition of revenue and certain

expenses in 2012. Revenue is recognized based on seasonal gas

consumption while certain expenses are generally incurred evenly

throughout the year, which, combined with an approved increase in those

expenses in 2012, has resulted in timing differences contributing to

lower earnings quarter over quarter

-- Lower capitalized AFUDC, due to lower assets under construction period

over period

-- Lower-than-expected customer additions in 2012


Favourable

-- Higher gas transportation volumes to industrial customers

-- The timing of certain operating and maintenance expenses during 2012

Factors Contributing to Year-to-Date Earnings Variance


Favourable

-- Rate base growth, due to continued investment in energy infrastructure

-- The same factors discussed above for the quarter


Unfavourable

-- Lower-than-expected customer additions in 2012

-- Lower capitalized AFUDC, for the same reason discussed above for the

quarter

-- The difference in the timing of recognition of revenue and certain

expenses in 2012, for the reasons discussed above for the quarter, which

reduced earnings year to date compared to the same period last year


REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

----------------------------------------------------------------------------

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended

September 30 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Energy Deliveries

(gigawatt hours

("GWh")) 4,099 3,911 188 12,434 12,135 299

Revenue ($ millions) 117 103 14 335 306 29

Earnings ($ millions) 26 19 7 73 58 15

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Factors Contributing to Quarterly Energy Deliveries Variance


Favourable

-- Higher average consumption by oilfield and commercial customers, due to

increased activity mainly as a result of higher market prices for oil

-- Higher average consumption by residential customers, due to warmer

temperatures which increased air conditioning load

-- Growth in the number of customers, with the total number of customers

increasing by approximately 9,000 year over year as at September 30,

2012, driven by favourable economic conditions

-- Higher average consumption by farm and irrigation customers, due to

warmer temperatures and lower precipitation levels

Factors Contributing to Year-to-Date Energy Deliveries Variance


Favourable

-- Higher average consumption by oilfield and commercial customers, for the

same reason discussed above for the quarter

-- Growth in the number of customers, for the same reason discussed above

for the quarter


As a significant portion of FortisAlberta's distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.

Factors Contributing to Quarterly Revenue Variance


Favourable

-- An increase in customer electricity distribution rates, effective

January 1, 2012, driven primarily by ongoing investment in energy

infrastructure and forecasted certain higher expenses recoverable from

customers

-- Net transmission revenue of approximately $3.5 million recognized for

the quarter and $6.5 million recognized year to date. In its April 2012

distribution revenue requirements decision, the regulator did not

approve the continuation of the deferral of transmission volume

variances associated with FortisAlberta's Alberta Electric System

Operator ("AESO") charges deferral account. In the absence of full

deferral, FortisAlberta is subject to volume risk on actual transmission

costs relative to those charged to customers based on forecast volumes

and price. Net transmission revenue is influenced by many factors, which

may result in actual transmission volumes varying from those forecasted.

-- Growth in the number of customers

-- An increase in franchise fee revenue of approximately $1 million for the

quarter and $3 million year to date


Unfavourable

-- A lower allowed ROE. The cumulative impact on revenue, from January 1,

2011, of the decrease in the allowed ROE to 8.75%, effective for both

2011 and 2012, from 9.00% for 2010 was recognized during the fourth

quarter of 2011, when the regulatory decision was received.

Factors Contributing to Year-to-Date Revenue Variance


Favourable

-- The same factors discussed above for the quarter


Unfavourable

-- The recognition in the second quarter of 2011 of accrued revenue related

to the cumulative 2010 and year-to-date 2011 allowed debt return and

recovery of depreciation on the additional $22 million in capital

expenditures approved by the regulator to be included in rate base

associated with the Automated Metering Project, which had the impact of

reducing revenue by approximately $2 million period over period.

-- The same factor discussed above for the quarter

Factors Contributing to Quarterly Earnings Variance


Favourable

-- Net transmission revenue of approximately $3.5 million recognized for

the quarter and $6.5 million recognized year to date, as a result of the

distribution revenue requirements decision received in April 2012

-- Rate base growth, due to continued investment in energy infrastructure

-- The timing of operating expenses during 2012


Unfavourable

-- A lower allowed ROE, as discussed above

Factors Contributing to Year-to-Date Earnings Variance


Favourable

-- The same factors discussed above for the quarter

-- Lower effective income taxes, primarily due to additional loss

carryforwards being utilized in FortisAlberta's 2011 income tax return

filed in 2012, which decreased income tax expense in 2012, and higher

income taxes in 2011 related to the sale of property

-- Lower-than-expected finance charges in 2012


Unfavourable

-- The same factor discussed above for the quarter

-- An approximate $1 million gain on the sale of property during the first

quarter of 2011


FORTISBC ELECTRIC (1)

----------------------------------------------------------------------------

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended

September 30 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Electricity Sales

(GWh) 728 713 15 2,313 2,300 13

Revenue ($ millions) 71 67 4 225 215 10

Earnings ($ millions) 13 10 3 38 38 -

----------------------------------------------------------------------------

----------------------------------------------------------------------------

(1) 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 electrical

utility assets 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 Quarterly and Year-to-Date

Electricity Sales Variances


Favourable

-- Growth in the number of customers

-- Higher average consumption, due to differences in weather conditions

period over period

Factors Contributing to Quarterly and Year-to-Date

Revenue Variances


Favourable

-- A net increase in customer electricity rates, effective January 1, 2012,

mainly due to ongoing investment in energy infrastructure and forecasted

certain higher expenses recoverable from customers as reflected in the

2012-2013 revenue requirements decision received in August 2012

-- A 1.4% increase in customer electricity rates, effective June 1, 2011,

as a result of the flow through to customers of increased purchased

power costs charged to FortisBC Electric by BC Hydro, which increased

revenue year to date

-- Higher pole-attachment revenue

-- Differences in the amount of PBR incentives refunded, and flow-through

adjustments owing, to customers period over period

-- The 2.1% and 0.6% increase in electricity sales for the quarter and year

to date, respectively

Factors Contributing to Quarterly Earnings Variance


Favourable

-- Rate base growth, due to continued investment in energy infrastructure

-- Higher pole-attachment revenue

-- Lower-than-expected finance charges in 2012. As approved in the 2012-

2013 revenue requirements decision received in August 2012, variances

between actual finance charges and those forecasted in determining

customer electricity rates, beginning January 1, 2012, are no longer

permitted deferral account treatment and, therefore, favourably impacted

earnings in 2012

Factors Contributing to Year-to-Date Earnings Variance


Favourable

-- The same factors discussed above for the quarter


Unfavourable

-- The expiry of the PBR mechanism on December 31, 2011. Year-to-date 2011,

lower-than-expected costs, primarily purchased power costs, were shared

equally between customers and FortisBC Electric under the PBR mechanism.

Pursuant to the Company's 2012-2013 revenue requirements decision

received in August 2012, variances between actual electricity revenue

and purchased power costs and those used in determining customer

electricity rates are subject to full deferral account treatment and,

therefore, did not impact earnings year-to-date 2012.


NEWFOUNDLAND POWER

----------------------------------------------------------------------------

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended

September 30 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Electricity Sales

(GWh) 940 923 17 4,113 4,026 87

Revenue ($ millions) 100 101 (1) 422 417 5

Earnings ($ millions) 9 8 1 28 24 4

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Factors Contributing to Quarterly and Year-to-Date

Electricity Sales Variances


Favourable

-- Growth in the number of customers

-- Higher concentration of electric-versus-oil heating in new home

construction combined with economic growth, which increased consumption


Unfavourable

-- Sunnier weather conditions, which reduced average consumption

Factors Contributing to Quarterly Revenue Variance


Unfavourable

-- Revenue for 2011 included amounts related to support structure

arrangements, which were in place with Bell Aliant during 2011,

associated with the joint-use poles held for sale to Bell Aliant. The

joint-use poles were sold in October 2011.


Favourable

-- The 1.8% increase in electricity sales

Factors Contributing to Year-to-Date Revenue Variance


Favourable

-- The 2.2% increase in electricity sales


Unfavourable

-- The impact of the support structure arrangements with Bell Aliant during

2011, as discussed above for the quarter

Factors Contributing to Quarterly and Year-to-Date

Earnings Variances


Favourable

-- Lower effective income taxes, primarily due to lower Part VI.1 taxes,

including the favourable impact of reversals of statute-barred Part VI.1

taxes period over period, and a lower statutory income tax rate. For

further information on Part VI.1 tax, refer to the "Significant Items"

section of this MD&A.

-- A higher allowed ROE, effective January 1, 2012, which is being accrued

in 2012, as approved by the regulator, as a decrease in operating

expenses for deferred recovery from customers

-- Electricity sales growth year to date


Unfavourable

-- The impact of the support structure arrangements with Bell Aliant during

2011, as discussed above

-- Approximately $1 million in additional operating labour and maintenance

costs incurred as a result of Tropical Storm Leslie in September 2012

-- Higher depreciation expense, due to continued investment in energy

infrastructure


OTHER CANADIAN ELECTRIC UTILITIES (1)

----------------------------------------------------------------------------

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended

September 30 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Electricity Sales

(GWh) 595 582 13 1,803 1,798 5

Revenue ($ millions) 91 87 4 264 256 8

Earnings ($ millions) 6 6 - 18 18 -

----------------------------------------------------------------------------

----------------------------------------------------------------------------

(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly

includes Canadian Niagara Power, Cornwall Electric and Algoma Power.

