ST. JOHN–S, NEWFOUNDLAND AND LABRADOR — (Marketwire) — 02/09/12 — Fortis Inc. (“Fortis” or the “Corporation”) (TSX: FTS) achieved net earnings attributable to common equity shareholders of $318 million, or $1.75 per common share, up $33 million, or $0.10 per common share, compared to $285 million, or $1.65 per common share, for 2010.
Increased investment in energy infrastructure at the utilities in western Canada and the $11 million after-tax, or $0.06 per common share, fee paid to Fortis in July 2011, following the termination of the Merger Agreement with Central Vermont Public Service Corporation, were the primary drivers of earnings growth.
Fortis increased its quarterly common share dividend to 30 cents from 29 cents, commencing with the first quarter dividend payable on March 1, 2012, which translates into an annualized dividend of $1.20. Fortis has raised its annualized dividend to common shareholders for 39 consecutive years, the record for a public corporation in Canada. The dividend payout ratio was 66% in 2011.
“Our annual capital expenditure program totalled a record $1.2 billion in 2011,” says Stan Marshall, President and Chief Executive Officer, Fortis Inc. “The significant investment in energy infrastructure being made by our utilities should help ensure we continue to meet our obligation to serve customers,” he adds.
The largest capital projects recently completed were the $212 million 1.5 billion-cubic foot liquefied natural gas storage facility on Vancouver Island and the $110 million Customer Care Enhancement Project, including two new call centres, at FortisBC–s gas utility; the $105 million Okanagan Transmission Reinforcement Project at FortisBC Electric; and the $126 million Automated Metering Project at FortisAlberta. Construction of the $900 million 335-megawatt Waneta Expansion hydroelectric generation facility in British Columbia, which is scheduled to be completed in spring 2015, is progressing on time and on budget, with approximately $244 million invested in the project since construction began in late 2010.
Canadian Regulated Gas Utilities delivered earnings of $139 million, up $9 million from $130 million for 2010. Excluding a favourable one-time $4 million item in 2010, earnings increased $13 million year over year. Results for 2011 reflected the impact of growth in energy infrastructure investment, lower-than-expected corporate income taxes, finance charges and amortization costs, and increased gas transportation volumes to the forestry and mining sectors, partially offset by lower-than-expected customer additions.
“The majority of our gas customers have benefited from the downward trend in natural gas commodity prices,” says Marshall. “The improving supply and cost fundamentals of natural gas throughout North America, combined with its positive environmental attributes, make natural gas an attractive energy supply source for residential and industrial use and as a fuel for the transportation and power generation sectors,” he explains.
Canadian Regulated Electric Utilities contributed earnings of $179 million, up $15 million from $164 million for 2010. The increase was driven by improved results at FortisAlberta and FortisBC Electric. The increase in earnings at FortisAlberta mainly resulted from growth in energy infrastructure investment, higher capitalized allowance for funds used during construction (“AFUDC”), customer growth and higher energy deliveries, and return earned on additional investment in automated meters, as approved by the regulator, partially offset by a lower allowed rate of return on common shareholders– equity (“ROE”) for 2011. The increase in earnings at FortisBC Electric resulted from growth in energy infrastructure investment, lower purchased power costs and higher electricity sales, partially offset by lower capitalized AFUDC.
“FortisAlberta continues to invest significant capital in its electricity network, which includes more than 100,000 kilometres of distribution lines, with over $400 million of capital expenditures in 2011 and a similar amount planned for 2012”, says Marshall. “A significant portion of the utility–s franchise territory overlaps with the tight oil and shale gas developments in Alberta, especially the Bakken, Cardium and Duvernay areas, and our business is benefiting from building the electricity infrastructure necessary to meet associated customer growth,” he explains.
Significant regulatory processes recently decided or underway at the Corporation–s largest utilities are as follows:
Caribbean Regulated Electric Utilities contributed $20 million to earnings compared to $23 million for 2010. There was no earnings contribution from Belize Electricity in 2011 due to the expropriation of the Corporation–s investment in the utility in June by the Government of Belize (“GOB”). Earnings contribution from Belize Electricity during 2010 was approximately $1.5 million. Fortis submitted its claim for compensation to the GOB in November. Earnings at Fortis Turks and Caicos decreased year over year, due to higher amortization costs and operating expenses, partially offset by reduced energy supply costs in 2011 reflecting the use of new, more fuel-efficient generating units. There was no growth in electricity sales year over year at Caribbean Utilities and Fortis Turks and Caicos, due to challenging economic conditions in the region and high fuel prices.
