Fortis Inc. Earns $62 Million in Second Quarter

Marketwired

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwire - July 31, 2012) - Fortis Inc. ("Fortis" or the "Corporation") (FTS.TO) achieved second quarter net earnings attributable to common equity shareholders of $62 million, or $0.33 per common share, compared to $57 million, or $0.32 per common share, for the second quarter of 2011. For the first half of 2012, net earnings attributable to common equity shareholders were $183 million, or $0.97 per common share, compared to $173 million, or $0.98 per common share, for the first half of last year.

Performance for the quarter was driven by FortisAlberta and higher non-regulated hydroelectric generation, partially offset by increased corporate costs. A 7% increase in the weighted average number of common shares outstanding quarter over quarter, largely associated with the issuance of common equity in mid-2011, and $4 million ($3 million after tax), or $0.02 per common share, of acquisition-related expenses incurred during the second quarter of 2012 associated with the CH Energy Group, Inc. ("CH Energy Group") transaction lowered earnings per common share in the second quarter of 2012.

Canadian Regulated Electric Utilities contributed earnings of $52 million, up $9 million from the second quarter of 2011. Earnings at FortisAlberta increased $8 million quarter over quarter, mainly due to growth in energy infrastructure investment, and increased transmission revenue and reduced depreciation as approved by the regulator, partially offset by a lower allowed rate of return on common shareholder's equity ("ROE").

FortisBC Electric and the City of Kelowna (the "City") are in preliminary discussions for FortisBC Electric to purchase the City's electricity distribution utility, which currently serves approximately 15,000 customers. The City's electricity distribution assets have been operated and maintained by FortisBC Electric since 2000. Closing of the transaction is subject to certain conditions, negotiation of definitive agreements and certain approvals, including municipal and regulatory approvals. The parties are working towards closing the transaction by the end of the first quarter of 2013.

Canadian Regulated Gas Utilities delivered earnings of $13 million compared to $15 million for the second quarter of 2011. The decrease in earnings was mainly due to lower-than-expected customer additions and lower capitalized allowance for funds used during construction during 2012, partially offset by higher-than-expected gas transportation volumes to industrial customers.

Regulatory decisions were received in April 2012 for 2012/2013 customer gas delivery rates at the FortisBC Energy companies and 2012 customer electricity distribution rates at FortisAlberta. A decision on 2012/2013 customer electricity rates at FortisBC Electric is expected during the third quarter of 2012. A Generic Cost of Capital Proceeding in British Columbia to determine cost of capital, effective January 1, 2013, and a performance-based rate-regulation initiative in Alberta are continuing.

In June 2012 Newfoundland Power received regulatory approval of an increase in its allowed ROE to 8.80% for 2012 up from 8.38% for 2011. The Company expects to file a general rate application for 2013 customer rates during the third quarter of 2012.

Caribbean Regulated Electric Utilities contributed $6 million of earnings, comparable to the second quarter of 2011.

Consolidated capital expenditures, before customer contributions, were approximately $511 million in the first half of 2012. The Customer Care Enhancement Project at FortisBC's gas business came into service at the beginning of January 2012. Construction continues on time and on budget on the $900 million Waneta Expansion hydroelectric generating facility (the "Waneta Expansion") with approximately $345 million in total having been spent on the Waneta Expansion since construction began in late 2010.

Non-Regulated Fortis Generation contributed $5 million to earnings, up $3 million quarter over quarter. Improved performance mainly related to increased production in Belize due to higher rainfall.

Fortis Properties delivered earnings of $8 million, comparable to the second quarter of 2011.

Corporate and other expenses were $22 million, $5 million higher quarter over quarter, largely the result of CH Energy Group acquisition-related expenses of approximately $4 million ($3 million after tax) incurred during the second quarter of 2012 and a lower income tax recovery, partially offset by a foreign exchange gain of approximately $2 million recognized during the second quarter of 2012.

Cash flow from operating activities was $583 million for the first half of 2012, up $50 million from the first half of 2011, driven by favourable changes in working capital and higher earnings.

In February 2012 Fortis announced 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 New York State Public Service Commission is currently reviewing the application for approval of the transaction 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 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 contained in the purchase agreement with 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 May 2012 and July 2012, Standard & Poor's Ratings Service ("S&P") and DBRS, respectively, affirmed the Corporation's debt credit ratings at A- and A(low), respectively. Also, S&P removed the rating from credit watch with negative implications and DBRS removed the rating from under review with developing implications, where the ratings had been placed in February 2012 following the announcement of the CH Energy Group acquisition.

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 second quarter of 2012 or 2011.

"The second half of 2012 will continue to be very busy for Fortis, with significant regulatory proceedings continuing at our largest utilities and our annual capital program projected to reach a record $1.3 billion," says Stan Marshall, President and Chief Executive Officer, Fortis Inc. "This investment in energy infrastructure will ensure we continue to meet our customers' energy needs with safe, reliable and cost-efficient supply."

"We are also focused on closing the CH Energy Group transaction by the end of the first quarter of 2013," says Marshall. "The addition of CH Energy Group to Fortis will deliver tangible benefits to customers of Central Hudson and support the utility's focus on enhancing customer service. Central Hudson's capital program from 2013 through 2016 is expected to add approximately $0.5 billion to the Fortis consolidated five-year $5.5 billion capital program," he explains.

"We remain disciplined and patient in our pursuit of additional electric and gas utility acquisitions in the United States and Canada that will add value for Fortis shareholders," concludes Marshall.

Interim Management Discussion and Analysis

For the three and six months ended June 30, 2012

Dated July 31, 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 six months ended June 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 during 2012; the possible acquisition of the City of Kelowna's electricity distribution utility by FortisBC Electric; the expected timing of filing regulatory applications and of receipt of regulatory decisions; and 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.

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 and other approvals 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; no significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; 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; 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; 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 six months ended June 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 June 30, 2012, the Corporation's electricity distribution systems met a combined peak demand of approximately 5,215 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 six months ended June 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 is 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.

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.

The acquisition is also subject to certain other approvals, including approval by the New York State Public Service Commission (the "NYSPSC"), and satisfaction of customary closing conditions. The NYSPSC is currently reviewing the application for approval of the transaction 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.

Subscription Receipts: 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. (collectively the "Underwriters"), resulting in gross proceeds of approximately $601 million. The gross proceeds from the sale of the Subscription Receipts are being held by an escrow agent, pending receipt of all required approvals and satisfaction of closing conditions 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 share purchase agreement 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.

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. 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. 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. For further information, refer to the "New Accounting Policies" section of this MD&A.

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 constitutes the electricity distribution system in Port Colborne.

Pending Acquisition of the Electricity Distribution Utility from the City of Kelowna: FortisBC Electric and the City of Kelowna (the "City") are in preliminary discussions for FortisBC Electric to purchase the City's electricity distribution utility, which currently serves approximately 15,000 customers. FortisBC Electric provides the City with electricity under a wholesale tariff and has operated and maintained its assets since 2000. Closing of the transaction is subject to certain conditions, negotiation of definitive agreements and certain approvals, including municipal and regulatory approvals. The parties are working towards closing the transaction by the end of the first quarter of 2013.

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 Electric is assuming 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 second quarter and year-to-date periods ended June 30, 2012 and June 30, 2011 are provided in the following table.

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Consolidated Financial Highlights (Unaudited)

Periods Ended June 30 Quarter Year-to-Date

($ millions, except for

common share data) 2012 2011 Variance 2012 2011 Variance

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Revenue 792 846 (54) 1,941 2,005 (64)

Energy Supply Costs 291 358 (67) 857 961 (104)

Operating Expenses 204 209 (5) 418 419 (1)

Depreciation and

Amortization 114 102 12 233 205 28

Other Income (Expenses),

Net - 4 (4) (3) 12 (15)

Finance Charges 92 93 (1) 183 185 (2)

Income Taxes 14 16 (2) 37 47 (10)

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Net Earnings 77 72 5 210 200 10

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Net Earnings Attributable

to:

Non-Controlling

Interests 3 3 - 4 4 -

Preference Equity

Shareholders 12 12 - 23 23 -

Common Equity

Shareholders 62 57 5 183 173 10

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Net Earnings 77 72 5 210 200 10

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Basic Earnings per Common

Share ($) 0.33 0.32 0.01 0.97 0.98 (0.01)

Diluted Earnings per

Common Share ($) 0.33 0.32 0.01 0.95 0.97 (0.02)

Weighted Average Number

of Common Shares

Outstanding (# millions) 189.6 177.1 12.5 189.3 175.8 13.5

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Cash Flow from Operating

Activities 255 231 24 583 533 50

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Factors Contributing to Quarterly and Year-to-Date

Revenue Variances

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

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

partially offset by higher gas transportation volumes to industrial

customers

-- Lower electricity sales at Newfoundland Power for the quarter and at

FortisBC Electric, Caribbean Utilities and FortisOntario for the quarter

and year-to-date 2012

Favourable

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

rates at the regulated utilities in western Canada, consistent with

final or interim rate decisions, reflecting ongoing investment in energy

infrastructure and forecasted higher expenses recoverable from customers

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

-- Increased electricity sales at Newfoundland Power and Fortis Turks and

Caicos year to date and at Maritime Electric for the quarter and year-

to-date 2012

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

supply costs

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

higher rainfall

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

from the Hilton Suites Winnipeg Airport hotel, which was acquired in

October 2011

-- Approximately $3 million of net transmission revenue recognized at

FortisAlberta in the second quarter of 2012, of which approximately $1

million related to the first quarter of 2012, as a result of the 2012

distribution revenue requirements decision received in April 2012

-- Approximately $3 million for the quarter and $4 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

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

-- Lower average gas consumption

-- Lower electricity sales at Newfoundland Power for the quarter and at

FortisBC Electric, Caribbean Utilities and FortisOntario for the quarter

and year-to-date 2012

Unfavourable

-- Increased fuel prices at Caribbean Utilities and increased purchased

power costs at FortisBC Electric and FortisOntario

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

Electric for the quarter associated with the higher flow through and

recovery of energy supply costs, partially offset by lower purchased

power costs at the utility

-- Increased electricity sales at Newfoundland Power and Fortis Turks and

Caicos year to date and at Maritime Electric for the quarter and year-

to-date 2012

-- Approximately $2 million for the quarter and $2 million year to date

associated with unfavourable foreign currency translation

Factors Contributing to Quarterly and Year-to-Date

Operating Expenses Variances

Favourable

-- Lower operating expenses at the FortisBC Energy companies, mainly due to

the accrual of non-asset retirement obligation ("non-ARO") removal costs

in depreciation, effective January 1, 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

-- The cumulative $1.5 million ($1 million after tax) impact of the

increase in the allowed ROE at Newfoundland Power, effective January 1,

2012, was accrued in the second quarter of 2012 as a decrease in

operating expenses.

Unfavourable

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

Corporation's regulated utilities, and timing of expenditures at

FortisBC Electric year-to-date 2012 and at FortisOntario for the quarter

and year-to-date 2012

-- Operating expenses associated with the Hilton Suites Winnipeg Airport

hotel, which was acquired in October 2011

Factors Contributing to Quarterly and Year-to-Date

Depreciation and Amortization Costs 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

-- Decreased depreciation at FortisAlberta, mainly due to lower

depreciation rates effective January 1, 2012, as a result of the 2012

revenue requirements decision received in April 2012. Approximately $3

million of reduced depreciation in the second quarter of 2012 related to

the first quarter of 2012.

-- Lower depreciation rates at FortisBC Electric

Factors Contributing to Quarterly and Year-to-Date

Other Income (Expenses), Net Variances

Unfavourable

-- Approximately $4 million ($3 million after tax) and $8 million ($7

million after tax) of costs incurred in the second quarter and first

half of 2012, respectively, related to the pending acquisition of CH

Energy Group

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

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

FortisBC Electric

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

during the first quarter of 2011

Favourable

-- An approximate $2 million and $0.5 million net foreign exchange gain for

the second quarter and first half of 2012, respectively, associated with

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

representing the book value of the Corporation's former investment in

Belize Electricity

Factors Contributing to Quarterly and Year-to-Date

Finance Charges Variances

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

-- Lower short-term borrowings at the regulated utilities, driven by the

FortisBC Energy companies

Unfavourable

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

expenditure programs

-- Lower capitalized debt component of AFUDC, mainly at the FortisBC Energy

companies and FortisBC Electric

Factors Contributing to Quarterly and Year-to-Date

Income Taxes Variances

Favourable

-- Lower statutory corporate income tax rates and higher earnings from non-

taxable foreign subsidiaries

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

accounting purposes period over period

Unfavourable

-- An increase in Part VI.1 tax

Factors Contributing to Quarterly Earnings Variance

Favourable

-- Increased earnings at FortisAlberta due to higher net transmission

revenue and lower depreciation expense as approved by the regulator, and

rate base growth, partially offset by a lower allowed ROE

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

higher rainfall

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

income taxes and a higher allowed ROE. The cumulative approximate $1.5

million ($1 million after tax) impact of the increase in the allowed

ROE, effective January 1, 2012, was accrued in the second quarter of

2012.

Unfavourable

-- Higher corporate expenses 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 net foreign exchange gain of

approximately $2 million recognized in the second quarter of 2012

-- Decreased earnings at the FortisBC Energy companies, mainly due to

lower-than-expected customer additions and lower capitalized AFUDC in

2012, partially offset by higher-than-expected gas transportation

volumes to industrial customers

Factors Contributing to Year-to-Date Earnings Variance

Favourable

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

transmission revenue and lower effective income taxes, 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 the FortisBC Energy companies, mainly due to rate

base growth, seasonality of gas consumption and the timing of certain

expenses in 2012 and higher-than-expected gas transportation volumes to

industrial customers. The increase was partially offset by lower-than-

expected customer additions and lower capitalized AFUDC in 2012.