Factors Contributing to Quarterly Electricity Sales Variance


Favourable

-- Higher average consumption by commercial customers in the agricultural

processing sector on Prince Edward Island ("PEI")

-- Higher average consumption by residential customers and several large

commercial customers in Ontario

Factors Contributing to Year-to-Date Electricity Sales Variance


Favourable

-- Higher average consumption by commercial customers in the agricultural

processing sector on PEI

-- Growth in the number of, and higher average consumption by, residential

customers on PEI and an increase in the number of such customers using

electricity for home heating


Unfavourable

-- Lower average consumption by residential and industrial customers in

Ontario, primarily during the first quarter of 2012, reflecting more

moderate temperatures and weak economic conditions in the region

Factors Contributing to Quarterly and Year-to-Date

Revenue Variances


Favourable

-- The overall 2.2% and 0.3% increase in electricity sales for the quarter

and year to date, respectively, for the reasons discussed above

-- An increase in the basic component of customer rates at Maritime

Electric, effective March 1, 2012, associated with the higher flow

through and recovery of energy supply costs

-- The flow through in customer electricity rates of higher energy supply

costs at FortisOntario

-- Increased customer rates at FortisOntario

Factors Contributing to Quarterly and Year-to-Date

Earnings Variances


Favourable

-- Lower operating expenses at FortisOntario for the quarter, largely due

to the timing of certain operating expenses during 2012

-- Electricity sales growth

-- Increased customer rates at FortisOntario


Unfavourable

-- Increased depreciation expense and finance charges at Maritime Electric,

due to continued investment in energy infrastructure and increased

short-term borrowings, respectively

-- Higher operating expenses at FortisOntario year to date, largely due to

an increase in employee-related costs and the timing of certain

operating expenses during 2012


REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)

----------------------------------------------------------------------------

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended

September 30 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Average US:CDN

Exchange Rate (2) 1.00 0.98 0.02 1.00 0.98 0.02

----------------------------------------------------------------------------

Electricity Sales

(GWh) 197 197 - 547 744 (197)

Revenue ($ millions) 72 74 (2) 202 234 (32)

Earnings ($

millions) 7 6 1 16 16 -

----------------------------------------------------------------------------

----------------------------------------------------------------------------

(1) Includes Caribbean Utilities on Grand Cayman, Cayman Islands, in which

Fortis holds an approximate 60% controlling interest; three small

wholly owned utilities in the Turks and Caicos Islands, which include

Turks and Caicos Utilities Ltd., acquired in August 2012, FortisTCI

Limited and Atlantic Equipment & Power (Turks and Caicos) Ltd.    

(collectively "Fortis Turks and Caicos"); and the financial results of

the Corporation's approximate 70% controlling interest in Belize

Electricity up to June 20, 2011. Effective June 20, 2011, the

Government of Belize expropriated the Corporation's investment in

Belize Electricity. As a result of no longer controlling the

operations of the utility, Fortis discontinued the consolidation

method of accounting for Belize Electricity, effective June 20, 2011.

For further information, refer to the "Significant Items" and

"Business Risk Management" sections of this MD&A.    

(2) The reporting currency of Caribbean Utilities and Fortis Turks and

Caicos is the US dollar. The reporting currency of Belize Electricity

was the Belizean dollar, which is pegged to the US dollar at

BZ$2.00=US$1.00.    

Factors Contributing to Quarterly Electricity Sales Variance


Favourable

-- Growth in the number of customers

-- Warmer temperatures experienced in the Turks and Caicos Islands, which

increased air conditioning load

-- Higher tourism activity in the Turks and Caicos Islands

-- Electricity sales in the Turks and Caicos Islands during the third

quarter of 2011 were reduced, due to the early and extended closure of a

certain hotel and other commercial customers resulting from a hurricane


Unfavourable

-- Higher rainfall experienced on Grand Cayman, which decreased air

conditioning load

Factors Contributing to Year-to-Date Electricity Sales Variance


Unfavourable

-- The expropriation of Belize Electricity and the resulting discontinuance

of the consolidation method of accounting for the utility, effective

June 20, 2011. Excluding Belize Electricity, electricity sales decreased

approximately 0.5% year to date.

-- The same factor discussed above for the quarter


Favourable

-- The same factors discussed above for the quarter

Factors Contributing to Quarterly Revenue Variance


Unfavourable

-- The flow through in customer electricity rates of lower energy supply

costs at Caribbean Utilities, due to a decrease in the cost of fuel

period over period

-- Decreased electricity sales at Caribbean Utilities

-- The discontinuance of government subsidization of Fortis Turks and

Caicos' South Caicos operations, effective April 1, 2012, in accordance

with a rate decision received in February 2012


Favourable

-- Increased electricity sales at Fortis Turks and Caicos

-- An increase in electricity rates for Fortis Turks and Caicos' large

hotel customers, effective April 1, 2012, in accordance with a rate

decision received in February 2012

-- Approximately $1 million for the quarter and $5 million year to date of

favourable foreign exchange associated with the translation of US

dollar-denominated revenue, due to the strengthening of the US dollar

relative to the Canadian dollar period over period

-- An increase in base electricity rates at Caribbean Utilities, effective

June 1, 2012

Factors Contributing to Year-to-Date Revenue Variance


Unfavourable

-- The expropriation of Belize Electricity and the resulting discontinuance

of the consolidation method of accounting for Belize Electricity,

effective June 20, 2011, which decreased revenue by approximately $45

million period over period

-- Decreased electricity sales at Caribbean Utilities

-- The discontinuance of government subsidization of Fortis Turks and

Caicos' South Caicos operations, as discussed above for the quarter


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

period over period

-- The same factors discussed above for the quarter

Factors Contributing to Quarterly Earnings Variance


Favourable

-- Lower finance charges at Caribbean Utilities

-- Increased electricity sales at Fortis Turks and Caicos


Unfavourable

-- Overall higher depreciation expense, and higher finance charges at

Fortis Turks and Caicos, largely due to investment in utility capital

assets

-- Decreased electricity sales at Caribbean Utilities

Factors Contributing to Year-to-Date Earnings Variance


Favourable

-- Lower energy supply costs at Fortis Turks and Caicos, mainly due to more

fuel-efficient production realized with the commissioning of new

generation units at the utility

-- Lower operating expenses at Caribbean Utilities, driven by the timing of

capital projects

-- Increased electricity sales at Fortis Turks and Caicos


Unfavourable

-- Overall higher depreciation expense and finance charges, for the same

reason discussed above for the quarter

-- Increased operating expenses at Fortis Turks and Caicos, mainly

associated with the timing of capital projects


Fortis Turks and Caicos acquired TCU in August 2012 for an aggregate purchase price of approximately $13 million (US$13 million), inclusive of debt assumed of $5 million (US$5 million). For further information refer to the "Significant Items" section of this MD&A.

NON-REGULATED - FORTIS GENERATION (1)

----------------------------------------------------------------------------

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended

September 30 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Energy Sales (GWh) 81 111 (30) 256 277 (21)

Revenue ($ millions) 8 11 (3) 26 25 1

Earnings ($

millions) 5 8 (3) 15 13 2

----------------------------------------------------------------------------

----------------------------------------------------------------------------

(1) Includes the financial results of non-regulated generation assets in

Belize, Ontario, central Newfoundland, British Columbia and Upstate

New York, with a combined generating capacity of 139 MW, mainly

hydroelectric

Factor Contributing to Quarterly Energy Sales Variance


Unfavourable

-- Decreased production in Belize and Upstate New York, due to lower

rainfall

Factors Contributing to Year-to-Date Energy Sales Variance


Unfavourable

-- Decreased production in Upstate New York, due to a generating facility

being out of service and lower rainfall

-- Decreased production in Ontario, due to lower rainfall


Favourable

-- Increased production in Belize, driven by higher rainfall during the

first half of 2012

Factor Contributing to Quarterly Revenue and Earnings Variances


Unfavourable

-- Decreased production in Belize

Factors Contributing to Year-to-Date Revenue and Earnings Variances


Favourable

-- Increased production in Belize


Unfavourable

-- Decreased production in Upstate New York


In May 2011 the generator at Moose River's hydroelectric generating facility in Upstate New York sustained electrical damage. Repairs to the generator were completed in the second quarter of 2012 but another repair continues to keep the generating facility offline. Revenue for the first half of 2012 reflected insurance amounts received related to the loss of earnings during the period in the first half of 2012 when the generator was being repaired due to the electrical damage. The generating facility is expected to be online by the end of 2012.

NON-REGULATED - FORTIS PROPERTIES (1)

----------------------------------------------------------------------------

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended

September 30 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Hospitality -

Revenue per

Available Room

("RevPAR") ($) 94.04 94.83 (0.79) 82.09 80.54 1.55

Real Estate -

Occupancy Rate (as

at, %) (2) 91.8 94.2 (2.4) 91.8 94.2 (2.4)

----------------------------------------------------------------------------

Hospitality Revenue

($ millions) 48 47 1 130 123 7

Real Estate Revenue

($ millions) 17 16 1 51 50 1

----------------------------------------------------------------------------

Total Revenue ($

millions) 65 63 2 181 173 8

----------------------------------------------------------------------------

Earnings ($

millions) 8 9 (1) 17 18 (1)

----------------------------------------------------------------------------

----------------------------------------------------------------------------

(1) Fortis Properties owns and operates 23 hotels, collectively

representing more than 4,400 rooms, in eight Canadian provinces,

including the acquisition of the StationPark Hotel in London, Ontario,

which was acquired in October 2012 for approximately $13 million.    

Fortis Properties also owns and operates approximately 2.7 million

square feet of commercial office and retail space primarily in

Atlantic Canada.    

(2) Reduced occupancy rate is primarily due to increased vacancy in New

Brunswick.    

