Fortis Reports Strong Third Quarter Earnings of $151 Million; $1.7 Billion in Capital Invested Year to Date
(firmenpresse) - ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 11/06/15 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS), a leader in the North American electric and gas utility industry, released its third quarter results today. Driven by its U.S. utility acquisitions, completion of the Waneta Expansion, and strong results from its other utilities, Fortis' net earnings attributable to common equity shareholders were $151 million, or $0.54 per common share, and $145 million, or $0.52 per common share, on an adjusted basis.
"All of our businesses contributed to our strong third quarter earnings," said Barry Perry, President and Chief Executive Officer of Fortis. "With our exit from the commercial real estate and hotel business, we have tightened our focus on the growth of our core utility business."
Strong earnings and cash flow; capital expenditure plan on track
Increasing total shareholder return and sharpening focus on the core utility business
During the third quarter Fortis increased its dividend per common share over 10% to $0.375 per quarter, or $1.50 on an annualized basis. This increase follows a 6.25% increase that was implemented in March 2015. Fortis also announced dividend guidance in the quarter, targeting annual dividend per common share growth through 2020 of 6% based on a 2016 dividend of $1.50.
After the sale of the commercial real estate and hotel assets, as well as the disposition of non-regulated generation assets in New York and Ontario, substantially all of Fortis' assets are comprised of regulated utilities and long-term contracted energy infrastructure. Net proceeds of almost $900 million from these sales were used by the Corporation to repay credit facility borrowings, largely associated with the acquisition of UNS Energy, and for other general corporate purposes. The sale of the hotel assets closed in mid-October.
"We remain committed to profitable growth, and we believe building on the strength of our core business and further diversifying our asset base in regulated utilities will achieve this," continued Mr. Perry. "Our confidence in our business, supported by investing in additional energy infrastructure opportunities, and executing on a robust capital expenditure plan, supports our forecast rate base growth and our targeted annual dividend growth rate of 6% through 2020."
Regulatory and Legal Proceedings
In November 2015 Tucson Electric Power Company ("TEP"), UNS Energy's largest utility, filed a general rate application with the Arizona Corporation Commission requesting new retail rates to be effective January 1, 2017, using June 30, 2015 as a historical test year. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.6 billion and the common equity component of capital structure increased from approximately 43.5% to approximately 50%.
The Corporation's regulatory calendar for its utilities in Canada continues to be extensive. Newfoundland Power and Maritime Electric recently filed general rate applications for 2016 and FortisBC Energy, the benchmark utility in British Columbia, filed its application to review cost of capital for 2016. The regulator in Alberta has also initiated a generic cost of capital proceeding for 2016 and 2017, which will impact FortisAlberta.
In August 2015 the Corporation agreed to terms of a settlement with the Government of Belize ("GOB") regarding the GOB's expropriation of the Corporation's approximate 70% interest in Belize Electricity Limited ("Belize Electricity") in June 2011. The terms of the settlement included a one-time US$35 million cash payment to Fortis from the GOB and an approximate 33% equity investment in Belize Electricity.
Outlook
Fortis' focus, and virtually all of the Corporations' assets, are low-risk, regulated utility businesses and long-term contracted energy infrastructure. No single regulatory jurisdiction comprises more than one third of total assets.
Over the five-year period through 2020, the Corporation's capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase rate base to approximately $20 billion in 2020 and produce a five-year compound annual growth rate of approximately 4.5%. In addition to the base capital expenditure program, Fortis is pursuing additional investment opportunities in existing and new franchise areas, including further investment in natural gas related infrastructure. Fortis expects this capital investment to support growth in earnings and dividends.
During the third quarter of 2015, Fortis initiated dividend guidance. Fortis is targeting annual dividend growth of 6% through 2020. This guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at its utilities, the successful execution of its $9 billion five-year capital plan, and management's continued confidence in the strength of its diversified portfolio of assets and record of operational excellence.
Teleconference to Discuss Third Quarter 2015 Results
A teleconference and webcast will be held on November 6 at 9:00 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 third 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 November 17, 2015. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 15840401.
