ST. JOHN–S, NEWFOUNDLAND AND LABRADOR — (Marketwired) — 11/01/13 — Fortis Inc. (“Fortis” or the “Corporation”) (TSX: FTS) achieved third quarter net earnings attributable to common equity shareholders of $48 million, or $0.23 per common share, compared to $45 million, or $0.24 per common share, for the third quarter of 2012. Year-to-date net earnings attributable to common equity shareholders were $253 million, or $1.27 per common share, compared to $228 million, or $1.20 per common share, for the same period last year.
Results for the third quarter of 2013 were impacted by the Corporation–s acquisition of CH Energy Group, Inc. (“CH Energy Group”) on June 27, 2013 for US$1.5 billion, including the assumption of US$518 million of debt on closing. The net purchase price of the acquisition was initially financed using proceeds from a $601 million common equity offering and drawings under the Corporation–s committed credit facility. Central Hudson Gas & Electric Corporation (“Central Hudson”), the main business of CH Energy Group, is a regulated transmission and distribution utility that serves 376,000 electricity and gas customers in New York State–s Mid-Hudson River Valley. Central Hudson contributed $12 million to earnings for the third quarter of 2013, comparable with performance in the third quarter of 2012. Due to the common share offering and financing costs associated with the acquisition, earnings per common share for the third quarter of 2013 were not materially impacted by the acquisition of CH Energy Group.
“Central Hudson has successfully integrated into the Fortis family,” says Stan Marshall, President and Chief Executive Officer, Fortis Inc. “The acquisition is expected to be accretive to earnings per common share of Fortis beginning in 2015.”
Regulated utilities comprise approximately 90% of total assets and serve more than 2.4 million customers across Canada and in New York State and the Caribbean. As at September 30, 2013, regulated rate base assets of Fortis exceed $10 billion.
Canadian Regulated Gas Utilities incurred a loss of $14 million compared to a loss of $6 million for the third quarter of 2012. The third quarter is normally a period of lower customer demand due to warmer temperatures. The higher loss largely related to higher operating and maintenance expenses, decreases in the allowed rate of return on common shareholders– equity (“ROE”) and the equity component of capital structure as a result of the regulatory decision related to the first phase of the Generic Cost of Capital (“GCOC”) Proceeding in British Columbia, and lower-than-expected customer additions. The above items were partially offset by earnings contribution from growth in energy infrastructure investment.
Canadian Regulated Electric Utilities contributed earnings of $51 million compared to $55 million for the third quarter of 2012. FortisAlberta–s earnings were approximately $1 million lower quarter over quarter, due to lower net transmission revenue and $1 million of costs related to flooding in southern Alberta in June 2013, largely offset by growth in energy infrastructure investment, customer growth and timing of operating expenses. FortisBC Electric–s earnings decreased $2 million due to a decrease in the interim allowed ROE as a result of the regulatory decision related to the first phase of the GCOC Proceeding in British Columbia, lower pole-attachment revenue and higher effective income taxes. The decreases were partially offset by earnings contribution from growth in energy infrastructure investment and lower-than-expected finance charges. At Newfoundland Power, earnings were $1 million lower quarter over quarter, due to the impact of the reversal of statute-barred Part VI.1 tax in the third quarter of 2012, partially offset by growth in energy infrastructure investment and lower storm-related costs.
In April 2013 Newfoundland Power received a cost of capital decision maintaining the utility–s allowed ROE at 8.8% and its common equity component of capital structure at 45% for 2013 through 2015. In May 2013 the British Columbia Utilities Commission issued its decision, effective January 1, 2013, on the first phase of its GCOC Proceeding. As a result, the allowed ROE for FortisBC Energy Inc. has been set at 8.75%, as compared to 9.50% for 2012, and the common equity component of capital structure has been reduced from 40.0% to 38.5%. The interim allowed ROEs for FortisBC Energy (Vancouver Island) Inc. (“FEVI”), FortisBC Energy (Whistler) Inc. (“FEWI”) and FortisBC Electric were also reduced by 75 basis points for 2013 as a result of the first phase of the GCOC Proceeding, while the common equity components of their capital structures remain unchanged. Final allowed ROEs and capital structures for FEVI, FEWI and FortisBC Electric will be determined in the second phase of the GCOC Proceeding, which is currently underway. A decision on the proceeding is expected in the first half of 2014. FortisAlberta–s final allowed ROE and capital structure for 2013 remain to be determined.
Caribbean Regulated Electric Utilities contributed $6 million to earnings, comparable with the third quarter of 2012.
Non-Regulated Fortis Generation contributed $8 million to earnings, up $3 million quarter over quarter. Improved performance mainly related to increased production in Belize due to higher rainfall.
Non-Utility operations contributed earnings of $6 million compared to $8 million for the third quarter of 2012. The decrease reflected a loss of approximately $2.5 million at Griffith Energy Services, Inc., the non-regulated petroleum supply operations of CH Energy Group, which is comparable with performance in the third quarter of 2012 and reflects the impact of seasonality. Improved performance at Fortis Properties– Hospitality Division partially offset the decrease in earnings.
