ST. JOHN–S, NEWFOUNDLAND AND LABRADOR — (Marketwire) — 05/02/12 — Fortis Inc. (“Fortis” or the “Corporation”) (TSX: FTS) achieved first quarter net earnings attributable to common equity shareholders of $121 million, or $0.64 per common share, compared to $116 million, or $0.66 per common share, for the first quarter of 2011. Performance was driven by the FortisBC Energy companies. The decrease in earnings per common share quarter over quarter mainly related to an 8% increase in the weighted average number of common shares outstanding, largely associated with the public common equity offering in mid-2011, and the $4 million, or $0.02 per common share, one-time acquisition-related expenses associated with the CH Energy Group, Inc. (“CH Energy Group”) transaction discussed below.
Common shareholders of Fortis received a dividend of 30 cents per common share on March 1, 2012, up from 29 cents in the fourth quarter of 2011. The 3.4% increase in the quarterly common share dividend translates into an annualized dividend of $1.20 and extends the Corporation–s record of annual common share dividend increases to 39 consecutive years, the longest record of any public corporation in Canada.
Canadian Regulated Gas Utilities delivered earnings of $82 million, up $7 million from the first quarter of 2011. The increase in earnings was mainly due to: (i) seasonality of gas consumption and the timing of certain expenses in 2012; (ii) growth in energy infrastructure investment; and (iii) increased gas transportation volumes to the forestry and mining sectors. The increase was partially offset by lower-than-expected customer additions and lower capitalized allowance for funds used during construction. Due to the seasonality of the business, most of the earnings of the regulated gas utilities are realized in the first and fourth quarters.
Canadian Regulated Electric Utilities contributed earnings of $51 million, compared to $52 million for the first quarter of 2011. The slight decrease in earnings was largely the result of the discontinuance of the performance-based rate-setting (“PBR”) mechanism and the timing of certain operating expenses in 2012 at FortisBC Electric, partially offset by higher electricity sales and lower effective corporate income taxes at Newfoundland Power and Maritime Electric. Excluding the approximate $1 million gain on sale of property in the first quarter of 2011, earnings at FortisAlberta improved quarter over quarter as a result of growth in energy infrastructure investment, partially offset by the impact of a lower allowed rate of return on common shareholders– equity.
“Recent regulatory decisions at FortisAlberta and the FortisBC Energy companies provide a measure of regulatory stability for our western Canadian utilities,” says Stan Marshall, President and Chief Executive Officer, Fortis Inc. In April 2012 regulatory decisions were received for 2012/2013 customer gas delivery rates at the FortisBC Energy companies and 2012 customer electricity distribution rates at FortisAlberta. A decision on 2012/2013 customer electricity rates at FortisBC Electric is expected mid-2012. “It remains a very busy period on the regulatory front as a number of regulatory processes are underway at FortisBC, FortisAlberta and Newfoundland Power,” he explains. A Generic Cost of Capital Proceeding in British Columbia to determine cost of capital, effective January 1, 2013, and a PBR rate-regulation initiative in Alberta are in progress. A Cost of Capital Application was filed by Newfoundland Power in March 2012.
Caribbean Regulated Electric Utilities contributed $3 million to earnings compared to $4 million for the first quarter of 2011. The decrease in earnings was due to higher finance charges and operating and depreciation expenses.
Non-Regulated Fortis Generation contributed $5 million to earnings, up $2 million from the first quarter of 2011. Improved performance was the result of higher production in Belize due to higher rainfall.
Fortis Properties delivered earnings of $1 million, comparable to the first quarter of 2011.
Corporate and other expenses were $21 million, $2 million higher quarter over quarter, largely the result of CH Energy Group acquisition-related expenses incurred in the first quarter of 2012, partially offset by lower finance charges.
Cash flow from operating activities was $328 million for the quarter, up $26 million from the first quarter of 2011, driven by favourable changes in working capital, largely associated with current regulatory deferral accounts, and higher earnings.
Fortis retroactively adopted accounting principles generally accepted in the United States (“US GAAP”), effective January 1, 2012, with the restatement of prior periods. The adoption of US GAAP did not have a material impact on the Corporation–s earnings per common share for the first quarter of 2012 or 2011.
In February 2012 Fortis entered into an agreement to acquire CH Energy Group for approximately US$1.5 billion, including the assumption of approximately $500 million of debt on closing. Central Hudson Gas & Electric Corporation (“Central Hudson”), the main business of CH Energy Group, is a regulated transmission and distribution utility serving approximately 300,000 electric and 75,000 natural gas customers in eight counties of New York State–s Mid-Hudson River Valley.
The closing of the acquisition is subject to the receipt of CH Energy Group–s common shareholders– approval, regulatory and other approvals, and satisfaction of customary closing conditions. The acquisition is expected to be immediately accretive to earnings per common share of Fortis, excluding one-time acquisition-related expenses. In April 2012 applications were filed with the New York State Public Service Commission and Federal Energy Regulatory Commission seeking approval of the transaction. The CH Energy Group shareholder vote on the transaction is expected to occur mid-2012.