Factors Contributing to Quarterly Revenue Variance


Favourable

-- Increased Hospitality Division revenue, driven by contribution from the

Hilton Suites Hotel, which was acquired in October 2011


Unfavourable

-- A 0.8% decrease in RevPar at the Hospitality Division. Excluding the

impact of the Hilton Suites Hotel, RevPAR was $93.20 for the third

quarter of 2012, a decrease of 1.7% quarter over quarter. The decrease

in RevPAR was due to an overall 2.0% decrease in hotel occupancy,

partially offset by an overall 0.3% increase in the average daily room

rate. Hotel occupancy in Atlantic Canada and central Canada decreased,

while occupancy in western Canada increased. The average daily room rate

increased in western Canada and central Canada, and decreased in

Atlantic Canada.

Factors Contributing to Year-to-Date Revenue Variance


Favourable

-- A 1.9% increase in RevPAR at the Hospitality Division, driven by

contribution from the Hilton Suites Hotel

-- Excluding the impact of the Hilton Suites Hotel, RevPAR was $80.80 year-

to-date 2012, an increase of 0.3% period over period. The increase in

RevPAR was due to an overall 1.7% increase in the average daily room

rate, partially offset by an overall 1.4% decrease in hotel occupancy.

The average daily room rate increased in all regions. Hotel occupancy in

Atlantic Canada and central Canada decreased, while occupancy in western

Canada increased.

Factors Contributing to Quarterly and Year-to-Date

Earnings Variances


Unfavourable

-- Lower performance at the Hospitality Division, excluding the Hilton

Suites Hotel, primarily due to the impact of decreased occupancy at

hotel operations in Atlantic Canada and central Canada, and increased

depreciation due to capital additions and improvements

-- A $0.5 million gain on the sale of the Viking Mall during the first

quarter of 2011


Favourable

-- Contribution from the Hilton Suites Hotel


CORPORATE AND OTHER (1)

----------------------------------------------------------------------------

Financial Highlights (Unaudited)

Periods Ended

September 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

----------------------------------------------------------------------------

----------------------------------------------------------------------------

Revenue 5 4 1 18 17 1

Operating Expenses 2 4 (2) 8 9 (1)

Depreciation and

Amortization - - - 1 1 -

Other Income

(Expenses), Net (3) 20 (23) (11) 20 (31)

Finance Charges 13 12 1 36 38 (2)

Income Tax

(Recovery) Expense (1) 3 (4) (6) (3) (3)

----------------------------------------------------------------------------

(12) 5 (17) (32) (8) (24)

Preference Share

Dividends 11 11 - 34 34 -

----------------------------------------------------------------------------

Net Corporate and

Other Expenses (23) (6) (17) (66) (42) (24)

----------------------------------------------------------------------------

----------------------------------------------------------------------------

(1) Includes Fortis net corporate expenses, net expenses of non-regulated

FortisBC Holdings Inc. ("FHI") corporate-related activities and the

financial results of FHI's wholly owned subsidiary FortisBC

Alternative Energy Services Inc. and FHI's 30% ownership interest in

CustomerWorks Limited Partnership ("CWLP"). The contracts between CWLP

and the FortisBC Energy companies ended on December 31, 2011.    

Factors Contributing to Quarterly

Net Corporate and Other Expenses Variance


Unfavourable

-- Increased other expenses, net of other income, primarily due to: (i) the

favourable impact in 2011 of the $17 million (US$17.5 million) ($11

million after tax) fee paid to Fortis in July 2011 following the

termination of a Merger Agreement between Fortis and CVPS; (ii)

approximately $0.5 million ($0.5 million after tax) and $8.5 million

($7.5 million after tax) of costs incurred during the third quarter and

year-to-date 2012, respectively, related to the pending acquisition of

CH Energy Group; and (iii) foreign exchange losses of approximately $3

million and $2.5 million for the third quarter and year-to-date 2012,

respectively, associated with the translation of the US dollar-

denominated long-term other asset representing the book value of the

Corporation's expropriated investment in Belize Electricity. During the

third quarter of 2011, a foreign exchange gain of $7 million associated

with the translation of the above-noted US dollar-denominated long-term

other asset was partially offset by a $5.5 million ($4.5 million after

tax) foreign exchange loss associated with the translation of previously

hedged US dollar-denominated long-term debt. The favourable net impact

to earnings during the third quarter of 2011 of the above-noted foreign

exchange impacts was approximately $2.5 million.

-- Excluding income tax expense associated with the merger termination fee

paid to Fortis in July 2011, income tax recovery decreased, primarily

due to higher Part VI.1 taxes

Factors Contributing to Year-to-Date

Net Corporate and Other Expenses Variance


Unfavourable

-- The same factors discussed above for the quarter


Favourable

-- Lower finance charges, primarily due to higher capitalized interest

associated with the financing of the construction of the Corporation's

51% controlling ownership interest in the Waneta Expansion and the

impact of the conversion of the Corporation's US$40 million convertible

debentures into common shares in November 2011. The above decreases were

partially offset by higher interest on credit facility borrowings in

2012, due to higher average credit facility borrowings and higher fees

associated with the increase in the Corporation's committed revolving

credit facility to $1 billion in May 2012. During the third quarter of

2011, credit facility borrowings were repaid with a portion of the

proceeds from the common share offering in June and July 2011.


REGULATORY HIGHLIGHTS

The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated gas and electric utilities year-to-date 2012 are summarized as follows.

NATURE OF REGULATION

--------------------------------------------------------------------------

Allowed

Common

Regulated Regulatory Equity Supportive

Utility Authority (%) Allowed Returns (%) Features

-------------

Future or

Historical

Test Year

Used to Set

Customer

2010 2011 2012 Rates

--------------------------------------------------------------------------

ROE COS/ROE

-------------------------

FEI British 40 9.50 9.50 9.50 FEI: Prior to

Columbia January 1,

Utilities 2010, 50/50

Commission sharing of

("BCUC") earnings

above or

below

the allowed

ROE under a

PBR

mechanism

that expired

on

December 31,

2009 with a

two-year

phase-out

FEVI BCUC 40 10.00 10.00 10.00

FEWI BCUC 40 10.00 10.00 10.00 ROEs

established

by the BCUC

-------------

Future Test

Year

--------------------------------------------------------------------------

FortisBC BCUC 40 9.90 9.90 9.90 COS/ROE

Electric

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

-------------

Future Test

Year

--------------------------------------------------------------------------

FortisAlberta AUC 41 9.00 8.75 8.75 COS/ROE

ROE

established

by the AUC

-------------

Future Test

Year

--------------------------------------------------------------------------

Newfoundland Newfoundland 45 9.00 +/-8.38 +/-8.80 +/- COS/ROE

Power and 50 bps 50 bps 50 bps

Labrador

Board of

Commissioners

of

Public

Utilities

("PUB")

The allowed

ROE had been

set using

an automatic

adjustment

formula tied

to long-term

Canada bond

yields. The

formula was

suspended for

2012.    

Future Test

Year

--------------------------------------------------------------------------

Maritime Island 40 9.75 9.75 9.75 COS/ROE

Electric Regulatory

and Appeals

Commission

("IRAC")

-------------

Future Test

Year

--------------------------------------------------------------------------

FortisOntario Ontario Canadian

Energy Niagara Power

Board ("OEB") - COS/ROE

Canadian 40 8.01 8.01 8.01 (1) Algoma Power

Niagara - COS/ROE and

Power

subject to

Rural and

Remote Rate

Algoma Power 40 8.57 9.85 9.85 (1) Protection

("RRRP")

Program

Franchise Cornwall

Agreement Electric -

Cornwall Price cap

Electric with

commodity

cost flow

through

-------------

Canadian

Niagara Power

- 2009

historical

test year for

2010, 2011

and 2012

Algoma Power

- 2007

historical

test

year for

2010; 2011

test year for

2011

and 2012

--------------------------------------------------------------------------

ROA COS/ROA

-------------------------

Caribbean Electricity N/A 7.75 - 7.75 - 7.25 -

Utilities Regulatory 9.75 9.75 9.25 Rate-cap

Authority adjustment

("ERA") mechanism

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 Utilities N/A 17.50 17.50 17.50 COS/ROA

and Caicos make annual (2) (2) (2)

filings to

the Interim

Government of

the Turks and

Caicos Caicos

Islands

("Interim

Government")

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) Based on the ROE automatic adjustment formula, the allowed ROE for

electric utilities in Ontario is 9.12% for utilities with rates

effective May 1, 2012. This ROE is not applicable to regulated

electric utilities in Ontario until they are scheduled to file their

next full COS rate applications. As a result, the allowed ROE of 9.12%

is not applicable to Canadian Niagara Power or Algoma Power for 2012.

(2) Amount provided under licence. ROA achieved in 2010 and 2011 was

significantly lower than the ROA allowed under the licence due to

significant investment occurring at the utility and the lack of rate

relief thereto.    

MATERIAL REGULATORY DECISIONS AND APPLICATIONS

----------------------------------------------------------------------------

Regulated Utility Summary Description

----------------------------------------------------------------------------

FEI/FEVI/FEWI - FEI and FEWI review with the BCUC natural gas

commodity prices and midstream costs 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 contracting for

midstream resources, such as third-party pipeline

and/or storage capacity. The commodity cost of

natural gas and midstream costs are flowed through

to customers without markup.    

- Effective January 1, 2012, rates for typical

residential customers in the Lower Mainland

increased by approximately 3%, reflecting changes

in delivery and midstream costs. Interim approval

was also received to hold FEVI customer rates at

2011 levels, effective January 1, 2012. Natural

gas commodity rates were unchanged, effective

January 1, 2012.    

- Effective April 1, 2012, due to a decrease in

natural gas commodity rates, rates for typical

residential customers in the Lower Mainland

decreased by approximately 10%, and rates for

residential customers at FEWI decreased

approximately 6%, following the BCUC's quarterly

review of commodity costs.    

- Natural gas commodity rates were unchanged,

effective July 1, 2012, following the BCUC's

quarterly review of commodity costs.    

