ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwire - May 2, 2012) - 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.
| Interim Management Discussion and Analysis |
| For the three months ended March 31, 2012 |
| Dated May 2, 2012 |
FORWARD-LOOKING STATEMENT
The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. Financial information for 2012 and comparative periods contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") and is presented in Canadian dollars unless otherwise specified. The MD&A should be read in conjunction with the following: (i) the interim unaudited consolidated financial statements and notes thereto for the three 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.
| Consolidated Financial Highlights (Unaudited) | Quarter Ended March 31 | |||||
| ($ millions, except for common share data) | 2012 | 2011 | Variance | |||
| Revenue | 1,149 | 1,159 | (10 | ) | ||
| Energy Supply Costs | 566 | 603 | (37 | ) | ||
| Operating Expenses | 214 | 210 | 4 | |||
| Depreciation and Amortization | 119 | 103 | 16 | |||
| Other Income (Expenses), Net | (3 | ) | 8 | (11 | ) | |
| Finance Charges | 91 | 92 | (1 | ) | ||
| Income Taxes | 23 | 31 | (8 | ) | ||
| Net Earnings | 133 | 128 | 5 | |||
| Net Earnings Attributable to: | ||||||
| Non-Controlling Interests | 1 | 1 | - | |||
| Preference Equity Shareholders | 11 | 11 | - | |||
| Common Equity Shareholders | 121 | 116 | 5 | |||
| Net Earnings | 133 | 128 | 5 | |||
| Basic Earnings per Common Share ($) | 0.64 | 0.66 | (0.02 | ) | ||
| Diluted Earnings per Common Share ($) | 0.62 | 0.64 | (0.02 | ) | ||
| Weighted Average Number of Common Shares Outstanding (# millions) | 189.0 | 175.0 | 14.0 | |||
| Cash Flow from Operating Activities | 328 | 302 | 26 | |||
Factors Contributing to Revenue Variance
Unfavourable
- Lower commodity cost of natural gas charged to customers
- The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011
- Lower average gas consumption by residential and commercial customers, partially offset by higher gas transportation volumes to the forestry and mining sectors
Favourable
- An increase in gas delivery rates and the base component of electricity rates at the regulated utilities in western Canada, consistent with interim rate decisions, reflecting ongoing investment in energy infrastructure and forecasted higher expenses recoverable from customers
- Growth in the number of customers, driven by FortisAlberta, and higher average electricity consumption at most of the regulated electric utilities
- The flow through in customer electricity rates of overall higher energy supply costs, driven by Caribbean Utilities
- Increased non-regulated hydroelectric production in Belize, due to higher rainfall
- Higher Hospitality revenue at Fortis Properties, driven by contribution from the Hilton Suites Winnipeg Airport hotel, which was acquired in October 2011
Factors Contributing to Energy Supply Costs Variance
Favourable
- Lower commodity cost of natural gas
- The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011
- Lower average gas consumption
- Lower purchased power costs at Maritime Electric
Unfavourable
- Increased fuel prices at Caribbean Utilities and purchased power costs at FortisBC Electric
- Higher electricity sales
Factors Contributing to Operating Expenses Variance
Unfavourable
- General inflationary and employee-related cost increases at the Corporation's regulated utilities and timing of expenditures at FortisBC Electric
- Operating expenses associated with the Hilton Suites Winnipeg Airport hotel, which was acquired in October 2011
Favourable
- Lower operating expenses at the FortisBC Energy companies, mainly due to the accrual of non-asset retirement obligation ("non-ARO") removal costs in depreciation, effective January 1, 2012, and lower customer care-related costs as a result of insourcing the customer care function, effective January 1, 2012
- The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011
Factors Contributing to Depreciation and Amortization Costs Variance
Unfavourable
- Continued investment in energy infrastructure
- Increased depreciation at the FortisBC Energy companies, mainly due to the accrual of non-ARO removal costs in depreciation, effective January 1, 2012, as discussed above
Favourable
- The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011
Factors Contributing to Other Income (Expenses), Net Variance
Unfavourable
- Approximately $4 million of costs incurred in the first quarter of 2012 related to the pending acquisition of CH Energy Group
- Lower capitalized equity component of allowance for funds used during construction ("AFUDC"), mainly at the FortisBC Energy companies and FortisBC Electric
- An approximate $1.5 million foreign exchange loss associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's former investment in Belize Electricity
- An approximate $1 million gain on the sale of property at FortisAlberta during the first quarter of 2011
Factors Contributing to Finance Charges Variance
Favourable
- Higher capitalized interest associated with the financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion hydroelectric generating facility ("Waneta Expansion")
- Lower corporate credit facility borrowings, due to the repayment of borrowings during the third quarter of 2011 with a portion of the proceeds from the public common equity offering in mid-2011
- The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011
- Lower short-term borrowings at the regulated utilities
Unfavourable
- Higher long-term debt levels in support of the utilities' capital expenditure programs
- Lower capitalized debt component of AFUDC mainly at the FortisBC Energy companies and FortisBC Electric
Factors Contributing to Income Taxes Variance
Favourable
- Lower statutory income tax rates
- Lower earnings before income taxes
- Higher deductions for income tax purposes compared to accounting purposes
Factors Contributing to Earnings Variance
Favourable
- Increased earnings at the FortisBC Energy companies, mainly due to seasonality of gas consumption and the timing of certain expenses in 2012, combined with growth in energy infrastructure investment and higher gas transportation volumes to the forestry and mining sectors. The increase was partially offset by lower-than-expected customer additions and lower capitalized AFUDC.
- Increased non-regulated hydroelectric production in Belize, due to higher rainfall
- Higher earnings at Newfoundland Power and Maritime Electric, mainly due to increased electricity sales and lower effective corporate income taxes
Unfavourable
- The expiry of the performance-based rate-setting ("PBR") mechanism on December 31, 2011 at FortisBC Electric and the timing of certain operating expenses at the utility in 2012
- Higher corporate expenses due to approximately $4 million of costs incurred in the first quarter of 2012 related to the pending acquisition of CH Energy Group and a $1.5 million foreign exchange loss, partially offset by lower finance charges
- An approximate $1 million gain on the sale of property at FortisAlberta during the first quarter of 2011
SEGMENTED RESULTS OF OPERATIONS
| Segmented Net Earnings Attributable to Common Equity Shareholders | |||||||
| (Unaudited) | Quarter Ended March 31 | ||||||
| ($ millions) | 2012 | 2011 | Variance | ||||
| Regulated Gas Utilities - Canadian | |||||||
| FortisBC Energy Companies | 82 | 75 | 7 | ||||
| Regulated Electric Utilities - Canadian | |||||||
| FortisAlberta | 21 | 21 | - | ||||
| FortisBC Electric | 16 | 19 | (3 | ) | |||
| Newfoundland Power | 7 | 6 | 1 | ||||
| Other Canadian Electric Utilities | 7 | 6 | 1 | ||||
| 51 | 52 | (1 | ) | ||||
| Regulated Electric Utilities - Caribbean | 3 | 4 | (1 | ) | |||
| Non-Regulated - Fortis Generation | 5 | 3 | 2 | ||||
| Non-Regulated - Fortis Properties | 1 | 1 | - | ||||
| Corporate and Other | (21 | ) | (19 | ) | (2 | ) | |
| Net Earnings Attributable to Common Equity Shareholders | 121 | 116 | 5 | ||||
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Corporation's regulated utilities, refer to the "Regulatory Highlights" section of this MD&A. A discussion of the financial results of the Corporation's reporting segments is as follows.
REGULATED GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES(1)
| Gas Volumes by Major Customer Category (Unaudited) |
Quarter Ended March 31 | ||||
| (TJ) | 2012 | 2011 | Variance | ||
| Core - Residential and Commercial | 48,532 | 50,448 | (1,916 | ) | |
| Industrial | 1,771 | 1,888 | (117 | ) | |
| Total Sales Volumes | 50,303 | 52,336 | (2,033 | ) | |
| Transportation Volumes | 21,469 | 20,484 | 985 | ||
| Throughput under Fixed Revenue Contracts | 607 | 476 | 131 | ||
| Total Gas Volumes | 72,379 | 73,296 | (917 | ) | |
| (1) | Includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI") |
Factors Contributing to Gas Volumes Variances
Unfavourable
- Lower average gas consumption by residential and commercial customers as a result of overall warmer temperatures
Favourable
- Higher gas transportation volumes reflecting improved economic conditions favourably affecting the forestry and mining sectors
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.
| Financial Highlights (Unaudited) | Quarter Ended March 31 | |||
| ($ millions) | 2012 | 2011 | Variance | |
| Revenue | 548 | 574 | (26 | ) |
| Earnings | 82 | 75 | 7 | |
Factors Contributing to Revenue Variance
Unfavourable
- Lower commodity cost of natural gas charged to customers
- Lower average gas consumption by residential and commercial customers
Favourable
- An interim increase in the delivery component of customer rates, mainly due to ongoing investment in energy infrastructure and forecasted higher expenses recoverable from customers. A decision on 2012 and 2013 customer delivery rates was received by the FortisBC Energy companies in April 2012.
- Higher gas transportation volumes to the forestry and mining sectors
Factors Contributing to Earnings Variance
Favourable
- The seasonality of gas consumption and the timing of certain expenses in 2012. Revenue is recognized based on seasonal gas consumption while certain operating expenses, as well as depreciation, are generally incurred evenly throughout the year.
- Rate base growth, due to continued investment in energy infrastructure
- Higher gas transportation volumes to the forestry and mining sectors
Unfavourable
- Lower-than-expected customer additions in the first quarter of 2012
- Lower capitalized AFUDC, due to a lower asset base under construction during the first quarter of 2012
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
| Financial Highlights (Unaudited) | Quarter Ended March 31 | ||
| 2012 | 2011 | Variance | |
| Energy Deliveries (gigawatt hours ("GWh")) | 4,482 | 4,402 | 80 |
| Revenue ($ millions) | 108 | 100 | 8 |
| Earnings ($ millions) | 21 | 21 | - |
Factors Contributing to Energy Deliveries Variance
Favourable
- Growth in the number of customers, with the total number of customers increasing by approximately 8,000 quarter over quarter, driven by favourable economic conditions
- Higher average consumption by the oilfield sector, due to increased activity mainly as a result of high market prices for oil
Unfavourable
- Lower average consumption by residential customers due to warmer-than-average temperatures during the first quarter of 2012
As a significant portion of FortisAlberta's distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.
Factors Contributing to Revenue Variance
Favourable
- An interim increase in customer electricity distribution rates, effective January 1, 2012, reflecting the parameters of the Negotiated Settlement Agreement ("NSA") filed by FortisAlberta in November 2011 for 2012 rates. The interim rate increase was driven primarily by ongoing investment in energy infrastructure and forecasted higher expenses recoverable from customers. A decision on the NSA was received in April 2012 approving the interim increase in customer rates as final.
- Growth in the number of customers
Unfavourable
- A lower allowed ROE quarter over quarter. The cumulative impact on revenue, from January 1, 2011, of the decrease in the allowed ROE to 8.75%, effective for both 2011 and 2012, from 9.00% for 2010 was recognized during the fourth quarter of 2011, when the regulatory decision was received.
Factors Contributing to Earnings Variance
Favourable
- Rate base growth, due to continued investment in energy infrastructure
Unfavourable
- An approximate $1 million gain on the sale of property during the first quarter of 2011
- Lower-than-expected number of customers and lower-than-expected energy consumption by residential customers in the first quarter of 2012
- A lower allowed ROE quarter over quarter
FORTISBC ELECTRIC(1)
| Financial Highlights (Unaudited) | Quarter Ended March 31 | |||
| 2012 | 2011 | Variance | ||
| Electricity Sales (GWh) | 909 | 905 | 4 | |
| Revenue ($ millions) | 87 | 83 | 4 | |
| Earnings ($ millions) | 16 | 19 | (3 | ) |
| (1) | Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants and the distribution system owned by the City of Kelowna. Excludes the non-regulated generation operations of FortisBC Inc.'s wholly owned partnership, Walden Power Partnership |
Factor Contributing to Electricity Sales Variance
Favourable
- Growth in the number of customers
Factors Contributing to Revenue Variance
Favourable
- An interim, refundable increase in customer electricity rates, effective January 1, 2012, mainly reflecting ongoing investment in energy infrastructure and forecasted higher expenses recoverable from customers
- A 1.4% increase in customer electricity rates, effective June 1, 2011, as a result of the flow through to customers of increased purchased power costs charged to FortisBC Electric by BC Hydro
- The 0.4% increase in electricity sales
Factors Contributing to Earnings Variance
Unfavourable
- The expiry of the PBR mechanism on December 31, 2011. During the first quarter of 2011, lower-than-expected costs, primarily purchased power costs, were shared equally between customers and FortisBC Electric under the PBR mechanism. Pursuant to the Company's 2012-2013 Revenue Requirements Application ("RRA"), which is subject to regulatory approval, variances between actual purchased power costs and certain other costs and those used to set customer electricity rates are subject to full deferral account treatment and, therefore, did not impact FortisBC Electric's earnings for the first quarter of 2012.
- Increased operating expenses due to the timing of expenditures in 2012
- Lower capitalized AFUDC due to a lower asset base under construction during the first quarter of 2012
Favourable
- Rate base growth, due to continued investment in energy infrastructure
NEWFOUNDLAND POWER
| Financial Highlights (Unaudited) | Quarter Ended March 31 | ||
| 2012 | 2011 | Variance | |
| Electricity Sales (GWh) | 1,914 | 1,834 | 80 |
| Revenue ($ millions) | 192 | 183 | 9 |
| Earnings ($ millions) | 7 | 6 | 1 |
Factors Contributing to Electricity Sales Variance
Favourable
- Growth in the number of customers
- Higher average consumption, reflecting the higher concentration of electric-versus-oil heating in new home construction combined with economic growth
Factors Contributing to Revenue Variance
Favourable
- The 4.4% increase in electricity sales
Unfavourable
- Revenue during the first quarter of 2011 included amounts related to support structure arrangements, which were in place with Bell Aliant Inc. ("Bell Aliant") during 2011, associated with the joint-use poles held for sale to Bell Aliant. The joint-use poles were sold in October 2011.
