ST. JOHN–S, NEWFOUNDLAND AND LABRADOR — (Marketwire) — 08/03/11 — Fortis Inc. (“Fortis” or the “Corporation”) (TSX: FTS) achieved second quarter net earnings attributable to common equity shareholders of $58 million, or $0.33 per common share, compared to $55 million, or $0.32 per common share, for the second quarter of 2010. Net earnings attributable to common equity shareholders for the first half of 2011 were $175 million, or $1.00 per common share, up $20 million from earnings of $155 million, or $0.90 per common share, for the first half of last year.
Canadian Regulated Electric Utilities contributed earnings of $45 million, up $5 million from the second quarter of 2010. The increase reflected improved results at the electric utilities in western Canada associated with overall growth in utility infrastructure investment, lower market-priced purchased power costs at FortisBC Electric and additional return earned on FortisAlberta–s investment in automated meters.
Canadian Regulated Gas Utilities contributed earnings of $15 million compared to $17 million for the second quarter of 2010. The decrease in earnings was mainly attributable to the timing of operating expenses, partially offset by the impact of growth in utility infrastructure investment and higher gas delivery volumes in the forestry sector. Due to the seasonality of the business, most of the earnings of the gas utilities are realized in the first and fourth quarters.
The average monthly run rate for the Corporation–s 2011 capital program is approximately $100 million, more than 80% of which is being driven by the regulated utilities in western Canada and the Corporation–s non-regulated Waneta hydroelectric generation expansion project in British Columbia (the “Waneta Expansion Project”), in which Fortis holds a 51% controlling interest. Gross capital expenditures for the first half of 2011 totalled $519 million. Several capital projects which commenced prior to 2011 are being completed this year. During the second quarter FortisBC–s gas business substantially completed construction of its liquefied natural gas (“LNG”) storage facility on Vancouver Island at an estimated cost of $214 million. The LNG storage facility is currently being filled and is expected to be available for the upcoming winter heating season. FortisBC–s electricity business expects to substantially complete its $105 million Okanagan Transmission Reinforcement Project later this year. FortisAlberta has substantially completed its $126 million Automated Metering Project, which involved the replacement of approximately 466,000 conventional meters. Work continues on the $900 million Waneta Expansion Project, which is expected to be completed in spring 2015.
With regard to regulatory matters, FortisBC recently filed two-year (2012-2013) rate applications for both its gas and electricity businesses. Earlier in the year, FortisAlberta filed a two-year (2012-2013) rate application, including proposed gross capital expenditures of more than $775 million over the two-year period.
Caribbean Regulated Electric Utilities contributed $7 million, consistent with earnings for the second quarter of 2010. Energy sales at Caribbean Utilities and Fortis Turks and Caicos continue to be impacted by the persistent challenging economic conditions being experienced in the region. Effective June 20, 2011, the Government of Belize (the “GOB”) expropriated the Corporation–s investment in Belize Electricity. Consequently, there will be no future earnings contribution to Fortis from Belize Electricity. Belize Electricity has contributed minimal earnings since mid-2008. In late July, Fortis, as part of its legal approach, initiated proceedings for compensation from the GOB for the value of the Corporation–s previous investment in Belize Electricity. To date, the Corporation–s non-regulated hydroelectric generating business in Belize, Belize Electric Company Limited (“BECOL”), has not been impacted by the GOB legislation.
Fortis Properties delivered earnings of $7 million compared to $8 million for the second quarter of 2010, reflecting lower occupancies at hotel operations in western Canada, combined with increased operating expenses.
Non-Regulated Fortis Generation contributed $2 million to earnings compared to $3 million for the second quarter of 2010. Results mainly reflected decreased production at BECOL due to lower rainfall.
Corporate and other expenses were $18 million, $2 million lower quarter over quarter, mainly due to reduced operating expenses. Higher operating expenses incurred in the second quarter of 2010 related to business development costs.
Cash flow from operating activities was $527 million for the first half of 2011, up $122 million from the first half of 2010, driven by higher earnings, the collection from customers of higher amortization costs and favourable changes in working capital and regulatory deferral accounts.
The Merger Agreement between Fortis and Central Vermont Public Service Corporation (“CVPS”) announced on May 30, 2011 (the “Merger Agreement”) was terminated in July, subsequent to quarter end. Pursuant to the terms of the Merger Agreement, CVPS paid Fortis a US$17.5 million termination fee plus US$2 million for expenses.
Fortis recently raised total gross proceeds of approximately $341 million from the public issuance of 9,100,000 common shares in June, and an additional 1,240,000 common shares in July upon the exercise of an over-allotment option by the underwriters. Net proceeds of the equity issue are being used to repay borrowings under credit facilities and finance equity injections into the utilities in western Canada and the Waneta Expansion Limited Partnership in support of infrastructure investment, and for general corporate purposes.
“We are on track to complete our $1.2 billion 2011 capital expenditure program,” says Stan Marshall, President and Chief Executive Officer, Fortis Inc. “Our five-year capital expenditure program out to the end of 2015 is forecasted to increase to $5.7 billion. This investment will ensure that Fortis continues to meet the energy needs of our customers,” he adds.