Consolidated capital expenditures, before customer contributions, were approximately $229 million in the first quarter of 2012. The Customer Care Enhancement Project at FortisBC–s gas business came into service in January 2012. Construction continues on the $900 million Waneta Expansion hydroelectric generating facility (“Waneta Expansion”) with excavation of the intake, powerhouse and power tunnels completed. Approximately $290 million has been spent on the Waneta Expansion since construction began in late 2010.
“Fortis utilities are well underway towards completing their 2012 capital projects to meet the energy needs of our customers,” says Marshall. “Our 2012 consolidated capital expenditure program is expected to be $1.3 billion. Over the next five years through 2016, our capital program is expected to total $5.5 billion. This investment should support continuing growth in earnings and dividends,” says Marshall.
“Fortis is working to close the acquisition of CH Energy Group, which is expected to occur by the end of the first quarter of 2013,” says Marshall. “We remain disciplined and patient in our pursuit of additional electric and gas utility acquisitions in the United States and Canada that will add value for Fortis shareholders,” concludes Marshall.
FORWARD-LOOKING STATEMENT
The following Fortis Inc. (“Fortis” or the “Corporation”) Management Discussion and Analysis (“MD&A”) has been prepared in accordance with National Instrument 51-102 – Continuous Disclosure Obligations. Financial information for 2012 and comparative periods contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States (“US GAAP”) and is presented in Canadian dollars unless otherwise specified. The MD&A should be read in conjunction with the following: (i) the interim unaudited consolidated financial statements and notes thereto for the three months ended March 31, 2012, prepared in accordance with US GAAP; (ii) the audited consolidated financial statements and notes thereto for the year ended December 31, 2011, prepared in accordance with US GAAP and voluntarily filed on the System for Electronic Document Analysis and Retrieval (“SEDAR”) by Fortis on March 16, 2012; (iii) the audited consolidated financial statements and notes thereto for the year ended December 31, 2011, prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”); (iv) the “Supplemental Interim Consolidated Financial Statements for the Year Ended December 31, 2011 (Unaudited)” contained in the above-noted voluntary filing which provides a detailed reconciliation between the Corporation–s interim unaudited consolidated 2011 Canadian GAAP financial statements and interim unaudited consolidated 2011 US GAAP financial statements; and (v) the MD&A for the year ended December 31, 2011 included in the Corporation–s 2011 Annual Report.
Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws in Canada (“forward-looking information”). The purpose of the forward-looking information is to provide management–s expectations regarding the Corporation–s future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation. The words “anticipates”, “believes”, “budgets”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management–s current beliefs and is based on information currently available to the Corporation–s management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the Corporation–s consolidated forecast gross capital expenditures for 2012 and in total over the five-year period 2012 through 2016; the nature, timing and amount of certain capital projects and their expected costs and time to complete; the expectation that the Corporation–s significant capital expenditure program should support continuing growth in earnings and dividends; forecast midyear rate base; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of cash from operations, borrowings under credit facilities, equity injections from Fortis and long-term debt offerings; the expected consolidated long-term debt maturities and repayments on average annually over the next five years; except for debt at the Exploits River Hydro Partnership (“Exploits Partnership”), the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2012; the expected timing of filing of regulatory applications and of receipt of regulatory decisions; the expected timing of the closing of the acquisition of CH Energy Group, Inc. (“CH Energy Group”) by Fortis and the expectation that the acquisition will be immediately accretive to earnings per common share, excluding one-time acquisition-related expenses; and the expectation of an increase in the Corporation–s committed corporate credit facility from $800 million to $1 billion.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; no material capital project and financing cost overrun related to the construction of the Waneta Expansion hydroelectric generating facility; sufficient liquidity and capital resources; the expectation that the Corporation will receive appropriate compensation from the Government of Belize (“GOB”) for fair value of the Corporation–s investment in Belize Electricity that was expropriated by the GOB; the expectation that Belize Electric Company Limited (“BECOL”) will not be expropriated by the GOB; the expectation that the Corporation will receive fair compensation from the Government of Newfoundland and Labrador related to the expropriation of the Exploits Partnership–s hydroelectric assets and water rights; the continuation of regulator-approved mechanisms to flow through the commodity cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in interest rates, foreign exchange rates, natural gas commodity prices and fuel prices; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the ability to report under US GAAP beyond 2014 or the adoption of International Financial Reporting Standards (“IFRS”) after 2014 that allows for the recognition of regulatory assets and liabilities; the continued tax-deferred treatment of earnings from the Corporation–s Caribbean operations; continued maintenance of information technology (“IT”) infrastructure; continued favourable relations with First Nations; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations include, but are not limited to: regulatory risk; interest rate risk, including the uncertainty of the impact a continuation of a low interest rate environment may have on allowed rates of return