Fortis Delivers Earnings of $198 Million for the First Quarter of 2015
- $900 Million Waneta Hydroelectric Expansion Online and Generating Power - 2015 Capital Expenditure Program Expected to Surpass $2 Billion
(firmenpresse) - ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 05/05/15 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS) released its first quarter results today.
"Fortis is positioned for a strong 2015 based on the performance of our major utilities in the first quarter," says Barry Perry, President and Chief Executive Officer, Fortis. "Also, the $900 million, 335-megawatt Waneta Expansion hydroelectric generating facility in British Columbia came online early April, six weeks ahead of schedule and on budget, while maintaining an excellent safety and environmental protection record. The facility will contribute to earnings beginning in the second quarter," he continues.
Net earnings attributable to common equity shareholders for the first quarter were $198 million, or $0.72 per common share, compared to $143 million, or $0.67 per common share, for the first quarter of 2014. Excluding a number of one-time impacts, adjusted net earnings attributable to common equity shareholders for the first quarter were $179 million, or $0.65 per common share, compared to $146 million, or $0.68 per common share, for the first quarter of 2014. While UNS Energy contributed $20 million to earnings in the first quarter, as expected the acquisition had a $0.13 dilutive impact on earnings per common share, after considering the common share offering and finance charges associated with the acquisition. The earnings of UNS Energy are highly seasonal, with approximately 75% of earnings contributed in the second and third quarters.
"Our enterprise-wide capital program is expected to surpass $2 billion this year and is well advanced, with more than $550 million invested in the first quarter," says Perry. FortisBC's Tilbury liquefied natural gas ("LNG") expansion (known as Tilbury 1A), at an estimated total cost of approximately $440 million, is the largest capital project ongoing. Tilbury 1A will add 950,000 mmBtus of storage and 34,000 mmBtus daily of liquefaction when the second LNG tank and new liquefier come in service, which is expected to occur by the end of 2016.
In January 2015 UNS Energy closed the purchase of an additional ownership interest in the Springerville Unit 1 generating facility for US$46 million, as expected, following the expiry of the lease agreement. UNS Energy's ownership interests in Springerville Unit 1 now total 49.5%.
"A number of significant regulatory processes were concluded in the quarter, ensuring ongoing regulatory stability for our utilities," says Perry. "In addition to the proceedings concluded in Alberta, our application for new rates in New York State was advanced as well," he explains.
At FortisAlberta, regulatory decisions were received in March 2015 on the utility's Capital Tracker Applications and the Generic Cost of Capital ("GCOC") Proceeding. The Capital Tracker Decision approved revenue for substantially all of FortisAlberta's capital programs as filed; previously, revenue was recognized on an interim basis at 60% of the applied for amounts. The GCOC Proceeding set the utility's allowed rate of return on common shareholder's equity ("ROE") for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41% approved on an interim basis. The impact of the decreases in the allowed ROE and common equity component of capital structure only applies to the portion of FortisAlberta's revenue that is associated with capital tracker amounts throughout the term of the performance-based rate setting regulation. As a result of these regulatory decisions, in the first quarter of 2015, FortisAlberta recognized a positive $10 million capital tracker revenue adjustment associated with 2013 and 2014.
At Central Hudson, a Joint Settlement Proposal was filed in February 2015 that proposes new rates at the utility for a three-year period beginning July 1, 2015, reflecting an allowed ROE of 9.0% and a 48% common equity component of capital structure. A delivery rate freeze was implemented for electricity and natural gas delivery rates through to June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson committed to invest US$215 million in capital expenditures during the two-year delivery rate freeze period ending June 30, 2015. Public statement and evidentiary hearings were held in March 2015 and a Final Joint Proposal was executed in April 2015. The Final Joint Settlement Proposal is targeted to go to the regulator in June for consideration and approval.
"Fortis remains focused on our core regulated utility business and long-term contracted energy infrastructure", explains Perry. "We expect to make an announcement regarding the outcome of the strategic review of Fortis Properties in the second quarter of 2015," he says.
In March 2015 the Corporation entered into an agreement to sell its non-regulated generation assets in Upstate New York and Ontario. The sale of the generation assets in Upstate New York and Ontario is expected to close in the second quarter of 2015 and the second half of 2015, respectively.
Fortis continues to be one of the highest-rated utility holding companies in North America, with its corporate debt rated A- by Standard and Poor's and A(low) by DBRS, which helps ensure efficient access to capital. In February 2015 Tucson Electric Power Company, UNS Energy's largest utility, issued US$300 million 10-year senior unsecured notes at 3.05%. Net proceeds were primarily used to repay long-term debt and credit facility borrowings and to finance capital expenditures. UNS Energy and its regulated utilities received credit rating upgrades from Moody's Investor Service in the first quarter of 2015.