“We are disciplined and patient in our pursuit of electric and gas utility acquisitions in the United States and Canada that will add value for Fortis shareholders,” concludes Marshall.
Interim Management Discussion and Analysis
For the three and six months ended June 30, 2011
Dated August 3, 2011
FORWARD-LOOKING STATEMENT
The following Management Discussion and Analysis (“MD&A”) should be read in conjunction with the Fortis Inc. (“Fortis” or the “Corporation”) interim unaudited consolidated financial statements and notes thereto for the three and six months ended June 30, 2011 and the MD&A and audited consolidated financial statements for the year ended December 31, 2010 included in the Corporation–s 2010 Annual Report. The MD&A has been prepared in accordance with National Instrument 51-102 – Continuous Disclosure Obligations. Financial information in the MD&A has been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) and is presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws in Canada (“forward-looking information”). The purpose of the forward-looking information is to provide management–s expectations regarding the Corporation–s future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation.
The Words “anticipates”, “believes”, “budgets”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management–s current beliefs and is based on information currently available to the Corporation–s management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the expected timing of filing of regulatory applications and of receipt of regulatory decisions; 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 issues; consolidated forecast gross capital expenditures for 2011 and in total over the five-year period 2011 through 2015; the expectation that the Corporation–s significant capital expenditure program should drive growth in earnings and dividends; expected consolidated long-term debt maturities and repayments on average annually over the next five years; except for debt at Exploits River Hydro Partnership (“Exploits Partnership”), the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2011; no material adverse credit rating actions are expected in the near term; and the expected impact of the transition to United States generally accepted accounting principles.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major event; the expectation that the Corporation will receive compensation from the Government of Belize (“GOB”) for the value of the Corporation–s previous investment in Belize Electricity; the expectation that Belize Electric Company Limited (“BECOL”) will not be expropriated by the GOB; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no material capital project and financing cost overrun related to the construction of the Waneta hydroelectric generation expansion project; no significant decline in capital spending in 2011; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; 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 interest rates, foreign exchange rates and natural gas commodity prices; no significant variability in interest rates; 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 supply; the continued ability to fund defined benefit pension plans; the absence of significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; maintenance of information technology infrastructure; favourable relations with First Nations; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations include, but are not limited to: regulatory risk; operating and maintenance risks; risk associated with the amount of compensation to be paid to Fortis for its previous investment in Belize Electricity; the timeliness of the receipt of the compensation and the ability of the GOB to pay the compensation owing to Fortis; risk that the GOB may expropriate BECOL; capital project budget overrun, completion and financing risk in the Corporation–s non-regulated business; economic conditions; capital resources and liquidity risk; weather and seasonality; commodity price risk; derivative financial instruments and hedging; interest rate risk; counterparty risk; competitiveness of natural gas; natural gas supply; defined benefit pension plan performance and funding requirements; risks related to the development of the FortisBC Energy (Vancouver Island) Inc. franchise; environmental risks; insurance coverage risk; loss of licences and permits; loss of service area; changes in tax legislation; information technology infrastructure; an ultimate resolution of the expropriation of the assets of the Exploits Partnership that differs from what is currently expected by management; an unexpected outcome of legal proceedings currently against the Corporation; relations with First Nations; labour relations; and human resources. For additional information with respect to the Corporation–s risk factors, reference should be made to the Corporation–s continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and to the heading “Business Risk Management” in the MD&A for the three and six months ended June 30, 2011 and for the year ended December 31, 2010.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned distribution utility in Canada, serving approximately 2,000,000 gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia, Canada. Fortis owns non-regulated generation assets, primarily hydroelectric, across Canada and in Belize and Upper New York State, and hotels and commercial office and retail space primarily in Atlantic Canada. Year-to-date June 30, 2011, the Corporation–s electricity distribution systems met a combined peak demand of approximately 5,028 megawatts (“MW”) and its gas distribution system met a peak day demand of 1,210 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, 2011 and to the “Corporate Overview” section of the MD&A for the year ended December 31, 2010.
The key goals of the Corporation–s regulated utilities are to operate sound gas and electricity distribution systems, deliver gas and electricity safely and reliably at the lowest reasonable cost and conduct business in an environmentally responsible manner. The Corporation–s main business, utility operations, is highly regulated and the earnings of the Corporation–s regulated utilities are primarily determined under cost of service (“COS”) regulation.
Generally under COS regulation, the respective regulatory authority sets customer gas and 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”). Generally, the ability of a regulated utility to recover prudently incurred costs of providing service and to 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 or ROA; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) timing differences, within an annual financial reporting period, between when actual expenses are incurred and when they are recovered from customers in rates. When forward test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible for deferral account treatment. 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.
Effective March 1, 2011, the Terasen Gas companies were renamed to operate under a common brand identity with FortisBC in British Columbia, Canada. As a result, Terasen Gas Inc. is now FortisBC Energy Inc. (“FEI”), Terasen Gas (Vancouver Island) Inc. is now FortisBC Energy (Vancouver Island) Inc. (“FEVI”) and Terasen Gas (Whistler) Inc. is now FortisBC Energy (Whistler) Inc. (“FEWI”), and collectively are referred to as the FortisBC Energy companies.