on common shareholders– equity of the Corporation–s regulated utilities; operating and maintenance risks; risk associated with changes in economic conditions; capital project budget overrun, completion and financing risk in the Corporation–s non-regulated business; capital resources and liquidity risk; risk associated with the amount of compensation to be paid to Fortis for its investment in Belize Electricity that was expropriated by the GOB; the timeliness of the receipt of the compensation and the ability of the GOB to pay the compensation owing to Fortis; risk that the GOB may expropriate BECOL; an ultimate resolution of the expropriation of the hydroelectric assets and water rights of the Exploits Partnership that differs from that which is currently expected by management; weather and seasonality risk; commodity price risk; the continued ability to hedge foreign exchange risk; counterparty risk; competitiveness of natural gas; natural gas, fuel and electricity supply risk; risk associated with the continuation, renewal, replacement and/or regulatory approval of power supply and capacity purchase contracts; risks relating to the ability to, and timing of, close of the acquisition of CH Energy Group and the realization of the benefits of the acquisition; the risk associated with defined benefit pension plan performance and funding requirements; risks related to FortisBC Energy (Vancouver Island) Inc.; environmental risks; insurance coverage risk; risk of loss of licences and permits; risk of loss of service area; risk of not being able to report under US GAAP beyond 2014 or risk that IFRS does not have an accounting standard for rate-regulated entities by the end of 2014 allowing for the recognition of regulatory assets and liabilities; risks related to changes in tax legislation; risk of failure of IT infrastructure; risk of not being able to access First Nations lands; labour relations risk; human resources risk; and risk of unexpected outcomes of legal proceedings currently against the Corporation. For additional information with respect to the Corporation–s risk factors, reference should be made to the Corporation–s continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and to the heading “Business Risk Management” in the MD&A for the three months ended March 31, 2012 and for the year ended December 31, 2011.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned distribution utility in Canada, serving more than 2,000,000 gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia, Canada. Fortis owns non-regulated generation assets, primarily hydroelectric, across Canada and in Belize and Upper New York State, and hotels and commercial office and retail space in Canada. Year-to-date March 31, 2012, the Corporation–s electricity distribution systems met a combined peak demand of approximately 5,183 megawatts (“MW”) and its gas distribution system met a peak day demand of 1,335 terajoules (“TJ”). For additional information on the Corporation–s business segments, refer to Note 1 to the Corporation–s interim unaudited consolidated financial statements for the three months ended March 31, 2012 and to the “Corporate Overview” section of the 2011 Annual MD&A.
The key goals of the Corporation–s regulated utilities are to operate sound gas and electricity distribution systems, deliver gas and electricity safely and reliably at the lowest reasonable cost and conduct business in an environmentally responsible manner. The Corporation–s main business, utility operations, is highly regulated and the earnings of the Corporation–s regulated utilities are primarily determined under cost of service (“COS”) regulation.
Generally under COS regulation, the respective regulatory authority sets customer gas and/or electricity rates to permit a reasonable opportunity for the utility to recover, on a timely basis, estimated costs of providing service to customers, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value (“rate base”). Generally, the ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on common shareholders– equity (“ROE”) and/or rate of return on rate base assets (“ROA”) depends on the utility achieving the forecasts established in the rate-setting processes. As such, earnings of regulated utilities are generally impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) timing differences within an annual financial reporting period, between when actual expenses are incurred and when they are recovered from customers in rates. When forward test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible to be deferred on the balance sheet. In addition, the Corporation–s regulated utilities, where applicable, are permitted by their respective regulatory authority to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms.
Pending Acquisition of CH Energy Group, Inc.: On February 21, 2012, Fortis announced that it had entered into an agreement to acquire CH Energy Group, Inc. (“CH Energy Group”) for US$65.00 per common share in cash, for an aggregate purchase price of approximately US$1.5 billion, including the assumption of approximately US$500 million of debt on closing (the “Acquisition”). CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New York. Its main business, Central Hudson Gas & Electric Corporation, is a regulated transmission and distribution (“T&D”) utility serving approximately 300,000 electric and 75,000 natural gas customers in eight counties of New York State–s Mid-Hudson River Valley. The closing of the Acquisition, which is expected by the end of the first quarter of 2013, is subject to receipt of CH Energy Group–s common shareholders– approval, regulatory and other approvals, and the satisfaction of customary closing conditions. The acquisition is expected to be immediately accretive to earnings per common share of Fortis, excluding one-time acquisition-related expenses. Fortis and CH Energy Group filed a joint petition with the New York State Public Service Commission in April 2012 for approval of the acquisition of all of the outstanding stock of CH Energy Group by Fortis and, indirectly, ownership of Central Hudson, and related transactions. The vote on the acquisition by CH Energy Group–s shareholders is expected to occur mid-2012. Also, an application was filed in April 2012 with the Federal Energy Regulatory Commission seeking similar approvals.
