Fortis Earns $54 Million in Second Quarter

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwired - Aug 1, 2013) - Fortis Inc. ("Fortis" or the "Corporation") (FTS.TO) achieved second quarter net earnings attributable to common equity shareholders of $54 million, or $0.28 per common share, compared to $62 million, or $0.33 per common share, for the second quarter of 2012. For the first half of 2013, net earnings attributable to common equity shareholders were $205 million, or $1.06 per common share, compared to $183 million, or $0.97 per common share, for the first half of last year.

On June 27, 2013, Fortis closed the acquisition of CH Energy Group, Inc. ("CH Energy Group") for approximately US$1.5 billion, including the assumption of US$518 million of debt on closing. The net purchase price of the acquisition was financed using proceeds from a $601 million common equity offering and drawings under the Corporation's committed credit facility. Central Hudson Gas & Electric Corporation ("Central Hudson"), the main business of CH Energy Group, is a regulated transmission and distribution utility that serves 377,000 electric and gas customers in New York State's Mid-Hudson River Valley. Earnings for the quarter were reduced by $32 million, or $0.17 per common share, due to acquisition-related expenses and customer and community benefits offered to obtain regulatory approval of the acquisition compared to $3 million of acquisition-related expenses for the same period last year.

Earnings for the quarter were favourably impacted by an income tax recovery of $25 million, or $0.13 per common share, due to the enactment of higher deductions associated with Part VI.1 tax on the Corporation's preference share dividends. In the second quarter of 2012, earnings were reduced by income tax expenses of $3 million associated with Part VI.1 tax.

Excluding the above-noted acquisition-related and Part VI.1 tax impacts, net earnings attributable to common equity shareholders for the second quarter of 2013 were $61 million, or $0.32 per common share, compared to $68 million, or $0.36 per common share, for the second quarter of 2012.

"The integration of Central Hudson into the Fortis Group is progressing well," says Stan Marshall, President and Chief Executive Officer, Fortis Inc. "The acquisition is expected to be accretive to earnings per common share of Fortis beginning in 2015."

Regulated utilities, including Central Hudson, comprise approximately 90% of total assets and serve approximately 2.4 million gas and electricity customers across Canada and in New York State and the Caribbean. Regulated rate base assets of Fortis exceed $10 billion.

Canadian Regulated Gas Utilities contributed earnings of $6 million compared to $13 million for the second quarter of 2012. The $7 million decrease in earnings reflects the $8 million unfavourable impact for the first half of 2013 of the regulatory decision related to the first phase of the Generic Cost of Capital ("GCOC") Proceeding in British Columbia, described more fully below, which was recognized in the second quarter of 2013 when the decision was received. Earnings contribution from growth in energy infrastructure investment was largely offset by lower gas transportation volumes to industrial customers and lower-than-expected customer additions.

Canadian Regulated Electric Utilities contributed earnings of $66 million, up $15 million from the second quarter of 2012. For the second quarter, earnings at Newfoundland Power and Maritime Electric were favourably impacted by income tax recoveries of $13 million and $4 million, respectively, associated with Part VI.1 tax. FortisAlberta's earnings decreased $1 million, due to lower net transmission revenue and timing of the recognition of a regulatory decision in 2012 impacting depreciation, partially offset by timing of operating expenses, growth in energy infrastructure investment and customer growth. The utility's depreciation rates were reduced, effective January 1, 2012, as a result of the decision related to FortisAlberta's 2012 revenue requirements, the impact of which was not recognized until the second quarter of 2012 when the decision was received. FortisBC Electric's earnings were $1 million lower quarter over quarter, due to the $2 million unfavourable impact for the first half of 2013 of the regulatory decision related to the first phase of the GCOC Proceeding, which was recognized in the second quarter of 2013 when the decision was received, partially offset by lower-than-expected finance charges, growth in energy infrastructure investment and higher capitalized allowance for funds used during construction.

In May 2013 the British Columbia Utilities Commission issued its decision on the first phase of its GCOC Proceeding. As a result, the allowed rate of return on common shareholders' equity ("ROE") for FortisBC Energy Inc. has been set at 8.75%, as compared to 9.50% for 2012, and the common equity component of capital structure has been reduced from 40.0% to 38.5% for 2013 through 2015. The interim allowed ROEs for the other FortisBC Energy companies, FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"), and for FortisBC Electric were also reduced by 75 basis points for 2013 as a result of the first phase of the GCOC Proceeding, while the common equity components of the capital structures remain unchanged. Final allowed ROEs and capital structures for FEVI, FEWI and FortisBC Electric will be determined in the second phase of the GCOC Proceeding, which is currently underway.

In April 2013 Newfoundland Power received a cost of capital decision maintaining the utility's allowed ROE and common equity component of capital structure at 8.8% and 45%, respectively, for 2013 through 2015. FortisAlberta's allowed ROE and capital structure for 2013 remain to be determined.

Caribbean Regulated Electric Utilities contributed $6 million of earnings, comparable with the second quarter of 2012.

Non-Regulated Fortis Generation contributed $3 million of earnings compared to $6 million for the second quarter of 2012. The $3 million decrease in earnings is mainly related to lower production in Belize due to lower rainfall.

Non-Utility operations contributed earnings of $9 million, $1 million higher than earnings for the second quarter of 2012, largely related to performance at Fortis Properties' hotels in western Canada.

Corporate and other expenses were $36 million compared to $22 million for the second quarter of 2012. Corporate and other expenses for the second quarter of 2013 included $32 million in CH Energy Group transaction expenses, compared to $3 million for the same quarter last year. An approximate $8 million income tax recovery, associated with Part VI.1 tax, reduced Corporate and other expenses in the second quarter of 2013, compared to income tax expense of $3 million associated with Part VI.1 tax for the same quarter last year. Excluding the above-noted impacts, Corporate and other expenses were $4 million lower, quarter over quarter, mainly due to the favourable impact of the release of income tax provisions in the second quarter of 2013, a higher foreign exchange gain and lower finance charges, partially offset by higher preference share dividends.

Consolidated capital expenditures, before customer contributions, were approximately $548 million for the first half of 2013 and are expected to total approximately $1.3 billion for the year. Construction of the $900 million, 335-megawatt Waneta Expansion hydroelectric generating facility ("Waneta Expansion") in British Columbia continues on time and on budget, with completion of the facility expected in spring 2015. Approximately $513 million in total has been invested in the Waneta Expansion since construction began in late 2010.

Cash flow from operating activities was $571 million for the first half of 2013 compared to $583 million for the first half of 2012.

Fortis has consolidated credit facilities of $2.7 billion, of which $1.7 billion was unused as at June 30, 2013. Credit facility borrowings as at June 30, 2013 include $605 million in drawings under the Corporation's committed credit facility. In July 2013 Fortis issued 10 million Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series K for gross proceeds of $250 million, the proceeds of which were used to redeem all of the Corporation's First Preference Shares, Series C in July 2013 for $125 million, to repay a portion of credit facility borrowings and for other general corporate purposes. In July 2013 the Corporation also priced a private placement of 10-year US$285 million unsecured notes at 3.84% and 30-year US$40 million unsecured notes at 5.08%. The offering is scheduled to close on October 1, 2013. Proceeds from the offering will be used to repay a portion of US dollar-denominated committed credit facility borrowings incurred to initially finance a portion of the CH Energy Group acquisition.

"The second half of 2013 will continue to be very busy for Fortis, with significant regulatory proceedings in British Columbia and Alberta and with work continuing on capital projects for the year to ensure we continue to meet our customers' energy needs. Our five-year capital program, including Central Hudson, is projected to total $6 billion, which is expected to drive growth in earnings and dividends," explains Marshall.

"We welcome the employees of Central Hudson to the Fortis team, now some 8,400 individuals strong. The addition of this well-run U.S. utility and its proven track record for providing customers with quality service will further enhance the positioning of Fortis as a leader in the North American utility industry," concludes Marshall.

Interim Management Discussion and Analysis
For the three and six months ended June 30, 2013
Dated August 1, 2013

FORWARD-LOOKING INFORMATION

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. The MD&A should be read in conjunction with the interim unaudited consolidated financial statements and notes thereto for the three and six months ended June 30, 2013 and the MD&A and audited consolidated financial statements for the year ended December 31, 2012 included in the Corporation's 2012 Annual Report. Financial information 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.

Fortis includes forward-looking information in the Management Discussion and Analysis ("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 forecasted gross consolidated capital expenditures for 2013 and total capital spending over the five-year period 2013 through 2017; the expectation that capital investment over the above-noted five-year period will allow utility rate base and hydroelectric investment to increase at a combined compound annual growth rate of approximately 6%; the expected nature, timing and capital cost related to the construction of the Waneta Expansion hydroelectric generating facility ("Waneta Expansion"); the expectation that, based on current tax legislation, future earnings will not be materially impacted by Part VI.1 tax; 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 expectation that the combination of available credit facilities and relatively low annual debt maturities and repayments will provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets; the expected consolidated long-term debt maturities and repayments on average annually over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2013; the expected timing of filing of regulatory applications and of receipt of regulatory decisions; the expectation that the acquisition of CH Energy Group, Inc. ("CH Energy Group") will be accretive to earnings per common share of Fortis beginning in 2015; and the expectation that the Corporation's capital expenditure program will support continuing growth in earnings and dividends.