"Fortis continues to build on its dividend record to shareholders," says Perry. The Corporation paid a quarterly dividend of $0.34 per common share on March 1, 2015 compared to $0.32 paid on December 1, 2014. The 6.25% increase extends the Corporation's record of annualized common share dividend increases to 42 consecutive years, the longest record of any public corporation in Canada.
"Following a decade of growth driven mainly by acquisitions, Fortis has entered a period of significant organic growth," says Perry.
Over the five-year period through 2019, the Corporation's capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase midyear rate base by approximately 38% from $14 billion in 2014 to more than $19 billion in 2019 and produce a five-year compound annual growth rate ("CAGR") of approximately 6.5%. Two new natural gas infrastructure investments in British Columbia that Fortis is pursuing - Tilbury 1B and the pipeline expansion to Woodfibre LNG - could increase the five-year CAGR in rate base to 7.5%.
"Looking out over the five-year horizon, we expect our capital investment to support continuing growth in earnings and dividends," concludes Perry.
Teleconference to Discuss First Quarter 2015 Results
A teleconference and webcast will be held on May 5 at 10:00 a.m. (Eastern). Barry Perry, President and Chief Executive Officer, Fortis, and Karl Smith, Executive Vice President, Chief Financial Officer, Fortis, will discuss the Corporation's first quarter 2015 results.
Analysts, members of the media and other interested parties in North America are invited to participate by calling 1.877.223.4471. International participants may participate by calling 647.788.4922. Please dial in 10 minutes prior to the start of the call. No pass code is required.
A live and archived audio webcast of the teleconference will be available on the Corporation's website, .
A replay of the conference will be available two hours after the conclusion of the call until May 15, 2015. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 13991420.
Interim Management Discussion and Analysis
For the three months ended March 31, 2015
Dated May 5, 2015
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 months ended March 31, 2015 and the MD&A and audited consolidated financial statements for the year ended December 31, 2014 included in the Corporation's 2014 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 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 based on information currently available.
The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the Corporation's review of strategic options for its hotel and commercial real estate business; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the Corporation's forecast gross consolidated capital expenditures for 2015 and total capital spending over the five-year period from 2015 through 2019; forecast midyear rate base and the associated compound annual growth rate through 2019; the nature, timing and expected costs of certain capital projects including, without limitation, the Tilbury liquefied natural gas ("LNG") facility expansion, the pipeline expansion to Woodfibre LNG, the development of a diesel power plant in Grand Cayman, and the Pinal transmission project in Arizona; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; 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 Corporation's subsidiaries will be able to source the cash required to fund their 2015 capital expenditure programs, operating and interest costs, and dividend payments;
the expected consolidated fixed-term debt maturities and repayments in 2015 and on average annually over the next five years; the expectation that long-term debt will not be settled prior to maturity; the expectation that the Corporation and its subsidiaries will continue to have reasonable access to capital in the near to long terms; 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 expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2015; the intent of management to hedge future exchange rate fluctuations and monitor its foreign currency exposure; the impact of advances in technology and new energy efficiency standards on the Corporation's results of operations; the impact of new or revised environmental laws and regulations on the Corporation's results of operations; the expectation that any liability from current legal proceedings will not have a material adverse effect on the Corporation's consolidated financial position and results of operations; the belief that the Corporation has a strong, well-positioned case supporting the unconstitutionality of the expropriation of the Corporation's investment in Belize; the expectation that ongoing labour negotiations will be settled in 2015; and the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the potential sale of assets or shares in the hotel and commercial real estate markets; the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; 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 electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity 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, coal 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; new or revised environmental laws and regulations will not severely affect the results of operations; 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 2018 or the adoption of International Financial Reporting Standards after 2018 that allows for the recognition of regulatory assets and liabilities; the continued tax-deferred treatment of earnings from the Corporation's Caribbean operations; no significant changes in tax legislation; continued maintenance of information technology infrastructure; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; 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 and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. Key risk factors for 2015 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 the Corporation's regulated utilities; uncertainty related to litigation; 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 the 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 a leader in the North American electric and gas utility business, with total assets of approximately $28 billion and fiscal 2014 revenue of $5.4 billion. Its regulated utilities account for approximately 93% of total assets and serve more than 3 million customers across Canada and in the United States and the Caribbean. Fortis owns non-regulated hydroelectric generation assets in Canada, Belize and Upstate New York. The Corporation's non-utility investment is comprised of hotels and commercial real estate in Canada.
Year-to-date March 31, 2015, the Corporation's electricity distribution systems met a combined peak demand of 8,455 megawatts ("MW") and its gas distribution system met a peak day demand of 1,198 terajoules. 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, 2015 and to the "Corporate Overview" section of the 2014 Annual MD&A.