Corporate and other expenses for the third quarter include $2 million of costs associated with the redemption of preference shares and a $2 million foreign exchange loss, compared to a $3 million foreign exchange loss in the third quarter of 2012. Excluding these impacts, Corporate and other expenses were $17 million for the third quarter, $3 million lower than the third quarter of 2012. The decrease was primarily due to a higher income tax recovery, resulting from the release of income tax provisions in the third quarter of 2013 and the recognition of income tax expense associated with Part VI.1 tax in the third quarter of 2012. Higher capitalized interest associated with the financing of construction of the Corporation–s 51% controlling ownership interest in the Waneta Expansion hydroelectric generating facility (“Waneta Expansion”) was offset by higher interest on credit facility borrowings associated with financing the acquisition of CH Energy Group. The decrease in Corporate and other expenses was partially offset by higher preference share dividends.
Consolidated capital expenditures were approximately $809 million year-to-date 2013. Construction of the $900 million, 335-megawatt Waneta Expansion in British Columbia continues on time and on budget, with completion of the facility expected in spring 2015. Approximately $534 million has been invested in the Waneta Expansion since construction began in late 2010.
Cash flow from operating activities was $680 million year-to-date 2013 compared to $804 million for the same period last year, primarily due to unfavourable changes in working capital.
In July 2013 Fortis issued 10 million 4% Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series K for gross proceeds of $250 million. The proceeds were used to redeem all of the Corporation–s 5.45% First Preference Shares, Series C in July 2013 for $125 million, to repay a portion of credit facility borrowings, and for other general corporate purposes. In October 2013 the Corporation closed a private placement of 10-year US$285 million unsecured notes at 3.84% and 30-year US$40 million unsecured notes at 5.08%. The proceeds were used to repay a portion of US dollar-denominated credit facility borrowings incurred to finance a portion of the CH Energy Group acquisition. In September 2013 FortisAlberta issued 30-year $150 million unsecured debentures at 4.85%, the proceeds of which are being used to repay credit facility borrowings, to fund future capital expenditures and for general corporate purposes.
Fortis has consolidated credit facilities of $2.7 billion, of which $1.9 billion was unused as at September 30, 2013. In August 2013 the Corporation extended the maturity of its $1 billion committed revolving credit facility to July 2018.
“We remain focused on completing our capital projects for 2013, which are expected to total approximately $1.2 billion,” explains Marshall. “Our five-year capital program to the end of 2017 is projected to total $6 billion and will continue to drive growth in earnings and dividends.”
FORWARD-LOOKING INFORMATION
The following Fortis Inc. (“Fortis” or the “Corporation”) Management Discussion and Analysis (“MD&A”) has been prepared in accordance with National Instrument 51-102 – Continuous Disclosure Obligations. The MD&A should be read in conjunction with the interim unaudited consolidated financial statements and notes thereto for the three and nine months ended September 30, 2013 and the MD&A and audited consolidated financial statements for the year ended December 31, 2012 included in the Corporation–s 2012 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States (“US GAAP”) and is presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the Management Discussion and Analysis (“MD&A”) within the meaning of applicable securities laws in Canada (“forward-looking information”). The purpose of the forward-looking information is to provide management–s expectations regarding the Corporation–s future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation. The words “anticipates”, “believes”, “budgets”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management–s current beliefs and is based on information currently available to the Corporation–s management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the Corporation–s forecast gross consolidated capital expenditures for 2013 and total capital spending over the five-year period 2013 through 2017; the expectation that capital investment over the above-noted five-year period will allow utility rate base and hydroelectric generation investment to increase at a combined compound annual growth rate of approximately 6%; the expected nature, timing and capital cost related to the construction of the Waneta Expansion hydroelectric generating facility (“Waneta Expansion”); the expectation that, based on current tax legislation, future earnings will not be materially impacted by Part VI.1 tax; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of cash from operations, borrowings under credit facilities, equity injections from Fortis and long-term debt offerings; the expectation that the combination of available credit facilities and relatively low annual debt maturities and repayments will provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets; the expected consolidated long-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2013; the expected timing of filing of regulatory applications and of receipt of regulatory decisions; the expectation that the acquisition of CH Energy Group, Inc. will be accretive to earnings per common share of Fortis beginning in 2015; and the expectation that the Corporation–s capital expenditure program will support continuing growth in earnings and dividends.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received and the expectation of regulatory stability; FortisAlberta continues to recover its cost of service and earn its allowed rate of return on common shareholders– equity (“ROE”) under performance-based rate-setting, which commenced for a five-year term effective January 1, 2013; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; no material capital project and financing cost overrun related to the construction of the Waneta Expansion; sufficient liquidity and capital resources; the expectation that the Corporation will receive appropriate compensation from the Government of Belize (“GOB”) for the fair value of the Corporation–s investment in Belize Electricity that was expropriated by the GOB; the expectation that Belize Electric Company Limited will not be expropriated by the GOB; the continuation of regulator-approved mechanisms to flow through the commodity cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas commodity prices, electricity prices and fuel prices;
no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans and environmental laws that may materially negatively affect the operations and cash flows of the Corporation and its subsidiaries; no material change in public policies and directions by governments that could materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the ability to report under US GAAP beyond 2014 or the adoption of International Financial Reporting Standards after 2014 that allows for the recognition of regulatory assets and liabilities; the continued tax-deferred treatment of earnings from the Corporation–s Caribbean operations; continued maintenance of information technology infrastructure; continued favourable relations with First Nations; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading “Business Risk Management” in this MD&A, the Corporation–s MD&A for the year ended December 31, 2012 and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. Key risk factors for 2013 include, but are not limited to: uncertainty of the impact a continuation of a low interest rate environment may have on the allowed ROE at certain of the Corporation–s regulated utilities in western Canada; risk associated with the amount of compensation to be paid to Fortis for its investment in Belize Electricity that was expropriated by the GOB; and the timeliness of the receipt of compensation and the ability of the GOB to pay the compensation owing to Fortis.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned gas and electric distribution utility in Canada. Its regulated utilities account for 90% of total assets and serve more than 2.4 million customers across Canada and in New York State and the Caribbean. Fortis owns non-regulated hydroelectric generation assets in Canada, Belize and Upstate New York. The Corporation–s non-utility investments are comprised of hotels and commercial real estate in Canada and petroleum supply operations in the Mid-Atlantic Region of the United States.