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 material adverse regulatory decisions being received and the expectation of regulatory stability; FortisAlberta continues to recover its cost of service and earn its allowed rate of return on common shareholders' equity ("ROE") under performance-based rate-setting, which commenced for a five-year term effective January 1, 2013; 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; sufficient liquidity and capital resources; the expectation that the Corporation will receive appropriate compensation from the Government of Belize ("GOB") for the fair value of the Corporation's investment in Belize Electricity that was expropriated by the GOB;
the expectation that Belize Electric Company Limited will not be expropriated by the GOB; 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, electricity 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 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 negatively affect the operations and cash flows of the Corporation and its subsidiaries; no material change in public policies and directions by governments that could materially negatively affect 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 accounting principles generally accepted in the United States beyond 2014 or the adoption of International Financial Reporting Standards 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 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. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A, the Corporation's MD&A for the year ended December 31, 2012 and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. Key risk factors for 2013 include, but are not limited to: uncertainty of the impact a continuation of a low interest rate environment may have on the allowed ROE at each of the Corporation's regulated utilities in western Canada; risk associated with the amount of compensation to be paid to Fortis for its investment in Belize Electricity that was expropriated by the GOB; and the timeliness of the receipt of compensation and the ability of the GOB to pay the compensation owing to Fortis.

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 gas and electric distribution utility in Canada. Its regulated utilities account for 90% of total assets and serve approximately 2.4 million gas and electricity customers across Canada and in New York State and the Caribbean. Fortis owns non-regulated hydroelectric generation assets in Canada, Belize and Upstate New York. The Corporation's non-utility investments are comprised of hotels and commercial real estate in Canada and petroleum supply operations in the Mid-Atlantic Region of the United States.

Year-to-date June 30, 2013, the Corporation's electricity distribution systems met a combined peak demand of approximately 5,159 megawatts ("MW") and its gas distribution system met a peak day demand of 1,113 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, 2013 and to the "Corporate Overview" section of the 2012 Annual MD&A.

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 and equity component of capital structure; (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 forecasted 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.

When performance-based rate-setting ("PBR") mechanisms are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover prudent COS and earn its allowed ROE.

SIGNIFICANT ITEMS

Acquisition of CH Energy Group, Inc.: On June 27, 2013, Fortis acquired all of the outstanding common shares of 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 US$518 million of debt on closing. The net purchase price of approximately $1,019 million (US$972 million) was financed through proceeds from the issuance of 18.5 million common shares of Fortis pursuant to the conversion of Subscription Receipts on closing of the acquisition for proceeds of approximately $567 million, net of after-tax expenses, with the balance being initially funded through drawings under the Corporation's $1 billion committed credit facility.

CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New York. Its main business, Central Hudson Gas & Electric Corporation ("Central Hudson"), is a regulated transmission and distribution ("T&D") utility serving approximately 300,000 electric and 77,000 natural gas customers in eight counties of New York State's Mid-Hudson River Valley. Central Hudson accounts for approximately 93% of the total assets of CH Energy Group and is subject to regulation by the New York State Public Service Commission ("PSC") under a traditional COS model. CH Energy Group's non-regulated operations mainly consist of Griffith Energy Services, Inc. ("Griffith"), which is primarily a fuel delivery business serving approximately 56,000 customers in the Mid-Atlantic Region of the United States.

To obtain regulatory approval of the acquisition, Fortis committed to provide Central Hudson's customers and community with approximately US$50 million in financial benefits. These incremental benefits outlined in the PSC order approving the acquisition include: (i) US$35 million to cover expenses that would normally be recovered in customer rates, including certain storm-restoration expenses; (ii) guaranteed savings to customers of more than US$9 million over five years resulting from the elimination of costs CH Energy Group would otherwise incur as a public company; and (iii) the establishment of a US$5 million Community Benefit Fund to be used for low-income customer and economic development programs for communities and residents of the Mid-Hudson River Valley. In addition, electric and natural gas customers of Central Hudson will benefit from a delivery rate freeze through to June 30, 2015. The Company is committed to invest US$215 million in capital expenditures over the same two-year period, including an estimated US$50 million which will have a "storm-hardening" effect on its infrastructure.

The above-noted commitments of US$35 million and US$5 million, together with acquisition-related expenses of approximately US$8 million, have been recognized in the Corporation's earnings for the second quarter of 2013. The acquisition is expected to be accretive to earnings per common share of Fortis beginning in 2015.

For further information on Central Hudson, refer to the "Segmented Results of Operation -Regulated Gas & Electric Utility - United States" section of this MD&A.

Part VI.1 Tax: In June 2013 the Government of Canada enacted changes associated with Part VI.1 tax on the Corporation's preference share dividends. In accordance with US GAAP, income taxes are required to be recognized based on enacted tax legislation. In the second quarter of 2013, the Corporation recognized an approximate $25 million income tax recovery due to the enactment of higher deductions associated with Part VI.1 tax. The income tax recovery impacted earnings at Newfoundland Power, Maritime Electric and the Corporation as a result of the allocation of Part VI.1 tax in previous years. Currently, all legislative changes associated with Part VI.1 tax are enacted and, as a result, future earnings are not expected to be materially impacted by Part VI.1 tax.

Receipt of Regulatory Decisions: In March 2013 FortisAlberta received a decision from its regulator approving an interim increase in customer distribution rates, effective January 1, 2013.

In April 2013 Newfoundland Power received a cost of capital decision maintaining the utility's allowed ROE and common equity component of capital structure at 8.8% and 45%, respectively, for 2013 through 2015.

In May 2013 the British Columbia Utilities Commission ("BCUC") issued its decision on the first phase of its Generic Cost of Capital ("GCOC") Proceeding for British Columbia utilities. As a result, the allowed ROE for FortisBC Energy Inc. ("FEI"), which is the benchmark utility for calculating the allowed ROE for certain utilities in British Columbia, has been set at 8.75%, as compared to 9.50% for 2012, and the common equity component of capital structure has been reduced from 40.0% to 38.5% for 2013 through 2015. The interim allowed ROEs for the other FortisBC Energy companies, FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"), and FortisBC Electric were also reduced by 75 basis points for 2013 as a result of the first phase of the GCOC Proceeding, while the common equity components of the capital structures remain unchanged. Final allowed ROEs and capital structures for FEVI, FEWI and FortisBC Electric will be determined in the second phase of the GCOC Proceeding, which is currently underway.

For a further discussion on the nature of the above regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.

Settlement of Expropriation Matters - Exploits River Hydro Partnership: In March 2013 the Corporation and the Government of Newfoundland and Labrador ("Government") settled all matters, including release from all debt obligations, pertaining to the Government's December 2008 expropriation of non-regulated hydroelectric generating assets and water rights in central Newfoundland, then owned by Exploits River Hydro Partnership ("Exploits Partnership"), in which Fortis held an indirect 51% interest. As a result of the settlement, an extraordinary after-tax gain of approximately $22 million was recognized in the first quarter of 2013.

Acquisition of the Electrical Utility Assets from the City of Kelowna: FortisBC Electric acquired the electrical utility assets of the City of Kelowna (the "City") for approximately $55 million in March 2013, which now allows FortisBC Electric to directly serve some 15,000 customers formerly served by the City. FortisBC Electric had provided the City with electricity under a wholesale tariff and had operated and maintained the City's electrical utility assets under contract since 2000.

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, 2013 and June 30, 2012 are provided in the following table.

Consolidated Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions, except for common share data) 2013 2012 Variance 2013 2012 Variance
Revenue 790 792 (2 ) 1,903 1,941 (38 )
Energy Supply Costs 282 291 (9 ) 787 857 (70 )
Operating Expenses 206 204 2 427 418 9
Depreciation and Amortization 130 114 16 259 233 26
Other Income (Expenses), Net (44 ) - (44 ) (38 ) (3 ) (35 )
Finance Charges 92 92 - 181 183 (2 )
Income Tax (Recovery) Expense (34 ) 14 (48 ) (4 ) 37 (41 )
Earnings Before Extraordinary Item 70 77 (7 ) 215 210 5
Extraordinary Gain, Net of Tax - - - 22 - 22
Net Earnings 70 77 (7 ) 237 210 27
Net Earnings Attributable to:
Non-Controlling Interests 2 3 (1 ) 4 4 -
Preference Equity Shareholders 14 12 2 28 23 5
Common Equity Shareholders 54 62 (8 ) 205 183 22
Net Earnings 70 77 (7 ) 237 210 27
Earnings per Common Share Before Extraordinary Item
Basic ($) 0.28 0.33 (0.05 ) 0.95 0.97 (0.02 )
Diluted ($) 0.28 0.33 (0.05 ) 0.94 0.95 (0.01 )
Earnings per Common Share
Basic ($) 0.28 0.33 (0.05 ) 1.06 0.97 0.09
Diluted ($) 0.28 0.33 (0.05 ) 1.05 0.95 0.10
Weighted Average Common Shares Outstanding (# millions) 193.4 189.6 3.8 192.7 189.3 3.4
Cash Flow from Operating Activities 291 255 36 571 583 (12 )