The Corporation's main business, utility operations, is highly regulated and the earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation and, in certain circumstances, performance-based rate-setting ("PBR") mechanisms. Generally, under COS regulation the respective regulatory authority sets customer electricity and/or gas 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. When 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 prudently incurred costs and earn its allowed ROE or ROA.
Earnings of regulated utilities may be generally impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA and common 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 future test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of the 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.
SIGNIFICANT ITEMS
Completion of the Waneta Expansion Hydroelectric Generating Facility: On April 1, 2015, the Corporation completed construction of the $900 million, 335-MW Waneta Expansion hydroelectric generating facility (the "Waneta Expansion") ahead of schedule and on budget. Fortis has a 51% controlling ownership interest in the Waneta Expansion, with Columbia Power Corporation and Columbia Basin Trust holding the remaining 49% interest. Construction of the Waneta Expansion, which is adjacent to the Waneta Dam and powerhouse facilities on the Pend d'Oreille River, south of Trail, British Columbia, commenced late in 2010. For further information regarding the Waneta Expansion, refer to the "Capital Expenditure Program" section of this MD&A.
Regulatory Decisions at FortisAlberta: In March 2015 regulatory decisions were received on FortisAlberta's Capital Tracker Applications and the Generic Cost of Capital ("GCOC") Proceeding in Alberta. The Capital Tracker Decision approved revenue for substantially all of FortisAlberta's capital programs as filed; previously, revenue was recognized on an interim basis at 60% of the applied for amounts. The GCOC Proceeding set FortisAlberta's allowed ROE for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41% approved on an interim basis. The impact of the decreases in the allowed ROE and common equity component of capital structure only applies to the portion of FortisAlberta's revenue that is associated with capital tracker amounts throughout the term of the PBR regulation. As a result of these regulatory decisions, in the first quarter of 2015, FortisAlberta recognized a positive $10 million capital tracker revenue adjustment associated with 2013 and 2014. This adjustment reflects the combined impact of the Capital Tracker Decision and the GCOC Decision, taking into consideration the capital tracker revenue previously recognized on an interim basis for 2013 and 2014 at 60% of the applied for amounts. For further details on these regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Sale of Non-Regulated Generation Assets: In March 2015 the Corporation entered into an agreement to sell its non-regulated generation assets in Upstate New York and Ontario. The sale of the generation assets in Upstate New York and Ontario is expected to close in the second quarter of 2015 and the second half of 2015, respectively. As a result, the associated assets and liabilities have been classified as held for sale on the Corporation's interim unaudited consolidated balance sheet as at March 31, 2015. A gain on the sale is expected to be recognized in earnings at the time of closing.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common share and total shareholder return as the primary measures 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, 2015 and 2014 are provided in the following table.
Revenue
The increase in revenue was driven by the acquisition of UNS Energy in August 2014. Favourable foreign exchange associated with the translation of US dollar-denominated revenue and a capital tracker revenue adjustment of approximately $10 million at FortisAlberta also contributed to the increase. The increase was partially offset by lower gas volumes at FortisBC Energy.
Energy Supply Costs
The increase in energy supply costs was primarily due to the acquisition of UNS Energy and unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs. The increase was partially offset by lower gas volumes at FortisBC Energy, which decreased natural gas purchases.
Operating Expenses
The increase in operating expenses was primarily due to the acquisition of UNS Energy, unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses and general inflationary and employee-related cost increases.
Depreciation and Amortization
The increase in depreciation and amortization was primarily due to the acquisition of UNS Energy and continued investment in energy infrastructure at the Corporation's regulated utilities.
Other Income (Expenses), Net
The increase in other income, net of expenses, was mainly due to favourable foreign exchange on the translation of the Corporation's US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity Limited ("Belize Electricity").
Finance Charges
The increase in finance charges was primarily due to the acquisition of UNS Energy, including interest expense on debt issued to complete the financing of the acquisition. The increase was partially offset by lower interest on convertible debentures. Approximately $16 million ($11 million after tax) in interest expense was recognized in the first quarter of 2014 associated with convertible debentures issued to finance a portion of the acquisition of UNS Energy. In October 2014 the convertible debentures were substantially all converted into common shares of the Corporation.
Income Tax Expense
The increase in income tax expense was primarily due to higher earnings before income taxes, driven by the acquisition of UNS Energy.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings Per Common Share
Net earnings attributable to common equity shareholders were impacted by a number of non-recurring items or non-operating factors. These factors, referred to as adjusting items, are reconciled below and discussed in the segmented results of operations for the respective reporting segments. Management believes that adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share provides useful information to investors and shareholders as it provides increased transparency and predictive value. The adjusting items do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar measures presented by other companies.
