Fortis Inc. Earns $62 Million in Second Quarter

07/31/2012 07:00 EST

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ST. JOHN'S, NEWFOUNDLAND AND LABRADOR - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved second quarter net earnings attributable to common equity shareholders of $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.

Consolidated Financial Highlights (Unaudited)
Periods Ended June 30		Quarter				Year-to-Date
($ millions, except for common share data)		2012	2011	Variance		2012		2011	Variance
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	)
Net Earnings		77	72	5		210		200	10
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
	Net Earnings	77	72	5		210		200	10
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
Cash Flow from Operating Activities		255	231	24		583		533	50

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 Utility	Regulatory Authority	Allowed Common Equity (%)	2010	2011	2012	Future or Historical Test Year Used to Set Customer Rates
				ROE		COS/ROE
FEI	British Columbia Utilities Commission ("BCUC")	40	9.50	9.50	9.50	FEI: Prior to January 1, 2010, 50/50 sharing of earnings above or below the allowed ROE under a PBR mechanism that expired on December 31, 2009 with a two-year phase-out
FEVI	BCUC	40	10.00	10.00	10.00
FEWI	BCUC	40	10.00	10.00	10.00	ROEs established by the BCUC
						Future Test Year
FortisBC Electric	BCUC	40	9.90	9.90	9.90	COS/ROE
						PBR mechanism for 2009 through 2011: 50/50 sharing of earnings above or below the allowed ROE up to an achieved ROE that is 200 basis points above or below the allowed ROE - excess to deferral account

						ROE established by the BCUC
						Future Test Year
Fortis- Alberta	Alberta Utilities Commission ("AUC")	41	9.00	8.75	8.75	COS/ROE ROE established by the AUC
						Future Test Year
Newfound- land Power	Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB")	45	9.00 +/- 50 bps	8.38 +/- 50 bps	8.80 +/- 50 bps	COS/ROE The allowed ROE is set using an automatic adjustment formula tied to long-term Canada bond yields. The formula was suspended for 2012.
						Future Test Year
Maritime Electric	Island Regulatory and Appeals Commission ("IRAC")	40	9.75	9.75	9.75	COS/ROE
Maritime Electric	Island Regulatory and Appeals Commission ("IRAC")	40	9.75	9.75	9.75	Future Test Year
Fortis- Ontario	Ontario Energy Board ("OEB")					Canadian Niagara Power - COS/ROE
	Canadian Niagara Power	40	8.01	8.01	8.01 ⁽¹⁾	Algoma Power - COS/ROE and subject to Rural and Remote Rate
	Algoma Power	40	8.57	9.85	9.85 ⁽¹⁾	Protection ("RRRP") Program
	Franchise Agreement Cornwall Electric					Cornwall Electric - Price cap with commodity cost flow through
						Canadian Niagara Power - 2009 historical test year for 2010, 2011 and 2012
						Algoma Power - 2007 historical test year for 2010; 2011 test year for 2011 and 2012
				ROA		COS/ROA
Caribbean Utilities	Electricity Regulatory Authority ("ERA")	N/A	7.75 - 9.75	7.75 - 9.75	7.25 - 9.25	Rate-cap adjustment mechanism based on published consumer price indices
						The Company may apply for a special additional rate to customers in the event of a disaster, including a hurricane.
						Historical Test Year
Fortis Turks and Caicos	Utilities make annual filings to the	N/A	17.50 ⁽²⁾	17.50 ⁽²⁾	17.50 ⁽²⁾	COS/ROA
	Interim Government of the Turks and Caicos Caicos Islands ("Interim Government")					If the actual ROA is lower than the allowed ROA, due to additional costs resulting from a hurricane or other event, the Company may apply for an increase in customer rates in the following year.
						Future Test Year


⁽¹⁾	Based on the ROE automatic adjustment formula, the allowed ROE for electric utilities in Ontario is 9.12% for utilities with rates effective May 1, 2012. This ROE is not applicable to regulated electric utilities in Ontario until they are scheduled to file their next full COS rate applications. As a result, the allowed ROE of 9.12% is not applicable to Canadian Niagara Power or Algoma Power for 2012.
⁽²⁾	Amount provided under licence. ROA achieved in 2010 and 2011 was significantly lower than the ROA allowed under the licence due to significant investment occurring at the utility and the lack of rate relief thereto.