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

higher rainfall

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

above for the quarter, combined with growth in electricity sales year to

date

Unfavourable

-- Higher corporate expenses, due to approximately $8 million ($7 million

after tax) of costs incurred during the first half of 2012 related to

the pending acquisition of CH Energy Group and a lower income tax

recovery, partially offset by lower finance charges

-- Decreased earnings at FortisBC Electric, due to the expiry of the

performance-based rate-setting ("PBR") mechanism on December 31, 2011

and lower capitalized AFUDC, partially offset by rate base growth

SEGMENTED RESULTS OF OPERATIONS

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

Segmented Net Earnings Attributable to Common Equity Shareholders

(Unaudited)

Periods Ended June 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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

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

Regulated Gas Utilities -

Canadian

FortisBC Energy

Companies 13 15 (2) 95 90 5

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

Regulated Electric

Utilities - Canadian

FortisAlberta 26 18 8 47 39 8

FortisBC Electric 9 9 - 25 28 (3)

Newfoundland Power 12 10 2 19 16 3

Other Canadian Electric

Utilities 5 6 (1) 12 12 -

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

52 43 9 103 95 8

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

Regulated Electric

Utilities - Caribbean 6 6 - 9 10 (1)

Non-Regulated - Fortis

Generation 5 2 3 10 5 5

Non-Regulated - Fortis

Properties 8 8 - 9 9 -

Corporate and Other (22) (17) (5) (43) (36) (7)

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

Net Earnings Attributable

to Common Equity

Shareholders 62 57 5 183 173 10

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

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

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

REGULATED GAS UTILITIES - CANADIAN

FORTISBC ENERGY COMPANIES (1)

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

Gas Volumes by Major Customer Category (Unaudited)

Periods Ended June 30 Quarter Year-to-Date

(TJ) 2012 2011 Variance 2012 2011 Variance

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

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

Core - Residential

and Commercial 21,508 24,951 (3,443) 70,040 75,399 (5,359)

Industrial 1,071 1,229 (158) 2,842 3,117 (275)

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

Total Sales Volumes 22,579 26,180 (3,601) 72,882 78,516 (5,634)

Transportation

Volumes 16,774 16,730 44 38,243 37,214 1,029

Throughput under

Fixed Revenue

Contracts 93 489 (396) 700 965 (265)

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

Total Gas Volumes 39,446 43,399 (3,953) 111,825 116,695 (4,870)

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

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

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

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

Factors Contributing to Quarterly and Year-to-Date

Gas Volumes Variances

Unfavourable

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

a result of overall warmer temperatures

Favourable

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

customers switching to natural gas from alternative sources of fuel as a

result of lower natural gas prices, and continued high demand from the

mining sector

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 June 30, 2012, the total number of customers served by the FortisBC Energy companies was approximately 937,000.

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.

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

Financial Highlights (Unaudited)

Periods Ended June 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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

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

Revenue 264 319 (55) 812 893 (81)

Earnings 13 15 (2) 95 90 5

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

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

Factors Contributing to Quarterly and Year-to-Date

Revenue Variances

Unfavourable

-- Lower commodity cost of natural gas charged to customers

-- Lower average gas consumption by residential and commercial 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 higher expenses recoverable from customers

and reflecting the 2012/2013 revenue requirements decision received by

the FortisBC Energy companies in April 2012

-- Higher-than-expected gas transportation volumes to industrial customers

in 2012

Factors Contributing to Quarterly Earnings Variance

Unfavourable

-- Lower-than-expected customer additions in 2012

-- Lower capitalized AFUDC, due to a lower asset base under construction in

2012

Favourable

-- Higher-than-expected gas transportation volumes to industrial customers

in 2012

Factors Contributing to Year-to-Date Earnings Variance

Favourable

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

-- The seasonality of gas consumption and the timing of certain expenses in

2012. Revenue is recognized based on seasonal gas consumption while

certain operating expenses, as well as depreciation, are generally

incurred evenly throughout the year, which, combined with an approved

increase in expenses in 2012, has resulted in favourable timing

differences contributing to higher earnings year to date compared to the

same period last year

-- Higher-than-expected gas transportation volumes to industrial customers

in 2012

Unfavourable

-- The same factors discussed above for the quarter

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

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

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended June 30 2012 2011 Variance 2012 2011 Variance

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

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

Energy Deliveries

(gigawatt hours

("GWh")) 3,853 3,822 31 8,335 8,224 111

Revenue ($ millions) 110 103 7 218 203 15

Earnings ($ millions) 26 18 8 47 39 8

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

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

Factors Contributing to Quarterly and Year-to-Date

Energy Deliveries Variances

Favourable

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

increasing by approximately 9,200 year over year as at June 30, 2012,

driven by favourable economic conditions

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

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

Unfavourable

-- Lower average consumption by residential, farm and irrigation customers,

due to warmer temperatures during the first four months of 2012 and

above-average precipitation levels during the second quarter of 2012

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

-- Approximately $3 million of net transmission revenue recognized in the

second quarter of 2012, of which approximately $1 million related to the

first quarter of 2012. 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 that were forecast.

-- Growth in the number of customers

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.

-- 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

-- An approximate $2 million increase in franchise fee revenue

Unfavourable

-- The same factors discussed above for the quarter

Factors Contributing to Quarterly Earnings Variance

Favourable

-- Approximately $3 million of net transmission revenue recognized in the

second quarter of 2012, of which approximately $1 million related to the

first quarter of 2012, as a result of the 2012 distribution revenue

requirements decision received in April 2012

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

-- Reduced depreciation expense, due to the recognition in the second

quarter of 2012 of the cumulative impact of an overall decrease in

depreciation rates, effective January 1, 2012, as a result of the 2012

distribution revenue requirements decision received in April 2012.

Approximately $3 million of reduced depreciation expense in the second

quarter of 2012 related to the first quarter of 2012.

Unfavourable

-- A lower allowed ROE, as discussed above

Factors Contributing to Year-to-Date Earnings Variance

Favourable

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

-- Approximately $3 million of net transmission revenue recognized in the

second quarter of 2012, as a result of the 2012 distribution revenue

requirements decision received in April 2012

-- Lower effective income taxes, 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

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 June 30 2012 2011 Variance 2012 2011 Variance

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

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

Electricity Sales

(GWh) 676 682 (6) 1,585 1,587 (2)

Revenue ($ millions) 67 65 2 154 148 6

Earnings ($ millions) 9 9 - 25 28 (3)

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

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

(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 distribution

system owned by the City of Kelowna. Excludes the non-regulated

generation operations of FortisBC Inc.'s wholly owned partnership,

Walden Power Partnership.


Factor Contributing to Quarterly and Year-to-Date

Electricity Sales Variances

Unfavourable

-- Lower average energy consumption, due to differences in weather

conditions

Favourable

-- Growth in the number of customers

Factors Contributing to Quarterly and Year-to-Date

Revenue Variances

Favourable

-- An interim, refundable increase in customer electricity rates, effective

January 1, 2012, mainly reflecting ongoing investment in energy

infrastructure and forecasted higher expenses recoverable from customers

-- 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

-- Differences in the amount of PBR incentive and flow-through adjustments

owing to customers period over period

Unfavourable

-- The 0.9% and 0.1% decrease in electricity sales for the quarter and year

to date, respectively

Factors Contributing to Quarterly and Year-to-Date

Earnings Variances

Unfavourable

-- The expiry of the PBR mechanism on December 31, 2011. During the first

half of 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 Application ("RRA"), which is subject to regulatory

approval, variances between actual electricity revenue, purchased power

costs and certain other costs and those used in determining customer

electricity rates are subject to full deferral account treatment and,

therefore, did not impact FortisBC Electric's earnings for the first

half of 2012.

-- Lower capitalized AFUDC, due to a lower asset base under construction in

2012

Favourable

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

NEWFOUNDLAND POWER

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

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended June 30 2012 2011 Variance 2012 2011 Variance

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

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

Electricity Sales

(GWh) 1,259 1,269 (10) 3,173 3,103 70

Revenue ($ millions) 130 133 (3) 322 316 6

Earnings ($ millions) 12 10 2 19 16 3

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

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

Factors Contributing to Quarterly Electricity Sales Variance

Unfavourable

-- Sunnier weather conditions, which reduced average energy consumption

Favourable

-- Growth in the number of customers

Factors Contributing to Year-to-Date Electricity Sales Variance

Favourable

-- Growth in the number of customers

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

construction combined with economic growth, which increased energy

consumption

Unfavourable

-- Sunnier weather conditions in the second quarter of 2012, which reduced

average energy consumption

Factors Contributing to Quarterly Revenue Variance

Unfavourable

-- Revenue during the first half of 2011 included amounts related to

support structure arrangements, which were in place with Bell Aliant

Inc. ("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.

-- The 0.8% decrease in electricity sales

Factors Contributing to Year-to-Date Revenue Variance

Favourable

-- The 2.3% 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 Earnings Variance

Favourable

-- Lower effective income taxes, primarily due to a lower allocation of

Part VI.1 tax to Newfoundland Power and a lower statutory income tax

rate

-- A higher allowed ROE. The cumulative approximate $1.5 million ($1

million after tax) impact of the increase in the allowed ROE, effective

January 1, 2012, was accrued in the second quarter of 2012 as a decrease

in operating expenses.

Unfavourable

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

2011, as discussed above

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

infrastructure

Factors Contributing to Year-to-Date Earnings Variance

Favourable

-- The same factors discussed above for the quarter

-- Electricity sales growth

Unfavourable

-- The same factors discussed above for the quarter

OTHER CANADIAN ELECTRIC UTILITIES (1)

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

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended June 30 2012 2011 Variance 2012 2011 Variance

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

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

Electricity Sales

(GWh) 563 562 1 1,208 1,216 (8)

Revenue ($ millions) 82 78 4 173 169 4

Earnings ($ millions) 5 6 (1) 12 12 -

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

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

(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly

includes Canadian Niagara Power, Cornwall Electric and Algoma Power.

Factors Contributing to Quarterly and Year-to-Date

Electricity Sales Variances

Favourable

-- Growth in the number of residential customers and an increase in the

number of residential customers using electricity for home heating on

Prince Edward Island ("PEI")

-- Higher average consumption by residential customers and commercial

customers in the agricultural processing sector on PEI, primarily during

the first quarter of 2012

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

-- Increased electricity sales on PEI, 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

Unfavourable

-- Decreased electricity sales in Ontario, for the reason discussed above

Factor Contributing to Quarterly Earnings Variance

Unfavourable

-- Higher operating expenses at FortisOntario, mainly during the second

quarter of 2012, largely due to an increase in employee-related costs

and the timing of expenses during 2012

Factors Contributing to Year-to-Date Earnings Variance

Favourable

-- Increased electricity sales on PEI

Unfavourable

-- The same factor discussed above for the quarter

REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)

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

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended June 30 2012 2011 Variance 2012 2011 Variance

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

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

Average US:CDN

Exchange Rate (2) 1.00 0.99 0.01 1.00 0.99 0.01

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

Electricity Sales

(GWh) 184 383 (199) 350 547 (197)

Revenue ($ millions) 67 85 (18) 130 160 (30)

Earnings ($ millions) 6 6 - 9 10 (1)

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

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

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

Fortis holds an approximate 60% controlling interest; wholly owned

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 "Key Trends and Risks - Expropriated Assets" and "Business Risk

Management - Investment in Belize" sections of the 2011 Annual MD&A and

Note 19 to the interim unaudited consolidated financial statements for

the three and six months ended June 30, 2012.


(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 and Year-to-Date

Electricity Sales Variances

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 2.6% for the quarter and 0.8% year to date.

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

conditioning load

Favourable

-- Growth in the number of customers on Grand Cayman and the Turks and

Caicos Islands

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

increased air conditioning load

-- A strong tourist season year to date on the Turks and Caicos Islands

Factors Contributing to Quarterly and Year-to-Date

Revenue Variances

Unfavourable

-- The expropriation of Belize Electricity and the resulting discontinuance

of the consolidation method of accounting for Belize Electricity,

effective June 20, 2011

-- 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

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

costs at Caribbean Utilities, due to an increase in the cost of fuel

-- Increased base electricity rates of 0.7% at Caribbean Utilities,

effective June 1, 2012

-- 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 $3 million for the quarter and $4 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

Factors Contributing to Quarterly Earnings Variance

Unfavourable

-- Higher depreciation expense and finance charges, excluding Belize

Electricity, largely due to investment in utility capital assets

-- Decreased electricity sales at Caribbean Utilities

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, due to the timing of

capital projects and decreased legal and certain administrative expenses

-- Increased electricity sales at Fortis Turks and Caicos

Factors Contributing to Year-to-Date Earnings Variance

Unfavourable

-- The same factors discussed above for the quarter

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

associated with the timing of capital projects and higher insurance

expense

Favourable

-- Lower energy supply costs at Fortis Turks and Caicos, for the same

reason discussed above for the quarter

-- Increased electricity sales at Fortis Turks and Caicos

-- Lower operating expenses at Caribbean Utilities, for the same reason

discussed above for the quarter, partially offset by increased employee-

related and pension costs

NON-REGULATED - FORTIS GENERATION (1)

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

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended June 30 2012 2011 Variance 2012 2011 Variance

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

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

Energy Sales (GWh) 87 90 (3) 175 166 9

Revenue ($ millions) 9 7 2 18 14 4

Earnings ($ millions) 5 2 3 10 5 5

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

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

(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.


Factors Contributing to Quarterly and Year-to-Date

Energy Sales Variances

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, due to higher rainfall

Factor Contributing to Quarterly and Year-to-Date

Revenue and Earnings Variances

Favourable

-- Increased production in Belize

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 generator was being repaired.