The increase in adjusted net earnings attributable to common equity shareholders for the quarter was driven by the Corporation's regulated utilities. UNS Energy contributed earnings of $20 million in the first quarter of 2015. Earnings at FortisBC Energy and FortisBC Electric were $9 million and $5 million, respectively, higher quarter over quarter, largely due to timing of quarterly earnings compared to the same periods last year resulting from the impact of regulatory deferral mechanisms. FortisAlberta's earnings were favourably impacted by higher capital tracker revenue for 2015 and customer growth. Central Hudson and Eastern Canadian Regulated Electric Utilities also reported improved performance.
The increase in earnings at the regulated utilities was partially offset by lower earnings at the Corporation's non-regulated subsidiaries, largely due to decreased production in Belize as a result of lower rainfall and costs at Fortis Properties associated with the ongoing strategic review. Higher preference share dividends and finance charges in the Corporate and Other segment associated with the acquisition of UNS Energy decreased earnings for the first quarter of 2015.
The decrease in adjusted earnings per common share was primarily due to the $0.13 dilutive impact of the acquisition of UNS Energy, after considering the finance charges associated with the acquisition and the increase in the weighted average number of common shares outstanding. The earnings of UNS Energy are highly seasonal, with approximately 75% of earnings contributed in the second and third quarters. The decrease in adjusted earnings per common share was partially offset by other increases in adjusted net earnings attributable to common equity shareholders, as discussed above.
SEGMENTED RESULTS OF OPERATIONS
The following is a discussion of the financial results of the Corporation's reporting segments. Refer to the "Material Regulatory Decisions and Applications" section of this MD&A for a discussion pertaining to the Corporation's regulated utilities.
REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES
UNS ENERGY (1)
Electricity Sales & Gas Volumes
Electricity sales for the first quarter were 3,397 gigawatt hours ("GWh") compared to 3,199 GWh for the same period last year. The increase was primarily due to an increase in short-term wholesale sales as a result of more favourable commodity prices compared to the same period last year. Short-term wholesale sales are flowed through to customers and have no impact on earnings.
Gas volumes for the first quarter were 5 petajoules ("PJ"), comparable with the same period last year.
Seasonality impacts the earnings of UNS Energy. Earnings for the electric utilities are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment and earnings for the gas utility are generally highest in the first and fourth quarters due to space-heating requirements. In 2014 approximately 75% of UNS Energy's earnings were recognized in the second and third quarters, excluding acquisition-related expenses.
Revenue
Revenue for the first quarter was US$350 million compared to US$333 million for the same period last year. The increase was primarily due to the flow through to customers of higher purchased power and fuel supply costs as a result of the operation of UNS Energy's regulatory cost recovery mechanisms.
Earnings
Earnings for the first quarter were approximately US$17 million, comparable with the same period last year.
CENTRAL HUDSON
Electricity Sales & Gas Volumes
Electricity sales and gas volumes for the first quarter of 2015 were comparable with the same period last year.
Seasonality impacts delivery revenue at 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.
Revenue
The increase in revenue was due to approximately $32 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. The recovery of deferred electricity and gas costs, higher gas revenue associated with a new contract in late 2014, as well as energy-efficiency incentives earned during the quarter upon achieving energy saving targets established by the regulator, also contributed to the increase in revenue. The increase was partially offset by the recovery from customers of lower commodity costs, which were mainly due to lower wholesale prices.
Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on revenue and earnings.
Earnings
The increase in earnings was primarily due to approximately $3 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings. A new gas contract in late 2014 and energy-efficiency incentives earned during the quarter, as discussed above, also contributed to the increase in earnings, and were partially offset by the impact of higher operating expenses during the two-year rate freeze period post acquisition in June 2013.
REGULATED GAS UTILITY - CANADIAN
FORTISBC ENERGY (1)
Gas Volumes
The decrease in gas volumes was primarily due to lower average consumption as a result of warmer temperatures.
FortisBC Energy earns 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 regulatory deferral mechanisms, changes in consumption levels and the cost of natural gas from those forecast to set customer gas rates do not materially affect earnings.
Seasonality has a material impact on the earnings of FortisBC Energy as a major portion of the gas distributed is used for space heating. Most of the annual earnings of FortisBC Energy are realized in the first and fourth quarters.
Revenue
The decrease in revenue was primarily due to lower gas volumes, partially offset by a higher commodity cost of natural gas charged to customers and the timing of regulatory flow-through deferral amounts. Prior to the amalgamation of FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI"), and FortisBC Energy (Whistler) Inc. ("FEWI") on December 31, 2014, FEVI was subject to a rate stabilization mechanism which accumulated the difference between revenue received and actual cost of service, thereby reducing the seasonality of revenue and earnings. As a result of the amalgamation, effective January 1, 2015, this rate stabilization mechanism ceased, resulting in greater seasonality whereby revenue and earnings will be higher in the first and fourth quarters and lower in the second and third quarters.
