Fortis Reports Third Quarter Earnings of $127 million
(firmenpresse) - ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 11/04/16 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS)(NYSE: FTS), a leader in the North American regulated electric and gas utility industry, released its third quarter results today. The Corporation's net earnings attributable to common equity shareholders for the third quarter were $127 million, or $0.45 per common share, compared to $151 million, or $0.54 per common share, for the third quarter of 2015. On a year-to-date basis, earnings were $396 million, or $1.40 per common share, compared to $593 million, or $2.13 per common share, for 2015. Results reflect acquisition-related expenses associated with ITC Holdings Corp. ("ITC") in 2016 and gains on the sale of non-core assets in 2015.
On an adjusted basis, net earnings attributable to common equity shareholders for the third quarter were $154 million, or $0.54 per common share, an increase of $9 million, or $0.02 per common share, over the third quarter of 2015. On a year-to-date basis, adjusted earnings were $475 million, or $1.67 per common share, an increase of $28 million, or $0.06 per common share, over 2015. A reconciliation of adjusted net earnings and adjusted earnings per common share is provided in the Corporation's Interim Management Discussion and Analysis for the three and nine months ended September 30, 2016.
Strong performance continued in the third quarter
- Factors that resulted in growth in adjusted earnings for the third quarter included:
- Earnings growth for the third quarter was tempered by:
- Cash flow from operating activities totalled $1.4 billion year to date, an increase of approximately 10% over the same period in 2015. The increase was driven by higher cash earnings and favourable changes in working capital.
- The Corporation's capital expenditure plan is on track and capital investments reached almost $1.4 billion year to date. Consolidated capital expenditures for 2016 are now expected to total $2.1 billion, up from the original forecast of $1.9 billion. The increase is primarily due to expected capital investments at ITC from the date of acquisition. In the third quarter, UNS Energy purchased the remaining 50.5% interest in Springerville Unit 1 for US$85 million as part of a settlement agreement with the third-party owners.
"Performance in the third quarter continues to demonstrate the strength of our low-risk and diversified portfolio of utilities," said Mr. Barry Perry, President and Chief Executive Officer of Fortis.
A transformative acquisition
On October 14, 2016, Fortis and GIC Private Limited closed the acquisition of ITC in a transaction valued at approximately US$11.8 billion on closing, including approximately US$4.8 billion of ITC consolidated indebtedness at fair value. Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion. Details on the financing of the acquisition are included in the Corporation's Interim Management Discussion and Analysis for the three and nine months ended September 30, 2016.
ITC is the largest independent electric transmission company in the United States. As a result of the acquisition, 2017 forecast midyear rate base of Fortis is expected to increase by almost $7.5 billion to approximately $26 billion.
"The ITC acquisition is the largest in the history of Fortis and dramatically increases our North American footprint," explained Mr. Perry. "ITC further diversifies our business and positions us well for continued growth. We remain confident that this transaction will be accretive to earnings per common share in 2017."
Execution of growth strategy
The Corporation's five-year consolidated capital expenditures through 2021 are expected to be approximately $13 billion, including more than $3.5 billion in capital investments at ITC. The Corporation's highly executable capital plan primarily consists of a large number of individually small capital projects.
Construction continues on the Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury 1A") in British Columbia, the Corporation's largest ongoing capital project, at an estimated cost of $440 million. Approximately $388 million has been invested in Tilbury 1A to the end of the third quarter of 2016 and the facility is expected to be in service in mid-2017. The Corporation will continue to invest in four Multi Value Projects ("MVPs") at ITC. Three of the MVPs are expected to be completed by the end of 2018, with the fourth scheduled for completion in 2023.
In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories, including ITC. Specifically, the Corporation continues to pursue LNG infrastructure investment opportunities in British Columbia, including FortisBC Energy's potential pipeline expansion to the Woodfibre LNG export facility. The potential pipeline expansion has an estimated total project cost of up to $600 million. A final investment decision by Woodfibre LNG is targeted for late 2016.
Regulatory proceedings
In the third quarter, the Corporation's regulated utilities made significant progress on a number of key regulatory proceedings.