MATERIAL REGULATORY DECISIONS AND APPLICATIONS
Regulated Utility		Summary Description
FEI/FEVI/FEWI		- FEI and FEWI review with the BCUC natural gas commodity prices 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 Electric		- In June 2011 FortisBC Electric filed its 2012-2013 RRA, 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 Power		- In March 2012 Newfoundland Power filed a Cost of Capital Application with the PUB to discontinue the use of the current ROE automatic adjustment mechanism and to approve a just and reasonable rate of return on average rate base for 2012. In June 2012 the PUB ordered that the allowed ROE for 2012 be increased to 8.80% from 8.38% for 2011. The PUB also approved the deferred recovery 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 Electric		- In February 2012 the PEI Energy Commission (the "PEI Commission") released its Discussion Paper, Charting Our Electricity Future, which outlined discussion points the PEI Commission is seeking input through a consultative process with stakeholders and the general public. These discussion points included: (i) electricity ownership and management on PEI and whether Maritime Electric is doing a good job of balancing safety and reliability with cost of service; (ii) the future role of IRAC, the PEI Energy Corporation and the PEI Office of Energy Efficiency; (iii) a new cable interconnection; (iv) the treatment of the financing of the $47 million of deferred incremental replacement energy costs associated with the New Brunswick Power Point Lepreau nuclear generating station; (v) regional energy collaboration; (vi) demand side management; (vii) renewable energy and environmental stewardship; and (viii) potential options for natural gas-generated electricity. Public forums and stakeholder consultations occurred in February and March 2012, in which Maritime Electric was a participant. The PEI Commission is expected to release a final report of its recommendations to the Government of PEI 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 Utilities		- In April 2012 the ERA approved Caribbean Utilities' 2012-2016 Capital Investment Plan ("CIP") for US$122 million of non-generation installation capital expenditures. The remaining US$62 million of the 2012-2016 CIP relates to new generation installation, which is subject to a competitive solicitation process with the next generation unit scheduled for installation in 2014. The 2012-2016 CIP was prepared in line with the Certificate of Need that was filed with the ERA in November 2011. Proposals for installation of the new generation unit from six qualified bidders, including Caribbean Utilities, was requested by the ERA and Caribbean Utilities' proposal was submitted in July 2012. The ERA's decision on the successful bidder is expected 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 and Caicos		- An independent review of the regulatory framework for the electricity sector in the Turks and Caicos Islands was performed during the third quarter of 2011 on behalf of the Interim Government. 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.

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
Balance Sheet Account	Increase/ (Decrease) ($ millions)	Explanation
Cash and cash equivalents	144	The increase was driven by cash on hand at the 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").
Accounts receivable	(129)	The decrease was primarily due to the impact of a seasonal decrease in sales mainly at the FortisBC Energy companies and Newfoundland Power.
Inventories	(27)	The decrease was driven by the normal seasonal reduction of gas in storage at the FortisBC Energy companies.
Regulatory assets -current and long-term	(40)	The decrease was mainly due to the change in the deferral of the fair market value of the natural gas derivatives at the FortisBC Energy 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.
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.
Utility capital assets	267	The increase primarily related to $473 million invested in electricity and gas systems, partially offset by depreciation and customer contributions for the six months ended June 30, 2012.
Short-term borrowings	(78)	The decrease was primarily due to a reduction in borrowings at the FortisBC Energy companies with a portion of the proceeds received from an equity injection by Fortis during the second quarter of 2012 and due to seasonality of operations, partially offset by increased borrowings at Caribbean Utilities, mainly to repay maturing long-term debt.
Accounts payable and other current liabilities	(127)	The decrease was mainly due to: (i) the change in the fair market value of the natural gas derivatives at the FortisBC Energy companies; (ii) lower amounts owing for purchased natural gas at the FortisBC Energy companies and purchased power at Newfoundland Power, associated with seasonality of operations; 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.
Regulatory liabilities - current and long-term	92	The increase was mainly due to an overall increase in deferrals at the FortisBC Energy companies and an increase in the AESO charges deferral at FortisAlberta. The increase in deferrals at the FortisBC Energy companies was 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.
Deferred income tax liabilities - current and long-term	28	The increase was driven by tax timing differences related to capital expenditures at the regulated utilities.
Long-term debt (including current portion)	180	The increase was primarily due to higher borrowings under the Corporation's committed credit facility to finance advances to the 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.
Shareholders' equity (before non-controlling interests)	106	The increase was primarily due to net earnings attributable to common equity shareholders for the six months ended June 30, 2012, less common share dividends, and the issuance of common shares under the Corporation's dividend reinvestment plan.
Non-controlling interests	67	The increase was driven by advances from the 49% non-controlling interests in the Waneta Partnership and an approximate $12 million, or 15%, equity investment by two First Nations bands in the LNG storage facility on Vancouver Island.