Non-Regulated Fortis Generation contributed $18 million to earnings compared to $20 million for 2010. The decline in earnings resulted from decreased hydroelectric production in Belize, due to lower rainfall associated with a longer dry season in 2011, combined with overall lower interest income.
Fortis Properties delivered earnings of $23 million compared to $26 million for 2010. However, results for 2010 were favourably impacted by lower corporate income tax rates, which reduced future income taxes. Results for 2011 reflected lower contribution from the Hospitality Division, driven by lower occupancy at the Company–s hotels in western Canada. Fortis Properties acquired the 160-room, full-service Hilton Suites Winnipeg Airport hotel for $25 million in October 2011.
Corporate and other expenses were $61 million, $17 million lower than $78 million for 2010. Excluding the $11 million after-tax termination fee, corporate and other expenses were $6 million lower year over year, as a result of both decreased business development costs and finance charges.
Earnings for the fourth quarter were $86 million, or $0.46 per common share, compared to $85 million, or $0.49 per common share, for the same quarter in 2010. Increased earnings at the FortisBC gas utilities, largely due to the same reasons described above for the improvement in annual earnings, were partially offset by a decrease in earnings at Newfoundland Power, Other Canadian Regulated Electric Utilities, Fortis Turks and Caicos and Fortis Properties. The decrease in earnings at Newfoundland Power reflected a lower allowed ROE and higher operating expenses, partially offset by reduced energy supply costs in the fourth quarter of 2011. Lower earnings at Other Canadian Regulated Electric Utilities were due to decreased electricity sales and higher operating expenses. Lower earnings at Fortis Turks and Caicos were due to the same reasons described above for the decrease in annual earnings. Earnings at Fortis Properties during the fourth quarter of 2010 reflected lower corporate income tax rates, which reduced future income taxes in that period. An 8% increase in the weighted average number of common shares outstanding quarter over quarter, largely associated with the public common equity offering in mid-2011, had the impact of decreasing earnings per common share.
Fortis and its regulated utilities raised $688 million of long-term capital in 2011. Fortis issued approximately 10.3 million common shares for $341 million, the proceeds of which were used to repay borrowings under credit facilities and finance equity injections into the regulated utilities in western Canada and the non-regulated Waneta Expansion Limited Partnership, in support of infrastructure investment, and for general corporate purposes. Consolidated long-term debt totalling $347 million was issued in 2011 at terms ranging from 15 to 50 years and at rates ranging from 4.25% to 5.118%. In December FortisBC–s largest gas utility issued 30-year $100 million 4.25% unsecured debentures, Maritime Electric issued 50-year 4.915% $30 million first mortgage bonds and FortisOntario issued 30-year $52 million 5.118% unsecured notes. Generally, proceeds of the debt offerings were used to repay borrowings under credit facilities incurred to finance capital expenditures, to finance future capital spending and for general corporate purposes. In the case of FortisOntario, the debt proceeds were used to repay an inter-company loan with Fortis, originally incurred to support the acquisition of Algoma Power in 2009.
The Corporation–s US$40 million convertible debentures were converted into 1.4 million common shares at US$29.11 per share in November 2011.
Newfoundland Power received $46 million of proceeds in October 2011 upon the sale to Bell Aliant Inc. of 40% of all joint-use poles owned by Newfoundland Power.
DBRS confirmed the Corporation–s debt credit rating at A(low) in September 2011. Standard and Poor–s (“S&P”) is expected to complete its annual review of the Corporation–s debt credit rating in the first quarter of 2012. S&P currently rates the Corporation–s debt at A-.
Cash flow from operating activities was $904 million for 2011, up $172 million from $732 million for 2010, driven by favourable working capital changes and higher earnings.
“We are focused on completing our $1.3 billion capital expenditure program for 2012,” says Marshall. “Over the next five years through 2016, our capital expenditure program is projected to total $5.5 billion, which should support continuing growth in earnings and dividends,” he adds.
“We remain 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.
FORWARD-LOOKING STATEMENT
The following fourth quarter 2011 media release should be read in conjunction with the Fortis Inc. (“Fortis” or the “Corporation”) Management Discussion and Analysis (“MD&A”) and audited consolidated financial statements for the year ended December 31, 2010 included in the Corporation–s 2010 Annual Report. Financial information in this material 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 this fourth quarter 2011 media release 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 this fourth quarter 2011 media release includes, but is not limited to, statements regarding: the expected timing of filing of regulatory applications and of receipt of regulatory decisions; consolidated forecast gross capital expenditures for 2012 and in total over the five-year period 2012 through 2016; the expectation that the Corporation–s significant capital expenditure program should drive growth in earnings and dividends; and the expected impact of the transition to US 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 events; the expectation that the Corporation will receive 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 (“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; 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 fuel 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 and fuel supply; the continuation of and/or regulatory approval of power supply and capacity purchase contracts; 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 consolidated 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 investment in Belize Electricity that was expropriated by the GOB; the timeliness of the receipt of the compensation and the ability of the GOB to pay the compensation owing to Fortis; risk that the GOB may expropriate BECOL; 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 and fuel supply; regulatory approval of power supply and capacity purchase contracts; defined benefit pension plan performance and funding requirements; risks related to FortisBC Energy (Vancouver Island) Inc.; 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 year ended December 31, 2010 and for the three and nine months ended September 30, 2011, and as otherwise disclosed in this fourth quarter 2011 media release.