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, 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. 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. Forward-looking statements are typically identified by words such as "anticipates", "budgets", "could", "estimates", "expects", "forecasts", "may", "might", "opportunity", "projects", "pending", "schedule", "should", "target", "would" and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements included in the MD&A include, but are not limited to, statements related to the annualized 2016 common share dividend; targeted annual dividend growth through 2020; the expectation that midyear rate base will increase from 2015 to 2020; the Corporation's forecast gross consolidated capital expenditures for 2015 and total capital spending for the period from 2016 through 2020; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; 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 the Woodfibre LNG site, the development of a diesel power plant in Grand Cayman, the Pinal transmission project in Arizona and additional opportunities including electric transmission, LNG and renewable related infrastructure and generation; 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 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; and the expectation that the adoption of future accounting or tax pronouncements will not have a material impact on the Corporation's consolidated financial statements.
Forward-looking statements involve significant risk, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements. These factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations. Such risk factors or assumptions include, but are not limited to, reasonable decisions by regulators; the implementation of the Corporation's five-year plan; no material capital project and financing cost overrun related to any of the Corporation's capital projects; the realization of additional opportunities including natural gas related infrastructure and generation; fluctuating foreign exchange; the Board exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; 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. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking statements. These factors should be considered carefully and undue reliance should not be placed on the forward-looking statements.
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. 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 almost $29 billion and fiscal 2014 revenue of $5.4 billion. Its regulated utilities serve more than 3 million customers across Canada and in the United States and the Caribbean. Fortis also owns long-term contracted hydroelectric generation assets in British Columbia and Belize.
Year-to-date September 30, 2015, the Corporation's electricity distribution systems met a combined peak demand of 9,685 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 and nine months ended September 30, 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 jurisdictions, 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. If a historical test year is used to set customer rates, which is the situation at UNS Energy Corporation ("UNS Energy"), there may be regulatory lag between when costs are incurred and when they are reflected in customer rates. 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 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; (vi) regulatory lag in the case of a historical test year; and (vii) 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
Settlement of Belize Electricity Limited Expropriation Matters: In August 2015 the Corporation agreed to terms of a settlement with the Government of Belize ("GOB") regarding the GOB's expropriation of the Corporation's approximate 70% interest in Belize Electricity Limited ("Belize Electricity") in June 2011. The terms of the settlement included a one-time US$35 million cash payment to Fortis from the GOB and an approximate 33% equity investment in Belize Electricity. As a result of the settlement, the Corporation recognized an approximate $9 million loss in the third quarter.
Sale of Commercial Real Estate and Hotel Assets: In June 2015 the Corporation completed the sale of the commercial real estate assets of Fortis Properties Corporation ("Fortis Properties") for gross proceeds of $430 million. As a result of the sale, the Corporation recognized an after-tax gain of approximately $109 million, net of expenses, in the second quarter. As part of the transaction, Fortis subscribed to $35 million in trust units of Slate Office REIT in conjunction with the REIT's public offering. Net proceeds from the sale were used by the Corporation to repay credit facility borrowings, the majority of which were used to finance a portion of the acquisition of UNS Energy.
In October 2015 the Corporation completed the sale of the hotel assets of Fortis Properties for gross proceeds of $365 million. As at September 30, 2015, the associated assets have been classified as held for sale on the Corporation's interim unaudited consolidated balance sheet. As a result, the Corporation recognized an approximate $8 million after-tax loss year-to-date 2015, which includes an impairment loss and expenses associated with the sale transaction. Net proceeds from the sale were used by the Corporation to repay credit facility borrowings and for other general corporate purposes.
Sale of Non-Regulated Generation Assets in New York and Ontario: In June 2015 the Corporation sold its non-regulated generation assets in Upstate New York for gross proceeds of approximately $77 million (US$63 million). As a result of the sale, the Corporation recognized an after-tax gain of approximately $27 million (US$22 million), net of expenses and foreign exchange impacts, in the second quarter.
In July 2015 the Corporation closed the sale of its non-regulated generation assets in Ontario for gross proceeds of approximately $16 million. As a result of the sale, the Corporation recognized an after-tax gain of approximately $5 million in the third quarter.
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. The Waneta Expansion contributed $17 million in earnings to the Corporation year-to-date 2015. For further information regarding the Waneta Expansion, refer to the "Non-Regulated - Fortis Generation" and "Capital Expenditure Program" sections of this MD&A.