Factors Contributing to Earnings Variance
Favourable
- Electricity sales growth
- Lower effective corporate income taxes, primarily due to a lower allocation of Part VI.1 tax to Newfoundland Power and a lower statutory income tax rate
Unfavourable
- The impact of the support structure arrangements with Bell Aliant during 2011, as discussed above
OTHER CANADIAN ELECTRIC UTILITIES(1)
| Financial Highlights (Unaudited) | Quarter Ended March 31 | |||
| 2012 | 2011 | Variance | ||
| Electricity Sales (GWh) | 645 | 654 | (9 | ) |
| Revenue ($ millions) | 91 | 91 | - | |
| Earnings ($ millions) | 7 | 6 | 1 | |
| (1) | Includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and Algoma Power. |
Factors Contributing to Electricity Sales Variance
Unfavourable
- Lower average consumption by residential and industrial customers in Ontario, reflecting more moderate temperatures and weakened economic conditions in the region
Favourable
- Growth in the number of residential customers and an increase in the number of residential customers using electricity for home heating on Prince Edward Island ("PEI")
- Higher average consumption by commercial customers in the agricultural processing sector on PEI
Factors Contributing to Revenue Variance
Favourable
- The flow through in customer electricity rates of higher energy supply costs at FortisOntario
- Increased electricity sales on PEI, for the reason discussed above
Unfavourable
- Lower basic component of customer rates at Maritime Electric, effective March 1, 2011, associated with the recovery of energy supply costs
- Decreased electricity sales in Ontario, for the reason discussed above
Factors Contributing to Earnings Variance
Favourable
- Lower effective corporate income taxes, primarily due to higher deductions taken for income tax purposes compared to accounting purposes and lower statutory income tax rates
- Increased electricity sales on PEI
REGULATED ELECTRIC UTILITIES - CARIBBEAN(1)
| Financial Highlights (Unaudited) | Quarter Ended March 31 | |||
| 2012 | 2011 | Variance | ||
| Average US:CDN Exchange Rate(2) | 1.00 | 0.99 | 0.01 | |
| Electricity Sales (GWh) | 166 | 257 | (91 | ) |
| Revenue ($ millions) | 63 | 75 | (12 | ) |
| Earnings ($ millions) | 3 | 4 | (1 | ) |
| (1) | Includes Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 60% controlling interest; wholly owned Fortis Turks and Caicos; and the financial results of the Corporation's approximate 70% controlling interest in Belize Electricity up to June 20, 2011. Effective June 20, 2011, the Government of Belize expropriated the Corporation's investment in Belize Electricity. As a result of no longer controlling the operations of the utility, Fortis discontinued the consolidation method of accounting for Belize Electricity, effective June 20, 2011. For further information, refer to the "Key Trends and Risks - Expropriated Assets" and "Business Risk Management - Investment in Belize" sections of the 2011 Annual MD&A. |
| (2) | The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00. |
Factors Contributing to Electricity Sales Variance
Unfavourable
- The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011. Excluding Belize Electricity, electricity sales increased approximately 1.7% quarter over quarter.
- Cooler temperatures and higher rainfall experienced on Grand Cayman, which decreased air conditioning load
Favourable
- Growth in the number of customers in Grand Cayman and the Turks and Caicos Islands
- Warmer temperatures experienced in the Turks and Caicos Islands, which increased air conditioning load
Factors Contributing to Revenue Variance
Unfavourable
- The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for Belize Electricity, effective June 20, 2011
Favourable
- The flow through in customer electricity rates of higher energy supply costs at Caribbean Utilities, due to an increase in the cost of fuel
- Higher electricity sales, excluding Belize Electricity
Factors Contributing to Earnings Variance
Unfavourable
- Higher depreciation expense and finance charges, excluding Belize Electricity, largely due to investment in utility capital assets
- Increased operating expenses, excluding Belize Electricity, mainly associated with higher insurance expense and employee-related costs at Caribbean Utilities and the timing of capital projects at Fortis Turks and Caicos
Favourable
- Higher electricity sales, excluding Belize Electricity
- Lower energy supply costs at Fortis Turks and Caicos, mainly due to more fuel-efficient production realized with the commissioning of new generation units at the utility
NON-REGULATED - FORTIS GENERATION(1)
| Financial Highlights (Unaudited) | Quarter Ended March 31 | ||
| 2012 | 2011 | Variance | |
| Energy Sales (GWh) | 88 | 76 | 12 |
| Revenue ($ millions) | 9 | 7 | 2 |
| Earnings ($ millions) | 5 | 3 | 2 |
| (1) | Includes the financial results of non-regulated generation assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New York State, with a combined generating capacity of 139 MW, mainly hydroelectric |
Factors Contributing to Energy Sales Variance
Favourable
- Increased production in Belize, due to higher rainfall
Unfavourable
- Decreased production in Upper New York State, due to a generating facility being out of service
Factor Contributing to Revenue and Earnings Variances
Favourable
- Increased production in Belize
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)
| Financial Highlights (Unaudited) | Quarter Ended March 31 | ||||
| 2012 | 2011 | Variance | |||
| Hospitality - Revenue per Available Room ("RevPAR") ($) | 66.54 | 63.29 | 3.25 | ||
| Real Estate - Occupancy Rate (as at, %) | 92.2 | 94.3 | (2.1 | ) | |
| Hospitality Revenue ($ millions) | 35 | 33 | 2 | ||
| Real Estate Revenue ($ millions) | 17 | 17 | - | ||
| Total Revenue ($ millions) | 52 | 50 | 2 | ||
| Earnings ($ millions) | 1 | 1 | - | ||
| (1) | Fortis Properties owns and operates 22 hotels, collectively representing 4,300 rooms, in eight Canadian provinces and approximately 2.7 million square feet of commercial office and retail space primarily in Atlantic Canada. |
Factors Contributing to Revenue Variance
Favourable
- A 5.1% increase in RevPAR at the Hospitality Division, driven by contribution from the Hilton Suites Winnipeg Airport hotel, which was acquired in October 2011
- Excluding the impact of the Hilton Suites Winnipeg Airport hotel, RevPAR was $64.85 for the first quarter of 2012, an increase of 2.5% quarter over quarter. RevPAR increased due to an overall 3.1% increase in the average daily room rate, partially offset by an overall 0.6% decrease in hotel occupancy. The average daily room rate increased in all regions. Hotel occupancy in Atlantic Canada and central Canada decreased, while occupancy in western Canada increased.
Factors Contributing to Earnings Variance
Favourable
- Contribution from the Hilton Suites Winnipeg Airport hotel
Unfavourable
- A $0.5 million gain on the sale of the Viking Mall during the first quarter of 2011
CORPORATE AND OTHER(1)
| Financial Highlights (Unaudited) | Quarter Ended March 31 | ||
| ($ millions) | 2012 | 2011 | Variance |
| Revenue | 6 | 6 | - |
| Operating Expenses | 3 | 2 | 1 |
| Depreciation and Amortization | 1 | 1 | - |
| Other Income (Expenses), Net | (5) | - | (5) |
| Finance Charges | 11 | 14 | (3) |
| Income Tax Recovery | (4) | (3) | (1) |
| (10) | (8) | (2) | |
| Preference Share Dividends | 11 | 11 | - |
| Net Corporate and Other Expenses | (21) | (19) | (2) |
| (1) | Includes Fortis net corporate expenses, net expenses of non-regulated FortisBC Holdings Inc. ("FHI") corporate-related activities and the financial results of FHI's non-regulated wholly owned subsidiary FortisBC Alternative Energy Services Inc. and FHI's 30% ownership interest in CustomerWorks Limited Partnership ("CWLP"). The contracts between CWLP and the FortisBC Energy companies ended on December 31, 2011. |
Factors Contributing to Net Corporate and Other Expenses Variance
Unfavourable
- Increased other expenses, net of other income, driven by approximately $4 million of costs incurred in the first quarter of 2012 related to the pending acquisition of CH Energy Group and an approximate $1.5 million foreign exchange loss associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's former investment in Belize Electricity
Favourable
- Lower finance charges primarily due to: (i) higher capitalized interest associated with the financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion; (ii) lower credit facility borrowings due to the repayment of borrowings during the third quarter of 2011 with a portion of the proceeds from the public common equity offering in mid-2011; and (iii) the conversion of the Corporation's US$40 million unsecured convertible subordinated debentures into common shares in November 2011
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.
| NATURE OF REGULATION | ||||||
| Allowed Returns (%) | Supportive Features | |||||
| Regulated Utility |
Regulatory Authority |
Allowed Common Equity (%) |
2010 | 2011 | 2012 | Future or Historical Test Year Used to Set Customer Rates |
| ROE | COS/ROE | |||||
| FEI | British Columbia Utilities Commission ("BCUC") |
40 |
9.50 |
9.50 |
9.50 |
FEI: Prior to January 1, 2010, 50/50 sharing of earnings above or below the allowed ROE under a PBR mechanism that expired on December 31, 2009 with a two-year phase-out |
| FEVI | BCUC | 40 |
10.00 |
10.00 |
10.00 |
|
| FEWI | BCUC | 40 |
10.00 |
10.00 |
10.00 |
ROEs established by the BCUC |
| Future Test Year | ||||||
| FortisBC Electric |
BCUC |
40 |
9.90 |
9.90 |
9.90 |
COS/ROE |
| |
|
|
|
|
|
PBR mechanism for 2009 through 2011: 50/50 sharing of earnings above or below the allowed ROE up to an achieved ROE that is 200 basis points above or below the allowed ROE - excess to deferral account ROE established by the BCUC |
| Future Test Year | ||||||
| Fortis- Alberta |
Alberta Utilities Commission |
41 |
9.00 |
8.75 |
8.75 |
COS/ROE |
| ("AUC") | ROE established by the AUC | |||||
| Future Test Year | ||||||
| Newfound- land Power |
Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB") |
45 |
9.00 +/- 50 bps |
8.38 +/- 50 bps |
8.38 +/-(1) 50 bps |
COS/ROE The allowed ROE is set using an automatic adjustment formula tied to long-term Canada bond yields. The formula has been suspended for 2012. |
| Future Test Year | ||||||
| Maritime Electric |
Island Regulatory and Appeals Commission ("IRAC") |
40 |
9.75 |
9.75 |
9.75 |
COS/ROE |
| Future Test Year | ||||||
| Fortis- Ontario Electric |
Ontario Energy Board ("OEB") |
|
|
|
|
Canadian Niagara Power - COS/ROE |
| |
Canadian Niagara Power |
40 |
8.01 |
8.01 |
8.01(2) |
Algoma Power - COS/ROE and subject to Rural and Remote Rate Protection ("RRRP") Program |
| |
Algoma Power |
40 |
8.57 |
9.85 |
9.85(2) |
|
| Franchise Agreement Cornwall Electric |
Cornwall Electric - Price cap with commodity cost flow through |
|||||
| |
|
|
|
|
|
Canadian Niagara Power - 2009 historical test year for 2010, 2011 and 2012 Algoma Power - 2007 historical test year for 2010; 2011 test year for 2011 and 2012 |
| Caribbean Utilities |
Electricity Regulatory Authority ("ERA") |
N/A |
7.75 - 9.75 |
7.75 - 9.75 |
7.25 - 9.25 |
COS/ROA Rate-cap adjustment mechanism ("RCAM") based on published consumer price indices |
| |
|
|
|
|
|
The Company may apply for a special additional rate to customers in the event of a disaster, including a hurricane. |
| Historical Test Year | ||||||
| Fortis Turks and Caicos |
Utilities make annual filings to the Interim Government of the Turks and Caicos Caicos Islands ("Interim Government") |
N/A | 17.50(3) | 17.50(3) | 17.50(3) | COS/ROA |
| If the actual ROA is lower than the allowed ROA, due to additional costs resulting from a hurricane or other event, the Company may apply for an increase in customer rates in the following year. | ||||||
| Future Test Year | ||||||
| (1) | Interim, pending the review of Newfoundland Power's cost of capital in 2012 by the PUB |
| (2) | Based on the ROE automatic adjustment formula, the allowed ROE for electric utilities in Ontario is 9.12% for utilities with rates effective May 1, 2012. This ROE is not applicable to regulated electric utilities in Ontario until they are scheduled to file their next full COS rate applications. As a result, the allowed ROE of 9.12% is not applicable to Canadian Niagara Power or Algoma Power for 2012. |
| (3) | Amount provided under licence. ROA achieved in 2010 and 2011 was significantly lower than the ROA allowed under the licence due to significant investment occurring at the utility and the lack of rate relief thereto. |
| MATERIAL REGULATORY DECISIONS AND APPLICATIONS | |
| Regulated Utility | Summary Description |
| FEI/FEVI/FEWI | - FEI and FEWI review with the BCUC natural gas and propane commodity prices every three months and midstream costs annually, in order to ensure the flow-through rates charged to customers are sufficient to cover the cost of purchasing natural gas and propane and contracting for midstream resources, such as third-party pipeline and/or storage capacity. The commodity cost of natural gas and propane and midstream costs are flowed through to customers without markup. The bundled rate charged to FEVI customers includes a component to recover approved gas costs and is set annually. In order to ensure that the balance in the Commodity Cost Reconciliation Account is recovered on a timely basis, FEI and FEWI prepare and file quarterly calculations with the BCUC to determine whether customer rate adjustments are needed to reflect prevailing market prices for natural gas. These rate adjustments ignore the temporal effect of derivative valuation adjustments on the balance sheet and, instead, reflect the forward forecast of gas costs over the recovery period. - Effective January 1, 2012, interim rates for residential customers in the Lower Mainland, Fraser Valley and Interior, North and Kootenay service areas increased by approximately 3% and interim rates for FEWI's residential customers increased by approximately 6%, reflecting changes in delivery and midstream costs. Interim approval was also received to hold FEVI customer rates at 2011 levels, effective January 1, 2012. Natural gas commodity rates were unchanged, effective January 1, 2012. - Effective April 1, 2012, due to a decrease in natural gas commodity rates, rates for residential customers in the Lower Mainland, Fraser Valley and Interior, North and Kootenay service areas decreased by approximately 10% and rates for residential customers at FEWI decreased approximately 6%, following the BCUC's quarterly review of commodity costs. - In July 2011 FEVI received a BCUC decision approving the option for two First Nations bands to invest up to a combined 15% in the equity component of the capital structure of the liquefied natural gas ("LNG") storage facility on Vancouver Island. In late 2011 each band exercised its option and each invested approximately $6 million in equity in the LNG storage facility on January 1, 2012. |
| - In October 2011 FEI filed an application for approval of expenditures of approximately $5 million on facilities required to provide thermal energy services to 19 buildings in the Delta School District located in the Greater Vancouver area and to provide thermal energy upgrades to the buildings over the next two years. When completed, FEI will own, operate and maintain the new thermal plants and charge the Delta School District a single rate for thermal energy consumed. In March 2012 the BCUC issued its decision granting FEI a Certificate of Public Convenience and Necessity ("CPCN") related to the capital expenditures, on the condition that FEI assign the related third-party contracts associated with the above-noted project to a regulated company affiliated with FEI, which FEI has complied with. Approval of the related customer rates and rate design, as filed by FEI, were denied and the Company refiled revised rates and rate design in April 2012, as invited by the BCUC, with a decision pending from the BCUC. - In February 2012 the BCUC approved FEI's amended application for a general tariff for the provision of compressed natural gas ("CNG") and LNG for transportation vehicles. In February 2012 FEI subsequently filed for a CPCN to construct and operate CNG fueling station infrastructure, to be in service October 2012, along with a long-term contract with a counterparty for the supply of CNG in accordance with the approved general tariff. A decision on the above matter is expected in May 2012. - In November 2011 FEI, FEVI and FEWI filed an application with the BCUC for the amalgamation of the three companies into one legal entity and for the implementation of common rates and services for the utilities' customers across British Columbia, effective January 1, 2013. In late 2011 the utilities temporarily suspended their application while they provide additional information to the BCUC, as requested. In April 2012 the utilities refiled their application. The amalgamation requires approval by the BCUC and consent of the Government of British Columbia. - In November 2011 the BCUC issued preliminary notification to public utilities subject to its regulation, including the FortisBC gas and electric utilities, that it planned to initiate a Generic Cost of Capital ("GCOC") Proceeding in early 2012. In February 2012 the BCUC established that a GCOC Proceeding would take place and, in March 2012, provided for comment a preliminary scoping document outlining the matters to be examined by the proceeding. In April 2012 the BCUC issued a final scoping document identifying the items that will be reviewed as part of the GCOC Proceeding, which include: (i) the appropriate cost of capital for a benchmark low-risk utility effective January 1, 2013, which includes capital structure, ROE and interest on debt; (ii) the establishment of a benchmark ROE based on a benchmark low-risk utility effective from January 1, 2013 through December 31, 2013 for the initial transition year; (iii) the determination of whether a return to an ROE automatic adjustment mechanism is warranted, which would be implemented January 1, 2014 or, if not, a future regulatory process will be set to review the ROE for a benchmark low-risk utility beyond December 31, 2013; (iv) a generic methodology on how to establish each utility's cost of capital in reference to the cost of capital for a benchmark low-risk utility; (v) a methodology to establish a deemed capital structure and deemed cost of capital, particularly for those utilities without third-party debt; and (vi) for those utilities that require a deemed interest rate, a methodology to establish a deemed interest rate automatic adjustment mechanism and, if not warranted, a future regulatory process will be set on how the deemed interest rate would be adjusted beyond December 31, 2013. The GCOC Proceeding is not intended to set each utility's risk premium. As part of the GCOC Proceeding, the BCUC will retain an independent consultant to report on regulatory practices in Canadian jurisdictions. The GCOC Proceeding will occur in 2012. The result of the GCOC Proceeding could materially impact the earnings of the FortisBC Energy Companies and FortisBC Electric. - In April 2012 the BCUC issued its decision on the FortisBC Energy companies' 2012-2013 RRAs. The interim increases in customer rates, effective January 1, 2012, at FEI and FEWI reflected the applied for rate increases. The above-noted decision is expected to result in a decrease in customer delivery rates at FEI and FEWI in the range of 1%-2% from the interim rates. In its decision, the BCUC approved FEVI's 2012 and 2013 customer rates to remain unchanged from 2011 customer rates. The difference between interim and final customer rates at FEI and FEWI will be refunded to customers over the remainder of 2012. The final approved customer delivery rates reflect allowed ROEs and capital structure unchanged from 2011. The final rate increases were driven by ongoing investment in energy infrastructure focused on system integrity and reliability, and forecasted increased operating expenses associated with inflation, a heightened focus on safety and security of the natural gas system, and increasing compliance with codes and regulations. |