Transition to US GAAP: In June 2011 the Ontario Securities Commission issued a decision allowing Fortis and its reporting issuer subsidiaries to prepare their financial statements, effective January 1, 2012 through to December 31, 2014, in accordance with US GAAP without qualifying as U.S. Securities and Exchange Commission (“SEC”) Issuers pursuant to Canadian securities laws. The Corporation and its reporting issuer subsidiaries, therefore, adopted US GAAP as opposed to International Financial Reporting Standards (“IFRS”) on January 1, 2012. Earnings recognized under US GAAP are more closely aligned with earnings recognized under Canadian GAAP, mainly due to the continued recognition of regulatory assets and liabilities under US GAAP. A transition to IFRS would likely have resulted in the derecognition of some, or perhaps all, of the Corporation–s regulatory assets and liabilities and significant volatility in the Corporation–s consolidated earnings. On March 16, 2012, Fortis voluntarily prepared and filed audited consolidated US GAAP financial statements for the year ended December 31, 2011, with 2010 comparatives. Also included in the voluntary filing were: (i) a detailed reconciliation between the Corporation–s audited consolidated Canadian GAAP and audited consolidated US GAAP financial statements for fiscal 2011, including 2010 comparatives; and (ii) a detailed reconciliation between the Corporation–s 2011 interim unaudited consolidated Canadian GAAP and 2011 interim unaudited consolidated US GAAP financial statements. For further information, refer to the “Changes in Accounting Policies” section of this MD&A.
Expropriated Assets – Belize Electricity: There were no material changes during the first quarter of 2012 with respect to matters pertaining to the expropriation of Belize Electricity from those disclosed in the Corporation–s 2011 Annual MD&A. Court proceedings continue in the Belize Supreme Court in respect of the Corporation–s challenge to the expropriation.
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 first quarters ended March 31, 2012 and March 31, 2011 are provided in the following table.
Factors Contributing to Revenue Variance
Unfavourable
Favourable
Factors Contributing to Energy Supply Costs Variance
Favourable
Unfavourable
Factors Contributing to Operating Expenses Variance
Unfavourable
Favourable
Factors Contributing to Depreciation and Amortization Costs Variance
Unfavourable
Favourable
Factors Contributing to Other Income (Expenses), Net Variance
Unfavourable
Factors Contributing to Finance Charges Variance
Favourable
Unfavourable
Factors Contributing to Income Taxes Variance
Favourable
Factors Contributing to Earnings Variance
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 Gas Volumes Variances
Unfavourable
Favourable
Net customer additions were 1,000 during the first quarter of 2012 compared to 1,400 during the same quarter in 2011. Net customer additions decreased due to lower building activity during 2012. With the implementation of the new Customer Care Enhancement Project on January 1, 2012, the FortisBC Energy companies changed their definition of a customer. As a result of this change, FEI adjusted its customer count downwards by approximately 17,000, effective January 1, 2012. As at March 31, 2012, the total number of customers served by the FortisBC Energy companies was approximately 939,000.
The FortisBC Energy companies earn approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulator-approved deferral mechanisms, changes in consumption levels and the commodity cost of natural gas from those forecast to set residential and commercial customer gas rates do not materially affect earnings.
Seasonality has a material impact on the earnings of the FortisBC Energy companies as a major portion of the gas distributed is used for space heating. Most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters.
Factors Contributing to Revenue Variance
Unfavourable
Favourable
Factors Contributing to Earnings Variance
Favourable
Unfavourable
REGULATED ELECTRIC UTILITIES – CANADIAN
FORTISALBERTA
Factors Contributing to Energy Deliveries Variance
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.
Factors Contributing to Revenue Variance
Favourable
Unfavourable
Factors Contributing to Earnings Variance
Favourable
Unfavourable
FORTISBC ELECTRIC(1)
Factor Contributing to Electricity Sales Variance
Favourable
Factors Contributing to Revenue Variance
Favourable
Factors Contributing to Earnings Variance
Unfavourable
Favourable
NEWFOUNDLAND POWER
Factors Contributing to Electricity Sales Variance
Favourable
Factors Contributing to Revenue Variance
Favourable
Unfavourable
Factors Contributing to Earnings Variance
Favourable
Unfavourable
OTHER CANADIAN ELECTRIC UTILITIES(1)
Factors Contributing to Electricity Sales Variance
Unfavourable
Favourable
Factors Contributing to Revenue Variance
Favourable
Unfavourable
Factors Contributing to Earnings Variance
Favourable
REGULATED ELECTRIC UTILITIES – CARIBBEAN(1)
Factors Contributing to Electricity Sales Variance
Unfavourable
Favourable
Factors Contributing to Revenue Variance
Unfavourable
Favourable
Factors Contributing to Earnings Variance
Unfavourable
Favourable
NON-REGULATED – FORTIS GENERATION(1)
Factors Contributing to Energy Sales Variance
Favourable
Unfavourable
Factor Contributing to Revenue and Earnings Variances
Favourable
In May 2011 the generator at Moose River–s hydroelectric generating facility in Upper New York State sustained electrical damage. Equipment and business interruption insurance claims are ongoing. Revenue for the first quarter of 2012 reflects the accrual of insurance proceeds related to the loss of earnings for the first quarter of 2012 associated with the shutdown of the facility. The generator is under repair and the facility is expected to become operational in May 2012.