- In July 2011 FEVI received a BCUC decision

approving the option for two First Nations bands

to invest up to a combined 15% in the equity

component of the capital structure of the

liquefied natural gas ("LNG") storage facility on

Vancouver Island. In late 2011 each band exercised

its option and each invested approximately $6

million in equity in the LNG storage facility on

January 1, 2012.    

- In February 2012 the BCUC approved FEI's amended

application for a general tariff for the provision

of compressed natural gas ("CNG") and LNG for

transportation vehicles. FEI has filed

applications for and received interim rate

approval for two projects under the general

tariff. FEI has also applied for approval of its

LNG sales and dispensing service rate schedule on

a permanent basis. In October 2012 FEI received

approval for rate treatment of expenditures

incurred related to the provision of CNG and LNG

services, under the Greenhouse Gas Reductions

(Clean Energy) Regulation ("GHG Regulation") under

the Clean Energy Act.    

- FEI is awaiting a decision from the BCUC on the

Alternative Energy Services Inquiry, which is a

proceeding to determine, among other things,

whether the provision of alternative energy

services is a regulated utility service and

whether FEI or an affiliate, i.e., FortisBC

Alternative Energy Services Inc. ("FAES"), should

provide these services. The alternative energy

services subject to the inquiry include providing

refuelling services for LNG-fuelled vehicles;

owning and operating district energy systems and

various forms of geo-exchange systems; and owning

facilities that upgrade raw biogas into biomethane

for the purpose of selling it to customers.    

- In November 2011 FEI, FEVI and FEWI filed an

application with the BCUC for the amalgamation of

the three companies into one legal entity and for

the implementation of common rates and services

for the utilities' customers across British

Columbia, effective January 1, 2014. In late 2011

the utilities temporarily suspended their

application while they provided additional

information to the BCUC, as requested. In April

2012 the utilities refiled their application. The

amalgamation requires approval by the BCUC and

consent of the Government of British Columbia. The

evidence in the regulatory proceeding has closed

and a BCUC decision is pending.    

- In November 2011 the BCUC issued preliminary

notification to public utilities subject to its

regulation, including the FortisBC gas and

electric utilities, that it would initiate a

Generic Cost of Capital ("GCOC") Proceeding in

early 2012. In February 2012 the BCUC established

that a GCOC Proceeding would take place and in

April 2012 issued a final scoping document

outlining the items that will be reviewed as part

of the GCOC Proceeding, which include: (i) the

appropriate cost of capital for a benchmark low-

risk utility, effective January 1, 2013, which

includes capital structure, ROE and interest on

debt; (ii) the establishment of a benchmark ROE

based on a benchmark low-risk utility effective

from January 1, 2013 through December 31, 2013 for

the initial transition year; (iii) the

determination of whether a return to an ROE

automatic adjustment mechanism is warranted, which

would be implemented January 1, 2014 or, if not, a

future regulatory process will be set to review

the ROE for a benchmark low-risk utility beyond

December 31, 2013; (iv) a generic methodology on

how to establish each utility's cost of capital in

reference to the cost of capital for a benchmark

low-risk utility; (v) a methodology to establish a

deemed capital structure and deemed cost of

capital, particularly for those utilities without

third-party debt; and (vi) for those utilities

that require a deemed interest rate, a methodology

to establish a deemed interest rate automatic

adjustment mechanism and, if not warranted, a

future regulatory process will be set on how the

deemed interest rate would be adjusted beyond

December 31, 2013. The GCOC Proceeding is not

intended to set each utility's risk premium. As

part of the GCOC Proceeding, the BCUC retained an

independent consultant to report on regulatory

practices in Canadian jurisdictions. The timetable

sets the evidence portion of the GCOC Proceeding

to take place through to early December 2012 with

an oral hearing to commence on December 12, 2012.

The result of the GCOC Proceeding could materially

impact the earnings of the FortisBC Energy

companies and FortisBC Electric.    

- In April 2012 the BCUC issued its decision on

the FortisBC Energy companies' 2012-2013 Revenue

Requirements Application ("RRA"). The interim

increases in customer rates, effective January 1,

2012, at FEI and FEWI reflected the applied for

rate increases. The final approved increase in

customer delivery rates, effective January 1,

2012, was 4.2% at FEI, approximately 1.4% lower

than the interim customer delivery rates. The

final approved increase in customer delivery

rates, effective January 1, 2012, was 3.6% at

FEWI, approximately 1.4% lower than the interim

customer delivery rates. In its decision, the BCUC

approved FEVI's 2012 and 2013 customer rates to

remain unchanged from 2011 customer rates. The

difference between interim and final customer

rates at FEI and FEWI is being refunded to

customers, which commenced June 1, 2012. The final

approved customer delivery rates reflect allowed

ROEs and capital structure unchanged from 2011,

pending the outcome of the GCOC Proceeding as it

may impact 2013 rates. The cumulative impacts of

the 2012-2013 revenue requirements decision, where

such impacts were different from those estimated,

were recorded in the second quarter of 2012. The

final rate increases were driven by ongoing

investment in energy infrastructure focused on

system integrity and reliability, forecasted

increased operating expenses associated with

inflation, a heightened focus on safety and

security of the natural gas system, and increasing

compliance with codes and regulations.    

- Following the announcement by the Government of

British Columbia of the GHG Regulation under the

Clean Energy Act, FEI announced an incentive

funding program to assist eligible vehicle

operators in purchasing LNG-fuelled vehicles. The

incentive program funding includes up to $62

million to offset a percentage of the incremental

capital cost for eligible operators in purchasing

qualifying LNG-fuelled vehicles. The eligible

applicants for the incentive program are

commercial return-to-base fleet operators of

heavy-duty trucks, buses, vocational vehicles and

marine vessels. Incentives are expected to be

awarded beginning in late 2012 and will cover up

to 80% of the eligible incremental capital costs

in the initial year. Additionally, the GHG

Regulation allows FEI to invest up to $30 million

for LNG fuelling stations and up to $12 million

for CNG fuelling stations. FEI has filed an

application with the BCUC for rate treatment of

the above expenditures under the GHG Regulation.

----------------------------------------------------------------------------

FortisBC Electric - In August 2012 the BCUC issued its decision on

FortisBC's 2012-2013 RRA, its 2012-2013 Capital

Expenditure Plan ("2012-2013 CEP") and its

Integrated System Plan ("ISP"). The ISP includes

the Company's Resource Plan, Long-Term Capital

Plan and Long-Term Demand Side Management Plan.

The resulting final revenue requirements for 2012

and 2013 reflect an allowed ROE and capital

structure unchanged from 2011, pending the outcome

of the GCOC Proceeding as it may impact 2013

rates. The decision includes an approved forecast

midyear rate base of approximately $1,112 million

for 2012 and $1,173 million for 2013. Under the

2012-2013 CEP, capital expenditures, before

customer contributions, of approximately $100

million for 2012 and approximately $120 million

for 2013, were approved by the BCUC. Approximately

$25 million of approved capital expenditures for

2012 are expected to be incurred in 2013, due to

the timing of receipt in 2012 of the BCUC

decision. The cumulative impacts of the 2012-2013

revenue requirements decision, where such impacts

were different from those estimated, were recorded

in the third quarter of 2012. In its decision the

BCUC approved deferral accounts and flow-through

treatment for variances between actual electricity

revenue and purchased power costs and those

forecasted in determining customer electricity

rates; however, flow-through treatment for finance

charges was denied. FortisBC Electric requested,

and the BCUC approved, that the interim refundable

1.5% increase in customer rates, effective January

1, 2012, as approved by the BCUC in November 2011,

be maintained for the remainder of 2012. The

difference between the final approved increase in

2012 customer rates of 0.6% and the interim

increase in customer rates of 1.5% has been

approved for deferral as a regulatory liability in

2012, to be used in 2013 to reduce the increase in

customer rates to 4.2%, effective January 1, 2013.

The rate increases are due to ongoing investment

in energy infrastructure, including increased

costs of financing the investment, as well as

increased purchased power costs.    

- In November 2011 FortisBC Electric executed an

agreement to purchase capacity from the Waneta

Expansion and submitted the agreement to the BCUC.

The agreement allows FortisBC Electric to purchase

capacity over 40 years upon completion of the

Waneta Expansion, which is expected to be in

spring 2015. The form of the agreement was

originally accepted for filing by the BCUC in

September 2010. In May 2012 the BCUC determined

that the executed agreement is in the public

interest and a hearing is not required. The

agreement has been accepted for filing as an

energy supply contract and FortisBC Electric has

been directed by the BCUC to develop a rate-

smoothing proposal as part of a separate

submission or as part of FortisBC Electric's next

RRA.    

- In March 2012 the BCUC issued an order

establishing a written hearing process to review

the prudency of approximately $29 million in

capital expenditures incurred related to the

Kettle Valley Distribution Source Project, which

was substantially completed in 2009. FortisBC

Electric believes that the capital expenditures

were prudently incurred and, therefore, cannot

reasonably determine if any of such expenditures

may be permanently disallowed from rate base and

any resulting financial impact. The written

hearing process is expected to continue through

the remainder of 2012.    

- In July 2012 FortisBC Electric filed its

Advanced Metering Infrastructure ("AMI")

application, which is currently being reviewed by

the BCUC and various interveners. The AMI project

proposes to improve and modernize FortisBC

Electric's grid by exchanging its manually read

meters with advanced meters. The AMI project is

expected to cost approximately $48 million and be

completed in 2015.    

----------------------------------------------------------------------------

FortisAlberta - In December 2011 the AUC issued its decision on

its 2011 GCOC Proceeding, establishing the allowed

ROE at 8.75% for 2011 and 2012 and, on an interim

basis, at 8.75% for 2013. The deemed equity

component of FortisAlberta's capital structure

remains at 41%. The AUC concluded that it would

not return to a formula-based ROE automatic

adjustment mechanism at that time and that it

would initiate a proceeding in due course to

establish a final allowed ROE for 2013 and revisit

the matter of a return to a formula-based approach

at a future proceeding. A GCOC Proceeding is

expected to commence late 2012 or early 2013.    

