Fortis Earns $45 Million in Third Quarter

Marketwired

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. 

Consolidated Financial Highlights (Unaudited)  
Periods Ended September 30 Quarter   Year-to-Date  
($ millions, except for common share data) 2012 2011 Variance   2012   2011 Variance  
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 )
Net Earnings 59 70 (11 ) 269   270 (1 )
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 )
  Net Earnings 59 70 (11 ) 269   270 (1 )
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  
Cash Flow from Operating Activities 221 151 70   804   684 120  
                   
                   
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
 
 
Regulated
Utility
 
 
 
 
 
 
Regulatory
Authority
Allowed
Common
Equity
(%)
   
Allowed Returns (%)
 
 
 
 
 
Supportive Features
 
2010
 
2011
 
2012
Future or Historical Test Year
Used to Set Customer Rates
          ROE     COS/ROE
FEI
 
 
 
 
 
 
 
 
 
British Columbia
Utilities Commission
("BCUC")
 
 
40
 
 
 
 
9.50
 
 
 
 
9.50
 
 
 
 
9.50
 
 
 
 
 
 
 
 
 
FEI: Prior to January 1, 2010, 50/50
sharing of earnings above or below
the allowed ROE under a PBR
mechanism that expired on
December 31, 2009 with a two-year
phase-out
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
Electric
 
 
BCUC
 
40
 
9.90
 
9.90
 
9.90
 
 
 
COS/ROE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PBR mechanism for 2009 through
2011: 50/50 sharing of earnings
above or below the allowed ROE up
to an achieved ROE that is 200 basis
points above or below the allowed
ROE - excess to deferral account
                 
                ROE established by the BCUC
                Future Test Year
FortisAlberta   AUC 41 9.00 8.75 8.75   COS/ROE
                 
                ROE established by the AUC
                Future Test Year
Newfoundland
Power
 
 
 
 
 
 
 
 
Newfoundland and
Labrador Board of
Commissioners of
Public Utilities
("PUB")
45
 
 
 
 
9.00 +/-
50 bps
 
 
 
8.38 +/-
50 bps
 
 
 
8.80 +/-
50 bps
 
 
 
 
 
 
 
 
COS/ROE
 
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
Electric
 
 
 
 
 
 
Island Regulatory
and Appeals
Commission
("IRAC")
40
 
 
 
9.75
 
 
 
9.75
 
 
 
9.75
 
 
 
 
 
 
 
COS/ROE
Future Test Year
 
 
FortisOntario
 
 
 
Ontario Energy
Board ("OEB")
 
 
 
 
 
 
 
 
 
 
Canadian Niagara Power - COS/ROE
 
 
 
 
 
Canadian Niagara
Power
40
 
8.01
 
8.01
 
8.01 (1)
 
 
 
Algoma Power - COS/ROE and
subject to Rural and Remote Rate
 
 
 
 
Algoma Power
 
40
 
8.57
 
9.85
 
9.85 (1)
 
 
 
Protection ("RRRP") Program
 
 
 
 
 
Franchise Agreement
Cornwall Electric
 
 
 
 
 
 
 
 
 
 
Cornwall Electric - Price cap 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
Utilities
 
 
 
 
 
 
Electricity
Regulatory
Authority ("ERA")
 
N/A
 
 
 
7.75 -
9.75
 
 
7.75 -
9.75
 
 
7.25 -
9.25
 
 
 
 
 
 
 
Rate-cap adjustment 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
and Caicos 
  Utilities make annual filings to the Interim Government of the Turks and Caicos Caicos Islands ("Interim Government") N/A   17.50 (2) 17.50 (2)   17.50 (2)   COS/ROA 
                 
                If the actual ROA is lower than the allowed ROA, due to additional costs resulting from a hurricane or other event, the Company may apply for an increase in customer rates in the following year.
                 
                Future Test Year
(1) 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
Power
  - In March 2012 Newfoundland Power filed a Cost of 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.
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.
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.
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.

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

       
Balance Sheet Account   Increase/
(Decrease)
($ millions)
Explanation
Cash and cash equivalents   60 The increase was primarily due to cash on 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").
Accounts receivable   (228) The decrease was driven by the FortisBC 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.
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.
Regulatory assets -
current and long-term
  (28) The decrease was mainly due to: (i) approximately $100 million associated with the deferral of the change in the fair market 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.
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.
Utility capital assets   406 The increase primarily related to $737 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.
Short-term borrowings   (62) The decrease was primarily due to a reduction 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.
Accounts payable and other current liabilities   (135) The decrease was mainly due to: (i) the $75 million change in the fair market value of the natural gas derivatives at the FortisBC 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.
Regulatory liabilities - current and long-term   65 The increase was mainly due to an overall increase in deferrals at the FortisBC Energy companies and an increase in the AESO charges 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.
Deferred income tax liabilities - current and long-term   57 The increase was driven by tax timing differences related mainly to capital expenditures at the regulated utilities.
Long-term debt
 (including current portion)
  149 The increase was primarily 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. 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.
Shareholders'' equity
 (before non-controlling interests)
  110 The increase was primarily due to net earnings attributable to common equity shareholders year-to-date 2012, less common share dividends, and the issuance of common shares mainly under the Corporation''s dividend reinvestment and stock option plans.
Non-controlling interests   80 The increase was driven by advances from the 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.

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.

Summary of Consolidated Cash Flows (Unaudited)  
Periods Ended September 30 Quarter   Year-to-Date  
($ millions) 2012   2011   Variance   2012   2011   Variance  
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 )
Cash, End of Period 147   106   41   147   106   41  

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  
Caribbean Utilities (1) - 9 (9 ) - 38 (38 )
Other - - -   - 1 (1 )
Total - 9 (9 ) - 39 (39 )
(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.
   
   
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  
FortisBC Energy Companies - (1 ) 1 (18 ) (3 ) (15 )
Caribbean Utilities - -   - (13 ) (12 ) (1 )
Fortis Properties - (2 ) 2 (24 ) (6 ) (18 )
Other - -   - (2 ) (6 ) 4  
Total - (3 ) 3 (57 ) (27 ) (30 )
                     
                     
Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)  
Periods Ended September 30 Quarter   Year-to-Date  
($ millions) 2012   2011   Variance   2012   2011   Variance  
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  
Total (9 ) (178 ) 169   221   (105 ) 326  

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.

Contractual Obligations (Unaudited)
As at September 30, 2012
($ millions)


Total
Due
within
1 year
Due in
years
2 and 3
Due in
years
4 and 5
Due
after
5 years
Long-term debt 5,937 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
Total 10,135 581 1,258 852 7,444
(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.

Capital Structure (Unaudited) As at
  September 30, 2012 December 31, 2011
  ($ millions) (%) ($ millions) (%)
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
Total (3) 11,173 100.0 11,031 100.0
(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.

Gross Consolidated Capital Expenditures (Unaudited) (1)  
Year-to-Date September 30, 2012   
($ millions)   
 
 
Fortis
BC
Energy
Compa-
nies
 
 
 
Fortis
Alberta
(2)
   
 
 
Fortis
BC
Elec-
tric
   
 
 
New-
found-
land
Power
  Other
Regula-
ted
Elec-
tric
Utili-
ties -
Cana-
dian
   
Total
 Regula-
ted

 Utili-
ties -

Cana-
dian
   
Regula-
ted

Elec-
tric

Utili-
ties -

Carib-
bean
   
 
Non-
Regula-
ted -

Utili-
ty
(3)
   
 
 
Fortis
Proper-
ties
 
 
 
 
Total
144  304    52    58    35    593    33    144    24  794 
(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.

Credit Facilities (Unaudited)         As at  
  Regulated   Fortis Corporate   September 30,   December 31,  
($ millions) Utilities   Properties and Other   2012   2011  
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 )
Credit facilities unused 1,174   13 808   1,995   1,949  

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.

Financial Instruments (Unaudited) As at
  September 30, 2012 December 31, 2011
  Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
Waneta Partnership promissory note 46 52 45 49
Long-term debt, including current portion 5,937 7,476 5,788 7,172

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

The financial instruments table above excludes the long-term other asset associated with the Corporation''s expropriated investment in Belize Electricity. The fair value of the Corporation''s expropriated investment in Belize Electricity determined under the GOB''s valuation is significantly lower than the fair value determined under the Corporation''s independent valuation of the utility. Due to uncertainty in the ultimate amount and ability of the GOB to pay appropriate fair value compensation owing to Fortis for the expropriation of Belize Electricity, the Corporation has recorded the long-term other asset at the carrying value of the Corporation''s previous investment in Belize Electricity, including foreign exchange impacts, which totalled approximately $103 million as at September 30, 2012.

Risk Management: The Corporation''s earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above-noted exposure through the use of US dollar borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange loss or gain on the translation of the Corporation''s foreign subsidiaries'' earnings, which are denominated in US dollars. The reporting currency of Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy and Belize Electric Company Limited ("BECOL") is the US dollar. Belize Electricity''s financial results were denominated in Belizean dollars, which are pegged to the US dollar. 

As at September 30, 2012, the Corporation''s corporately issued US$557 million (December 31, 2011 - US$550 million) long-term debt had been designated as an effective hedge of the Corporation''s foreign net investments. As at September 30, 2012, the Corporation had approximately US$19 million (December 31, 2011 - US$6 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation''s corporately issued US dollar borrowings designated as effective hedges are recorded in other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded in other comprehensive income. 

Effective June 20, 2011, the Corporation''s asset associated with its expropriated investment in Belize Electricity does not qualify for hedge accounting as Belize Electricity is no longer a foreign subsidiary of Fortis. As a result, during 2011, a portion of corporately issued debt that previously hedged the former investment in Belize Electricity was no longer an effective hedge. Effective from June 20, 2011, foreign exchange gains and losses on the translation of the long-term other asset associated with Belize Electricity and the corporately issued US dollar-denominated debt that previously qualified as a hedge of the investment were recognized in earnings. The Corporation has recognized in earnings foreign exchange losses of approximately $3 million and $2.5 million during the three and nine months ended September 30, 2012, respectively. 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, resulting in a net foreign exchange gain of approximately $2.5 million after tax.

From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and fuel and natural gas prices through the use of derivative financial instruments. The Corporation and its subsidiaries do not hold or issue derivative financial instruments for trading purposes. As at September 30, 2012, the Corporation''s derivative contracts consisted of fuel option contracts, natural gas swap and option contracts, and gas purchase contract premiums. The fuel option contracts are held by Caribbean Utilities and the remaining derivative instruments are held by the FortisBC Energy companies.

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

Derivative Financial Instruments (Unaudited) As at  
 
 
 
(Liability) Asset
 
 
 
Maturity
 
 
 
 
 
 
Number of
Contracts
 
 
 
Volume (1)
September 30,
2012
Carrying
Value
(2)
($ millions)
 
 
 
 
December 31,
2011
Carrying
Value (2)
($ millions)
 
 
 
 
Foreign exchange forward contract 2012 (3)   - - -   -  
Fuel option contracts 2013 (4)   4 7 -   (1 )
Natural gas derivatives:                
  Gas swaps and options 2014   99 36 (60 ) (135 )
  Gas purchase contract premiums 2014   80 112 1   -  
(1) The volume for fuel option contracts is reported in millions of imperial gallons and for natural gas derivatives is reported in PJ.
   
(2) Carrying value is estimated fair value. The (liability) asset represents the gross derivatives balance.
   
(3) The foreign exchange forward contract held by FEI expired in April 2012. The carrying value of the contract was less than $1 million as at December 31, 2011.
   
(4) The carrying value of the fuel option contracts was less than $1 million as at September 30, 2012.

The fuel option contracts are used by Caribbean Utilities to reduce the impact of volatility in fuel prices on customer rates, as approved by the regulator under the Company''s Fuel Price Volatility Management Program. In October 2012 Caribbean Utilities executed additional fuel option contracts covering the period from November 1, 2012 to October 31, 2013. With the execution of these new contracts, approximately 70% of the Company''s annual diesel fuel requirements are under fuel hedging arrangements.