NON-REGULATED – FORTIS PROPERTIES(1)
Factors Contributing to Revenue Variance
Favourable
Factors Contributing to Earnings Variance
Favourable
Unfavourable
CORPORATE AND OTHER(1)
Factors Contributing to Net Corporate and Other Expenses Variance
Unfavourable
Favourable
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 quarter of 2012 are summarized as follows.
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between March 31, 2012 and December 31, 2011.
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation–s consolidated sources and uses of cash for the three months ended March 31, 2012, as compared to the same period in 2011, 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 $26 million higher quarter over quarter largely due to favourable changes in working capital mainly associated with current regulatory deferral accounts at the FortisBC Energy companies and FortisAlberta, and higher earnings. The above-noted increases were partially offset by unfavourable changes in accounts receivable, inventories and long-term regulatory deferral accounts.
Investing Activities: Cash used in investing activities was comparable quarter over quarter. Lower capital spending at the regulated utilities in western Canada and the Caribbean was largely offset by an increase in capital spending related to the non-regulated Waneta Expansion.
Financing Activities: Cash used in financing activities was $14 million lower for the quarter compared to the same quarter last year. The decrease was due to higher advances from non-controlling interests and lower repayments of short-term borrowings, partially offset by: (i) higher common share dividends; (ii) lower proceeds from the issuance of common shares; and (iii) lower net borrowings under committed credit facilities classified as long term.
Net repayment of short-term borrowings was $83 million for the quarter compared to $98 million for the same quarter last year. The change quarter over quarter was driven by the FortisBC Energy companies.
Net borrowings under committed credit facilities for the first quarter of 2012 compared to the same quarter of 2011 are summarized in the following table.
Borrowings under credit facilities by the utilities are primarily in support of their capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation–s committed credit facility.
Advances of approximately $29 million were received in the first quarter of 2012 from non-controlling interests in the Waneta Partnership to finance capital spending related to the Waneta Expansion compared to $17 million received in the first quarter of 2011. In January 2012 advances of approximately $12 million were received from two First Nations bands representing their 15% equity investment in the LNG storage facility on Vancouver Island.
Proceeds from the issuance of common shares decreased $9 million quarter over quarter, reflecting a lower number of stock options exercised under the Corporation–s stock option plans.
Common share dividends paid during the first quarter of 2012 were $44 million, net of $13 million in dividends reinvested, compared to $35 million, net of $16 million in dividends reinvested, paid during the same quarter of 2011. The dividend paid per common share for the first quarter of 2012 was $0.30 compared to $0.29 for the first quarter of 2011. The weighted average number of common shares outstanding for the first quarter was 189.0 million compared to 175.0 million for the first quarter of 2011.
CONTRACTUAL OBLIGATIONS
As at March 31, 2012, consolidated contractual obligations of Fortis over the next five years and for periods thereafter are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2011 Annual MD&A and below, where applicable. The presentation of certain contractual obligations has changed from that provided in the 2011 Annual MD&A due to the adoption of US GAAP. For further information concerning these changes, refer to the 2011 audited consolidated financial statements prepared in accordance with US GAAP and voluntarily filed on SEDAR.
Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2011 Annual MD&A, except as described below.
In January 2012 two First Nations bands each invested approximately $6 million in equity in the Mount Hayes LNG storage facility, representing a 15% equity interest in the Mount Hayes Limited Partnership, with FEVI holding the controlling 85% ownership interest. The non-controlling interests hold put options, which, if exercised, would require FEVI to repurchase the 15% ownership interest for cash, in accordance with the terms of the partnership agreement.
For a discussion of the nature and amount of the Corporation–s consolidated capital expenditure program, which is not included in the Contractual Obligations table above, refer to the “Capital Expenditure Program” section of this MD&A.
CAPITAL STRUCTURE
The Corporation–s principal businesses of regulated gas and electricity distribution require ongoing access to capital to 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 each of the utility–s customer rates.
The consolidated capital structure of Fortis is presented in the following table.
The improvement in the capital structure was primarily due to: (i) lower short-term borrowings; (ii) net earnings attributable to common equity shareholders, net of dividends; (iii) an increase in cash; and (iv) common shares issued under the Corporation–s dividend reinvestment plan.
CREDIT RATINGS
The Corporation–s credit ratings are as follows:
The above 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. In February 2012, after the announcement by Fortis that it had entered into an agreement to acquire CH Energy Group, DBRS placed the Corporation–s credit rating under review with developing implications. Similarly, S&P placed the Corporation–s credit rating on credit watch with negative implications.
CAPITAL EXPENDITURE PROGRAM
Capital investment in infrastructure is required to ensure continued and enhanced performance, reliability and safety of the gas and electricity systems and to meet customer growth. All costs considered to be maintenance and repairs are expensed as incurred. Costs related to replacements, upgrades and betterments of capital assets are capitalized as incurred.
A breakdown of the $229 million in gross capital expenditures by segment for the first quarter of 2012 is provided in the following table.
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts.
There have been no material changes in the overall expected level, nature and timing of the Corporation–s significant capital projects from those that were disclosed in the 2011 Annual MD&A. Gross consolidated capital expenditures for 2012 are forecasted at approximately $1.3 billion.