NON-REGULATED - FORTIS PROPERTIES (1)

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

Financial Highlights

(Unaudited) Quarter Year-to-Date

Periods Ended June 30 2012 2011 Variance 2012 2011 Variance

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

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

Hospitality - Revenue

per Available Room

("RevPAR") ($) 85.56 83.57 1.99 76.05 73.41 2.64

Real Estate - Occupancy

Rate (as at, %) 91.7 93.4 (1.7) 91.7 93.4 (1.7)

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

Hospitality Revenue ($

millions) 47 43 4 82 76 6

Real Estate Revenue ($

millions) 17 17 - 34 34 -

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

Total Revenue ($

millions) 64 60 4 116 110 6

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

Earnings ($ millions) 8 8 - 9 9 -

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

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

(1) Fortis Properties owns and operates 22 hotels, collectively

representing 4,300 rooms, in eight Canadian provinces and approximately

2.7 million square feet of commercial office and retail space primarily

in Atlantic Canada.


Factors Contributing to Quarterly and Year-to-Date

Revenue Variances

Favourable

-- A 2.4% and 3.6% increase in RevPAR at the Hospitality Division for the

quarter and year to date, respectively, driven by contribution from the

Hilton Suites Winnipeg Airport hotel, which was acquired in October 2011

-- Excluding the impact of the Hilton Suites Winnipeg Airport hotel, RevPAR

was $84.21 for the second quarter of 2012, an increase of 0.8% quarter

over quarter. The increase in RevPAR was due to an overall 2.3% increase

in the average daily room rate, partially offset by an overall 1.5%

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.

-- Excluding the impact of the Hilton Suites Winnipeg Airport hotel, RevPAR

was $74.53 year-to-date 2012, an increase of 1.5% period over period.

The increase in RevPAR was due to an overall 2.6% increase in the

average daily room rate, partially offset by an overall 1.1% 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

Favourable

-- Contribution from the Hilton Suites Winnipeg Airport hotel

Unfavourable

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

quarter of 2011

CORPORATE AND OTHER (1)

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

Financial Highlights (Unaudited)

Periods Ended June 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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

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

Revenue 7 7 - 13 13 -

Operating Expenses 3 3 - 6 5 1

Depreciation and

Amortization - - - 1 1 -

Other Income (Expenses),

Net (3) - (3) (8) - (8)

Finance Charges 12 12 - 23 26 (3)

Income Tax Recovery (1) (3) 2 (5) (6) 1

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

(10) (5) (5) (20) (13) (7)

Preference Share Dividends 12 12 - 23 23 -

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

Net Corporate and Other

Expenses (22) (17) (5) (43) (36) (7)

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

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

(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 non-regulated 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 and Year-to-Date

Net Corporate and Other Expenses Variances

Unfavourable

-- Increased other expenses, net of other income, driven by approximately

$4 million ($3 million after tax) and $8 million ($7 million after tax)

of costs incurred during the second quarter and first half of 2012,

respectively, related to the pending acquisition of CH Energy Group. The

increases were partially offset by net foreign exchange gains of

approximately $2 million and $0.5 million for second quarter and first

half of 2012, respectively, associated with the translation of the US

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

the Corporation's former investment in Belize Electricity.

-- Lower income tax recovery, primarily due to higher Part VI.1 tax

Favourable

-- Lower finance charges year to date, 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

REGULATORY HIGHLIGHTS

The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated gas and electric utilities for the first half of 2012 are summarized as follows.

NATURE OF REGULATION

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

Allowed Returns (%) Supportive Features

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

Regulated Regulatory Allowed Future or Historical

Utility Authority Common 2010 2011 2012 Test Year

Equity Used to Set Customer

(%) Rates

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

ROE COS/ROE

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

FEI British 40 9.50 9.50 9.50 FEI: Prior to January

Columbia 1, 2010, 50/50

Utilities sharing of earnings

Commission above or below the

("BCUC") allowed ROE under a

PBR mechanism that

expired on December

31, 2009 with a two-

year phase-out

FEVI BCUC 40 10.00 10.00 10.00

FEWI BCUC 40 10.00 10.00 10.00 ROEs established by

the BCUC

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

Future Test Year

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

FortisBC BCUC 40 9.90 9.90 9.90 COS/ROE

Electric

PBR mechanism for

2009 through 2011:

50/50 sharing of

earnings above or

below the allowed ROE

up to an achieved ROE

that is 200 basis

points above or below

the allowed ROE -

excess to deferral

account

ROE established by

the BCUC

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

Future Test Year

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

Fortis- Alberta 41 9.00 8.75 8.75 COS/ROE

Alberta Utilities

Commission ROE established by

("AUC") the AUC

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

Future Test Year

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

Newfound- Newfoundland 45 9.00 8.38 8.80 COS/ROE

land and Labrador +/- +/- +/-

Power Board of 50 bps 50 bps 50 bps The allowed ROE is

Commissioners set using an

of Public automatic adjustment

Utilities formula tied to long-

("PUB") term Canada bond

yields. The formula

was suspended for

2012.


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

Future Test Year

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

Maritime Island 40 9.75 9.75 9.75 COS/ROE

Electric Regulatory

and Appeals

Commission

("IRAC")

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

Future Test Year

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

Fortis- Ontario Canadian Niagara

Ontario Energy Power - COS/ROE

Board

("OEB")

Canadian 40 8.01 8.01 8.01 Algoma Power -

Niagara (1) COS/ROE and

Power subject to Rural and

Remote Rate

Algoma Power 40 8.57 9.85 9.85 Protection ("RRRP")

(1) Program

Franchise Cornwall Electric -

Agreement Price cap with

Cornwall commodity cost flow

Electric through

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

Canadian Niagara

Power - 2009

historical test year

for 2010, 2011 and

2012

Algoma Power - 2007

historical test year

for 2010; 2011 test

year for 2011 and

2012

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

ROA COS/ROA

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

Caribbean Electricity N/A 7.75 - 7.75 - 7.25 -

Utilities Regulatory 9.75 9.75 9.25 Rate-cap adjustment

Authority mechanism based on

("ERA") 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 Utilities N/A 17.50 17.50 17.50 COS/ROA

Turks make (2) (2) (2)

and Caicos annual

filings

to the

Interim If the actual ROA is

Government lower than the

of the Turks allowed ROA, due to

and Caicos additional costs

Caicos resulting from a

Islands hurricane or other

("Interim event, the Company

Government") 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

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

prices every three months and midstream costs annually, 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. The bundled

rate charged to FEVI customers includes a component to

recover approved gas costs and is set annually. In order

to ensure that the balance in the Commodity Cost

Reconciliation Account is recovered on a timely basis, FEI

and FEWI prepare and file quarterly calculations with the

BCUC to determine whether customer rate adjustments are

needed to reflect prevailing market prices for natural

gas. These rate adjustments ignore the temporal effect of

derivative valuation adjustments on the balance sheet and,

instead, reflect the forward forecast of gas costs over

the recovery period.


- Effective January 1, 2012, interim rates for residential

customers in the Lower Mainland, Fraser Valley and

Interior, North and Kootenay service areas 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 residential customers in

the Lower Mainland, Fraser Valley and Interior, North and

Kootenay service areas decreased by approximately 10% and

rates for residential customers at FEWI decreased

approximately 6%, following the BCUC's quarterly review of

commodity costs.


- Effective June 1, 2012, the delivery component of rates

decreased approximately 1.4% for FEI customers in the

Lower Mainland, Fraser Valley and Interior, North and

Kootenay service areas and for FEWI customers in Whistler,

as a result of the BCUC's final decision on the utilities'

2012-2013 RRAs.


- 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 October 2011 FEI filed an application for approval of

expenditures of approximately $5 million on facilities

required to provide thermal energy services to 19

buildings in the Delta School District located in the

Greater Vancouver area and to provide thermal energy

upgrades to the buildings over the next two years. When

completed, FEI would have owned, operated and maintained

the new thermal plants and charged the Delta School

District a single rate for thermal energy consumed. In

March 2012 the BCUC issued its decision granting a

Certificate of Public Convenience and Necessity ("CPCN")

related to the capital expenditures, on the condition that

FEI assign the related third-party contracts associated

with the above-noted project to a regulated company

affiliated with FEI. FEI has complied with the condition.

In June 2012 the BCUC approved the rate design for the

project.


- 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. In February 2012 FEI subsequently filed for a

CPCN to construct and operate CNG fuelling station

infrastructure, to be in service October 2012, along with

a long-term contract with a counterparty for the supply of

CNG in accordance with the approved general tariff. A

decision on the application was issued by the BCUC in

April 2012 and, subsequently, in May 2012, the Government

of British Columbia issued the Greenhouse Gas Reduction

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

(British Columbia). As a result of the GHG Regulation and

concerns FEI had with elements of the BCUC decision, FEI

sought reconsideration or variance of certain elements of

the decision. In July 2012 the BCUC issued a letter

confirming that the reconsideration application will be

heard.


- 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.

Regulatory review of the application is underway.


- 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 March 2012, provided for comment a

preliminary scoping document outlining the matters to be

examined by the GCOC Proceeding. In April 2012 the BCUC

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

preliminary timetable sets the evidence portion of the

GCOC Proceeding to take place through to early December

2012 with an oral hearing, if required, 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 RRAs. 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. The final rate increases were driven

by ongoing investment in energy infrastructure focused on

system integrity and reliability, and 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.


- In May 2012 FortisBC Alternative Energy Services

("FAES") applied for a CPCN to construct and operate a

thermal energy system and for approval of associated

customer rates. The thermal energy system comprises a geo-

exchange ground loop, heat pumps, high-efficiency natural

gas boilers and ancillary equipment to provide space

heating, cooling and domestic hot water to PCI Marine

Gateway development tenants through an exclusive energy

supply arrangement. The thermal energy system will be

owned, operated and maintained by FAES. A written

regulatory review process has been established, which will

conclude at the end of August 2012 with a decision

expected in fall 2012.


- Following the announcement of the GHG Regulation by the

Government of British Columbia, FEI announced an incentive

funding program to assist heavy-duty fleet 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 qualifying LNG-fuelled

vehicles, up to $30 million for LNG fuelling stations and

up to $12 million for CNG fuelling stations. Incentives

are expected to be awarded beginning in 2012 and will

cover up to 80% of the eligible incremental capital costs.

The eligible applicants for this program are commercial,

return-to-base fleet operators of heavy-duty trucks,

buses, vocational vehicles and marine vessels. FEI will be

applying to the BCUC in 2012 to determine how these costs

are to be recovered from FEI's natural gas utility

customers.


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

FortisBC - In June 2011 FortisBC Electric filed its 2012-2013 RRA,

Electric which included 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.

FortisBC Electric requested an interim 4% increase in

customer electricity rates, effective January 1, 2012, and

a 6.9% increase, 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.

The requested customer rates reflect an allowed ROE and

capital structure unchanged from 2011. In addition to a

continuation of deferral accounts and flow-through

treatments that existed under the PBR agreement, which

expired at the end of 2011, the 2012-2013 RRA proposes

deferral accounts and flow-through treatment for variances

between actual electricity revenue, purchased power costs

and certain other costs and those forecasted in

determining customer electricity rates.


- In November 2011 FortisBC Electric filed an updated

2012-2013 RRA to include updated financial estimates and

forecasts, resulting in a revised requested increase in

customer rates of 1.5%, effective January 1, 2012, and

6.5%, effective January 1, 2013. The revised application

assumes forecast midyear rate base of approximately $1,146

million for 2012 and $1,215 million for 2013. An oral

hearing process occurred in March 2012 and a decision is

expected in the third quarter of 2012. The interim,

refundable customer rate increase of 1.5%, effective

January 1, 2012, was approved by the BCUC pending a final

decision on the Company's 2012-2013 RRA.


- 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 hearing is expected to take place throughout

2012.


- In late July 2012, FortisBC Electric filed its Advanced

Metering Infrastructure ("AMI") application with the BCUC.

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. The

project was included in the utility's 2012-2013 CEP and

ISP.


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

FortisAlberta - In 2010 the AUC initiated a process to reform utility

rate regulation for distribution utilities in Alberta. The

AUC intends to introduce PBR-based distribution service

rates beginning in 2013 for a five-year term, with 2012

expected to be used as the base year. In July 2011

FortisAlberta, along with other distribution utilities

operating under the AUC's jurisdiction, submitted PBR

proposals to the AUC. The Company's submission outlined

its views as to how PBR should be implemented at

FortisAlberta. A hearing on the matter occurred during

April and May 2012, with a final argument submitted in

July 2012 and a decision on the matter expected in the

fourth quarter of 2012.


- 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 this 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.


- 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 (the "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

are not expected to be completed until September 2012.


- 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 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 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. The AUC did not approve the

continuation of the deferral of transmission volume

variances associated with FortisAlberta's AESO charges

deferral account. This item will be examined by the AUC in

a future proceeding. In its PBR proposal, FortisAlberta

provided evidence that the discontinuance of the deferral

of transmission volume variances be reversed at the outset

of PBR in 2013.


- 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.

- In June 2012 AESO filed two applications with the AUC:

(i) the AESO Customer Contribution Policy Application; and

(ii) the 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. A decision on the applications is not

expected until 2013.


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

Newfoundland - In March 2012 Newfoundland Power filed a Cost of Capital

Power 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 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 June 2012 Newfoundland Power filed an application

with the PUB requesting approval for its 2013 Capital

Expenditure Plan totalling approximately $83 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 is

primarily due to 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 increase in customer rates will not have

an impact on Newfoundland Power's earnings.


- As directed by the PUB, Newfoundland Power will be

filing a General Rate Application for 2013 customer

electricity rates during the third quarter of 2012.


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

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

Electric 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 in fall 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 in fall

2012.