All forward-looking information in this fourth quarter 2011 media release is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned distribution utility in Canada, serving more than 2,000,000 gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia, Canada. Fortis owns non-regulated generation assets, primarily hydroelectric, across Canada and in Belize and Upper New York State, and hotels and commercial office and retail space in Canada. In 2011 the Corporation–s electricity distribution systems met a combined peak demand of 5,045 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 2010 annual audited consolidated financial statements.
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.
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”). 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 and/or ROA; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) timing differences within an annual financial reporting period, between when actual expenses are incurred and when they are recovered from customers in rates. When forward test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible to be deferred on the balance sheet. In addition, the Corporation–s regulated utilities, where applicable, are permitted by their respective regulatory authority to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms.
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”) enacted legislation leading to the expropriation of the Corporation–s investment in Belize Electricity. As a result of no longer controlling the operations of the utility, the Corporation has discontinued the consolidation method of accounting for Belize Electricity, effective June 20, 2011, and has classified the book value of the previous investment in the utility as a long-term other asset on the consolidated balance sheet. As at December 31, 2011, the long-term other asset, including foreign exchange impacts, totalled $106 million.
In October 2011 Fortis commenced an action in the Belize Supreme Court to challenge the legality of the expropriation of its investment in Belize Electricity. Fortis commissioned an independent valuation of its expropriated investment in Belize Electricity and submitted its claim for compensation to the GOB in November 2011.
The GOB also commissioned an independent valuation of Belize Electricity and communicated the results of such valuation in its response to the Corporation–s claim for compensation. The fair value of Belize Electricity determined under the GOB–s valuation is significantly lower than the fair value determined under the Corporation–s valuation. The Corporation is pursuing alternative options for obtaining fair compensation from the GOB.
Fortis continues to control and consolidate the financial statements of Belize Electric Company Limited (“BECOL”), the Corporation–s indirect wholly owned non-regulated hydroelectric generation 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. Assuming normal hydrological conditions, Belize Electricity purchases BECOL–s normalized annual energy production of 240 gigawatt hours (“GWh”) at approximately US$0.10 per kilowatt hour, which generally is the lowest-cost energy supply source in the country of Belize. As at December 31, 2011, the book value of the Corporation–s investment in BECOL was $154 million. In October 2011 the GOB purportedly amended the Constitution of Belize to require majority government ownership of three public utility providers, including Belize Electricity, but excluding BECOL.
As at January 31, 2012, Belize Electricity owed BECOL US$7.4 million for overdue energy purchases, representing almost one-third of BECOL–s annual sales to Belize Electricity. In accordance with long-standing agreements, the GOB guarantees the payment of Belize Electricity–s obligations to BECOL.
SUMMARY 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 fourth quarters and years ended December 31, 2011 and December 31, 2010 are provided in the following table.
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
Unfavourable
Unfavourable
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
Favourable
Unfavourable
Favourable
Unfavourable
SEGMENTED RESULTS OF OPERATIONS
For a discussion of the material regulatory decisions and applications pertaining to the Corporation–s regulated utilities, refer to the “Regulatory Highlights” section of this media release. A discussion of the financial results of the Corporation–s reporting segments is as follows.
REGULATED GAS UTILITIES – CANADIAN
FORTISBC ENERGY COMPANIES (1)
Favourable
Unfavourable
Net customer additions were 7,450 for 2011 compared to 9,393 for 2010. Net customer additions decreased year over year due to lower building activity.
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.
Unfavourable
Favourable
Favourable/Unfavourable
Favourable
Unfavourable
REGULATED ELECTRIC UTILITIES – CANADIAN
FORTISALBERTA
Unfavourable
Favourable
Favourable
Unfavourable
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.