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

Unfavourable

  • Lower commodity cost of natural gas charged to customers at the FortisBC Energy companies
  • Decreases in the allowed ROEs at the FortisBC Energy companies and FortisBC Electric, and a decrease in the equity component of capital structure at FEI as a result of the BCUC decision in May 2013 on the first phase of its GCOC Proceeding
  • Lower average gas consumption by residential and commercial customers and lower gas transportation volumes to industrial customers at the FortisBC Energy companies
  • Decreased non-regulated hydroelectric production in Belize, due to lower rainfall
  • Lower net transmission revenue at FortisAlberta

Favourable

  • An increase in gas delivery rates at the FortisBC Energy companies and the base component of electricity rates at most of the regulated electric utilities, consistent with rate decisions, reflecting ongoing investment in energy infrastructure and forecasted certain higher expenses recoverable from customers
  • Growth in the number of customers, driven by FortisAlberta
  • Increased electricity sales at Newfoundland Power, Maritime Electric, Fortis Turks and Caicos and Caribbean Utilities

Factors Contributing to Quarterly and Year-to-Date Energy Supply Costs Variances

Favourable

  • Lower commodity cost of natural gas
  • Lower average gas consumption by residential and commercial customers and lower gas transportation volumes to industrial customers at the FortisBC Energy companies, which reduced natural gas purchases

Unfavourable

  • Increased electricity sales at Newfoundland Power, Maritime Electric, Fortis Turks and Caicos and Caribbean Utilities, which increased fuel and power purchases
  • Increased costs at Maritime Electric associated with energy supply costs expensed in the first half of 2013 related to the New Brunswick Power Point Lepreau nuclear generating station ("Point Lepreau"), which returned to service in the fourth quarter of 2012

Factor Contributing to Quarterly and Year-to-Date Operating Expenses Variances

Unfavourable

  • General inflationary and employee-related cost increases at most of the Corporation's regulated utilities

Factors Contributing to Quarterly and Year-to-Date Depreciation and Amortization Expense Variances

Unfavourable

  • Continued investment in energy infrastructure at the Corporation's regulated utilities
  • Lower depreciation rates at FortisAlberta, effective January 1, 2012, as a result of the 2012 distribution revenue requirements decision received in April 2012. The cumulative impact of the overall decrease in depreciation rates was recognized in the second quarter of 2012, when the decision was received. Approximately $3 million of decreased depreciation expense related to the first quarter of 2012.

Factors Contributing to Quarterly and Year-to-Date Other Income (Expenses), Net Variances

Unfavourable

  • Approximately $41 million (US$40 million), or $26 million (US$26 million) after tax, in expenses associated with customer and community benefits offered by the Corporation to close the acquisition of CH Energy Group in June 2013
  • Approximately $8 million ($6 million after tax) in costs incurred in the second quarter of 2013 related to the acquisition of CH Energy Group, compared to approximately $4 million ($3 million after tax) and $8 million ($7 million after tax) for the second quarter and first half of 2012, respectively

Favourable

  • Foreign exchange gains of approximately $3 million and $5 million for the second quarter and the first half of 2013, respectively, associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity, compared to approximately $2 million and $0.5 million, respectively, for the same periods in 2012

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")
  • Higher capitalized allowance for funds used during construction ("AFUDC"), mainly at FortisBC Electric

Unfavourable

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

Factors Contributing to Quarterly and Year-to-Date Income Tax (Recovery) Expense Variances

Favourable

  • An approximate $25 million income tax recovery in the second quarter of 2013, due to the enactment of higher deductions associated with Part VI.1 tax, compared to income tax expense of $3 million associated with Part VI.1 tax for the same quarter last year. In the first quarter of 2013, income tax expense included $2 million associated with Part VI.1 tax.
  • An approximate $5 million income tax recovery associated with the release of income tax provisions in the second quarter of 2013

Unfavourable

  • Higher effective income taxes, due to differences in the deductions for income tax purposes compared to accounting purpose, mainly at the FortisBC Energy companies and FortisBC Electric

Factor Contributing to Year-to-Date Extraordinary Gain, Net of Tax Variance

Favourable

  • An approximate $25 million ($22 million after-tax) extraordinary gain recognized in the first quarter of 2013 on the settlement of expropriation matters associated with Exploits Partnership

Factors Contributing to Quarterly Earnings Variance

Unfavourable

  • Higher corporate expenses due to $32 million in CH Energy Group transaction expenses and higher preference share dividends, due to the issuance of First Preference Shares, Series J in November 2012. The increases were partially offset by: (i) income tax recoveries of approximately $13 million, comprised of $8 million associated with Part VI.1 tax and $5 million associated with the release of income tax provisions in the second quarter of 2013; (ii) a higher foreign exchange gain associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity; and (iii) lower finance charges. In the first quarter of 2013, income tax expense included $2 million associated with Part VI.1 tax.
  • Decreased earnings at the FortisBC Energy companies primarily due to: (i) the $8 million unfavourable impact for the first half of 2013 of the regulatory decision in May 2013 related to the first phase of the GCOC Proceeding; (ii) lower gas transportation volumes to industrial customers; and (iii) lower-than-expected customer additions. The decreases were partially offset by earnings contribution from growth in energy infrastructure investment.
  • Decreased earnings at FortisBC Electric mainly due to the $2 million unfavourable impact for the first half of 2013 of the regulatory decision in May 2013 related to first phase of the GCOC Proceeding, partially offset by lower-than-expected finance charges, growth in energy infrastructure investment and higher capitalized AFUDC
  • Decreased non-regulated hydroelectric production in Belize, due to lower rainfall
  • Decreased earnings at FortisAlberta due to lower net transmission revenue and timing of the recognition of a regulatory decision in 2012 impacting depreciation, partially offset by timing of operating expenses, growth in energy infrastructure investment and customer growth

Favourable

  • Increased earnings at Newfoundland Power and Maritime Electric due to income tax recoveries of $13 million and $4 million, respectively, associated with Part VI.1 tax

Factors Contributing to Year-to-Date Earnings Variance

Favourable

  • An approximate $22 million after-tax extraordinary gain recognized in the first quarter of 2013 on the settlement of expropriation matters associated with the Exploits Partnership
  • Increased earnings at Newfoundland Power and Maritime Electric due to income tax recoveries associated with Part VI.1 tax, as discussed above
  • Increased earnings at FortisAlberta, due to timing of operating expenses, growth in energy infrastructure investment and customer growth, partially offset by lower net transmission revenue

Unfavourable

  • Higher corporate expenses, for the same reasons discussed above for the quarter
  • Decreased earnings at the FortisBC Energy companies, for the same reasons discussed above for the quarter, as well as higher effective income taxes
  • Decreased non-regulated hydroelectric production in Belize, due to lower rainfall

SEGMENTED RESULTS OF OPERATIONS

The basis of segmentation of the Corporation's reportable segments is consistent with that disclosed in the 2012 Annual MD&A, except as follows as a result of the acquisition of CH Energy Group. Central Hudson is reported in a new segment "Regulated Gas & Electric Utility - United States"; and the former "Non-Regulated - Fortis Properties" segment is now "Non Regulated - Non-Utility" and is comprised of Fortis Properties and Griffith, the non-regulated operations of CH Energy Group.

Segmented Net Earnings Attributable to Common Equity Shareholders (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
Regulated Gas Utilities - Canadian
FortisBC Energy Companies 6 13 (7 ) 91 95 (4 )
Regulated Gas & Electric Utility - United States
Central Hudson - - - - - -
Regulated Electric Utilities - Canadian
FortisAlberta 25 26 (1 ) 51 47 4
FortisBC Electric 8 9 (1 ) 26 25 1
Newfoundland Power 24 11 13 31 18 13
Other Canadian Electric Utilities 9 5 4 15 12 3
66 51 15 123 102 21
Regulated Electric Utilities - Caribbean 6 6 - 9 9 -
Non-Regulated - Fortis Generation 3 6 (3 ) 27 11 16
Non-Regulated - Non-Utility 9 8 1 9 9 -
Corporate and Other (36 ) (22 ) (14 ) (54 ) (43 ) (11 )
Net Earnings Attributable to Common Equity Shareholders 54 62 (8 ) 205 183 22

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 follows.

REGULATED GAS UTILITIES - CANADIAN

FORTISBC ENERGY COMPANIES (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
Gas Volumes (petajoules ("PJ")) 36 40 (4 ) 107 112 (5 )
Revenue ($ millions) 246 264 (18 ) 738 812 (74 )
Earnings ($ millions) 6 13 (7 ) 91 95 (4 )
(1) Includes FEI, FEVI and FEWI

Factors Contributing to Quarterly and Year-to-Date Gas Volumes Variances

Unfavourable

  • Lower average gas consumption by residential and commercial customers, due to warmer temperatures
  • Lower gas transportation volumes to industrial customers

As at June 30, 2013, the total number of customers served by the FortisBC Energy companies was approximately 947,000. Net customer additions for the first half of 2013 were approximately 2,000, comparable to the first half of 2012.