LIQUIDITY AND CAPITAL RESOURCES

The table below outlines the Corporation's consolidated sources and uses of cash for the 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.

Summary of Consolidated Cash Flows (Unaudited)
Periods Ended June 30		Quarter						Year-to-Date
($ millions)		2012		2011		Variance		2012		2011		Variance
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	)
Cash, End of Period		231		296		(65	)	231		296		(65	)

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.

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
Caribbean Utilities ⁽¹⁾	-	29	(29	)	-	29	(29	)
Other	-	1	(1	)	-	1	(1	)
Total	-	30	(30	)	-	30	(30	)

(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.

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

Net Borrowings Under Committed Credit Facilities (Unaudited)
Periods Ended June 30	Quarter			Year-to-Date
($ millions)	2012	2011	Variance	2012	2011	Variance
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
Total	223	58	165	230	73	157

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.

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

(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.

Capital Structure (Unaudited)	As at
	June 30, 2012		December 31, 2011
	($ millions)	(%)	($ millions)	(%)
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
Total ⁽³⁾	11,094	100.0	11,031	100.0

(1)	Includes long-term debt and capital lease and finance obligations, including current portion, and short-term borrowings, net of cash
(2)	Excluding capital lease and finance obligations, the debt component of the capital structure was 54.6% 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.

Gross Consolidated Capital Expenditures (Unaudited) ⁽¹⁾
Year-to-Date June 30, 2012
($ millions)
				Other
				Regulated	Total	Regulated
FortisBC				Electric	Regulated	Electric	Non-
Energy	Fortis	FortisBC	Newfoundland	Utilities -	Utilities -	Utilities -	Regulated -	Fortis
Companies	Alberta ⁽²⁾	Electric	Power	Canadian	Canadian	Caribbean	Utility ⁽³⁾	Properties	Total
78	200	33	36	22	369	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.

Credit Facilities (Unaudited)								As at
		Regulated		Fortis		Corporate		June 30,		December 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	(76	)	(5	)	-		(81	)	(159	)
	Long-term debt (including current portion)	(123	)	-		(185	)	(308	)	(74	)
Letters of credit outstanding		(67	)	-		(1	)	(68	)	(66	)
Credit facilities unused		1,168		8		859		2,035		1,949

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.

Financial Instruments (Unaudited)	As at
	June 30, 2012		December 31, 2011
	Carrying	Estimated	Carrying	Estimated
($ millions)	Value	Fair Value	Value	Fair Value
Waneta Partnership promissory note	46	50	45	49
Long-term debt, including current portion	5,968	7,394	5,788	7,172

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

The financial instruments table above excludes the long-term other asset associated with the Corporation's 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.

Derivative Financial Instruments (Unaudited)						As at
						June 30,		December 31,
						2012		2011
				Number of		Carrying Value ⁽²⁾		Carrying Value ⁽²⁾
(Liability) Asset		Maturity		Contracts	Volume ⁽¹⁾	($ millions)		($ millions)
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		-

(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 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.