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
Unfavourable
FORTISBC ELECTRIC (1)
Unfavourable
Favourable
Favourable
Favourable
Unfavourable
Favourable
Unfavourable
NEWFOUNDLAND POWER
Favourable
Favourable
Unfavourable
Unfavourable
Favourable
OTHER CANADIAN ELECTRIC UTILITIES (1)
Unfavourable
Favourable
Favourable
Unfavourable
Unfavourable
Favourable
Favourable
Unfavourable
Unfavourable
Favourable
Favourable
Unfavourable
REGULATED ELECTRIC UTILITIES – CARIBBEAN (1)
Unfavourable
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
NON-REGULATED – FORTIS GENERATION (1)
Unfavourable
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
In May 2011 the generator at Moose River–s hydroelectric generating facility in Upper New York State sustained damage. Equipment and business interruption insurance claims are ongoing. Revenue for 2011 reflects the accrual of the 2011 earnings impact of the shut down of the facility that is recoverable from the insurance claim. The generator is under repair and the facility is expected to be operational in late March 2012.
NON-REGULATED – FORTIS PROPERTIES (1)
Favourable
Unfavourable
Favourable
Unfavourable
Unfavourable
Favourable
Unfavourable
Favourable
CORPORATE AND OTHER (1)
Favourable
Unfavourable
On July 11, 2011, the Board of Directors of CVPS determined that the acquisition proposal from Gaz Metro Limited Partnership was a “Superior Proposal”, as that term was defined in the Merger Agreement between Fortis and CVPS announced on May 30, 2011, and CVPS elected to terminate the Merger Agreement in accordance with its terms. Prior to such termination taking effect, the Merger Agreement provided Fortis the right to require CVPS to negotiate with Fortis for at least five business days with respect to any changes to the terms of the Merger Agreement proposed by Fortis. Fortis agreed to waive such right in exchange for the prompt payment by CVPS to Fortis of the US$17.5 million termination fee plus US$2.0 million for the reimbursement of expenses as set forth in the Merger Agreement, thereby resulting in the termination of the Merger Agreement. Fortis received the $18.8 million (US$19.5 million) payment on July 12, 2011.
REGULATORY HIGHLIGHTS
The nature of material regulatory decisions and applications associated with each of the Corporation–s regulated gas and electric utilities for 2011 are summarized as follows:
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation–s consolidated sources and uses of cash for the fourth quarter and year ended December 31, 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 $29 million higher quarter over quarter and $172 million higher year over year. The increases were mainly due to favourable changes in working capital and higher earnings. Quarter over quarter, favourable working capital changes associated with accounts receivable and inventories were partially offset by unfavourable changes in accounts payable. The favourable working capital changes year over year, associated primarily with accounts payable, accounts receivable and inventories, were driven by the FortisBC Energy companies and FortisAlberta.
Investing Activities: Cash used in investing activities was $36 million higher quarter over quarter. The increase was due to a $49 million deferred payment being made in December 2011, in accordance with an agreement, associated with FHI–s acquisition of FEVI in 2002. The deferred payment was originally classified in long-term other liabilities. Cash used in investing activities also increased as a result of the acquisition of the Hilton Suites Winnipeg Airport hotel in 2011. The increases were partially offset by higher proceeds from the sale of utility capital assets associated with the sale of joint-use poles at Newfoundland Power in October 2011.
Cash used in investing activities was $134 million higher year over year. The increase was due to the same reasons as discussed above for the quarter, as well as higher capital spending related to the non-regulated Waneta hydroelectric generation expansion project (“Waneta Expansion Project”) and higher capital spending at FortisAlberta, partially offset by lower capital spending at FortisBC Electric.
Financing Activities: Cash provided by financing activities was $56 million lower quarter over quarter, due to: (i) lower proceeds from long-term debt; (ii) higher repayments of short-term borrowings; and (iii) lower advances from non-controlling interests in the Waneta Expansion Limited Partnership (“Waneta Partnership”), partially offset by lower repayments of both long-term debt and committed credit facility borrowings classified as long-term.
Cash provided by financing activities was $82 million lower year over year, due to: (i) lower proceeds from the issuance of preference shares; (ii) lower proceeds from long-term debt; (iii) higher repayments of short-term borrowings; (iv) higher repayments of committed credit facility borrowings classified as long-term; and (v) higher common share dividends, partially offset by: (i) higher proceeds from the issuance of common shares; (ii) lower repayments of long-term debt; and (iii) higher advances from non-controlling interests in the Waneta Partnership.
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 offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40% equity, including preference shares, and 60% debt, as well as investment-grade credit ratings. Each of the Corporation–s regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in the utilities– customer rates.
The consolidated capital structure of Fortis is presented in the following table.