The natural gas derivatives held by the FortisBC Energy companies are used to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts at the FortisBC Energy companies have floating, rather than fixed, prices. The price risk management strategy of the FortisBC Energy companies aims to improve the likelihood that natural gas prices remain competitive, to mitigate gas price volatility on customer rates and to reduce the risk of regional price discrepancies. As directed by the BCUC, FEI and FEVI suspended their commodity hedging activities in 2011, which has continued into 2012, with the exception of certain limited swaps as permitted by the BCUC. The existing hedging contracts will continue in effect through to their maturity and the FortisBC Energy companies'' ability to fully recover the commodity cost of gas in customer rates remains unchanged. 

The changes in the fair values of the fuel option contracts and natural gas derivatives are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. The fair values of the derivative financial instruments were recorded in accounts payable and other current liabilities as at September 30, 2012 and as at December 31, 2011. 

The fair value of the fuel option contracts reflects only the value of the heating oil derivative and not the offsetting change in the value of the underlying future purchases of heating oil and is calculated using published market prices for heating oil. The fair value of the natural gas derivatives is calculated using the present value of cash flows based on market prices and forward curves for the commodity cost of natural gas. The fair values of the fuel option contracts and natural gas derivatives were estimates of the amounts that the utilities would have to receive or pay to terminate the outstanding contracts as at the balance sheet dates. 

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

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $68 million, as at September 30, 2012, the Corporation had no off-balance sheet arrangements, such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities, that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. 

BUSINESS RISK MANAGEMENT

There were no changes in the Corporation''s significant business risks year-to-date 2012 from those disclosed in the 2011 Annual MD&A, except for those described below.

Regulatory Risk: In April 2012 regulatory decisions were received for 2012-2013 revenue requirements at the FortisBC Energy companies and for 2012 distribution revenue requirements at FortisAlberta. Similarly, a decision was received in August 2012 for 2012-2013 revenue requirements at FortisBC Electric. The receipt of two-year revenue requirements decisions at the FortisBC utilities helps to provide a level of operating stability for 2012 and 2013.

The recent decision by the AUC to transition distribution utilities in Alberta to PBR for a five-year period commencing in 2013 is a fundamental change in how these utilities are regulated; however, the change provides an opportunity for reduced regulatory burden and the incentive to achieve greater efficiencies and cost savings, which can lead to improved earnings. Under PBR, there is greater risk that FortisAlberta''s earnings will be negatively impacted given the length of the PBR term and the uncertainty of resulting rate adjustments. It is possible that the approved PBR formula could have an unfavourable impact on FortisAlberta if the utility''s actual costs, including costs associated with certain of its required capital projects, exceed the costs permitted by the PBR formula. In the absence of clarification by the AUC, which would broaden the scope of the recovery of these costs, the PBR formula conflicts with FortisAlberta''s legal right to recover prudent costs of providing distribution services and to earn a reasonable ROE. FortisAlberta will be seeking further clarification regarding the application of the PBR formula in proceedings before the AUC and has sought leave to appeal the PBR Decision with the Alberta Court of Appeal.

The regulatory calendar, particularly at the FortisBC utilities, will be busy to the end of 2012 and into 2013 with various filings, interrogatories, inquiries and/or hearings occurring, including that related to the GCOC Proceeding and an expected request for approval of FortisBC Electric''s proposed acquisition of the City of Kelowna''s electrical utility assets. Determinations of cost of capital and final allowed ROEs for 2013 for FortisAlberta and Newfoundland Power also remain outstanding. The results of cost of capital proceedings could materially impact the earnings of the Corporation''s largest utilities.

For further information, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.

Completion of the Acquisition of CH Energy Group: The acquisition of CH Energy Group remains subject to NYSPSC approval. A delay in receiving the approval, and/or conditions imposed, if any, under such approval, may result in the failure to materialize some, or all, of the expected benefits of the acquisition of CH Energy Group or such benefits may not occur within the time periods anticipated by the Corporation. The realization of such benefits may also be impacted by other factors beyond the control of Fortis. 

The agreement and plan of merger may be terminated by the Corporation or CH Energy Group at any time prior to closing in certain circumstances, including if the acquisition has not closed by February 20, 2013 provided, however, that if the only unsatisfied conditions to closing are the obtaining of the regulatory approvals as defined in the agreement and plan of merger, then such date shall be extended to August 20, 2013.

A portion of the acquisition purchase price is expected to be funded by $601 million of escrowed proceeds from the Corporation''s June 2012 Subscription Receipts offering. If conditions precedent to the closing of the transaction are not fulfilled or waived, including receipt of NYSPSC approval, by June 30, 2013, or if the agreement and plan of merger related to the acquisition is terminated prior to such time, the proceeds from the Subscription Receipts offering, plus pro rata interest earned, are required to be returned to the holders of such receipts. As a result, closing of the transaction subsequent to June 30, 2013 could result in the Corporation having to raise alternative capital to finance the acquisition.

For further information refer to the "Significant Items" section of this MD&A.

Expropriation of Shares in Belize Electricity: In 2008 the newly elected GOB changed the electricity rate-setting methodology in Belize to one that did not allow Belize Electricity to recover its reasonable COS and make a reasonable rate of return on its investment as required by law and, thereby, it is the Corporation''s position that the GOB has breached covenants that the GOB made when it sold its shares in Belize Electricity to Fortis in 1999. Relying on the new rate-setting methodology, the Belize Public Utilities Commission denied Belize Electricity a customer rate increase in its June 2008 Final Decision and subsequently amended that decision to decrease customer rates by 15%, notwithstanding the fact that a rate increase was required to adequately finance the utility''s operations. The GOB further compounded Belize Electricity''s financial problems when it increased the utility''s business tax from 1.75% to 6.5%, effective in 2010. Due to an increase in the cost of purchased power, higher business taxes and the above-noted denial of compensatory customer rates, Belize Electricity required short-term financial assistance from the GOB in spring 2011. The GOB chose to prepay some of its electricity bills, as the preferred alternative of financial assistance from the options proposed by Belize Electricity, which allowed the utility to meet its power purchase obligations with the Mexican state-owned Comision Federal de Electricidad ("CFE") to the end of June 2011, after which time Belize Electricity would have been able to source most of its energy power requirements from lower-cost local hydroelectric generating facilities, rather than from the CFE, coinciding with the commencement of the rainy season in Belize.

On June 20, 2011, the GOB enacted in one day the Electricity (Amendment) Act 2011 ("Acquisition Act") and the Electricity (Assumption of Control over Belize Electricity Limited) Order 2011 ("Acquisition Order"), to expropriate the Corporation''s majority ownership investment in Belize Electricity but did not expropriate any of the minority ownership investments, which continue to be held by the Social Security Board of Belize and Belizean residents. The purported public purpose stated in the Acquisition Order, as the basis of the decision to expropriate Belize Electricity, was "to maintain an uninterrupted and reliable supply of electricity to the public". The Corporation''s evidence is that there was no risk of interruption or unreliable electricity supply at the time of expropriation and, while Belize Electricity had financial difficulties in 2011, such difficulties were caused by the GOB and, therefore, the GOB cannot rely on a situation it created to justify expropriating Belize Electricity.

Four days after expropriation of the Corporation''s investment in Belize Electricity, the Belize Court of Appeal delivered its judgment that a similar expropriation of control of Belize Telemedia Limited ("Belize Telemedia"), a public telecommunications provider in Belize, in 2009 was unconstitutional, null and void. Rather than accept and appeal the judgment, the GOB enacted revised expropriation legislation to retain control of Belize Telemedia and contemporaneously proposed a constitutional amendment, the purported effect of which was to: (i) declare the GOB ownership of three specifically identified public utility providers, including Belize Electricity and Belize Telemedia; (ii) deem the expropriation of Belize Electricity and re-expropriation of Belize Telemedia to have been done for a public purpose; and (iii) oust the jurisdiction of the Belize Courts to review the GOB expropriation actions.

On October 21, 2011, Fortis filed a claim ("Claim No. 673 of 2011") in the Belize Supreme Court challenging the GOB''s expropriation of the Corporation''s investment in Belize Electricity pursuant to the Acquisition Act and Acquisition Order. On October 25, 2011, the Belize Constitution (Eighth Amendment) Act 2011 ("Eighth Amendment") was enacted to validate and immunize the GOB''s expropriation of Belize Electricity and Belize Telemedia. As a consequence of the above, Fortis subsequently amended its Claim No. 673 of 2011 to additionally challenge the constitutionality of the Eighth Amendment.

On June 11, 2012, the trial division of the Belize Supreme Court delivered its judgment in the claims of British Caribbean Bank Limited v Attorney General et al ("Claim No. 597 of 2011") and Dean Boyce v Attorney General et al ("Claim No. 646 of 2011") (collectively the "Telemedia Judgment") regarding the purported re-expropriation of Belize Telemedia. The court determined that the re-expropriation of the Claimants'' properties by the GOB in those claims was unconstitutional, null and void. The judge determined most of the Eighth Amendment to be invalid, but found that he could sever those portions of sections 143 and 144 which declare GOB ownership of the named utilities, and that the severance thereby prevented the judge from ordering divestiture of the GOB''s control of Belize Telemedia and hence the judge found himself precluded by the Belize Constitution from granting the Claimants the consequential relief sought.

Hearing of the Corporation''s Claim No. 673 of 2011 occurred on July 2, 2012 before the same judge who delivered the Telemedia Judgment. The judge believed he was bound by his reasons in the Telemedia Judgment and dismissed the Corporation''s Claim No. 673 of 2011 on the grounds that the severed portions of the Eighth Amendment precluded divestiture of the GOB ownership and control of Belize Electricity, notwithstanding the Acquisition Act and Acquisition Order, which are virtually identical to the provisions of the 2009 expropriation of Belize Telemedia, and were found to be invalid by the Belize Court of Appeal. The judge, therefore, denied the relief sought by Fortis.

On July 5, 2012, Fortis filed its appeal of the above-noted July 2, 2012 trial judgment to the Belize Court of Appeal. The Belize Court of Appeal allowed an application for consolidation of the Corporation''s appeal with the appeal and cross-appeal of the Telemedia Judgment, and directed that the appeals be heard on an expedited basis commencing October 8, 2012. 

In its appeal, Fortis has submitted that the Acquisition Act violates the Belize Constitution and should be struck down as: (i) the Acquisition Act does not prescribe the principles and manner in which reasonable compensation is to be determined in a reasonable time; (ii) the Acquisition Act does not prescribe the principles and manner in which reasonable compensation is to be given in a reasonable time; (iii) the Acquisition Act does not provide a right of access to the Belize Court for the purpose of enforcing a right to compensation; and (iv) certain sections of the Acquisition Act violate certain sections of the Belize Constitution. Fortis also submitted that the Acquisition Order violates the Corporation''s constitutional rights and should be struck down as: (i) it is not proportionate; (ii) the expropriation of Belize Electricity by the GOB was arbitrary as the GOB did not acquire the minority shareholdings of the Social Security Board or Belizean nationals in Belize Electricity and is, therefore, in violation of the Belize Constitution; and (iii) Fortis was not afforded a right to be heard by the Belize Minister of Public Utilities before its property was compulsorily acquired by the GOB. Fortis also contends that the application of saved portions of sections 143 and 144 of the Eighth Amendment are also invalid and should not have precluded the ordering of consequential relief to Fortis for several reasons, including that fact that such provisions are void as they: (i) deprive the Belize Court of jurisdiction to conduct the constitutionally mandated inquiry to determine a person''s interest or right in property compulsorily acquired, whether such acquisition was for a public purpose, the amount of compensation to which a person is entitled and for enforcement of a person''s right to any such compensation; (ii) are in breach of the principle of equality before the law and the rule of law; and (iii) on their own do not fulfill the intention of the legislature of the Belize Government and are inextricably bound up with the legislation ruled to be unconstitutional in the Telemedia Judgment.