On June 20, 2011, the Government of Belize (“GOB”) convened special sittings of legislature to enact legislation leading to the expropriation of the Corporation–s investment in Belize Electricity. As a result of no longer controlling the operations of the utility, the Corporation has discontinued the consolidation method of accounting for the financial results of Belize Electricity, effective June 20, 2011. As at June 30, 2011, the book value of the Corporation–s previous investment in Belize Electricity was $112 million which has been classified in other long-term assets on the consolidated balance sheet of Fortis.
In June 2008 the Public Utilities Commission of Belize (“PUC”) issued a rate order that had a significant negative impact on the financial condition and operations of Belize Electricity. The order effectively disallowed the recovery of $18 million of previously incurred fuel and purchased power costs in customer rates, $13 million of which was the Corporation–s share, and set customer rates at a level that does not allow Belize Electricity to finance its operations and earn a fair and reasonable return. Since 2008, Belize Electricity has been in default of covenants under its long-term lending agreements, has had no access to credit and has not paid any dividends on common shares. Belize Electricity appealed the PUC rate order to the Supreme Court of Belize. On March 15, 2011, the Court rendered its judgment dismissing Belize Electricity–s application and finding that, among other things, the generally accepted concept of good utility practice is not applicable in Belize. Belize Electricity has appealed this judgment to the Court of Appeal of Belize; however, as a result of the GOB–s actions, it is unlikely that the appeal will be prosecuted by government-controlled Belize Electricity.
Fortis has initiated proceedings for compensation from the GOB for the value of the Corporation–s previous investment in Belize Electricity.
The GOB has indicated publicly that it does not intend to expropriate Belize Electric Company Limited (“BECOL”), the Corporation–s indirect wholly owned non-regulated subsidiary in Belize. BECOL generates hydroelectricity from three plants located on the Macal River with a combined generating capacity of 51 MW. The entire output of the plants is sold to Belize Electricity under 50-year contracts expiring in 2055 and 2060. Belize Electricity is currently purchasing energy from BECOL at approximately US$11 cents per kilowatt hour, which is one of the lowest-cost energy supply sources in the country of Belize. Fortis continues to control and consolidate the financial results of BECOL. As at June 30, 2011, the book value of the Corporation–s investment in BECOL was $150 million.
As at July 31, 2011, Belize Electricity owed BECOL US$6.5 million for overdue energy purchases. The last payment received by BECOL for overdue energy purchases totaled US$0.5 million and was received on July 11, 2011. In accordance with long-standing agreements, the GOB guarantees the payment of Belize Electricity–s obligations to BECOL.
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, 2011 and June 30, 2010 are provided in the following table.
Factors Contributing to Quarterly Revenue Variance
Favourable
Unfavourable
Factors Contributing to Year-to-Date Revenue Variance
Favourable
Unfavourable
Factors Contributing to Quarterly Energy Supply Costs Variance
Favourable
Unfavourable
Factors Contributing to Year-to-Date Energy Supply Costs Variance
Unfavourable
Favourable
Factors Contributing to Quarterly and Year-to-Date Operating Expenses Variances
Unfavourable
Favourable
Factors Contributing to Quarterly and Year-to-Date Amortization Costs Variances
Unfavourable
Favourable
Factors Contributing to Quarterly and Year-to-Date Finance Charges Variances
Unfavourable
Favourable
Factors Contributing to Quarterly and Year-to-Date Corporate Taxes Variances
Favourable
Unfavourable
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
Unfavourable
SEGMENTED RESULTS OF OPERATIONS
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Corporation–s regulated utilities, refer to the “Regulatory Highlights” section of this MD&A. A discussion of the financial results of the Corporation–s reporting segments is as follows.
REGULATED GAS UTILITIES – CANADIAN
FORTISBC ENERGY COMPANIES (1)
Factors Contributing to Quarterly and Year-to-Date Gas Volumes Variances
Favourable
Unfavourable
Net customer additions were 1,002 during the first half of 2011 compared to 1,829 during the first half of 2010. Gross customer additions decreased due to lower building activity during 2011.
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.
The FortisBC Energy companies earn approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or for the transportation only of natural gas. As a result of the operation of regulator-approved deferral mechanisms, changes in consumption levels and energy supply costs from those forecast to set residential and commercial customer gas rates do not materially affect earnings.