- In March 2012 the AUC issued a bulletin

regarding maintaining regulated electricity rates.

The bulletin addressed the Government of Alberta's

letter requesting that regulated electricity rates

be maintained until the government responds to the

recommendations of the Retail Market Review

Committee ("Committee"), announced in February

2012. The Committee's mandate includes the review

of the default electricity rate charged to

customers who do not obtain retail service from a

retailer. The AUC will continue processing

applications and may approve applications that

maintain existing rates or propose rate

reductions; however, the AUC will not issue

decisions that result in rate increases. The

Committee's recommendations were provided to the

Alberta Minister for review in September 2012.    

Further process has yet to be established and the

government-sanctioned rate freeze has not been

lifted.    

- In January 2012 FortisAlberta and other

distribution utilities in Alberta filed motions

for leave to appeal with the Alberta Court of

Appeal with respect to the 2011 GCOC decision,

challenging certain pronouncements made by the AUC

as being incorrect regarding cost responsibility

for stranded assets. In June 2012 the AUC decided

that it would not permit a review and variance of

the 2011 GCOC decision which had been requested by

the utilities, but would examine the issue in a

future proceeding. The court process has been

temporarily adjourned pending the AUC's follow-up

proceeding.    

- In April 2012 the AUC approved, substantially as

filed, a Negotiated Settlement Agreement ("NSA")

pertaining to FortisAlberta's 2012 distribution

revenue requirements, resulting in an average

increase in customer distribution rates of

approximately 5%, effective January 1, 2012,

consistent with the interim rate increase that was

previously approved by the AUC in December 2011.

The cumulative impacts of the 2012 revenue

requirements decision, where such impacts were

different from those estimated, were recorded in

the second quarter of 2012. The increase in

customer rates was driven primarily by ongoing

investment in energy infrastructure, including

increased financing costs. The NSA provided for

forecast midyear rate base of $2,025 million for

2012. The AUC did not approve the continuation of

the deferral of transmission volume variances

associated with FortisAlberta's AESO charges

deferral account for 2012. The deferral of

transmission volume variances, however, was

reinstated, effective January 1, 2013, per the

AUC's generic decision on its PBR Initiative ("PBR

Decision") as discussed further.    

- In July 2012 the AUC issued a decision denying

an application made by the Central Alberta Rural

Electrification Association ("CAREA") in which

CAREA had requested, effective January 1, 2012,

that it be entitled to service any new customers

wishing to obtain electricity for use on property

overlapping CAREA's service area and that

FortisAlberta be restricted to providing service

in the overlapping CAREA service area to only

those customers who are not being provided service

by CAREA. The decision confirms that FortisAlberta

is the primary electricity distribution service

provider within its service territory, including

that portion of the Company's service territory

that overlaps with CAREA's service territory.    

CAREA has not sought leave to appeal this

decision.    

- In June 2012 AESO filed with the AUC a Customer

Contribution Policy Application and an Amortized

Construction Contribution Rider I Application. The

first application proposes a reduction in the

level of AESO contributions that transmission

customers, including FortisAlberta, would pay

versus what the transmission facility owner would

pay. The second application proposes that

transmission customers be given the option to make

the required AESO contributions as a series of

payments over a number of years, rather than as an

up-front payment. Effectively, this would result

in the transmission facility owner financing the

AESO contributions. Decisions on the applications

are not expected until 2013.    

- In September 2012 the AUC issued a generic PBR

Decision outlying the PBR framework applicable to

distribution utilities in Alberta, including

FortisAlberta, for a five-year term commencing

January 1, 2013. Under PBR rate-making, a formula

is used to determine customer rates on an annual

basis. The implementation of PBR does not alter a

utility's right to a reasonable opportunity to

recover the prudent COS and the right to earn a

reasonable ROE. The formula approved by the AUC in

the PBR Decision raises concerns and uncertainty

for FortisAlberta regarding the treatment of

certain capital expenditures. The Company will be

seeking further clarification regarding those

capital expenditures in the required compliance

application, scheduled to be filed with the AUC in

November 2012. FortisAlberta has also sought leave

to appeal this issue with the Alberta Court of

Appeal.    

----------------------------------------------------------------------------

Newfoundland - In March 2012 Newfoundland Power filed a Cost of

Power Capital Application with the PUB to discontinue

the use of the current ROE automatic adjustment

mechanism and to approve a just and reasonable

rate of return on average rate base for 2012. In

June 2012 the PUB ordered that the allowed ROE for

2012 be increased to 8.80% from 8.38% for 2011.

The PUB also approved the deferred recovery from

customers of approximately $2.5 million before

tax, reflecting the difference between the 8.38%

allowed ROE currently reflected in customer

electricity rates in 2012 and the final approved

allowed ROE of 8.80%.    

- In October 2012 the PUB approved Newfoundland

Power's 2013 Capital Expenditure Plan totalling

approximately $82 million, before customer

contributions.    

- Effective July 1, 2012, the PUB approved an

overall average increase in Newfoundland Power's

customer electricity rates of 6.6%. The increase

in rates was primarily the result of the normal

annual operation of the Newfoundland and Labrador

Hydro ("Newfoundland Hydro") Rate Stabilization

Plan. Variances in the cost of fuel used to

generate electricity that Newfoundland Hydro sells

to Newfoundland Power are captured and flowed

through to customers through the operation of

Newfoundland Power's Rate Stabilization Account

("RSA"). The operation of the RSA further captures

variances in certain of Newfoundland Power's

costs, such as pension and energy supply costs.

The above-noted increase in customer rates does

not impact Newfoundland Power's earnings.    

- In September 2012 Newfoundland Power filed a

General Rate Application for 2013 customer

electricity rates and cost of capital. A hearing

on the application is expected in the first

quarter of 2013.    

----------------------------------------------------------------------------

Maritime Electric - In February 2012 the PEI Energy Commission ("PEI

Commission") released its Discussion Paper,

Charting Our Electricity Future, which outlined

discussion points the PEI Commission is seeking

input through a consultative process with

stakeholders and the general public. These

discussion points included: (i) electricity

ownership and management on PEI and whether

Maritime Electric is doing a good job of balancing

safety and reliability with cost of service; (ii)

the future role of IRAC, the PEI Energy

Corporation and the PEI Office of Energy

Efficiency; (iii) a new cable interconnection;

(iv) the treatment of the financing of the $47

million of deferred incremental replacement energy

costs associated with the New Brunswick Power

Point Lepreau nuclear generating station; (v)

regional energy collaboration; (vi) demand side

management; (vii) renewable energy and

environmental stewardship; and (viii) potential

options for natural gas-generated electricity.    

Public forums and stakeholder consultations

occurred in February and March 2012, in which

Maritime Electric was a participant. The PEI

Commission is expected to release a final report

of its recommendations to the Government of PEI

before the end of 2012.    

- In March 2012 Maritime Electric received

regulatory approval to defer, for refund to

customers in a future period to be determined,

income tax expense reductions associated with the

Company's amendment of corporate income tax

filings for the years 2007 through 2010. The

amended filings seek to expense certain costs

previously capitalized for income tax purposes.

- In June 2012 Maritime Electric filed its 2013

Capital Budget Application totaling approximately

$26 million, before customer contributions.    

- Maritime Electric intends to file an application

for 2013 customer rates and allowed ROE with IRAC.

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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 the first quarter of

2012, the OEB published applicable inflationary

and efficiency targets, resulting in minimal

changes in base customer electricity distribution

rates at FortisOntario's operations in Fort Erie,

Gananoque and Port Colborne effective May 1, 2012.

The Third-Generation IRM maintains the allowed ROE

at 8.01% for 2012.    

- In April 2012 the OEB issued Final Decisions and

Orders for customer rates effective May 1, 2012 at

FortisOntario's operations in Fort Erie, Gananoque

and Port Colborne. The result was an average 3.1%

decrease in residential customer rates in Fort

Erie, an average 0.6% increase in residential

customer rates in Gananoque and an average 4.6%

decrease in residential customer rates in Port

Colborne. The above-noted rate changes were mainly

due to changes in rate riders associated with

regulatory deferral accounts and smart meter

funding.    

- In April 2011 FortisOntario provided the City of

Port Colborne and Port Colborne Hydro with an

irrevocable written notice of FortisOntario's

election to exercise the purchase option, under

the then-current operating lease agreement, at the

purchase option price of approximately $7 million

on April 15, 2012. The purchase constituted the

sale of the remaining assets of Port Colborne

Hydro to FortisOntario. The purchase transaction

was approved by the OEB in March 2012 and closed

on April 16, 2012.    

- In March 2012 the OEB issued its decision on

Algoma Power's Third-Generation IRM application

for customer electricity distribution rates,

effective January 1, 2012. The decision approved a

price-cap index of 2.81% for customers subject to

RRRP funding and 0.38% for those customers not

subject to RRRP funding. RRRP funding for 2012 has

been set at approximately $11 million. Algoma

Power's allowed ROE is maintained at 9.85% for

2012.    

- In May 2012 FortisOntario filed a COS

Application for electricity distribution rates in

Fort Erie, Port Colborne and Gananoque, effective

January 1, 2013, using a 2013 forward test year.

The application proposes an allowed ROE of 9.12%

on a deemed equity component of capital structure

of 40%. The allowed ROE is subject to change based

on operation of the automatic ROE adjustment

formula. In September 2012 a settlement agreement

on the COS Application was reached on all issues,

except for the disposal of an income tax-related

regulatory deferral account of $1 million, which

is expected to be decided upon by the OEB by the

end of 2012.    