The consolidated appeal hearing occurred from October 8 to October 10, 2012. However, since one of the judges on the panel is the subject of a complaint to the Belize Judicial Council by parties to the Telemedia Judgment, an application for disqualification of that judge was made and subsequently denied by a majority of the appeal panel. Reasons for denial of leave to appeal of the disqualification application was delivered and judgment on the consolidated appeal hearing has been suspended, pending the outcome of the appeal in the Caribbean Court of Justice ("CCJ") relating to the disqualification application. Counsel for the GOB admitted during the consolidated appeal hearing that the Acquisition Act and Acquisition Order were contrary to the laws of Belize as it now stands, on the basis of the Belize Court of Appeal decision regarding the 2009 expropriation of Belize Telemedia, but that the severed provisions of the Eighth Amendment preclude return of majority control over Belize Electricity back to Fortis. A possible outcome of the consolidated appeal could be the return to Fortis of the majority ownership interest in Belize Electricity. Alternatively, in the event that the Belize Court of Appeal decision confirms the trial judgment, Fortis could pursue an appeal of the case to the CCJ, the highest court of appeal available for judicial matters in Belize.

Consequent to the deprivation of control over the operations of Belize Electricity, the Corporation discontinued the consolidation method of accounting for the utility, effective June 20, 2011. The Corporation has classified the book value of the expropriated investment in Belize Electricity as a long-term other asset on the consolidated balance sheet. As at September 30, 2012, the long-term other asset, including foreign exchange impacts, totalled $103 million (December 31, 2011 - $106 million; September 30, 2011 - $103 million). Fortis commissioned an independent valuation of its expropriated investment in Belize Electricity and submitted its claim for compensation to the GOB in November 2011. The book value of the long-term other asset is below fair value as at the date of expropriation as determined under the Corporation''s valuation. The GOB also commissioned a valuation of Belize Electricity and communicated the results of such valuation in its response to the Corporation''s claim for compensation. The fair value of Belize Electricity determined under the GOB''s valuation is significantly lower than both the fair value determined under the Corporation''s valuation and the book value of the long-term other asset. While Fortis and representatives and third-party consultants of the GOB have held discussions in 2012 on differences in assumptions used in the valuations, there have been no discussions on any compensation settlement amount.

Fortis believes it has a strong, well-positioned case before the Belize Courts and will continue to vigorously litigate the legality of the expropriation. There exists, however, a reasonable possibility that the outcome of the above-noted litigation may be unfavourable to the Corporation and the amount of compensation to be paid to Fortis could be lower than the book value of its expropriated investment in Belize Electricity. Based on presently available information, the outcome of the above is not determinable at this time. As such, the long-term other asset is not deemed impaired. Fortis will continue to assess for impairment each reporting period based on the outcomes of court proceedings and/or compensation settlement negotiations, if any. As well as continuing its legal actions, Fortis is also pursuing alternative options for obtaining fair compensation. 

Fortis continues to control and consolidate the financial statements of BECOL, the Corporation''s indirect wholly owned non-regulated hydroelectric generating subsidiary in Belize. As at October 31, 2012, Belize Electricity owed BECOL US$10 million for overdue energy purchases representing over 40% of BECOL''s annual sales to Belize Electricity. In accordance with long-standing agreements, the GOB guarantees the payment of Belize Electricity''s obligations to BECOL.

Capital Resources and Liquidity Risk - Credit Ratings: 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. Similarly, FortisAlberta''s existing debt credit rating by S&P was confirmed in May 2012 and removed from credit watch with negative implications. There were no other changes in the credit ratings of the Corporation''s utilities year-to-date 2012.

Power Supply and Capacity Purchase Contracts: 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.

Defined Benefit Pension Plan Assets: As at September 30, 2012, the fair value of the Corporation''s consolidated defined benefit pension plan assets was $850 million, up $65 million or 8.3%, from $785 million as at December 31, 2011.

Labour Relations: The collective agreement between FortisBC Electric and the Canadian Office and Professional Employees Union ("COPE"), Local 378, expired on January 31, 2011. A new collective agreement expiring in March 2014 was reached with regard to certain customer service employees who were previously covered under the expired contract. A tentative agreement has been reached with regard to the remaining support and technical employees. The tentative agreement expires on December 31, 2013 and is subject to ratification by the affected employees.

The collective agreements between the FortisBC Energy companies and the International Brotherhood of Electrical Workers ("IBEW"), Local 213, expired on March 31, 2011. IBEW, Local 213, represents employees in specified occupations in the areas of T&D. A new four-year collective agreement, expiring in March 2015, was reached in June 2012.

The collective agreements between the FortisBC Energy companies and COPE, Local 378, expired on March 31, 2012. COPE, Local 378, represents employees in specified occupations in the areas of administration and operations support. The parties are negotiating the terms of a renewed collective agreement.

The two collective agreements between Newfoundland Power and IBEW, Local 1620, expired on September 30, 2011. One of the two newly negotiated collective agreements was ratified during the first quarter of 2012; the other was ratified in May 2012. The agreements are for three-year terms expiring in September 2014.

NEW ACCOUNTING STANDARDS AND POLICIES

Transition to US GAAP: In June 2011 the Ontario Securities Commission issued a decision allowing Fortis and its reporting issuer subsidiaries to prepare their financial statements, effective January 1, 2012 through to December 31, 2014, in accordance with US GAAP without qualifying as U.S. Securities and Exchange Commission ("SEC") Issuers. The Corporation and its reporting issuer subsidiaries, therefore, adopted US GAAP as opposed to International Financial Reporting Standards ("IFRS") on January 1, 2012 with the restatement of comparative reporting periods. Earnings recognized under US GAAP are more closely aligned with earnings recognized under Canadian GAAP, mainly due to the continued recognition of regulatory assets and liabilities under US GAAP. A transition to IFRS would likely have resulted in the derecognition of some, or perhaps all, of the Corporation''s regulatory assets and liabilities and caused significant volatility in the Corporation''s consolidated earnings. On March 16, 2012, Fortis voluntarily prepared and filed audited consolidated US GAAP financial statements for the year ended December 31, 2011 with 2010 comparatives on SEDAR. Also included in the voluntary filing were: (i) a detailed reconciliation between the Corporation''s audited consolidated Canadian GAAP and audited consolidated US GAAP financial statements for fiscal 2011, including 2010 comparatives; and (ii) a detailed reconciliation between the Corporation''s 2011 interim unaudited consolidated Canadian GAAP and 2011 interim unaudited consolidated US GAAP financial statements.

New Accounting Policies: Effective January 1, 2012, the FortisBC Energy companies prospectively adopted the policy of accruing for non-ARO removal costs in depreciation expense, as requested in their 2012-2013 RRA and subsequently approved by the regulator in its April 2012 decision. The accrual of estimated non-ARO removal costs is included in depreciation expense and the provision balance is recognized as a long-term regulatory liability. Actual non-ARO removal costs, net of salvage proceeds, are recorded against the regulatory liability when incurred. Non-ARO removal costs are direct costs incurred by the FortisBC Energy companies in taking assets out of service, whether through actual removal of the assets or through disconnection of the assets from the transmission or distribution system. Prior to 2012 estimated non-ARO removal costs, net of salvage proceeds, were recognized in operating expenses with variances between actual non-ARO removal costs and those forecasted for rate-setting purposes recorded in a regulatory deferral account for future recovery from, or refund to, customers in rates commencing in 2012. For the three and nine months ended September 30, 2012, non-ARO removal costs of $5 million and $15 million, respectively, were accrued as a part of depreciation expense. For the three and nine months ended September 30, 2011, non-ARO removal costs of approximately $4 million and $12 million, respectively, were recognized in operating expenses.

Prior to 2012 variances from forecast, adjusted for certain revenue and cost variances which flowed through to customers, for rate-setting purposes were shared equally between customers and FortisBC Electric. As applied for in FortisBC Electric''s 2012-2013 RRA and approved by the BCUC, prospectively from January 1, 2012 the above-noted sharing of positive or negative variances is no longer in effect. Beginning in 2012, variances between actual electricity revenue and purchased power costs and those forecasted in determining customer electricity rates are subject to full deferral account treatment, to be recovered from, or refunded to, customers in future rates and, therefore, do not impact net earnings in 2012. Effective January 1, 2012, however, the flow through treatment for finance charges, as was applied for in FortisBC Electric''s 2012-2013 RRA, was denied by the regulator pursuant to its revenue requirements decision. As a result, a retroactive adjustment was recorded in the third quarter of 2012 to eliminate the flow through treatment. Variances between actual finance charges from those forecasted in determining customer electricity rates, therefore, have an impact on net earnings in 2012.

Effective January 1, 2012, as approved by the regulator, the FortisBC Energy companies are deferring variances between actual depreciation expense and that forecasted in determining customer gas rates.

Effective January 1, 2012, as approved by the regulator, FortisAlberta is no longer permitted to defer transmission volume variances associated with its AESO charges deferral account. For the three and nine months ended September 30, 2012, FortisAlberta recognized approximately $3.5 million and $6.5 million, respectively, of net transmission revenue as a result of this change.

New US GAAP Accounting Pronouncements: The new US GAAP accounting pronouncements that are applicable to, and were adopted by, Fortis effective January 1, 2012 are described as follows:

Presentation of Comprehensive Income

The Corporation adopted the amendments to Accounting Standards Codification ("ASC") Topic 220, Comprehensive Income. The amended standard requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. Fortis continues to report the components of comprehensive income in a separate but consecutive statement.

Testing Goodwill for Impairment

The Corporation adopted the amendments to ASC Topic 350, Goodwill. The amended standard allows entities testing goodwill for impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. If the qualitative factors indicate that the fair value of the reporting unit is more likely than not (i.e., greater than a 50% chance) to be greater than the carrying value, then the two-step impairment test, including the quantification of the fair value of the reporting unit, would not be required. In adopting the amendments, Fortis will perform a qualitative assessment before calculating the fair value of its reporting units when it performs its annual impairment test as of October 1.

Fair Value Measurement

The Corporation adopted the amendments to ASC Topic 820, Fair Value Measurements and Disclosures. The amended standard improves comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with US GAAP. The amendment does not change what items are measured at fair value but instead makes various changes to the guidance pertaining to how fair value is measured. The above-noted changes did not materially impact the Corporation''s interim unaudited consolidated financial statements for the three and nine months ended September 30, 2012.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Corporation''s interim unaudited consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation''s utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. During the second quarter of 2012, the FortisBC Energy companies and FortisAlberta received revenue requirements decisions, effective January 1, 2012, the cumulative impacts of which, where such impacts were different from those estimated, were recorded in the second quarter of 2012. Similarly, FortisBC Electric recorded the cumulative impacts of its revenue requirements decision, effective January 1, 2012, in the third quarter of 2012 when the decision was received. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period they become known. 

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation''s critical accounting estimates year-to-date 2012 from those disclosed in the 2011 Annual MD&A except for that related to capital asset depreciation. Changes in regulator-approved depreciation rates at FortisAlberta and FortisBC Electric, in conjunction with approved depreciation studies and revenue requirements decisions received in 2012, have impacted consolidated depreciation expense. The composite depreciation rate for utility capital assets at FortisAlberta decreased to 4.0% for 2012 from 4.1% for 2011. FortisBC Electric''s composite depreciation rate for utility capital assets decreased to 3.1% for 2012 from 3.2% for 2011. As required by the BCUC, effective January 1, 2012, depreciation rates at the FortisBC Energy companies now include an amount allowed for regulatory purposes to accrue for estimated non-ARO removal costs, net of salvage proceeds. For further information, refer to the "New Accounting Standards and Policies" section of this MD&A. The impact of the above-noted changes in depreciation rates on depreciation expense has been reflected in the utilities'' approved revenue requirements and resulting customer rates.

Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with ordinary course business operations. Management believes that the amount of liability, if any, from these actions would not have a material effect on the Corporation''s consolidated financial position or results of operations.

The following describes the nature of the Corporation''s contingent liabilities.