The improvement in the capital structure was driven by the public offering of approximately $341 million of common shares in June and July 2011, combined with common shares issued under the Corporation–s dividend reinvestment and stock option plans, and the reclassification of net unrealized foreign currency translation losses related to the Corporation–s previous investment in Belize Electricity to long-term other assets. Also contributing to the improvement were net earnings attributable to common equity shareholders, net of dividends, combined with an overall decrease in total debt. A portion of the proceeds from the public common equity offering were used to repay credit facility borrowings in 2011.
Credit Ratings: The Corporation–s credit ratings are as follows:
Standard & Poor–s (“S&P”) A- (long-term corporate and unsecured debt credit rating)
DBRS A(low) (unsecured debt credit rating)
During the third quarter of 2011, DBRS confirmed the Corporation–s existing debt credit rating at A(low). S&P is expected to complete its annual review of the Corporation–s credit rating in the first quarter of 2012. 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 approximate $1.2 billion in gross capital expenditures by segment for 2011 is provided in the following table.
Gross consolidated capital expenditures of $1,174 million for 2011 were $38 million lower than $1,212 million forecasted for 2011, as 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. Lower-than-forecasted capital spending was mainly due to: (i) a shift in the timing of certain capital expenditures from 2011 to 2012 and various individually small capital projects determined not to be required at the FortisBC Energy companies; (ii) the discontinuance of the consolidation method of accounting for Belize Electricity, effective June 2011; and (iii) a shift in capital expenditures from 2011 to 2012 related to the timing of payments associated with the Waneta Expansion Project.
An update on significant capital projects for 2011 from that disclosed in the MD&A as at December 31, 2010 is provided below.
FEVI–s construction of the estimated $212 million 1.5 billion-cubic foot LNG storage facility at Mount Hayes on Vancouver Island was completed in the second quarter of 2011 and was brought online in late 2011. The storage facility provides a reliable, cost-competitive means of storing gas close to customers, while reducing the dependence on out-of-province storage facilities. The facility provides greater flexibility to meet customer needs during winter months when demand for natural gas is at its highest and meet planned and unplanned system interruptions.
FEI–s Customer Care Enhancement Project, at an estimated total project cost of $110 million, was put into service in January 2012. The Company estimates approximately $30 million of the project cost to be incurred in the first half of 2012 related to final contractor payments with the total project cost expected to come in under budget. The project entailed the insourcing of core elements of FEI–s customer care services, including two company-owned call centres and billing operations, and implementation of a new customer information system. The BCUC approved the project upon the Company–s acceptance of a cost risk-sharing condition, whereby FEI agreed to equally share with customers any costs or savings outside a band of plus or minus 10% of the approved total project cost.
FortisBC Electric–s $105 million Okanagan Reinforcement Project was substantially completed in the fall of 2011. The project related to upgrading the existing overhead transmission line between Penticton and Vaseux Lake, near Oliver, from 161 kilovolts (“kV”) to a double-circuit 230-kV line and building a new 230-kV terminal substation in the Oliver area.
The Fraser River South Bank South Arm Rehabilitation Project involved the installation and replacement of underwater transmission pipeline crossings that were at potential risk of failure from a major seismic event. During 2010 difficulties were experienced with one of the directional drills delaying the project that was subsequently completed and came into service in 2011, rather than in 2010 as originally expected, at an estimated total cost of approximately $36 million.
During the first quarter of 2011, FortisAlberta substantially completed its $126 million Automated Metering Project, which involved the replacement of approximately 477,000 conventional meters.
During 2011 FortisAlberta continued with the replacement of vintage poles under its Pole Management Program, which involves 96,000 poles in total, to prevent risk of failure due to age. The total capital cost of the program through to 2019 is now expected to be approximately $335 million, an increase from the $283 million forecast as at December 31, 2010. The increase is primarily due to a revised forecast estimating higher labour and material costs later in the program and a change in the program scope to include minor-line rebuilds.
Fortis Turks and Caicos had an agreement with a supplier to purchase two diesel-powered generating units, each with a capacity of 9 MW. The units were delivered in 2010 and 2011. Assuming demand for additional generating capacity in 2014, an additional 9-MW unit is forecast for delivery at an estimated cost of approximately $8 million (US$8 million). An agreement for the additional unit has not yet been formalized as it is dependent on future demand trends.
In August 2011 Fortis Properties received municipal government approval to construct a $47 million 12-storey office building in downtown St. John–s, Newfoundland. The building will feature 152,000 square feet of Class A office space and include 261 parking spaces. Construction is expected to be completed in the second half of 2013.