|
| FortisBC Electric | - In June 2011 FortisBC Electric filed its 2012-2013 RRA, which included its 2012-2013 Capital Expenditure Plan and its Integrated System Plan ("ISP"). The ISP includes the Company's Resource Plan, Long-Term Capital Plan and Long-Term Demand Side Management Plan. FortisBC Electric requested an interim 4% increase in customer electricity rates effective January 1, 2012 and a 6.9% increase effective January 1, 2013. The rate increases are due to ongoing investment in energy infrastructure, including increased costs of financing the investment, as well as increased purchased power costs. The requested customer rates reflect an allowed ROE and capital structure unchanged from 2011. In addition to a continuation of deferral accounts and flow-through treatments that existed under the PBR agreement, which expired at the end of 2011, the 2012-2013 RRA proposes deferral accounts and flow-through treatment for variances from the forecast used to set customer rates for electricity revenue, purchased power costs and certain other costs. - In November 2011 FortisBC Electric filed an updated 2012-2013 RRA to include updated financial estimates and forecasts, resulting in a revised requested increase in customer rates of 1.5%, effective January 1, 2012, and 6.5%, effective January 1, 2013. The revised application assumes forecast midyear rate base of approximately $1,146 million for 2012 and $1,215 million for 2013. An oral hearing process occurred in March 2012 and a decision is expected mid-2012. The interim, refundable customer rate increase of 1.5%, effective January 1, 2012, was approved by the BCUC pending a final decision on the Company's 2012-2013 RRA. - In November 2011 FortisBC Electric executed an agreement to purchase capacity from the Waneta Expansion. The agreement allows FortisBC Electric to purchase capacity over 40 years upon completion of the Waneta Expansion, which is expected to be in spring 2015. The form of the agreement was originally accepted for filing by the BCUC in September 2010. The BCUC is conducting its usual review process of the executed agreement, filed in November 2011, to determine whether a hearing is necessary to decide whether the agreement is in the public interest. - In March 2012 the BCUC issued an order establishing a written hearing process to review the prudency of approximately $29 million in capital expenditures incurred related to the Kettle Valley Distribution Source Project, which was substantially completed in 2009. FortisBC Electric believes that the capital expenditures were prudently incurred and, therefore, cannot reasonably determine if any of such expenditures may be disallowed from rate base and any resulting financial impact. The hearing is expected to take place throughout 2012. |
| FortisAlberta | - In October 2010 the Central Alberta Rural Electrification Association ("CAREA") filed an application with the AUC requesting that, effective January 1, 2012, CAREA be entitled to service any new customers wishing to obtain electricity for use on property overlapping CAREA's service area and that FortisAlberta be restricted to providing service in the CAREA service area only to those customers who are not being provided service by CAREA. FortisAlberta intervened in the proceeding to oppose CAREA's request, with an oral argument heard in April 2012. A decision on this matter is expected during the third quarter of 2012. - In 2010 the AUC initiated a process to reform utility rate regulation for distribution utilities in Alberta. The AUC intends to introduce PBR-based distribution service rates beginning in 2013 for a five-year term, with 2012 to be used as the base year. In July 2011 FortisAlberta, along with other distribution utilities operating under the AUC's jurisdiction, submitted PBR proposals to the AUC. The Company's submission outlines its views as to how PBR should be implemented at FortisAlberta. A hearing on the matter commenced in April 2012 with a decision expected in 2012. - In December 2011 the AUC issued its decision on its 2011 GCOC Proceeding, establishing the allowed ROE at 8.75% for 2011 and 2012 and, on an interim basis, at 8.75% for 2013. The equity component of FortisAlberta's capital structure remains at 41% and will continue at that level until changed by any future order of the AUC. The AUC concluded that it would not return to a formula-based ROE automatic adjustment mechanism at this time and that it would initiate a proceeding in due course to establish a final allowed ROE for 2013 and revisit the matter of a return to a formula-based approach in future periods. - In January 2012 FortisAlberta and other distribution utilities in Alberta filed motions for leave to appeal with the Alberta Court of Appeal with respect to the 2011 GCOC decision, challenging certain pronouncements made by the AUC as being incorrect regarding cost responsibility for stranded assets. In February 2012 FortisAlberta and other utilities filed requests for the AUC to review and vary its pronouncements. |
| - In April 2012 the AUC approved, substantially as filed, an NSA pertaining to FortisAlberta's 2012 distribution revenue requirements resulting in an average increase in customer rates of approximately 5%, effective January 1, 2012, consistent with the interim rate increase that was previously approved by the AUC in December 2011. The increase in customer rates was driven primarily by ongoing investment in energy infrastructure, including increased depreciation and financing costs. The NSA provides for forecast midyear rate base of $2,025 million. The AUC did not approve the continuation of the deferral of volume variances associated with FortisAlberta's Alberta Electric System Operator ("AESO") charges deferral account. This item is to be examined by the AUC in a future proceeding. | |
| Newfoundland Power |
- In March 2012 Newfoundland Power filed a Cost of Capital Application with the PUB to discontinue the use of the current ROE automatic adjustment mechanism and to approve a just and reasonable rate of return on average rate base for 2012. A public hearing on the application is currently scheduled for June 2012. - Newfoundland Power expects to file a Rate Stabilization Account ("RSA") application with the PUB by the end of May 2012 to seek an average increase in customer electricity rates of approximately 7%, effective July 1, 2012. The expected increase in rates is primarily due to the result of the normal annual operation of Newfoundland and Labrador Hydro's ("Newfoundland Hydro") Rate Stabilization Plan. Variances in the cost of fuel used to generate electricity that Newfoundland Hydro sells to Newfoundland Power are captured and flowed through to customers through the operation of Newfoundland Power's RSA. The increase in rates, principally due to higher fuel prices, will not have an impact on Newfoundland Power's earnings. - The Company is currently assessing its requirement to file a general rate application with the PUB to recover expected increased costs in 2013. |
| Maritime Electric | - In February 2012 the PEI Energy Commission (the "PEI Commission") released its Discussion Paper "Charting Our Electricity Future", which outlined discussion points the PEI Commission is seeking input on through a consultative process with stakeholders and the general public. These discussion points included: (i) electricity ownership and management on PEI and whether Maritime Electric is doing a good job of balancing safety and reliability with cost of service; (ii) the future role of IRAC, the PEI Energy Corporation and the PEI Office of Energy Efficiency; (iii) a new cable interconnection; (iv) the treatment of the financing of the $47 million of deferred incremental replacement energy costs associated with the Point Lepreau nuclear generating station; (v) regional energy collaboration; (vi) demand-side management; (vii) renewable energy and environmental stewardship; and (viii) potential options for natural gas-generated electricity. Public forums and stakeholder consultations occurred in February and March 2012, in which Maritime Electric was a participant. The PEI Commission is expected to release a final report of its recommendations to the Government of PEI in fall 2012. - In March 2012 Maritime Electric received regulatory approval to defer, for refund to customers in a future period to be determined, contingent income tax expense reductions associated with the Company's amendment of corporate income tax filings for the years 2007 through 2010. The amended filings seek to expense certain costs previously capitalized for income tax purposes. - Maritime Electric intends to file an application with IRAC in fall 2012 for 2013 customer rates and allowed ROE. |
| FortisOntario | - In non-rebasing years, customer electricity distribution rates are set using inflationary factors less an efficiency target under the Third-Generation Incentive Rate Mechanism ("IRM") as prescribed by the OEB. In the first quarter of 2012, the OEB published applicable inflationary and efficiency targets, resulting in minimal changes in base customer electricity distribution rates at FortisOntario's operations in Fort Erie, Gananoque and Port Colborne effective May 1, 2012. The Third-Generation IRM maintains the allowed ROE at 8.01% for 2012. - In April 2012 the OEB issued Final Decisions and Orders for customer rates effective May 1, 2012 at FortisOntario's operations in Fort Erie, Gananoque and Port Colborne. The result was an average 3.1% decrease in residential customer rates in Fort Erie, an average 0.6% increase in residential customer rates in Gananoque, and an average 4.6% decrease in residential customer rates in Port Colborne. The above-noted rate changes were mainly due to changes in rate riders associated with regulatory deferral accounts and smart meter funding. - In April 2011 FortisOntario provided the City of Port Colborne and Port Colborne Hydro with an irrevocable written notice of FortisOntario's election to exercise the purchase option, under the current operating lease agreement, at the purchase option price of approximately $7 million on April 15, 2012. The purchase constitutes the sale of the remaining assets of Port Colborne Hydro to FortisOntario. The purchase transaction was approved by the OEB in March 2012 and closed on April 16, 2012. |
| - In March 2012 the OEB issued its decision on Algoma Power's Third-Generation IRM application for customer electricity distribution rates, effective January 1, 2012. The decision approved a price-cap index of 2.81% for customers subject to RRRP funding and 0.38% for those customers not subject to RRRP funding. RRRP funding for 2012 has been set at approximately $11 million. Algoma Power's allowed ROE is maintained at 9.85% for 2012. - FortisOntario expects to file a COS Application in 2012 for harmonized electricity distribution rates in Fort Erie, Port Colborne and Gananoque, effective January 1, 2013, using a 2013 forward test year. The timing of the filing of the COS Application corresponds with the ending of the period that the current Third-Generation IRM applies to FortisOntario. |
|
| Caribbean Utilities | - In April 2012 the ERA approved Caribbean Utilities' 2012-2016 Capital Investment Plan ("CIP") for US$122 million of non-generation installation capital expenditures. The remaining US$62 million of the 2012-2016 CIP relates to new generation installation, which would be subject to a competitive solicitation process with the next generation unit scheduled for installation in 2014. The 2012-2016 CIP was prepared in line with the Certificate of Need that was filed with the ERA in November 2011, which included 18 MW of generating capacity to be installed in either 2015 or 2016, contingent on load growth over the next two years. - In March 2012 the ERA approved the creation of Caribbean Utilities' wholly owned subsidiary DataLink, Ltd. ("DataLink"). Subsequently, the Information and Communications Technology Authority ("ICTA") granted a licence to DataLink to provide fibre optic infrastructure on Grand Cayman. The ICTA licence allows DataLink to assume full responsibility for existing pole attachment agreements and optical fibre lease agreement currently held by Caribbean Utilities with third-party information and communications technology service providers. - In December 2011 Caribbean Utilities conducted and completed a competitive bidding process to fill up to 13 MW of non-firm renewable energy capacity. Two renewable energy developers have been chosen to commence discussions with Caribbean Utilities to provide energy to the utility's grid. The proposals being considered are two 5-MW solar photovoltaic power plants and one 3-MW small-scale wind turbine project. Caribbean Utilities and the developers are expected to commence negotiations related to power purchase agreements. The power purchase agreements, however, are subject to ERA review and approval. |
| Fortis Turks and Caicos | - An independent review of the regulatory framework for the electricity sector in the Turks and Caicos Islands was performed during the third quarter of 2011 on behalf of the Interim Government. The purpose of the review was to: (i) assess the effectiveness of the current regulatory framework in terms of its administrative and economic efficiency; (ii) assess the current and proposed electricity costs and tariffs in the Turks and Caicos Islands in relation to comparable regional and international utilities; (iii) make recommendations for a revised regulatory framework and Electricity Ordinance; and (iv) make recommendations for the implementation and operation of the revised regulatory framework. Fortis Turks and Caicos provided a comprehensive response to the Interim Government in January 2012 stating that the Company supports limited mutually agreed upon reforms, but that its current licences must be respected and can only be changed by mutual consent. Specifically, Fortis Turks and Caicos would support reforms that strengthen the role of the regulator in the rate-setting process and that are fair to all stakeholders. Negotiations between Fortis Turks and Caicos and the Interim Government are expected to commence mid-2012 with implementation of any resulting changes in the regulatory framework expected to occur at the end of 2012. - In February 2012 the Interim Government approved an approximate 26% increase in electricity rates, effective April 1, 2012, for Fortis Turks and Caicos' large hotel customers. In addition, other qualitative enhancements to the franchise were also achieved, including: (i) improved wording in the Electricity Rate Regulation; (ii) an approved increase in kilowatt hour consumption thresholds for both medium and large hotels; (iii) an expansion of service territory to cover all of the Caicos Islands, except for areas currently serviced by private suppliers' licences, with new 25-year licenses issued for the expanded service territory; and (iv) the discontinuance of the government subsidization of the utility's South Caicos operations. - In March 2012 Fortis Turks and Caicos submitted its 2011 annual regulatory filing outlining the Company's performance in 2011. Included in the filing were the calculations, in accordance with the utility's licence, of rate base of US$166 million for 2011 and cumulative shortfall in achieving allowable profits of US$72 million as at December 31, 2011. - In April 2012 Fortis Turks and Caicos entered into a Streetlight Takeover Agreement with the Interim Government whereby the responsibility for the ownership, installation and maintenance of all streetlights in the utility's service territory was transferred to Fortis Turks and Caicos. |
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between March 31, 2012 and December 31, 2011.
| Significant Changes in the Consolidated Balance Sheets (Unaudited) between March 31, 2012 and December 31, 2011 | |||
| Balance Sheet Account | Increase/ (Decrease) ($ millions) |
Explanation | |
| Accounts receivable | 58 | The increase was primarily due to the impact of a seasonal increase in sales, and the operation of the equal payment plans for customers, mainly at the FortisBC Energy companies and Newfoundland Power. | |
| Inventories | (58) | The decrease was driven by the normal seasonal reduction of gas in storage at the FortisBC Energy companies, due to higher consumption during the winter months. | |
| Utility capital assets | 96 | The increase primarily related to $211 million invested in electricity and gas systems, partially offset by depreciation and customer contributions for the three months ended March 31, 2012. | |
| Short-term borrowings | (83) | The decrease was driven by lower borrowings at the FortisBC Energy companies due to seasonality of operations. | |
| Regulatory liabilities - current and long-term | 70 | The increase was driven by deferrals at the FortisBC Energy companies associated with an increase in the Rate Stabilization Deferral Account at FEVI, reflecting amounts collected in customer rates in excess of the cost of providing service during the three months ended March 31, 2012, and an increase in the Midstream Cost Reconciliation Account, as amounts collected in customer rates were in excess of actual midstream gas-delivery costs for the three months ended March 31, 2012. | |
| Shareholders' equity (before non-controlling interests) | 78 | The increase was primarily due to net earnings attributable to common equity shareholders for the three months ended March 31, 2012, less common share dividends, and the issuance of common shares under the Corporation's dividend reinvestment plan. | |
| Non-controlling interests | 38 | The increase was driven by advances from the 49% non-controlling interests in the Waneta Expansion Limited Partnership ("Waneta Partnership") and an approximate $12 million, or 15%, equity investment by two First Nations bands in the LNG storage facility on Vancouver Island. | |
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash for the three months ended March 31, 2012, as compared to the same period in 2011, followed by a discussion of the nature of the variances in cash flows.
| Summary of Consolidated Cash Flows (Unaudited) | Quarter Ended March 31 | ||||||
| ($ millions) | 2012 | 2011 | Variance | ||||
| Cash, Beginning of Period | 87 | 107 | (20 | ) | |||
| Cash Provided by (Used in): | |||||||
| Operating Activities | 328 | 302 | 26 | ||||
| Investing Activities | (211 | ) | (217 | ) | 6 | ||
| Financing Activities | (94 | ) | (108 | ) | 14 | ||
| Cash, End of Period | 110 | 84 | 26 | ||||
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 $98 million for the same quarter last year. The change quarter over quarter was driven by the FortisBC Energy companies.