FEI–s Customer Care Enhancement Project, at an estimated total project cost of $110 million, came into service in January 2012. Approximately $25 million of the project costs were incurred in the first quarter of 2012, mainly related to final contractor payments, with a remaining $5 million expected to be incurred in the second quarter of 2012.
Construction progress on the $900 million Waneta Expansion is going well and the project is currently on schedule. Major construction activities on-site include the completion of the excavation of the intake, powerhouse and power tunnels. Approximately $290 million has been spent on the Waneta Expansion since construction began late in 2010.
Over the five-year period 2012 through 2016, consolidated gross capital expenditures are expected to be approximately $5.5 billion, consistent with that disclosed in the 2011 Annual MD&A. 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 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 and T&D assets (i.e., sustaining capital expenditures); and 23% is expected to be incurred for facilities, equipment, vehicles, information technology and other assets.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of subsidiary operating cash flows, with varying levels of residual cash flow available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, equity injections from Fortis and long-term debt offerings.
The Corporation–s ability to service its debt obligations and pay dividends on its common shares and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. Certain regulated subsidiaries may be subject to restrictions that may limit their ability to distribute cash to Fortis. Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation–s committed credit facility and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation–s committed credit facility may be required from time to time to support the servicing of debt and payment of dividends.
As at March 31, 2012, management expects consolidated long-term debt maturities and repayments to average approximately $265 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 $56 million as at March 31, 2012 (December 31, 2011 – $56 million). The lenders of the term loan have not demanded accelerated repayment. The scheduled repayments under the term loan are being made by Nalcor Energy, a Crown corporation, acting as agent for the Government of Newfoundland and Labrador with respect to expropriation matters. For further information refer to Note 35 to the Corporation–s 2011 annual audited consolidated financial statements prepared in accordance with US GAAP.
Except for the debt at the Exploits Partnership, as discussed above, Fortis and its subsidiaries were in compliance with debt covenants as at March 31, 2012 and are expected to remain compliant throughout the remainder of 2012.
CREDIT FACILITIES
As at March 31, 2012, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.2 billion, of which $2.0 billion was unused, including $769 million unused under the Corporation–s $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 $2.0 billion of the total credit facilities are committed facilities with maturities ranging from 2013 through 2017.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
As at March 31, 2012 and December 31, 2011, certain borrowings under the Corporation–s and subsidiaries– credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and management–s intention is to refinance these borrowings with long-term permanent financing during future periods.
In March 2012 Newfoundland Power renegotiated and amended its $100 million unsecured committed credit facility, obtaining an extension to the maturity of the facility to August 2017 from August 2015. The amended credit facility agreement reflects a decrease in pricing but, otherwise, contains substantially similar terms and conditions as the previous credit facility agreement.
In April 2012 FortisBC Electric renegotiated and amended its credit facility agreement resulting in an extension to the maturity of the Company–s $150 million unsecured committed revolving credit facility with $100 million now maturing in May 2015 and $50 million now maturing in May 2013.
Fortis has requested an increase in the amount available for borrowing under its committed corporate credit facility from $800 million to $1 billion, as permitted under the credit facility agreement, and expects the increase to be available in May 2012.
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.
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, the fair value is determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills, with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs.
The financial instruments table above excludes the long-term other asset associated with the Corporation–s previous investment in Belize Electricity. The fair value of the Corporation–s expropriated investment in Belize Electricity determined under the Government of Belize–s valuation is significantly lower than the fair value determined under the Corporation–s independent valuation of the utility. Due to uncertainty in the ultimate amount and ability of the Government of Belize to pay compensation owing to Fortis for the expropriation of Belize Electricity, the Corporation has recorded the long-term other asset at the carrying value of the Corporation–s previous investment in Belize Electricity, including foreign exchange impacts, which was approximately $104 million as at March 31, 2012.
Risk Management: The Corporation–s earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above exposure through the use of US dollar borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange loss or gain on the translation of the Corporation–s foreign subsidiaries– earnings, which are denominated in US dollars. The reporting currency of Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy Corporation and BECOL is the US dollar. Belize Electricity–s financial results were denominated in Belizean dollars, which are pegged to the US dollar.
As at March 31, 2012, the Corporation–s corporately issued US$550 million (December 31, 2011 – US$550 million) long-term debt had been designated as an effective hedge of the Corporation–s foreign net investments. As at March 31, 2012, the Corporation had approximately US$8 million (December 31, 2011 – US$6 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation–s corporately issued US dollar borrowings designated as effective hedges are recorded in other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which are also recorded in other comprehensive income.
Effective June 20, 2011, the Corporation–s asset associated with its previous investment in Belize Electricity does not qualify for hedge accounting as Belize Electricity is no longer a foreign subsidiary of Fortis. As a result, during 2011, a portion of corporately issued debt that previously hedged the former investment in Belize Electricity was no longer an effective hedge. Effective from June 20, 2011, foreign exchange gains and losses on the translation of the asset associated with Belize Electricity and the corporately issued US dollar-denominated debt that previously qualified as a hedge of the investment were recognized in earnings. As a result, the Corporation recognized a foreign exchange loss of approximately $1.5 million in earnings during the first quarter of 2012.