Summary of Quarterly Results		Net Earnings
(Unaudited)		Attributable to
		Common Equity
	Revenue	Shareholders	Earnings per Common Share
Quarter Ended	($ millions)	($ millions)	Basic ($)	Diluted ($)
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

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)

	Common Shares				Preference Shares		Additional Paid-in Capital		Accumulated Other Comprehensive Loss		Retained Earnings			Non-Controlling Interests				Total Equity
		(Note 4	)
As at December 31, 2011	$	3,036		$	912	$	14	$	(95	)	$	868		$	208		$	4,943
Net earnings		-			-		-		-			206			4			210
Other comprehensive income		-			-		-		1			-			-			1
Common share issues		35			-		-		-			-			-			35
Stock-based compensation		-			-		1		-			-			-			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	)		-			(114	)
Dividends declared on preference shares		-			-		-		-			(23	)		-			(23	)
As at June 30, 2012	$	3,071		$	912	$	15	$	(94	)	$	937		$	275		$	5,116

As at December 31, 2010	$	2,575		$	912	$	12	$	(108	)	$	774		$	162		$	4,327
Net earnings		-			-		-		-			196			4			200
Other comprehensive income		-			-		-		14			-			-			14
Common share issues		337			-		-		-			-			-			337
Stock-based compensation		-			-		1		-			-			-			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	)		-			(105	)
Dividends declared on preference shares		-			-		-		-			(23	)		-			(23	)
As at June 30, 2011	$	2,912		$	912	$	13	$	(94	)	$	842		$	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:

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.

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.

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.

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.

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".

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
		($ millions)		(in millions)		EPS	($ millions)		(in 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
		($ millions)	(in millions)	EPS	($ millions)	(in 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							NON-REGULATED
	Gas Utilities	Electric Utilities
Quarter Ended	FortisBC Energy					Total						Inter-
June 30, 2012	Companies -	Fortis	FortisBC	Newfound- land	Other	Electric	Electric	Fortis	Fortis	Corporate		segment
($ millions)	Canadian	Alberta	Electric	Power	Canadian	Canadian	Carib- bean	Generation	Properties	and Other		eliminations		Consolidated
Revenue	264	110	67	130	82	389	67	9	64	7		(8	)	792
Energy supply costs	109	-	13	78	51	142	39	1	-	-		-		291
Operating expenses	63	37	21	17	12	87	9	1	42	3		(1	)	204
Depreciation and amortization	40	30	12	11	6	59	9	1	5	-		-		114
Operating income	52	43	21	24	13	101	10	6	17	4		(7	)	183
Other income (expenses), net	1	-	-	1	-	1	1	-	-	(3	)	-		-
Finance charges	36	17	10	9	6	42	3	-	6	12		(7	)	92
Income tax expense (recovery)	3	-	2	4	2	8	-	1	3	(1	)	-		14
Net earnings (loss)	14	26	9	12	5	52	8	5	8	(10	)	-		77
Non-controlling interests	1	-	-	-	-	-	2	-	-	-		-		3
Preference share dividends	-	-	-	-	-	-	-	-	-	12		-		12
Net earnings (loss) attributable to common equity shareholders	13	26	9	12	5	52	6	5	8	(22	)	-		62

Goodwill	913	227	221	-	67	515	142	-	-	-		-		1,570
Identifiable assets	4,605	2,543	1,671	1,251	692	6,157	737	653	620	501		(412	)	12,861
Total assets	5,518	2,770	1,892	1,251	759	6,672	879	653	620	501		(412	)	14,431
Gross capital expenditures ⁽¹⁾	32	121	16	21	13	171	12	57	10	-		-		282

Quarter Ended
June 30, 2011
($ millions)
Revenue	319	103	65	133	78	379	85	7	60	7		(11	)	846
Energy supply costs	170	-	11	80	47	138	53	1	-	-		(4	)	358
Operating expenses	70	36	21	17	11	85	11	1	40	3		(1	)	209
Depreciation and amortization	27	33	12	11	6	62	8	1	4	-		-		102
Operating income	52	34	21	25	14	94	13	4	16	4		(6	)	177
Other income (expenses), net	3	-	-	-	-	-	1	-	-	-		-		4
Finance charges	36	16	9	9	6	40	4	1	6	12		(6	)	93
Income tax expense (recovery)	4	-	3	6	2	11	1	1	2	(3	)	-		16
Net earnings (loss)	15	18	9	10	6	43	9	2	8	(5	)	-		72
Non-controlling interests	-	-	-	-	-	-	3	-	-	-		-		3
Preference share dividends	-	-	-	-	-	-	-	-	-	12		-		12
Net earnings (loss) attributable to common equity shareholders	15	18	9	10	6	43	6	2	8	(17	)	-		57