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Caribbean Utilities - In April 2012 the ERA approved Caribbean

Utilities' 2012-2016 Capital Investment Plan

("CIP") for US$122 million of non-generation

installation capital expenditures. The remaining

US$62 million of the 2012-2016 CIP relates to new

generation installation, which is subject to a

competitive solicitation process with the next

generation unit scheduled for installation in

2014. The 2012-2016 CIP was prepared in line with

the Certificate of Need that was filed with the

ERA in November 2011. Proposals for installation

of the new generation unit from six qualified

bidders, including Caribbean Utilities, was

requested by the ERA and Caribbean Utilities'

proposal was submitted in July 2012. The ERA's

decision on the successful bidder is expected by

the end of the 2012. A second increment of 18 MW

of new generating capacity is required up to three

years later in 2017, contingent on economic growth

on Grand Cayman and the related growth in demand

for electricity.    

- The proposed 2013-2017 CIP, totalling

approximately US$125 million of non-generation

installation capital expenditures, was submitted

to the ERA in October 2012 for approval.    

- In March 2012 the ERA approved the creation of

Caribbean Utilities' wholly owned subsidiary

DataLink Ltd. ("DataLink"). Subsequently, the

Information and Communications Technology

Authority ("ICTA") granted a licence to DataLink

to provide fibre optic infrastructure and other

information and communication technology services

on Grand Cayman. The ICTA licence allows DataLink

to assume full responsibility for existing pole-

attachment agreements and optical fibre lease

agreement currently held by Caribbean Utilities

with third-party information and communications

technology service providers. The reassignment of

existing contracts is in progress and is expected

to be completed before the end of 2012. The ERA

has approved executed management and maintenance,

pole attachment and fibre optic agreements between

Caribbean Utilities and DataLink.    

- In December 2011 Caribbean Utilities conducted

and completed a competitive bidding process to

fill up to 13 MW of non-firm renewable energy

capacity. During the third quarter of 2012,

Caribbean Utilities commenced discussions with two

renewable energy developers that were selected to

provide renewable energy to the utility's grid.

The proposals being considered are two 5-MW solar

photovoltaic power plants and one 3-MW small-scale

wind turbine project. The developers will finance,

construct, own and operate the renewable

generation facilities. Negotiations towards firm

power purchase agreements with the developers are

ongoing. The power purchase agreements, however,

are subject to ERA review and approval. Once the

negotiations are completed, and the necessary

regulatory approvals received, final power

purchase agreements will be established with the

two developers who will then start construction of

the projects. It is anticipated that the 13 MW of

renewable energy capacity will be connected to the

grid by 2014.    

- Effective June 1, 2012, following review and

approval by the ERA, Caribbean Utilities' base

customer electricity rates increased by 0.7% as a

result of changes in the applicable consumer price

indices and the utility's achieved ROA for 2011.

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Fortis Turks and Caicos - An independent review of the regulatory

framework for the electricity sector in the Turks

and Caicos Islands was performed during the third

quarter of 2011 on behalf of the Interim

Government. Fortis Turks and Caicos provided a

comprehensive response to the Interim Government

in January 2012 stating that the Company supports

limited mutually agreed upon reforms, but that its

current licences must be respected and can only be

changed by mutual consent. Specifically, Fortis

Turks and Caicos would support reforms that

strengthen the role of the regulator in the rate-

setting process and that are fair to all

stakeholders. Negotiations between Fortis Turks

and Caicos and the Interim Government commenced

during the third quarter of 2012 with Fortis Turks

and Caicos presenting a new regulatory framework

proposal to the Interim Government. A third-party

consultant was engaged by the Interim Government

to review the proposal and provide

recommendations.    

- In February 2012 the Interim Government approved

an approximate 26% increase in electricity rates,

effective April 1, 2012, for Fortis Turks and

Caicos' large hotel customers. In addition, other

qualitative enhancements to the franchise were

also achieved, including: (i) improved wording in

the Electricity Rate Regulation; (ii) an approved

increase in kilowatt hour consumption thresholds

for both medium and large hotels; (iii) an

expansion of service territory to cover all of the

Caicos Islands, except for areas currently

serviced by private suppliers' licences, with new

25-year licences issued for the expanded service

territory; and (iv) the discontinuance of the

government subsidization of the utility's South

Caicos operations.    

- In March 2012 Fortis Turks and Caicos submitted

its 2011 annual regulatory filing outlining the

Company's performance in 2011. Included in the

filing were the calculations, in accordance with

the utility's licence, of rate base of US$166

million for 2011 and cumulative shortfall in

achieving allowable profits of US$72 million as at

December 31, 2011.    

- In April 2012 Fortis Turks and Caicos entered

into a Streetlight Takeover Agreement with the

Interim Government, whereby the responsibility for

the ownership, installation and maintenance of all

streetlights in the utility's service territory

was transferred to Fortis Turks and Caicos.    

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CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between September 30, 2012 and December 31, 2011.

Significant Changes in the Consolidated Balance Sheets (Unaudited) between September 30, 2012 and December 31, 2011

----------------------------------------------------------------------------

Increase/

Balance Sheet (Decrease)

Account ($ millions) Explanation

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Cash and cash 60 The increase was primarily due to cash on

equivalents hand at the FortisBC Energy companies

associated with seasonality of operations and

a portion of the proceeds received from an

equity injection by Fortis during the second

quarter of 2012, and the timing of cash

payments at FortisAlberta and the Waneta

Expansion Limited Partnership (the "Waneta

Partnership").    

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Accounts (228) The decrease was driven by the FortisBC

receivable Energy companies, mainly due to a seasonal

decrease in sales and the lower commodity

cost of natural gas reflected in customer

rates. Accounts receivable also decreased at

Newfoundland Power, due to seasonality and

the timing of collections from customers and

decreased at FortisAlberta, due to decreased

rate riders and a change in the billing of

retailers from a monthly to a weekly basis.

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Inventories 23 The increase was driven by the normal

seasonal increase of gas in storage at the

FortisBC Energy companies, partially offset

by the impact of lower natural gas commodity

prices.    

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Regulatory (28) The decrease was mainly due to: (i)

assets - approximately $100 million associated with

current and the deferral of the change in the fair market

long-term value of the natural gas derivatives at the

FortisBC Energy companies; (ii) the

collection of approximately $44 million in

AESO charges deferral at FortisAlberta; and

(iii) a reduction in regulatory deferred

employee future benefits costs. The decrease

was partially offset by higher regulatory

deferred income taxes, and an increase in the

deferral of various other costs, as permitted

by the regulators, mainly at the FortisBC

regulated utilities.    

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Other assets 25 The increase was mainly due to financing

costs associated with the Corporation's

Subscription Receipts offering, an increase

in income taxes receivable at Maritime

Electric and an increase in defined benefit

pension assets at Newfoundland Power.    

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Utility capital 406 The increase primarily related to $737

assets million invested in electricity and gas

systems, partially offset by depreciation and

customer contributions year-to-date 2012, and

the impact of foreign exchange on the

translation of US-dollar denominated utility

capital assets.    

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Short-term (62) The decrease was primarily due to a reduction

borrowings in borrowings at the FortisBC Energy

companies with a portion of the proceeds

received from an equity injection by Fortis

during the second quarter of 2012 and

seasonality of operations, partially offset

by increased borrowings at Caribbean

Utilities, mainly to repay maturing long-term

debt.    

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Accounts (135) The decrease was mainly due to: (i) the $75

payable and million change in the fair market value of

other current the natural gas derivatives at the FortisBC

liabilities Energy companies; (ii) lower amounts owing

for purchased natural gas at the FortisBC

Energy companies and purchased power at

Newfoundland Power, associated with

seasonality of operations; (iii) the timing

of payment of property taxes and franchise

fees at the FortisBC Energy companies; and

(iv) lower accounts payable at the Waneta

Partnership associated with the timing of

payments related to the construction of the

Waneta Expansion. The decrease was partially

offset by higher accounts payable associated

with transmission-connected projects and

timing of AESO payments for transmission

costs at FortisAlberta.    

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Regulatory 65 The increase was mainly due to an overall

liabilities - increase in deferrals at the FortisBC Energy

current and companies and an increase in the AESO charges

long-term deferral at FortisAlberta. The increase in

deferrals at the FortisBC Energy companies

was mainly due to: (i) an increase in the

Revenue Surplus Deferred Account, reflecting

amounts collected in customer rates in excess

of the cost of providing service at FEVI

year-to-date 2012; (ii) an increase in the

Midstream Cost Reconciliation Account and the

Commodity Cost Reconciliation Account, as

amounts collected in customer rates were in

excess of actual midstream and commodity gas-

delivery costs, respectively, year-to-date

2012; and (iii) the provisioning for non-ARO

removal costs commencing January 1, 2012. The

increase was partially offset by

approximately $25 million associated with the

deferral of the change in the fair market

value of the natural gas derivatives at the

FortisBC Energy companies.    

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Deferred income 57 The increase was driven by tax timing

tax liabilities differences related mainly to capital

- current and expenditures at the regulated utilities.    

long-term

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Long-term debt 149 The increase was primarily due to higher

(including borrowings under the Corporation's committed

current credit facility, largely in support of the

portion) construction of the Waneta Expansion and for

other general corporate purposes. The

increase was partially offset by regularly

scheduled debt repayments at Fortis

Properties, the FortisBC Energy companies and

Caribbean Utilities, and the impact of

foreign exchange on the translation of US-

dollar denominated debt.    

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Shareholders' 110 The increase was primarily due to net

equity earnings attributable to common equity

(before non- shareholders year-to-date 2012, less common

controlling share dividends, and the issuance of common

interests) shares mainly under the Corporation's

dividend reinvestment and stock option plans.

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Non-controlling 80 The increase was driven by advances from the

interests 49% non-controlling interests in the Waneta

Partnership and an approximate $12 million,

or 15%, equity investment by two First

Nations bands in the LNG storage facility on

Vancouver Island.    