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

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 current operating lease

agreement, at the purchase option price of approximately

$7 million on April 15, 2012. The purchase constitutes 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%. FortisOntario also filed with the COS Application

the quantification of an amount owing to customers related

to the disposal of an income tax-related regulatory

deferral account, as required by the OEB. The amount owing

to customers of approximately $1 million is expected to be

recognized by FortisOntario once a final decision is made

by the OEB on the amount owing, which is expected before

the end of 2012, and will have the impact of reducing

FortisOntario's earnings at that time.


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

Caribbean - In April 2012 the ERA approved Caribbean Utilities'

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

during the second half of 2012. A second increment of 18

MW of new generating capacity is required up to three

years later in 2017, contingent on economic and load

growth over the next few years.


- 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 during the second half 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. Two renewable

energy developers have been chosen to commence discussions

with Caribbean Utilities 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 are ongoing towards firm power

purchase agreements with the developers. The power

purchase agreements, however, are subject to ERA review

and approval. Upon regulatory approval of negotiated power

purchase agreements, construction will commence. It is

anticipated that the projects will be completed within a

two-year period.


- 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 in the utility's

targeted allowed ROA for 2012.


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

Fortis Turks - An independent review of the regulatory framework for

and Caicos the electricity sector in the Turks and Caicos Islands was

performed during the third quarter of 2011 on behalf of

the Interim Government. The purpose of the review was to:

(i) assess the effectiveness of the current regulatory

framework in terms of its administrative and economic

efficiency; (ii) assess the current and proposed

electricity costs and tariffs in the Turks and Caicos

Islands in relation to comparable regional and

international utilities; (iii) make recommendations for a

revised regulatory framework and Electricity Ordinance;

and (iv) make recommendations for the implementation and

operation of the revised regulatory framework. 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 are expected

to commence in the third quarter of 2012 with

implementation of any resulting changes in the regulatory

framework expected to occur at the end of 2012.


- 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 licenses issued for the

expanded service territory; and (iv) the discontinuance of

the government subsidization of the utility's South Caicos

operations.


- In March 2012 Fortis Turks and Caicos submitted its 2011

annual regulatory filing outlining the Company's

performance in 2011. Included in the filing were the

calculations, in accordance with the utility's licence, of

rate base of US$166 million for 2011 and cumulative

shortfall in achieving allowable profits of US$72 million

as at December 31, 2011.


- In April 2012 Fortis Turks and Caicos entered into a

Streetlight Takeover Agreement with the Interim Government

whereby the responsibility for the ownership, installation

and maintenance of all streetlights in the utility's

service territory was transferred to Fortis Turks and

Caicos.


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CONSOLIDATED FINANCIAL POSITION

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

Significant Changes in the Consolidated Balance Sheets (Unaudited) between

June 30, 2012 and December 31, 2011

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Balance Sheet Increase/

Account (Decrease) Explanation

($ millions)

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Cash and cash 144 The increase was driven by cash on hand at the

equivalents FortisBC Energy companies associated with a

portion of the proceeds received from an equity

injection by Fortis during the second quarter

of 2012 and seasonality of operations, and the

timing of cash payments at the Waneta Expansion

Limited Partnership (the "Waneta Partnership").

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Accounts (129) The decrease was primarily due to the impact of

receivable a seasonal decrease in sales mainly at the

FortisBC Energy companies and Newfoundland

Power.


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Inventories (27) The decrease was driven by the normal seasonal

reduction of gas in storage at the FortisBC

Energy companies.


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Regulatory (40) The decrease was mainly due to the change in

assets the deferral of the fair market value of the

-current and natural gas derivatives at the FortisBC Energy

long-term companies and in the deferral of AESO charges

at FortisAlberta, partially offset by higher

regulatory deferred income taxes and an

increase in the deferral of various costs, as

permitted by the regulators, mainly at the

FortisBC Energy companies.


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Other assets 29 The increase was mainly due to financing costs

associated with the Corporation's Subscription

Receipts offering, an increase in income taxes

receivable at Maritime Electric and an increase

in defined benefit pension assets at

Newfoundland Power.


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Utility capital 267 The increase primarily related to $473 million

assets invested in electricity and gas systems,

partially offset by depreciation and customer

contributions for the six months ended June 30,

2012.


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Short-term (78) The decrease was primarily due to a reduction

borrowings in borrowings at the FortisBC Energy companies

with a portion of the proceeds received from an

equity injection by Fortis during the second

quarter of 2012 and due to seasonality of

operations, partially offset by increased

borrowings at Caribbean Utilities, mainly to

repay maturing long-term debt.


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Accounts (127) The decrease was mainly due to: (i) the change

payable and in the fair market value of the natural gas

other current derivatives at the FortisBC Energy companies;

liabilities (ii) lower amounts owing for purchased natural

gas at the FortisBC Energy companies and

purchased power at Newfoundland Power,

associated with seasonality of operations; and

(iii) 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 at

FortisAlberta.


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Regulatory 92 The increase was mainly due to an overall

liabilities - increase in deferrals at the FortisBC Energy

current and companies and an increase in the AESO charges

long-term deferral at FortisAlberta. The increase in

deferrals at the FortisBC Energy companies was

due to: (i) an increase in the Midstream Cost

Reconciliation Account, as amounts collected in

customer rates were in excess of actual

midstream gas-delivery costs for the six months

ended June 30, 2012; (ii) an increase in the

Rate Stabilization Deferral Account, reflecting

amounts collected in customer rates in excess

of the cost of providing service at FEVI during

the six months ended June 30, 2012; and (iii)

the provisioning for non-ARO removal costs

commencing January 1, 2012.


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Deferred income 28 The increase was driven by tax timing

tax differences related to capital expenditures at

liabilities - the regulated utilities.


current and

long-term

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Long-term debt 180 The increase was primarily due to higher

(including borrowings under the Corporation's committed

current credit facility to finance advances to the

portion) Waneta Partnership and an equity injection into

the FortisBC Energy companies, in support of

energy infrastructure investment, and for

general corporate purposes. The increase was

partially offset by regularly scheduled debt

repayments at Fortis Properties, the FortisBC

Energy companies and Caribbean Utilities.


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Shareholders' 106 The increase was primarily due to net earnings

equity attributable to common equity shareholders for

(before non- the six months ended June 30, 2012, less common

controlling share dividends, and the issuance of common

interests) shares under the Corporation's dividend

reinvestment plan.


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Non-controlling 67 The increase was driven by advances from the

interests 49% non-controlling interests in the Waneta

Partnership and an approximate $12 million, or

15%, equity investment by two First Nations

bands in the LNG storage facility on Vancouver

Island.


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LIQUIDITY AND CAPITAL RESOURCES

The table below outlines the Corporation's consolidated sources and uses of cash for the three and six months ended June 30, 2012, as compared to the same periods in 2011, followed by a discussion of the nature of the variances in cash flows.

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Summary of Consolidated Cash Flows (Unaudited)

Periods Ended June 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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Cash, Beginning of Period 110 84 26 87 107 (20)

Cash Provided by (Used in):

Operating Activities 255 231 24 583 533 50

Investing Activities (273) (266) (7) (484) (483) (1)

Financing Activities 139 247 (108) 45 139 (94)

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Cash, End of Period 231 296 (65) 231 296 (65)

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Operating Activities: Cash flow from operating activities was $24 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 costs, mainly at the FortisBC Energy companies; and (iii) higher earnings. The favourable changes in working capital quarter over quarter were associated with changes in accounts receivable, partially offset by changes in accounts payable and other current liabilities. The increase was partially offset by unfavourable changes in long-term regulatory deferral accounts and a pension solvency deficit funding payment made by Newfoundland Power during the second quarter of 2012.

Cash flow from operating activities was $50 million higher year to date compared to the same period last year, due to the same factors discussed above for the quarter. Favourable changes in working capital year to date compared to the same period last year, however, were associated with changes in accounts receivable and current regulatory deferral accounts, partially offset by changes in inventories and accounts payable and other current liabilities.

Investing Activities: Cash used in investing activities was $7 million higher for the quarter and $1 million higher year to date. Lower capital spending at the FortisBC Energy companies, FortisBC Electric and the utilities in the Caribbean for the quarter and year to date was largely offset by an increase in capital spending at FortisAlberta for the quarter and year to date and an increase in capital spending related to the non-regulated Waneta Expansion year to date. 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 Government of Belize.

Cash used in investing activities also reflects the acquisition of the remaining assets of Port Colborne Hydro by FortisOntario in April 2012 for approximately $7 million.

Financing Activities: Cash provided by financing activities was $108 million lower quarter over quarter. The decrease was primarily due to: (i) lower proceeds from the issuance of common shares; (ii) higher repayments of long-term debt; (iii) lower proceeds from long-term debt; (iv) lower advances from non-controlling interests; (v) issue costs related to the June 2012 Subscription Receipts offering; and (vi) higher common share dividends. The decrease was partially offset by higher net borrowings under committed credit facilities classified as long term and lower repayments of short-term borrowings.

Cash provided by financing activities was $94 million lower year to date compared to the same period last year. The decrease was due to the same factors discussed above for the quarter; however, advances from non-controlling interests were higher year to date compared to the same period last year.

Net proceeds from short-term borrowings were $5 million for the quarter compared to net repayments of short-term borrowings of $102 million for the same quarter last year. Net repayments of short-term borrowings were $78 million year to date compared to $200 million for the same period last year. The changes for the quarter and year-to-date periods were driven by the FortisBC Energy companies and Caribbean Utilities.

Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net 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.

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

Periods Ended June 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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Caribbean Utilities (1) - 29 (29) - 29 (29)

Other - 1 (1) - 1 (1)

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Total - 30 (30) - 30 (30)

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(1) Issued in June 2011, 15-year US$11.25 million 4.85% and 20-year

US$18.75 million 5.10% unsecured notes. The net proceeds were used to

repay current installments on long-term debt and short-term borrowings

and to finance capital expenditures.


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

(Unaudited)

Periods Ended June 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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FortisBC Energy

Companies (17) (1) (16) (18) (2) (16)

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

Fortis Properties (22) (2) (20) (24) (4) (20)

Other (1) (4) 3 (2) (6) 4

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Total (53) (19) (34) (57) (24) (33)

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Net Borrowings Under Committed Credit Facilities (Unaudited)

Periods Ended June 30 Quarter Year-to-Date

($ millions) 2012 2011 Variance 2012 2011 Variance

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FortisAlberta 38 5 33 9 17 (8)

FortisBC Electric 17 7 10 8 7 1

Newfoundland Power 14 10 4 28 23 5

Corporate 154 36 118 185 26 159

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Total 223 58 165 230 73 157

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

Advances of approximately $27 million for the quarter and $56 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 $40 million received for the second quarter of 2011 and $57 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 issued 9.1 million common shares for gross proceeds of $300 million. The net proceeds of $288 million were used to repay borrowings under credit facilities and finance equity injections into the utilities in western Canada and the Waneta Expansion in support of infrastructure investment, and for general corporate purposes.

Common share dividends paid during the second quarter of 2012 were $42 million, net of $15 million in dividends reinvested, compared to $36 million, net of $15 million in dividends reinvested, paid during the same quarter of 2011. Common share dividends paid in the first half of 2012 were $86 million, net of $28 million in dividends reinvested, compared to $71 million, net of $31 million in dividends reinvested, paid in the first half of 2011. The dividend paid per common share for the first and second quarters of 2012 was $0.30 compared to $0.29 for the first and second quarters of 2011. The weighted average number of common shares outstanding for the second quarter and year to date was 189.6 million and 189.3 million, respectively, compared to 177.1 million and 175.8 million for the second quarter and year to date, respectively, in 2011.

CONTRACTUAL OBLIGATIONS

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

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Contractual Obligations (Unaudited) Due Due in Due in Due

As at June 30, 2012 within years years after

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

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Long-term debt 5,968 90 775 610 4,493

Capital lease and finance

obligations (1) 2,609 47 97 100 2,365

Waneta Partnership promissory note 72 - - - 72

Gas purchase contract obligations

(2) 255 175 80 - -

Power purchase obligations

FortisBC Electric 23 12 8 3 -

FortisOntario 387 47 99 104 137

Maritime Electric 162 41 79 28 14

Capital cost 452 17 35 36 364

Joint-use asset and shared service

agreements 63 4 8 6 45

Operating lease obligations 25 5 7 6 7

Defined benefit pension funding

contributions (3) 92 34 39 17 2

Other 7 1 2 - 4

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Total 10,115 473 1,229 910 7,503

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

mainly related to FortisBC Electric's Brilliant Power Purchase

Agreement and Brilliant Terminal Station

(2) Based on index prices as at June 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, 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 below.

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.

Caribbean Utilities has a primary fuel supply contract with a major supplier and is committed to purchasing approximately 80% of the Company's diesel fuel requirements from this supplier for the operation of Caribbean Utilities' diesel-powered generating plant. The contract contains an automatic renewal clause for the years 2010 through to 2012. The approximate quantity per the contract on an annual basis is 10.1 million imperial gallons for 2012. The Company has renewed the contract to July 2012 and is in the process of negotiating terms of a new contract.

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 resulting in 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 "Corporate Overview" 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 Contractual Obligations table above, refer to the "Capital Expenditure Program" section of this MD&A.

CAPITAL STRUCTURE

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

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

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Capital Structure

(Unaudited) As at

June 30, 2012 December 31, 2011

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

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Total debt and capital lease

and finance obligations

(net of cash) (1) (2) 6,253 56.4 6,296 57.1

Preference shares 912 8.2 912 8.3

Common shareholders' equity 3,929 35.4 3,823 34.6

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Total (3) 11,094 100.0 11,031 100.0

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

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

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

the capital structure was 54.6% as at June 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) an increase in cash; (ii) lower short-term borrowings; (iii) net earnings attributable to common equity shareholders, net of dividends; and (iv) common shares issued mainly under the Corporation's dividend reinvestment plan. 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 in support of utility infrastructure investment, 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. Also, S&P and DBRS 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, mainly reflecting 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.