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

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

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

Unfavourable

  • Lower commodity cost of natural gas charged to customers
  • Decreases in the allowed ROE and the equity component of capital structure, as a result of the regulatory decision in May 2013 related to the first phase of the GCOC Proceeding in British Columbia
  • Lower average gas consumption by residential and commercial customers and lower gas transportation volumes to industrial customers

Favourable

  • An increase in the delivery component of customer rates, effective January 1, 2013, mainly due to ongoing investment in energy infrastructure and forecasted higher expenses recoverable from customers as reflected in the 2012/2013 revenue requirements decision received in April 2012

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

Unfavourable

  • Decreases in the allowed ROE and the equity component of the capital structure, as discussed above. The cumulative impact of the decision, effective January 1, 2013, of approximately $8 million was recognized in the second quarter when the decision was received.
  • Lower gas transportation volumes to industrial customers
  • Lower-than-expected customer additions
  • Higher effective income taxes, due to differences in the deductions for income tax purposes compared to accounting purposes

Favourable

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

REGULATED GAS & ELECTRIC UTILITY - UNITED STATES

CENTRAL HUDSON

Central Hudson is a regulated T&D utility serving approximately 300,000 electric and 77,000 natural gas customers in eight counties of New York State's Mid-Hudson River Valley. The Company's electric assets, which comprise approximately 77% of its total assets as at June 30, 2013, include over 11,700 kilometres of distribution lines and approximately 2,300 kilometres of transmission lines. The electric business met a peak demand of 1,168 MW in 2012. Central Hudson's natural gas assets, which comprise the remaining 23% of its total assets as at June 30, 2013, include approximately 1,900 kilometres of distribution pipelines and more than 264 kilometres of transmission pipelines. The gas business met a peak day demand of 115 TJ in 2012.

Central Hudson primarily relies on electricity purchases from third-party providers and the New York Independent System Operator ("NYISO")-administered energy and capacity markets to meet the demands of its full-service electricity customers. It also generates a small portion of its electricity requirements. Central Hudson purchases its gas supply requirements from a number of suppliers at various receipt points on pipelines that it has contracted with for firm transport capacity.

Regulation

Central Hudson is regulated by the PSC regarding such matters as rates, construction, operations, financing and accounting. Certain activities of the Company are subject to regulation by the U.S. Federal Energy Regulatory Commission under the Federal Power Act (United States). Central Hudson is also subject to regulation by the North American Electric Reliability Corporation.

Central Hudson operates under COS regulation as administered by the PSC. The PSC provides for the use of a future test year in the establishment of rates for the utility and, pursuant to this method, the determination of the approved rate of return on forecast rate base and deemed capital structure, together with the forecast of all reasonable and prudent costs, establishes the revenue requirement upon which the Company's customer rates are determined. Once rates are approved, they are not adjusted as a result of actual COS being different from that which was applied for, other than for certain prescribed costs that are eligible for deferral account treatment.

Central Hudson's allowed ROE is set at 10% on a deemed capital structure of 48% common equity. The Company began operating under a three-year rate order issued by the PSC effective July 1, 2010. As approved by the PSC in June 2013, the original three-year rate order has been extended for two years, through June 30, 2015, as a condition required to close the acquisition of CH Energy Group by Fortis. Effective July 1, 2013, Central Hudson is also subject to a modified earnings sharing mechanism, whereby the Company and customers share equally earnings in excess of the allowed ROE up to an achieved ROE that is 50 basis points above the allowed ROE, and share 10%/90% (Company/customers) earnings in excess of 50 basis points above the allowed ROE.

Central Hudson's approved regulatory regime also allows for full recovery of purchased electricity and natural gas costs. The Company's rates also include Revenue Decoupling Mechanisms ("RDMs") which are intended to minimize the earnings impact resulting from reduced energy consumption as energy-efficiency programs are implemented. The RDMs allow the Company to recognize electric delivery revenue and gas revenue at the levels approved in rates for most of Central Hudson's customer base. Deferral account treatment is approved for certain other specified costs, including provisions for manufactured gas plant ("MGP") site remediation, pension and other post-employment benefit ("OPEB") costs.

Financial Highlights

The financial statements of Central Hudson have been included in the consolidated financial statements of Fortis commencing June 27, 2013, the date of acquisition. Other than expenses associated with customer and community benefits offered by the Corporation to close the acquisition of CH Energy Group reported in the Corporate and Other segment, financial performance for Central Hudson from the date of acquisition through June 30, 2013 did not have a material impact on the Corporation's consolidated statement of earnings.

Seasonality impacts the delivery revenues of Central Hudson, as sales of electricity are highest during the summer months, primarily due to the use of air conditioning and other cooling equipment, and sales of natural gas are highest during the winter months, primarily due to space heating usage.

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
Energy Deliveries (gigawatt hours ("GWh")) 3,995 3,853 142 8,486 8,335 151
Revenue ($ millions) 117 110 7 235 218 17
Earnings ($ millions) 25 26 (1 ) 51 47 4

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 10,000 year over year as at June 30, 2013, driven by favourable economic conditions and a high commodity price for oil
  • Higher average consumption by commercial and residential customers, due to cooler temperatures

Unfavourable

  • Lower average consumption by oil and gas customers, mainly in the first quarter of 2013, due to decreased activity associated with a low commodity price for natural gas
  • Lower average consumption by farm and irrigation customers, primarily due to increased rainfall in the second quarter of 2013

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 and Year-to-Date Revenue Variances

Favourable

  • An interim increase in customer electricity distribution rates, effective January 1, 2013, associated with the regulator's interim decision received in March 2013 related to FortisAlberta's PBR Compliance Application
  • Growth in the number of customers

Unfavourable

  • Lower net transmission revenue, due to approximately $3 million of favourable volume variances recognized in the second quarter of 2012. As approved by the regulator in April 2012, FortisAlberta assumed the risk of volume variances related to net transmission costs during 2012. The deferral of transmission volume variances, however, was reinstated by the regulator effective January 1, 2013. Year-to-date 2013, lower net transmission revenue was partially offset by approximately $2 million recognized in the first quarter of 2013 associated with the finalization of the 2012 net transmission volume variances.

Factors Contributing to Quarterly Earnings Variance

Unfavourable

  • Lower net transmission revenue of approximately $3 million, as discussed above
  • Lower depreciation rates, effective January 1, 2012, as a result of the 2012 distribution revenue requirements decision received in April 2012. The cumulative impact of the overall decrease in depreciation rates was recognized in the second quarter of 2012, when the decision was received. Approximately $3 million of decreased depreciation expense related to the first quarter of 2012.

Favourable

  • Timing of operating expenses
  • Rate base growth, due to continued investment in energy infrastructure
  • Growth in the number of customers

Factors Contributing to Year-to-Date Earnings Variance

Favourable

  • The same factors discussed above for the quarter

Unfavourable

  • Lower net transmission revenue of approximately $1 million, as discussed above

In June 2013 parts of FortisAlberta's service territory were impacted by the flooding in southern Alberta. Restoration efforts related to the flood did not have a material impact on the consolidated financial statements for the three and six months ended June 30, 2013. Restoration efforts are ongoing and the final impact on FortisAlberta's operations, assets, earnings and cash flow is not fully determinable at this time.

FORTISBC ELECTRIC (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
Electricity Sales (GWh) 681 676 5 1,572 1,585 (13 )
Revenue ($ millions) 68 67 1 156 154 2
Earnings ($ millions) 8 9 (1 ) 26 25 1
(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. Excludes the non-regulated generation operations of FortisBC Inc.'s wholly owned partnership, Walden Power Partnership. In March 2013 FortisBC Inc. acquired the City of Kelowna's electrical utility assets for approximately $55 million. For further information, refer to the "Significant Items" section of this MD&A.

Factor Contributing to Quarterly Electricity Sales Variance

Favourable

  • Higher average consumption, due to cooler temperatures in the second quarter of 2012

Factor Contributing to Year-to-Date Electricity Sales Variance

Unfavourable

  • Lower average consumption, due to warmer temperatures in the first quarter of 2013

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

Favourable

  • An increase in customer electricity rates, effective January 1, 2013, mainly due to ongoing investment in energy infrastructure and forecasted certain higher expenses recoverable from customers as reflected in the 2012/2013 revenue requirements decision received in August 2012
  • Revenue associated with the acquisition of the City of Kelowna's electrical utility assets in March 2013

Unfavourable

  • Differences in the amortization to revenue of flow-through adjustments owing to customers period over period
  • A decrease in the interim allowed ROE, as a result of the regulatory decision in May 2013 related to the first phase of the GCOC Proceeding
  • Lower contribution from non-regulated operating, maintenance and management services

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

Unfavourable

  • A decrease in the interim allowed ROE, as discussed above. The cumulative impact of the decision, effective January 1, 2013, of approximately $2 million was recognized in the second quarter when the decision was received.
  • Higher effective income taxes, due to lower deductions for income tax purposes

Favourable

  • Lower-than-expected finance charges
  • Rate base growth, due to continued investment in energy infrastructure, including the acquisition of the City of Kelowna's electrical utility assets in March 2013
  • Higher capitalized AFUDC, as approved by the regulator

NEWFOUNDLAND POWER

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
Electricity Sales (GWh) 1,288 1,259 29 3,230 3,173 57
Revenue ($ millions) 132 130 2 329 322 7
Earnings ($ millions) 24 11 13 31 18 13

Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances

Favourable

  • Growth in the number of customers
  • Higher average consumption, reflecting the higher use of electric-versus-oil heating in new home construction combined with economic growth

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

Favourable

  • The 2.3% and 1.8% increase in electricity sales for the quarter and year to date, respectively

Unfavourable

  • Lower amortization to revenue of regulatory liabilities and deferrals, as approved by the regulator

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

Favourable

  • An approximate $13 million income tax recovery in the second quarter of 2013, due to the enactment of higher deductions associated with Part VI.1 tax
  • Rate base growth, due to continued investment in energy infrastructure
  • Electricity sales growth

OTHER CANADIAN ELECTRIC UTILITIES (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
Electricity Sales (GWh) 558 563 (5 ) 1,229 1,208 21
Revenue ($ millions) 87 82 5 183 173 10
Earnings ($ millions) 9 5 4 15 12 3
(1) Comprised of 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

Unfavourable

  • Lower average consumption by customers in Ontario in the second quarter of 2013, reflecting more moderate temperatures, energy conservation and continued weak economic conditions in the region

Favourable

  • Higher average consumption by residential customers on Prince Edward Island ("PEI"), due to cooler temperatures and an increase in the number of customers using electricity for home heating
  • Higher average consumption by commercial customers in the agricultural processing sector on PEI, primarily during the second quarter of 2013

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

Favourable

  • Higher electricity sales on PEI combined with an increase in the basic component of customer rates at Maritime Electric, effective March 1, 2013
  • The flow through in customer electricity rates of higher energy supply costs at FortisOntario

Unfavourable

  • Lower electricity sales in Ontario in the second quarter of 2013

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

Favourable

  • An approximate $4 million income tax recovery at Maritime Electric in the second quarter of 2013, due to the enactment of higher deductions associated with Part VI.1 tax
  • Electricity sales growth at Maritime Electric

Unfavourable

  • Timing of the recognition of a regulatory rate of return adjustment at Maritime Electric in 2013 as compared to 2012

REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
Average US:CDN Exchange Rate (2) 1.02 1.01 0.01 1.01 1.01 -
Electricity Sales (GWh) 193 184 9 363 350 13
Revenue ($ millions) 70 67 3 136 130 6
Earnings ($ millions) 6 6 - 9 9 -
(1) Comprised of Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 60% controlling interest and two wholly owned utilities in the Turks and Caicos Islands, FortisTCI Limited ("FortisTCI") and Turks and Caicos Utilities Limited ("TCU"), acquired in August 2012, (collectively "Fortis Turks and Caicos"). In June 2013 Atlantic Equipment & Power (Turks and Caicos) Ltd. was amalgamated with FortisTCI.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar.

Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances

Favourable

  • Increased electricity sales at Fortis Turks and Caicos due to approximately 5 GWh and 10 GWh of electricity sales in the second quarter and first half of 2013, respectively, at TCU, which was acquired in August 2012, partially offset by lower average consumption by commercial customers at FortisTCI, mainly due to higher fuel costs and resulting energy conservation
  • Growth in the number of customers at Caribbean Utilities and lower rainfall experienced on Grand Cayman, which increased air conditioning load

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

Favourable

  • The 4.9% and 3.7% increase in electricity sales for the quarter and year to date, respectively
  • An increase in electricity rates for FortisTCI's large hotel customers, effective April 1, 2012
  • A 1.8% increase in base customer electricity rates at Caribbean Utilities, effective June 1, 2013

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

Favourable

  • Increased electricity sales at Caribbean Utilities
  • Decreased operating expenses at Caribbean Utilities, mainly due to lower employee-related costs and maintenance costs

Unfavourable

  • Overall higher depreciation expense, due to continued investment in energy infrastructure
  • Decreased electricity sales at FortisTCI

NON-REGULATED - FORTIS GENERATION (1)

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
Energy Sales (GWh) 83 87 (4 ) 138 175 (37 )
Revenue ($ millions) 7 9 (2 ) 12 18 (6 )
Earnings ($ millions) 3 6 (3 ) 27 11 16
(1) Comprised of the financial results of non-regulated generation assets in Belize, Ontario, British Columbia and Upstate New York, with a combined generating capacity of 103 MW, mainly hydroelectric

Factors Contributing to Quarterly and Year-to-Date Energy Sales Variances

Unfavourable

  • Decreased production in Belize, due to lower rainfall

Favourable

  • Increased production in Ontario, Upstate New York and British Columbia, due to higher rainfall, and a generating unit in New York State being returned to service for part of the second quarter of 2013

Factor Contributing to Quarterly and Year-to-Date Revenue Variances

Unfavourable

  • Decreased production in Belize

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

Unfavourable

  • Decreased production in Belize

Favourable

  • An approximate $22 million after-tax extraordinary gain recognized in the first quarter of 2013 on the settlement of expropriation matters associated with Exploits Partnership. For further information refer to the "Significant Items" section of this MD&A.

Since the end of the second quarter of 2013, a tropical depression that passed over Belize provided enough precipitation to fill the Chalillo reservoir. The hydroelectric generating facilities in Belize are currently running at full capacity.

NON-REGULATED - NON-UTILITY

The Non-Utility segment is comprised of Fortis Properties and Griffith. Fortis Properties owns and operates 23 hotels, comprised of more than 4,400 rooms, in eight Canadian provinces, and owns and operates approximately 2.7 million square feet of commercial office and retail space, primarily in Atlantic Canada. Non-regulated operations of CH Energy Group mainly consist of Griffith, which is primarily a fuel delivery business serving approximately 56,000 customers in the Mid-Atlantic Region of the United States.

Fortis Properties

Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
Hospitality - Revenue per Available Room ("RevPar") $87.76 $85.56 2.6 % $76.96 $76.05 1.2 %
Real Estate - Occupancy Rate (as at) 92.3 % 91.7 % 0.7 % 92.3 % 91.7 % 0.7 %
Revenue ($ millions) 65 64 1 118 116 2
Earnings ($ millions) 9 8 1 9 9 -

Factors Contributing to Quarterly RevPar Variance

Favourable

  • A 1.6% increase in occupancy, driven by hotel operations in western Canada
  • A 1.0% increase in the average daily room rate, mainly in western Canada

Factor Contributing to Year-to-Date RevPar Variance

Favourable

  • A 1.5% increase in the average daily room rate, mainly in western Canada, partially offset by a 0.3% decrease in occupancy, mainly at hotel operations in central Canada

Factor Contributing to Quarterly and Year-to-Date Revenue Variances

Favourable

  • Increased revenue at the Hospitality Division, mainly due to contribution from the StationPark All Suite Hotel, which was acquired in October 2012, and hotel operations in western Canada

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

Favourable

  • Improved performance at the Hospitality Division, primarily due to hotel operations in western Canada

Unfavourable

  • Increased depreciation, due to capital additions and improvements

Griffith

Griffith is an indirect wholly owned subsidiary of CH Energy Group, which supplies heating oil, gasoline, diesel fuel, kerosene and propane to approximately 56,000 customers in Maryland, Delaware, Washington D.C. and Virginia in the United States. Griffith also installs and maintains heating, ventilating and air conditioning equipment in these markets, which includes a customer base of an additional 12,000.

The financial statements of Griffith have been included in the consolidated financial statements of Fortis commencing June 27, 2013, the date of acquisition. Financial performance for Griffith from the date of acquisition through June 30, 2013 did not have a material impact on the Corporation's consolidated statement of earnings.

A considerable portion of the sales volume for Griffith is derived directly or indirectly from usage in space heating and air conditioning and, as a result, seasonality impacts Griffith's earnings.

CORPORATE AND OTHER (1)

Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
Revenue 7 7 - 13 13 -
Operating Expenses 3 3 - 6 6 -
Depreciation and Amortization - - - 1 1 -
Other Income (Expenses), Net (46 ) (3 ) (43 ) (44 ) (8 ) (36 )
Finance Charges 11 12 (1 ) 21 23 (2 )
Income Tax Recovery (31 ) (1 ) (30 ) (33 ) (5 ) (28 )
(22 ) (10 ) (12 ) (26 ) (20 ) (6 )
Preference Share Dividends 14 12 2 28 23 5
Net Corporate and Other Expenses (36 ) (22 ) (14 ) (54 ) (43 ) (11 )
(1) Includes Fortis net corporate expenses, net expenses of non-regulated FortisBC Holdings Inc. ("FHI") corporate-related activities, and the financial results of FHI's wholly owned subsidiary FortisBC Alternative Energy Services Inc. and FHI's 30% ownership interest in CustomerWorks Limited Partnership

Factors Contributing to Quarterly and Year-to-Date Net Corporate and Other Expenses Variances

Unfavourable

  • Increased other expenses primarily due to: (i) approximately $41 million (US$40 million), $26 million (US$26 million) after tax, in expenses associated with customer and community benefits offered by the Corporation to close the acquisition of CH Energy Group in June 2013; and (ii) approximately $8 million ($6 million after tax) in costs incurred in the second quarter of 2013 related to the acquisition of CH Energy Group, compared to approximately $4 million ($3 million after tax) and $8 million ($7 million after tax) for the second quarter and first half of 2012, respectively. For additional information on the acquisition of CH Energy Group, refer to the "Significant Items" section of this MD&A. The above-noted increases were partially offset by foreign exchange gains of approximately $3 million and $5 million for the second quarter and the first half of 2013, respectively, associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity, compared to approximately $2 million and $0.5 million, respectively, for the same periods in 2012.
  • Higher preference share dividends, due to the issuance of First Preference Shares, Series J in November 2012

Favourable

  • An approximate $8 million income tax recovery in the second quarter of 2013, due to the enactment of higher deductions associated with Part VI.1 tax, compared to income tax expense of $3 million associated with Part VI.1 tax for the same quarter last year. In the first quarter of 2013, income tax expense included $2 million associated with Part VI.1 tax.
  • An approximate $5 million income tax recovery associated with the release of income tax provisions in the second quarter of 2013
  • Lower finance charges, primarily due to higher capitalized interest associated with the financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion

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 2013 are summarized as follows.