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LIQUIDITY AND CAPITAL RESOURCES

The table below outlines the Corporation's consolidated sources and uses of cash for the third quarter and year-to-date 2012, as compared to the same periods in 2011, followed by a discussion of the nature of the variances in cash flows.

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Summary of Consolidated Cash Flows (Unaudited)

Periods Ended

September 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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Cash, Beginning of

Period 231 296 (65) 87 107 (20)

Cash Provided by

(Used in):

Operating

Activities 221 151 70 804 684 120

Investing

Activities (277) (265) (12) (761) (748) (13)

Financing

Activities (28) (77) 49 17 62 (45)

Effect of Exchange

Rate Changes on

Cash and Cash

Equivalents - 1 (1) - 1 (1)

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Cash, End of Period 147 106 41 147 106 41

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Operating Activities: Cash flow from operating activities was $70 million higher quarter over quarter. The increase was primarily due to: (i) favourable changes in working capital; (ii) the collection from customers of regulator-approved increased depreciation and amortization expense, mainly at the FortisBC Energy companies; and (iii) favourable changes in long-term regulatory deferral accounts. The favourable changes in working capital were associated with changes in inventories, accounts payable and other current liabilities, and current regulatory deferral accounts, partially offset by unfavourable changes in accounts receivable. The increase was partially offset by lower earnings.

Cash flow from operating activities was $120 million higher year to date compared to the same period last year. The increase was primarily due to favourable changes in working capital and the collection from customers of regulator-approved increased depreciation and amortization expense, mainly at the FortisBC Energy companies. Favourable changes in working capital were associated with changes in current regulatory deferral accounts and accounts receivable. The above increase was partially offset by unfavourable changes in long-term regulatory deferral accounts and a defined benefit pension solvency deficit funding payment made by Newfoundland Power during the second quarter of 2012.

Investing Activities: Cash used in investing activities was $12 million higher for the quarter and $13 million higher year to date. The increases reflected the acquisition of TCU in August 2012 for a net cash purchase price of approximately $7 million (US$7 million), net of cash acquired. The increase year to date also reflected the acquisition of the remaining assets of Port Colborne Hydro by FortisOntario in April 2012 for approximately $7 million.

For the quarter, lower capital spending related to the non-regulated Waneta Expansion and at FortisBC Electric and the Caribbean Regulated Electric Utilities was largely offset by an increase in capital spending at FortisAlberta. Year to date, lower capital spending at the FortisBC Energy companies and FortisBC Electric was largely offset by an increase in capital spending at FortisAlberta and capital spending related to the non-regulated Waneta Expansion. Capital expenditures for the first half of 2011 included those of Belize Electricity up to June 20, 2011, when the utility was expropriated by the GOB.

Financing Activities: Cash used in financing activities was $49 million lower quarter over quarter. The decrease was primarily due to lower net repayments under committed credit facilities classified as long term, partially offset by lower net proceeds from short-term borrowings and lower proceeds from the issuance of common shares.

Cash provided by financing activities was $45 million lower year to date compared to the same period last year. The decrease was primarily due to: (i) lower proceeds from the issuance of common shares; (ii) lower proceeds from long-term debt; (iii) higher repayments of long-term debt; (iv) higher common share dividends paid; and (v) issue costs related to the June 2012 Subscription Receipts offering. The decrease was partially offset by higher net borrowings under committed credit facilities classified as long term and lower net repayments of short-term borrowings.

Net proceeds from short-term borrowings were $69 million lower quarter over quarter, driven by the FortisBC Energy companies. Net repayments of short-term borrowings were $53 million lower year to date compared to same period last year, driven by Caribbean Utilities.

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

----------------------------------------------------------------------------

Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)

Periods Ended

September 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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Caribbean Utilities

(1) - 9 (9) - 38 (38)

Other - - - - 1 (1)

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Total - 9 (9) - 39 (39)

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(1) Issued 15-year US$15 million 4.85% and 20-year US$25 million 5.10%

unsecured notes. The first tranche of US$30 million was issued in June

2011 and the second tranche of US$10 million was issued in July 2011.

The net proceeds were used to repay current installments on long-term

debt and short-term credit facility borrowings and to finance capital

expenditures.    

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Repayments of Long-Term Debt and Capital Lease and Finance Obligations

(Unaudited)

Periods Ended

September 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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FortisBC Energy

Companies - (1) 1 (18) (3) (15)

Caribbean Utilities - - - (13) (12) (1)

Fortis Properties - (2) 2 (24) (6) (18)

Other - - - (2) (6) 4

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Total - (3) 3 (57) (27) (30)

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Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)

Periods Ended

September 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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FortisAlberta (22) 33 (55) (13) 50 (63)

FortisBC Electric (17) (7) (10) (9) - (9)

Newfoundland Power (20) (13) (7) 8 10 (2)

Corporate 50 (191) 241 235 (165) 400

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Total (9) (178) 169 221 (105) 326

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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 offerings are used to repay borrowings under the Corporation's committed credit facility. The borrowings under the Corporation's committed credit facility during 2012 were largely in support of the construction of the Waneta Expansion and for other general corporate purposes.

Advances of approximately $14 million for the quarter and $70 million year to date were received from non-controlling interests in the Waneta Partnership to finance capital spending related to the Waneta Expansion, compared to $20 million received for the third quarter of 2011 and $76 million received year-to-date 2011. In January 2012 advances of approximately $12 million were received from two First Nations bands representing their 15% equity investment in the LNG storage facility on Vancouver Island.

In June 2011 Fortis publicly issued 9.1 million common shares for gross proceeds of $300 million. In July 2011 an additional 1.2 million common shares were publicly issued upon the exercise of an over-allotment option, resulting in gross proceeds of approximately $41 million. The total net proceeds of $327 million from the common share offering were used to repay borrowings under credit facilities and finance equity injections into the regulated utilities in western Canada and the Waneta Partnership in support of infrastructure investment, and for other general corporate purposes.

Common share dividends paid during the third quarter of 2012 were $42 million, net of $15 million of dividends reinvested, compared to $38 million, net of $16 million of dividends reinvested, paid during the same quarter of 2011. Common share dividends paid year-to-date 2012 were $128 million, net of $43 million of dividends reinvested, compared to $109 million, net of $47 million of dividends reinvested, paid year-to-date 2011. The dividend paid per common share for each of the first, second and third quarters of 2012 was $0.30 compared to $0.29 for each of the first, second and third quarters of 2011. The weighted average number of common shares outstanding for the third quarter and year to date was 190.2 million and 189.6 million, respectively, compared to 186.5 million and 179.5 million for the third quarter and year to date, respectively, in 2011.

CONTRACTUAL OBLIGATIONS

As at September 30, 2012, consolidated contractual obligations of Fortis over the next five years and for periods thereafter are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2011 Annual MD&A and below, where applicable. The presentation of certain contractual obligations has changed from that provided in the 2011 Annual MD&A, due to the adoption of US GAAP. For further information concerning these changes, refer to the 2011 audited consolidated financial statements prepared in accordance with US GAAP and voluntarily filed on SEDAR.

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Contractual Obligations (Unaudited) Due Due in Due in Due

As at September 30, 2012 within years years after

($ millions) Total 1 year 2 and 3 4 and 5 5 years

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Long-term debt 5,937 90 826 563 4,458

Capital lease and finance

obligations (1) 2,605 47 97 101 2,360

Waneta Partnership promissory note 72 - - - 72

Gas purchase contract obligations

(2) 351 289 62 - -

Power purchase obligations

FortisBC Electric 20 11 6 3 -

FortisOntario 371 44 99 105 123

Maritime Electric 148 37 80 18 13

Capital cost 446 17 36 35 358

Joint-use asset and shared service

agreements 63 4 8 6 45

Operating lease obligations 26 4 7 6 9

Defined benefit pension funding

contributions (3) 88 37 34 15 2

Other 8 1 3 - 4

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Total 10,135 581 1,258 852 7,444

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(1) Includes principal payments, imputed interest and executory costs,

mainly related to FortisBC Electric's Brilliant Power Purchase

Agreement and Brilliant Terminal Station

(2) Based on index prices as at September 30, 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, 2012 FortisBC Energy companies (covering non-unionized

employees)

December 31, 2013 FortisBC Energy companies (covering unionized

employees)

December 31, 2013 FortisBC Electric

December 31, 2013 FortisAlberta

December 31, 2014 Newfoundland Power

The estimate of defined benefit pension funding contributions includes

the impact of the outcome of the December 31, 2011 actuarial

valuation, completed in April 2012, associated with the defined

benefit pension plan at Newfoundland Power. As a result of the

valuation, Newfoundland Power is required to fund a solvency

deficiency of approximately $53 million, including interest, over five

years beginning in 2012, which is reflected in the above table. The

Company fulfilled its 2012 annual solvency deficit funding requirement

during the second quarter of 2012.    


Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2011 Annual MD&A, except as described as follows.

In January 2012 two First Nations bands each invested approximately $6 million in equity in the Mount Hayes LNG storage facility, representing a 15% equity interest in the Mount Hayes Limited Partnership, with FEVI holding the controlling 85% ownership interest. The non-controlling interests hold put options, which, if exercised, would require FEVI to repurchase the 15% ownership interest for cash, in accordance with the terms of the partnership agreement.

In September 2012 Caribbean Utilities entered into primary and secondary fuel supply contracts with two different suppliers and is committed to purchasing approximately 60% and 40% of the Company's diesel fuel requirements under each of the contracts, respectively, for the operation of Caribbean Utilities' diesel-powered generating plant. The approximate combined quantities under the contracts, expressed in millions of imperial gallons, on an annual basis by fiscal year are: 2012 - 10.8, 2013 - 32.4 and 2014 - 18.9. The contracts expire in July 2014 with the option to renew for two additional 18-month terms. The renewal options can be exercised only within six months of the expiry dates of the existing contracts.