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 $511 million in gross capital expenditures by segment for the first half of 2012 is provided in the following table.

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Gross Consolidated Capital Expenditures (Unaudited) (1)

Year-to-Date June 30, 2012

($ millions)

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Other

Regulated Total

FortisBC Electric Regulated

Energy Fortis FortisBC Newfoundland Utilities - Utilities -

Companies Alberta (2) Electric Power Canadian Canadian

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78 200 33 36 22 369

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

Gross Consolidated Capital Expenditures (Unaudited)

(1)

Year-to-Date June 30, 2012

($ millions)

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

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

Regulated

Electric Non-

Utilities - Regulated - Fortis

Caribbean Utility (3) Properties Total

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

22 105 15 511

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

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

(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

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 a record of 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. Most of the remaining $30 million of the project costs were incurred in the first half of 2012, with remaining smaller payments expected to be made during 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 $345 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 65% of the $5.5 billion capital program is expected to be incurred at the regulated electric utilities, driven by FortisAlberta and FortisBC Electric. Approximately 21% and 14% 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 June 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 "Corporate Overview" section 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 June 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 six months ended June 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 June 30, 2012 and are expected to remain compliant throughout the remainder of 2012.

CREDIT FACILITIES

As at June 30, 2012, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.5 billion, of which $2.0 billion was unused, including $815 million unused under the Corporation's $1 billion committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, with no one bank holding more than 20% of these facilities. Approximately $2.3 billion of the total credit facilities are committed facilities with maturities ranging from 2013 through 2017.

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

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Credit Facilities (Unaudited) As at

December

Regulated Fortis Corporate June 30, 31,

($ millions) Utilities Properties and Other 2012 2011

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Total credit

facilities 1,434 13 1,045 2,492 2,248

Credit facilities

utilized:

Short-term

borrowings (76) (5) - (81) (159)

Long-term debt

(including

current portion) (123) - (185) (308) (74)

Letters of credit

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

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Credit facilities

unused 1,168 8 859 2,035 1,949

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As at June 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 to August 2017 from August 2015. 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 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 agreement, amending the maturity date from August 2013 to August 2014. The amended 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 to August 2016 from September 2015 and a decrease in pricing. The amended credit facility agreement otherwise contains substantially similar terms and conditions as the previous credit facility agreement.

FINANCIAL INSTRUMENTS

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

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Financial Instruments

(Unaudited) As at

June 30, 2012 December 31, 2011

Carrying Estimated Carrying Estimated

($ millions) Value Fair Value Value Fair Value

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Waneta Partnership promissory

note 46 50 45 49

Long-term debt, including

current portion 5,968 7,394 5,788 7,172

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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 previous investment in Belize Electricity. The fair value of the Corporation's expropriated investment in Belize Electricity determined under the Government of Belize'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 Government of Belize to pay 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 was approximately $106 million as at June 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 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 is the US dollar. Belize Electricity's financial results were denominated in Belizean dollars, which are pegged to the US dollar.

As at June 30, 2012, the Corporation's corporately issued US$550 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 June 30, 2012, the Corporation had approximately US$13 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 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 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. As a result, the Corporation recognized a net foreign exchange gain in earnings of approximately $2 million and $0.5 million during the three and six months ended June 30, 2012, respectively.

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 June 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.

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Derivative Financial Instruments (Unaudited) As at

June 30, December 31,

2012 2011

Carrying Carrying

Number of Value (2) Value (2)

(Liability) Asset Maturity Contracts Volume (1) ($ millions) ($ millions)

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Foreign exchange

forward contract 2012 (3) - - - -

Fuel option

contracts 2013 4 4 (1) (1)

Natural gas

derivatives:

Swaps and

options 2014 90 39 (93) (135)

Gas purchase

contract

premiums 2014 46 91 3 -

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(1) The volume for fuel option contracts is reported in millions of gallons

and for natural gas derivatives is reported in petajoules.


(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.


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 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 as at June 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 are estimates of the amounts that would have to be received or paid 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 June 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 during the first half of 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 and 2013 customer gas delivery rates at the FortisBC Energy companies and for 2012 customer electricity distribution rates at FortisAlberta. The rate decisions help to reduce regulatory risk at the 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 is subject to certain regulatory and other approvals. Failure to obtain, or any delay in obtaining, such approvals could adversely impact the Corporation's ability to close the acquisition or the timing of such closing. In addition, there is risk that some, or all, of the expected benefits of the acquisition of CH Energy Group may fail to materialize or may not occur within the time periods anticipated by the Corporation. The realization of such benefits may be impacted by a number of factors, many of which are beyond the control of Fortis.

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. Also, S&P and DBRS 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, mainly reflecting 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. 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 June 30, 2012, the fair value of the Corporation's consolidated defined benefit pension plan assets was $826 million, up $41 million or 5.2%, 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 agreement expiring in March 2014 has been reached with regard to certain customer service employees. Discussions continue with regard to certain support and technical 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 POLICIES

Transition to US GAAP: Effective January 1, 2012, Fortis retroactively adopted US GAAP with the restatement of comparative reporting periods. The areas of most significant financial statement impacts upon adopting US GAAP include, but are not limited to the: (i) recognition of the funded status of defined benefit pension plans on the consolidated balance sheet and the inability to recognize regulatory assets or liabilities associated with other post-employment benefit ("OPEB") costs that are recovered on a cash basis; (ii) recognition of the Brilliant Power Purchase Agreement as a capital lease at FortisBC Electric; (iii) recognition of lease-in lease-out transactions at the FortisBC Energy companies as financing transactions with the corresponding assets recognized as utility capital assets and the sales proceeds accounted for as long-term finance obligations; (iv) reclassification of preference shares from long-term liabilities to shareholders' equity; and (v) the calculation and recognition of corporate income taxes based on enacted versus substantially enacted corporate income tax rates.

The above-noted items do not represent a complete list of differences between US GAAP and Canadian GAAP. Other less significant differences have also been identified and accounted for. A detailed description of the differences and a detailed reconciliation between the Corporation's annual audited consolidated Canadian GAAP and annual audited consolidated US GAAP financial statements for 2011 is disclosed in Note 38 to the Corporation's voluntarily filed annual audited consolidated US GAAP financial statements with accompanying notes thereto for the year ended December 31, 2011, with 2010 comparatives. A detailed reconciliation between the Corporation's interim unaudited consolidated 2011 Canadian GAAP and interim unaudited consolidated 2011 US GAAP financial statements is provided in the above-noted voluntarily filed document under the section "Supplemental Interim Consolidated Financial Statements for the Year Ended December 31, 2011 (Unaudited)".

The audited quantification and reconciliation of the Corporation's consolidated balance sheet as at December 31, 2011, prepared in accordance with US GAAP versus Canadian GAAP, may be summarized as follows.

-- Total assets as at December 31, 2011 increased by $603 million. The

increase was due primarily to increases in regulatory assets and utility

capital assets in accordance with US GAAP.

-- Total liabilities as at December 31, 2011 increased by $337 million. The

increase was due primarily to increases in long-term debt, capital lease

obligations and pension liabilities in accordance with US GAAP,

partially offset by the reclassification of preference shares from

liabilities to shareholders' equity.

-- Shareholders' equity as at December 31, 2011 increased by $266 million.

The increase was due primarily to the reclassification of preference

shares from liabilities to shareholders' equity in accordance with US

GAAP, partially offset by a reduction in retained earnings of

approximately $37 million and an increase in accumulated other

comprehensive loss of approximately $21 million. Approximately half of

the reduction in retained earnings resulted from higher corporate income

taxes and is expected to reverse in a future period once pending

Canadian federal income tax legislation is passed and proposed Part VI.1

tax rate changes are enacted.

There were no material adjustments to the Corporation's consolidated 2011 earnings under US GAAP due to the Corporation's continued ability to apply rate-regulated accounting policies.

The unaudited quantification and reconciliation of the Corporation's consolidated statement of earnings for the three and six months ended June 30, 2011, prepared in accordance with US GAAP versus Canadian GAAP, may be summarized as follows:

-- Three Months Ended June 30, 2011 (Unaudited): Consolidated net earnings

recognized in accordance with US GAAP increased by $3 million, from $69

million to $72 million. The increase was due primarily to the

reclassification of preference share dividends totaling $4 million, in

accordance with US GAAP, from finance charges to earnings attributable

to preference equity shareholders, partially offset by a reduction in

earnings attributable to common equity shareholders of $1 million.

-- Six months ended June 30, 2011 (Unaudited): Consolidated net earnings

recognized in accordance with US GAAP increased by $6 million, from $194

million to $200 million. The increase was due primarily to the

reclassification of preference share dividends totaling $8 million, in

accordance with US GAAP, from finance charges to earnings attributable

to preference equity shareholders, partially offset by a reduction in

earnings attributable to common equity shareholders of $2 million.

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 RRAs and subsequently approved by the BCUC in its April 2012 rate 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 forecast 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 six months ended June 30, 2012, non-ARO removal costs of $5 million and $10 million, respectively, were accrued as a part of depreciation expense. For the three and six months ended June 30, 2011, non-ARO removal costs of approximately $4 million and $8 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. Prospectively from January 1, 2012, the above-noted sharing of positive or negative variances is no longer in effect pursuant to the utility's filed 2012-2013 RRA, which is subject to BCUC approval and reflects primarily a COS rate-setting methodology. Beginning in 2012 variances between actual electricity revenue, purchased power costs and certain other 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, are not subject to the sharing mechanism that existed prior to 2012 and do not impact earnings in 2012.

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 on 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 consolidated financial statements for the three and six months ended June 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. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period they become known.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the first half of 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, in conjunction with an approved depreciation study and revenue requirements decision received in the second quarter of 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. 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 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.

As part of its 2012-2013 RRA and depreciation study filed with the BCUC, which are pending approval, FortisBC Electric's composite depreciation rate for utility capital assets decreased to 3.1% for 2012 from 3.2% for 2011, which has impacted consolidated depreciation expense. The change in the composite depreciation rate is subject to final approval by the BCUC.

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 has begun the appeal process associated with the 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 has filed a statement of defence. During the second quarter of 2010, FHI was added as a third party in all of the related actions. Following a mediation, in which FHI did not participate, FHI was advised that all matters have now been settled.

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 September 30, 2010 through June 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.

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Summary of Quarterly Results Net Earnings

(Unaudited) Attributable to

Common Equity

Revenue Shareholders Earnings per Common Share

Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)

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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

September 30, 2010 717 43 0.25 0.25

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A summary of the past eight quarters reflects the Corporation's continued organic growth, 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 and second quarters of 2012 were reduced by approximately $4 million and $3 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. Financial results from the fourth quarter ended December 31, 2011 reflected the acquisition of the Hilton Suites Winnipeg Airport 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 Central Vermont Public Service Corporation ("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 Government of Belize. For further information, refer to the "Key Trends and Risks - Expropriated Assets" and "Business Risk Management - Investment in Belize" sections of the 2011 Annual MD&A and Note 19 to the interim unaudited consolidated financial statements for the three and six months ended June 30, 2012. Revenue for the third quarter ended September 30, 2010 reflected the favourable cumulative retroactive impact associated with the 2010 revenue requirements decision at FortisAlberta.

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. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.

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 seasonality of gas consumption and the timing of certain operating expenses in 2012, rate base growth and higher gas transportation volumes to industrial customers, partially offset by lower-than-expected customer additions and lower capitalized AFUDC in 2012. The increase in corporate expenses was the result of approximately $4 million 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 associated with the previously hedged investment in Belize Electricity, 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 the forestry and mining sectors, 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.

September 2011/September 2010: Net earnings attributable to common equity shareholders were $56 million, or $0.30 per common share, for the third quarter of 2011 compared to earnings of $43 million, or $0.25 per common share, for the third quarter of 2010. The increase in earnings was mainly due to the $11 million after-tax fee paid to Fortis in July 2011, following the termination of the Merger Agreement between Fortis and CVPS. Results also improved due to rate base growth associated with energy infrastructure investment, mainly at the regulated utilities in western Canada, a net foreign exchange gain of approximately $2.5 million after tax associated with the previously hedged investment in Belize Electricity, lower-than-expected operating costs at the FortisBC Energy companies due to the timing of spending and capitalization of certain operating expenses in 2011 and a higher allowed ROE at Algoma Power. The above increases in earnings were partially offset by the impact of the regulator-approved reversal in the third quarter of 2010 of $4 million after tax of project overrun costs previously expensed in 2009 related to the conversion of Whistler customer appliances from propane to natural gas, the expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility since June 2011, lower capitalized AFUDC at FortisBC Electric, lower non-regulated hydroelectric production in Belize and the timing of recording the 2010 revenue requirements decision at FortisAlberta. The favourable cumulative impact of the decision was recorded in the third quarter of 2010 when the decision was received. 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 third 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 during the first half of 2012, other than the above-noted change, there was no change in the Corporation's internal controls over financial reporting that has materially, or is 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.

The pending acquisition of CH Energy Group is expected to close by the end of the first quarter of 2013. 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.

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.

OUTSTANDING SHARE DATA

As at July 30, 2012, the Corporation had issued and outstanding approximately 190.0 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 voting rights.

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 July 30, 2012 is as follows.

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

Conversion of Securities into Common Shares (Unaudited)

As at July 30, 2012 Number of

Common Shares

Security (millions)

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

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

Stock Options 5.2

First Preference Shares, Series C 4.0

First Preference Shares, Series E 6.3

Subscription Receipts 18.5

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

Total 34.0

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

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

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.