Year-to-date September 30, 2013, the Corporation–s electricity distribution systems met a combined peak demand of approximately 6,380 megawatts (“MW”) and its gas distribution system met a peak day demand of 1,238 terajoules (“TJ”). For additional information on the Corporation–s business segments, refer to Note 1 to the Corporation–s interim unaudited consolidated financial statements for the three and nine months ended September 30, 2013 and to the “Corporate Overview” section of the 2012 Annual MD&A.
The Corporation–s main business, utility operations, is highly regulated and the earnings of the Corporation–s regulated utilities are primarily determined under cost of service (“COS”) regulation. Generally under COS regulation, the respective regulatory authority sets customer gas and/or electricity rates to permit a reasonable opportunity for the utility to recover, on a timely basis, estimated costs of providing service to customers, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value (“rate base”). The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on common shareholders– equity (“ROE”) and/or rate of return on rate base assets (“ROA”) depends on the utility achieving the forecasts established in the rate-setting processes. As such, earnings of regulated utilities are generally impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA and equity component of capital structure; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and 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.
When performance-based rate-setting (“PBR”) mechanisms are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover prudent COS and earn its allowed ROE.
SIGNIFICANT ITEMS
Acquisition of CH Energy Group, Inc.: On June 27, 2013, Fortis acquired all of the outstanding common shares of CH Energy Group, Inc. (“CH Energy Group”) for US$65.00 per common share in cash, for an aggregate purchase price of approximately US$1.5 billion, including the assumption of US$518 million of debt on closing. The net purchase price of approximately $1,019 million (US$972 million) was financed through proceeds from the issuance of 18.5 million common shares of Fortis pursuant to the conversion of Subscription Receipts on closing of the acquisition for proceeds of approximately $567 million, net of after-tax expenses, with the balance being initially funded through drawings under the Corporation–s $1 billion committed credit facility.
CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New York. Its main business, Central Hudson Gas & Electric Corporation (“Central Hudson”), is a regulated transmission and distribution (“T&D”) utility serving approximately 300,000 electricity and 76,000 natural gas customers in eight counties of New York State–s Mid-Hudson River Valley. Central Hudson accounts for approximately 93% of the total assets of CH Energy Group and is subject to regulation by the New York State Public Service Commission (“PSC”) under a traditional COS model. CH Energy Group–s non-regulated operations primarily consist of Griffith Energy Services, Inc. (“Griffith”), which mainly supplies petroleum products and related services to approximately 65,000 customers in the Mid-Atlantic Region of the United States.
To obtain regulatory approval of the acquisition, Fortis committed to provide Central Hudson–s customers and community with approximately US$50 million in financial benefits. These incremental benefits outlined in the PSC order approving the acquisition include: (i) US$35 million to cover expenses that would normally be recovered in customer rates; (ii) guaranteed savings to customers of more than US$9 million over five years resulting from the elimination of costs CH Energy Group would otherwise incur as a public company; and (iii) the establishment of a US$5 million Community Benefit Fund to be used for low-income customer and economic development programs for communities and residents of the Mid-Hudson River Valley. In addition, electricity and natural gas customers of Central Hudson will benefit from a delivery rate freeze through to June 30, 2015. The Company is committed to invest US$215 million in capital expenditures over the same two-year period.
The above-noted commitments of US$35 million and US$5 million, together with acquisition-related expenses of approximately US$8 million, were recognized in the Corporation–s earnings for the second quarter of 2013. The acquisition is expected to be accretive to earnings per common share of Fortis beginning in 2015.
For further information on Central Hudson, refer to the “Segmented Results of Operation -Regulated Gas & Electric Utility – United States” section of this MD&A.
First Preference Shares: In July 2013 Fortis issued 10 million 4% Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series K for gross proceeds of $250 million. The proceeds were used to redeem all of the Corporation–s 5.45% First Preference Shares, Series C in July 2013 for $125 million, to repay a portion of credit facility borrowings, and for other general corporate purposes. Approximately $2 million of costs associated with the redemption of First Preference Shares, Series C were expensed in the third quarter.