Construction progress on the $900 million 335-MW Waneta Expansion Project, in partnership with Columbia Power Corporation and Columbia Basin Trust, is going well and the project is currently on schedule. Fortis owns a 51% interest in the Waneta Partnership and will operate and maintain the non-regulated investment when the facility comes into service, which is expected in spring 2015. Major construction activities on-site include excavation of the intake, powerhouse and power tunnels. Approximately $244 million has been spent on this project since construction began late 2010. The Waneta Expansion Project will be included in the Canal Plant Agreement and will receive fixed energy and capacity entitlements based upon long-term average water flows, thereby significantly reducing hydrologic risk associated with the project. The energy, approximately 630 GWh, and associated capacity required to deliver such energy, for the Waneta Expansion Project will be sold to BC Hydro under a long-term energy purchase agreement. The surplus capacity, equal to 234 MW on an average annual basis, is expected to be sold to FortisBC Electric under a long-term capacity purchase agreement.
Over the five-year period 2012 through 2016, consolidated gross capital expenditures are expected to be approximately $5.5 billion. Approximately 64% of the capital spending is expected to be incurred at the regulated electric utilities, driven by FortisAlberta and FortisBC Electric. Approximately 23% and 13% 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. Over the five-year period, on average annually, 39% of utility capital spending is expected to be incurred to meet customer growth; 38% is expected to be incurred to ensure continued and enhanced performance, reliability and safety of generation, transmission and distribution assets (i.e., sustaining capital expenditures); and 23% is expected to be incurred for facilities, equipment, vehicles, information technology and other assets.
A breakdown of forecast gross consolidated capital expenditures by segment for 2012 is provided in the following table.
Significant individual capital projects for 2012 include the continuation of the construction of the non-regulated Waneta Expansion Project for $254 million and the 12-storey office building in St. John–s, Newfoundland for $32 million, as well as the continued replacement of vintage poles under FortisAlberta–s Pole Management Program for $27 million.
CREDIT FACILITIES
As at December 31, 2011, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.2 billion, of which $1.9 billion was unused, including the Corporation–s unused $800 million committed revolving credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, with no one bank holding more than 20% of these facilities. Approximately $2.1 billion of the total credit facilities are committed facilities with maturities ranging from 2012 to 2015.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
FUTURE ACCOUNTING CHANGES
Adoption of New Accounting Standards: Due to continued uncertainty around the 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 International Financial Reporting Standards (“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 a Securities and Exchange Commission (“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 Ontario Securities Commission (“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 refers to 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.
During the fourth quarter of 2010, the Corporation 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 was completed during 2011.
Phase II – Analysis and Development: Phase II consisted 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 US 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 were no longer required or applicable as a result of the Exemption granted by the OSC as discussed above.
Phase II of the plan commenced in January 2011 and was essentially completed during 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 result in 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 is currently ongoing and has involved the implementation of financial reporting systems and internal control changes required by the Corporation to prepare and file its consolidated financial statements in accordance with US GAAP beginning in 2012, and the communication of associated impacts.
The Corporation will prepare and file its audited Canadian GAAP consolidated financial statements for the year ended December 31, 2011 in the usual manner. The Corporation then intends to voluntarily prepare and file audited US GAAP consolidated financial statements for the year ended December 31, 2011, with 2010 comparatives. The Corporation–s voluntary filing of audited US GAAP consolidated financial statements for the year ended December 31, 2011, subsequent to the filing of its audited Canadian GAAP consolidated financial statements for the year ended December 31, 2011, has been approved by the OSC and is expected to be completed by 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 will conclude when the Corporation files its annual audited consolidated financial statements for the year ending December 31, 2012 prepared in accordance with US GAAP.
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 outlined below. The identified impacts are unaudited and are subject to change based on further analysis.
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 which have not yet been recognized.
US GAAP requires recognition of the funded status of defined benefit plans on the balance sheet. Unamortized balances related to past service costs, actuarial gains and losses and transitional obligations or assets are separately recognized on the balance sheet as a component of accumulated other comprehensive income or, in the case of entities with activities subject to rate regulation, as regulatory assets or liabilities for recovery from, or refund to, customers in future rates. Subsequent changes to past service costs, actuarial gains and losses and transitional obligations would be recognized as part of 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 will recognize the funded status of their defined benefit pension plans on the balance sheet with the above-noted unamortized balances recognized as regulatory assets or liabilities.