Net borrowings under committed credit facilities for the first quarter of 2012 compared to the same quarter of 2011 are summarized in the following table.
| Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited) | ||||||
| Quarter Ended March 31 | ||||||
| ($ millions) | 2012 | 2011 | Variance | |||
| FortisAlberta | (29 | ) | 12 | (41 | ) | |
| FortisBC Electric | (9 | ) | - | (9 | ) | |
| Newfoundland Power | 14 | 13 | 1 | |||
| Corporate | 31 | (10 | ) | 41 | ||
| Total | 7 | 15 | (8 | ) | ||
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 $0.29 for the first quarter of 2011. The weighted average number of common shares outstanding for the first quarter was 189.0 million compared to 175.0 million for the first quarter of 2011.
CONTRACTUAL OBLIGATIONS
As at March 31, 2012, consolidated contractual obligations of Fortis over the next five years and for periods thereafter are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2011 Annual MD&A and below, where applicable. The presentation of certain contractual obligations has changed from that provided in the 2011 Annual MD&A due to the adoption of US GAAP. For further information concerning these changes, refer to the 2011 audited consolidated financial statements prepared in accordance with US GAAP and voluntarily filed on SEDAR.
| Contractual Obligations (Unaudited) As at March 31, 2012 ($ millions) |
Total |
Due within 1 year |
Due in years 2 and 3 |
Due in years 4 and 5 |
Due after 5 years |
|
| Long-term debt | 5,901 | 121 | 768 | 428 | 4,584 | |
| Capital lease obligations(1) | 2,501 | 42 | 86 | 89 | 2,284 | |
| Waneta Partnership promissory note | 72 | - | - | - | 72 | |
| Gas purchase contract obligations(2) | 217 | 130 | 87 | - | - | |
| Power purchase obligations | ||||||
| FortisBC Electric | 25 | 12 | 10 | 3 | - | |
| FortisOntario | 399 | 41 | 99 | 103 | 156 | |
| Maritime Electric | 176 | 42 | 79 | 41 | 14 | |
| Capital cost | 457 | 17 | 36 | 36 | 368 | |
| Joint-use asset and share service agreements | 64 | 4 | 8 | 7 | 45 | |
| Operating lease obligations | 155 | 20 | 36 | 34 | 65 | |
| Defined benefit pension funding contributions(3) | 111 | 40 | 46 | 22 | 3 | |
| Other | 8 | 1 | 2 | 1 | 4 | |
| Total | 10,086 | 470 | 1,257 | 764 | 7,595 | |
| (1) | Includes principal payments and approximately $2 million of imputed interest and executory costs, mainly related to FortisBC Electric's Brilliant Power Purchase Agreement and Brilliant Terminal Station. |
| (2) | Based on index prices as at March 31, 2012 |
| (3) | Consolidated defined benefit pension funding contributions include current service, solvency and special funding amounts. The contributions are based on estimates provided under the latest completed actuarial valuations, which generally provide funding estimates for a period of three to five years from the date of the valuations. As a result, actual pension funding contributions may be higher than these estimated amounts, pending completion of the next actuarial valuations for funding purposes, which are expected to be performed as of the following dates for the larger defined benefit pension plans: |
| December 31, 2012 FortisBC Energy companies (covering non-unionized employees) | |
| December 31, 2013 FortisBC Energy companies (covering unionized employees) | |
| December 31, 2013 FortisBC Electric | |
| December 31, 2014 Newfoundland Power | |
| The estimate of defined benefit pension funding contributions in the above table includes the impact of the outcome of the December 31, 2011 actuarial valuation, completed in April 2012, associated with the defined benefit pension plan at Newfoundland Power. As a result of the valuation, Newfoundland Power is required to fund a solvency deficiency of approximately $53.5 million, including interest, over five years beginning in 2012, which is included in the above table. |
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 $6 million in equity in the Mount Hayes LNG storage facility, representing a 15% equity interest in the Mount Hayes Limited Partnership, with FEVI holding the controlling 85% ownership interest. The non-controlling interests hold put options, which, if exercised, would require FEVI to repurchase the 15% ownership interest for cash, in accordance with the terms of the partnership agreement.
For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program, which is not included in the Contractual Obligations table above, refer to the "Capital Expenditure Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40% equity, including preference shares, and 60% debt, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
| Capital Structure (Unaudited) | As at | |||
| March 31, 2012 | December 31, 2011 | |||
| ($ millions) | (%) | ($ millions) | (%) | |
| Total debt and capital lease obligations (net of cash)(1)(2) | 6,186 | 56.2 | 6,296 | 57.1 |
| Preference shares | 912 | 8.3 | 912 | 8.3 |
| Common shareholders' equity | 3,901 | 35.5 | 3,823 | 34.6 |
| Total(3) | 10,999 | 100.0 | 11,031 | 100.0 |
| (1) | Includes long-term debt and capital lease obligations, including current portion, and short-term borrowings, net of cash |
| (2) | Excluding capital lease obligations and financing obligations under lease-in lease-out transactions, the debt component of the capital structure was 54.4% as at March 31, 2012 and 55.3% as at December 31, 2011. |
| (3) | Excludes amounts related to non-controlling interests |
The improvement in the capital structure was primarily due to: (i) 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:
| Standard & Poor's | A-/Credit Watch - Negative (unsecured debt credit rating) |
| DBRS | A(low)/Under Review - Developing Implications (unsecured debt credit rating) |
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 $229 million in gross capital expenditures by segment for the first quarter of 2012 is provided in the following table.
| Gross Consolidated Capital Expenditures (Unaudited)(1) | |||||||||
| Quarter Ended March 31, 2012 | |||||||||
| ($ millions) | |||||||||
| FortisBC Energy Com- panies |
Fortis Alberta (2) |
FortisBC Electric |
New- found- land Power |
Other Regu- lated Elec- tric Utili- ties - Cana- dian |
Total Regu- lated Utili- ties - Cana- dian |
Regu- lated Elec- tric Utili- ties - Carib- bean |
Non- Regu- lated - Utility (3) |
Fortis Proper- ties |
Total |
| 46 | 79 | 17 | 15 | 9 | 166 | 10 | 48 | 5 | 229 |
| (1) | Relates to cash payments to acquire or construct utility capital assets, income producing properties and intangible assets, as reflected in the consolidated statement of cash flows. Includes non-ARO removal expenditures, net of salvage proceeds, for those utilities where such expenditures are permissible in rate base in 2012. Excludes capitalized amortization and non-cash equity component of AFUDC. |
| (2) | Includes payments made to AESO for investment in transmission-related capital projects |
| (3) | Includes non-regulated generation capital expenditures, mainly related to the Waneta Expansion |
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts.
There have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2011 Annual MD&A. Gross consolidated capital expenditures for 2012 are forecasted at 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 $2.0 billion of the total credit facilities are committed facilities with maturities ranging from 2013 through 2017.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| Credit Facilities (Unaudited) | As at | ||||||||||
($ millions) |
Corporate and Other |
Regulated Utilities |
Fortis Properties |
March 31, 2012 |
December 31, 2011 |
||||||
| Total credit facilities | 845 | 1,389 | 13 | 2,247 | 2,248 | ||||||
| Credit facilities utilized: | |||||||||||
| Short-term borrowings | - | (73 | ) | (3 | ) | (76 | ) | (159 | ) | ||
| Long-term debt (including current portion) | (31 | ) | (50 | ) | - | (81 | ) | (74 | ) | ||
| Letters of credit outstanding | (1 | ) | (65 | ) | - | (66 | ) | (66 | ) | ||
| Credit facilities unused | 813 | 1,201 | 10 | 2,024 | 1,949 | ||||||
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 $1 billion, as permitted under the credit facility agreement, and expects the increase to be available in May 2012.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.
| Financial Instruments (Unaudited) | As at | |||
| March 31, 2012 | December 31, 2011 | |||
| ($ millions) |
Carrying Value |
Estimated Fair Value |
Carrying Value |
Estimated Fair Value |
| Waneta Partnership promissory note | 45 | 50 | 45 | 49 |
| Long-term debt, including current portion | 5,901 | 7,207 | 5,912 | 7,296 |
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 $1.5 million in earnings during the first quarter of 2012.
From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and fuel and natural gas prices through the use of derivative financial instruments. The Corporation and its subsidiaries do not hold or issue derivative financial instruments for trading purposes. As at March 31, 2012, the Corporation's derivative contracts consisted of a foreign exchange forward contract, natural gas swap and option contracts, and gas purchase contract premiums, all held by the FortisBC Energy companies.
The following table summarizes the Corporation's derivative financial instruments.
| Derivative Financial Instruments (Unaudited) | As at | |||||||
(Liability) Asset |
Maturity |
Number of Contracts |
Volume (petajoules) |
March 31, 2012 Carrying Value(1) ($ millions) |
December 31, 2011 Carrying Value(1) ($ millions) |
|||
| Foreign exchange forward contract | 2012 | 1 | - | - | - | |||
| Fuel option contracts | 2012 | - | - | - | (1 | ) | ||
| Natural gas derivatives: | ||||||||
| Swaps and options | 2014 | 90 | 51 | (135 | ) | (135 | ) | |
| Gas purchase contract premiums | 2014 | 27 | 99 | 3 | - | |||
| (1) | Carrying value approximates fair value. The (liability) asset represents the gross derivatives balance. |
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.
- Total assets as at December 31, 2011 increased by approximately $603 million. The increase was due primarily to increases in regulatory assets and utility capital assets in accordance with US GAAP.
- Total liabilities as at December 31, 2011 increased by approximately $337 million. The increase was due primarily to increases in long-term debt, capital lease obligations and pension liabilities in accordance with US GAAP, partially offset by the reclassification of preference shares from liabilities to shareholders' equity.
- Shareholders' equity as at December 31, 2011 increased by approximately $266 million. The increase was due primarily to the reclassification of preference shares from liabilities to shareholders' equity in accordance with US GAAP, partially offset by a reduction in retained earnings of approximately $37 million and an increase in accumulated other comprehensive loss of approximately $21 million. Approximately half of the reduction in retained earnings resulted from higher income taxes and is expected to reverse in a future period once pending Canadian federal income tax legislation is passed and proposed Part VI.1 tax rate changes are enacted.
There were no material adjustments to the Corporation's consolidated 2011 earnings under US GAAP due to the Corporation's continued ability to apply rate-regulated accounting policies.
The unaudited quantification and reconciliation of the Corporation's consolidated statement of earnings for the three months ended March 31, 2011, prepared in accordance with US GAAP versus Canadian GAAP, may be summarized as follows:
- Three Months Ended March 31, 2011 (Unaudited): Consolidated net earnings recognized in accordance with US GAAP increased by $3 million, from $125 million to $128 million. The increase was due primarily to the reclassification of preference share dividends totaling $4 million, in accordance with US GAAP, from finance charges to earnings attributable to preference equity shareholders, partially offset by a reduction in earnings attributable to common equity shareholders of approximately of $1 million.
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 ended March 31, 2012.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period they become known.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the first quarter of 2012 from those disclosed in the 2011 Annual MD&A.
Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with ordinary course business operations. Management believes that the amount of liability, if any, from these actions would not have a material effect on the Corporation's consolidated financial position or results of operations.
The following describes the nature of the Corporation's contingent liabilities.
Fortis
Following the announcement of the proposed acquisition of CH Energy Group on February 21, 2012, several complaints, which named Fortis and other defendants, were filed in, or transferred to, the Supreme Court of the State of New York, County of New York, challenging the proposed acquisition. The complaints generally allege that the directors of CH Energy Group breached their fiduciary duties in connection with the proposed transaction and that CH Energy Group, Fortis, FortisUS Inc., and Cascade Acquisition Sub Inc. aided and abetted that breach.
The outcome of these lawsuits is uncertain and cannot be predicted with any certainty and, accordingly, no amount has been accrued in the consolidated financial statements. An adverse judgment for monetary damages could have a material adverse effect on the operations of the surviving company after the completion of the acquisition. A preliminary injunction could delay or jeopardize the completion of the acquisition and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the transaction. Subject to the foregoing, in management's opinion, based upon currently known facts and circumstances, the outcome of such lawsuits is not expected to have a material adverse effect on the consolidated financial condition of Fortis. The defendants intend to vigorously defend themselves against the lawsuits.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of Assessment from Canada Revenue Agency for additional taxes related to the taxation years 1999 through 2003. The exposure has been fully provided for in the consolidated financial statements. FHI has begun the appeal process associated with the assessments.