Factors Contributing to Quarterly Revenue Variance
Unfavourable
Favourable
Factors Contributing to Year-to-Date Revenue Variance
Favourable
Unfavourable
Factors Contributing to Quarterly Earnings Variance
Unfavourable
Favourable
Factors Contributing to Year-to-Date Earnings Variance
Favourable
Unfavourable
REGULATED ELECTRIC UTILITIES – CANADIAN
FORTISALBERTA
Factors Contributing to Quarterly Energy Deliveries Variance
Favourable
Unfavourable
Factors Contributing to Year-to-Date Energy Deliveries Variance
Favourable
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
Unfavourable
Factors Contributing to Quarterly Earnings Variance
Favourable
Unfavourable
Factors Contributing to Year-to-Date Earnings Variance
Favourable
Unfavourable
FORTISBC ELECTRIC (1)
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Favourable
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
Unfavourable
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
Unfavourable
NEWFOUNDLAND POWER
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Favourable
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
Unfavourable
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
Favourable
OTHER CANADIAN ELECTRIC UTILITIES (1)
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Favourable
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
Unfavourable
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
REGULATED ELECTRIC UTILITIES – CARIBBEAN (1)
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Unfavourable
Favourable
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
Unfavourable
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
Favourable
NON-REGULATED – FORTIS GENERATION (1)
Factors Contributing to Quarterly and Year-to-Date Energy Sales Variances
Favourable
Unfavourable
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Unfavourable
Favourable
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
Favourable
NON-REGULATED – FORTIS PROPERTIES (1)
Factors Contributing to Quarterly Revenue Variance
Favourable
Unfavourable
Factors Contributing to Year-to-Date Revenue Variance
Favourable
Unfavourable
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
Favourable
CORPORATE AND OTHER (1)
Factors Contributing to Quarterly and Year-to-Date Net Corporate and Other Expenses Variances
Favourable
Unfavourable
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 2011 are summarized as follows:
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between June 30, 2011 and December 31, 2010.
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation–s consolidated sources and uses of cash for the three and six months ended June 30, 2011, as compared to the same periods in 2010, followed by a discussion of the nature of the variances in cash flows.
Operating Activities: Cash flow from operating activities, after working capital adjustments, was $24 million higher quarter over quarter and $122 million higher year to date compared to the same period last year. The increases were primarily due to: (i) higher earnings; (ii) the collection from customers of regulator-approved increased amortization costs, mainly at FortisAlberta; and (iii) favourable changes in working capital and regulatory deferral accounts. The favourable working capital changes were driven by greater impacts of seasonality at the FortisBC Energy companies and higher Alberta Electric System Operator (“AESO”) net transmission-related receipts and payments at FortisAlberta. The favourable changes in regulatory deferral accounts related mainly to the increase in the RSDA at the FortisBC Energy companies, due to the accumulation of over-recovered costs of providing service to customers during 2011.
Investing Activities: Cash used in investing activities was $39 million higher quarter over quarter and $82 million higher year to date compared to the same period last year. The increases were driven by capital spending related to the non-regulated Waneta Expansion Project and an increase in capital spending at FortisAlberta year to date, partially offset by lower capital spending at FortisBC Electric and an increase in contributions received in aid of construction.
Financing Activities: Cash provided by financing activities was $249 million higher quarter over quarter and $163 million higher year to date compared to the same period last year. The increases were mainly due to higher proceeds from the issuance of common shares, lower repayments of long-term debt, higher advances from non-controlling interests and higher proceeds from long-term debt, partially offset by unfavourable variances in short-term borrowings and lower net borrowings under committed credit facilities classified as long term. Proceeds from the issuance of preferences shares were also lower year to date compared to the same period in 2010.
Net repayments of short-term borrowings were $102 million during the second quarter of 2011 compared to net proceeds from short-term borrowings of $55 million during the same quarter in 2010. Net repayments of short-term borrowings were $200 million year to date compared to $126 million during the same period in 2010. The changes in short-term borrowings were driven by the FortisBC Energy companies due to seasonality differences and timing of repayments using proceeds from equity injections from the Corporation.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease obligations and net borrowings under committed credit facilities for the quarter and year to date compared to the same periods last year are summarized in the following tables.
Borrowings under credit facilities by the utilities are primarily in support of their capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt issues are used to repay borrowings under the Corporation–s committed credit facility.
Advances of approximately $40 million and $57 million for the quarter and year to date, respectively, were received from non-controlling interests in the Waneta Partnership to finance capital expenditures related to the Waneta Expansion Project.
In June 2011 Fortis issued 9.1 million common shares for gross proceeds of $300 million. The net proceeds of $288 million are being used to repay borrowings under credit facilities and finance equity injections into the utilities in western Canada and the Waneta Expansion Project in support of infrastructure investment, and for general corporate purposes.
In January 2010 Fortis completed a $250 million offering of 10 million First Preference Shares, Series H. The net proceeds of approximately $242 million were used to repay borrowings under the Corporation–s committed credit facility and fund an equity injection into FEI.
Common share dividends paid during the second quarter of 2011 were $36 million, net of $15 million in dividends reinvested, compared to $36 million, net of $13 million in dividends reinvested, paid during the same quarter of 2010. Common share dividends paid year-to-date 2011 were $71 million, net of $31 million in dividends reinvested, compared to $69 million, net of $28 million in dividends reinvested, paid year-to-date 2010. The dividend paid per common share for each of the first and second quarters of 2011 was $0.29 compared to $0.28 for each of the first and second quarters of 2010. The weighted average number of common shares outstanding for the quarter and year to date were 177.1 million and 175.8 million, respectively, compared to 172.4 million and 172.0 million, respectively, for the same periods in 2010.
CONTRACTUAL OBLIGATIONS
Consolidated contractual obligations of Fortis over the next five years and for periods thereafter, as at June 30, 2011, are outlined in the following table. A detailed description of the nature of the obligations is provided in the MD&A for the year ended December 31, 2010 and below, where applicable.