Regulatory Decisions and Applications: The information below highlights the most significant regulatory decisions and applications of the Corporation's utilities year-to-date 2015. For further details, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
In November 2015 Tucson Electric Power Company ("TEP"), UNS Energy's largest utility, filed a general rate application ("GRA") with the Arizona Corporation Commission ("ACC") requesting new retail rates to be effective January 1, 2017, using June 30, 2015 as a historical test year. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.6 billion and the common equity component of capital structure increased from approximately 43.5% to approximately 50%.
In June 2015 the New York State Public Service Commission ("PSC") issued a Rate Order for Central Hudson covering a three-year period, with new electricity and natural gas delivery rates effective July 1, 2015. A delivery rate freeze was implemented for electricity and natural gas delivery rates through June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson invested approximately US$225 million in energy infrastructure during the two-year delivery rate freeze period ending June 30, 2015. The approved Rate Order reflects an allowed ROE of 9.0% and a 48% common equity component of capital structure and includes continuation of revenue decoupling and earnings sharing mechanisms.
In March 2015 regulatory decisions were received on FortisAlberta Inc.'s ("FortisAlberta") Capital Tracker Applications and the Generic Cost of Capital ("GCOC") Proceeding in Alberta. As a result of these regulatory decisions, in the first half of 2015, FortisAlberta recognized a positive $9 million capital tracker revenue adjustment associated with 2013 and 2014.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with the primary measures of financial performance being earnings per common share and total shareholder return. 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, 2015 and 2014 are provided in the following table.
Revenue
The increase in revenue for the quarter and year to date was driven by the acquisition of UNS Energy in August 2014. Favourable foreign exchange associated with the translation of US dollar-denominated revenue, contribution from the Waneta Expansion and higher revenue at the Canadian Regulated Electric Utilities also contributed to the increase. The increase was partially offset by a decrease in the commodity cost of natural gas charged to customers at FortisBC Energy and a decrease in non-utility revenue due to the sale of commercial real estate assets in June 2015.
Energy Supply Costs
The increase in energy supply costs for the quarter and year to date 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 a lower commodity cost of natural gas at FortisBC Energy.
Operating Expenses
The increase in operating expenses for the quarter and year to date 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. The increase was partially offset by a decrease in non-utility operating expenses due to the sale of commercial real estate assets in June 2015 and lower retirement expenses. Retirement expenses of approximately $9 million ($8 million after tax) and $13 million ($11 million after tax) were recognized in the third quarter and year-to-date 2014, respectively, compared to approximately $2 million ($1 million after tax) recognized year-to-date 2015.
Depreciation and Amortization
The increase in depreciation and amortization for the quarter and year to date 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, for the quarter was primarily due to acquisition-related expenses associated with UNS Energy recognized in the third quarter of 2014.
The increase in other income, net of expenses, year to date was primarily due to gains on the sale of commercial real estate and non-regulated generation assets year-to-date 2015 and acquisition-related expenses associated with UNS Energy recognized year-to-date 2014. The increase was partially offset by a loss associated with the sale of hotel assets year-to-date 2015.
Finance Charges
The decrease in finance charges for the quarter was primarily due to lower interest on convertible debentures. Approximately $33 million ($23 million after tax) and $67 million ($47 million after tax) in interest expense for the quarter and year to date, respectively, was recognized in 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. The decrease was partially offset by finance charges associated with the acquisition of UNS Energy, including interest expense on debt issued to complete the financing of the acquisition, and unfavorable foreign exchange associated with the translation of US-dollar denominated interest expense.
The increase in finance charges year to date was primarily due to the acquisition of UNS Energy, as discussed above for the quarter, and unfavorable foreign exchange associated with the translation of US-dollar denominated interest expense. The increase was partially offset by lower interest on convertible debentures, as discussed above for the quarter.
Income Tax Expense
The increase in income tax expense for the quarter was primarily due to higher earnings before income taxes, driven by the acquisition of UNS Energy. The increase was partially offset by a deferred income tax recovery associated with the sale of hotel assets.
The increase in income tax expense year to date was primarily due to higher earnings before income taxes, driven by the acquisition of UNS Energy and gains on the sale of commercial real estate and non-regulated generation assets. The increase was partially offset by a deferred income tax recovery associated with the sale of hotel assets.