Interim Consolidated Financial Statements

For the three and six months ended June 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)

June 30, December 31,

2012 2011

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

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

(Note 21)

ASSETS

Current assets

Cash and cash equivalents $ 231 $ 87

Accounts receivable 509 638

Prepaid expenses 25 19

Inventories 107 134

Regulatory assets (Note 3) 122 219

Deferred income taxes 33 24

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

1,027 1,121

Other assets 213 184

Regulatory assets (Note 3) 1,457 1,400

Deferred income taxes 6 8

Utility capital assets 9,235 8,968

Income producing properties 599 594

Intangible assets 324 325

Goodwill (Note 12) 1,570 1,565

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

$ 14,431 $ 14,165

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

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

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities

Short-term borrowings (Note 17) $ 81 $ 159

Accounts payable and other current liabilities 863 990

Regulatory liabilities (Note 3) 82 43

Current installments of long-term debt 90 103

Current installments of capital lease and

finance obligations 7 7

Deferred income taxes 2 5

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

1,125 1,307

Other liabilities 572 573

Regulatory liabilities (Note 3) 608 555

Deferred income taxes 704 673

Long-term debt 5,878 5,685

Capital lease and finance obligations 428 429

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

9,315 9,222

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

Shareholders' equity

Common shares (a)(Note 4) 3,071 3,036

Preference shares 912 912

Additional paid-in capital 15 14

Accumulated other comprehensive loss (94) (95)

Retained earnings 937 868

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

4,841 4,735

Non-controlling interests (Note 5) 275 208

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

5,116 4,943

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

$ 14,431 $ 14,165

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

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

(a) no par value: unlimited authorized shares; 190.0 million and 188.8

million issued and outstanding as at June 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 June 30

(in millions of Canadian dollars, except per share amounts)

Quarter Ended Six Months Ended

2012 2011 2012 2011

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

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

Revenue $ 792 $ 846 $ 1,941 $ 2,005

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

Expenses

Energy supply costs 291 358 857 961

Operating 204 209 418 419

Depreciation and

amortization 114 102 233 205

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

609 669 1,508 1,585

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

Operating income 183 177 433 420

Other income

(expenses), net (Note

8) - 4 (3) 12

Finance charges (Note

9) 92 93 183 185

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

Earnings before income

taxes 91 88 247 247

Income taxes (Note 10) 14 16 37 47

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

Net earnings $ 77 $ 72 $ 210 $ 200

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

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

Net earnings

attributable to:

Non-controlling

interests $ 3 $ 3 $ 4 $ 4

Preference equity

shareholders 12 12 23 23

Common equity

shareholders 62 57 183 173

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

$ 77 $ 72 $ 210 $ 200

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

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

Earnings per common

share (Note 11)

Basic $ 0.33 $ 0.32 $ 0.97 $ 0.98

Diluted $ 0.33 $ 0.32 $ 0.95 $ 0.97

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

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

See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.


Consolidated Statements of Comprehensive Income (Unaudited)

For the periods ended June 30

(in millions of Canadian dollars)

Quarter Ended Six Months Ended

2012 2011 2012 2011

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

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

Net earnings $ 77 $ 72 $ 210 $ 200

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

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

Other comprehensive

income (loss)

Unrealized foreign

currency

translation

gains (losses),

net of hedging

activities and

tax 2 - - (3)

Reclassification of

unrealized foreign

currency

translation

losses, net of

hedging

activities and

tax, related to

Belize

Electricity - 17 - 17

Unrealized employee

future benefits

gains,

net of tax - - 1 -

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

2 17 1 14

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

Comprehensive income$ 79 $ 89 $ 211 $ 214

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

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

Comprehensive income

attributable to:

Non-controlling

interests $ 3 $ 3 $ 4 $ 4

Preference equity

shareholders 12 12 23 23

Common equity

shareholders 64 74 184 187

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

$ 79 $ 89 $ 211 $ 214

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

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

See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.


Consolidated Statements of Cash Flows (Unaudited)

For the periods ended June 30

(in millions of Canadian dollars)

Quarter Ended Six Months Ended

2012 2011 2012 2011

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

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

Operating activities

Net earnings $ 77 $ 72 $ 210 $ 200

Adjustments to

reconcile net

earnings to net

cash provided by

operating

activities:

Depreciation -

utility capital

assets and income

producing

properties 94 94 201 189

Amortization -

intangible assets 10 9 21 18

Amortization -

other 10 (1) 11 (2)

Deferred income

taxes 3 1 8 (1)

Accrued employee

future benefits (11) 5 (7) 9

Equity component

of allowance for

funds used

construction

(Note 8) (1) (3) (3) (8)

Other 3 5 (11) 4

Change in long-term

regulatory assets

and liabilities (13) - (9) 18

Change in non-cash

operating working

capital (Note 14) 83 49 162 106

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

255 231 583 533

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

Investing activities

Change in other

assets and other

liabilities - - 4 (2)

Capital expenditures

- utility capital

assets (262) (268) (473) (486)

Capital expenditures

- income producing

properties (10) (6) (15) (9)

Capital expenditures

- intangible assets (10) (12) (23) (23)

Contributions in aid

of construction 16 19 30 31

Proceeds on sale of

utility capital

assets and income

producing

properties - 1 - 6

Business acquisition

(Note 12) (7) - (7) -

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

(273) (266) (484) (483)

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

Financing activities

Change in short-term

borrowings 5 (102) (78) (200)

Proceeds from long-

term debt, net of

issue costs - 30 - 30

Repayments of long-

term debt and

capital lease and

finance obligations (53) (19) (57) (24)

Net borrowings under

committed credit

facilities 223 58 230 73

Advances from non-

controlling

interests 28 40 69 57

Subscription

Receipts issue

costs (Note 4) (12) - (12) -

Issue of common

shares, net of

costs and dividends

reinvested 4 290 6 301

Dividends

Common shares, net

of dividends

reinvested (42) (36) (86) (71)

Preference shares (12) (12) (23) (23)

Subsidiary

dividends paid to

non-controlling

interests (2) (2) (4) (4)

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

139 247 45 139

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

Change in cash and

cash equivalents 121 212 144 189

Cash and cash

equivalents,

beginning of period 110 84 87 107

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

Cash and cash

equivalents, end of

period $ 231 $ 296 $ 231 $ 296

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

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

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 June 30

(in millions of Canadian dollars)

Accumulated

Additional Other

Common Preference Paid-in Comprehensive Retained

Shares Shares Capital Loss Earnings

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

(Note 4)

As at December

31, 2011 $ 3,036 $ 912 $ 14 $ (95)$ 868

Net earnings - - - - 206

Other

comprehensive

income - - - 1 -

Common share

issues 35 - - - -

Stock-based

compensation - - 1 - -

Advances from

non-

controlling

interests - - - - -

Foreign

currency

translation

impacts - - - - -

Subsidiary

dividends paid

to non-

controlling

interests - - - - -

Dividends

declared on

common shares

($0.60 per

share) - - - - (114)

Dividends

declared on

preference

shares - - - - (23)

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

As at June 30,

2012 $ 3,071 $ 912 $ 15 $ (94)$ 937

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

As at December

31, 2010 $ 2,575 $ 912 $ 12 $ (108)$ 774

Net earnings - - - - 196

Other

comprehensive

income - - - 14 -

Common share

issues 337 - - - -

Stock-based

compensation - - 1 - -

Advances from

non-

controlling

interests - - - - -

Foreign

currency

translation

impacts - - - -

Subsidiary

dividends paid

to non-

controlling

interests - - - - -

Expropriation

of Belize

Electricity

(Notes 16, 17

and 19)

Dividends

declared on

common shares

($0.58 per

share) - - - - (105)

Dividends

declared on

preference

shares - - - - (23)

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

As at June 30,

2011 $ 2,912 $ 912 $ 13 $ (94)$ 842

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

Non-

Controlling

Interests Total Equity

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

As at December

31, 2011 $ 208 $ 4,943

Net earnings 4 210

Other

comprehensive

income - 1

Common share

issues - 35

Stock-based

compensation - 1

Advances from

non-

controlling

interests 69 69

Foreign

currency

translation

impacts (2) (2)

Subsidiary

dividends paid

to non-

controlling

interests (4) (4)

Dividends

declared on

common shares

($0.60 per

share) - (114)

Dividends

declared on

preference

shares - (23)

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

As at June 30,

2012 $ 275 $ 5,116

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

As at December

31, 2010 $ 162 $ 4,327

Net earnings 4 200

Other

comprehensive

income - 14

Common share

issues - 337

Stock-based

compensation - 1

Advances from

non-

controlling

interests 57 57

Foreign

currency

translation

impacts (3) (3)

Subsidiary

dividends paid

to non-

controlling

interests (4) (4)

Expropriation

of Belize

Electricity

(Notes 16, 17

and 19) (38) (38)

Dividends

declared on

common shares

($0.58 per

share) - (105)

Dividends

declared on

preference

shares - (23)

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

As at June 30,

2011 $ 178 $ 4,763

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

See accompanying Notes to Interim Consolidated Financial Statements

FORTIS INC.


NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

For the three and six months ended June 30, 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:

a. 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.

b. 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.

c. Regulated Electric Utilities - Caribbean: Includes Caribbean Utilities,

in which Fortis holds an approximate 60% controlling ownership interest;

wholly owned Fortis Turks and Caicos, which includes FortisTCI Limited

and Atlantic Equipment & Power (Turks and Caicos) Ltd.; and Belize

Electricity, in which Fortis held an approximate 70% controlling

ownership interest 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. FortisBC Electric is assuming 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").

NON-REGULATED - FORTIS PROPERTIES

Fortis Properties owns and operates 22 hotels, collectively representing 4,300 rooms, in eight Canadian provinces, and approximately 2.7 million square feet of commercial office and retail space primarily in Atlantic Canada.

CORPORATE AND OTHER

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

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 ("FERC") and the Committee on Foreign Investment in the United States in July 2012.

The acquisition is also subject to certain other approvals, including approval by the New York State Public Service Commission (the "NYSPSC"), and satisfaction of customary closing conditions. The NYSPSC is currently reviewing the application for approval of the transaction 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.

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 2012 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. 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 six months ended June 30, 2012, except as described below with respect to capital asset depreciation.

An evaluation of subsequent events through July 30, 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 June 30, 2012.

All amounts are presented in Canadian dollars unless otherwise stated.

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 on 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 six months ended June 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 Applications ("RRAs") and subsequently approved by the regulator in its April 2012 rate 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 forecast 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 six months ended June 30, 2012, non-ARO removal costs of approximately $5 million and $10 million, respectively, were accrued as part of depreciation expense. For the three and six months ended June 30, 2011, non-ARO removal costs of approximately $4 million and $8 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. Prospectively from January 1, 2012, the above-noted sharing of positive or negative variances is no longer in effect pursuant to the utility's filed 2012-2013 RRA, which is subject to regulatory approval and reflects primarily a cost of service rate-setting methodology. Beginning in 2012 variances between actual electricity revenue, purchased power costs and certain other 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, are not subject to the sharing mechanism that existed prior to 2012 and do not impact earnings in 2012.

Change in Estimates - Capital Asset Depreciation

Changes in regulator-approved depreciation rates at FortisAlberta, in conjunction with an approved depreciation study and revenue requirements decision received in the second quarter of 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. 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.

As part of its 2012-2013 RRA and depreciation study filed with the regulator, which are pending approval, FortisBC Electric's composite depreciation rate for utility capital assets decreased to 3.1% for 2012 from 3.2% for 2011, which has impacted consolidated depreciation expense. The change in the composite depreciation rate is subject to final approval by the regulator.

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

June 30, December 31,

($ millions) 2012 2011

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

Regulatory assets

Deferred income taxes 664 630

Employee future benefits 413 428

Deferred lease costs - FortisBC Electric 73 70

Rate stabilization accounts - electric

utilities 54 55

Rate stabilization accounts - FortisBC Energy

companies 53 105

Replacement energy deferral - Point Lepreau

(1) 47 47

Deferred energy management costs 42 36

Deferred operating overhead costs 27 22

Customer Care Enhancement Project cost

deferral 25 13

Income taxes recoverable on other post-

employment benefit ("OPEB") plans 23 22

Deferred net losses on disposal of utility

capital assets 22 23

Whistler pipeline contribution deferral 16 16

Pension cost variance deferral 13 10

Alternative energy projects cost deferral 11 8

Deferred development costs for capital 10 11

Deferred costs - smart meters 8 8

Alberta Electric System Operator ("AESO")

charges deferral - 44

Other regulatory assets 78 71

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

Total regulatory assets 1,579 1,619

Less: current portion (122) (219)

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

Long-term regulatory assets 1,457 1,400

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

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

(1) New Brunswick Power Point Lepreau Nuclear Generating Station

As at

June 30, December 31,

($ millions) 2012 2011

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

Regulatory liabilities

Non-ARO removal cost provision 370 354

Rate stabilization accounts - FortisBC Energy

companies 187 127

Rate stabilization accounts - electric utilities 40 33

AESO charges deferral 22 12

Deferred income taxes 16 9

Deferred interest 9 10

Income tax variance deferral 8 12

Performance-based rate-setting incentive

liabilities 8 7

Southern Crossing Pipeline deferral 6 8

Unrecognized net gains on disposal of utility

capital assets - 6

Other regulatory liabilities 24 20

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

Total regulatory liabilities 690 598

Less: current portion (82) (43)

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

Long-term regulatory liabilities 608 555

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

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

4. COMMON SHARES

Common shares issued during the period were as follows:

Quarter Ended Year-to-Date

June 30, 2012 June 30, 2012

Number of Number of

Shares Amount Shares Amount

(in thousands) ($ millions) (in thousands) ($ millions)

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

Balance, beginning

of period 189,274 3,050 188,828 3,036

Dividend

Reinvestment

Plan 495 15 895 28

Consumer Share

Purchase Plan 11 1 24 1

Stock Option

Plans 187 5 220 6

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

Balance, end of

period 189,967 3,071 189,967 3,071

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

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

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. (collectively the "Underwriters"), resulting in gross proceeds of approximately $601 million. The gross proceeds from the sale of the Subscription Receipts are being held by an escrow agent, pending receipt of all required approvals and satisfaction of closing conditions 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 share purchase agreement 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

June 30, December 31,

($ millions) 2012 2011

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

Waneta Expansion Limited Partnership ("Waneta

Partnership") 184 128

Caribbean Utilities 72 73

Mount Hayes Limited Partnership (Note 18) 12 -

Preference shares of Newfoundland Power 7 7

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

275 208

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

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

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 to grant 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 six months ended June 30, 2012, stock-based compensation expense of approximately $1.5 million and $3 million, respectively, was recognized ($1.5 million and $3 million for the three and six months ended June 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 June 30

Defined Benefit

Pension Plans OPEB Plans

($ millions) 2012 2011 2012 2011

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

Components of net

benefit cost:

Service costs 7 5 1 1

Interest costs 11 12 3 3

Expected return on plan

assets (13) (12) - -

Amortization of

actuarial losses 7 5 1 1

Amortization of past

service costs/plan

amendments - - (1) (1)

Amortization of

transitional obligation 1 - 1 -

Regulatory adjustments (5) (2) - 1

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

Net benefit cost 8 8 5 5

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

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

Year-to-Date June 30

Defined Benefit

Pension Plans OPEB Plans

($ millions) 2012 2011 2012 2011

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

Components of net

benefit cost:

Service costs 14 10 3 2

Interest costs 23 24 6 6

Expected return on plan

assets (25) (24) - -

Amortization of

actuarial losses 13 10 2 2

Amortization of past

service costs/plan

amendments - - (2) (2)

Amortization of

transitional obligation 1 - 1 -

Regulatory adjustments (6) (4) 1 2

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

Net benefit cost 20 16 11 10

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

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

For the three and six months ended June 30, 2012, the Corporation expensed $3 million and $7 million, respectively ($4 million and $8 million for the three and six months ended June 30, 2011, respectively) related to defined contribution pension plans.