In August, Tucson Electric Power Company ("TEP") entered into a partial settlement agreement regarding its general rate application requesting new retail rates to be effective January 1, 2017, using the year ended June 30, 2015 as a historical test year. The settlement agreement includes an increase in non-fuel base revenue of US$81.5 million, an allowed rate of return on common shareholder's equity ("ROE") of 9.75%, and a common equity component of capital structure of approximately 50%. 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 has increased from 43.5% to approximately 50%. Certain aspects of the general rate application, including net metering and rate design for distributed generation customers, have been deferred to a second rate case proceeding, which is expected to begin in the first quarter of 2017. The settlement agreement is subject to regulatory approval, which is expected by the end of 2016.
GCOC Proceedings in British Columbia and Alberta also concluded in recent months. In British Columbia, the outcome resulted in FortisBC Energy maintaining its allowed ROE at 8.75% and common equity component of capital structure at 38.5%. In Alberta, the GCOC Proceeding resulted in FortisAlberta maintaining its allowed ROE at 8.30% for 2016, with a decrease in the common equity component of capital structure from 40% to 37% effective January 1, 2016. The allowed ROE for 2017 has been approved at 8.50%. Changes in FortisAlberta's allowed ROE and common equity component of capital structure impact only the portion of rate base that is funded by capital tracker revenue.
These regulatory outcomes provide stability for the Corporation's utilities in the near term. Fortis continues to be actively engaged with all of its existing regulators and is focused on maintaining constructive regulatory relationships and outcomes across its utilities.
Outlook
The Corporation's business continues to grow in 2016 and results for 2017 will benefit from the impact of ITC, the expected outcome of the TEP general rate case and continued growth of the underlying business. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital plan, the balance and strength of its diversified portfolio of businesses, as well as growth opportunities within its franchise regions.
Over the five-year period through 2021, including ITC, the Corporation's capital program is expected to be approximately $13 billion. This investment in energy infrastructure is expected to increase rate base to almost $30 billion in 2021. Fortis expects long-term sustainable growth in rate base, resulting from investment in its existing utility operations and strategic utility acquisitions, to support continuing growth in earnings and dividends.
Fortis extended its targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital expenditure program, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence.
"In September we raised our quarterly common share dividend by almost 7%, marking 43 consecutive years of common share dividend payment increases," said Perry. "This is the longest record of any public company in Canada and is one that we will strive to maintain," he concluded.
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, 2016 and the MD&A and audited consolidated financial statements for the year ended December 31, 2015 included in the Corporation's 2015 Annual Report. Financial information contained in this 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 including the Private Securities Litigation Reform Act of 1995. Forward-looking statements included in this MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities as of November 4, 2016. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking statements, which include, without limitation: the expectation that the acquisition of ITC Holdings Corp. ("ITC") will be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses; the expectation that the Corporation will recognize additional acquisition-related expenses in the fourth quarter of 2016; targeted annual dividend growth through 2021; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the Corporation's forecast midyear rate base for 2017 and the expectation that midyear rate base will increase from 2016 to 2021; the Corporation's forecast gross consolidated capital expenditures for 2016 and total capital spending through 2021;
forecast gross consolidated capital expenditures for 2016 for certain of the Corporation's subsidiaries, including ITC, FortisAlberta and UNS Energy; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas ("LNG") facility, including Tilbury 1A, the pipeline expansion to the Woodfibre LNG site, 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 the acquisition of ITC will increase total capitalization, but will not have a significant impact on the percentage breakdown of the Corporation's capital structure; 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 maintaining the targeted capital structure of the Corporation's regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the expectation that the Corporation's subsidiaries will be able to source the cash required to fund their 2016 capital expenditure programs; the expected consolidated fixed-term debt maturities and repayments over the next five years, including ITC; 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 throughout 2016; the intent of management to hedge future exchange rate fluctuations and monitor its foreign currency exposure; the expectation that FortisAlberta will recognize capital tracker revenue in 2016; Tucson Electric Power Company's expected share of mine reclamation costs; Central Hudson's estimated total remediation costs for manufactured gas plant sites; the estimated range of return on common shareholder's equity refunds and associated regulatory liabilities at ITC; 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 pronouncements will not have a material impact on the Corporation's consolidated financial statements.
Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements, including, without limitation: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; 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; the Board of Directors 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, environmental laws and regulations that may materially negatively affect the operations and cash flows of the Corporation and its subsidiaries; no material change in public policies and directions by governments that could materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the continued tax-deferred treatment of earnings from the Corporation's Caribbean operations; continued maintenance of information technology infrastructure; continued favourable relations with First Nations; favourable labour relations; 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.
Forward-looking statements involve significant risks, uncertainties and assumptions. 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 and the Securities and Exchange Commission. Key risk factors for 2016 include, but are not limited to: uncertainty related to the realization of some or all of the expected benefits of the acquisition of ITC; uncertainty regarding the outcome of regulatory proceedings of the Corporation's utilities; uncertainty of the impact a continuation of a low interest rate environment may have on the allowed rate of return on common shareholders' equity at the Corporation's regulated utilities; the impact of fluctuations in foreign exchange rates; and risk associated with the impact of less favorable economic conditions on the Corporation's results of operations.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
CORPORATE OVERVIEW
Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $47 billion, on a pro forma basis as at September 30, 2016 including the acquisition of ITC Holdings Corp. ("ITC"). The Corporation's 8,000 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.
Year-to-date September 30, 2016, the Corporation's electricity distribution systems met a combined peak demand of 9,590 megawatts ("MW") and its gas distribution system met a peak day demand of 1,335 terajoules. In addition, ITC's electricity transmission system serves a combined peak load exceeding 26,000 MW. 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, 2016 and to the "Corporate Overview" section of the 2015 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, 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
Acquisition of ITC: On October 14, 2016, Fortis and GIC Private Limited ("GIC") acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion on closing, including approximately US$4.8 billion of ITC consolidated indebtedness at fair value. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC.
Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion. The net cash consideration totalled approximately US$3.4 billion and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes on October 4, 2016; (ii) net proceeds from GIC's US$1.228 billion minority investment; and (iii) drawings of approximately US$404 million ($535 million) under the Corporation's non-revolving term senior unsecured equity bridge credit facility. On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.6 billion, based on the closing price for Fortis common shares of $40.96 and the closing foreign exchange rate of 1.32 on October 13, 2016. The financing of the acquisition has been structured to allow Fortis to maintain investment-grade credit ratings.
ITC is the largest independent electric transmission company in the United States. Based in Novi, Michigan, ITC invests in the electrical transmission grid to improve reliability, expand access to markets, allow new generating resources to interconnect to its transmission systems and lower the overall cost of delivered energy. Through its regulated operating subsidiaries ITCTransmission, Michigan Electric Transmission Company, ITC Midwest and ITC Great Plains, ITC owns and operates high-voltage transmission facilities in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma, serving a combined peak load exceeding 26,000 MW along approximately 15,700 circuit miles of transmission line. In addition, ITC Midwest maintains utility status in Wisconsin.
ITC's tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC"). As at September 30, 2016, the weighted average allowed ROEs for ITC's regulated operating subsidiaries are more than 11.00% on a 60% common equity component of capital structure. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag. Dating back to 2013, two third-party complaints were filed with FERC requesting that FERC find the Midcontinent Independent System Operator ("MISO") regional base ROE rate for all MISO transmission organizations, including ITCTransmission, Michigan Electric Transmission Company and ITC Midwest, for the periods November 2013 through February 2015 (the "Initial Refund Period") and February 2015 through May 2016 (the "Second Refund Period") to no longer be just and reasonable. In September 2016 FERC issued an order affirming the presiding Administrative Law Judge's ("ALJ's") initial decision for the Initial Refund Period and setting the base ROE at 10.32%, with a maximum ROE of 11.35%. Additionally, the rates established by the September 2016 order will be used prospectively from the date of the order until a new approved rate is established for the Second Refund Period. In June 2016 the presiding ALJ issued an initial decision for the Second Refund Period, which recommended a base ROE of 9.7%, with a maximum ROE of 10.68%, which is a non-binding recommendation to FERC. A decision from FERC for the Second Refund Period is expected in 2017. As at September 30, 2016, the estimated range of refunds for both periods is between US$219 million and US$256 million and ITC has recognized an aggregate estimated regulatory liability of US$256 million. It is possible that the outcome of these matters could differ materially from the estimated range of refunds.