Fortis

In May 2012 CH Energy Group and Fortis entered into a proposed settlement agreement with counsel to plaintiff shareholders pertaining to several complaints, which named Fortis and other defendants, which were filed in, or transferred to, the Supreme Court of the State of New York, County of New York, relating to the proposed acquisition of CH Energy Group by Fortis. The complaints generally alleged that the directors of CH Energy Group breached their fiduciary duties in connection with the proposed acquisition and that CH Energy Group, Fortis, FortisUS Inc. and Cascade Acquisition Sub Inc. aided and abetted that breach. The settlement agreement is subject to court approval.

FHI

During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of Assessment from Canada Revenue Agency for additional taxes related to the taxation years 1999 through 2003. The exposure has been fully provided for in the consolidated financial statements. FHI is appealing these assessments.

In 2009 FHI was named, along with other defendants, in an action related to damages to property and chattels, including contamination to sewer lines and costs associated with remediation, related to the rupture in July 2007 of an oil pipeline owned and operated by Kinder Morgan, Inc. FHI filed a statement of defence. During the second quarter of 2010, FHI was added as a third party in all of the related actions. FHI was advised that all matters have now been settled and the action has been dismissed by consent.

FortisBC Electric

The Government of British Columbia has alleged breaches of the Forest Practices Code and negligence relating to a forest fire near Vaseux Lake and has filed and served a writ and statement of claim against FortisBC Electric dated August 2, 2005. The Government of British Columbia has now disclosed that its claim includes approximately $13.5 million in damages but that it has not fully quantified its damages. In addition, private landowners have filed separate writs and statements of claim dated August 19, 2005 and August 22, 2005 for undisclosed amounts in relation to the same matter. FortisBC Electric and its insurers are defending the claims. A date for mediation of this matter has been set for December 2012. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

The Government of British Columbia filed a claim in the British Columbia Supreme Court in June 2012 claiming on its behalf, and on behalf of approximately 17 homeowners, damages suffered as a result of a landslide caused by a dam failure in Oliver, British Columbia in 2010. The Government of British Columbia alleges in its claim that the dam failure was caused by the defendants'', which includes FortisBC Electric, use of a road on top of the dam. The Government of British Columbia estimates its damages and the damages of the homeowners, on whose behalf it is claiming, to be approximately $12 million. FortisBC Electric has not been served, however, has retained counsel and has contacted its insurers. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

SUMMARY OF QUARTERLY RESULTS

The following table sets forth unaudited quarterly information for each of the eight quarters ended December 31, 2010 through September 30, 2012. The quarterly information has been obtained from the Corporation''s interim unaudited consolidated financial statements, which have been prepared in accordance with US GAAP. The timing of the recognition of certain assets, liabilities, revenue and expenses, as a result of regulation, may differ from that otherwise expected using US GAAP for non-regulated entities. The nature of regulation is further disclosed in Notes 2, 3 and 7 to the Corporation''s 2011 annual audited consolidated financial statements prepared in accordance with US GAAP. The quarterly financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance. 

Summary of Quarterly Results      
(Unaudited)      
  Revenue Net Earnings
Attributable to
Common Equity
Shareholders
Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
September 30, 2012 714 45 0.24 0.24
June 30, 2012 792 62 0.33 0.33
March 31, 2012 1,149 121 0.64 0.62
December 31, 2011 1,034 82 0.44 0.43
September 30, 2011 699 56 0.30 0.30
June 30, 2011 846 57 0.32 0.32
March 31, 2011 1,159 116 0.66 0.64
December 31, 2010 1,032 127 0.73 0.71

A summary of the past eight quarters reflects the Corporation''s continued organic growth, growth from acquisitions, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel and purchased power and the commodity cost of natural gas, which are flowed through to customers without markup. Given the diversified nature of the Fortis subsidiaries, seasonality may vary. Most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters. Earnings for the first, second and third quarters of 2012 were reduced by approximately $4 million, $3 million and $0.5 million, respectively, associated with costs incurred related to the pending acquisition of CH Energy Group. During the second quarter of 2012, the FortisBC Energy companies and FortisAlberta received revenue requirements decisions, effective from January 1, 2012, the cumulative impacts of which, where such impacts were different from those estimated, were recorded in the second quarter of 2012. Similarly, FortisBC Electric recorded the cumulative impacts of its rate decision, effective January 1, 2012, in the third quarter of 2012 when the decision was received. Financial results from the fourth quarter ended December 31, 2011 reflected the acquisition of the Hilton Suites Hotel in October 2011. Earnings for the third quarter ended September 30, 2011 included the $11 million after-tax termination fee paid to Fortis by CVPS. Financial results from June 20, 2011 reflected the discontinuance of the consolidation method of accounting for Belize Electricity due to the expropriation of the utility by the GOB. For further information, refer to the "Significant Items" and "Business Risk Management" sections of this MD&A. 

September 2012/September 2011: Net earnings attributable to common equity shareholders were $45 million, or $0.24 per common share, for the third quarter of 2012 compared to earnings of $56 million, or $0.30 per common share, for the third quarter of 2011. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.

June 2012/June 2011: Net earnings attributable to common equity shareholders were $62 million, or $0.33 per common share, for the second quarter of 2012 compared to earnings of $57 million, or $0.32 per common share, for the second quarter of 2011. The increase in earnings was mainly due to higher contribution from FortisAlberta, increased non-regulated hydroelectric production in Belize, associated with higher rainfall, and higher earnings at Newfoundland Power, partially offset by higher corporate expenses and decreased earnings at the FortisBC Energy companies. Higher contribution from FortisAlberta related to rate base growth, and increased net transmission revenue and reduced depreciation as approved by the regulator, partially offset by a lower allowed ROE. Higher earnings at Newfoundland Power were the result of lower effective income taxes and a higher allowed ROE. The cumulative impact of the increase in the regulator-approved allowed ROE, effective January 1, 2012, was recorded in the second quarter of 2012. The increase in corporate expenses was due to approximately $4 million ($3 million after tax) of costs incurred during the second quarter of 2012 related to the pending acquisition of CH Energy Group and a lower income tax recovery, partially offset by a foreign exchange gain of approximately $2 million recognized in the second quarter of 2012. Decreased earnings at the FortisBC Energy companies mainly related to lower-than-expected customer additions in 2012 and lower capitalized AFUDC, partially offset by higher gas transportation volumes to industrial customers. A 7% increase in the weighted average number of common shares outstanding quarter over quarter, largely associated with the issuance of common equity mid-2011, had the impact of lowering earnings per common share in the second quarter of 2012.

March 2012/March 2011: Net earnings attributable to common equity shareholders were $121 million, or $0.64 per common share, for the first quarter of 2012 compared to earnings of $116 million, or $0.66 per common share, for the first quarter of 2011. The increase in earnings was mainly due to higher contribution from the FortisBC Energy companies, increased non-regulated hydroelectric production in Belize, associated with higher rainfall, and higher earnings at Newfoundland Power and Maritime Electric, mainly the result of increased electricity sales and lower effective corporate income taxes. The increase in earnings was partially offset by the impact of the expiry of the PBR mechanism on December 31, 2011 at FortisBC Electric and the timing of certain operating expenses at the utility in 2012, higher corporate expenses and an approximate $1 million gain on the sale of property at FortisAlberta during the first quarter of 2011. The increase in earnings at the FortisBC Energy companies mainly related to the favourable impact of the difference in the timing of recognition of revenue associated with seasonal gas consumption and certain increased regulator-approved expenses in 2012, rate base growth and higher gas transportation volumes to industrial customers, partially offset by lower-than-expected customer additions in 2012 and lower capitalized AFUDC. The increase in corporate expenses was the result of approximately $4 million ($4 million after tax) of costs incurred during the first quarter of 2012 related to the pending acquisition of CH Energy Group and a $1.5 million foreign exchange loss, partially offset by lower finance charges. An 8% increase in the weighted average number of common shares outstanding quarter over quarter, largely associated with the issuance of common equity mid-2011, had the impact of lowering earnings per common share in the first quarter of 2012.

December 2011/December 2010: Net earnings attributable to common equity shareholders were $82 million, or $0.44 per common share, for the fourth quarter of 2011 compared to earnings of $127 million, or $0.73 per common share, for the fourth quarter of 2010. Excluding the one-time $46 million favourable impact to Newfoundland Power''s earnings in the fourth quarter of 2010 due to the rerecognition of a regulatory asset, as required under US GAAP, to recognize amounts recoverable from customers upon regulatory approval of the adoption the accrual method of accounting for OPEB costs, earnings increased $1 million quarter over quarter. The increase in earnings was led by the FortisBC Energy companies, driven by rate base growth, lower-than-expected corporate income taxes and finance charges in 2011, and higher gas transportation volumes to industrial customers, partially offset by both lower customer additions and capitalized AFUDC in 2011. The above-noted increase in earnings was partially offset by a decrease in earnings at Newfoundland Power, Other Canadian Regulated Electric Utilities, Fortis Turks and Caicos and Fortis Properties. The decrease in earnings at Newfoundland Power reflected a lower allowed ROE and higher operating expenses, partially offset by reduced energy supply costs in the fourth quarter of 2011. Lower earnings at Other Canadian Regulated Electric Utilities were due to decreased electricity sales and higher operating expenses. Lower earnings at Fortis Turks and Caicos were due to higher depreciation and operating expenses, partially offset by reduced energy supply costs in 2011 reflecting the use of new, more fuel-efficient generating units. Earnings at Fortis Properties during the fourth quarter of 2010 reflected lower corporate income tax rates, which reduced deferred taxes in that period. An 8% increase in the weighted average number of common shares outstanding quarter over quarter, largely associated with the issuance of common equity in mid-2011, had the impact of lowering earnings per common share in the fourth quarter of 2011.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

In an effort to optimize customer service operations within the FortisBC Energy companies, a Customer Care Enhancement Project was implemented at the beginning of January 2012 with new in-house customer contact and billing centres replacing the services of an external third-party service provider. This represents a material change in the Corporation''s internal controls over financial reporting surrounding the revenue, receivable and receipts cycle. Throughout the related systems design and implementation, management had considered the control risks associated with the systems changes and had performed procedures to obtain reasonable assurance on the design of all new and significantly modified internal controls over financial reporting as a result of the project. It has been concluded that year-to-date 2012, other than the above-noted change, there were no changes in the Corporation''s internal controls over financial reporting that have materially, or are reasonably likely to materially affect, the Corporation''s internal controls over financial reporting.

OUTLOOK

The Corporation''s significant capital expenditure program, which is expected to be approximately $5.5 billion over the five-year period 2012 through 2016, should support continuing growth in earnings and dividends. CH Energy Group is expected to add approximately $0.5 billion to the Corporation''s consolidated capital expenditure program from 2013 through 2016. 

Fortis is 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.

Fortis remains disciplined and patient in its pursuit of additional electric and gas utility acquisitions in the United States and Canada that will add value for Fortis shareholders. Fortis will also pursue growth in its non-regulated businesses in support of its regulated utility growth strategy. 

SUBSEQUENT EVENT

In October 2012 FortisAlberta issued 40-year $125 million 3.98% senior unsecured debentures, the proceeds of which are being used to repay borrowings under the Company''s credit facility, fund future capital expenditures, and for general corporate purposes.

OUTSTANDING SHARE DATA

As at October 31, 2012, the Corporation had issued and outstanding approximately 190.7 million common shares; 5.0 million First Preference Shares, Series C; 8.0 million First Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 10.0 million First Preference Shares, Series H; and 18.5 million Subscription Receipts. Only the common shares of the Corporation have regular voting rights. The Corporation''s First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether or not such dividends have been declared.

The number of common shares of Fortis that would be issued if all outstanding stock options, First Preference Shares, Series C and E, and Subscription Receipts were converted as at October 31, 2012 is as follows.