Other contractual obligations, which are not reflected in the above table, did not change from that disclosed in the MD&A for the year ended December 31, 2010 except that $20 million of FEVI government loans are now included in long-term debt obligations due within one year as a result of an expected repayment within one year.
For a discussion of the nature and amount of the Corporation–s consolidated capital expenditure program, which is not included in the contractual obligations table above, refer to the “Capital Program” section of this MD&A.
CAPITAL STRUCTURE
The Corporation–s principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt issues. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40% equity, including preference shares, and 60% debt, as well as investment-grade credit ratings. Each of the Corporation–s regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in the utilities– customer rates.
The consolidated capital structure of Fortis is presented in the following table.
The change in the capital structure was driven by the public issuance of $300 million in common shares in June 2011 combined with common shares issued under the Corporation–s dividend reinvestment and stock option plans and the reclassification of unrealized foreign currency translation losses related to the Corporation–s previous investment in Belize Electricity to other long-term assets. Also contributing to the change in the capital structure was net earnings applicable to common shares, net of dividends, lower short-term borrowings and higher cash on hand.
CREDIT RATINGS
The Corporation–s credit ratings are as follows:
The credit ratings reflect the Corporation–s low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, management–s commitment to maintaining low levels of debt at the holding company level, the Corporation–s reasonable credit metrics and its demonstrated ability and continued focus on acquiring and integrating stable regulated utility businesses financed on a conservative basis.
CAPITAL PROGRAM
Capital investment in infrastructure is required to ensure continued and enhanced performance, reliability and safety of the gas and electricity systems and to meet customer growth. All costs considered to be maintenance and repairs are expensed as incurred. Costs related to replacements, upgrades and betterments of capital assets are capitalized as incurred.
A breakdown of the $519 million in gross capital expenditures by segment for the first half of 2011 is provided in the following table.
There has been no material change in forecast gross consolidated capital expenditures for 2011 from the approximate $1.2 billion forecast as was disclosed in the MD&A for the year ended December 31, 2010. Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts.
There were no material changes in the overall expected level, nature and timing of the Corporation–s significant capital projects from those disclosed in the MD&A for the year ended December 31, 2010, except as described below.
In April 2011 Fortis Properties filed a development application to construct a 12-storey office building in St. John–s, Newfoundland, subject to municipal government approval. The $50 million project will feature 145,000 square feet of Class A office space and include 262 parking spaces. It is expected to be completed in the second half of 2013.
Approximately $10 million of the originally estimated forecast project cost for 2011 related to FEI–s Customer Care Enhancement Project is expected to be incurred in the first half of 2012. The total project cost is expected to be approximately $116 million.
During the first quarter of 2011, FortisAlberta substantially completed its $126 million Automated Metering Project, which involved the replacement of approximately 466,000 conventional meters.
During the second quarter of 2011, FEI substantially completed construction of its estimated $214 million LNG storage facility. The facility is currently being filled and is expected to be available for the upcoming winter heating season.
Over the five-year period 2011 through 2015, consolidated gross capital expenditures are expected to be approximately $5.7 billion, up from $5.5 billion as disclosed in the MD&A for the year ended December 31, 2010. The increase largely reflects higher capital expenditures at the FortisBC Energy companies, partially offset by the exclusion of capital expenditures at Belize Electricity due to the discontinuance of the consolidation method of accounting for the financial results of the Company. Approximately 61% of the capital spending is expected to be incurred at the regulated electric utilities, driven by FortisAlberta and FortisBC Electric. Approximately 23% and 16% of the capital spending is expected to be incurred at the regulated gas utilities and at the non-regulated operations, respectively. Capital expenditures at the regulated utilities are subject to regulatory approval.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of operating cash flows, with varying levels of residual cash flow available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, equity injections from Fortis and long-term debt issues.
The Corporation–s ability to service its debt obligations and pay dividends on its common and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. Certain regulated subsidiaries may be subject to restrictions which may limit their ability to distribute cash to Fortis. Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation–s committed credit facility and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation–s committed credit facility may be required from time to time to support the servicing of debt and payment of dividends.
As at June 30, 2011, management expects consolidated long-term debt maturities and repayments to average approximately $260 million annually over the next five years. The combination of available credit facilities and relatively low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
As the hydroelectric assets and water rights of the Exploits River Hydro Partnership (“Exploits Partnership”) had been provided as security for the Exploits Partnership term loan, the expropriation of such assets and rights by the Government of Newfoundland and Labrador constituted an event of default under the loan. The term loan is without recourse to Fortis and was approximately $57 million as at June 30, 2011 (December 31, 2010 – $58 million). The lenders of the term loan have not demanded accelerated repayment. The scheduled repayments under the term loan are being made by Nalcor, a Crown corporation, acting as an agent for the Government of Newfoundland and Labrador with respect to the expropriation matters. For further information refer to Note 30 to the Corporation–s 2010 annual audited consolidated financial statements.
Except for the debt at the Exploits Partnership, as discussed above, Fortis and its subsidiaries were in compliance with debt covenants as at June 30, 2011 and are expected to remain compliant throughout 2011.