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 and year to date was driven by earnings contribution of $97 million and $169 million, respectively, at UNS Energy compared to $37 million for the third quarter and year-to-date 2014. Earnings contribution of $5 million and $17 million for the third quarter and year-to-date 2015, respectively, from the Waneta Expansion, which represents the Corporation's 51% controlling ownership, also contributed to the increase. Performance for the quarter and year to date was also driven by the Corporation's other regulated utilities, including higher capital tracker revenue for 2015 and customer growth at FortisAlberta; improved performance at Central Hudson; and favourable foreign exchange associated with US dollar-denominated earnings. Earnings at FortisBC Energy and FortisBC Electric were impacted by the timing of regulatory deferral mechanisms; however, FortisBC Energy's earnings for the quarter and year to date were favourably impacted by lower operating expenses and a higher equity component of allowance for funds used during construction ("AFUDC"). The increase in adjusted earnings for the quarter and year to date was partially offset by higher preference share dividends and finance charges in the Corporate and Other segment, largely associated with the acquisition of UNS Energy.
The increase in adjusted earnings per common share for the quarter and year to date was driven by accretion associated with 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. Performance at the Corporation's other regulated utilities, as discussed above, contribution from the Waneta Expansion, and the impact of favourable foreign exchange also contributed to the increase.
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 third quarter were 4,426 gigawatt hours ("GWh") compared to 4,219 GWh for the full quarter last year and 11,804 GWh for the first nine months of 2015 compared to 10,977 GWh for the full nine months of 2014. The increase was primarily due to higher short-term wholesale sales. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings. Retail sales were comparable quarter over quarter. The year-to-date increase was partially offset by lower retail sales as a result of a decrease in industrial and commercial load.
Gas volumes for the quarter and year to date were comparable with the same periods 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 quarter and year to date was US$476 million and US$1,228 million, respectively, compared to US$457 million and US$1,177 million, respectively, for the same periods last year. The increase was primarily due to the flow through to customers of higher purchased power and fuel supply costs, higher wholesale electricity sales, higher transmission revenue and an increase in lost fixed cost recovery revenue. The year-to-date increase was partially offset by lower retail electricity sales.
Earnings
Earnings for the quarter and year to date were US$74 million and US$132 million, respectively, compared to US$67 million and US$123 million for the same periods last year, excluding the impact of acquisition-related expenses. The increase was primarily due to higher transmission revenue, an increase in lost fixed cost recovery revenue, and a decrease in interest expense due to the expiry of leasing arrangements. The year-to-date increase was partially offset by higher operating expenses.
CENTRAL HUDSON
Electricity Sales & Gas Volumes
The increase in electricity sales for the quarter and year to date was due to higher average consumption as a result of warmer temperatures. Gas volumes for the quarter and year to date were comparable with the same periods last year.
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.
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 for the quarter and year to date was driven by approximately $32 million and $83 million, respectively, of favourable foreign exchange associated with the translation of US dollar-denominated revenue. An increase in base electricity rates effective July 1, 2015 and the recovery from customers of previously deferred electricity costs also contributed to the increase in revenue. Additionally, revenue for the first half of 2015 was favourably impacted by energy efficiency incentives and higher gas revenue associated with a new gas delivery contract in late 2014. The increase in revenue for the quarter and year to date was partially offset by the recovery from customers of lower commodity costs, which were mainly due to lower wholesale prices.
Earnings
The increase in earnings for the quarter was primarily due to approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings and an increase in base electricity rates effective July 1, 2015.
The increase in earnings year to date was primarily due to approximately $6 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings. An increase in base electricity rates effective July 1, 2015, a new gas delivery contract in late 2014 and energy efficiency incentives earned during the first half of 2015 also contributed to the increase in earnings. The increase was partially offset by the impact of higher expenses during the two-year rate freeze period post acquisition, which ended on June 30, 2015.
REGULATED GAS UTILITY - CANADIAN
FORTISBC ENERGY (1)
Gas Volumes
Gas volumes for the quarter were comparable with the same period last year. The decrease in gas volumes year to date was primarily due to lower average consumption in the first quarter 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 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 for the quarter and year to date was primarily due to a lower commodity cost of natural gas charged to customers, amounts owing to customers under the earnings sharing mechanism, 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. Lower gas volumes also had an unfavourable impact on revenue year to date.