Fortis and ITC shareholders approved the acquisition at shareholder meetings held in May and June 2016, respectively. All required regulatory, state and federal approvals associated with the acquisition, including, among others, those of FERC and the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act, were received prior to closing.
The acquisition is expected to be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses. ITC represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix. As a result of the acquisition, 2017 forecast midyear rate base of Fortis is expected to increase by almost $7.5 billion to approximately $26 billion.
In connection with the acquisition, on May 17, 2016, Fortis became a U.S. Securities and Exchange Commission registrant and, on October 14, 2016, commenced trading its common shares on the New York Stock Exchange. Fortis continues to list its shares on the Toronto Stock Exchange.
Acquisition-related expenses totalling $25 million ($19 million after tax) and $74 million ($58 million after tax) were recognized in earnings for the third quarter and year-to-date 2016, respectively. Acquisition-related expenses included: (i) investment banking, legal, consulting and other fees totalling approximately $4 million ($3 million after tax) and $39 million ($32 million after tax) for the third quarter and year-to-date 2016, respectively, which were included in operating expenses; and (ii) fees associated with the Corporation's acquisition credit facilities and deal-contingent interest rate swap contracts totalling approximately $21 million ($16 million after tax) and $35 million ($26 million after tax) for third quarter and year-to-date 2016, respectively, which were included in finance charges. The Corporation expects to recognize additional acquisition-related expenses in the fourth quarter of 2016.
Acquisition of Aitken Creek Gas Storage Facility
On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC ("ACGS") from Chevron Canada Properties Ltd. for approximately $349 million (US$266 million), plus working gas inventory. The net cash purchase price was primarily financed through US dollar-denominated borrowings under the Corporation's committed revolving credit facility.
ACGS owns 93.8% of the Aitken Creek gas storage site ("Aitken Creek"), with the remaining share owned by BP Canada Energy Company. Aitken Creek is the only underground natural gas storage facility in British Columbia and has a total working gas capacity of 77 billion cubic feet. The facility is an integral part of western Canada's natural gas transmission network. ACGS also owns 100% of the North Aitken Creek gas storage site which offers future expansion potential. The financial results of ACGS have been included in the Corporation's consolidated results from the date of acquisition and are included in the Non-Regulated - Energy Infrastructure reporting segment.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of long-term 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, 2016 and 2015 are provided in the following table.
Revenue
The decrease in revenue for the quarter and year to date was mainly due to a decrease in non-utility revenue due to the sale of commercial real estate and hotel assets in 2015 and the flow through in customer rates of lower overall energy supply costs, partially offset by contribution from Aitken Creek, which was acquired in April 2016. The decrease year to date was partially offset by the impact of favourable foreign exchange associated with the translation of US dollar-denominated revenue.
Energy Supply Costs
The decrease in energy supply costs for the quarter and year to date was mainly due to lower overall commodity costs, partially offset by energy supply costs at Aitken Creek. The decrease year to date was partially offset by the impact of unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs.
Operating Expenses
The decrease in operating expenses for the quarter and year to date was mainly due to a decrease in non-utility operating expenses due to the sale of commercial real estate and hotel assets. The decrease was partially offset by acquisition-related expenses associated with ITC, operating expenses at Aitken Creek, and general inflationary and employee-related cost increases. The year-to-date decrease was also partially offset by the impact of unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses.
Depreciation and Amortization
The increase in depreciation for the quarter and year to date was primarily due to continued investment in energy infrastructure at the Corporation's regulated utilities and depreciation at Aitken Creek. The impact of unfavourable foreign exchange associated with the translation of US dollar-denominated depreciation also contributed to the year-to-date increase. The year-to-date increase was partially offset by lower non-utility depreciation due to the sale of commercial real estate and hotel assets.
Other Income (Expenses), Net
The decrease in other income, net of expenses, year to date was primarily due to a net gain of approximately $109 million ($101 million after tax), net of expenses, related to the sale of commercial real estate and hotel assets in 2015 and a gain of approximately $56 million ($32 million after tax), net of expenses and foreign exchange impacts, on the sale of generation assets in 2015.