CREDIT FACILITIES
As at June 30, 2011, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.1 billion, of which $1.5 billion was unused, including $409 million unused under the Corporation–s $600 million committed revolving credit facility. The credit facilities are syndicated almost entirely with the seven largest Canadian banks, with no one bank holding more than 25% of these facilities. Approximately $2.0 billion of the total credit facilities are committed facilities with maturities between 2012 and 2015.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
As at June 30, 2011 and December 31, 2010, certain borrowings under the Corporation–s and subsidiaries– credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and management–s intention is to refinance these borrowings with long-term permanent financing during future periods.
In February 2011 Maritime Electric renewed its unsecured committed revolving credit facility, which matures annually in March. The unsecured committed revolving credit facility was reduced from $60 million to $50 million.
In April 2011 FortisBC Electric renegotiated and amended its credit facility agreement resulting in an extension to the maturity of the Company–s $150 million unsecured committed revolving credit facility with $100 million now maturing in May 2014 and $50 million now maturing in May 2012.
In April 2011 FHI extended the maturity date of its $30 million unsecured committed revolving credit facility to May 2012.
In June 2011 Newfoundland Power renegotiated and amended its $100 million unsecured committed credit facility, obtaining an extension to the maturity of the facility to August 2015 from August 2013. The amended credit facility agreement reflects a decrease in pricing but, otherwise, contains substantially similar terms and conditions as the previous credit facility agreement.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation–s consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows:
Excluded from the above table is the $112 million asset as at June 30, 2011 related to the Corporation–s previous investment in Belize Electricity. The fair value of this financial asset is not determinable at this time.
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note, the fair value is determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills, with similar terms to maturity, plus a market credit risk premium equal to that of issuers of similar credit quality. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs. The fair value of the Corporation–s preference shares is determined using quoted market prices.
Risk Management: The Corporation–s earnings from, and net investments in, self-sustaining foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above exposure through the use of US dollar borrowings at the corporate level. Foreign exchange gains and losses on the translation of US dollar-denominated interest expense partially offsets the foreign exchange losses and gains on the translation of the Corporation–s foreign subsidiaries– earnings, which are denominated in US dollars. The reporting currency of Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy Corporation and BECOL is the US dollar.
As at June 30, 2011, US$529 million of the US$594 million corporately issued long-term debt (December 31, 2010 – US$590 million of US$590 million) had been designated as an effective hedge of the Corporation–s net investments in self-sustaining foreign subsidiaries. Foreign currency exchange rate fluctuations associated with the translation of the Corporation–s corporately issued US dollar borrowings designated as effective hedges are recognized in other comprehensive income and help offset unrealized foreign currency gains and losses on the net investments in self-sustaining foreign subsidiaries, which are also recognized in other comprehensive income.
Effective June 20, 2011, the Corporation–s asset associated with its previous investment in Belize Electricity, recorded in other long-term assets, does not qualify for hedge accounting as Belize Electricity is no longer a self-sustaining foreign subsidiary of Fortis. As a result, approximately US$65 million of corporately issued debt that previously hedged the former investment in Belize Electricity is no longer an effective hedge. Effective June 20, 2011, foreign exchange gains and losses on the translation of the asset associated with Belize Electricity and the corporately issued US dollar denominated debt that previously qualified as a hedge of the investment are required to be recognized in earnings. This change in accounting treatment is not expected to have a material impact on consolidated earnings of Fortis. As at June 30, 2011, all of the Corporation–s net investments in self-sustaining foreign subsidiaries were hedged (December 31, 2010 – 99%).
From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and fuel and natural gas prices through the use of derivative financial instruments. The Corporation and its subsidiaries do not hold or issue derivative financial instruments for trading purposes.
The following table summarizes the valuation of the Corporation–s derivative financial instruments.
The foreign exchange forward contracts are held by the FortisBC Energy companies. During 2010 FEI entered into a foreign exchange forward contract to hedge the cash flow risk related to approximately US$5 million remaining to be paid under a contract for the implementation of a customer information system. FEVI also hedges the cash flow risk related to less than US$1 million remaining to be paid under a contract for the construction of the LNG storage facility on Vancouver Island.
The fuel option contracts are held by Caribbean Utilities. During the first quarter of 2011, the Company–s Fuel Price Volatility Management Program was approved by the regulator to reduce the impact of volatility in fuel prices on customer rates. In April 2011 Caribbean Utilities entered into two fuel option contracts.
The natural gas derivatives are held by the FortisBC Energy companies and are used to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The price risk-management strategy of the FortisBC Energy companies aims to improve the likelihood that natural gas prices remain competitive with electricity rates, temper gas price volatility on customer rates and reduce the risk of regional price discrepancies.
The changes in the fair values of the foreign exchange forward contracts, fuel option contracts and natural gas derivatives are deferred as a regulatory asset or liability, subject to regulatory approval, for recovery from, or refund to, customers in future rates. The fair values of the derivative financial instruments were recorded in accounts payable as at June 30, 2011 and as at December 31, 2010.