Earnings
The increase in earnings was driven by approximately $12 million associated with the timing of regulatory flow-through deferral amounts, as discussed above. This increase was partially offset by a decrease in the allowed ROE and equity component of capital structure as a result of the amalgamation of FEVI and FEWI with FEI, effective December 31, 2014. Prior to the amalgamation, the allowed ROEs for FEVI and FEWI were 9.25% and 9.50%, respectively, on a common equity component of capital structure of 41.5%. Effective January 1, 2015, the allowed ROE and common equity component of capital structure revert to those of FEI, which are 8.75% and 38.5%, respectively.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
Energy Deliveries
The decrease in energy deliveries was primarily due to lower average consumption by residential, commercial and farm and irrigation customers due to warmer temperatures, partially offset by growth in the number of customers. The total number of customers increased by approximately 12,000 year over year as at March 31, 2015, driven by residential customers as a result of favorable economic conditions in Alberta in 2014.
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.
Revenue
The increase in revenue was primarily due to a $10 million capital tracker revenue adjustment recognized in the first quarter of 2015 associated with 2013 and 2014, as discussed below, and higher revenue resulting from the operation of the PBR formula, including an increase in customer rates based on a combined inflation and productivity factor of 1.49% and higher 2015 capital tracker revenue. Growth in the number of customers and higher revenue related to flow-through costs to customers also contributed to the increase in revenue.
In March 2015 regulatory decisions were received on FortisAlberta's Capital Tracker Applications and the GCOC Proceeding in Alberta. The Capital Tracker Decision approved revenue for substantially all of FortisAlberta's capital programs as filed; previously, revenue was recognized on an interim basis at 60% of the applied for amounts. The GCOC Proceeding set the utility's allowed ROE for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41% approved on an interim basis. The impact of the decreases in the allowed ROE and common equity component of capital structure only applies to the portion of FortisAlberta's revenue that is associated with capital tracker amounts throughout the term of the PBR regulation. The $10 million capital tracker revenue adjustment associated with 2013 and 2014 reflects the combined impact of the Capital Tracker Decision and the GCOC Decision, taking into consideration the capital tracker revenue previously recognized on an interim basis for 2013 and 2014 at 60% of the applied for amounts. For further details on these regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of the MD&A.
Earnings
The increase in earnings was driven by capital tracker revenue of approximately $10 million recognized in the first quarter of 2015 associated with 2013 and 2014, as discussed above, as well as rate base growth and associated 2015 capital tracker revenue and growth in the number of customers.
FORTISBC ELECTRIC (1)
Electricity Sales
The decrease in electricity sales was mainly due to lower average consumption as a result of warmer temperatures.
Revenue
Revenue for the first quarter of 2015 was comparable to the same period last year. An interim refundable increase in base electricity rates, effective January 1, 2015, and the amortization of regulatory deferral adjustments owing to customers were largely offset by lower electricity sales.
Earnings
The increase in earnings was primarily due to the timing of earnings compared to the same period last year as a result of the impact of regulatory deferral mechanisms, timing of power purchase costs and rate base growth.
EASTERN CANADIAN ELECTRIC UTILITIES (1)
Electricity Sales
The increase in electricity sales was driven by customer growth and higher average consumption in Newfoundland and Prince Edward Island, including an increase in the number of customers using electricity for home heating. The increase was partially offset by lower average consumption by residential customers in Ontario.
Revenue
The increase in revenue was primarily due to electricity sales growth and the flow through in customer electricity rates of higher energy supply costs at FortisOntario.
Earnings
The increase in earnings was primarily due to electricity sales growth and lower operating costs associated with restoration efforts at Newfoundland Power following the loss of energy supply from Newfoundland and Labrador Hydro and related power interruptions in January 2014.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
Electricity Sales
Electricity sales for the quarter were consistent with the same period last year.
Revenue
The increase in revenue was driven by approximately $9 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, partially offset by the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities.
Earnings
Earnings for the quarter were consistent with the same period last year. Foreign exchange associated with the translation of US dollar-denominated earnings had a slightly favourable impact on earnings, which was largely offset by higher depreciation.
NON-REGULATED - FORTIS GENERATION (1)
Energy Sales
The decrease in energy sales was primarily due to decreased production in Belize due to lower rainfall. Decreased production in Upstate New York and Ontario, due to lower rainfall and generating units taken out of service for repairs, also contributed to the overall decrease in energy sales.
Revenue
The decrease in revenue was primarily due to decreased production in Belize, Upstate New York and Ontario.
Earnings
The decrease in earnings was primarily due to decreased production in Belize, Upstate New York and Ontario, partially offset by $1 million in business development costs in the first quarter of 2014 associated with investigating a potential generating facility in British Columbia.