(Loss) Earnings
The higher loss for the quarter and decrease in earnings year to date were mainly due to approximately $13 million and $9 million, respectively, associated with the timing of regulatory flow-through deferral amounts, as discussed above, and 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 reverted to those of FEI, which are 8.75% and 38.5%, respectively. The decrease was partially offset by lower operating expenses, net of the regulatory earnings sharing mechanism, and a higher equity component of AFUDC.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
Energy Deliveries
The increase in energy deliveries for the quarter and year to date was primarily due to higher average consumption by residential, commercial and farm and irrigation customers, mainly due to warmer temperatures, and growth in the number of residential and commercial customers. Lower levels of precipitation also had a favorable impact on energy deliveries to farm and irrigation customers for the quarter. The increase was partially offset by lower average consumption by oil and gas customers due to low commodity prices for oil and gas.
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 for the quarter was primarily due to the operation of the PBR formula, including an increase in customer rates based on a combined inflation and productivity factor of 1.49%, higher 2015 capital tracker revenue, growth in the number of customers, and higher revenue related to flow-through costs to customers.
The increase in revenue year to date was due to the same factors discussed above for the quarter, combined with a positive $9 million capital tracker revenue adjustment recognized in the first half of 2015 associated with 2013 and 2014, as discussed below.
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%. The impact of the changes in the allowed ROE and common equity component of capital structure only applies to the portion of FortisAlberta's revenue that is funded by capital tracker revenue throughout the term of the PBR regulation. The $9 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 this MD&A.
Earnings
The increase in earnings for the quarter and year to date was primarily due to rate base growth and associated 2015 capital tracker revenue, growth in the number of customers and a decrease in depreciation and amortization as a result of a technical update to FortisAlberta's last depreciation study. Also contributing to the increase in earnings year to date was capital tracker revenue of approximately $9 million recognized in the first half of 2015 associated with 2013 and 2014, as discussed above.
FORTISBC ELECTRIC (1)
Electricity Sales
The increase in electricity sales for the quarter was mainly due to higher average consumption as a result of changes in temperatures. The decrease in electricity sales year to date was primarily due to lower average consumption in the first quarter as a result of warmer temperatures.
Revenue
The increase in revenue for the quarter was driven by increases in base electricity rates, electricity sales growth and surplus capacity sales. Revenue was also favourably impacted by higher contribution from non-regulated operating, maintenance and management services.
The increase in revenue year to date was due to the same factors discussed above for the quarter, partially offset by a decrease in electricity sales.
Earnings
The decrease in earnings for the quarter 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, as well as the timing of power purchase costs. The decrease was partially offset by higher earnings from non-regulated operating, maintenance and management services.
The increase in earnings year to date was primarily due to timing differences, as discussed above for the quarter, which had the opposite effect on year-to-date earnings, rate base growth, and higher earnings from non-regulated operating, maintenance and management services. The increases in base electricity rates were mainly established to recover higher power purchase costs, which commenced in the second quarter of 2015.
EASTERN CANADIAN ELECTRIC UTILITIES (1)
Electricity Sales
The increase in electricity sales for the quarter and year to date was primarily due to customer growth in Newfoundland, as well as higher average consumption on Prince Edward Island, mainly due to an increase in the number of customers using electricity for home heating. The year-to-date increase was partially offset by lower average consumption in Ontario.
Revenue
The increase in revenue for the quarter and year to date was mainly due to the flow through in customer electricity rates of higher energy supply costs and electricity sales growth. The increase was partially offset by a higher regulatory rate of return adjustment at Maritime Electric for the quarter and year-to-date 2015 compared to the same periods last year, and lower electricity sales in Ontario.
Earnings
Earnings for the quarter were comparable with the same period last year.
The increase in earnings year to date was primarily due to electricity sales growth and lower operating costs, mainly due to restoration efforts at Newfoundland Power following the loss of energy supply from Newfoundland and Labrador Hydro and related power interruptions in January 2014. The increase was partially offset by $1 million in business development costs in Ontario.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
Electricity Sales
The increase in electricity sales for the quarter and year to date was primarily due to growth in the number of customers as a result of increased economic activity and overall warmer temperatures, which increased air conditioning load.
Revenue
The increase in revenue for the quarter and year to date was primarily due to approximately $13 million and $30 million, respectively, of favourable foreign exchange associated with the translation of US dollar-denominated revenue, and electricity sales growth. The increase was partially offset by the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities.
Earnings
The increase in earnings for the quarter and year to date was due to approximately $2 million and $3 million, respectively, of favourable foreign exchange associated with the translation of US dollar-denominated earnings, electricity sales growth and higher capitalized interest at Caribbean Utilities, partially offset by higher depreciation.