Long-Term Debt Offering: In September 2013 FortisAlberta issued 30-year $150 million unsecured debentures at 4.85%. The proceeds of the debt offering are being used to repay credit facility borrowings, to fund future capital expenditures and for general corporate purposes.
Part VI.1 Tax: In June 2013 the Government of Canada enacted previously announced legislative changes associated with Part VI.1 tax on the Corporation–s preference share dividends. In accordance with US GAAP, income taxes are required to be recognized based on enacted tax legislation. In the second quarter of 2013, the Corporation recognized an approximate $25 million income tax recovery due to the enactment of higher deductions associated with Part VI.1 tax. The income tax recovery impacted earnings at Newfoundland Power, Maritime Electric and the Corporation as a result of the allocation of Part VI.1 tax in previous years. Currently, all legislative changes associated with Part VI.1 tax are enacted and, as a result, future earnings are not expected to be materially impacted by Part VI.1 tax.
Receipt of Regulatory Decisions: In March 2013 FortisAlberta received a decision from its regulator approving an interim increase in customer distribution rates, effective January 1, 2013, including interim approval of 60% of the revenue requirement associated with certain capital expenditures in 2013 not otherwise recovered under performance-based rates. The Company–s final allowed ROE and capital structure for 2013 remain to be determined.
In April 2013 Newfoundland Power received a cost of capital decision maintaining the utility–s allowed ROE at 8.8% and its common equity component of capital structure at 45% for 2013 through 2015 .
In May 2013 the British Columbia Utilities Commission (“BCUC”) issued its decision, effective January 1, 2013, on the first phase of its Generic Cost of Capital (“GCOC”) Proceeding. As a result, the allowed ROE for FortisBC Energy Inc. (“FEI”) has been set at 8.75%, as compared to 9.50% for 2012, and the common equity component of capital structure has been reduced from 40.0% to 38.5%. The interim allowed ROEs for FortisBC Energy (Vancouver Island) Inc. (“FEVI”), FortisBC Energy (Whistler) Inc. (“FEWI”) and FortisBC Electric were also reduced by 75 basis points for 2013 as a result of the first phase of the GCOC Proceeding, while the common equity components of their capital structures remain unchanged. Final allowed ROEs and capital structures for FEVI, FEWI and FortisBC Electric will be determined in the second phase of the GCOC Proceeding, which is currently underway. A decision on the proceeding is expected in the first half of 2014.
For further discussion on the nature of the above regulatory decisions, refer to the “Material Regulatory Decisions and Applications” section of this MD&A.
Settlement of Expropriation Matters – Exploits River Hydro Partnership: In March 2013 the Corporation and the Government of Newfoundland and Labrador (“Government”) settled all matters, including release from all debt obligations, pertaining to the Government–s December 2008 expropriation of non-regulated hydroelectric generating assets and water rights in central Newfoundland, then owned by the Exploits River Hydro Partnership (“Exploits Partnership”), in which Fortis held an indirect 51% interest. As a result of the settlement, an extraordinary after-tax gain of approximately $22 million was recognized in the first quarter of 2013.
Acquisition of the Electrical Utility Assets from the City of Kelowna: FortisBC Electric acquired the electrical utility assets of the City of Kelowna (the “City”) for approximately $55 million in March 2013, which now allows FortisBC Electric to directly serve some 15,000 customers formerly served by the City. FortisBC Electric had provided the City with electricity under a wholesale tariff and had operated and maintained the City–s electrical utility assets under contract since 2000.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. The Corporation–s business is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Key financial highlights for the third quarter and year-to-date periods ended September 30, 2013 and September 30, 2012 are provided in the following table.
Favourable
Unfavourable
Unfavourable
Favourable
Unfavourable
Unfavourable
Favourable
Unfavourable
Unfavourable
Favourable
Favourable
Unfavourable
Favourable
Favourable
Unfavourable
Favourable
Unfavourable
SEGMENTED RESULTS OF OPERATIONS
The basis of segmentation of the Corporation–s reportable segments is consistent with that disclosed in the 2012 Annual MD&A, except as follows as a result of the acquisition of CH Energy Group. Central Hudson is reported in a new segment “Regulated Gas & Electric Utility – United States”; and the former “Non-Regulated – Fortis Properties” segment is now “Non-Regulated – Non-Utility” and is comprised of Fortis Properties and Griffith.
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Corporation–s regulated utilities, refer to the “Regulatory Highlights” section of this MD&A. A discussion of the financial results of the Corporation–s reporting segments follows.
REGULATED GAS UTILITIES – CANADIAN
FORTISBC ENERGY COMPANIES (1)
Unfavourable
As at September 30, 2013, the total number of customers served by the FortisBC Energy companies was approximately 947,000. Net customer additions year-to-date 2013 were approximately 2,000.
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.
Favourable
Unfavourable
Unfavourable
Favourable
REGULATED GAS & ELECTRIC UTILITY – UNITED STATES
CENTRAL HUDSON
Central Hudson–s electric assets comprised approximately 78% of its total assets as at September 30, 2013, and include approximately 14,000 kilometres of distribution lines and 1,000 kilometres of transmission lines. The electric business met a peak demand of 1,202 MW year-to-date 2013. Central Hudson–s natural gas assets comprise the remaining 22% of its total assets as at September 30, 2013, and include approximately 1,900 kilometres of distribution pipelines and more than 264 kilometres of transmission pipelines. The gas business met a peak day demand of 125 TJ year-to-date 2013, which occurred in the first quarter of 2013.