NON-REGULATED - NON-UTILITY (1)
Revenue
Revenue at Fortis Properties for the first quarter of 2015 was comparable to the same period last year.
Earnings
Fortis Properties generated a loss of approximately $2 million in the first quarter of 2015 compared to earnings of less than $0.5 million for the same period last year. The decrease in earnings was primarily due to costs associated with the ongoing strategic review, as discussed below, and higher finance charges. Earnings for the first quarter of 2014 include $5 million associated with Griffith from normal operations to the date of sale.
In September 2014 the Corporation announced that it would engage in a review of strategic options for its hotel and commercial real estate business, operating as Fortis Properties. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering. An announcement on the outcome of the strategic review is expected to be made in the second quarter of 2015.
CORPORATE AND OTHER (1)
Net Corporate and Other expenses were impacted by the following items:
Excluding the above-noted items, net Corporate and Other expenses were $30 million for the first quarter of 2015 compared to $22 million for the same period last year. The increase was primarily due to higher preference share dividends and finance charges associated with the acquisition of UNS Energy in August 2014. Finance charges were also impacted by unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
The nature of regulation associated with each of the Corporation's regulated electric and gas utilities is generally consistent with that disclosed in the 2014 Annual MD&A. The following summarizes the significant regulatory decisions and applications for the Corporation's regulated utilities in the first quarter of 2015.
Central Hudson
In July 2014 Central Hudson filed a General Rate Application ("GRA") seeking to increase electricity and natural gas delivery rates effective July 1, 2015. A delivery rate freeze was implemented for electricity and natural gas delivery rates through to June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson committed to invest US$215 million in capital expenditures during the two-year delivery rate freeze period ending June 30, 2015. In its GRA, the Company requested an allowed ROE of 9.0% with a 48% common equity component of capital structure for a term of one year. The current rate order includes an allowed ROE of 10.0% with a 48% common equity component of capital structure. A Joint Settlement Proposal was filed in February 2015 that provides for new rates at Central Hudson for a three-year period beginning July 1, 2015, reflecting an allowed ROE of 9.0% and a 48% common equity component of capital structure. The Joint Settlement Proposal includes continuation of certain mechanisms currently in place, including revenue decoupling and earnings sharing mechanisms. Under the proposed earnings sharing mechanism, the Company and customers share equally earnings in excess of 50 basis points above the allowed ROE up to an achieved ROE that is 100 basis points above the allowed ROE. Public statement and evidentiary hearings were held in March 2015 and a Final Joint Proposal was executed in April 2015. The Final Joint Settlement Proposal is targeted to go to the regulator in June for consideration and approval.
FortisBC Energy and FortisBC Electric
On December 31, 2014, FEI, FEVI and FEWI were amalgamated, as approved by the British Columbia Utilities Commission ("BCUC") in February 2014, and FEI is the resulting Company. Prior to the amalgamation, the allowed ROEs for FEVI and FEWI were 9.25% and 9.50%, respectively, on a common equity component of capital structure of 41.5%. Effective January 1, 2015, the allowed ROE and common equity component of capital structure revert to those of FEI, which are 8.75% and 38.5%, respectively.
In compliance with the PBR decisions issued by the BCUC in September 2014, in January and February 2015, FEI and FortisBC Electric, respectively, filed for approval of their 2015 rates under the PBR decisions. The applications assume a forecast midyear rate base of approximately $3,656 million and $1,267 million for FEI and FortisBC Electric, respectively, and request approval of customer rate increases of approximately 2.0% and 4.6% over 2014 rates, respectively, determined under a formulaic approach for operating and maintenance costs and capital costs. A decision on the final rate increases is expected in the second quarter of 2015.
FEI is required to file an application to review the 2016 benchmark allowed ROE and common equity component of capital structure by no later than November 30, 2015. As FEI is the benchmark utility, the review of the application could have an impact on FortisBC Electric.
FortisAlberta
In March 2015 the Alberta Utilities Commission ("AUC") issued its decision on the GCOC Proceeding in Alberta. The GCOC Proceeding set FortisAlberta's allowed ROE for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41% approved on an interim basis. The AUC also decided that it will not re-establish a formula-based approach to setting the allowed ROE on an annual basis. The allowed ROE of 8.30% and common equity component of capital structure of 40% will remain in effect for 2016 and beyond on an interim basis. For regulated utilities in Alberta under PBR mechanisms, including FortisAlberta, the allowed ROE and common equity component of capital structure resulting from the GCOC Proceeding applies only to the portion of revenue that is associated with capital tracker amounts throughout the term of the PBR regulation.