NON-REGULATED - FORTIS GENERATION (1)
Energy Sales
The increase in energy sales for the quarter was driven by the Waneta Expansion, which commenced production on April 2, 2015 and reported energy sales of 88 GWh for the third quarter. Increased production in Belize due to higher rainfall early in the quarter also contributed to the increase, which was partially offset by decreased production in Upstate New York and Ontario due to the sale of generation assets in June 2015 and July 2015, respectively.
The increase in energy sales year to date was driven by the Waneta Expansion, as discussed above for the quarter, which reported energy sales of 485 GWh. The increase was partially offset by decreased production in Belize due to lower rainfall and decreased production in Upstate New York and Ontario due to the sale of generation assets, as discussed above for the quarter, lower rainfall, and generating units taken out of service for repairs.
Revenue
The increase in revenue for the quarter and year to date was driven by the Waneta Expansion, which recognized revenue of $18 million and $49 million, respectively, and favourable foreign exchange associated with the translation of US dollar-denominated revenue of approximately $2 million and $3 million, respectively. Increased production in Belize also contributed to the increase for the quarter. The increase in revenue year to date was partially offset by decreased production in Belize, Upstate New York and Ontario.
Earnings
The increase in earnings for the quarter was due to earnings contribution of $5 million from the Waneta Expansion, which represents the Corporation's 51% controlling ownership interest, the recognition of an after-tax gain of approximately $5 million on the sale of generation assets in Ontario in July 2015, increased production in Belize, and approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings.
The increase in earnings year to date was driven by the recognition of after-tax gains of approximately $27 million (US$22 million) and $5 million, net of expenses and foreign exchange impacts, on the sale of generation assets in Upstate New York in June 2015 and Ontario in July 2015, respectively, and earnings contribution of $17 million from the Waneta Expansion. Favourable foreign exchange associated with the translation of US dollar-denominated earnings of approximately $2 million and lower business development costs were partially offset by decreased production in Belize, Upstate New York and Ontario.
NON-REGULATED - NON-UTILITY (1)
Revenue
The decrease in revenue at Fortis Properties for the quarter and year to date was primarily due to the sale of commercial real estate assets in June 2015.
Earnings
Earnings for the quarter reflect a $5 million positive adjustment, largely related to a deferred income tax recovery, associated with the sale of hotel assets, compared to an after-tax loss of approximately $8 million year to date. An after-tax gain of approximately $109 million, net of expenses, on the sale of Fortis Properties' commercial real estate assets was recognized in the second quarter of 2015. For further information, refer to the "Significant Items" section of this MD&A.
Excluding the impacts of the above-noted sales transactions, Fortis Properties contributed earnings of $6 million and $12 million for the quarter and year to date, respectively, compared to $9 million and $16 million, respectively, for the same periods last year. The decrease in earnings was primarily due to the sale of commercial real estate assets in June 2015, partially offset by lower depreciation associated with the hotel assets. Earnings for the first quarter of 2014 include $5 million associated with Griffith from normal operations to the date of sale in March 2014.
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 $31 million and $100 million for the quarter and year to date, respectively, compared to $35 million and $80 million, respectively, for the same periods last year. The variance explanations below exclude the above-noted items.
The $4 million decrease in net Corporate and Other expenses for the quarter was primarily due to lower operating expenses, partially offset by higher preference share dividends associated with preference shares issued to finance a portion of the acquisition of UNS Energy. Retirement expenses of approximately $9 million ($8 million after tax) were recognized in the third quarter of 2014. Finance charges were comparable quarter over quarter. The impacts of no longer capitalizing interest upon completion of the Waneta Expansion, new long-term debt associated with the acquisition of UNS Energy, and unfavourable foreign exchange associated with the translation of US-dollar denominated interest expense were largely offset by interest on the Corporation's acquisition credit facility in the third quarter of 2014, which was used to initially finance a portion of the acquisition of UNS Energy.
The $20 million increase in net Corporate and Other expenses year to date was primarily due to higher preference share dividends and finance charges, largely as a result of the acquisition of UNS Energy. Finance charges were also impacted by no longer capitalizing interest upon completion of the Waneta Expansion and unfavourable foreign exchange associated with the translation of US-dollar denominated interest expense. The increases were partially offset by a higher income tax recovery and lower operating expenses. Retirement expenses of approximately $13 million ($11 million after tax) were recognized year-to-date 2014 compared to approximately $2 million ($1 million after tax) recognized year-to-date 2015. Additionally, a $3 million ($2 million after tax) corporate donation was recognized in the second quarter of 2015.