From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and fuel and natural gas prices through the use of derivative financial instruments. The Corporation and its subsidiaries do not hold or issue derivative financial instruments for trading purposes. As at March 31, 2012, the Corporation–s derivative contracts consisted of a foreign exchange forward contract, natural gas swap and option contracts, and gas purchase contract premiums, all held by the FortisBC Energy companies.
The following table summarizes the Corporation–s derivative financial instruments.
The foreign exchange forward contract is held by FEI to hedge the cash flow risk related to approximately US$4 million remaining to be paid under a contract for the implementation of a customer information system.
The fuel option contracts were held by Caribbean Utilities to reduce the impact of volatility in fuel prices on customer rates, as approved by the regulator under the Company–s Fuel Price Volatility Management Program. The fuel option contracts matured in March 2012.
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, to temper gas price volatility on customer rates and to reduce the risk of regional price discrepancies. As directed by the BCUC, FEI and FEVI suspended their commodity hedging activities in 2011, which has continued into 2012, with the exception of certain limited swaps. The existing hedging contracts will continue in effect through to their maturity and the FortisBC Energy companies– ability to fully recover the commodity cost of gas in customer rates remains unchanged.
The changes in the fair values of the foreign exchange forward contract 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 March 31, 2012 and as at December 31, 2011.
The fair value of the foreign exchange forward contract is calculated using the present value of cash flows based on a market foreign exchange rate and the foreign exchange forward rate curve. The fair value of the natural gas derivatives is calculated using the present value of cash flows based on market prices and forward curves for the commodity cost of natural gas. The fair values of the foreign exchange forward contract 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 $66 million, as at March 31, 2012, the Corporation had no off-balance sheet arrangements, such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities, that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
There were no changes in the Corporation–s significant business risks during the first quarter of 2012 from those disclosed in the 2011 Annual MD&A, except for those described below.
Regulatory Risk: In April 2012 regulatory decisions received for 2012 and 2013 customer gas delivery rates at the FortisBC Energy companies and for 2012 customer electricity distribution rates at FortisAlberta help to reduce regulatory risk at the utilities. For further information, refer to the “Material Regulatory Decisions and Applications” section of this MD&A.
Completion of the Acquisition of CH Energy Group: There is risk that some, or all, of the expected benefits of the acquisition of CH Energy Group may fail to materialize or may not occur within the time periods anticipated by the Corporation. The realization of such benefits may be impacted by a number of factors, many of which are beyond the control of Fortis.
Capital Resources and Liquidity Risk – Credit Ratings: In February 2012, after the announcement by Fortis that it had entered into an agreement to acquire all of the shares of CH Energy Group, DBRS placed the Corporation–s credit rating under review with developing implications. Similarly, S&P placed the Corporation–s credit rating on credit watch with negative implications. FortisAlberta–s existing debt credit rating by S&P was confirmed in January 2012, but was put on credit watch with negative implications in February 2012 as a result of the Corporation–s credit rating being placed on credit watch. During the first quarter of 2012, DBRS confirmed FortisAlberta and Newfoundland Power–s existing debt credit ratings, and both DBRS and S&P confirmed Caribbean Utilities– debt credit ratings.
Defined Benefit Pension Plan Assets: As at March 31, 2012, the fair value of the Corporation–s consolidated defined benefit pension plan assets was $821 million, up $36 million or 4.6%, from $785 million as at December 31, 2011.
Labour Relations: The collective agreement between FortisBC Electric and the Canadian Office and Professional Employees Union (“COPE”), Local 378, expired January 31, 2011. An agreement expiring in March 2014 has been reached with regard to certain customer service employees. Discussions continue with regard to the remaining FortisBC Electric COPE bargaining unit.
The collective agreements between the FortisBC Energy companies and the International Brotherhood of Electrical Workers (“IBEW”), Local 213, expired on March 31, 2011. IBEW, Local 213, represents employees in specified occupations in the areas of T&D. The parties are negotiating terms of a renewed collective agreement.
The collective agreements between the FortisBC Energy companies and COPE, Local 378, expired on March 31, 2012. COPE, Local 378, represents employees in specified occupations in the areas of administration and operations support. The parties are negotiating the terms of a renewed collective agreement.
The two collective agreements between Newfoundland Power and IBEW, Local 1620, expired on September 30, 2011. During the first quarter of 2012, one of the two newly negotiated collective agreements was ratified. The other collective agreement was not accepted and is now subject to ratification in May 2012. The agreements are for three-year terms expiring in September 2014.