Conversion of Securities into Common Shares (Unaudited)
As at October 31, 2012 Number of
  Common Shares
Security (millions)
Stock Options 5.1
First Preference Shares, Series C 3.9
First Preference Shares, Series E 6.2
Subscription Receipts 18.5
Total 33.7

Additional information, including the Fortis 2011 Annual Information Form, Management Information Circular and Annual Report, is available on SEDAR at www.sedar.com and on the Corporation''s website at www.fortisinc.com.

FORTIS INC.
 
Interim Consolidated Financial Statements
For the three and nine months ended September 30, 2012 and 2011
(Unaudited)

Prepared in accordance with accounting principles generally accepted in the United States

 
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
 
 September 30, December 31, 
 2012 2011 
     (Note 22) 
ASSETS      
       
Current assets      
Cash and cash equivalents$147 $87 
Accounts receivable 410  638 
Prepaid expenses 33  19 
Inventories 157  134 
Regulatory assets (Note 3) 98  219 
Deferred income taxes 24  24 
  869  1,121 
       
Other assets 209  184 
Regulatory assets (Note 3) 1,493  1,400 
Deferred income taxes 1  8 
Utility capital assets 9,374  8,968 
Income producing properties 604  594 
Intangible assets 322  325 
Goodwill (Note 12) 1,566  1,565 
       
 $14,438 $14,165 
       
LIABILITIES AND SHAREHOLDERS'' EQUITY      
       
Current liabilities      
Short-term borrowings (Note 17)$97 $159 
Accounts payable and other current liabilities 855  990 
Regulatory liabilities (Note 3) 75  43 
Current installments of long-term debt 90  103 
Current installments of capital lease and finance obligations 7  7 
Deferred income taxes 2  5 
  1,126  1,307 
       
Other liabilities 577  573 
Regulatory liabilities (Note 3) 588  555 
Deferred income taxes 733  673 
Long-term debt 5,847  5,685 
Capital lease and finance obligations 434  429 
  9,305  9,222 
       
Shareholders'' equity      
Common shares (a)(Note 4) 3,092  3,036 
Preference shares 912  912 
Additional paid-in capital 15  14 
Accumulated other comprehensive loss (97) (95)
Retained earnings 923  868 
  4,845  4,735 
Non-controlling interests (Note 5) 288  208 
  5,133  4,943 
       
 $14,438 $14,165 
  
(a) no par value: unlimited authorized shares; 190.7 million and 188.8 million issued and outstanding as at
 September 30, 2012 and December 31, 2011, respectively
  
 Commitments and Contingent Liabilities (Notes 18 and 20, respectively)
 See accompanying Notes to Interim Consolidated Financial Statements
 
 
 
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars, except per share amounts)
 
 Quarter EndedNine Months Ended
 201220112012 2011
          
Revenue$714$699$2,655 $2,704
          
Expenses         
 Energy supply costs 235 246 1,092  1,207
 Operating 203 200 621  619
 Depreciation and amortization 118 104 351  309
  556 550 2,064  2,135
          
Operating income 158 149 591  569
          
Other income (expenses), net (Note 8) 1 22 (2) 34
Finance charges (Note 9) 93 89 276  274
          
Earnings before income taxes 66 82 313  329
          
Income taxes (Note 10) 7 12 44  59
          
Net earnings$59$70$269 $270
          
Net earnings attributable to:         
 Non-controlling interests$3$3$7 $7
 Preference equity shareholders 11 11 34  34
 Common equity shareholders 45 56 228  229
 $59$70$269 $270
          
Earnings per common share (Note 11)         
 Basic$0.24$0.30$1.20 $1.28
 Diluted$0.24$0.30$1.19 $1.27
          
 
See accompanying Notes to Interim Consolidated Financial Statements
 
 
 
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
 
 Quarter EndedNine Months Ended
 2012 20112012 2011
           
Net earnings$59 $70$269 $270
           
Other comprehensive (loss) income          
Unrealized foreign currency translation (losses) gains, net of hedging activities and tax (3) 8 (3) 5
Reclassification of unrealized foreign currency translation losses, net of hedging activities and tax, related to Belize Electricity -  - -  17
Reclassification to earnings of net losses on discontinued cash flow hedges, net of tax -  1 -  1
Unrealized employee future benefits gains, net of tax -  - 1  -
  (3) 9 (2) 23
           
Comprehensive income$56 $79$267 $293
           
Comprehensive income attributable to:          
 Non-controlling interests$3 $3$7 $7
 Preference equity shareholders 11  11 34  34
 Common equity shareholders 42  65 226  252
 $56 $79$267 $293
 
See accompanying Notes to Interim Consolidated Financial Statements
 
 
 
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
 
 Quarter Ended Nine Months Ended 
 2012 2011 2012 2011 
             
Operating activities            
Net earnings$59 $70 $269 $270 
Adjustments to reconcile net earnings to net cash provided by operating activities:            
 Depreciation - utility capital assets and income producing properties 105  95  316  284 
 Amortization - intangible assets 12  9  33  27 
 Amortization - other 1  -  2  (2)
 Deferred income taxes -  4  8  3 
 Accrued employee future benefits 3  4  (4) 13 
 Equity component of allowance for funds used construction (Note 8) (1) (2) (4) (10)
 Other 1  -  (10) 4 
Change in long-term regulatory assets and liabilities (16) (27) (25) (9)
Change in non-cash operating working capital (Note 14) 57  (2) 219  104 
  221  151  804  684 
             
Investing activities            
Change in other assets and other liabilities (2) 3  2  1 
Capital expenditures - utility capital assets (264) (259) (737) (745)
Capital expenditures - income producing properties (9) (11) (24) (20)
Capital expenditures - intangible assets (10) (16) (33) (39)
Contributions in aid of construction 15  18  45  49 
Proceeds on sale of utility capital assets and income producing properties -  -  -  6 
Business acquisitions, net of cash acquired (Note 12) (7) -  (14) - 
  (277) (265) (761) (748)
             
Financing activities            
Change in short-term borrowings 17  86  (61) (114)
Proceeds from long-term debt, net of issue costs -  9  -  39 
Repayments of long-term debt and capital lease and finance obligations -  (3) (57) (27)
Net (repayments) borrowings under committed credit facilities (9) (178) 221  (105)
Advances from non-controlling interests 14  20  83  77 
Subscription Receipts issue costs (Note 4) (1) -  (13) - 
Issue of common shares, net of costs and dividends reinvested 6  40  12  341 
Dividends            
 Common shares, net of dividends reinvested (42) (38) (128) (109)
 Preference shares (11) (11) (34) (34)
 Subsidiary dividends paid to non-controlling interests (2) (2) (6) (6)
  (28) (77) 17  62 
             
Effect of exchange rate changes on cash and cash equivalents -  1  -  1 
             
Change in cash and cash equivalents (84) (190) 60  (1)
             
Cash and cash equivalents, beginning of period 231  296  87  107 
             
Cash and cash equivalents, end of period$147 $106 $147 $106 
 
Supplementary Information to Consolidated Statements of Cash Flows (Note 14)
See accompanying Notes to Interim Consolidated Financial Statements
 
 
 
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
 
 Common
Shares
Prefe-
rence

Shares
Addi-
tional
Paid-in

Capital
 Accu-
mulated
Other
Compre-
hensive

Loss
 Retained
Earnings
 Non-Control-
ling

Interests
 Total
Equity
 
 (Note 4)                 
                    
As at December 31, 2011$3,036$912$14 $(95)$868 $208 $4,943 
                    
Net earnings - - -  -  262  7  269 
                    
Other comprehensive income - - -  (2) -  -  (2)
Common share issues 56 - (1) -  -  -  55 
Stock-based compensation - - 2  -  -  -  2 
Advances from non-controlling interests - - -  -  -  83  83 
Foreign currency translation impacts - - -  -  -  (4) (4)
Subsidiary dividends paid to non-controlling interests - - -  -  -  (6) (6)
Dividends declared on common shares ($0.90 per share) - - -  -  (173) -  (173)
Dividends declared on preference shares - - -  -  (34) -  (34)
                    
As at September 30, 2012$3,092$912$15 $(97)$923 $288 $5,133 
                    
As at December 31, 2010$2,575$912$12 $(108)$774 $162 $4,327 
                    
Net earnings - - -  -  263  7  270 
                    
Other comprehensive income - - -  23  -  -  23 
Common share issues 395 - (2) -  -  -  393 
Stock-based compensation - - 3  -  -  -  3 
Advances from non-controlling interests - - -  -  -  77  77 
Foreign currency translation impacts - - -  -  -  3  3 
Subsidiary dividends paid to non-controlling interests - - -  -  -  (6) (6)
Expropriation of Belize Electricity (Notes 16, 17 and 19) - - -  -  -  (38) (38)
Dividends declared on common shares ($0.87 per share) - - -  -  (159) -  (159)
Dividends declared on preference shares - - -  -  (34) -  (34)
                    
As at September 30, 2011$2,970$912$13 $(85)$844 $205 $4,859 
 
See accompanying Notes to Interim Consolidated Financial Statements
 
 
 
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2012 and 2011 (unless otherwise stated)
(Unaudited)
 

1. DESCRIPTION OF THE BUSINESS

Nature of Operations

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

The following outlines each of the Corporation''s reportable segments and is consistent with the basis of segmentation as disclosed in the Corporation''s 2011 annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States ("US GAAP"). 

REGULATED UTILITIES

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

  1. Regulated Gas Utilities - Canadian: Includes the FortisBC Energy companies, which is comprised of FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc.
  1. Regulated Electric Utilities - Canadian: Includes FortisAlberta; FortisBC Electric; Newfoundland Power; and Other Canadian Electric Utilities, which includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power Inc., Cornwall Street Railway, Light and Power Company, Limited and Algoma Power Inc. 
  1. Regulated Electric Utilities - Caribbean: Includes Caribbean Utilities, in which Fortis holds an approximate 60% controlling ownership interest; three small wholly owned utilities in the Turks and Caicos Islands, which include Turks and Caicos Utilities Limited ("TCU"), 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 ("GOB") 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 (Notes 16, 17 and 19). 

NON-REGULATED - FORTIS GENERATION

Fortis Generation includes the financial results of non-regulated generation assets in Belize, Ontario, central Newfoundland, British Columbia and Upstate New York. 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 megawatts ("MW"), was transferred from Fortis Properties to a limited partnership directly held by Fortis.

NON-REGULATED - FORTIS PROPERTIES

Fortis Properties owns and operates 23 hotels, collectively representing more than 4,400 rooms, in eight Canadian provinces, including the acquisition of the StationPark All Suite Hotel in London, Ontario, which was acquired on October 1, 2012. Fortis Properties also owns and operates approximately 2.7 million square feet of commercial office and retail space primarily in Atlantic Canada.

CORPORATE AND OTHER

The Corporate and Other segment includes Fortis net corporate expenses and the net expenses of non-regulated FortisBC Holdings Inc. ("FHI") corporate-related activities. Also included in the Corporate and Other segment are the financial results of FHI''s 30% ownership interest in CustomerWorks Limited Partnership ("CWLP") and of FHI''s wholly owned subsidiary FortisBC Alternative Energy Services Inc. ("FAES"). CWLP provides billing and customer care services to utilities, municipalities and certain energy companies. The contracts between CWLP and the FortisBC Energy companies ended on December 31, 2011. FAES provides alternative energy solutions.

PENDING ACQUISITION

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 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 (Notes 8 and 18).

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These interim consolidated financial statements have been prepared in accordance with US GAAP for interim financial statements. As a result, these interim consolidated financial statements do not include all of the information and disclosures required in the annual consolidated financial statements and should be read in conjunction with the Corporation''s 2011 annual audited consolidated financial statements prepared in accordance with US GAAP and voluntarily filed on the System for Electronic Document Analysis and Retrieval by Fortis on March 16, 2012 (the "Corporation''s 2011 US GAAP annual audited consolidated financial statements"). In management''s opinion, the interim consolidated financial statements include all adjustments that are of a recurring nature and necessary to present fairly the financial position of the Corporation.

Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Because of natural gas consumption patterns, most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters. Given the diversified group of companies, seasonality may vary.

The preparation of financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation''s utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. During the second quarter of 2012, the FortisBC Energy companies and FortisAlberta received revenue requirements decisions, effective January 1, 2012, the cumulative impacts of which, where such impacts were different from those estimated, were recorded in the second quarter of 2012. Similarly, FortisBC Electric recorded the cumulative impacts of its revenue requirements decision, effective January 1, 2012, in the third quarter of 2012 when the decision was received. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period in which they become known. 

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation''s critical accounting estimates during the three and nine months ended September 30, 2012, except as described further with respect to capital asset depreciation.

An evaluation of subsequent events through to October 31, 2012, the date these interim consolidated financial statements were approved by the Audit Committee of the Board of Directors, was completed to determine whether circumstances warranted recognition and disclosure of events or transactions in the interim consolidated financial statements as at September 30, 2012 (Note 21).

All amounts are presented in Canadian dollars unless otherwise stated.

These interim consolidated financial statements include the accounts of Fortis and its wholly owned subsidiaries and controlling ownership interests. All significant intercompany balances and transactions have been eliminated on consolidation.

These interim consolidated financial statements have been prepared following the same accounting policies and methods as those used in preparing the Corporation''s 2011 US GAAP annual audited consolidated financial statements, except as described below. 

Presentation of Comprehensive Income

Effective January 1, 2012, the Corporation adopted the amendments to Accounting Standards Codification ("ASC") Topic 220, Comprehensive Income. The amended standard requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. Fortis continues to report the components of comprehensive income in a separate but consecutive statement.

Testing Goodwill for Impairment

Effective January 1, 2012, the Corporation adopted the amendments to ASC Topic 350, Goodwill. The amended standard allows entities testing goodwill for impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. If the qualitative factors indicate that the fair value of the reporting unit is more likely than not (i.e., greater than a 50% chance) to be greater than the carrying value, then the two-step impairment test, including the quantification of the fair value of the reporting unit, would not be required. In adopting the amendments, Fortis will perform a qualitative assessment before calculating the fair value of its reporting units when it performs its annual impairment test as of October 1.

Fair Value Measurement

Effective January 1, 2012, the Corporation adopted the amendments to ASC Topic 820, Fair Value Measurements and Disclosures. The amended standard improves comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with US GAAP. The amendment does not change what items are measured at fair value but instead makes various changes to the guidance pertaining to how fair value is measured. The above-noted changes did not materially impact the Corporation''s interim consolidated financial statements for the three and nine months ended September 30, 2012.

New Accounting Policies

Effective January 1, 2012, the FortisBC Energy companies prospectively adopted the policy of accruing for non-asset retirement obligation ("non-ARO") removal costs in depreciation expense, as requested in their 2012-2013 Revenue Requirements Application ("RRA") and subsequently approved by the regulator in its April 2012 decision. The accrual of estimated non-ARO removal costs is included in depreciation expense and the provision balance is recognized as a long-term regulatory liability. Actual non-ARO removal costs, net of salvage proceeds, are recorded against the regulatory liability when incurred. Non-ARO removal costs are direct costs incurred by the FortisBC Energy companies in taking assets out of service, whether through actual removal of the assets or through disconnection of the assets from the transmission or distribution system. Prior to 2012 estimated non-ARO removal costs, net of salvage proceeds, were recognized in operating expenses with variances between actual non-ARO removal costs and those forecasted for rate-setting purposes recorded in a regulatory deferral account for future recovery from, or refund to, customers in rates commencing in 2012. For the three and nine months ended September 30, 2012, non-ARO removal costs of approximately $5 million and $15 million, respectively, were accrued as part of depreciation expense. For the three and nine months ended September 30, 2011, non-ARO removal costs of approximately $4 million and $12 million, respectively, were recognized in operating expenses.

Prior to 2012 variances from forecast, adjusted for certain revenue and cost variances which flowed through to customers, for rate-setting purposes were shared equally between customers and FortisBC Electric. As applied for in FortisBC Electric''s 2012-2013 RRA and approved by the regulator, prospectively from January 1, 2012 the above-noted sharing of positive or negative variances is no longer in effect. Beginning in 2012, variances between actual electricity revenue and purchased power costs and those forecasted in determining customer electricity rates are subject to full deferral account treatment, to be recovered from, or refunded to, customers in future rates and, therefore, do not impact net earnings in 2012. Effective January 1, 2012, however, the flow through treatment for finance charges, as was applied for in FortisBC Electric''s 2012-2013 RRA, was denied by the regulator pursuant to its revenue requirements decision. As a result, a retroactive adjustment was recorded in the third quarter of 2012 to eliminate the flow through treatment. Variances between actual finance charges from those forecasted in determining customer electricity rates, therefore, have an impact on net earnings in 2012.

Effective January 1, 2012, as approved by the regulator, the FortisBC Energy companies are deferring variances between actual depreciation expense and that forecasted in determining customer gas rates.

Effective January 1, 2012, as approved by the regulator, FortisAlberta is no longer permitted to defer transmission volume variances associated with its Alberta Electric System Operator ("AESO") charges deferral account. For the three and nine months ended September 30, 2012, FortisAlberta recognized approximately $3.5 million and $6.5 million, respectively, of net transmission revenue as a result of this change.

Change in Estimates - Capital Asset Depreciation

Changes in regulator-approved depreciation rates at FortisAlberta and FortisBC Electric, in conjunction with approved depreciation studies and revenue requirements decisions received in 2012, have impacted consolidated depreciation expense. The composite depreciation rate for utility capital assets at FortisAlberta decreased to 4.0% for 2012 from 4.1% for 2011. FortisBC Electric''s composite depreciation rate for utility capital assets decreased to 3.1% for 2012 from 3.2% for 2011. As required by the regulator, effective January 1, 2012, depreciation rates at the FortisBC Energy companies now include an amount allowed for regulatory purposes to accrue for estimated non-ARO removal costs, net of salvage proceeds. The impact of the above-noted changes in depreciation rates on depreciation expense has been reflected in the utilities'' approved revenue requirements and resulting customer rates.

3. REGULATORY ASSETS AND LIABILITIES

A summary of the Corporation''s regulatory assets and liabilities is provided below. A detailed description of the nature of the Corporation''s regulatory assets and liabilities is provided in Note 7 to the Corporation''s 2011 US GAAP annual audited consolidated financial statements.

 As at 
 September 30, December 31, 
($ millions)2012 2011 
Regulatory assets    
Deferred income taxes683 630 
Employee future benefits406 428 
Deferred lease costs - FortisBC Electric81 70 
Rate stabilization accounts - electric utilities53 55 
Replacement energy deferral - Point Lepreau (1)47 47 
Deferred energy management costs43 36 
Rate stabilization accounts - FortisBC Energy companies31 105 
Deferred operating overhead costs30 22 
Customer Care Enhancement Project cost deferral25 13 
Deferred net losses on disposal of utility capital assets25 23 
Income taxes recoverable on other post-employment benefit ("OPEB") plans23 22 
Whistler pipeline contribution deferral16 16 
Pension cost variance deferral14 10 
Alternative energy projects cost deferral13 8 
Deferred development costs for capital10 11 
Deferred costs - smart meters8 8 
AESO charges deferral- 44 
Other regulatory assets83 71 
Total regulatory assets1,591 1,619 
Less: current portion(98)(219)
Long-term regulatory assets1,493 1,400 
  
(1)New Brunswick Power Point Lepreau Nuclear Generating Station
   
   
   
 As at 
 September 30, December 31, 
($ millions)2012 2011 
Regulatory liabilities    
Non-ARO removal cost provision374 354 
Rate stabilization accounts - FortisBC Energy companies154 127 
Rate stabilization accounts - electric utilities36 33 
AESO charges deferral33 12 
Deferred income taxes15 9 
Deferred interest8 10 
Performance-based rate-setting incentive liabilities8 7 
Income tax variance deferral6 12 
Southern Crossing Pipeline deferral5 8 
Unrecognized net gains on disposal of utility capital assets- 6 
Other regulatory liabilities24 20 
Total regulatory liabilities663 598 
Less: current portion(75)(43)
Long-term regulatory liabilities588 555 

4. COMMON SHARES

Common shares issued during the period were as follows:
     
 Quarter EndedYear-to-Date
 September 30, 2012September 30, 2012
 Number of Number of 
 SharesAmountSharesAmount
 (in thousands)($ millions)(in thousands)($ millions)
Balance, beginning of period189,9673,071188,8283,036
 Dividend Reinvestment Plan460151,35543
 Consumer Share Purchase Plan8-321
 Employee Share Purchase Plan632632
 Stock Option Plans160438010
Balance, end of period190,6583,092190,6583,092

Effective May 4, 2012, the Corporation''s Board of Directors approved the 2012 Employee Share Purchase Plan ("2012 ESPP"). Under the 2012 ESPP, common shares may be issued from treasury, acquired in the open market or a combination from treasury and the open market, as determined by the Corporation. The first shares issued from treasury under the 2012 ESPP occurred in September 2012.

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 ("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 (Note 18).

5. NON-CONTROLLING INTERESTS

 As at
 September 30,December 31,
($ millions)20122011
Waneta Expansion Limited Partnership ("Waneta Partnership")197128
Caribbean Utilities7273
Mount Hayes Limited Partnership (Note 18)12-
Preference shares of Newfoundland Power77
 288208

6. STOCK-BASED COMPENSATION PLANS

In January 2012 21,417 Deferred Share Units ("DSUs") were granted to the Corporation''s Board of Directors, representing the equity component of the Directors'' annual compensation and, where opted, their annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation. 

In March 2012 44,863 Performance Share Units ("PSUs") were paid out to the President and Chief Executive Officer ("CEO") of the Corporation at $32.40 per PSU, for a total of approximately $1.5 million. The payout was made upon the three-year maturation period in respect of the PSU grant made in March 2009 and the President and CEO satisfying the payment requirements, as determined by the Human Resources Committee of the Board of Directors of Fortis.

In May 2012 62,000 PSUs were granted to the President and CEO of the Corporation. Each PSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation. The maturation period of the May 2012 PSU grant is three years, at which time a cash payment may be made to the President and CEO after evaluation by the Human Resources Committee of the Board of Directors of the achievement of payment requirements.

In May 2012 the 2012 Stock Option Plan ("2012 Plan") was approved at the Annual General Meeting of the Corporation''s shareholders. The 2012 Plan will ultimately replace the 2002 Stock Option Plan ("2002 Plan") and the 2006 Stock Option Plan ("2006 Plan"). The 2002 Plan and 2006 Plan will cease to exist when all outstanding options are exercised or expire in or before 2016 and 2018, respectively. The Corporation has ceased the granting of options under the 2002 Plan and 2006 Plan and all new options granted after 2011 will be made under the 2012 Plan. 

In May 2012 the Corporation granted 789,220 options to purchase common shares under its 2012 Plan at the five-day volume weighted average trading price immediately preceding the date of grant of $34.27. The options vest evenly over a four-year period on each anniversary of the date of grant. The options expire 10 years after the date of grant. The fair value of each option granted was $4.21 per option.

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

Dividend yield (%)3.67
Expected volatility (%)22.2
Risk-free interest rate (%)1.50
Weighted average expected life (years)5.3

For the three and nine months ended September 30, 2012, stock-based compensation expense of approximately $2 million and $5 million, respectively, was recognized ($2 million and $5 million for the three and nine months ended September 30, 2011, respectively). 

7. EMPLOYEE FUTURE BENEFITS

The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group registered retirement savings plans, for employees. The Corporation and certain subsidiaries also offer OPEB plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following tables.