Goodwill	913	227	221	-	63	511	132	-	-	-		-		1,556
Identifiable assets	4,380	2,244	1,613	1,233	661	5,751	673	473	581	675		(422	)	12,111
Total assets	5,293	2,471	1,834	1,233	724	6,262	805	473	581	675		(422	)	13,667
Gross capital expenditures ⁽¹⁾	65	86	23	17	11	137	19	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							NON-REGULATED
	Gas Utilities	Electric Utilities
Year-to-Date	FortisBC Energy					Total						Inter-
June 30, 2012	Companies -	Fortis	FortisBC	Newfound- land	Other	Electric	Electric	Fortis	Fortis	Corporate		segment
($ millions)	Canadian	Alberta	Electric	Power	Canadian	Canadian	Carib- bean	Generation	Properties	and Other		eliminations		Consolidated
Revenue	812	218	154	322	173	867	130	18	116	13		(15	)	1,941
Energy supply costs	411	-	38	220	109	367	79	1	-	-		(1	)	857
Operating expenses	133	76	42	37	24	179	17	4	82	6		(3	)	418
Depreciation and amortization	80	65	24	22	13	124	16	2	10	1		-		233
Operating income	188	77	50	43	27	197	18	11	24	6		(11	)	433
Other income (expenses), net	1	2	-	1	-	3	1	1	-	(8	)	(1	)	(3	)
Finance charges	71	32	20	18	11	81	7	1	12	23		(12	)	183
Income tax expense (recovery)	22	-	5	7	4	16	-	1	3	(5	)	-		37
Net earnings (loss)	96	47	25	19	12	103	12	10	9	(20	)	-		210
Non-controlling interests	1	-	-	-	-	-	3	-	-	-		-		4
Preference share dividends	-	-	-	-	-	-	-	-	-	23		-		23
Net earnings (loss) attributable to common equity shareholders	95	47	25	19	12	103	9	10	9	(43	)	-		183

Goodwill	913	227	221	-	67	515	142	-	-	-		-		1,570
Identifiable assets	4,605	2,543	1,671	1,251	692	6,157	737	653	620	501		(412	)	12,861
Total assets	5,518	2,770	1,892	1,251	759	6,672	879	653	620	501		(412	)	14,431
Gross capital expenditures ⁽¹⁾	78	200	33	36	22	291	22	105	15	-		-		511

Year-to-Date
June 30, 2011
($ millions)
Revenue	893	203	148	316	169	836	160	14	110	13		(21	)	2,005
Energy supply costs	514	-	34	214	107	355	99	1	-	-		(8	)	961
Operating expenses	144	71	39	37	23	170	22	4	77	5		(3	)	419
Depreciation and amortization	54	66	23	21	12	122	17	2	9	1		-		205
Operating income	181	66	52	44	27	189	22	7	24	7		(10	)	420
Other income (expenses), net	6	3	1	-	-	4	2	1	-	-		(1	)	12
Finance charges	70	29	19	18	11	77	9	2	12	26		(11	)	185
Income tax expense (recovery)	27	1	6	10	4	21	1	1	3	(6	)	-		47
Net earnings (loss)	90	39	28	16	12	95	14	5	9	(13	)	-		200
Non-controlling interests	-	-	-	-	-	-	4	-	-	-		-		4
Preference share dividends	-	-	-	-	-	-	-	-	-	23		-		23
Net earnings (loss) attributable to common equity shareholders	90	39	28	16	12	95	10	5	9	(36	)	-		173

Goodwill	913	227	221	-	63	511	132	-	-	-		-		1,556
Identifiable assets	4,380	2,244	1,613	1,233	661	5,751	673	473	581	675		(422	)	12,111
Total assets	5,293	2,471	1,834	1,233	724	6,262	805	473	581	675		(422	)	13,667
Gross capital expenditures ⁽¹⁾	113	171	53	31	19	274	40	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 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 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 > 10%	4	4
Net exposure to counterparties > 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
		Regulated		Fortis		Corporate		June 30,		December 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%).

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.

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)

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.

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

FHI

FortisBC Electric

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

9^th 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.

Barry V. Perry
Vice President Finance and Chief Financial Officer
Fortis Inc.
709.737.2822

Fortis Inc. Earns $62 Million in Second Quarter

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