8. OTHER INCOME (EXPENSES), NET

Quarter Ended Year-to-Date

June 30 June 30

($ millions) 2012 2011 2012 2011

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

Net foreign exchange gain 2 - - -

Equity component of

allowance for funds used

during construction 1 3 3 8

Interest income 1 1 2 2

Acquisition-related

expenses (4) - (8) -

Other income, net of

expenses - - - 2

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

- 4 (3) 12

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

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

The net foreign exchange gain for the three and six months ended June 30, 2012 includes approximately $2 million and $0.5 million, respectively, related to the translation into Canadian dollars of the Corporation's long-term other asset associated with Belize Electricity (Notes 17 and 19).

The acquisition-related expenses are associated with the pending acquisition of CH Energy Group (Notes 1 and 18).

9. FINANCE CHARGES

Quarter Ended Year-to-Date

June 30 June 30

($ millions) 2012 2011 2012 2011

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

Interest:

Long-term debt and

finance and capital

lease obligations 93 91 187 184

Short-term borrowings

and other finance

charges 2 5 3 9

Debt component of

allowance for funds

used during

construction (3) (3) (7) (8)

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

92 93 183 185

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

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

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

June 30 June 30

($ millions, except as

noted) 2012 2011 2012 2011

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

Combined Canadian

federal and provincial

statutory income tax

rate 29.0% 30.5% 29.0% 30.5%

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

Statutory income tax

rate applied to

earnings before income

taxes 26 27 72 75

Difference between

Canadian statutory

income tax rate and

rates applicable to

foreign subsidiaries (5) (3) (7) (5)

Difference in Canadian

provincial statutory

income tax rates

applicable to

subsidiaries in

different Canadian

jurisdictions (3) (3) (8) (8)

Items capitalized for

accounting purposes but

expensed for income tax

purposes (9) (12) (28) (28)

Difference between

capital cost allowance

and amounts claimed for

accounting purposes 1 4 4 6

Non-deductible expenses 2 - 3 1

Difference between

enacted and

substantially enacted

income tax rates

associated with Part

VI.1 tax 3 1 3 2

Difference between

employee future

benefits paid and

amounts expensed for

accounting purposes 1 - 1 -

Other (2) 2 (3) 4

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

Income taxes 14 16 37 47

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

Effective income tax

rate 15.4% 18.2% 15.0% 19.0%

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

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

As at June 30, 2012, the Corporation had approximately $85 million (December 31, 2011 - $86 million) in non-capital and capital loss carryforwards, of which $13 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 June 30

2012 2011

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

Earnings Weighted Earnings Weighted

to Common Average to Common Average

Shareholders Shares Shareholders Shares

(in (in

($ millions) millions) EPS ($ millions) millions) EPS

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

Basic EPS 62 189.6 $ 0.33 57 177.1 $ 0.32

Effect of

potential

dilutive

securities:

Stock

Options - 0.9 - 1.2

Preference

Shares 4 10.3 4 10.1

Convertible

Debentures - - 1 1.4

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

66 200.8 62 189.8

Deduct anti-

dilutive

impacts:

Preference

Shares (4) (10.3) (4) (10.1)

Convertible

Debentures - - (1) (1.4)

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

Diluted EPS 62 190.5 $ 0.33 57 178.3 $ 0.32

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

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

Year-to-Date June 30

2012 2011

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

Earnings Weighted Earnings Weighted

to Common Average to Common Average

Shareholders Shares Shareholders Shares

(in (in

($ millions) millions) EPS ($ millions) millions) EPS

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

Basic EPS 183 189.3 $ 0.97 173 175.8 $ 0.98

Effect of

potential

dilutive

securities:

Stock Options - 0.9 - 1.2

Preference

Shares 8 10.3 8 10.1

Convertible

Debentures - - 1 1.4

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

Diluted EPS 191 200.5 $ 0.95 182 188.5 $ 0.97

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

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

12. BUSINESS ACQUISITION

In April 2012 FortisOntario exercised its option, under the terms of a 10-year operating lease agreement with the City of Port Colborne (the "City") 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, and now through ownership of the previously leased assets, FortisOntario operates and maintains the City'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 constitutes 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.

13. SEGMENTED INFORMATION

Information by reportable segment is as follows:

REGULATED

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

Gas

Utilities Electric Utilities

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

FortisBC

Quarter Ended Energy Total

Companies Newfound-

June 30, 2012 - Fortis FortisBC land Other Electric Electric

Carib-

($ millions) Canadian Alberta Electric Power Canadian Canadian bean

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

Revenue 264 110 67 130 82 389 67

Energy supply

costs 109 - 13 78 51 142 39

Operating

expenses 63 37 21 17 12 87 9

Depreciation

and

amortization 40 30 12 11 6 59 9

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

Operating

income 52 43 21 24 13 101 10

Other income

(expenses),

net 1 - - 1 - 1 1

Finance

charges 36 17 10 9 6 42 3

Income tax

expense

(recovery) 3 - 2 4 2 8 -

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

Net earnings

(loss) 14 26 9 12 5 52 8

Non-

controlling

interests 1 - - - - - 2

Preference

share

dividends - - - - - - -

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

Net earnings

(loss)

attributable

to common

equity

shareholders 13 26 9 12 5 52 6

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

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

Goodwill 913 227 221 - 67 515 142

Identifiable

assets 4,605 2,543 1,671 1,251 692 6,157 737

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

Total assets 5,518 2,770 1,892 1,251 759 6,672 879

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

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

Gross capital

expenditures

(1) 32 121 16 21 13 171 12

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

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

Quarter Ended

June 30, 2011

($ millions)

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

Revenue 319 103 65 133 78 379 85

Energy supply

costs 170 - 11 80 47 138 53

Operating

expenses 70 36 21 17 11 85 11

Depreciation

and

amortization 27 33 12 11 6 62 8

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

Operating

income 52 34 21 25 14 94 13

Other income

(expenses),

net 3 - - - - - 1

Finance

charges 36 16 9 9 6 40 4

Income tax

expense

(recovery) 4 - 3 6 2 11 1

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

Net earnings

(loss) 15 18 9 10 6 43 9

Non-

controlling

interests - - - - - - 3

Preference

share

dividends - - - - - - -

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

Net earnings

(loss)

attributable

to common

equity

shareholders 15 18 9 10 6 43 6

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

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

Goodwill 913 227 221 - 63 511 132

Identifiable

assets 4,380 2,244 1,613 1,233 661 5,751 673

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

Total assets 5,293 2,471 1,834 1,233 724 6,262 805

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

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

Gross capital

expenditures

(1) 65 86 23 17 11 137 19

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

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

NON-REGULATED

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

Quarter Ended Inter-

June 30, 2012 Fortis Fortis Corporate segment

($ millions) Generation Properties and Other eliminations Consolidated

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

Revenue 9 64 7 (8) 792

Energy supply

costs 1 - - - 291

Operating

expenses 1 42 3 (1) 204

Depreciation

and

amortization 1 5 - - 114

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

Operating

income 6 17 4 (7) 183

Other income

(expenses),

net - - (3) - -

Finance

charges - 6 12 (7) 92

Income tax

expense

(recovery) 1 3 (1) - 14

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

Net earnings

(loss) 5 8 (10) - 77

Non-

controlling

interests - - - - 3

Preference

share

dividends - - 12 - 12

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

Net earnings

(loss)

attributable

to common

equity

shareholders 5 8 (22) - 62

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

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

Goodwill - - - - 1,570

Identifiable

assets 653 620 501 (412) 12,861

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

Total assets 653 620 501 (412) 14,431

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

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

Gross capital

expenditures

(1) 57 10 - - 282

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

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

Quarter Ended

June 30, 2011

($ millions)

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

Revenue 7 60 7 (11) 846

Energy supply

costs 1 - - (4) 358

Operating

expenses 1 40 3 (1) 209

Depreciation

and

amortization 1 4 - - 102

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

Operating

income 4 16 4 (6) 177

Other income

(expenses),

net - - - - 4

Finance

charges 1 6 12 (6) 93

Income tax

expense

(recovery) 1 2 (3) - 16

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

Net earnings

(loss) 2 8 (5) - 72

Non-

controlling

interests - - - - 3

Preference

share

dividends - - 12 - 12

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

Net earnings

(loss)

attributable

to common

equity

shareholders 2 8 (17) - 57

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

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

Goodwill - - - - 1,556

Identifiable

assets 473 581 675 (422) 12,111

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

Total assets 473 581 675 (422) 13,667

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

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

Gross capital

expenditures

(1) 59 6 - - 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.


REGULATED

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

Gas

Utilities Electric Utilities

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

FortisBC

Year-to-Date Energy Total

Companies Newfound-

June 30, 2012 - Fortis FortisBC land Other Electric Electric

Carib-

($ millions) Canadian Alberta Electric Power Canadian Canadian bean

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

Revenue 812 218 154 322 173 867 130

Energy supply

costs 411 - 38 220 109 367 79

Operating

expenses 133 76 42 37 24 179 17

Depreciation

and

amortization 80 65 24 22 13 124 16

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

Operating

income 188 77 50 43 27 197 18

Other income

(expenses),

net 1 2 - 1 - 3 1

Finance

charges 71 32 20 18 11 81 7

Income tax

expense

(recovery) 22 - 5 7 4 16 -

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

Net earnings

(loss) 96 47 25 19 12 103 12

Non-

controlling

interests 1 - - - - - 3

Preference

share

dividends - - - - - - -

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

Net earnings

(loss)

attributable

to common

equity

shareholders 95 47 25 19 12 103 9

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

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

Goodwill 913 227 221 - 67 515 142

Identifiable

assets 4,605 2,543 1,671 1,251 692 6,157 737

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

Total assets 5,518 2,770 1,892 1,251 759 6,672 879

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

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

Gross capital

expenditures

(1) 78 200 33 36 22 291 22

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

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

Year-to-Date

June 30, 2011

($ millions)

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

Revenue 893 203 148 316 169 836 160

Energy supply

costs 514 - 34 214 107 355 99

Operating

expenses 144 71 39 37 23 170 22

Depreciation

and

amortization 54 66 23 21 12 122 17

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

Operating

income 181 66 52 44 27 189 22

Other income

(expenses),

net 6 3 1 - - 4 2

Finance

charges 70 29 19 18 11 77 9

Income tax

expense

(recovery) 27 1 6 10 4 21 1

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

Net earnings

(loss) 90 39 28 16 12 95 14

Non-

controlling

interests - - - - - - 4

Preference

share

dividends - - - - - - -

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

Net earnings

(loss)

attributable

to common

equity

shareholders 90 39 28 16 12 95 10

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

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

Goodwill 913 227 221 - 63 511 132

Identifiable

assets 4,380 2,244 1,613 1,233 661 5,751 673

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

Total assets 5,293 2,471 1,834 1,233 724 6,262 805

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

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

Gross capital

expenditures

(1) 113 171 53 31 19 274 40

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

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

NON-REGULATED

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

Year-to-Date Inter-

June 30, 2012 Fortis Fortis Corporate segment

($ millions) Generation Properties and Other eliminations Consolidated

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

Revenue 18 116 13 (15) 1,941

Energy supply

costs 1 - - (1) 857

Operating

expenses 4 82 6 (3) 418

Depreciation

and

amortization 2 10 1 - 233

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

Operating

income 11 24 6 (11) 433

Other income

(expenses),

net 1 - (8) (1) (3)

Finance

charges 1 12 23 (12) 183

Income tax

expense

(recovery) 1 3 (5) - 37

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

Net earnings

(loss) 10 9 (20) - 210

Non-

controlling

interests - - - - 4

Preference

share

dividends - - 23 - 23

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

Net earnings

(loss)

attributable

to common

equity

shareholders 10 9 (43) - 183

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

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

Goodwill - - - - 1,570

Identifiable

assets 653 620 501 (412) 12,861

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

Total assets 653 620 501 (412) 14,431

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

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

Gross capital

expenditures

(1) 105 15 - - 511

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

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

Year-to-Date

June 30, 2011

($ millions)