In 2009 FHI was named, along with other defendants, in an action related to damages to property and chattels, including contamination to sewer lines and costs associated with remediation, related to the rupture in July 2007 of an oil pipeline owned and operated by Kinder Morgan, Inc. FHI has filed a statement of defence. During the second quarter of 2010, FHI was added as a third party in all of the related actions and all claims are expected to be tried at the same time. The amount and outcome of the actions are indeterminable at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
FortisBC Electric
The Government of British Columbia has alleged breaches of the Forest Practices Code and negligence relating to a forest fire near Vaseux Lake and has filed and served a writ and statement of claim against FortisBC Electric, dated August 2, 2005. The Government of British Columbia has now disclosed that its claim includes approximately $13.5 million in damages but that it has not fully quantified its damages. In addition, private landowners have filed separate writs and statements of claim dated August 19, 2005 and August 22, 2005 for undisclosed amounts in relation to the same matter. FortisBC Electric and its insurers are defending the claims. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements. A date for mediation of this matter has been set for December 2012.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended June 30, 2010 through March 31, 2012. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements, which have been prepared in accordance with US GAAP. The timing of the recognition of certain assets, liabilities, revenue and expenses, as a result of regulation, may differ from that otherwise expected using US GAAP for non-regulated entities. The nature of regulation is further disclosed in Notes 2, 3 and 7 to the Corporation's 2011 annual audited consolidated financial statements prepared in accordance with US GAAP. The quarterly financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
| Summary of Quarterly Results | Net Earnings | |||
| (Unaudited) | Attributable to | |||
| Common Equity | ||||
| Revenue | Shareholders | Earnings per Common Share | ||
| Quarter Ended | ($ millions) | ($ millions) | Basic ($) | Diluted ($) |
| March 31, 2012 | 1,149 | 121 | 0.64 | 0.62 |
| December 31, 2011 | 1,034 | 82 | 0.44 | 0.43 |
| September 30, 2011 | 699 | 56 | 0.30 | 0.30 |
| June 30, 2011 | 846 | 57 | 0.32 | 0.32 |
| March 31, 2011 | 1,159 | 116 | 0.66 | 0.64 |
| December 31, 2010 | 1,032 | 127 | 0.73 | 0.71 |
| September 30, 2010 | 717 | 43 | 0.25 | 0.25 |
| June 30, 2010 | 831 | 53 | 0.31 | 0.31 |
A summary of the past eight quarters reflects the Corporation's continued organic growth, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel and purchased power and the commodity cost of natural gas, which are flowed through to customers without markup. Given the diversified nature of the Fortis subsidiaries, seasonality may vary. Most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters. Earnings for the third quarter ended September 30, 2011 included the $11 million after-tax termination fee paid to Fortis by Central Vermont Public Service Corporation ("CVPS"). Financial results from the fourth quarter ended December 31, 2011 reflected the acquisition of the Hilton Suites Winnipeg Airport hotel, which was acquired in October 2011. Financial results from June 20, 2011 reflected the discontinuance of the consolidation method of accounting for Belize Electricity due to the expropriation of the utility by the GOB. For further information, refer to the "Key Trends and Risks - Expropriated Assets" and "Business Risk Management - Investment in Belize" sections of the 2011 Annual MD&A. Revenue for the third quarter ended September 30, 2010 reflected the favourable cumulative retroactive impact associated with the 2010 revenue requirements decision at FortisAlberta.
March 2012/March 2011: Net earnings attributable to common equity shareholders were $121 million, or $0.64 per common share, for the first quarter of 2012 compared to earnings of $116 million, or $0.66 per common share, for the first quarter of 2011. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.
December 2011/December 2010: Net earnings attributable to common equity shareholders were $82 million, or $0.44 per common share, for the fourth quarter of 2011 compared to earnings of $127 million, or $0.73 per common share, for the fourth quarter of 2010. Excluding the one-time $46 million favourable impact to Newfoundland Power's earnings in the fourth quarter of 2010 due to the rerecognition of a regulatory asset, as required under US GAAP, to recognize amounts recoverable from customers upon regulatory approval of the adoption the accrual method of accounting for OPEB costs, earnings increased $1 million quarter over quarter. The increase in earnings was led by the FortisBC Energy Companies, driven by rate base growth, lower-than-expected corporate income taxes and finance charges in 2011, and higher gas transportation volumes to the forestry and mining sectors, partially offset by both lower customer additions and capitalized AFUDC. The above increase in earnings was partially offset by a decrease in earnings at Newfoundland Power, Other Canadian Regulated Electric Utilities, Fortis Turks and Caicos and Fortis Properties. The decrease in earnings at Newfoundland Power reflected a lower allowed ROE and higher operating expenses, partially offset by reduced energy supply costs in the fourth quarter of 2011. Lower earnings at Other Canadian Regulated Electric Utilities were due to decreased electricity sales and higher operating expenses. Lower earnings at Fortis Turks and Caicos were due to higher depreciation and operating expenses, partially offset by reduced energy supply costs in 2011 reflecting the use of new, more fuel-efficient generating units. Earnings at Fortis Properties during the fourth quarter of 2010 reflected lower corporate income tax rates, which reduced deferred taxes in that period. An 8% increase in the weighted average number of common shares outstanding quarter over quarter, largely associated with the public common equity offering in mid-2011, had the impact of tempering earnings per common share.
September 2011/September 2010: Net earnings attributable to common equity shareholders were $56 million, or $0.30 per common share, for the third quarter of 2011 compared to earnings of $43 million, or $0.25 per common share, for the third quarter of 2010. The increase in earnings was mainly due to the $11 million after-tax fee paid to Fortis in July 2011, following the termination of the Merger Agreement between Fortis and CVPS. Results also improved due to rate base growth associated with energy infrastructure investment, mainly at the regulated utilities in western Canada, a net foreign exchange gain of approximately $2.5 million after tax associated with the previously hedged investment in Belize Electricity, lower-than-expected operating costs at the FortisBC Energy companies due to the timing of spending and capitalization of certain operating expenses in 2011 and a higher allowed ROE at Algoma Power. The above increases in earnings were partially offset by the impact of the regulator-approved reversal in the third quarter of 2010 of $4 million after tax of project overrun costs previously expensed in 2009 related to the conversion of Whistler customer appliances from propane to natural gas, the expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility since June 2011, lower capitalized AFUDC at FortisBC Electric, lower non-regulated hydroelectric production in Belize and the timing of recording the 2010 revenue requirements decision at FortisAlberta. The favourable cumulative impact of the decision was recorded in the third quarter of 2010 when the decision was received. A 4% 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 tempering earnings per common share.
June 2011/June 2010: Net earnings attributable to common equity shareholders were $57 million, or $0.32 per common share, for the second quarter of 2011 compared to earnings of $53 million, or $0.31 per common share, for the second quarter of 2010. The increase was mainly due to improved performance at Canadian Regulated Electric Utilities, driven by rate base growth associated with energy infrastructure investment, mainly at the electric utilities in western Canada; return earned on additional investment in automated meters at FortisAlberta, as approved by the regulator; lower market-priced purchased power costs at FortisBC Electric and a higher allowed ROE at Algoma Power. Results also improved due to lower corporate business development costs. The above increases in earnings were partially offset by the unfavourable impact of the timing of spending of certain regulator-approved increased operating expenses at the FortisBC Energy companies during 2011, lower non-regulated hydroelectric generation in Belize, and lower contribution from Fortis Properties reflecting lower occupancies at hotel operations in western Canada and increased operating expenses. During the second quarter of 2011, the Government of Belize expropriated the Corporation's investment in Belize Electricity.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
In an effort to optimize customer service operations within the FortisBC Energy companies, a Customer Care Enhancement Project was implemented in January 2012 with new in-house customer contact and billing centres replacing the services of an external third-party service provider. This represents a material change in the Corporation's internal controls over financial reporting surrounding the revenue, receivable and receipts cycle. Throughout the related systems design and implementation, management had considered the control risks associated with the systems changes and had performed procedures to obtain reasonable assurance on the design of all new and significantly modified internal controls over financial reporting as a result of the project. It has been concluded that during the first quarter 2012, other than the above-noted change, there was no change in the Corporation's internal controls over financial reporting that has materially, or is reasonably likely to materially affect, the Corporation's internal controls over financial reporting.
OUTLOOK
The Corporation's significant capital expenditure program, which is expected to be approximately $5.5 billion over the five-year period 2012 through 2016, should support continuing growth in earnings and dividends.
The pending acquisition of CH Energy Group is expected to close by the end of the first quarter of 2013. Fortis remains disciplined and patient in its pursuit of additional electric and gas utility acquisitions in the United States and Canada that will add value for Fortis shareholders. Fortis will also pursue growth in its non-regulated businesses in support of its regulated utility growth strategy.
OUTSTANDING SHARE DATA
As at May 1, 2012, the Corporation had issued and outstanding approximately 189.3 million common shares; 5.0 million First Preference Shares, Series C; 8.0 million First Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; and 10.0 million First Preference Shares, Series H. Only the common shares of the Corporation have voting rights.
The number of common shares of Fortis that would be issued if all outstanding stock options and First Preference Shares, Series C and E were converted as at May 1, 2012 is as follows.
| Conversion of Securities into Common Shares(Unaudited) | |
| As at May 1, 2012 | Number of |
| Common Shares | |
| Security | (millions) |
| Stock Options | 4.6 |
| First Preference Shares, Series C | 3.8 |
| First Preference Shares, Series E | 6.2 |
| Total | 14.6 |
Additional information, including the Fortis 2011 Annual Information Form, Management Information Circular and Annual Report, is available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three months ended March 31, 2012 and 2011
(Unaudited)
Prepared in accordance with accounting principles generally accepted in the United States
| Fortis Inc. | ||||||
| Consolidated Balance Sheets (Unaudited) | ||||||
| As at | ||||||
| (in millions of Canadian dollars) | ||||||
| March 31, | December 31, | |||||
| 2012 | 2011 | |||||
| ASSETS | ||||||
| Current assets | ||||||
| Cash and cash equivalents | $ | 110 | $ | 87 | ||
| Accounts receivable | 696 | 638 | ||||
| Prepaid expenses | 17 | 19 | ||||
| Inventories | 76 | 134 | ||||
| Regulatory assets (Note 3) | 168 | 219 | ||||
| Deferred income taxes | 33 | 24 | ||||
| 1,100 | 1,121 | |||||
| Other assets | 194 | 184 | ||||
| Regulatory assets (Note 3) | 1,451 | 1,400 | ||||
| Deferred income taxes | 3 | 8 | ||||
| Utility capital assets | 9,064 | 8,968 | ||||
| Income producing properties | 595 | 594 | ||||
| Intangible assets | 324 | 325 | ||||
| Goodwill | 1,563 | 1,565 | ||||
| $ | 14,294 | $ | 14,165 | |||
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||
| Current liabilities | ||||||
| Short-term borrowings (Note 16) | $ | 76 | $ | 159 | ||
| Accounts payable and other current liabilities | 1,009 | 990 | ||||
| Regulatory liabilities (Note 3) | 76 | 43 | ||||
| Current installments of long-term debt | 121 | 107 | ||||
| Current installments of capital lease obligations | 3 | 3 | ||||
| Deferred income taxes | 3 | 5 | ||||
| 1,288 | 1,307 | |||||
| Other liabilities | 574 | 573 | ||||
| Regulatory liabilities (Note 3) | 592 | 555 | ||||
| Deferred income taxes | 685 | 673 | ||||
| Long-term debt | 5,780 | 5,805 | ||||
| Capital lease obligations | 316 | 309 | ||||
| 9,235 | 9,222 | |||||
| Shareholders' equity | ||||||
| Common shares (a)(Note 4) | 3,050 | 3,036 | ||||
| Preference shares | 912 | 912 | ||||
| Additional paid-in capital | 15 | 14 | ||||
| Accumulated other comprehensive loss | (96 | ) | (95 | ) | ||
| Retained earnings | 932 | 868 | ||||
| 4,813 | 4,735 | |||||
| Non-controlling interests (Note 5) | 246 | 208 | ||||
| 5,059 | 4,943 | |||||
| $ | 14,294 | $ | 14,165 | |||
| (a) no par value: unlimited authorized shares; 189.3 million and 188.8 million issued and outstanding as at March 31, 2012 and December 31, 2011, respectively | ||||||
| Commitments and Contingent Liabilities (Notes 17 and 19) | ||||||
| See accompanying Notes to Interim Consolidated Financial Statements | ||||||
| Fortis Inc. | ||||||
| Consolidated Statements of Earnings (Unaudited) | ||||||
| For the three months ended March 31 | ||||||
| (in millions of Canadian dollars, except per share amounts) | ||||||
| Quarter Ended | ||||||
| 2012 | 2011 | |||||
| Revenue | $ | 1,149 | $ | 1,159 | ||
| Expenses | ||||||
| Energy supply costs | 566 | 603 | ||||
| Operating | 214 | 210 | ||||
| Depreciation and amortization | 119 | 103 | ||||
| 899 | 916 | |||||
| Operating income | 250 | 243 | ||||
| Other income (expenses), net (Note 8) | (3 | ) | 8 | |||
| Finance charges (Note 9) | 91 | 92 | ||||
| Earnings before income taxes | 156 | 159 | ||||
| Income taxes (Note 10) | 23 | 31 | ||||
| Net earnings | $ | 133 | $ | 128 | ||
| Net earnings attributable to: | ||||||
| Non-controlling interests | $ | 1 | $ | 1 | ||
| Preference equity shareholders | 11 | 11 | ||||
| Common equity shareholders | 121 | 116 | ||||
| $ | 133 | $ | 128 | |||
| Earnings per common share (Note 11) | ||||||
| Basic | $ | 0.64 | $ | 0.66 | ||
| Diluted | $ | 0.62 | $ | 0.64 | ||
| See accompanying Notes to Interim Consolidated Financial Statements | ||||||
| Fortis Inc. | |||||||
| Consolidated Statements of Comprehensive Income (Unaudited) | |||||||
| For the three months ended March 31 | |||||||
| (in millions of Canadian dollars) | |||||||
| Quarter Ended | |||||||
| 2012 | 2011 | ||||||
| Net earnings | $ | 133 | $ | 128 | |||
| Other comprehensive (loss) income | |||||||
| Unrealized foreign currency translation losses, net of hedging activities and tax | (2 | ) | (3 | ) | |||
| Unrealized employee future benefits gains, net of tax | 1 | - | |||||
| (1 | ) | (3 | ) | ||||
| Comprehensive income | $ | 132 | $ | 125 | |||
| Comprehensive income attributable to: | |||||||
| Non-controlling interests | $ | 1 | $ | 1 | |||
| Preference equity shareholders | 11 | 11 | |||||
| Common equity shareholders | 120 | 113 | |||||
| $ | 132 | $ | 125 | ||||
| See accompanying Notes to Interim Consolidated Financial Statements | |||||||
| Fortis Inc. | |||||||
| Consolidated Statements of Cash Flows (Unaudited) | |||||||
| For the three months ended March 31 | |||||||
| (in millions of Canadian dollars) | |||||||
| Quarter Ended | |||||||
| 2012 | 2011 | ||||||
| Operating activities | |||||||
| Net earnings | $ | 133 | $ | 128 | |||
| Items not affecting cash: | |||||||
| Depreciation - utility capital assets and income producing properties | 107 | 95 | |||||
| Amortization - intangible assets | 11 | 9 | |||||
| Amortization - other | 1 | (1 | ) | ||||
| Deferred income taxes | 5 | (2 | ) | ||||