Central Hudson primarily relies on electricity purchases from third-party providers and the New York Independent System Operator (“NYISO”)-administered energy and capacity markets to meet the demands of its full-service electricity customers. It also generates a small portion of its electricity requirements. Central Hudson purchases its gas supply requirements at various pipeline receipt points from a number of suppliers that it has contracted for firm transport capacity.
Regulation
Central Hudson is regulated by the PSC regarding such matters as rates, construction, operations, financing and accounting. Certain activities of the Company are subject to regulation by the U.S. Federal Energy Regulatory Commission under the Federal Power Act (United States). Central Hudson is also subject to regulation by the North American Electric Reliability Corporation.
Central Hudson operates under COS regulation as administered by the PSC. The PSC uses a future test year to establish of rates for the utility and, pursuant to this method, the determination of the approved rate of return on forecast rate base and deemed capital structure, together with the forecast of all reasonable and prudent costs, establishes the revenue requirement upon which the Company–s customer rates are determined. Once rates are approved, they are not adjusted as a result of actual COS being different from that which was applied for, other than for certain prescribed costs that are eligible for deferral account treatment.
Central Hudson–s allowed ROE is set at 10% on a deemed capital structure of 48% common equity. The Company began operating under a three-year rate order issued by the PSC effective July 1, 2010. As approved by the PSC in June 2013, the original three-year rate order has been extended for two years, through June 30, 2015, as a condition required to close the acquisition of CH Energy Group by Fortis. Effective July 1, 2013, Central Hudson is also subject to a modified earnings sharing mechanism, whereby the Company and customers equally share earnings in excess of the allowed ROE up to an achieved ROE that is 50 basis points above the allowed ROE, and share 10%/90% (Company/customers) earnings in excess of 50 basis points above the allowed ROE.
Central Hudson–s approved regulatory regime allows for full recovery of purchased electricity and natural gas costs. The Company–s rates also include Revenue Decoupling Mechanisms (“RDMs”) which are intended to minimize the earnings impact resulting from reduced energy consumption as energy-efficiency programs are implemented. The RDMs allow the Company to recognize electricity delivery revenue and gas revenue at the levels approved in rates for most of Central Hudson–s customer base. Deferral account treatment is approved for certain other specified costs, including provisions for manufactured gas plant (“MGP”) site remediation, pension and other post-employment benefit (“OPEB”) costs.
Financial Highlights
Electricity Sales and Gas Volumes
Seasonality impacts the delivery revenues of Central Hudson, as electricity sales are highest during the summer months, primarily due to the use of air conditioning and other cooling equipment, and gas volumes are highest during the winter months, primarily due to space heating usage.
Electricity sales for the third quarter were 1,420 GWh compared to 1,454 GWh for the same period last year. The decrease was mainly due to cooler temperatures in the third quarter of 2013. Gas volumes for the third quarter were 4 PJ compared to 6 PJ for the same period last year. The decrease was primarily due to lower volumes delivered to a power generating facility as a result of reduced facility operations and lower volumes for resale.
A portion of Central Hudson–s electricity sales and gas volumes are to other entities for resale. Electricity sales for resale do not have an impact on earnings, as any related earnings or loss is refunded to or collected from customers, respectively. For gas volumes for resale, 85% of any related earnings or loss is refunded to or collected from customers, respectively.
Revenue
Revenue for the third quarter was US$164 million compared to US$167 million for the same period last year. The decrease was primarily due to lower gas volumes for resale, partially offset by higher revenue from electricity energy efficiency programs.
Earnings
Earnings for the third quarter were comparable with the same period last year.
REGULATED ELECTRIC UTILITIES – CANADIAN
FORTISALBERTA
Unfavourable
Favourable
As a significant portion of FortisAlberta–s distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.
Favourable
Unfavourable
Unfavourable
Favourable
FORTISBC ELECTRIC (1)
Favourable
Unfavourable
Favourable
Unfavourable
Unfavourable
Favourable
NEWFOUNDLAND POWER
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
Favourable
OTHER CANADIAN ELECTRIC UTILITIES (1)
Unfavourable
Favourable
Favourable
Unfavourable
Favourable
Unfavourable
REGULATED ELECTRIC UTILITIES – CARIBBEAN (1)
Favourable
Unfavourable
Favourable
Favourable
Unfavourable
NON-REGULATED – FORTIS GENERATION (1)
Favourable
Unfavourable
Favourable
Unfavourable
Favourable
Unfavourable
NON-REGULATED – NON-UTILITY
The Non-Utility segment is comprised of Fortis Properties and Griffith. Fortis Properties owns and operates 23 hotels, comprised of more than 4,400 rooms, in eight Canadian provinces, and owns and operates approximately 2.7 million square feet of commercial office and retail space, primarily in Atlantic Canada. Non-regulated operations of CH Energy Group primarily consist of Griffith, which mainly supplies petroleum products and related services to approximately 65,000 customers in the Mid-Atlantic Region of the United States.