Finance Charges
The increase in finance charges for the quarter and year to date was primarily due to acquisition-related fees associated with the Corporation's acquisition credit facilities and deal-contingent interest rate swap contracts. The impact of unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense also contributed to the year-to-date increase.
Income Tax Expense
The decrease in income tax expense year to date was primarily due to lower earnings before income taxes, mainly due to the net gains on the sale of commercial real estate and hotel assets and generation assets in 2015.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings Per Common Share
Fortis supplements the use of US GAAP financial measures with non-US GAAP financial measures, including adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share. The Corporation refers to these measures as non-US GAAP financial measures since they are not required by, or presented in accordance with, US GAAP.
The Corporation defines: (i) adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes help investors better evaluate results of operations; and (ii) adjusted basic earnings per common share as adjusted net earnings attributable to common equity shareholders divided by the weighted average number of common shares outstanding. The most directly comparable US GAAP measures to adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share are net earnings attributable to common equity shareholders and basic earnings per common share.
The following table provides a reconciliation of the non-US GAAP financial measures and each of the adjusting items are discussed in the segmented results of operations for the respective reporting segments. 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 mainly due to: (i) strong performance at most of the Corporation's regulated utilities driven by UNS Energy, largely due to the settlement of Springerville Unit 1 matters, and Central Hudson, due to an increase in delivery revenue; (ii) the timing of quarterly earnings at FortisBC Electric compared to the third quarter of 2015; and (iii) contribution of $2 million from Aitken Creek, which was acquired in early April 2016. The increase was partially offset by: (i) lower earnings at FortisAlberta due to higher operating expenses, a negative capital tracker revenue adjustment as a result of the outcome of the 2016 Generic Cost of Capital ("GCOC") Proceeding in Alberta, and lower average energy consumption; (ii) the sale of hotel assets in 2015; and (iii) an increase in Corporate and Other expenses.
The increase in adjusted net earnings attributable to common equity shareholders year to date was mainly due to: (i) strong performance at most of the Corporation's regulated utilities, driven by the same factors discussed above for the quarter, a higher allowance for funds used during construction ("AFUDC") at FortisBC Energy Inc. ("FEI"), equity income of $3 million from Belize Electricity and electricity sales growth at Caribbean Utilities; (ii) favourable foreign exchange associated with US dollar-denominated earnings; and (iii) contribution of $6 million from Aitken Creek and higher earnings at the Waneta Expansion, which commenced production in early April 2015. The increase was partially offset by: (i) the sale of commercial real estate and hotel assets in 2015; (ii) lower earnings at FortisAlberta due to higher operating expenses, a negative capital tracker revenue adjustment, as discussed above, and lower average energy consumption; (iii) the timing of quarterly earnings at FortisBC Electric compared to the same period in 2015; and (iv) higher Corporate and Other expenses.
Adjusted earnings per common share for the quarter and year to date were $0.02 and $0.06 higher, respectively, compared to the same periods in 2015. The impact of the above-noted items on adjusted net earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding.
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 further discussion pertaining to the Corporation's regulated utilities.
REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES
UNS ENERGY (1)
Electricity Sales & Gas Volumes
The decrease in electricity sales for the quarter was primarily due to lower mining retail sales and year to date was primarily due to lower short-term wholesale and mining retail sales, all as a result of less favourable commodity prices compared to the same periods in 2015. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings. The decrease in electricity sales year to date was partially offset by higher residential retail electricity sales, mainly due to warmer temperatures in the second quarter of 2016, which increased air conditioning load, and cooler temperatures in the first quarter of 2016, which increased electric heating load.
Gas volumes for the quarter and year to date were comparable with the same periods in 2015.
Revenue
The decrease in revenue for the quarter was mainly due to the flow through to customers of lower purchased power and fuel supply costs, and $11 million (US$9 million), or $7 million (US$5 million) after tax, in FERC ordered transmission refunds associated with late-filed transmission service agreements. The decrease was partially offset by $17 million (US$13 million), or $10 million (US$8 million) after tax, in revenue related to the settlement of Springerville Unit 1. For details on the FERC order, refer to the "Material Regulatory Decisions and Applications" section of this MD&A. For details on the settlement of Springerville Unit 1, refer to the "Critical Accounting Estimates" section of this MD&A.