| Accrued employee future benefits | 4 | 4 | |||||
| Equity component of allowance for funds used during construction | (2 | ) | (5 | ) | |||
| Other | (14 | ) | (1 | ) | |||
| Change in long-term regulatory assets and liabilities | 4 | 18 | |||||
| Change in non-cash operating working capital (Note 13) | 79 | 57 | |||||
| 328 | 302 | ||||||
| Investing activities | |||||||
| Change in other assets and other liabilities | 4 | (2 | ) | ||||
| Capital expenditures - utility capital assets | (211 | ) | (218 | ) | |||
| Capital expenditures - income producing properties | (5 | ) | (3 | ) | |||
| Capital expenditures - intangible assets | (13 | ) | (11 | ) | |||
| Contributions in aid of construction | 14 | 12 | |||||
| Proceeds on sale of utility capital assets and income producing properties | - | 5 | |||||
| (211 | ) | (217 | ) | ||||
| Financing activities | |||||||
| Change in short-term borrowings | (83 | ) | (98 | ) | |||
| Repayments of long-term debt and capital lease obligations | (4 | ) | (5 | ) | |||
| Net borrowings under committed credit facilities | 7 | 15 | |||||
| Advances from non-controlling interests | 41 | 17 | |||||
| Issue of common shares, net of costs and dividends reinvested | 2 | 11 | |||||
| Dividends | |||||||
| Common shares, net of dividends reinvested | (44 | ) | (35 | ) | |||
| Preference shares | (11 | ) | (11 | ) | |||
| Subsidiary dividends paid to non-controlling interests | (2 | ) | (2 | ) | |||
| (94 | ) | (108 | ) | ||||
| Change in cash and cash equivalents | 23 | (23 | ) | ||||
| Cash and cash equivalents, beginning of period | 87 | 107 | |||||
| Cash and cash equivalents, end of period | $ | 110 | $ | 84 | |||
| Supplementary Information to Consolidated Statements of Cash Flows (Note 13) | |||||||
| See accompanying Notes to Interim Consolidated Financial Statements | |||||||
| Fortis Inc. | |||||||||||||||||||
| Consolidated Statements of Changes in Equity (Unaudited) | |||||||||||||||||||
| For the three months ended March 31 | |||||||||||||||||||
| (in millions of Canadian dollars) | |||||||||||||||||||
| Common Shares | Preference Shares | Additional Paid-in Capital | Accumulated Other Comprehensive Loss | Retained Earnings | Non- Controlling Interests | Total Equity | |||||||||||||
| (Note 4) | |||||||||||||||||||
| As at December 31, 2011 | $ | 3,036 | $ | 912 | $ | 14 | $ | (95 | ) | $ | 868 | $ | 208 | $ | 4,943 | ||||
| Net earnings | - | - | - | - | 132 | 1 | 133 | ||||||||||||
| Other comprehensive loss | - | - | - | (1 | ) | - | - | (1 | ) | ||||||||||
| Common share issues | 14 | - | - | - | - | - | 14 | ||||||||||||
| Stock-based compensation | - | - | 1 | - | - | - | 1 | ||||||||||||
| Advances from non-controlling interests | - | - | - | - | - | 41 | 41 | ||||||||||||
| Foreign currency translation impacts | - | - | - | - | - | (2 | ) | (2 | ) | ||||||||||
| Subsidiary dividends paid to non-controlling interests | - | - | - | - | - | (2 | ) | (2 | ) | ||||||||||
| Dividends declared on common shares ($0.30 per share) | - | - | - | - | (57 | ) | - | (57 | ) | ||||||||||
| Dividends declared on preference shares | - | - | - | - | (11 | ) | - | (11 | ) | ||||||||||
| As at March 31, 2012 | $ | 3,050 | $ | 912 | $ | 15 | $ | (96 | ) | $ | 932 | $ | 246 | $ | 5,059 | ||||
| As at December 31, 2010 | $ | 2,575 | $ | 912 | $ | 12 | $ | (108 | ) | $ | 774 | $ | 162 | $ | 4,327 | ||||
| Net earnings | - | - | - | - | 127 | 1 | 128 | ||||||||||||
| Other comprehensive loss | - | - | - | (3 | ) | - | - | (3 | ) | ||||||||||
| Common share issues | 28 | - | (1 | ) | - | - | - | 27 | |||||||||||
| Stock-based compensation | - | - | 1 | - | - | - | 1 | ||||||||||||
| Advances from non-controlling interests | - | - | - | - | - | 17 | 17 | ||||||||||||
| Foreign currency translation impacts | - | - | - | - | - | (3 | ) | (3 | ) | ||||||||||
| Subsidiary dividends paid to non-controlling interests | - | - | - | - | - | (2 | ) | (2 | ) | ||||||||||
| Dividends declared on common shares ($0.29 per share) | - | - | - | - | (51 | ) | - | (51 | ) | ||||||||||
| Dividends declared on preference shares | - | - | - | - | (11 | ) | - | (11 | ) | ||||||||||
| As at March 31, 2011 | $ | 2,603 | $ | 912 | $ | 12 | $ | (111 | ) | $ | 839 | $ | 175 | $ | 4,430 | ||||
| See accompanying Notes to Consolidated Financial Statements | |||||||||||||||||||
| FORTIS INC. |
| NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS |
| For the three months ended March 31, 2012 and 2011 (unless otherwise stated) |
| (Unaudited) |
1. DESCRIPTION OF THE BUSINESS
Nature of Operations
Fortis Inc. ("Fortis" or the "Corporation") is principally an international distribution utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated generation assets, and commercial office and retail space and hotels, which are treated as two separate segments. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each reporting segment operates as an autonomous unit, assumes profit and loss responsibility and is accountable for its own resource allocation.
The following outlines each of the Corporation's reportable segments and is consistent with the basis of segmentation as disclosed in the Corporation's 2011 annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States ("US GAAP").
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric utilities in Canada and the Caribbean by utility are as follows:
- Regulated Gas Utilities - Canadian: Includes the FortisBC Energy companies, which is comprised of FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc.
- Regulated Electric Utilities - Canadian: Includes FortisAlberta; FortisBC Electric; Newfoundland Power; and Other Canadian Electric Utilities, which includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power Inc., Cornwall Street Railway, Light and Power Company, Limited and Algoma Power Inc.
- Regulated Electric Utilities - Caribbean: Includes Caribbean Utilities, in which Fortis holds an approximate 60% controlling ownership interest; wholly owned Fortis Turks and Caicos, which includes FortisTCI Limited and Atlantic Equipment & Power (Turks and Caicos) Ltd.; and Belize Electricity, in which Fortis held an approximate 70% controlling ownership interest up to June 20, 2011. Effective June 20, 2011, the Government of Belize ("GOB") expropriated the Corporation's investment in Belize Electricity. As a result of no longer controlling the operations of the utility, Fortis discontinued the consolidation method of accounting for Belize Electricity, effective June 20, 2011.
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of non-regulated generation assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New York State.
NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns and operates 22 hotels, collectively representing 4,300 rooms in eight Canadian provinces, and approximately 2.7 million square feet of commercial office and retail space primarily in Atlantic Canada.
CORPORATE AND OTHER
The Corporate and Other segment includes Fortis net corporate expenses, net expenses of non-regulated FortisBC Holdings Inc. ("FHI") corporate-related activities, and the financial results of FHI's 30% ownership interest in CustomerWorks Limited Partnership "(CWLP") and of FHI's non-regulated wholly owned subsidiary FortisBC Alternative Energy Services Inc. CWLP provides billing and customer care services to utilities, municipalities and certain energy companies. The contracts between CWLP and the FortisBC Energy companies ended on December 31, 2011.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements have been prepared in accordance with US GAAP for interim financial statements. As a result, these interim consolidated financial statements do not include all of the information and disclosures required in the annual consolidated financial statements and should be read in conjunction with the Corporation's 2011 annual audited consolidated financial statements prepared in accordance with US GAAP and voluntarily filed on the System for Electronic Document Analysis and Retrieval ("SEDAR") by Fortis on March 16, 2012 (the "Corporation's 2011 US GAAP annual audited consolidated financial statements"). In management's opinion, the interim consolidated financial statements include all adjustments that are of a recurring nature and necessary to present fairly the financial position of the Corporation.
Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Because of natural gas consumption patterns, most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters. Given the diversified group of companies, seasonality may vary.
The preparation of financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period in which they become known.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2012.
An evaluation of subsequent events through May 1, 2012, the date these interim consolidated financial statements were approved by the Audit Committee of the Board of Directors, was completed to determine whether circumstances warranted recognition and disclosure of events or transactions in the interim consolidated financial statements as at March 31, 2012.
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements have been prepared following the same accounting policies and methods as those used in preparing the Corporation's 2011 US GAAP annual audited consolidated financial statements, except as described below.
Presentation of Comprehensive Income
Effective January 1, 2012, the Corporation adopted the amendments to Accounting Standards Codification ("ASC") Topic 220, Comprehensive Income. The amended standard requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. Fortis continues to report the components of comprehensive income in a separate but consecutive statement.
Testing Goodwill for Impairment
Effective January 1, 2012, the Corporation adopted the amendments to ASC Topic 350, Goodwill. The amended standard allows entities testing goodwill for impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. If the qualitative factors indicate that the fair value of the reporting unit is more likely than not (greater than a 50% chance) to be greater than the carrying value, then the two-step impairment test, including the quantification of the fair value of the reporting unit, would not be required. In adopting the amendments, Fortis will perform a qualitative assessment before calculating the fair value of its reporting units when it performs its annual impairment test on October 1.
Fair Value Measurement
Effective January 1, 2012, the Corporation adopted the amendments to ASC Topic 820, Fair Value Measurements and Disclosures. The amended standard improves comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with US GAAP. The amendment does not change what items are measured at fair value but instead makes various changes to the guidance pertaining to how fair value is measured. The above-noted changes did not materially impact the Corporation's consolidated financial statements for the three months ended March 31, 2012.
Changes in Accounting Policies
Effective January 1, 2012, the FortisBC Energy companies prospectively adopted the policy of accruing for non-asset retirement obligation ("non-ARO") removal costs in depreciation expense, as requested in their 2012-2013 Revenue Requirements Applications and subsequently approved by the regulator in its April 2012 rate decision. The accrual of estimated non-ARO removal costs is included in depreciation expense and the provision balance is recognized as a long-term regulatory liability. Actual non-ARO removal costs, net of salvage proceeds, are recorded against the regulatory liability when incurred. Non-ARO removal costs are direct costs incurred by the FortisBC Energy companies in taking assets out of service, whether through actual removal of the assets or through disconnection of the assets from the transmission or distribution system. Prior to 2012 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, $3 million of non-ARO removal costs were recognized in operating expenses.
Prior to 2012 variances from forecast, adjusted for certain revenue and cost variances which flowed through to customers, for rate-setting purposes were shared equally between customers and FortisBC Electric. Prospectively from January 1, 2012, the above sharing of positive or negative variances is no longer in effect pursuant to the utility's filed 2012-2013 Revenue Requirements Application, which is subject to regulatory approval and reflects a cost of service rate-setting methodology. Beginning in 2012 variances from forecast for rate-setting purposes related to electricity revenue, purchased power costs and certain other costs, are subject to full deferral account treatment, to be recovered from, or refunded to, customers in future rates and, therefore, are not subject to the sharing mechanism that existed prior to 2012 and do not impact earnings in 2012.
3. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided below. A detailed description of the nature of the Corporation's regulatory assets and liabilities is provided in Note 7 to the Corporation's 2011 US GAAP annual audited consolidated financial statements.
| As at | ||||
| March 31, | December 31, | |||
| ($ millions) | 2012 | 2011 | ||
| Regulatory assets | ||||
| Deferred income taxes | 645 | 630 | ||
| Employee future benefits | 425 | 428 | ||
| Rate stabilization accounts - FortisBC Energy companies | 91 | 105 | ||
| Deferred lease costs - FortisBC Electric | 78 | 70 | ||
| Rate stabilization accounts - electric utilities | 55 | 55 | ||
| Replacement energy deferral - Point Lepreau (1) | 47 | 47 | ||
| Deferred energy management costs | 39 | 36 | ||
| Deferred losses on disposal of utility capital assets | 28 | 23 | ||
| Customer Care Enhancement Project cost deferral | 25 | 13 | ||
| Deferred operating overhead costs | 24 | 22 | ||
| Income taxes recoverable on other post-employment benefit ("OPEB") plans | 22 | 22 | ||
| Whistler pipeline contribution deferral | 16 | 16 | ||
| Alberta Electric System Operator ("AESO") charges deferral | 11 | 44 | ||
| Deferred development costs for capital | 11 | 11 | ||
| Pension cost variance deferral | 11 | 10 | ||
| Alternative energy projects cost deferral | 9 | 8 | ||
| Deferred costs - smart meters | 8 | 8 | ||
| Other regulatory assets | 74 | 71 | ||
| Total regulatory assets | 1,619 | 1,619 | ||
| Less: current portion | (168 | ) | (219 | ) |
| Long-term regulatory assets | 1,451 | 1,400 | ||
| (1) New Brunswick Power Point Lepreau Nuclear Generating Station | ||||
| As at | ||||
| March 31, | December 31, | |||
| ($ millions) | 2012 | 2011 | ||
| Regulatory liabilities | ||||
| Non-ARO removal cost provision | 359 | 354 | ||
| Rate stabilization accounts - FortisBC Energy companies | 187 | 127 | ||
| Rate stabilization accounts - electric utilities | 38 | 33 | ||
| Income tax variance deferral | 10 | 12 | ||
| Deferred interest | 10 | 10 | ||
| AESO charges deferral | 9 | 12 | ||
| Southern Crossing Pipeline deferral | 7 | 8 | ||
| Performance-based rate-setting incentive liabilities | 6 | 7 | ||
| Unrecognized net gains on disposal of utility capital assets | 6 | 6 | ||
| Other regulatory liabilities | 36 | 29 | ||
| Total regulatory liabilities | 668 | 598 | ||
| Less: current portion | (76 | ) | (43 | ) |
| Long-term regulatory liabilities | 592 | 555 | ||
4. COMMON SHARES
Common shares issued during the period were as follows:
| Quarter Ended | |||
| March 31, 2012 | |||
| Number of | |||
| Shares | Amount | ||
| (in thousands) | ($ millions) | ||
| Balance, beginning of period | 188,828 | 3,036 | |
| Dividend Reinvestment Plan | 400 | 13 | |
| Consumer Share Purchase Plan | 13 | - | |
| Stock Option Plans | 33 | 1 | |
| Balance, end of period | 189,274 | 3,050 | |
5. NON-CONTROLLING INTERESTS
| Quarter Ended | ||
| March 31 | ||
| ($ millions) | 2012 | 2011 |
| Waneta Expansion Limited Partnership ("Waneta Partnership") | 157 | 128 |
| Caribbean Utilities | 70 | 73 |
| Mount Hayes Limited Partnership (Note 17) | 12 | - |
| Preference shares of Newfoundland Power | 7 | 7 |
| 246 | 208 | |
6. STOCK-BASED COMPENSATION PLANS
In January 2012 21,417 Deferred Share Units ("DSUs") were granted to the Corporation's Board of Directors, representing the equity component of the Directors' annual compensation and, where opted, their annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation.
In March 2012 44,863 Performance Share Units ("PSUs") were paid out to the President and Chief Executive Officer ("CEO") of the Corporation at $32.14 per PSU, for a total of approximately $1.4 million. The payout was made upon the three-year maturation period in respect of the PSU grant made in March 2009 and the President and CEO satisfying the payment requirements, as determined by the Human Resources Committee of the Board of Directors of Fortis.
Stock-based compensation expense of $1.2 million was recognized for the three months ended March 31, 2012 ($1.5 million for the three months ended March 31, 2011).
7. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group registered retirement savings plans for employees. The Corporation and certain subsidiaries also offer OPEB plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following table.
| Quarter Ended March 31 | ||||||||
| Defined Benefit | ||||||||
| Pension Plans | OPEB Plans | |||||||
| ($ millions) | 2012 | 2011 | 2012 | 2011 | ||||
| Components of net benefit cost: | ||||||||
| Service costs | 7 | 5 | 2 | 1 | ||||
| Interest costs | 12 | 12 | 3 | 3 | ||||
| Expected return on plan assets | (12 | ) | (12 | ) | - | - | ||
| Amortization of actuarial losses | 6 | 5 | 1 | 1 | ||||
| Amortization of past service costs/plan amendments | - | - | (1 | ) | (1 | ) | ||
| Regulatory adjustments | (1 | ) | (2 | ) | 1 | 1 | ||
| Net benefit cost | 12 | 8 | 6 | 5 | ||||
For the three months ended March 31, 2012, the Corporation expensed $4 million ($4 million for the three months ended March 31, 2011) related to defined contribution pension plans.
8. OTHER INCOME (EXPENSES), NET
| Quarter Ended | |||
| March 31 | |||
| ($ millions) | 2012 | 2011 | |
| Equity component of allowance for funds used during construction | 2 | 5 | |
| Interest income | 1 | 1 | |
| Net foreign exchange loss | (2 | ) | - |
| Acquisition-related expenses | (4 | ) | - |
| Other income, net of expenses | - | 2 | |
| (3 | ) | 8 | |
The net foreign exchange loss includes an approximate $1.5 million foreign exchange loss on the translation into Canadian dollars of the Corporation's long-term other asset associated with Belize Electricity (Note 18).
The acquisition-related expenses are associated with the proposed acquisition of CH Energy Group, Inc. ("CH Energy Group"), as announced by the Corporation on February 21, 2012.
9. FINANCE CHARGES
| Quarter Ended | |||||
| March 31 | |||||
| ($ millions) | 2012 | 2011 | |||
| Interest | - Long-term debt and capital lease obligations | 94 | 93 | ||
| - Short-term borrowings and other | 1 | 4 | |||
| Debt component of allowance for funds used during construction | (4 | ) | (5 | ) | |
| 91 | 92 | ||||
10. INCOME TAXES
Income taxes differ from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory income tax rate to earnings before income taxes. The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.
| Quarter Ended | ||||
| March 31 | ||||
| ($ millions, except as noted) | 2012 | 2011 | ||
| Combined Canadian federal and provincial statutory income tax rate | 29.0 | % | 30.5 | % |
| Statutory income tax rate applied to earnings before income taxes | 45 | 48 | ||
| Difference between Canadian statutory rate and rates applicable to foreign | ||||
| subsidiaries | (5 | ) | (5 | ) |
| Difference in Canadian provincial statutory rates applicable to subsidiaries | ||||
| in different Canadian jurisdictions | (1 | ) | (2 | ) |
| Items capitalized for accounting purposes but expensed for income tax | ||||
| purposes | (19 | ) | (16 | ) |
| Difference between capital cost allowance and amounts claimed for accounting | ||||
| purposes | 3 | 2 | ||
| Non-deductible expenses | 1 | 1 | ||
| Difference between enacted and substantially enacted income tax rates | ||||
| associated with Part VI.1 tax | - | 1 | ||
| Other | (1 | ) | 2 | |
| Income taxes | 23 | 31 | ||
| Effective tax rate | 14.7 | % | 19.5 | % |
As at March 31, 2012, the Corporation had approximately $96 million (December 31, 2011 - $86 million) in non-capital and capital loss carryforwards, of which $13 million (December 31, 2011 - $13 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2014 and 2032.
11. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS was calculated using the treasury stock method for options and the "if-converted" method for convertible securities.
EPS were as follows:
| Quarter Ended March 31 | ||||||
| 2012 | 2011 | |||||
| Earnings | Weighted | Earnings | Weighted | |||
| to Common | Average | to Common | Average | |||
| Shareholders | Shares | Shareholders | Shares | |||
| ($ millions) | (in millions) | EPS | ($ millions) | (in millions) | EPS | |
| Basic EPS | 121 | 189.0 | $ 0.64 | 116 | 175.0 | $ 0.66 |
| Effect of potential dilutive | ||||||
| securities: | ||||||
| Stock Options | - | 1.0 | - | 1.2 | ||
| Preference Shares | 4 | 10.3 | 4 | 10.1 | ||
| Convertible Debentures | - | - | 1 | 1.4 | ||
| Diluted EPS | 125 | 200.3 | $ 0.62 | 121 | 187.7 | $ 0.64 |
12. SEGMENTED INFORMATION
Information by reportable segment is as follows:
| REGULATED | NON-REGULATED | ||||||||||||||||
| Gas Utilities | Electric Utilities | ||||||||||||||||
| Quarter Ended March 31, 2012 ($ millions) | FortisBC Energy Companies - Canadian | | Fortis Alberta | FortisBC Electric | Newfound- land Power | Other Canadian | Total Electric Canadian | Electric Caribbean | | Fortis Generation | Fortis Properties | Corporate and Other | | Inter- segment eliminations | | Consolidated | |
| Revenue | 548 | 108 | 87 | 192 | 91 | 478 | 63 | 9 | 52 | 6 | (7 | ) | 1,149 | ||||
| Energy supply costs | 302 | - | 25 | 142 | 58 | 225 | 40 | - | - | - | (1 | ) | 566 | ||||
| Operating expenses | 70 | 39 | 21 | 20 | 12 | 92 | 8 | 3 | 40 | 3 | (2 | ) | 214 | ||||
| Depreci- ation and amorti- zation | 40 | 35 | 12 | 11 | 7 | 65 | 7 | 1 | 5 | 1 | - | 119 | |||||
| Operating income | 136 | 34 | 29 | 19 | 14 | 96 | 8 | 5 | 7 | 2 | (4 | ) | 250 | ||||
| Other income (expenses), net | - | 2 | - | - | - | 2 | - | 1 | - | (5 | ) | (1 | ) | (3 | ) | ||
| Finance charges | 35 | 15 | 10 | 9 | 5 | 39 | 4 | 1 | 6 | 11 | (5 | ) | 91 | ||||
| Income tax expense (recovery) | 19 | - | 3 | 3 | 2 | 8 | - | - | - | (4 | ) | - | 23 | ||||
| Net earnings (loss) | 82 | 21 | 16 | 7 | 7 | 51 | 4 | 5 | 1 | (10 | ) | - | 133 | ||||
| Non-contro- lling interests | - | - | - | - | - | - | 1 | - | - | - | - | 1 | |||||
| Preference share dividends | - | - | - | - | - | - | - | - | - | 11 | - | 11 | |||||
| Net earnings (loss) attributable to common equity shareholders | 82 | 21 | 16 | 7 | 7 | 51 | 3 | 5 | 1 | (21 | ) | - | 121 | ||||
| Goodwill | 913 | 227 | 221 | - | 63 | 511 | 139 | - | - | - | - | 1,563 | |||||
| Identifiable assets | 4,621 | 2,476 | 1,677 | 1,266 | 690 | 6,109 | 708 | 612 | 612 | 468 | (399 | ) | 12,731 | ||||
| Total assets | 5,534 | 2,703 | 1,898 | 1,266 | 753 | 6,620 | 847 | 612 | 612 | 468 | (399 | ) | 14,294 | ||||
| Gross capital expenditures (1) | 46 | 79 | 17 | 15 | 9 | 120 | 10 | 48 | 5 | - | - | 229 | |||||
| Quarter Ended | |||||||||||||||||
| March 31, 2011 | |||||||||||||||||
| ($ millions) | |||||||||||||||||
| Revenue | 574 | 100 | 83 | 183 | 91 | 457 | 75 | 7 | 50 | 6 | (10 | ) | 1,159 | ||||
| Energy supply costs | 344 | - | 23 | 134 | 60 | 217 | 46 | - | - | - | (4 | ) | 603 | ||||
| Operating expenses | 74 | 35 | 18 | 20 | 12 | 85 | 11 | 3 | 37 | 2 | (2 | ) | 210 | ||||
| Depreci- ation and amorti- zation | 27 | 33 | 11 | 10 | 6 | 60 | 9 | 1 | 5 | 1 | - | 103 | |||||
| Operating income | 129 | 32 | 31 | 19 | 13 | 95 | 9 | 3 | 8 | 3 | (4 | ) | 243 | ||||
| Other income (expenses), net | 3 | 3 | 1 | - | - | 4 | 1 | 1 | - | - | (1 | ) | 8 | ||||
| Finance charges | 34 | 13 | 10 | 9 | 5 | 37 | 5 | 1 | 6 | 14 | (5 | ) | 92 | ||||
| Income tax expense (recovery) | 23 | 1 | 3 | 4 | 2 | 10 | - | - | 1 | (3 | ) | - | 31 | ||||
| Net earnings (loss) | 75 | 21 | 19 | 6 | 6 | 52 | 5 | 3 | 1 | (8 | ) | - | 128 | ||||
| Non- contro- lling interests | - | - | - | - | - | - | 1 | - | - | - | - | 1 | |||||
| Preference share dividends | - | - | - | - | - | - | - | - | - | 11 | - | 11 | |||||
| Net earnings (loss) attribu- table to common equity share- holders | 75 | 21 | 19 | 6 | 6 | 52 | 4 | 3 | 1 | (19 | ) | - | 116 | ||||
| Goodwill | 913 | 227 | 221 | - | 63 | 511 | 133 | - | - | - | - | 1,557 | |||||
| Identifi- able assets | 4,397 | 2,188 | 1,613 | 1,244 | 658 | 5,703 | 775 | 422 | 576 | 473 | (416 | ) | 11,930 | ||||
| Total assets | 5,310 | 2,415 | 1,834 | 1,244 | 721 | 6,214 | 908 | 422 | 576 | 473 | (416 | ) | 13,487 | ||||
| Gross capital expendi- tures (1) | 48 | 85 | 30 | 14 | 8 | 137 | 21 | 23 | 3 | - | - | 232 | |||||
| (1) | Relates to cash payments to acquire or construct utility capital assets, including amounts for AESO transmission-related capital projects, income producing properties and intangible assets, as reflected on the consolidated statements of cash flows |
Related party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The significant related party inter-segment transactions primarily related to: (i) the sale of energy from Fortis Generation to Belize Electricity, up to June 20, 2011; (ii) electricity sales from Newfoundland Power to Fortis Properties; and (iii) finance charges on related party borrowings. The significant related party inter-segment transactions for the three months ended March 31, 2012 and 2011 were as follows:
| Significant Inter-Segment Transactions | Quarter Ended | ||
| March 31 | |||
| ($ millions) | 2012 | 2011 | |
| Sales from Fortis Generation to Regulated Electric Utilities - Caribbean | - | 4 | |
| Sales from Newfoundland Power to Fortis Properties | 2 | 1 | |
| Inter-segment finance charges on lending from: | |||
| Corporate to Regulated Electric Utilities - Caribbean | 1 | 1 | |
| Corporate to Fortis Generation | - | 1 | |
| Corporate to Fortis Properties | 4 | 3 | |
| The significant inter-segment asset balances were as follows: | |||
| As at March 31 | |||
| ($ millions) | 2012 | 2011 | |
| Inter-segment lending from: | |||
| Fortis Generation to Other Canadian Electric Utilities | 20 | 20 | |
| Corporate to Regulated Electric Utilities - Canadian | - | 50 | |
| Corporate to Regulated Electric Utilities - Caribbean | 76 | 58 | |
| Corporate to Fortis Generation | 20 | 50 | |
| Corporate to Fortis Properties | 257 | 222 | |
| Other inter-segment assets | 26 | 16 | |
| Total inter-segment eliminations | 399 | 416 | |
13. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
| Quarter Ended | ||||
| March 31 | ||||
| ($ millions) | 2012 | 2011 | ||
| Cash paid for: | ||||
| Interest | 80 | 81 | ||
| Income taxes | 33 | 24 | ||
| Change in non-cash operating working capital: | ||||
| Accounts receivable | (59 | ) | (36 | ) |
| Prepaid expenses | 2 | (1 | ) | |
| Regulatory assets - current portion | 43 | (5 | ) | |
| Inventories | 58 | 80 | ||
| Accounts payable and other current liabilities | 9 | (7 | ) | |
| Regulatory liabilities - current portion | 26 | 26 | ||
| 79 | 57 | |||
| Non-cash investing and financing activities: | ||||
| Common share dividends reinvested | 13 | 16 | ||
| Additions to utility capital assets included in accounts payable | 7 | 41 | ||
| Exercise of stock options into common shares | - | 1 | ||
14. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Corporation generally limits the use of derivative instruments to those that qualify as accounting or economic hedges. As at 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.
Volume of Derivative Activity
As at March 31, 2012, FEI and FEVI had the following notional volumes related to an outstanding foreign exchange forward contract and natural gas derivatives, designated for regulatory approval, that are expected to be settled as outlined below.
| 2012 | 2013 | 2014 | ||
| Foreign Exchange Forward Contract: | ||||
| Cash exposure ($ millions) | 1 | - | - | |
| Weighted average CDN$ to US$ exchange rate | 1.00 | - | - | |
| Natural Gas Derivatives: | ||||
| Swaps and options (petajoules) | 26 | 18 | 7 | |
| Gas purchase contract premiums (petajoules) | 70 | 20 | 9 | |
Presentation of Derivative Instruments in the Consolidated Financial Statements
In the Corporation's consolidated balance sheets, derivative instruments are presented on a net basis by counterparty, where the right of offset exists. The net balances include outstanding cash collateral associated with derivative positions.
The Corporation's outstanding derivative balances were as follows:
| As at | ||
| March 31, | December 31, | |
| ($ millions) | 2012 | 2011 |
| Gross derivatives balance (1) | 132 | 136 |
| Netting (2) | - | - |
| Cash collateral | - | - |
| Total derivative balances (3) | 132 | 136 |
| (1) | Refer to Note 15 for a discussion of the valuation techniques used to calculate the fair value of these derivative instruments. |
| (2) | Positions, by counterparty, are netted where the intent and legal right to offset exists. |
| (3) | Unrealized losses of $132 million on commodity risk-related derivative instruments were recognized as current regulatory assets as at March 31, 2012 (December 31, 2011 - $135 million), which would otherwise be recognized on the consolidated statement of comprehensive income or as accumulated other comprehensive loss. These amounts exclude the impact of cash collateral postings. |
Cash flows associated with the settlement of all derivative instruments are included in operating cash flows on the Corporation's consolidated statements of cash flows.
The majority of the FortisBC Energy companies' risk-related derivative instruments contain collateral posting provisions tied to FEI's credit rating. A downgrade of FEI below investment grade by any of the major credit rating agencies could trigger margin calls and other cash requirements under FEI's gas purchase, swap and option contracts. Most of the existing natural gas derivative contracts are in liability positions and might be subject to margin calls and other cash requirements if FEI was downgraded below investment grade.
15. FAIR VALUE MEASUREMENTS
Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value. The Corporation is required to determine the fair value of all derivative instruments.
The three levels of the fair value hierarchy are defined as follows:
| Level 1: | Fair value determined using unadjusted quoted prices in active markets |
| Level 2: | Fair value determined using pricing inputs that are observable |
| Level 3: | Fair value determined using unobservable inputs only when relevant observable inputs are not available |
The fair values of the Corporation's financial instruments, including derivatives, reflect a point-in-time estimate 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.