Favourable
Unfavourable
Favourable
CORPORATE AND OTHER (1)
Favourable
Unfavourable
Unfavourable
Favourable
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications associated with each of the Corporation–s regulated gas and electric utilities year-to-date 2013 are summarized as follows.
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheet between September 30, 2013 and December 31, 2012.
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation–s sources and uses of cash for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, followed by a discussion of the nature of the variances in cash flows.
Operating Activities: Cash flow from operating activities was $119 million lower for the quarter and $124 million lower year to date compared to the same periods last year. The decreases were primarily due to unfavourable changes in working capital at FortisAlberta and unfavourable changes in long-term regulatory deferral accounts at the FortisBC Energy companies. The decreases were partially offset by: (i) higher earnings and the collection from customers of regulator-approved increases in depreciation and amortization; (ii) favourable changes in working capital at Maritime Electric in the first quarter of 2013; and (iii) cash proceeds received in the second quarter of 2013 on the settlement of the expropriation matters associated with the Exploits Partnership.
Investing Activities: Cash used in investing activities was $28 million lower quarter over quarter, primarily due to lower capital expenditures related to the non-regulated Waneta Expansion and at FortisAlberta and the FortisBC Energy companies. The decrease was partially offset by capital spending at Central Hudson in the third quarter of 2013.
Cash used in investing activities was $1,073 million higher year to date compared to the same period last year. The increase was primarily due to the acquisition of CH Energy Group in June 2013 for a net cash purchase price of $1,019 million and FortisBC Electric–s acquisition of electrical utility assets of the City of Kelowna in March 2013 for approximately $55 million. Higher capital expenditures at the regulated utilities, including capital spending at Central Hudson in the third quarter of 2013, and Fortis Properties was partially offset by lower capital expenditures related to the non-regulated Waneta Expansion.
Financing Activities: Cash provided by financing activities was $35 million for the third quarter compared to cash used in financing activities of $28 million for the same period last year. The change quarter over quarter was primarily due to the issuance of preference shares in July 2013 and higher proceeds from long-term debt, partially offset by higher repayments under committed credit facilities classified as long term and the redemption of preference shares in July 2013.
Cash provided by financing activities was $1,138 million higher year to date compared to the same period last year. The increase was primarily due to the issuance of common shares and borrowings under the Corporation–s committed credit facility in connection with the acquisition of CH Energy Group, combined with the issuance of preference shares in July 2013 and higher proceeds from long-term debt. The increase was partially offset by the redemption of preference shares in July 2013 and lower advances from non-controlling interests.
In May 2013 Caribbean Utilities issued 15-year US$10 million 3.34% and 20-year US$40 million 3.54% senior unsecured notes. The proceeds were used to repay short-term borrowings and to finance capital expenditures.
In September 2013 FortisAlberta issued 30-year $150 million 4.85% unsecured debentures. The net proceeds are being used to repay credit facility borrowings, to fund future capital expenditures and for general corporate purposes.
Repayments of long-term debt and capital lease and finance obligations and net (repayments) borrowings under committed credit facilities for the quarter and year to date compared to the same periods last year are summarized in the following tables.
Borrowings under credit facilities by the utilities are primarily in support of their capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation–s committed credit facility. The borrowings under the Corporation–s committed credit facility in 2013 were incurred to finance a portion of the acquisition of CH Energy Group, to support the construction of the Waneta Expansion and to finance an equity injection into FortisAlberta in support of energy infrastructure investment.
Advances from non-controlling interests in the Waneta Partnership of approximately $42 million were received in the first half of 2013 to finance capital spending related to the Waneta Expansion, compared to $14 million and $70 million received during the third quarter and year-to-date periods in 2012, respectively. 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 were $592 million year-to-date 2013, compared to $12 million for the same period last year. The increase was primarily due to the issuance of 18.5 million common shares in June 2013, as a result of the conversion of the Subscription Receipts on closing of the CH Energy Group acquisition, for proceeds of approximately $567 million, net of after-tax expenses. The increase also reflected a higher number of common shares issued under the Corporation–s dividend reinvestment and employee share purchase plans.
In July 2013 Fortis issued 10 million First Preference Shares, Series K for gross proceeds of $250 million. The proceeds were used to redeem all of the Corporation–s First Preference Shares, Series C in July 2013 for $125 million, to repay a portion of credit facility borrowings, and for other general corporate purposes.
Common share dividends paid in the third quarter of 2013 were $49 million, net of $17 million of dividends reinvested, compared to $42 million, net of $15 million of dividends reinvested, paid in the same quarter of 2012. Common share dividends paid year-to-date 2013 were $134 million, net of $51 million of dividends reinvested, compared to $128 million, net of $43 million of dividends reinvested, paid year-to-date 2012. The dividend paid per common share for each of the first, second and third quarters of 2013 was $0.31 compared to $0.30 for each of the first, second and third quarters of 2012. The weighted average number of common shares outstanding for the third quarter and year to date was 212.0 million and 199.1 million, respectively, compared to 190.2 million and 189.6 million, respectively, for the same periods in 2012.