NATURE OF REGULATION
Allowed Returns (%) Supportive Features
Regulated
Utility
Regulatory
Authority
Allowed
Common
Equity
(%)
2011 2012 2013 Future or Historical Test Year
Used to Set Customer Rates
ROE COS/ROE
FEI



BCUC



38.5(1)



9.50



9.50



8.75



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(2)
10.00
10.00
9.25(2)
FEWI
BCUC
40(2)
10.00
10.00
9.25(2)
ROEs established by the BCUC - 2013 ROEs are under review
Future Test Year
FortisBC
Electric
BCUC
40(2)
9.90
9.90
9.15(2)
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 - 2013 ROE is under review
Future Test Year
Central
Hudson
PSC
48(3)
10.00
10.00
10.00(3)
COS/ROE




































Earnings sharing mechanism effective July 1, 2013: 50%/50% sharing of earnings above the allowed ROE up to 50 basis points above the allowed ROE; and 10%/90% sharing of earnings in excess of 50 basis points above the allowed ROE
ROE established by PSC
Future Test Year
Fortis-
Alberta
Alberta
Utilities
Commission
("AUC")
41(4)
8.75
8.75
8.75(4)
COS/ROE












PBR mechanism for 2013 through 2017 with capital tracker account and other supportive features






ROE established by the AUC - 2013 ROE is under review






2012 test year with 2013 through 2017 rates set using PBR mechanism
Newfound-
land
Power
Newfoundland
and Labrador
Board of
Commissioners
of Public
Utilities ("PUB")
45
8.38 +/-
50 bps
8.80 +/-
50 bps
8.80 +/-
50 bps
COS/ROE





















The allowed ROE was set using an automatic adjustment formula tied to long-term Canada bond yields for 2011. ROE established by the PUB for 2012 through 2015
Future Test Year
Maritime
Electric
Island
Regulatory
and Appeals
Commission
40
9.75
9.75
9.75
COS/ROE
Future Test Year
ROE Canadian Niagara Power - COS/ROE
Fortis-
Ontario
Ontario Energy
Board ("OEB")





Algoma Power - COS/ROE and subject to Rural and Remote Rate Protection ("RRRP") program

Canadian
Niagara
Power
40
8.01
8.01
8.93(5)
Algoma Power 40 9.85 9.85 9.85(5)


Franchise
Agreement




Cornwall Electric - Price cap with commodity cost flow through
Cornwall
Electric
Canadian Niagara Power - 2009 test year for 2011 and 2012; 2013 test year for 2013






Algoma Power - 2011 test year for 2011, 2012 and 2013
ROA COS/ROA
Caribbean
Utilities

Electricity
Regulatory
Authority
("ERA")
N/A


7.75 -
9.75

7.25 -
9.25

6.50 -
8.50


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
Government of
the Turks and
Caicos Islands
N/A
17.50(6)
17.50(6)
17.50(6)
COS/ROA




























If the actual ROA is lower than the allowed ROA, due to additional costs resulting from a hurricane or other event, the utilities may apply for an increase in customer rates in the
following year.
Future Test Year
(1) Effective January 1, 2013. For 2011 and 2012, the allowed deemed equity component of the capital structure was 40%.
(2) Capital structures and allowed ROEs for 2013 are interim and are subject to change based on the outcome of the second phase of the GCOC Proceeding. The allowed ROEs for 2013 reflect the benchmark 8.75% allowed ROE for FEI, as set by the BCUC, and risk premiums associated with each of these utilities.
(3) Effective until June 30, 2015
(4) Capital structure and allowed ROE for 2013 are interim and are subject to change based on the outcome of the cost of capital proceeding.
(5) Based on the ROE automatic adjustment formula, the allowed ROE for regulated electric utilities in Ontario is 8.93% for 2013. This ROE is not applicable to the regulated electric utilities until they are scheduled to file full COS rate applications. As a result, the allowed ROE of 8.93% is not applicable to Algoma Power for 2013.
(6) Amount provided under licences as it relates to FortisTCI. Amount provided under licence for TCU is 15%. Achieved ROAs at the utilities were significantly lower than those allowed under licences as a result of the inability, due to economic and political factors, to increase base electricity rates associated with significant capital investment in recent years.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
Regulated Utility Summary Description
FEI/FEVI/FEWI - Effective January 1, 2013, rates increased by approximately 1.6% for typical residential customers at FEI in the Lower Mainland, as a result of an increase in delivery rates in accordance with the BCUC's decision in April 2012 pertaining to the FortisBC Energy companies' 2012/2013 Revenue Requirements Application ("RRA"), partially offset by a decrease in midstream rates. Natural gas commodity rates effective January 1, 2013 remained unchanged for customers at FEI.

- In February 2012 the BCUC approved FEI's amended application for a general tariff for the provision of compressed natural gas and liquefied natural gas ("LNG") refuelling services for transportation vehicles. FEI has received either permanent or interim rate approval for three refuelling projects. In June 2013 FEI received a decision on changing its LNG sales and dispensing service rate schedule from a pilot program to a permanent program. The decision did not approve the program as permanent, but extended the pilot program until the end of 2020, and set out the rate to be charged. In addition, FEI received BCUC approval for rate treatment of expenditures under the Greenhouse Gas Reductions (Clean Energy) Regulation ("GGRR") under the Clean Energy Act that was announced in May 2012. In May 2013 FEI filed an application for approval of its first refuelling station under the GGRR and a decision on the rate to be charged to customers is expected in the third quarter of 2013.
- In August 2011 FEI received a BCUC decision on the use of Energy Efficiency and Conservation ("EEC") funds as incentives for natural gas-fuelled vehicles ("NGVs"). FEI had made these funds available to assist large customers in purchasing NGVs in lieu of vehicles fuelled by diesel. The decision determined that it was not appropriate to use EEC funds for the above-noted purpose and the BCUC requested that FEI provide further submissions to determine the prudency of the EEC incentives. In August 2012 an application was filed with the BCUC to review the prudency of the EEC incentives totalling approximately $6 million. A decision was received in April 2013 in which the BCUC determined that the EEC incentives for NGVs were prudently incurred and can be recovered from customers in rates.

- During the first quarter of 2013, the BCUC approved the capital expenditures for the Telus Garden project at FortisBC Alternative Energy Services Inc. ("FAES"); however, approval of revisions to the rate design and rates is pending. In July 2013 the BCUC approved the capital expenditures for the Kelowna District Energy System project; however, approval of revisions to the rate design and rates is also pending. In May 2013 the BCUC initiated a process to review a proposal for a streamlined regulatory framework for thermal energy system utilities in British Columbia. The process is ongoing with a decision expected in the third quarter of 2013.

- In April 2012 the FortisBC Energy companies applied to the BCUC for the necessary approvals to amalgamate the three utilities and implement common rates across the service territories served by the amalgamated entity, effective January 1, 2014. The BCUC issued its decision in February 2013 denying the request to implement common rates. The FortisBC Energy companies filed a leave to appeal the decision to the British Columbia Court of Appeal in March 2013 and filed an Application for Reconsideration with the BCUC in April 2013. In June 2013 the BCUC determined that the reconsideration application will be heard and has set out a regulatory timetable for filing of evidence.

- The public oral hearing for the first phase of a GCOC Proceeding to determine the allowed ROE and appropriate capital structure for FEI, the designated low-risk benchmark utility in British Columbia, occurred in December 2012. In May 2013 the BCUC issued its decision on the first phase of the GCOC Proceeding. Effective January 1, 2013, the decision set the ROE of the benchmark utility at 8.75%, compared to 9.50% for 2012, with a 38.5% equity component of capital structure, compared to 40% for 2012. The equity component of capital structure will remain in effect until December 31, 2015. Effective January 1, 2014 through December 31, 2015, the BCUC is also introducing an Automatic Adjustment Mechanism ("AAM") to set the ROE for the benchmark utility on an annual basis. The AAM will take effect when the long-term Government of Canada bond yield exceeds 3.8%. FEVI, FEWI and FortisBC Electric will have their allowed ROEs and capital structures determined in the second phase of the GCOC Proceeding. As a result of the BCUC's decision on the first phase of the GCOC Proceeding, which reduced the allowed ROE of the benchmark utility by 75 basis points, the interim allowed ROEs for FEVI, FEWI and FortisBC Electric decreased to 9.25%, 9.25% and 9.15%, respectively, effective January 1, 2013, while the deemed equity component of capital structures remained unchanged. The allowed ROEs and equity component of capital structures for FEVI, FEWI and FortisBC Electric could change further as a result of the outcome of the second phase of the GCOC Proceeding. In March 2013 the BCUC initiated the second phase of the GCOC Proceeding. The review process for the second phase is underway and in July 2013 FEVI, FEWI and FortisBC Electric filed evidence in accordance with the review. A decision on the second phase of the GCOC Proceeding is expected in the first half of 2014. For further discussion on the nature of the GCOC Proceeding, refer to the "Material Regulatory Decisions and Applications" section of the Corporation's 2012 Annual MD&A.