The foreign exchange forward contracts are valued using the present value of cash flows based on a market foreign exchange rate and the foreign exchange forward rate curve. The fuel option contracts are valued using published market prices for similar commodities. The natural gas derivatives are valued using the present value of cash flows based on market prices and forward curves for the commodity cost of natural gas. The fair values of the foreign exchange forward contracts, fuel option contracts and natural gas derivatives are estimates of the amounts that would have to be received or paid to terminate the outstanding contracts as at the balance sheet dates.
The fair values of the Corporation–s financial instruments, including derivatives, reflect point-in-time estimates based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation–s future consolidated earnings or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $121 million, as at June 30, 2011, the Corporation had no off-balance sheet arrangements, such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities, that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
There were no changes in the Corporation–s significant business risks during the first half of 2011 from those disclosed in the MD&A for the year ended December 31, 2010, except for those described below.
Investment in Belize: In June 2011 the GOB expropriated the Corporation–s investment in Belize Electricity. Fortis has initiated proceedings for compensation from the GOB for the value of the Corporation–s previous investment in Belize Electricity. The Corporation is exposed to risk associated with the amount of compensation to be paid for its previous investment in Belize Electricity, the timeliness of payment of the compensation and the ability of the GOB to pay the compensation owing to Fortis.
The GOB has indicated publicly that it does not intend to expropriate BECOL. As at June 30, 2011, the book value of the Corporation–s investment in BECOL was $150 million.
Transition to New Accounting Standards: In June 2011 the Ontario Securities Commission (“OSC”) issued a decision allowing Fortis and its reporting issuer subsidiaries to prepare their financial statements, effective January 1, 2012, in accordance with US GAAP without qualifying as U.S. Securities and Exchange Commission (“SEC”) Issuers. The Corporation and its reporting issuer subsidiaries, therefore, will be adopting US GAAP as opposed to International Financial Reporting Standards (“IFRS”) at the above date. Earnings to be recognized under US GAAP are expected to be closely aligned with earnings recognized under Canadian GAAP, mainly due to the continued recognition of regulatory assets and liabilities. A transition to IFRS would likely have resulted in the derecognition of some, or perhaps all, of the Corporation–s regulatory assets and liabilities and significant volatility in the Corporation–s consolidated earnings. For further information, refer to the “Future Accounting Standards” section of this MD&A.
Capital Resources and Liquidity Risk – Credit Ratings: Fortis and its regulated utilities do not anticipate any material adverse rating actions by the credit rating agencies in the near term. During the first half of 2011, DBRS confirmed its existing credit ratings for Newfoundland Power and Caribbean Utilities and in July 2011 Moody–s Investors Service confirmed its existing credit ratings for Newfoundland Power and FEI.
Defined Benefit Pension Plan Performance: As at June 30, 2011, the fair value of the Corporation–s consolidated defined benefit pension plan assets was $753 million, up $26 million, or 3.6%, from $727 million as at December 31, 2010.
Labour Relations: The collective agreement between FortisBC Electric and Local 378 of the Canadian Office and Professional Employees Union (“COPE”) expired January 31, 2011. The Company and COPE have commenced negotiations. In the interim, the current collective agreement remains in full effect until such time as the parties negotiate and ratify a new agreement.
CHANGE IN ACCOUNTING TREATMENT
Effective January 1, 2011, as approved by the regulator, the cost of OPEB plans at Newfoundland Power is being expensed and recovered in customer rates based on the accrual method of accounting for OPEBs. Additionally, the Company–s transitional regulatory OPEB asset of $53 million as at December 31, 2010 is being amortized on a straight-line basis over 15 years. During the three and six months ended June 30, 2011, operating expenses increased by approximately $2 million and $4 million, respectively, as a result of this change in accounting treatment. Prior to January 1, 2011, the cost of OPEB plans at Newfoundland Power was being expensed and recovered in customer rates based on the cash payments made.
FUTURE ACCOUNTING CHANGES
Adoption of New Accounting Standards: Due to continued uncertainty around the timing and adoption of a rate-regulated accounting standard by the International Accounting Standards Board, Fortis has evaluated the option of adopting US GAAP, as opposed to IFRS, and has decided to adopt US GAAP effective January 1, 2012.
Canadian securities rules allow a reporting issuer to prepare and file its financial statements in accordance with US GAAP by qualifying as an SEC Issuer. An SEC Issuer is defined under the Canadian rules as an issuer that: (i) has a class of securities registered with the SEC under Section 12 of the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”); or (ii) is required to file reports under Section 15(d) of the Exchange Act. The Corporation is currently not an SEC Issuer. Therefore, on June 6, 2011, the Corporation filed an application with the OSC seeking relief, pursuant to National Policy 11-203 – Process for Exemptive Relief Applications in Multiple Jurisdictions, to permit the Corporation and its reporting issuer subsidiaries to prepare their financial statements in accordance with US GAAP without qualifying as SEC Issuers (“the Exemption”). On June 9, 2011, the OSC issued its decision and granted the Exemption for financial years commencing on or after January 1, 2012 but before January 1, 2015, and interim periods therein. The Exemption will terminate in respect of financial statements for annual and interim periods commencing on or after the earlier of: (i) January 1, 2015; or (ii) the date on which the Corporation ceases to have activities subject to rate regulation.