The following table details the estimated fair value measurements of the Corporation's financial instruments, all of which were measured using Level 2 inputs.
| As at | |||||||||
| Asset (Liability) | March 31, 2012 | December 31, 2011 | |||||||
| Carrying | Estimated | Carrying | Estimated | ||||||
| ($ millions) | Value | Fair Value | Value | Fair Value | |||||
| Other asset - Belize Electricity (1) | 104 | - (2 | ) | 106 | - (2 | ) | |||
| Long-term debt, including current portion | (5,901 | ) | (7,207 | ) | (5,912 | ) | (7,296 | ) | |
| Waneta Partnership promissory note (3) | (45 | ) | (50 | ) | (45 | ) | (49 | ) | |
| Foreign exchange forward contract (4) | - | - | - | - | |||||
| Fuel option contracts (4) | - | - | (1 | ) | (1 | ) | |||
| Natural gas derivatives: (4) | |||||||||
| Swaps and options | (135 | ) | (135 | ) | (135 | ) | (135 | ) | |
| Gas purchase contract premiums | 3 | 3 | - | - | |||||
| (1) | Included in long-term other assets on the consolidated balance sheet |
| (2) | The fair value of the Corporation's expropriated investment in Belize Electricity determined under the GOB's valuation is significantly lower than the fair value determined under the Corporation's independent valuation of the utility. Due to uncertainty in the ultimate amount and ability of the GOB to pay compensation owing to Fortis for the expropriation of Belize Electricity, the Corporation has recorded the long-term other asset at the carrying value of the Corporation's previous investment in Belize Electricity, including foreign exchange impacts. |
| (3) | Included in long-term other liabilities on the consolidated balance sheet |
| (4) | The fair values of the derivatives were recorded in accounts payable and other current liabilities as at March 31, 2012 and December 31, 2011. |
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 prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs.
The fair value of the foreign exchange forward contract was calculated using the present value of cash flows based on a market foreign exchange rate and the foreign exchange forward rate curve. Any change in the fair value of the foreign exchange forward contract at FEI was deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulator.
The fuel option contracts were used by Caribbean Utilities to reduce the impact of volatility in fuel prices on customer rates, as approved by the regulator under the Company's Fuel Price Volatility Management Program. The fuel option contracts matured in March 2012.
The natural gas derivatives are used to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts at the FortisBC Energy companies have floating, rather than fixed, prices. Any resulting gains or losses were recorded in regulatory assets or liabilities in the consolidated balance sheet. The fair value of the natural gas derivatives was calculated using the present value of cash flows based on market prices and forward curves for the commodity cost of natural gas.
The fair values of the foreign exchange forward contract and the natural gas derivatives were estimates of the amounts that the FortisBC Energy companies would have had to receive or pay to terminate the outstanding contracts as at the balance sheet date. As at March 31, 2012, none of the natural gas derivatives were designated as hedges of the natural gas supply contracts. However, any changes in the fair value of the natural gas derivatives were deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulator.
16. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.
| Credit Risk | Risk that a counterparty to a financial instrument might fail to meet its obligations under the terms of the financial instrument. |
| Liquidity Risk | Risk that an entity will encounter difficulty in raising funds to meet commitments associated with financial instruments. |
| Market Risk | Risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices. The Corporation is exposed to foreign exchange risk, interest rate risk and commodity price risk. |
Credit Risk
For cash equivalents, trade and other accounts receivable, and other long-term receivables, the Corporation's credit risk is limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts.
FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at March 31, 2012, the utility's gross credit risk exposure was approximately $156 million, representing the projected value of retailer billings over a 60-day period. The Company has reduced its exposure to approximately $9 million by obtaining from the retailers either a cash deposit, bond, letter of credit or an investment-grade credit rating from a major rating agency, or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.
The FortisBC Energy companies are exposed to credit risk in the event of non-performance by counterparties to derivative financial instruments. To help mitigate credit risk, the FortisBC Energy companies deal with high credit-quality institutions in accordance with established credit-approval practices. The counterparties with which the FortisBC Energy companies have significant transactions are A-rated entities or better. The Company uses netting arrangements to reduce credit risk and net settles payments with counterparties where net settlement provisions exist.
The following table summarizes the FortisBC Energy companies' net credit risk exposure to its counterparties, as well as credit risk exposure to counter parties accounting for greater than 10% net credit exposure.
| As at | ||
| March 31, | December 31, | |
| ($ millions, except for number of customers) | 2012 | 2011 |
| Gross credit exposure before credit collateral (1) | 136 | 136 |
| Credit collateral | - | - |
| Net credit exposure (2) | 136 | 136 |
| Number of counterparties > 10% | 4 | 4 |
| Net exposure to counterparties > 10% | 99 | 104 |
| (1) | Gross credit exposure equals mark-to-market value on physically and financially settled contracts, notes receivable and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported do not include adjustments for time value or liquidity. |
| (2) | Net credit exposure is the gross credit exposure collateral minus credit collateral (cash deposits and letters of credit). |
The Corporation is exposed to credit risk associated with the amount and timing of compensation that Fortis is entitled to receive from the GOB as a result of the expropriation of the Corporation's investment in Belize Electricity by the GOB on June 20, 2011. The Corporation has a long-term other asset of $104 million, including foreign exchange impacts, recognized on the consolidated balance sheet related to its expropriated investment in Belize Electricity (Note 18).
Liquidity Risk
The Corporation's consolidated financial position could be adversely affected if it, or one of its subsidiaries, fails to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the consolidated results of operations and financial position of the Corporation and its subsidiaries, conditions in capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.
To help mitigate liquidity risk, the Corporation and its larger regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed credit facility is available for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at March 31, 2012, average annual consolidated long-term debt maturities and repayments over the next five years are expected to be approximately $265 million. The combination of available credit facilities and relatively low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
As at March 31, 2012, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.2 billion, of which $2.0 billion was unused. The credit facilities are syndicated mostly with the seven largest Canadian banks, with no one bank holding more than 20% of these facilities.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
| As at | |||||||||||
| Corporate | Regulated | Fortis | March 31, | December 31, | |||||||
| ($ millions) | and Other | Utilities | Properties | 2012 | 2011 | ||||||
| Total credit facilities | 845 | 1,389 | 13 | 2,247 | 2,248 | ||||||
| Credit facilities utilized: | |||||||||||
| Short-term borrowings (1) | - | (73 | ) | (3 | ) | (76 | ) | (159 | ) | ||
| Long-term debt (2) | (31 | ) | (50 | ) | - | (81 | ) | (74 | ) | ||
| Letters of credit outstanding | (1 | ) | (65 | ) | - | (66 | ) | (66 | ) | ||
| Credit facilities unused | 813 | 1,201 | 10 | 2,024 | 1,949 | ||||||
| (1) | The weighted average interest rate on short-term borrowings was approximately 1.7% as at March 31, 2012 (December 31, 2011 - 1.2%). |
| (2) | As at March 31, 2012, credit facility borrowings classified as long-term included $16 million (December 31, 2011 - $16 million) that was included in current installments of long-term debt on the consolidated balance sheet. The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 2.0% as at March 31, 2012 (December 31, 2011 - 2.1%). |
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.
The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at March 31, 2012, the Corporation's credit ratings are as follows:
| Standard & Poor's | A-/Credit Watch - Negative (unsecured debt credit rating) |
| DBRS | A(low)/Under Review - Developing Implications (unsecured debt credit rating) |
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.
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investment in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above exposure through the use of US dollar borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange loss or gain on the translation of the Corporation's foreign subsidiaries' earnings, which are denominated in US dollars. The reporting currency of Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy and 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 that are designated as 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 three months ended March 31, 2012 (Note 8).
FEI's US dollar payments under a contract for the implementation of a customer care information system are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. FEI entered into a foreign exchange forward contract to hedge this exposure. FEI has regulatory approval to defer any increase or decrease in the fair value of the foreign exchange forward contract for recovery from, or refund to, customers in future rates.
Interest Rate Risk
The Corporation and its subsidiaries are exposed to interest rate risk associated with short-term borrowings and floating-rate debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk.
Commodity Price Risk
The FortisBC Energy companies are exposed to commodity price risk associated with changes in the market price of natural gas. This risk has been minimized by entering into natural gas derivatives that effectively fix the price of natural gas purchases. The natural gas derivatives are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, subject to regulatory approval, for recovery from, or refund to, customers in future rates.
The price risk-management strategy of the FortisBC Energy companies aims to improve the likelihood that natural gas prices remain competitive with electricity rates, temper gas price volatility on customer rates and reduce the risk of regional price discrepancies. In 2011 the BCUC determined that commodity hedging in the current environment was not a cost-effective means to meet the objectives of price competitiveness and rate stability. The BCUC concurrently denied FEI's 2011-2014 Price Risk Management Plan ("PRMP") with the exception of certain elements to address regional price discrepancies. As a result, the FortisBC Energy companies have suspended all commodity hedging activities, with the exception of certain limited swaps as permitted by the BCUC. The existing hedging contracts will continue in effect through to their maturity and the FortisBC Energy companies' ability to fully recover the commodity cost of gas in customer rates remains unchanged. Any differences between the cost of natural gas purchased and the price of natural gas included in customer rates are recorded as regulatory deferrals and are recovered from, or refunded to, customers in future rates, subject to regulatory approval.
17. COMMITMENTS
There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2011 US GAAP annual audited consolidated financial statements, except as described below.
In January 2012 two First Nations bands each invested approximately $6 million in equity in the Mount Hayes liquefied natural gas storage facility, representing a 15% equity interest in the Mount Hayes Limited Partnership, with FEVI holding the controlling 85% ownership interest (Note 5). The non-controlling interests hold put options, which, if exercised, would require FEVI to repurchase the 15% ownership interest for cash, in accordance with the terms of the partnership agreement.
In April 2012 the December 31, 2011 actuarial valuation of the defined benefit pension plan at Newfoundland Power was completed. As a result Newfoundland Power is required to fund a solvency deficiency of approximately $53.5 million, including interest, over five years beginning in 2012. The increase in funding contributions is expected to be recovered from customers in future rates.
18. EXPROPRIATED ASSETS
Belize Electricity
On June 20, 2011, the GOB enacted legislation leading to the expropriation of the Corporation's investment in Belize Electricity. As a result of no longer controlling the operations of the utility, the Corporation 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 interim consolidated balance sheet.
In October 2011 Fortis commenced an action in the Belize Supreme Court with respect to the challenge of the legality of the expropriation of the Corporation's investment in Belize Electricity and court proceedings are continuing. Fortis commissioned an independent valuation of its expropriated investment in Belize Electricity and submitted its claim for compensation to the GOB in November 2011.
The GOB also commissioned a valuation of Belize Electricity and communicated the results of such valuation in its response to the Corporation's claim for compensation. The fair value of Belize Electricity determined under the GOB's valuation is significantly lower than the fair value determined under the Corporation's valuation. Pursuant to the expropriation action, Fortis is assessing alternative options for obtaining fair compensation from the GOB.
Exploits Partnership
The Exploits Partnership is owned 51% by Fortis Properties and 49% by AbitibiBowater Inc. ("Abitibi"). The Exploits Partnership operated two non-regulated hydroelectric generating facilities in central Newfoundland with a combined capacity of approximately 36 MW. In December 2008 the Government of Newfoundland and Labrador expropriated Abitibi's hydroelectric assets and water rights in Newfoundland, including those of the Exploits Partnership. The newsprint mill in Grand Falls-Windsor closed on February 12, 2009, subsequent to which the day-to-day operations of the Exploits Partnership's hydroelectric generating facilities were assumed by Nalcor Energy as an agent for the Government of Newfoundland and Labrador with respect to expropriation matters. The Government of Newfoundland and Labrador has publicly stated that it is not its intention to adversely affect the business interests of lenders or independent partners of Abitibi in the province. The loss of control over cash flows and operations required Fortis to cease consolidation of the Exploits Partnership, effective February 12, 2009. Discussions between Fortis Properties and Nalcor Energy with respect to expropriation matters are ongoing.
19. CONTINGENT LIABILITIES
The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material effect on the Corporation's consolidated financial position or results of operations.
The following describes the nature of the Corporation's contingent liabilities.
Fortis
Following the announcement of the proposed acquisition of CH Energy Group on February 21, 2012, several complaints, which named Fortis and other defendants, were filed in, or transferred to, the Supreme Court of the State of New York, County of New York, challenging the proposed acquisition. The complaints generally allege that the directors of CH Energy Group breached their fiduciary duties in connection with the proposed transaction and that CH Energy Group, Fortis, FortisUS Inc., and Cascade Acquisition Sub Inc. aided and abetted that breach.
The outcome of these lawsuits is uncertain and cannot be predicted with any certainty and, accordingly, no amount has been accrued in the consolidated financial statements. An adverse judgment for monetary damages could have a material adverse effect on the operations of the surviving company after the completion of the acquisition. A preliminary injunction could delay or jeopardize the completion of the acquisition and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the transaction. Subject to the foregoing, in management's opinion, based upon currently known facts and circumstances, the outcome of such lawsuits is not expected to have a material adverse effect on the consolidated financial condition of Fortis. The defendants intend to vigorously defend themselves against the lawsuits.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of Assessment from Canada Revenue Agency for additional taxes related to the taxation years 1999 through 2003. The exposure has been fully provided for in the consolidated financial statements. FHI has begun the appeal process associated with the assessments.
In 2009 FHI was named, along with other defendants, in an action related to damages to property and chattels, including contamination to sewer lines and costs associated with remediation, related to the rupture in July 2007 of an oil pipeline owned and operated by Kinder Morgan, Inc. FHI has filed a statement of defence. During the second quarter of 2010, FHI was added as a third party in all of the related actions and all claims are expected to be tried at the same time. The amount and outcome of the actions are indeterminable at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
FortisBC Electric
The Government of British Columbia has alleged breaches of the Forest Practices Code and negligence relating to a forest fire near Vaseux Lake and has filed and served a writ and statement of claim against FortisBC Electric dated August 2, 2005. The Government of British Columbia has now disclosed that its claim includes approximately $13.5 million in damages but that it has not fully quantified its damages. In addition, private landowners have filed separate writs and statements of claim dated August 19, 2005 and August 22, 2005 for undisclosed amounts in relation to the same matter. FortisBC Electric and its insurers are defending the claims. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements. A date for mediation of this matter has been set for December 2012.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada, with total assets of more than $14 billion and fiscal 2011 revenue totalling approximately $3.7 billion. The Corporation serves more than 2,000,000 gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State. It also owns hotels and commercial office and retail space in Canada.
The Common Shares, First Preference Shares, Series C; First Preference Shares, Series E; First Preference Shares, Series F; First Preference Shares, Series G; and First Preference Shares, Series H of Fortis are traded on the Toronto Stock Exchange under the symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F, FTS.PR.G and FTS.PR.H, respectively.
| Share Transfer Agent and Registrar: |
| Computershare Trust Company of Canada |
| 9th Floor, 100 University Avenue |
| Toronto, ON M5J 2Y1 |
| T: 514.982.7555 or 1.866.586.7638 |
| F: 416.263.9394 or 1.888.453.0330 |
| W: www.computershare.com/fortisinc |
Additional information, including the Fortis 2011 Annual Information Form, Management Information Circular and Annual Report, are available on SEDAR at www.sedar.com and on the Corporation's web site at www.fortisinc.com.
Contact Information:
Vice President Finance and Chief Financial Officer
Fortis Inc.
709.737.2822