- In June 2013 FEI filed an application for a Multi-Year Performance-Based Ratemaking Plan for 2014 through 2018. The application assumes a forecast average rate base for 2014 of approximately $2,789 million. The application requests approval of a delivery rate increase of approximately 1% for 2014 determined under a formula approach for operating and capital costs, and a continuation of this rate-setting methodology for a further four years. The review process for the application will continue throughout 2013.
FortisBC Electric - Effective January 1, 2013, as approved by the BCUC in its August 2012 decision pertaining to FortisBC Electric's 2012/2013 RRA, customer electricity rates increased 4.2%.

- In July 2012 FortisBC Electric filed its Advanced Metering Infrastructure ("AMI") Application, which was updated in early 2013. A regulatory review by the BCUC and various interveners concluded with an oral hearing in March 2013. In July 2013 the BCUC approved the AMI project for a total cost of approximately $51 million. The AMI project proposes to improve and modernize FortisBC Electric's grid by exchanging its manually read meters with advanced meters. As a condition of the BCUC decision, FortisBC Electric has confirmed that it will file, by November 2013, an application for an opt-out provision which would require the incremental cost of opting-out of AMI to be borne by customers who choose to opt-out.

- In March 2013 the BCUC approved the acquisition by FortisBC Electric of the City of Kelowna's electrical utility assets and allowed for approximately $38 million of the $55 million purchase price to be included in FortisBC Electric's rate base, resulting in the recognition of approximately $14 million of goodwill and a $3 million deferred income tax asset. The transaction closed in March 2013, which allows FortisBC Electric to directly serve approximately 15,000 customers formerly served by the City. Prior to the acquisition, FortisBC Electric had provided the City with electricity under a wholesale tariff and had operated and maintained the City's electrical utility assets under contract since 2000.

- In March 2012 the BCUC ordered a written hearing process to review the prudency of approximately $29 million in capital expenditures already incurred related to the Kettle Valley Distribution Source Project, which was substantially completed in 2009. In April 2013 the BCUC issued a decision approving substantially all of the $29 million to be included in rate base, effective from January 1, 2012.

- In July 2013 FortisBC Electric filed an application for a Multi-Year Performance-Based Ratemaking Plan for 2014 through 2018. The application assumes a forecast midyear rate base for 2014 of approximately $1,227 million. The application requests approval of a basic customer rate increase for 2014 of approximately 3.3%, determined under a formula approach for operating and capital costs, and a continuation of this rate-setting methodology for a further four years. The review process for the application will continue throughout 2013.
FortisAlberta - In September 2012 the AUC issued a generic PBR Decision outlining the PBR framework applicable to distribution utilities in Alberta, including FortisAlberta, for a five-year term, which commenced January 1, 2013. In the PBR Decision, a formula that estimates inflation annually and assumes productivity improvements is to be used by the distribution utilities to determine customer rates on an annual basis. The PBR framework also includes mechanisms for the recovery or settlement of items determined to flow through directly to customers and the recovery of costs related to capital expenditures that are not being recovered through the inflationary factor of the formula. The AUC also approved: (i) a Z factor permitting an application for recovery of costs related to significant unforeseen events; (ii) a PBR re-opener mechanism permitting an application to re-open and review the PBR plan to address specific problems with the design or operation of the PBR plan; and (iii) an ROE efficiency carry-over mechanism permitting an efficiency incentive by allowing the utility to continue to benefit from any efficiency gains achieved during the PBR term for two years following the end of the term. The PBR formula does, however, raise some concern and uncertainty for FortisAlberta regarding the treatment of certain capital expenditures. While the PBR Decision did provide for a capital tracker mechanism for the recovery of costs related to certain capital expenditures, FortisAlberta sought further clarification regarding this mechanism in a Review and Variance ("R&V") Application and a Capital Tracker Application and sought leave to appeal the issue to the Alberta Court of Appeal.

- In March 2013 the AUC issued a decision denying the R&V Application. FortisAlberta has filed a leave to appeal the decision on similar grounds as the leave to appeal the 2012 PBR Decision. Both appeals have been adjourned pending further determinations in outstanding PBR-related proceedings.

- In January 2013 FortisAlberta filed a Phase II Distribution Tariff Application ("Phase II DTA"), which proposed rates by customer class based on a cost allocation study and requested that the 2012 interim distribution rates by customer class be made final for 2012 and 2013, subject to further adjustments as a result of the PBR decision. The Phase II DTA will continue as a written proceeding with a decision expected in the third quarter of 2013. The outcome of the proceeding is not expected to have a material impact on FortisAlberta's 2013 financial results.
- In March 2013 the AUC issued an interim decision regarding the Compliance Applications filed by the distribution utilities in Alberta. The interim decision approved a combined inflation and productivity factor of 1.71%, certain adjustments to the Company's going-in rates, including specific flow-through amounts, and the recovery, on an interim basis, of 60% of the revenue requirement associated with the 2013 capital tracker expenditures applied for by FortisAlberta. For FortisAlberta, the AUC approved approximately $14.5 million of the $24 million in revenue requested in the utility's 2013 Capital Tracker Application. The decision resulted in an interim increase in FortisAlberta's distribution rates of approximately 4%, effective January 1, 2013, with collection from customers commencing April 1, 2013. A final decision on the Compliance Application was received in July 2013 directing the Company to continue to use interim rates until all remaining 2013 placeholders have been determined. A hearing on the Capital Tracker Application commenced in June 2013, with a decision expected in the second half of 2013.

- In October 2012 the AUC initiated a 2013 GCOC Proceeding to establish the final allowed ROE for 2013 and determine whether a formulaic ROE automatic adjustment mechanism should be re-established. In November 2012 the 2013 GCOC Proceeding was suspended until other regulatory matters were resolved. In April 2013 the AUC recommenced the 2013 GCOC Proceeding to set the allowed ROE and capital structure for distribution utilities in Alberta for 2013, as well as the allowed ROE for 2014. In addition, an interim allowed ROE for 2015 will be established. The AUC may consider the possibility of re-establishing a formulaic ROE automatic adjustment mechanism at this time. The process for the 2013 GCOC Proceeding commenced in the second quarter of 2013 and a hearing is scheduled for early 2014. The expected outcome of this proceeding is currently unknown.

- In its 2011 GCOC Decision, the AUC made statements regarding cost responsibility for stranded assets, which FortisAlberta and other utilities challenged as being incorrectly made. As a result, FortisAlberta, together with other Alberta utilities, filed an R&V Application with the AUC. In June 2012 the AUC decided it would not permit an R&V of the decision in question but would examine the issue in the Utility Asset Disposition ("UAD") Proceeding, which was reinitiated in November 2012. FortisAlberta and the other Alberta utilities had also sought leave to appeal the stranded asset pronouncements to the Alberta Court of Appeal and temporarily adjourned that court process pending the AUC's follow-up proceeding. Any decision by the AUC regarding the treatment of stranded assets does not alter a utility's right to a reasonable opportunity to recover prudent COS and the right to earn a reasonable ROE. In July 2013 FortisAlberta, together with other Alberta utilities, filed reply arguments in the UAD Proceeding, after which the AUC will commence deliberations with a decision expected in the fourth quarter of 2013.
Newfoundland
Power
- In April 2013 the PUB issued its decision related to Newfoundland Power's 2013/2014 General Rate Application ("GRA"), which was filed in September 2012, to establish the Company's cost of capital for rate-making purposes. In its decision, the PUB ordered that the allowed ROE and common equity component of capital structure remain at 8.8% and 45%, respectively, for 2013 through 2015. The PUB also ordered: (i) the recognition of pension expense for regulatory purposes in accordance with US GAAP and the related regulatory asset to be recovered from customers over 15 years; (ii) a decrease in the overall composite depreciation rate to 3.42% from 3.47%; (iii) the deferral of annual customer energy conservation program costs to be recovered from customers over the subsequent seven-year period; and (iv) the approval of various regulatory amortizations over a three-year period, including cost-recovery deferrals recognized in 2011 and 2012, costs associated with the GRA and the December 31, 2011 balance in the Weather Normalization Account. The impact of the decision resulted in an overall average increase in customer electricity rates of approximately 4.8% effective July 1, 2013 and the deferral of approximately $4 million of costs incurred in 2013 but not recovered from customers, due to the timing of collection in customer rates. The cumulative impact of the decision was recorded in the second quarter of 2013, when the decision was received. Newfoundland Power is required to file its GRA for 2016 on or before June 1, 2015.
- Effective July 1, 2013, the PUB approved an overall average decrease in Newfoundland Power's customer electricity rates of approximately 3.1% to reflect the combined impact of the annual operation of Newfoundland Power's Rate Stabilization Account ("RSA") and the above-noted GRA decision. Through the annual operation of Newfoundland Hydro's 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 the Company's RSA. As a result of a decrease in the forecast cost of oil to be used to generate electricity at Newfoundland Hydro, customer electricity rates decreased approximately 7.9% effective July 1, 2013. The RSA also captures variances in certain of Newfoundland Power's costs, such as pension and energy supply costs. The decrease in customer rates as a result of the operation of the RSA is not expected to impact Newfoundland Power's earnings in 2013.