US GAAP also requires that OPEB costs be recorded on an accrual basis, and prohibits the recognition of regulatory assets or liabilities associated with OPEB costs that are recovered on a cash basis. 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. Historically, Newfoundland Power had also recovered its OPEB costs on a cash basis. However, in December 2010, the regulator approved Newfoundland Power–s application to: (i) adopt the accrual method of accounting for OPEB costs, effective January 1, 2011; (ii) recover the transitional regulatory asset associated with the adoption of accrual accounting over a 15-year period; and (iii) adopt an OPEB cost-variance deferral account to capture differences between OPEB expense calculated in accordance with applicable generally accepted accounting principles and OPEB expense approved by the regulator for rate-setting purposes. The rules under US GAAP related to accounting for OPEBs by rate-regulated entities require that Newfoundland Power de-recognize its OPEB regulatory asset as at January 1, 2010 on the premise that, as at that date, Newfoundland Power was recovering its OPEB costs on a cash basis. However, the regulatory asset will be re-recognized through earnings in accordance with US GAAP in 2010 based on the regulator–s approval of Newfoundland Power–s application to adopt the accrual method of accounting for OPEBs effective January 1, 2011 and to recover the associated transitional regulatory asset over a 15-year period.
Additional differences between Canadian GAAP and US GAAP in terms of accounting for defined benefit plans include the determination of the measurement date and the attribution period over which pension expense is recognized. Canadian GAAP allows for the use of a measurement date up to three months prior to the date of an entity–s fiscal year end. However, US GAAP requires the entity–s fiscal year end to be used as the measurement date. Canadian GAAP also allows for the use of an attribution period for defined benefit pension plans, under specific circumstances, that extends beyond the date when the credited service period ends. However, US GAAP allows for the use of an attribution period for defined benefit pension plans up to the date when credited service ends. The differences are expected to impact the calculation of the Corporation–s consolidated benefit obligation, which will be mostly offset by a corresponding change to regulatory assets or liabilities.
With the exception of a one-time adjustment with respect to Newfoundland Power–s inability to recognize its OPEB regulatory asset as at January 1, 2010 and its ability to subsequently re-recognize this OPEB regulatory asset through earnings in 2010, the impact of adopting US GAAP with respect to accounting for employee future benefits is not expected to have a material impact on the Corporation–s consolidated earnings.
Brilliant Power Purchase Agreement (“BPPA”): FortisBC Electric expects that its BPPA will be accounted for as a capital lease under US GAAP. While the requirement to evaluate whether an arrangement includes a lease is similar between Canadian GAAP and US GAAP, the effective date for prospective adoption of lease accounting guidance differs, resulting in an accounting difference with respect to the BPPA.
Fulfillment of the BPPA is dependent on the use of a specific asset, the Brilliant Hydroelectric Plant (“Brilliant”), and the conveyance unto FortisBC Electric of the right to use that asset under an arrangement between FortisBC Electric and the legal owner of Brilliant. The BPPA qualifies as a capital lease as the present value of the minimum lease payments to be made by FortisBC Electric represents recovery of the entire amount of the initial investment in Brilliant by the legal owner over the term of the arrangement.
The anticipated effect of retrospectively recognizing Brilliant as a capital lease upon adoption of US GAAP includes the recognition on the consolidated balance sheet of a utility capital asset with a corresponding capital lease obligation for an equivalent amount. Each subsequent reporting period, the total amount of amortization and interest expense to be recognized under capital lease accounting is expected to differ from the amount paid under the BPPA and recovered through current electricity rates as permitted by the BCUC. This timing difference is expected to be recognized as a regulatory asset, with amounts recovered through electricity rates expected to equal the combined amount of the capitalized lease asset and interest on the lease obligation over the term of the BPPA.
Since US GAAP allows for entities to account for the effects of rate regulation, the impact of adopting capital lease accounting for Brilliant is not expected to affect the Corporation–s consolidated earnings.
Lease-In Lease-Out (“LILO”) Transactions: FEI had entered into arrangements whereby certain natural gas distribution assets were leased to certain municipalities and then leased back by FEI from the municipalities. Under Canadian GAAP, the lease of the assets to the municipalities has been accounted for as a sales-type lease and the lease back of the assets as an operating lease. Gains recorded on the lease out of the assets were deferred and are being amortized over the term of the lease back arrangements.
Under US GAAP, the natural gas distribution assets are considered to be equipment integral to FEI–s operations and, therefore, must be evaluated as a real estate sale-leaseback transaction. As a result of this evaluation, the transaction is required to be accounted for as a financing transaction under US GAAP. Under the financing method, the assets subject to the sale-leaseback arrangement are to be recorded as utility capital assets on the Corporation–s consolidated balance sheet and subsequently depreciated. Sale proceeds received are recorded as long-term debt. Lease payments, less the portion considered to be interest expense, decrease the long-term debt. The deferred gains, and amortization thereof, which were recorded in accordance with Canadian GAAP are not recognized under US GAAP.