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 year-to-date 2015.
UNS Energy
In November 2015 TEP, UNS Energy's largest utility, filed a GRA with the ACC requesting new retail rates to be effective January 1, 2017, using June 30, 2015 as a historical test year. The key provisions of the rate request include: (i) a base retail rate increase of US$110 million, or 12.0%, compared with adjusted test year revenue; (ii) a 7.34% return on original cost rate base of US$2.1 billion, which includes approximately US$73 million of post-test year adjustments for utility capital assets that are expected to be in service by December 31, 2016; (iii) a common equity component of capital structure of approximately 50%; and (iv) rate design changes that would reduce the reliance on volumetric sales to recover fixed costs, and a new net metering tariff that would ensure that customers who install distributed generation pay an equitable price for their electric service. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.6 billion and the common equity component of capital structure increased from approximately 43.5% to approximately 50%. In May 2015 UNS Electric filed a GRA requesting new retail rates to be effective May 1, 2016, using December 31, 2014 as a historical test year. The nature of UNS Electric's GRA was similar to that of TEP.
Central Hudson
In June 2015 the PSC issued a Rate Order for Central Hudson covering a three-year period, with new electricity and natural gas delivery rates effective July 1, 2015. A delivery rate freeze was implemented for electricity and natural gas delivery rates through June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson invested approximately US$225 million in energy infrastructure during the two-year delivery rate freeze period ending June 30, 2015. The approved Rate Order reflects an allowed ROE of 9.0% and a 48% common equity component of capital structure. The Rate Order includes capital investments of approximately US$490 million during the three-year period targeted at making the electric and gas systems stronger.
The approved Rate Order includes full cost recovery of electric and natural gas commodity costs and continuation of certain mechanisms, including revenue decoupling and earnings sharing mechanisms. In the approved 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. In addition, the Rate Order includes a major storm reserve for electric operations and provides for continuation of recovery of various operating expenses, including environmental site investigation and remediation costs. To the extent that Central Hudson receives gas delivery revenue associated with a new contract in late 2014, effective July 1, 2015, associated revenue is being used to mitigate future gas customer rate increases.
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 reverted to those of FEI, which are 8.75% and 38.5%, respectively.
In May 2015 and June 2015, the BCUC issued its decisions on FEI and FortisBC Electric's 2015 rates in compliance with the PBR decisions issued in September 2014. The decisions approved 2015 midyear rate base of approximately $3,661 million and $1,249 million for FEI and FortisBC Electric, respectively, and approved customer rate increases for 2015 of 0.7% and 4.2% over 2014 rates, respectively. For FortisBC Electric, this decision results in the Company applying a 3.5% rate increase from January 1, 2015 to July 31, 2015, and a 5.1% rate increase effective August 1, 2015, both as compared to 2014 rates.
In September 2015 FEI and FortisBC Electric filed applications for approval of 2016 rates under the PBR plan. The 2016 applications include forecast midyear rate base of approximately $3,691 million and $1,287 million for FEI and FortisBC Electric, respectively, and request approval of customer rate increases for 2016 of 2.22% and 1.98%, respectively. In October 2015 the Companies filed evidentiary updates to the applications, which updated the 2016 customer rate increases to 2.74% for FEI and 3.12% for FortisBC Electric.
In October 2015, as required by the regulator, FEI filed its application to review the 2016 benchmark allowed ROE and common equity component of capital structure. As FEI is the benchmark utility, the review of the application could also have an impact on FortisBC Electric.
FortisAlberta
Generic Cost of Capital Proceedings
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%. The AUC also determined that it will not re-establish a formula-based approach to setting the allowed ROE at this time. Instead, the allowed ROE of 8.30% and common equity component of capital structure of 40% will remain in effect on an interim basis for 2016 and beyond. For regulated utilities in Alberta under PBR mechanisms, including FortisAlberta, the impact of the changes to the allowed ROE and common equity component of capital structure resulting from the GCOC Proceeding applies to the portion of rate base that is funded by capital tracker revenue only. For assets not being funded by capital tracker revenue, no revenue adjustment is required for the change in the allowed ROE of 8.75% and common equity component of capital structure of 41%, as set in a previous GCOC decision.