The Corporation–s application of Canadian GAAP currently relies on US GAAP for guidance on accounting for rate-regulated activities. The adoption of US GAAP in 2012 is, therefore, expected to result in fewer significant changes to the Corporation–s accounting policies as compared to accounting policy changes that may have resulted from the adoption of IFRS. US GAAP guidance on accounting for rate-regulated activities allows the economic impact of rate-regulated activities to be recognized in the consolidated financial statements in a manner consistent with the timing by which amounts are reflected in customer rates. Fortis believes that the continued application of rate-regulated accounting, and the associated recognition of regulatory assets and liabilities under US GAAP, accurately reflects the impact that rate regulation has on the Corporation–s consolidated financial position and results of operations.
The Corporation has developed a three-phase plan to adopt US GAAP effective January 1, 2012. The following is an overview of the activities under each phase and their current status.
Phase I – Scoping and Diagnostics: Phase I consisted of project initiation and awareness; project planning and resourcing; and identification of high-level differences between US GAAP and Canadian GAAP in order to highlight areas where detailed analysis would be needed to determine and conclude as to the nature and extent of financial statement impacts. External accounting and legal advisors were engaged during this phase to assist the Corporation–s internal US GAAP conversion team and to provide technical input and expertise as required. Phase I commenced in the fourth quarter of 2010 and is now complete.
Phase II – Analysis and Development: Phase II consists of detailed diagnostics and evaluation of the financial statement impacts of adopting US GAAP based on the high-level assessment conducted under Phase I; identification and design of any new, or changes to, operational or financial business processes; initial staff training and audit committee orientation; and development of required solutions to address identified issues.
Phase II had included planned activities for the registration of securities as required to achieve SEC Issuer status and an assessment of ongoing requirements of the United States Sarbanes-Oxley Act (“US SOX”), including auditor attestation of internal controls over financial reporting, and a comparison of the requirements under US SOX to those required in Canada under National Instrument 52-109 – Certification of Disclosure in Issuers– Annual and Interim Filings. These activities are no longer required or applicable following the Exemption granted by the OSC as discussed above.
Phase II of the plan commenced in January 2011. Based on the research and analysis completed to date, and the Corporation–s continued ability to apply rate-regulated accounting policies under US GAAP, the differences between US GAAP and Canadian GAAP are not expected to have a material impact on consolidated earnings. In addition, adoption of US GAAP is expected to result in limited changes in balance sheet classifications, and additional disclosure requirements. The impact on information systems and internal controls over financial reporting is expected to be minimal.
Phase III – Implementation and Review: Phase III involves the implementation of all financial reporting, systems and internal control changes required by the Corporation to prepare and file its consolidated financial statements based on US GAAP beginning in 2012 and the communication of associated impacts.
The Corporation will prepare and file, in accordance with Canadian GAAP, its annual audited consolidated financial statements for the year ending December 31, 2011. The Corporation intends to voluntarily prepare and file, in accordance with US GAAP, its annual audited consolidated financial statements for the year ending December 31, 2011 and the comparative period. The voluntary filing is expected to be completed prior to March 31, 2012. Beginning with the first quarter of 2012, the Corporation–s unaudited interim consolidated financial statements will be prepared and filed in accordance with US GAAP.
Phase III has commenced and will conclude when the Corporation prepares and files, in accordance with US GAAP, its annual audited consolidated financial statements for the year ending December 31, 2012.
Financial Statement Impacts – US GAAP: The areas identified to date where differences between US GAAP and Canadian GAAP are expected to have the most significant financial statement impacts are as follows:
Employee future benefits: Under Canadian GAAP, the accrued benefit asset or liability associated with defined benefit plans is recognized on the balance sheet with a reconciliation of the recognized asset or liability to the funded or unfunded status being disclosed in the notes to the consolidated financial statements. The accrued benefit asset or liability excludes unamortized balances related to past service costs, actuarial gains and losses and transitional obligations or assets which have not yet been recognized.
US GAAP requires recognition of the funded or unfunded status of defined benefit plans on the balance sheet, with the opening unamortized balances related to past service costs, actuarial gains and losses and transitional obligations recognized on the balance sheet as a component of accumulated other comprehensive income. Changes to past service costs, actuarial gains and losses and transitional obligations which are not immediately recognized as components of net pension expense are required to be recognized in other comprehensive income. Entities with activities subject to rate regulation would recognize the opening unamortized balances as regulatory assets or liabilities for recovery from, or refund to, customers in future rates, with subsequent changes to these balances recognized as net pension expense, where required by the regulator, or otherwise as a change in the regulatory asset or liability. Therefore, upon adoption of US GAAP, the Corporation–s rate-regulated subsidiaries, with the exception of FortisAlberta as discussed below, will recognize the unfunded or funded status of its defined benefit plans on the balance sheet with the above-noted unamortized balances recognized as regulatory assets or liabilities.
FortisAlberta has historically recovered its OPEB costs on a cash basis, as opposed to an accrual basis, and will likely continue to do so as ordered by its regulator. Therefore, FortisAlberta–s regulatory asset associated with OPEB costs does not meet the criteria for recognition under US GAAP.
Additional differences between Canadian GAAP and US GAAP in the accounting for defined