 Quarter Ended September 30 
 Defined Benefit   
 Pension Plans OPEB Plans 
($ millions)2012 2011 2012 2011 
Components of net benefit cost:        
Service costs6 5 2 1 
Interest costs12 12 2 3 
Expected return on plan assets(12)(12)- - 
Amortization of actuarial losses6 5 2 1 
Amortization of past service costs/plan amendments- - - (1)
Regulatory adjustments(2)(2)- 1 
Net benefit cost10 8 6 5 
         
 Year-to-Date September 30 
 Defined Benefit   
 Pension Plans OPEB Plans 
($ millions)2012 2011 2012 2011 
Components of net benefit cost:        
Service costs20 15 5 3 
Interest costs35 36 8 9 
Expected return on plan assets(37)(36)- - 
Amortization of actuarial losses19 15 4 3 
Amortization of past service costs/plan amendments- - (2)(3)
Amortization of transitional obligation1 - 1 - 
Regulatory adjustments(8)(6)1 3 
Net benefit cost30 24 17 15 

For the three and nine months ended September 30, 2012, the Corporation expensed $3 million and $10 million, respectively ($3 million and $11 million for the three and nine months ended September 30, 2011, respectively) related to defined contribution pension plans.

8. OTHER INCOME (EXPENSES), NET

 Quarter EndedYear-to-Date
 September 30September 30
($ millions)2012 20112012 2011
Interest income2 24 4
Equity component of allowance for funds used during construction1 24 10
Foreign exchange (loss) gain(2)1(2)1
Acquisition-related expenses- -(8)-
Merger termination fee- 17- 17
Other income, net of expenses- -- 2
 1 22(2)34

The foreign exchange loss for the three and nine months ended September 30, 2012 included approximately $3 million and $2.5 million, respectively, related to the translation of the Corporation''s US dollar-denominated long-term other asset representing the book value of the Corporation''s expropriated investment in Belize Electricity (Notes 17 and 19).

The foreign exchange gain for the three and nine months ended September 30, 2011 included a foreign exchange gain of $7 million associated with the translation of the above-noted US dollar-denominated long-term other asset, which 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 acquisition-related expenses are associated with the pending acquisition of CH Energy Group (Notes 1 and 18).

The termination fee was paid to Fortis in July 2011 following the termination of a Merger Agreement between Fortis and Central Vermont Public Service Corporation.

9. FINANCE CHARGES

 Quarter Ended Year-to-Date 
 September 30 September 30 
($ millions)2012 2011 2012 2011 
Interest:        
 Long-term debt and finance and capital lease obligations95 91 282 275 
 Short-term borrowings and other finance charges3 1 6 10 
Debt component of allowance for funds used during construction(5)(3)(12)(11)
 93 89 276 274 

10. INCOME TAXES

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

 Quarter Ended Year-to-Date 
 September 30 September 30 
($ millions, except as noted)2012 2011 2012 2011 
Combined Canadian federal and provincial statutory income tax rate29.0%30.5%29.0%30.5%
Statutory income tax rate applied to earnings before income taxes19 25 91 100 
Difference between Canadian statutory income tax rate and rates applicable to foreign subsidiaries(3)(4)(10)(9)
Difference in Canadian provincial statutory income tax rates applicable to subsidiaries in different Canadian jurisdictions(1)(1)(9)(9)
Items capitalized for accounting purposes but expensed for income tax purposes(11)(11)(39)(39)
Difference between capital cost allowance and amounts claimed for accounting purposes3 5 7 11 
Non-deductible expenses2 2 5 3 
Part VI.1 tax - difference between enacted and substantively enacted tax rates and the effect of statute-barred reversals(1)- 2 2 
Difference between employee future benefits paid and amounts expensed for accounting purposes- (1)1 (1)
Other(1)(3)(4)1 
Income taxes7 12 44 59 
Effective income tax rate10.6%14.6%14.1%17.9%

As at September 30, 2012, the Corporation had approximately $100 million (December 31, 2011 - $86 million) in non-capital and capital loss carryforwards, of which $8 million (December 31, 2011 - $13 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2014 and 2032.

11. EARNINGS PER COMMON SHARE

The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the "if-converted" method for convertible securities.

EPS were as follows:

 Quarter Ended September 30
 20122011
 Earnings
to Common
Share-
holders

($ millions)
 Weighted
Average
Shares
(in millions)
 


EPS
Earnings
to Common
Share-
holders
($ millions)
 Weighted
Average
Shares
(in millions)
 


EPS
Basic EPS45 190.2 $ 0.2456 186.5 $ 0.30
Effect of potential dilutive securities:          
 Stock Options- 0.9  - 1.0  
 Preference Shares4 10.3  4 10.1  
 Convertible Debentures- -  1 1.4  
 49 201.4  61 199.0  
Deduct anti-dilutive impacts:          
 Preference Shares(4)(10.3) (4)(10.1) 
 Convertible Debentures- -  (1)(1.4) 
Diluted EPS45 191.1 $ 0.2456 187.5 $ 0.30
           
 Year-to-Date September 30
 20122011
 Earnings
to Common
Share-
holders

($ millions)
 Weighted
Average
Shares
(in millions)
 


EPS
Earnings
to Common
Share-
holders
($ millions)
 Weighted
Average
Shares
(in millions)
 


EPS
Basic EPS228 189.6 $ 1.20229 179.5 $ 1.28
Effect of potential dilutive securities:          
 Stock Options- 0.9  - 1.0  
 Preference Shares12 10.3  12 10.1  
 Convertible Debentures- -  2 1.4  
 240 200.8  243 192.0  
Deduct anti-dilutive impacts:          
 Preference Shares(5)(3.9) (5)(3.9) 
Diluted EPS235 196.9 $ 1.19238 188.1 $ 1.27

12. BUSINESS ACQUISITIONS

In April 2012 FortisOntario exercised its option, under the terms of a 10-year operating lease agreement with the City of Port Colborne that commenced in April 2002, to purchase the remaining assets of Port Colborne Hydro for approximately $7 million. Under the lease arrangement with the City of Port Colborne, and now through ownership of the previously leased assets, FortisOntario operates and maintains the City of Port Colborne''s electricity distribution system for provision of electricity service to the residents of Port Colborne. Throughout the 10-year lease term, FortisOntario incurred approximately $17 million in capital expenditures in Port Colborne Hydro''s electricity distribution system. 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 entire distribution system in Port Colborne. The purchase was approved by the Ontario Energy Board.

FortisOntario is regulated under traditional cost of service and the determination of revenue and earnings is based on a regulated rate of return that is applied to historic values which do not change with a change of ownership. Therefore, fair market value approximates book value and no adjustments were recorded for the assets acquired, because all of the economic benefits and obligations associated with them beyond regulated rates of return accrue to the customers. Accordingly, $3 million of the purchase price was allocated to utility capital assets and $4 million was recognized as goodwill in the preliminary purchase price allocation.

In August 2012 Fortis Turks and Caicos acquired 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 between Grand Turk and Salt Cay with a diesel-fired generating capacity of 9 MW. Fortis Turks and Caicos is regulated under traditional cost of service and the determination of revenue and earnings is based on a regulated rate of return that is applied to historic values which do not change with a change of ownership. Therefore, fair market value approximates book value and no adjustments were recorded for the net assets acquired, because all of the economic benefits and obligations associated with them beyond regulated rates of return accrue to the customers. Accordingly, approximately $9 million of the purchase price was allocated to utility capital assets, $3 million to current net assets, $5 million to long-term debt and $1 million was recognized as goodwill in the preliminary purchase price allocation.

13. SEGMENTED INFORMATION

Information by reportable segment is as follows:

 REGULATEDNON-REGULATED    
 Gas Utilities Electric Utilities       
Quarter Ended
September 30, 2012
($ millions)
FortisBC Energy
Companies
-

Canadian
 
Fortis
Alberta

FortisBC
Electric

New-
found-
land
Power

Other
Cana-
dian
Total
Electric
Cana-
dian

Electric
Carib-
bean

Fortis
Gene-
ration

Fortis
Proper-
ties

Corporate
and Other
 Inter-segment
elimi-
nations
 

Conso-
lidated
Revenue192 1177110091379728655 (7)714
Energy supply costs61 -16545912945--- - 235
Operating expenses64 402017118872422 (2)203
Depreciation and amortization40 341211764815- - 118
Operating income27 4323181498125183 (5)158
Other income (expenses), net1 -11-21--(3)- 1
Finance charges36 17995403-613 (5)93
Income tax (recovery) expense(2)-2136--4(1)- 7
Net (loss) earnings(6)261396541058(12)- 59
Non-controlling interests- -----3--- - 3
Preference share dividends- --------11 - 11
Net (loss) earnings attributable to common equity shareholders(6)26139654758(23)- 45
                
Goodwill913 227221-67515138--- - 1,566
Identifiable assets4,503 2,6171,6861,2447056,252735686623498 (425)12,872
Total assets5,416 2,8441,9071,2447726,767873686623498 (425)14,438
Gross capital expenditures (1)66 10419221315811399- - 283
                
Quarter Ended September 30, 2011($ millions)               
Revenue197 10367101873587411634 (8)699
Energy supply costs76 -15525612347--- - 246
Operating expenses65 351917118292404 (2)200
Depreciation and amortization29 341111662715- - 104
Operating income27 342221149111818- (6)149
Other income (expenses), net2 --------20 - 22
Finance charges36 151095392-612 (6)89
Income tax (recovery) expense(3)-2439--33 - 12
Net (loss) earnings(4)191086439895 - 70
Non-controlling interests- -----3--- - 3
Preference share dividends- --------11 - 11
Net (loss) earnings attributable to common equity shareholders(4)19108643689(6)- 56
                
Goodwill913 227221-63511144--- - 1,568
Identifiable assets4,364 2,3451,6261,2326705,873742539589507 (434)12,180
Total assets5,277 2,5721,8471,2327336,384886539589507 (434)13,748
Gross capital expenditures (1)64 82252414145174911- - 286
(1)Relates to cash payments to acquire or construct utility capital assets, including amounts for AESO transmission-related capital projects, income producing properties and intangible assets, as reflected on the consolidated statements of cash flows
        
        
        
 REGULATEDNON-REGULATED     
 Gas UtilitiesElectric Utilities        
Year-to-Date
September 30, 2012
($ millions)
FortisBC Energy
Companies
-

Canadian

Fortis
Alberta

FortisBC
Electric

New-
found-
land
Power

Other
Cana-
dian
Total
Electric
Cana-
dian

Electric
Carib-
bean

Fortis
Gene-
ration

Fortis
Proper-
ties

Corporate
and Other
 Inter-
segment
elimi-
nations
 

Conso-
lidated
 
Revenue1,0043352254222641,2462022618118 (22)2,655 
Energy supply costs472-542741684961241-- (1)1,092 
Operating expenses1971166254352672461248 (5)621 
Depreciation and amortization12099363320188243151 - 351 
Operating income2151207361412953016429 (16)591 
Other income (expenses), net2212-521-(11)(1)(2)
Finance charges107492927161211011836 (17)276 
Income tax expense (recovery)20-78722-17(6)- 44 
Net earnings (loss)9073382818157221517(32)- 269 
Non-controlling interests1-----6--- - 7 
Preference share dividends---------34 - 34 
Net earnings (loss) attributable to common equity shareholders8973382818157161517(66)- 228 
                
Goodwill913227221-67515138--- - 1,566 
Identifiable assets4,5032,6171,6861,2447056,252735686623498 (425)12,872 
Total assets5,4162,8441,9071,2447726,767873686623498 (425)14,438 
Gross capital expenditures (1)1443045258354493314424- - 794 
                
Year-to-Date September 30, 2011($ millions)               
Revenue1,0903062154172561,1942342517317 (29)2,704 
Energy supply costs590-492661634781461-- (8)1,207 
Operating expenses2091065854342523161179 (5)619 
Depreciation and amortization83100343218184243141 - 309 
Operating income2081007465412803315427 (16)569 
Other income (expenses), net831--421-20 (1)34 
Finance charges106442927161161121838 (17)274 
Income tax expense (recovery)241814730116(3)- 59 
Net earnings (loss)8658382418138231318(8)- 270 
Non-controlling interests------7--- - 7 
Preference share dividends---------34 - 34 
Net earnings (loss) attributable to common equity shareholders8658382418138161318(42)- 229 
                