In April 2015 the AUC initiated a GCOC Proceeding to set the allowed ROE and capital structure for 2016 and 2017. While the AUC approved a request by utilities in Alberta to negotiate matters at issue in the GCOC Proceeding for 2016, a negotiated settlement was not reached. Therefore, the 2016 and 2017 GCOC Proceeding will commence in the first quarter of 2016.
Capital Tracker Applications
The funding of capital expenditures during the PBR term is a material aspect of the PBR plan for FortisAlberta. The PBR plan provides a capital tracker mechanism to fund the recovery of costs associated with certain qualifying capital expenditures.
In March 2015 the AUC issued its decision related to FortisAlberta's 2013, 2014 and 2015 Capital Tracker Applications. The decision: (i) indicated that the majority of the Company's applied for capital trackers 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) confirmed 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.
In September 2015 the AUC approved FortisAlberta's compliance filing related to the 2015 Capital Tracker Decision, substantially as filed. Capital tracker revenue of $17 million was approved for 2013 on an actual basis and capital tracker revenue of $42 million and $62 million was approved on a forecast basis for 2014 and 2015, respectively. FortisAlberta collected $15 million and $29 million in 2013 and 2014, respectively, and expects to collect $62 million in 2015, related to capital tracker expenditures.
In May 2015 FortisAlberta filed an application with the AUC seeking: (i) capital tracker revenue for 2016 of $72 million and 2017 of $90 million, respectively; (ii) a reduction of $7 million to reflect actual capital expenditures; and (iii) approval of additional revenue of $3 million related to capital tracker amounts that had not been fully approved in the 2015 Capital Tracker Decision. A hearing related to this proceeding concluded in October 2015, with a decision from the regulator expected in the first quarter of 2016.
FortisAlberta expects to recognize capital tracker revenue of approximately $59 million in 2015, of which $9 million is related to 2013 and 2014 capital tracker expenditures and is not yet collected from customers. The capital tracker revenue for 2015 of approximately $50 million incorporates an updated forecast for related capital expenditures as compared to the approved forecast reflected in current rates. This is expected to result in a deferral of approximately $12 million of 2015 capital tracker revenue as a regulatory liability. For the nine months ended September 30, 2015, FortisAlberta recognized capital tracker revenue of approximately $36 million related to 2015 capital tracker expenditures and deferred $9 million of revenue as a regulatory liability.
2016 Annual Rates Application
In September 2015 FortisAlberta filed its 2016 Annual Rates Application. The rates and riders, proposed to be effective on an interim basis for January 1, 2016, include an increase of approximately 6.2% to the distribution component of customer rates. This increase reflects: (i) a combined inflation and productivity factor of 0.9%; (ii) a K factor placeholder of $72 million, which is 100% of the depreciation and return associated with the 2016 forecast capital tracker expenditures as filed for in the capital tracker applications, as discussed previously; and (iii) $17 million for adjustments to 2013, 2014 and 2015 capital tracker revenue as filed for in the capital tracker compliance filing related to the 2015 capital tracker decision. A decision on this filing is expected in the fourth quarter of 2015.
Utility Asset Disposition Matters
In previous decisions, the AUC made statements regarding cost responsibility for stranded assets and gains or losses related to extraordinary retirement of utility assets, which FortisAlberta and other Alberta utilities challenged as being incorrectly made. The AUC's statements implied that the shareholder is responsible for the cost of stranded assets in a broader sense than that generally understood by regulated utilities and also conflicted with the Electric Utilities Act (Alberta). As a result, the utilities in Alberta had filed leave to appeal motions with the Court of Appeal of Alberta.
In September 2015 the Court of Appeal of Alberta issued a decision that dismissed the appeals of the utilities. The basis for the decision was that the AUC should be accorded deference for its conclusions in utility asset disposition matters. The decision by the Court of Appeal of Alberta has no immediate impact on FortisAlberta's financial position. However, the Company is exposed to the risk that the remaining unrecovered costs of utility assets subsequently deemed by the AUC to have been subject to an extraordinary retirement will not be recoverable from customers. FortisAlberta is assessing its option to file a leave to appeal motion with the Supreme Court of Canada.
Eastern Canadian Electric Utilities
In October 2015 Newfoundland Power filed a 2016/2017 GRA with the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB") to set custo
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