In February 2012 Fortis entered into an agreement to acquire CH Energy Group for US$1.5 billion, including the assumption of approximately US$500 million in debt on closing. The acquisition is expected to close by the end of the first quarter of 2013. In June 2012, to finance a portion of the purchase price of CH Energy Group, Fortis sold 18,500,000 Subscription Receipts at $32.50 each, realizing gross proceeds of approximately $601 million. Each Subscription Receipt will entitle the holder thereof to receive, on satisfaction of the Release Conditions and without payment of additional consideration, one common share of Fortis and a cash payment equal to the dividends declared on Fortis common shares to holders of record during the period from June 27, 2012 to the date of issuance of the common shares in respect of the Subscription Receipts. For further information on the pending acquisition of CH Energy Group and the Subscription Receipts offering, refer to the "Significant Items" and "Business Risk Management" sections of this MD&A.

FortisBC Electric has offered to purchase the City of Kelowna's electrical utility assets for approximately $55 million. Closing of the transaction is subject to certain conditions and approvals. For further information, refer to the "Significant Items" section of this MD&A.

For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program, which is not included in the preceeding Contractual Obligations table, refer to the "Capital Expenditure 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 enable 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 offerings. 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 each of the utility's customer rates.

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

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Capital Structure

(Unaudited) As at

September 30, 2012 December 31, 2011

($ millions) (%)($ millions) (%)

----------------------------------------------------------------------------

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Total debt and capital lease

and finance obligations

(net of cash) (1) (2) 6,328 56.6 6,296 57.1

Preference shares 912 8.2 912 8.3

Common shareholders' equity 3,933 35.2 3,823 34.6

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Total (3) 11,173 100.0 11,031 100.0

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(1) Includes long-term debt and capital lease and finance obligations,

including current portion, and short-term borrowings, net of cash

(2) Excluding capital lease and finance obligations, the debt component of

the capital structure was 54.9% as at September 30, 2012 and 55.3% as

at December 31, 2011.    

(3) Excludes amounts related to non-controlling interests


The improvement in the capital structure was primarily due to: (i) lower short-term borrowings; (ii) an increase in cash; (iii) common shares issued, mainly under the Corporation's dividend reinvestment and stock option plans; and (iv) net earnings attributable to common equity shareholders, net of dividends. The capital structure was also impacted by an increase in long-term debt, mainly due to higher borrowings under the Corporation's committed credit facility, largely in support of the construction of the Waneta Expansion and for other general corporate purposes, partially offset by regularly scheduled debt repayments.

CREDIT RATINGS

The Corporation's credit ratings are as follows:

Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt credit

rating)

DBRS A(low) (unsecured debt credit rating)


In May 2012 and July 2012, S&P and DBRS, respectively, affirmed the Corporation's debt credit ratings. Due to the Corporation's financing plans for the pending acquisition of CH Energy Group and the expected completion of the Waneta Expansion on time and on budget, S&P and DBRS also removed the ratings from credit watch with negative implications and under review with developing implications, respectively, where the ratings had been placed in February 2012.

The above-noted 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, 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 EXPENDITURE 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 $794 million in gross capital expenditures by segment year-to-date 2012 is provided in the following table.

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Gross Consolidated Capital Expenditures (Unaudited) (1)

Year-to-Date September 30, 2012

($ millions)

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Other

Regula- Total Regula-

ted Regula ted

Elec- - Elec- Non-

Fortis tric ted tric Regula-

BC Fortis New- Utili- Utili- Utili- ted -

Energy Fortis BC found- ties - ties - ties - Utili- Fortis

Compa- Alberta Elec- land Cana- Cana- Carib- ty Proper-

nies (2) tric Power dian dian bean (3) ties Total

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144 304 52 58 35 593 33 144 24 794

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(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 non-

ARO removal expenditures, net of salvage proceeds, for those utilities

where such expenditures are permissible in rate base in 2012. Excludes

capitalized depreciation and amortization and non-cash equity

component of AFUDC.    

(2) Includes payments made to AESO for investment in transmission-related

capital projects

(3) Includes non-regulated generation capital expenditures, mainly related

to the Waneta Expansion


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 have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2011 Annual MD&A. Gross consolidated capital expenditures for 2012 are forecasted at approximately $1.3 billion.

FEI's Customer Care Enhancement Project, at an estimated total project cost of $110 million, came into service at the beginning of January 2012.

Construction progress on the $900 million Waneta Expansion is going well and the project is currently on schedule and on budget. Major construction activities on-site include the completion of the excavation of the intake, powerhouse and power tunnels. Approximately $380 million in total has been spent on the Waneta Expansion since construction began late in 2010.

Over the five-year period 2012 through 2016, consolidated gross capital expenditures are expected to be approximately $5.5 billion, consistent with that disclosed in the 2011 Annual MD&A. The addition of CH Energy Group is expected to add approximately $0.5 billion to the Corporation's consolidated capital expenditure program from 2013 through 2016. Approximately 64% of the $5.5 billion capital program is expected to be incurred at the regulated electric utilities, driven by FortisAlberta and FortisBC Electric. Approximately 23% and 13% of the capital program is expected to be incurred at the regulated gas utilities and non-regulated operations, respectively. Capital expenditures at the regulated utilities are subject to regulatory approval. Over the five-year period, excluding CH Energy Group, on average annually, 39% of utility capital spending is expected to be incurred to meet customer growth; 38% is expected to be incurred to ensure continued and enhanced performance, reliability and safety of generation and T&D assets (i.e., sustaining capital expenditures); and 23% is expected to be incurred for facilities, equipment, vehicles, information technology and other assets.

CASH FLOW REQUIREMENTS

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

The Corporation's ability to service its debt obligations and pay dividends on its common shares 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 that 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 September 30, 2012, management expects consolidated long-term debt maturities and repayments to average approximately $295 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.

In May 2012 Fortis filed a base shelf prospectus under which Fortis may, from time to time during the 25-month period from May 10, 2012, offer, by way of a prospectus supplement, common shares, preference shares, subscription receipts and/or unsecured debentures in the aggregate amount of up to $1.3 billion (or the equivalent in US dollars or other currencies). The base shelf prospectus provides the Corporation with flexibility to access securities markets in a timely manner. The nature, size and timing of any offering of securities under the Corporation's base shelf prospectus will be consistent with the past capital raising practices of the Corporation and continue to be dependant upon the Corporation's assessment of its requirements for funding and general market conditions.

To finance a portion of the Corporation's pending acquisition of CH Energy Group, Fortis offered and sold, by way of a prospectus supplement, approximately $601 million in Subscription Receipts under a bought-deal offering with a syndicate of underwriters. For further information refer to the "Significant Items" and "Business Risk Management" sections of this MD&A.

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 $55 million as at September 30, 2012 (December 31, 2011 - $56 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 19 to the Corporation's interim unaudited consolidated financial statements for the three and nine months ended September 30, 2012.

Except for the debt at the Exploits Partnership, as discussed above, Fortis and its subsidiaries were in compliance with debt covenants as at September 30, 2012 and are expected to remain compliant throughout the remainder of 2012.

CREDIT FACILITIES

As at September 30, 2012, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.5 billion, of which $2.0 billion was unused, including $764 million unused under the Corporation's $1 billion committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, with no one bank holding more than 20% of these facilities. Approximately $2.3 billion of the total credit facilities are committed facilities with maturities ranging from 2013 through 2017.

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

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Credit Facilities (Unaudited) As at

September December

Regulated Fortis Corporate 30, 31,

($ millions) Utilities Properties and Other 2012 2011

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Total credit facilities 1,401 13 1,045 2,459 2,248

Credit facilities

utilized:

Short-term borrowings (97) - - (97) (159)

Long-term debt

(including current

portion) (63) - (236) (299) (74)

Letters of credit

outstanding (67) - (1) (68) (66)

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Credit facilities

unused 1,174 13 808 1,995 1,949

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As at September 30, 2012 and December 31, 2011, 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 March 2012 Newfoundland Power renegotiated and amended its $100 million unsecured committed revolving credit facility, obtaining an extension to the maturity of the facility from August 2015 to August 2017. The amended credit facility agreement reflects a decrease in pricing but, otherwise, contains substantially similar terms and conditions as the previous credit facility agreement.

In April 2012 FortisBC Electric renegotiated and amended its 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 2015 and $50 million now maturing in May 2013.

In May 2012 FHI extended its $30 million operating credit facility to mature in May 2013 from May 2012. The new agreement contains substantially similar terms and conditions as the previous credit facility agreement.

In May 2012 Fortis increased the amount available for borrowing under its unsecured committed revolving corporate credit facility from $800 million to $1 billion, as permitted under the credit facility agreement.

In May 2012 Caribbean Utilities renegotiated and increased the amount available for borrowing under its unsecured credit facilities to US$47 million from US$33 million.

In June 2012 FortisOntario entered into a new short-term credit facility agreement for $30 million, replacing two short-term credit facilities totaling $20 million. The new credit facility agreement reflects a decrease in pricing and improved terms and conditions. In July 2012 the former credit facilities were terminated.

In July 2012 FEI entered into a one-year extension of its $500 million unsecured committed revolving credit facility, extending the maturity date from August 2013 to August 2014. The amended credit facility agreement reflects an increase in pricing but, otherwise, contains substantially similar terms and conditions as the previous credit facility agreement.

In July 2012 FortisAlberta renegotiated and amended its $250 million unsecured committed revolving credit facility, obtaining an extension to the maturity of the facility from September 2015 to August 2016. The amended credit facility agreement reflects a decrease in pricing but, otherwise, contains substantially similar terms and conditions as the previous credit facility agreement.

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.

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Financial Instruments ...