In March 2015 the AUC also issued its decision related to FortisAlberta's 2013, 2014 and 2015 Capital Tracker Applications. The decision: (i) indicated which capital programs met the criteria established in the original PBR decision and were, therefore, approved for collection from customers; (ii) approved FortisAlberta's accounting test; and (iii) provided clarification on certain inputs to be used in the accounting test, including the conclusion that the weighted average cost of capital used in the accounting test is to be based on actual debt rates and the allowed ROE and capital structure approved in the GCOC Proceeding. Substantially all of FortisAlberta's capital programs were approved as filed.
FortisAlberta completed the required Capital Tracker Compliance Filing in April 2015, requesting that the adjustments to capital tracker revenue be considered in the 2016 Annual Rates Application to be filed in September 2015 and reflected in customer rates effective January 1, 2016. A decision on the Capital Tracker Compliance Filing is expected in the second half of 2015.
Additional capital tracker revenue of approximately $10 million was recognized in the first quarter of 2015 related to 2013 and 2014 capital expenditures. This adjustment reflects the combined impact of the Capital Tracker Decision and the GCOC Decision, taking into consideration the capital tracker revenue previously recognized on an interim basis for 2013 and 2014 at 60% of the applied for amounts. Capital tracker revenue for 2015 also reflects the impact of both decisions, taking into consideration the estimated 2015 capital expenditures related to qualifying capital programs.
In May 2015 FortisAlberta will file an application with the AUC seeking capital tracker revenue for 2016 and 2017, as well as a true-up to the actual 2014 capital expenditures. As part of this application, the Company will provide more comprehensive information on the components of the capital program that were not fully approved in the Capital Tracker Decision, seeking approval of the related capital expenditures incurred in 2013, 2014 and 2015. A hearing related to this proceeding is scheduled for October 2015, with a decision from the AUC expected in the first quarter of 2016.
In April 2015 the AUC initiated a 2016 GCOC Proceeding. A pre-proceeding conference will be held in May 2015, after which the AUC will identify the issues it has determined to be in-scope for this proceeding. In addition, an informal roundtable discussion will be held in June 2015 to explore procedural alternatives that may expedite completion of the 2016 GCOC Proceeding in a timely manner.
Eastern Canadian Electric Utilities
Newfoundland Power is required to file a GRA on or before June 1, 2015 to establish customer electricity rates for 2016, unless otherwise directed by the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB"). In April 2015 Newfoundland Power filed an application with the PUB to defer the filing of its next GRA to on or before June 1, 2016 and to request a 2016 cost recovery deferral of $4 million. The application is currently under review by the PUB.
Significant Regulatory Proceedings
The following table summarizes ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's largest regulated utilities.
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between March 31, 2015 and December 31, 2014.
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the three months ended March 31, 2015, as compared to the same period in 2014, followed by a discussion of the nature of the variances in cash flows.
Operating Activities: Cash flow from operating activities was $185 million higher quarter over quarter. The increase was primarily due to higher cash earnings, largely due to the acquisition of UNS Energy, and favourable changes in working capital associated with accounts receivable at FortisBC Energy and UNS Energy. The increase was partially offset by unfavorable changes in long-term regulatory deferrals at FortisBC Energy and FortisAlberta.
Investing Activities: Cash used in investing activities was $443 million higher quarter over quarter. The increase was driven by capital expenditures at UNS Energy and higher capital spending at FortisBC Energy, FortisBC Electric and FortisAlberta. Proceeds from the sale of Griffith in March 2014 of approximately $105 million (US$95 million) also contributed to the variance.
Financing Activities: Cash provided by financing activities was $145 million lower quarter over quarter. The decrease was primarily due to lower proceeds from the Corporation's convertible debentures and higher repayments of long-term debt, partially offset by higher proceeds from the issuance of long-term debt, lower net repayments of committed credit facility borrowings and changes in short-term borrowings.
In January 2014 proceeds of approximately $599 million, or $561 million net of issue costs, were received from the first installment of the convertible debentures issued to finance a portion of the acquisition of UNS Energy. Initially, a portion of the net proceeds were cash on hand, while a portion was used to repay borrowings under the Corporation's committed credit facility and for other general corporate purposes, including intercompany loan advances to subsidiaries.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net (repayments) borrowings under committed credit facilities for the quarter compared to the same period last year are summarized in the following tables.
Borrowings under credit facilities by the utilities are primarily in support of their respective 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.
Common share dividends paid in the first quarter of 2015 were $60 million, net of $34 million of dividends reinvested, compared to $47 million, net of $22 million of dividends reinvested, paid in the same quarter of 2014. The dividend paid per common share for the first quarter of 2015 was $0.34 compared to $0.32 for the first quarter of 2014. The weighted average number of common shares outstanding for the first quarter of 2015 was 276.7 million compared to 213.6 million for the same quarter of 2014.
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 March 31, 2015, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2014 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 2014 Annual MD&A.