Goodwill913227221-63511144--- - 1,568 
Identifiable assets4,3642,3451,6261,2326705,873742539589507 (434)12,180 
Total assets5,2772,5721,8471,2327336,384886539589507 (434)13,748 
Gross capital expenditures (1)1772537855334195713120- - 804 
  
(1)Relates to cash payments to acquire or construct utility capital assets, including amounts for AESO transmission-related capital projects, income producing properties and intangible assets, as reflected on the consolidated statements of cash flows

Related party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The significant related party inter-segment transactions primarily related to: (i) the sale of energy from Fortis Generation to Belize Electricity, up to June 20, 2011; (ii) electricity sales from Newfoundland Power to Fortis Properties; and (iii) finance charges on related party borrowings. The significant related party inter-segment transactions for the three and nine months ended September 30, 2012 and 2011 were as follows:

Significant Inter-Segment TransactionsQuarter EndedYear-to-Date
 September 30September 30
($ millions)2012201120122011
Sales from Fortis Generation to    
 Regulated Electric Utilities - Caribbean---7
Sales from Fortis Generation to    
 Other Canadian Electric Utilities---1
Sales from Newfoundland Power to Fortis Properties1143
Inter-segment finance charges on lending from:    
 Fortis Generation to Other Canadian Electric Utilities--11
 Corporate to Regulated Electric Utilities - Canadian-1-2
 Corporate to Regulated Electric Utilities - Caribbean1133
 Corporate to Fortis Generation-112
 Corporate to Fortis Properties43129
     
The significant inter-segment asset balances were as follows:
  As at September 30
($ millions)  20122011
Inter-segment lending from:    
 Fortis Generation to Other Canadian Electric Utilities  2020
 Corporate to Regulated Electric Utilities - Canadian  -50
 Corporate to Regulated Electric Utilities - Caribbean  8478
 Corporate to Fortis Generation  1232
 Corporate to Fortis Properties  284226
Other inter-segment assets  2528
Total inter-segment eliminations  425434

14. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

 Quarter Ended Year-to-Date 
 September 30 September 30 
($ millions)2012 2011 2012 2011 
Cash paid for:        
Interest84 79 269 260 
Income taxes12 16 63 61 
         
Change in non-cash operating working capital:        
Accounts receivable96 115 224 184 
Prepaid expenses(8)(8)(14)(15)
Inventories(48)(84)(21)(28)
Regulatory assets - current portion2 (15)50 (21)
Accounts payable and other current liabilities28 4 (39)(34)
Regulatory liabilities - current portion(13)(14)19 18 
 57 (2)219 104 
         
Non-cash investing and financing activities:        
Common share dividends reinvested15 16 43 47 
Exercise of stock options into common shares- - 1 2 
         

15. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Corporation generally limits the use of derivative instruments to those that qualify as accounting or economic hedges. As at September 30, 2012, the Corporation''s derivative contracts consisted of fuel option contracts, natural gas swap and option contracts, and gas purchase contract premiums. The fuel option contracts are held by Caribbean Utilities and the remaining derivative instruments are held by the FortisBC Energy companies.

Volume of Derivative Activity

As at September 30, 2012, the following notional volumes related to fuel option contracts and natural gas derivatives that are expected to be settled are outlined below.

 201220132014
Fuel option contracts (millions of imperial gallons)43-
Gas swaps and options (petajoules)4266
Gas purchase contract premiums (petajoules)94171

Presentation of Derivative Instruments in the Consolidated Financial Statements

In the Corporation''s consolidated balance sheets, derivative instruments are presented on a net basis by counterparty, where the right of offset exists.

The Corporation''s outstanding derivative balances were as follows:

 As at
 September 30,December 31,
($ millions)20122011
Gross derivatives balance (1)59136
Netting (2)--
Cash collateral--
Total derivative balances (3)59136
   
  
(1)Refer to Note 16 for a discussion of the valuation techniques used to calculate the fair value of the derivative instruments.
  
(2)Positions, by counterparty, are netted where the intent and legal right to offset exists.
  
(3)Unrealized losses of $34 million on commodity risk-related derivative instruments as at September 30, 2012 were recognized in current regulatory assets and $25 million were recognized as an offset to current regulatory liabilities (December 31, 2011 - $136 million recognized in current regulatory assets), which would otherwise be recognized on the consolidated statement of comprehensive income and in accumulated other comprehensive loss. These amounts exclude the impact of cash collateral postings.

Cash flows associated with the settlement of all derivative instruments are included in operating cash flows on the Corporation''s consolidated statements of cash flows.

The majority of the FortisBC Energy companies'' risk-related derivative instruments contain collateral posting provisions tied to FEI''s credit rating. A downgrade of FEI below investment grade by any of the major credit rating agencies could trigger margin calls and other cash requirements under FEI''s gas purchase and swap and option contracts. Most of the existing natural gas derivative contracts are in liability positions and might be subject to margin calls and other cash requirements if FEI was downgraded below investment grade.

16. FAIR VALUE MEASUREMENTS

Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value. The Corporation is required to record all derivative instruments at fair value except for those which qualify for the normal purchase and normal sale exception.

The three levels of the fair value hierarchy are defined as follows:

Level 1:Fair value determined using unadjusted quoted prices in active markets
Level 2:Fair value determined using pricing inputs that are observable
Level 3:Fair value determined using unobservable inputs only when relevant observable inputs are not available

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

The following table details the estimated fair value measurements of the Corporation''s financial instruments, all of which were measured using Level 2 inputs, except for certain long-term debt as noted.

 As at 
Asset (Liability)September 30, 2012 December 31, 2011 
 Carrying Estimated Carrying Estimated 
($ millions)Value Fair Value Value Fair Value 
Other asset - Belize Electricity (1)103 (2) 106 (2) 
Long-term debt, including current portion (3)(5,937)(7,476)(5,788)(7,172)
Waneta Partnership promissory note (4)(46)(52)(45)(49)
Foreign exchange forward contract (5)- - - - 
Fuel option contracts (5)- - (1)(1)
Natural gas derivatives: (5)        
 Swaps and options(60)(60)(135)(135)
 Gas purchase contract premiums1 1 - - 
  
(1)Included in long-term other assets on the consolidated balance sheet
  
(2)The fair value of the Corporation''s expropriated investment in Belize Electricity determined under the GOB''s valuation is significantly lower than the fair value determined under the Corporation''s independent valuation of the utility. Due to uncertainty in the ultimate amount and ability of the GOB to pay appropriate fair value compensation owing to Fortis for the expropriation of Belize Electricity, the Corporation has recorded the long-term other asset at the carrying value of the Corporation''s previous investment in Belize Electricity, including foreign exchange impacts (Notes 17 and 19).
  
(3)The Corporation''s $200 million unsecured debentures due 2039 and consolidated credit facilities classified as long-term are valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs.
  
(4)Included in long-term other liabilities on the consolidated balance sheet
  
(5)The fair values of the derivatives were recorded in accounts payable and other current liabilities as at September 30, 2012 and December 31, 2011. The fair value of the fuel option contracts as at September 30, 2012 were less than $1 million. The foreign exchange forward contract held by FEI expired in April 2012. The fair value of the contract was less than $1 million as at December 31, 2011.

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

The fuel option contracts are used by Caribbean Utilities to reduce the impact of volatility in fuel prices on customer rates, as approved by the regulator under the Company''s Fuel Price Volatility Management Program. The fair value of the fuel option contracts reflects only the value of the heating oil derivative and not the offsetting change in the value of the underlying future purchases of heating oil and is calculated using published market prices for heating oil. The fuel option contracts mature in March 2013. In October 2012 Caribbean Utilities executed additional fuel option contracts covering the period from November 1, 2012 to October 31, 2013. With the execution of these new contracts, approximately 70% of the Company''s annual diesel fuel requirements are under fuel hedging arrangements.

The natural gas derivatives are used to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts at the FortisBC Energy companies have floating, rather than fixed, prices. The fair value of the natural gas derivatives was calculated using the present value of cash flows based on market prices and forward curves for the commodity cost of natural gas. 

The fair values of the fuel option contracts and natural gas derivatives were estimates of the amounts that the utilities would have to receive or pay to terminate the outstanding contracts as at the balance sheet dates. As at September 30, 2012, none of the fuel option contracts or natural gas derivatives were designated as hedges of fuel purchases or natural gas supply contracts. However, any gains or losses associated with changes in the fair value of the derivatives were deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators.

17. FINANCIAL RISK MANAGEMENT

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

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

Credit Risk

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

FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at September 30, 2012, the utility''s gross credit risk exposure was approximately $57 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to less than $1 million by obtaining from the retailers an acceptable form of prudential, which includes either a cash deposit, bond, letter of credit or an investment-grade credit rating from a major rating agency, or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating. 

The FortisBC Energy companies are exposed to credit risk in the event of non-performance by counterparties to derivative financial instruments. To help mitigate credit risk, the FortisBC Energy companies deal with reasonable credit-quality institutions in accordance with established credit-approval practices. The FortisBC Energy companies do not expect any counterparties to fail to meet their obligations. The counterparties with which the FortisBC Energy companies have significant derivative transactions are A-rated entities or better. The Company uses netting arrangements to reduce credit risk and net settles payments with counterparties where net settlement provisions exist.

The following table summarizes the FortisBC Energy companies'' net credit risk exposure to its counterparties, as well as credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as it relates to its natural gas swaps and options.

 As at
 September 30,December 31,
($ millions, except for number of customers)20122011
Gross credit exposure before credit collateral (1)60136
Credit collateral--
Net credit exposure (2)60136
   
Number of counterparties > 10%44
Net exposure to counterparties > 10%53104
  
(1)Gross credit exposure equals mark-to-market value on physically and financially settled contracts, notes receivable and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported do not include adjustments for time value or liquidity.
  
(2)Net credit exposure is the gross credit exposure collateral minus credit collateral (cash deposits and letters of credit).

The Corporation is exposed to credit risk associated with the amount and timing of fair value compensation that Fortis is entitled to receive from the GOB as a result of the expropriation of the Corporation''s investment in Belize Electricity by the GOB on June 20, 2011. As at September 30, 2012, the Corporation had a long-term other asset of $103 million (December 31, 2011 - $106 million; September 30, 2011 - $103 million), including foreign exchange impacts, recognized on the consolidated balance sheet related to its expropriated investment in Belize Electricity (Notes 16 and 19).

Additionally, as at September 30, 2012, Belize Electricity owed Belize Electric Company Limited ("BECOL") approximately US$10 million for energy purchases of which US$6 million was overdue. In accordance with long-standing agreements, the GOB guarantees the payment of Belize Electricity''s obligations to BECOL.

Liquidity Risk

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

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

The Corporation''s committed credit facility is available for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation''s committed credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at September 30, 2012, average annual consolidated long-term debt maturities and repayments over the next five years are expected to be approximately $295 million. The combination of available credit facilities and relatively low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

As at September 30, 2012, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.5 billion, of which $2.0 billion was unused. 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 credit facilities with maturities ranging from 2013 to 2017.

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

      As at 
 Regulated FortisCorporate September 30, December 31, 
($ millions)Utilities Propertiesand Other 2012 2011 
Total credit facilities1,401 131,045 2,459 2,248 
Credit facilities utilized:         
 Short-term borrowings (1)(97)-- (97)(159)
 Long-term debt (2)(63)-(236)(299)(74)
Letters of credit outstanding(67)-(1)(68)(66)
Credit facilities unused1,174 13808 1,995 1,949 
  
(1)The weighted average interest rate on short-term borrowings was approximately 2.2% as at September 30, 2012 (December 31, 2011 - 1.9%).
  
(2)As at September 30, 2012, credit facility borrowings classified as long term included $20 million (December 31, 2011 - $16 million) that was included in current installments of long-term debt on the consolidated balance sheet. The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 2.2% as at September 30, 2012 (December 31, 2011 - 2.2%).

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.