CONTRACTUAL OBLIGATIONS
The Corporation–s consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter, as at September 30, 2013, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2012 Annual MD&A and below, where applicable.
Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2012 Annual MD&A, except as follows.
In May 2013 FortisBC Electric entered into a new Power Purchase Agreement (“PPA”) with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term beginning October 1, 2013. This new PPA does not change the basic parameters of the BC Hydro PPA, which expired on September 30, 2013. An executed version of the PPA was submitted by BC Hydro to the BCUC in May 2013 and is pending regulatory approval. In the interim period until the new PPA is approved by the BCUC, FortisBC Electric and BC Hydro have agreed to continue under the terms of the expired BC Hydro PPA. Power purchases in the interim are approved for recovery in customer rates. The power purchases from the new PPA are expected to be recovered in customer rates.
For a discussion of the nature and amount of the Corporation–s consolidated capital expenditure program, that is not included in the preceding Contractual Obligations table, 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 enable 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 45% equity, including preference shares, and 55% debt, as well as investment-grade credit ratings. Each of the Corporation–s regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility–s customer rates.
The consolidated capital structure of Fortis is presented in the following table.
The change in the capital structure was primarily due to the financing of the acquisition of CH Energy Group, including: (i) the conversion of Subscription Receipts into common shares for $567 million, net of after-tax expenses; (ii) debt assumed upon acquisition; and (iii) higher borrowings under the Corporation–s committed credit facility, to initially finance the remaining portion of the acquisition. The capital structure was also impacted by: (i) an increase in total debt, mainly in support of energy infrastructure investment; (ii) the issuance of First Preference Shares, Series K, partially offset by the redemption of First Preference Shares, Series C; (iii) net earnings attributable to common equity shareholders for the nine months ended September 30, 2013, less dividends declared on common shares; and (iv) the issuance of common shares under the Corporation–s Dividend Reinvestment Plan.
Excluding capital lease and finance obligations, the Corporation–s capital structure as at September 30, 2013 was 54.4% debt, 9.5% preference shares and 36.1% common shareholders– equity (December 31, 2012 – 53.6% debt, 10.1% preference shares and 36.3% common shareholders– equity).
CREDIT RATINGS
The Corporation–s credit ratings are as follows:
In February 2013 S&P and DBRS affirmed the Corporation–s debt credit ratings. The above-noted credit ratings reflect the Corporation–s 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. The credit ratings also reflect the Corporation–s financing of the acquisition of CH Energy Group and the expected completion of the Waneta Expansion on time and on budget.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $809 million in gross consolidated capital expenditures by segment year-to-date 2013 is provided in the following table.
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from those forecast.
Gross consolidated capital expenditures for 2013 are forecast to be approximately $1.2 billion. This represents a decrease of approximately $150 million from the original 2013 forecast disclosed in the 2012 Annual MD&A. The decrease is primarily due to the non-regulated Waneta Expansion, FortisBC Electric and FAES, partially offset by Central Hudson.
Lower forecast capital expenditures related to the Waneta Expansion for 2013 are primarily due to the timing of payments. Capital expenditures at FortisBC Electric are expected to be lower than the original forecast for 2013 as a result of labour disruptions. For further information on labour relations refer to the “Business Risk Management” section of this MD&A. Due to the uncertainty of the timing of alternative energy projects at FAES, capital expenditures for 2013 are delayed and are expected to be lower than the original forecast. Capital expenditures for 2013 now include approximately $59 million forecast at Central Hudson from the date of acquisition.
Construction of the $900 million Waneta Expansion is ongoing, with an additional $98 million invested year-to-date 2013. Approximately $534 million has been invested in the Waneta Expansion since construction began late in 2010. Key construction activities year-to-date 2013 include the ongoing civil construction of the powerhouse and intake, installation of the turbine components, installation of ancillary mechanical and electrical powerhouse services, and most notably, the encapsulating of the scrollcase in concrete. During the third quarter, the generator step-up transformers were received onsite for assembly. The key offsite activity in the third quarter of 2013 was the successful completion of the manufacturing of the first turbine runner and turbine operating mechanism.
Over the five-year period 2013 through 2017, gross consolidated capital expenditures are expected to be approximately $6 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 53% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 21% at Canadian Regulated Gas Utilities; 11% at Central Hudson; 4% at Caribbean Regulated Electric Utilities; and the remaining 11% at non-regulated operations. Capital expenditures at the regulated utilities are subject to regulatory approval. Over the five-year period, on average annually, the approximate breakdown of the total capital spending to be incurred is as follows: 36% to meet customer growth, 41% for sustaining capital expenditures, and 23% 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 flows 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 corporate 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 corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends.
As at September 30, 2013, management expects consolidated long-term debt maturities and repayments to average approximately $335 million annually over the next five years, excluding borrowings under the Corporation–s committed credit facility which were subsequently replaced with long-term financing. The combination of available credit facilities and relatively low annual debt maturities and repayments will provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
In May 2012 Fortis filed a short-form base shelf prospectus under which Fortis may offer, from time to time during the 25-month period from May 10, 2012, by way of a prospectus supplement, common shares, preference shares, subscription receipts and/or unsecured debentures in the aggregate amount of up to $1.3 billion (or the equivalent in US dollars or other currencies). The base shelf prospectus provides the Corporation with flexibility to access securities markets in a timely manner.