- In June 2013 Newfoundland Power filed an application with the PUB requesting approval for its 2014 Capital Expenditure Plan totalling approximately $85 million, before customer contributions.
Maritime Electric - In December 2012 the Electric Power (Energy Accord Continuation) Amendment Act ("Accord Continuation Act") was enacted, which sets out the inputs, rates and other terms for the continuation of the PEI Energy Accord for an additional three years covering the period March 1, 2013 through February 29, 2016. Under the terms of the Accord Continuation Act, Maritime Electric received, in March 2013, proceeds of approximately $47 million from the Government of PEI upon its assumption of Maritime Electric's $47 million regulatory asset related to certain deferred incremental replacement energy costs during the refurbishment of Point Lepreau. Over the above-noted three-year period, increases in electricity costs for a typical residential customer have been set at 2.2%, effective March 1 annually, and Maritime Electric's allowed ROE has been capped at 9.75% each year. The resulting customer rate increases are due to the collection from customers by Maritime Electric, acting as an agent on behalf of the Government of PEI, of Point Lepreau-related costs assumed by the Government of PEI and higher COS. The proceeds were used by Maritime Electric to repay short-term borrowings, to pay a special dividend to Fortis to maintain the utility's capital structure and to finance its capital expenditure program.

- In July 2013 Maritime Electric filed its 2014 Capital Budget Application totalling approximately $28 million, before customer contributions.
FortisOntario - Effective January 1, 2013, residential customer rates in Fort Erie, Gananoque and Port Colborne increased by an average of 6.8%, 5.9% and 7.4%, respectively. The rate increases were the result of the OEB's decision pertaining to FortisOntario's 2013 COS Application using a 2013 forward test year and the recovery of smart meter costs and stranded assets related to conventional meters and reflect an allowed ROE of 8.93%.

- In March 2013 the OEB issued its decision on Algoma Power's Third-Generation Incentive-Rate Mechanism Application for customer electricity distribution rates and smart meter cost recovery, effective January 1, 2013, resulting in an overall increase in residential and commercial customer distribution rates of 3.75%. Residential and commercial customer distribution rates are adjusted by the average increase in customer rates of all other distributor rate changes in Ontario in the most recent rate year. The difference in the recovery of COS in residential and commercial customer distribution rates and the revenue requirement is compensated from RRRP program funding. Recovery of smart meter costs allocated to residential customers will also be recovered from RRRP program funding as ordered by the OEB. Total RRRP program funding for 2013 is expected to be approximately $12 million.
Caribbean Utilities - In June 2013 the ERA approved Caribbean Utilities' 2013-2017 Capital Investment Plan for US$123 million related to non-generation installation capital expenditures. Capital expenditures relating to additional generation installation are subject to ERA approval through a competitive bid process.

- A Certificate of Need was filed with the ERA by Caribbean Utilities in November 2011, due to the upcoming retirements of some of the Company's generating units due to begin in mid-2014. In March 2012 proposals for the installation of new generation units from six qualified bidders, including Caribbean Utilities, was requested by the ERA and the Company's proposal was submitted in July 2012. In February 2013 the ERA awarded the bid to develop, install and operate two new 18-MW generation units to a third party. In April 2013 the ERA announced that it would be engaging an independent party to conduct an investigation of irregularities in the bid process. In July 2013 the ERA announced that it has cancelled the solicitation process as a result of unavoidable and unforeseen delays. The need for additional firm generating capacity for mid-2014 remains. In light of the ERA's decision to cancel the solicitation process, Caribbean Utilities will explore all cost-effective options with the ERA to ensure that there is sufficient installed generating capacity to serve the needs of its customers until the firm capacity needs can be met.
- Effective June 1, 2013, following review and approval by the ERA, Caribbean Utilities' base customer electricity rates increased by 1.8% as a result of changes in the applicable consumer price indices and the utility's targeted allowed ROA for 2013.
Fortis Turks and Caicos - In March 2013 the Fortis Turks and Caicos utilities submitted their 2012 annual regulatory filings outlining performance in 2012. Included in the filings were the calculations, in accordance with the utilities' licences, of rate base of US$195 million for 2012 and cumulative shortfall in achieving allowable profits of US$105 million as at December 31, 2012.

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheet between June 30, 2013 and December 31, 2012. The changes in the consolidated balance sheet as at June 30, 2013 associated with the acquisition of CH Energy Group are itemized separately below.

...
Significant Changes in the Consolidated Balance Sheet (Unaudited) between June 30, 2013 and December 31, 2012
Balance Sheet Account Increase
Due to
CH Energy Group
($ millions)

Other
Increase/
(Decrease)
($ millions)
Explanation for Other Increase/(Decrease)
Cash and cash equivalents 81 32 The increase in cash and cash equivalents was not significant.
Accounts receivable 118 (114) The decrease was primarily due to the impact of a seasonal decrease in sales at the FortisBC Energy companies, partially offset by an increase due to the operation of equal payment plans.
Regulatory assets - current and long-term 271 (3) The decrease was mainly due to: (i) proceeds of approximately $47 million received from the Government of PEI in March 2013 upon its assumption of Maritime Electric's replacement energy deferral associated with Point Lepreau; and (ii) the $26 million change in the deferral of the fair market value of the natural gas commodity derivatives at the FortisBC Energy companies. The above decreases were partially offset by an increase in the rate stabilization deferrals at the FortisBC Energy companies, an increase in regulatory deferred income taxes, and the deferral of various other costs, as permitted by the regulators, mainly at the FortisBC utilities and FortisAlberta.
Other assets 41 (3) The decrease in other assets was not significant.
Utility capital assets 1,286 363 The increase primarily related to: (i) $508 million invested in electricity and gas systems; (ii) the impact of foreign exchange on the translation of US dollar-denominated utility capital assets; and (iii) the acquisition of the City of Kelowna's electrical utility assets by FortisBC Electric. The above increases were partially offset by depreciation and customer contributions.
Intangible assets 45 (9) The decrease in intangible assets was not significant.
Goodwill 486 23 The increase in goodwill was not significant.
Short-term borrowings 39 (76) The decrease was primarily due to: (i) a reduction in borrowings at the FortisBC Energy companies due to the seasonality of operations; (ii) the repayment of short-term borrowings at Caribbean Utilities using proceeds from the issuance of long-term debt; and (iii) the repayment of borrowings at Maritime Electric with a portion of proceeds received from the Government of PEI in March 2013.
Accounts payable and other current liabilities 122 (126) The decrease was mainly due to: (i) the timing of Alberta Electric System Operator ("AESO") payments for 2012 transmission costs and lower accounts payable associated with transmission-connected projects at FortisAlberta; (ii) the $26 million change in the fair market value of the natural gas commodity derivatives at the FortisBC Energy companies; (iii) the enactment of higher deductions associated with Part VI.1 tax, resulting in the reversal of approximately $23 million in income tax liabilities; (iv) lower amounts owing for purchased power at Newfoundland Power, associated with seasonality of operations; and (v) timing of payments for trade accounts payable at the FortisBC Energy companies. The decrease was partially offset by an increase in income and other taxes payable at the FortisBC Energy companies.
Regulatory liabilities - current and long-term 155 39 The increase was mainly due to: (i) a higher AESO charges deferral at FortisAlberta; (ii) an increase in non-ARO site removal cost provisions, primarily at FortisAlberta and the FortisBC Energy companies; and (iii) an increase in rate stabilization accounts at the FortisBC Energy companies.
Deferred income tax liabilities - current and long-term 279 40 The increase was driven by tax timing differences related mainly to capital expenditures at the regulated utilities.
Long-term debt (including current portion) 544 742 The increase was driven by higher committed credit facility borrowings at the Corporation to finance a portion of the acquisition of CH Energy Group, advances to the Waneta Expansion Limited Partnership ("Waneta Partnership"), and an equity injection into FortisAlberta in support of energy infrastructure investment. Higher committed credit facility borrowings at the regulated utilities were largely in support of energy infrastructure investment, including the acquisition of the City of Kelowna's electrical utility assets by FortisBC Electric. In addition, Caribbean Utilities issued US$50 million in senior unsecured debentures in May 2013 to repay short-term borrowings and to finance capital expenditures. The translation of US-dollar denominated debt also resulted in an increase for the period. The above-noted increases were partially offset by regularly scheduled debt repayments at the FortisBC Energy companies and Fortis Properties.
Other Liabilities 185