CHANGES IN ACCOUNTING POLICIES
Transition to US GAAP: Effective January 1, 2012, Fortis retroactively adopted US GAAP with the restatement of comparative reporting periods. The areas of most significant financial statement impacts upon adopting US GAAP include, but are not limited to the: (i) recognition of the funded status of defined benefit pension plans on the consolidated balance sheet and the inability to recognize regulatory assets or liabilities associated with other post-employment benefit (“OPEB”) costs that are recovered on a cash basis; (ii) recognition of the Brilliant Power Purchase Agreement as a capital lease at FortisBC Electric; (iii) recognition of lease-in lease-out transactions at the FortisBC Energy companies as financing transactions with the corresponding assets recognized as utility capital assets and the sales proceeds accounted for as long-term debt; (iv) reclassification of preference shares from long-term liabilities to shareholders– equity; and (v) the calculation and recognition of income taxes based on enacted versus substantially enacted income tax rates.
The above-noted items do not represent a complete list of differences between US GAAP and Canadian GAAP. Other less significant differences have also been identified and accounted for. A detailed description of the differences and a detailed reconciliation between the Corporation–s annual audited consolidated Canadian GAAP and annual audited consolidated US GAAP financial statements for 2011 is disclosed in Note 38 to the Corporation–s voluntarily filed annual audited consolidated US GAAP financial statements with accompanying notes thereto for the year ended December 31, 2011, with 2010 comparatives. A detailed reconciliation between the Corporation–s interim unaudited consolidated 2011 Canadian GAAP and interim unaudited consolidated 2011 US GAAP financial statements is provided in the above-noted voluntarily filed document under the section “Supplemental Interim Consolidated Financial Statements for the Year Ended December 31, 2011 (Unaudited)”.
The audited quantification and reconciliation of the Corporation–s consolidated balance sheet as at December 31, 2011, prepared in accordance with US GAAP versus Canadian GAAP, may be summarized as follows.
There were no material adjustments to the Corporation–s consolidated 2011 earnings under US GAAP due to the Corporation–s continued ability to apply rate-regulated accounting policies.
The unaudited quantification and reconciliation of the Corporation–s consolidated statement of earnings for the three months ended March 31, 2011, prepared in accordance with US GAAP versus Canadian GAAP, may be summarized as follows:
Changes in Accounting Policies: Effective January 1, 2012, the FortisBC Energy companies prospectively adopted the policy of accruing for non-ARO removal costs in depreciation expense, as requested in their 2012-2013 RRAs and subsequently approved by the BCUC in its April 2012 rate decision. The accrual of estimated non-ARO removal costs is included in depreciation expense and the provision balance is recognized as a long-term regulatory liability. Actual non-ARO removal costs, net of salvage proceeds, are recorded against the regulatory liability when incurred. Non-ARO removal costs are direct costs incurred by the FortisBC Energy companies in taking assets out of service, whether through actual removal of the assets or through disconnection of the assets from the transmission or distribution system. Prior to 2012 non-ARO removal costs, net of salvage proceeds, were recognized in operating expenses as incurred with variances between actual non-ARO removal costs and those forecast for rate-setting purposes recorded in a regulatory deferral account for future recovery from, or refund to, customers in rates commencing in 2012. During the first quarter of 2012, $4 million of non-ARO removal costs were accrued as a part of depreciation expense. During the first quarter of 2011, $3 million of non-ARO removal costs were recognized in operating expenses.
Prior to 2012 variances from forecast, adjusted for certain revenue and cost variances which flowed through to customers, for rate-setting purposes were shared equally between customers and FortisBC Electric. Prospectively from January 1, 2012, the above sharing of positive or negative variances is no longer in effect pursuant to the utility–s filed 2012-2013 RRA, which is subject to BCUC approval and reflects a COS rate-setting methodology. Beginning in 2012 variances from forecast for rate-setting purposes related to electricity revenue, purchased power costs and certain other costs, are subject to full deferral account treatment, to be recovered from, or refunded to, customers in future rates and, therefore, are not subject to the sharing mechanism that existed prior to 2012 and do not impact earnings in 2012.
New US GAAP Accounting Pronouncements: The following new US GAAP accounting pronouncements that are applicable to, and were adopted by, Fortis effective January 1, 2012 are described as follows:
Presentation of Comprehensive Income
The Corporation adopted the amendments to Accounting Standards Codification (“ASC”) Topic 220, Comprehensive Income. The amended standard requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. Fortis continues to report the components of comprehensive income in a separate but consecutive statement.
Testing Goodwill for Impairment
The Corporation has prospectively adopted the amendments to ASC Topic 350, Goodwill. The amended standard allows entities testing goodwill for impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. If the qualitative factors indicate that the fair value of the reporting unit is more likely than not (greater than a 50% chance) to be greater than the carrying value, then the two-step impairment test, including the quantification of the fair value of the reporting unit, would not be required. In adopting the amendments, Fortis will perform a qualitative assessment before calculating the fair value of its reporting units when it performs its annual impairment test on October 1.
Fair Value Measurement
The Corporation adopted the amendments to ASC Topic 820, Fair Value Measurements and Disclosures. The amended standard improves comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with US GAAP. The amendment does not change what items are measured at fair value but instead makes various changes to the guidance pertaining to how fair value is measured. The above-noted changes did not materially impact the Corporation–s consolidated financial statements for the three months ende