Through prospectus supplements filed under its base shelf prospectus, Fortis offered and sold: (i) approximately $601 million of Subscription Receipts in June 2012 (refer to the “Significant Items” section in this MD&A); (ii) $200 million First Preference Shares, Series J in November 2012; and (iii) $250 million First Preference Shares, Series K in July 2013 (refer to the “Significant Items” section in this MD&A). The remaining amount available under the base shelf prospectus is approximately $250 million.
In July 2013 FortisBC Electric filed a short-form base shelf prospectus to establish a Medium-Term Note (“MTN”) Debentures Program and entered into a dealer agreement with certain affiliates of a group of Canadian Chartered Banks. Upon filing the shelf prospectus, the Company may, from time to time during the 25-month life of the base shelf prospectus, issue MTN Debentures in an aggregate principal amount of up to $300 million. The establishment of the MTN Debentures Program has been approved by the BCUC.
In October 2013 FortisAlberta filed a short-form base shelf prospectus under which the Company may, from time to time during the 25-month life of the base shelf prospectus, issue MTN Debentures in an aggregate principal amount of up to $500 million.
Fortis and its subsidiaries were compliant with debt covenants as at September 30, 2013 and are expected to remain compliant throughout 2013.
CREDIT FACILITIES
As at September 30, 2013, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.7 billion, of which $1.9 billion was unused, including $490 million unused under the Corporation–s $1 billion committed revolving corporate 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 $2.6 billion of the total credit facilities are committed facilities with maturities ranging from 2014 through 2018.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
As at September 30, 2013 and December 31, 2012, 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 January 2013 FEVI–s $20 million unsecured committed non-revolving credit facility matured and was not replaced.
In April 2013 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 2016 and $50 million now maturing in May 2014. The amended credit facility agreement contains substantially similar terms and conditions as the previous credit facility agreement.
In April 2013 FHI extended its $30 million unsecured committed revolving credit facility to mature in May 2014 from May 2013.
In May 2013 FortisOntario extended its $30 million unsecured revolving credit facility to mature in June 2014 from June 2013.
In June 2013 Fortis Turks and Caicos entered into new short-term unsecured demand credit facilities for US$21 million ($22 million), replacing its previous US$21 million ($22 million) facilities. The new facilities are comprised of a revolving operating credit facility of US$12 million ($12 million) and a US$9 million ($9 million) emergency standby loan. The facilities mature in June 2014, with an option to renew annually. The new credit facilities reflect a decrease in pricing but otherwise contain terms and conditions substantially similar to the previous facilities.
In July 2013 FEI, FEVI and FortisAlberta amended their $500 million, $200 million and $250 million committed revolving credit facilities, resulting in extensions to the maturity dates to August 2015, December 2015 and August 2018, respectively, from August 2014, December 2013 and August 2016, respectively. The new agreements contain substantially similar terms and conditions as the previous credit facility agreements.
In August 2013 the Corporation extended its $1 billion committed revolving corporate credit facility to mature in July 2018 from July 2015.
As at September 30, 2013, CH Energy Group had a US$100 million ($103 million) unsecured revolving credit facility maturing in October 2015, and Central Hudson had a US$150 million ($155 million) unsecured committed revolving credit facility maturing in October 2016.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation–s consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) 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; or (ii) by obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.
The Financial Instruments table above excludes the long-term other asset associated with the Corporation–s expropriated investment in Belize Electricity. Due to uncertainty in the ultimate amount and ability of the Government of Belize (“GOB”) to pay appropriate fair value compensation owing to Fortis for the expropriation of Belize Electricity, the Corporation has recorded the book value of the expropriated investment, including foreign exchange impacts, in long-term other assets, which totalled approximately $105 million as at September 30, 2013 (December 31, 2012 – $104 million).
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-noted exposure through the use of US dollar-denominated 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 Central Hudson, Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy Corporation, Belize Electric Company Limited (“BECOL”) and Griffith is the US dollar.
As at September 30, 2013, the Corporation–s corporately issued US$1,044 million (December 31, 2012 – US$557 million) long-term debt had been designated as an effective hedge of the Corporation–s foreign net investments. As at September 30, 2013, the Corporation had approximately US$549 million (December 31, 2012 – US$17 million) in foreign net investments remaining to be hedged. Both the Corporation–s US dollar-denominated long-term debt and foreign net investments as at September 30, 2013 were significantly impacted by the CH Energy Group acquisition. Foreign currency exchange rate fluctuations associated with the translation of the Corporation–s corporately issued US dollar-denominated 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 gains and losses are also recorded in other comprehensive income.
Effective from June 20, 2011, the Corporation–s asset associated with its expropriated investment in Belize Electricity does not qualify for hedge accounting as Belize Electricity is no longer a foreign subsidiary of Fortis. As a result, foreign exchange gains and losses on the translation of the long-term other asset associated with Belize Electricity are recognized in earnings. The Corporation recognized in earnings a foreign exchange loss of $2 million for the three months ended and a foreign exc