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

Revenue 14 110 13 (21) 2,005

Energy supply

costs 1 - - (8) 961

Operating

expenses 4 77 5 (3) 419

Depreciation

and

amortization 2 9 1 - 205

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

Operating

income 7 24 7 (10) 420

Other income

(expenses),

net 1 - - (1) 12

Finance

charges 2 12 26 (11) 185

Income tax

expense

(recovery) 1 3 (6) - 47

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

Net earnings

(loss) 5 9 (13) - 200

Non-

controlling

interests - - - - 4

Preference

share

dividends - - 23 - 23

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

Net earnings

(loss)

attributable

to common

equity

shareholders 5 9 (36) - 173

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

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

Goodwill - - - - 1,556

Identifiable

assets 473 581 675 (422) 12,111

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

Total assets 473 581 675 (422) 13,667

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

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

Gross capital

expenditures

(1) 82 9 - - 518

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

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

(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 six months ended June 30, 2012 and 2011 were as follows:

Significant Inter-Segment

Transactions Quarter Ended Year-to-Date

June 30 June 30

($ millions) 2012 2011 2012 2011

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

Sales from Fortis Generation to

Regulated Electric Utilities -

Caribbean - 3 - 7

Sales from Fortis Generation to

Other Canadian Electric Utilities - 1 - 1

Sales from Newfoundland Power to

Fortis Properties 1 1 3 2

Inter-segment finance charges on

lending from:

Fortis Generation to Other

Canadian Electric Utilities 1 1 1 1

Corporate to Regulated Electric

Utilities - Canadian - 1 - 1

Corporate to Regulated Electric

Utilities - Caribbean 1 1 2 2

Corporate to Fortis Generation 1 - 1 1

Corporate to Fortis Properties 4 3 8 6

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

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

The significant inter-segment asset balances were as follows:

As at June 30

($ millions) 2012 2011

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

Inter-segment lending from:

Fortis Generation to Other Canadian Electric

Utilities 20 20

Corporate to Regulated Electric Utilities -

Canadian - 50

Corporate to Regulated Electric Utilities -

Caribbean 77 68

Corporate to Fortis Generation 14 33

Corporate to Fortis Properties 281 225

Other inter-segment assets 20 26

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

Total inter-segment eliminations 412 422

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

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

14. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

Quarter Ended Year-to-Date

June 30 June 30

($ millions) 2012 2011 2012 2011

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

Cash paid for:

Interest 105 100 185 181

Income taxes 18 21 51 45

Change in non-cash operating

working capital:

Accounts receivable 187 105 128 69

Prepaid expenses (8) (6) (6) (7)

Inventories (31) (24) 27 56

Regulatory assets - current

portion 5 (1) 48 (6)

Accounts payable and other

current liabilities (76) (31) (67) (38)

Regulatory liabilities -

current portion 6 6 32 32

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

83 49 162 106

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

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

Non-cash investing and

financing activities:

Common share dividends

reinvested 15 15 28 31

Exercise of stock options

into common shares 1 1 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 June 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 June 30, 2012, the following notional volumes related to fuel option contracts and natural gas derivatives that are expected to be settled are outlined below.

2012 2013 2014

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

Fuel option contracts (millions of gallons) 3 1 -

Swaps and options (petajoules) 14 18 7

Gas purchase contract premiums (petajoules) 67 19 5

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

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 net balances include outstanding cash collateral associated with derivative positions.

The Corporation's outstanding derivative balances were as follows:

As at

June 30, December 31,

($ millions) 2012 2011

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

Gross derivatives balance (1) 91 136

Netting (2) - -

Cash collateral - -

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

Total derivative balances (3) 91 136

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

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

(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 $91 million on commodity risk-related derivative

instruments were recognized as current regulatory assets as at June 30,

2012 (December 31, 2011 - $136 million), which would otherwise be

recognized on the consolidated statement of comprehensive income or as

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 determine the fair value of all derivative instruments.

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) June 30, 2012 December 31, 2011

Carrying Estimated Carrying Estimated

($ millions) Value Fair Value Value Fair Value

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

Other asset - Belize

Electricity (1) 106 - (2) 106 - (2)

Long-term debt, including

current portion (3) (5,968) (7,394) (5,788) (7,172)

Waneta Partnership

promissory note (4) (46) (50) (45) (49)

Foreign exchange forward

contract (5) - - - -

Fuel option contracts (5) (1) (1) (1) (1)

Natural gas derivatives: (5)

Swaps and options (93) (93) (135) (135)

Gas purchase contract

premiums 3 3 - -

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

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

(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 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.


(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 June 30, 2012 and December 31, 2011. As

at December 31, 2011, the fair value of the foreign exchange forward

contract was less than $1 million and the contract expired in April

2012.


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.

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 June 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 Risk Risk that a counterparty to a financial instrument might

fail to meet its obligations under the terms of the

financial instrument.


Liquidity Risk Risk that an entity will encounter difficulty in raising

funds to meet commitments associated with financial

instruments.


Market Risk Risk that the fair value or future cash flows of a financial

instrument will fluctuate due to changes in market prices.

The Corporation is exposed to foreign exchange risk,

interest rate risk and commodity price risk.


Credit Risk

For cash 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 June 30, 2012, the utility's gross credit risk exposure was approximately $160 million, representing the projected value of retailer billings over a 60-day period. The Company has reduced its exposure to approximately $8 million by obtaining from the retailers either a cash deposit, bond, letter of credit or an investment-grade credit rating from a major rating agency, or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.

The FortisBC Energy companies are exposed to credit risk in the event of non-performance by counterparties to derivative financial instruments. To help mitigate credit risk, the FortisBC Energy companies deal with high credit-quality institutions in accordance with established credit-approval practices. The counterparties with which the FortisBC Energy companies have significant transactions are A-rated entities or better. The 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 counter parties accounting for greater than 10% net credit exposure.

As at

June 30, December 31,

($ millions, except for number of customers) 2012 2011

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

Gross credit exposure before credit collateral

(1) 93 136

Credit collateral - -

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

Net credit exposure (2) 93 136

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

Number of counterparties greater than 10% 4 4

Net exposure to counterparties greater than 10% 73 104

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

(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 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. The Corporation has a long-term other asset of $106 million, including foreign exchange impacts, recognized on the consolidated balance sheet related to its expropriated investment in Belize Electricity (Note 19).

Liquidity Risk

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

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

The Corporation's committed credit facility is available for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at June 30, 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 June 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

December

Regulated Fortis Corporate June 30, 31,

($ millions) Utilities Properties and Other 2012 2011

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

Total credit

facilities 1,434 13 1,045 2,492 2,248

Credit facilities

utilized:

Short-term

borrowings (1) (76) (5) - (81) (159)

Long-term debt (2) (123) - (185) (308) (74)

Letters of credit

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

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

Credit facilities

unused 1,168 8 859 2,035 1,949

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

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

(1) The weighted average interest rate on short-term borrowings was

approximately 2.1% as at June 30, 2012 (December 31, 2011 - 1.9%).


(2) As at June 30, 2012, credit facility borrowings classified as long-term

included $16 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 2.3% as at June 30, 2012

(December 31, 2011 - 2.6%).


As at June 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 to August 2017 from August 2015. 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 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 agreement, amending the maturity date from August 2013 to August 2014. The amended 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 to August 2016 from September 2015 and a decrease in pricing. The amended credit facility agreement otherwise contains substantially similar terms and conditions as the previous credit facility agreement.

The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at June 30, 2012, the Corporation's credit ratings were 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. Also, S&P and DBRS 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, mainly reflecting 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.

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.

Market Risk

Foreign Exchange Risk

The Corporation's earnings from, and net investment 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 is the US dollar. Belize Electricity's financial results were denominated in Belizean dollars, which are pegged to the US dollar.

As at June 30, 2012, the Corporation's corporately issued US$550 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 June 30, 2012, the Corporation had approximately US$13 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 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 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. As a result, the Corporation recognized a net foreign exchange gain in earnings of approximately $2 million and $0.5 million during the three and six months ended June 30, 2012, respectively (Note 8).

FEI's US dollar payments under a contract for the implementation of a customer care information system were exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. FEI had entered into a foreign exchange forward contract to hedge this exposure. FEI had regulatory approval to defer any increase or decrease in the fair value of the foreign exchange forward contract for recovery from, or refund to, customers in future rates. FEI's foreign exchange forward contract expired in April 2012.

Interest Rate Risk

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

Commodity Price Risk

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

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. In 2011 the BCUC determined that commodity hedging in the current environment was not a cost-effective means to meet the objectives of price competitiveness and rate stability. The BCUC concurrently denied FEI's 2011-2014 Price Risk Management Plan with the exception of certain elements to address regional price discrepancies. As a result, the FortisBC Energy companies have suspended all commodity hedging activities, 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. Any differences between the cost of natural gas purchased and the price of natural gas included in customer rates are recorded as regulatory deferrals and are recovered from, or refunded to, customers in future rates, subject to regulatory approval.

18. COMMITMENTS

There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2011 US GAAP annual audited consolidated financial statements, except as described below.

(a) Pending Acquisition

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 transaction received CH Energy Group shareholder approval in June 2012 and regulatory approval from FERC and the Committee on Foreign Investment in the United States in July 2012. The acquisition is subject to certain other approvals, including approval by the NYSPSC, and satisfaction of customary closing conditions. The NYSPSC is currently reviewing the application for approval of the transaction jointly filed by Fortis and CH Energy Group in April 2012 (Note 1).

(b) Subscription Receipts Offering

To finance a portion of the purchase price of CH Energy Group, Fortis sold 18,500,000 Subscription Receipts in June 2012 resulting in gross proceeds of approximately $601 million. Each Subscription Receipt entitles the holder to receive, on satisfaction of 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. In the event that the Release Conditions are not satisfied by June 30, 2013, or if the share purchase agreement relating to the acquisition is terminated prior to such time, the holders of Subscription Receipts will be entitled to receive an amount equal to the full subscription price thereof plus their pro rata share of the interest earned on such amount (Note 4).

(c) Other

In January 2012 two First Nations bands each invested approximately $6 million in equity in the Mount Hayes liquefied natural gas storage facility, representing a 15% equity interest in the Mount Hayes Limited Partnership, with FEVI holding the controlling 85% ownership interest (Note 5). 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 April 2012 the December 31, 2011 actuarial valuation of the defined benefit pension plan at Newfoundland Power was completed. As a result Newfoundland Power is required to fund a solvency deficiency of approximately $53 million, including interest, over five years beginning in 2012. The Company fulfilled its 2012 annual solvency deficit funding requirement during the second quarter of 2012. The increase in funding contributions is expected to be recovered from customers in future rates.

19. EXPROPRIATED ASSETS

Belize Electricity

On June 20, 2011, the GOB enacted legislation leading to the expropriation of the Corporation's investment in Belize Electricity. As a result of no longer controlling the operations of the utility, the Corporation discontinued the consolidation method of accounting for Belize Electricity, effective June 20, 2011, and classified the book value of the previous investment in the utility as a long-term other asset on the consolidated balance sheet.

In October 2011 Fortis commenced an action in the Belize Supreme Court with respect to the challenge of the legality of the expropriation of the Corporation's investment in Belize Electricity and court proceedings are continuing. 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 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 the fair value determined under the Corporation's valuation. Pursuant to the expropriation action, Fortis is pursuing alternative options for obtaining fair compensation from the GOB.

Exploits River Hydro Partnership

The Exploits River Hydro Partnership ("Exploits Partnership") is owned 51% by Fortis Properties and 49% by AbitibiBowater Inc. ("Abitibi"). The Exploits Partnership operated two non-regulated hydroelectric generating facilities in central Newfoundland with a combined capacity of approximately 36 MW. In December 2008 the Government of Newfoundland and Labrador expropriated Abitibi's hydroelectric assets and water rights in Newfoundland, including those of the Exploits Partnership. The newsprint mill in Grand Falls-Windsor closed on February 12, 2009, subsequent to which the day-to-day operations of the Exploits Partnership's hydroelectric generating facilities were assumed by Nalcor Energy as an agent for the Government of Newfoundland and Labrador with respect to expropriation matters. The Government of Newfoundland and Labrador has publicly stated that it is not its intention to adversely affect the business interests of lenders or independent partners of Abitibi in the province. The loss of control over cash flows and operations required Fortis to cease consolidation of the Exploits Partnership, effective February 12, 2009. Discussions between Fortis Properties and Nalcor Energy with respect to expropriation matters are ongoing.

20. CONTINGENT LIABILITIES

The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of 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 has begun the appeal process associated with the 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 has filed a statement of defence. During the second quarter of 2010, FHI was added as a third party in all of the related actions. Following a mediation, in which FHI did not participate, FHI was advised that all matters have now been settled.

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.

21. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period presentation. The most significant change related to a decrease in current and long-term debt of $4 million and $120 million, respectively, and a corresponding increase in current and long-term capital lease and finance obligations associated with a change in the presentation of finance obligations.

CORPORATE INFORMATION

Fortis Inc. is the largest investor-owned distribution utility in Canada, with total assets of more than $14 billion and fiscal 2011 revenue totalling approximately $3.7 billion. The Corporation serves more than 2,000,000 gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upstate New York. It also owns hotels and commercial office and retail space in Canada.

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

Share Transfer Agent and Registrar:

Computershare Trust Company of Canada

9th Floor, 100 University Avenue

Toronto, ON M5J 2Y1

T: 514.982.7555 or 1.866.586.7638

F: 416.263.9394 or 1.888.453.0330

W: www.computershare.com/fortisinc

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

Contact:
Vice President Finance and Chief Financial Officer
Barry V. Perry
Fortis Inc.
709.737.2822

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