For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program 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 electric and gas utilities 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.
Excluding capital lease and finance obligations, the Corporation's capital structure as at March 31, 2015 was 55.1% debt, 8.9% preference shares and 36.0% common shareholders' equity (December 31, 2014 - 55.0% debt, 9.4% preference shares and 35.6% common shareholders' equity).
The change in the capital structure was due to an increase in long-term debt, mainly due to the impact of foreign exchange on the translation of US-dollar denominated debt and the issuance of long-term debt, largely in support of energy infrastructure investment, partially offset by regularly scheduled debt repayments. The capital structure was also impacted by an increase in common shareholders' equity as a result of: (i) an increase in accumulated other comprehensive income associated with the translation of the Corporation's US dollar-denominated investments in subsidiaries, net of hedging activities and tax; (ii) net earnings attributable to common equity shareholders for the three months ended March 31, 2015, less dividends declared on common shares; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans.
CREDIT RATINGS
The Corporation's credit ratings are as follows:
The above-noted 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, and management's commitment to maintaining reasonable levels of debt at the holding company level. In April 2015 S&P confirmed the Corporation's credit rating with a Stable outlook.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $554 million in gross consolidated capital expenditures by segment year-to-date 2015 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 2015 are forecast to be approximately $2.2 billion. 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 2014 Annual MD&A.
Construction of the $900 million, 335-MW Waneta Expansion was completed on April 1, 2015, ahead of schedule and on budget. The expansion adds a second powerhouse, immediately downstream of the Waneta Dam on the Pend d'Oreille River, that shares the existing hydraulic head and generates clean, renewable, cost-effective power from water that would otherwise be spilled. The project included construction of a 10-kilometre, 230-kilovolt transmission line and provides enough energy to power about 60,000 homes per year. On April 2, 2015, the Waneta Expansion began generating power, all of which will be sold to BC Hydro and FortisBC Electric under 40-year contracts.
Construction of FortisBC's Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury 1A") in Delta, British Columbia is ongoing. Key construction activities during the quarter focused on completion of the LNG tank concrete foundation and commencement of the tank wall and bottom steel plate. Tilbury 1A will be included in regulated rate base and is estimated to cost approximately $440 million, including an equity component of allowance for funds used during construction. It will include a second LNG tank and a new liquefier, both expected to be in service by the end of 2016.
FortisBC is pursuing additional LNG infrastructure investment opportunities, including a further $450 million expansion of Tilbury ("Tilbury 1B") and a $600 million pipeline expansion to the proposed LNG facility by Woodfibre LNG in Squamish, British Columbia. In December 2014 FortisBC received an Order in Council from the Government of British Columbia effectively exempting these projects from further regulatory approval by the British Columbia Utilities Commission; however, Tilbury 1B approval is conditional upon having long-term energy supply contracts in place for 70% of the additional liquefaction capacity, on average for the first 15 years of operation. FortisBC has a conditional contract with Hawaiian Electric Company that would meet this requirement, subject to the regulatory approval process in Hawaii. The pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG facility. These additional $1 billion of investment opportunities, which would be included in FortisBC's regulated rate base, are not included in the Corporation's capital expenditure forecast.
In January 2015, upon expiration of the Springerville Unit 1 lease, UNS Energy closed the purchase of an additional ownership interest in the unit for US$46 million. UNS Energy's ownership interests in Springerville Unit 1 now total 49.5%. Additionally, upon expiration of the Springerville Coal Handling Facilities lease in April 2015, UNS Energy purchased the previously leased coal-handling assets for US$73 million.
Over the five-year period through 2019, gross consolidated capital expenditures are expected to be approximately $9 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 37% at U.S. Regulated Electric & Gas Utilities; 36% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 20% at Canadian Regulated Gas Utility; 5% at Caribbean Regulated Electric Utilities; and the remaining 2% 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: 50% for sustaining capital expenditures, 28% to meet customer growth, and 22% 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. The subsidiaries expect to be able to source the cash required to fund their 2015 capital expenditure programs.
In April 2015 FortisBC Energy filed a short-form base shelf prospectus to establish a Medium Term Note Debenture Program under which FortisBC Energy may issue debentures in an aggregate principal amount of up to $1 billion during the 25-month life of the shelf prospectus. In April 2015 FortisBC Energy issued 30-year $150 million 3.375% unsecured debentures. The net proceeds were used to repay short-term borrowings.
As at March 31, 2015, management expects consolidated fixed-term debt maturities and repayments to average approximately $250 million annually over the next five years. The combination of available credit facilities and relatively low annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
Fortis and its subsidiaries were compliant with debt covenants as at March 31, 2015 and are expected to remain compliant throughout 2015.
CREDIT FACILITIES
As at March 31, 2015, th
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