The retrospective impact of accounting for FEI–s LILO transactions under US GAAP is expected to result in a decrease in opening retained earnings as at January 1, 2010. The impact on the Corporation–s consolidated earnings is not expected to be material.
Reclassification of preference shares: Currently, under Canadian GAAP, the Corporation–s First Preference Shares, Series C and Series E are classified as long-term liabilities with associated dividends classified as finance charges. Under US GAAP, the First Preference Shares, Series C and Series E do not meet the criteria for recognition as a financial liability. Therefore, upon the adoption of US GAAP, the Corporation will reclassify its First Preference Shares, Series C and Series E from long-term liabilities to shareholders– equity on the consolidated balance sheet. The associated dividends will not be recorded as finance charges on the Corporation–s consolidated statement of earnings but, rather, will be recorded as earnings attributable to preference equity shareholders.
Corporate income taxes: Under Canadian GAAP, the Corporation has calculated and recognized corporate income taxes using substantively enacted corporate income tax rates. Under US GAAP, the Corporation is required to calculate and record corporate income taxes based on enacted corporate income tax rates. Therefore, upon adoption of US GAAP, the Corporation will be required to recognize the impact of the difference between enacted tax rates and substantively enacted tax rates related to the calculation of Part VI.1 tax deductions associated with preference share dividends. The retrospective adjustment to recognize the Part VI.1 tax deductions based on enacted corporate income tax rates will result in a reduction in opening retained earnings under US GAAP and annual earnings thereafter. However, the adjustments are expected to reverse once pending Canadian federal legislation is passed and proposed corporate income tax rate changes become enacted.
The above items do not represent a complete list of expected differences between US GAAP and Canadian GAAP and are subject to change. Other less significant differences have also been identified. Analysis also remains ongoing and additional areas where the Corporation–s consolidated financial statements could be materially impacted may be identified prior to the Corporation–s voluntary preparation and filing of its audited US GAAP consolidated financial statements for the year ended December 31, 2011. A detailed reconciliation between the Corporation–s audited Canadian GAAP and US GAAP financial statements for 2011, including 2010 comparatives, will be disclosed as part of that voluntary filing.
The unaudited estimated quantification and reconciliation of the Corporation–s consolidated balance sheets as at December 31, 2011 and December 31, 2010, prepared in accordance with US GAAP versus Canadian GAAP, based on the differences identified to date, may be summarized as follows.
Total assets as at December 31, 2011 are estimated to increase by approximately $597 million (December 31, 2010 – $496 million). The estimated increase is due primarily to expected increases in regulatory assets and utility capital assets in accordance with US GAAP.
Total liabilities as at December 31, 2011 are estimated to increase by approximately $329 million (December 31, 2010 – $226 million). The estimated increase is due primarily to the expected increases in long-term debt and capital lease obligations and pension liabilities in accordance with US GAAP, partially offset by the reclassification of preference shares from liabilities to shareholders– equity.
Shareholders– equity as at December 31, 2011 is estimated to increase by approximately $268 million (December 31, 2010 – $270 million). The estimated increase is due primarily to the expected reclassification of preference shares from liabilities to shareholders– equity in accordance with US GAAP, partially offset by an estimated reduction in retained earnings of approximately $35 million (December 31, 2010 – $28 million), an estimated increase in accumulated other comprehensive loss of approximately $21 million (December 31, 2010 – $14 million) and other miscellaneous reductions in shareholders– equity based on the retrospective application of US GAAP. Approximately half of the reduction in retained earnings results from higher corporate income taxes, as referred to above, and is expected to reverse in a future period once pending Canadian federal income tax legislation is passed and proposed Part VI.1 tax rate changes become enacted.
As previously indicated, and subject to the above referenced one-time adjustment with respect to Newfoundland Power–s inability to recognize its OPEB regulatory asset as at January 1, 2010 and its subsequent ability to re-recognize this OPEB regulatory asset in 2010, no material adjustments to the Corporation–s consolidated earnings are currently expected under US GAAP due to the Corporation–s continued ability to apply rate-regulated accounting policies.
The unaudited estimated quantification and reconciliation of the Corporation–s consolidated statements of earnings for the years ended December 31, 2011 and December 31, 2010, prepared in accordance with US GAAP versus Canadian GAAP, based on the differences identified to date, may be summarized as follows.
Year ended December 31, 2011: Consolidated net earnings to be recognized in accordance with US GAAP are estimated to increase by $10 million (from $356 million to $366 million). The estimated increase is due primarily to the reclassification of preference share dividends totalling $17 million, in accordance with US GAAP, from finance charges to earnings attributable to preference equity shareholders, partially offset by an expected reduction in earnings attrib