The decrease in revenue year to date was mainly due to the flow through to customers of lower purchased power and fuel supply costs, lower short-term wholesale electricity sales, and $29 million (US$22 million), or $18 million (US$13 million) after tax, in FERC ordered transmission refunds. The decrease was partially offset by approximately $51 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, revenue related to the settlement of Springerville Unit 1, an increase in lost fixed-cost recovery revenue and higher residential retail electricity sales.
Earnings
The increase in earnings for the quarter was primarily due to $10 million (US$8 million) related to the settlement of Springerville Unit 1, lower deferred income tax expense, and higher gains on investments. The increase was partially offset by $7 million (US$5 million) in FERC ordered transmission refunds in the third quarter of 2016 and higher depreciation and amortization.
The increase in earnings year to date was primarily due to the settlement of Springerville Unit 1, approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, lower deferred income tax expense, an increase in lost fixed-cost recovery revenue and higher residential retail electricity sales. The increase was partially offset by $18 million (US$13 million) in FERC ordered transmission refunds and higher operating expenses and depreciation and amortization.
CENTRAL HUDSON
Electricity Sales & Gas Volumes
Electricity sales and gas volumes for the quarter and year to date were favorably impacted by the timing of customer billings, as a result of regulatory approval to increase billing frequency to monthly effective July 1, 2016. The increase in electricity sales for the quarter was also due to higher average consumption as a result of warmer temperatures, which increased air conditioning load. The decrease in electricity sales and gas volumes year to date was due to lower average consumption in the first quarter of 2016 as a result of warmer temperatures, which reduced heating load.
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.
Revenue
The increase in revenue for the quarter was primarily due to the recovery from customers of higher commodity costs and higher delivery revenue from an increase in base electricity rates effective July 1, 2016.
The decrease in revenue year to date was mainly due to the recovery from customers of lower commodity costs, which were mainly due to overall lower wholesale prices, and the impact of energy-efficiency incentives earned during the first half 2015 upon achieving energy saving targets established by the regulator. The decrease was partially offset by approximately $19 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue and higher delivery revenue from increases in base electricity rates effective July 1, 2016 and 2015.
Earnings
The increase in earnings for the quarter and year to date was primarily due to increases in delivery revenue. The increase year to date was also due to approximately $4 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, partially offset by the impact of energy-efficiency incentives earned during the first half of 2015, as discussed above.
REGULATED GAS UTILITY - CANADIAN
FORTISBC ENERGY
Gas Volumes
The increase in gas volumes for the quarter and year to date was primarily due to higher volumes for transportation customers, due to certain transportation customers switching to natural gas compared to alternative fuel sources. Also contributing to the year to date increase was higher average consumption by residential and commercial customers during the first quarter of 2016 due to colder temperatures.
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 and the timing of regulatory flow-through deferral amounts. The decrease was partially offset by an increase in customer delivery rates effective January 1, 2016 and higher gas volumes.
(Loss) Earnings
The lower loss for the quarter and increase in earnings year to date were primarily due to higher AFUDC, partially offset by the timing of regulatory flow-through deferral amounts compared to the same periods in 2015.
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.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
Energy Deliveries
The decrease in energy deliveries for the quarter and year to date was primarily due to lower average consumption by oil and gas customers as a result of low commodity prices for oil and gas, and lower average consumption by residential, commercial and irrigation customers, mainly due to cooler temperatures in the third quarter of 2016. The decrease was partially offset by higher energy deliveries to residential customers due to customer growth.
Revenue
The increase in revenue for the quarter was due to an increase in customer rates effective January 1, 2016 based on a combined inflation and productivity factor of 0.9%, growth in the number of residential customers and higher revenue related to flow-through costs to customers. The increase was partially offset by lower average consumption and a $2 million negative capital tracker revenue adjustment as a result of the outcome of the 2016 GCOC Proceeding in Alberta. For details on this regulatory decision, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
The increase in revenue year to date was due to the same factors discussed above for the quarter, partially offset by the impact of a $9 million positive capital tracker revenue adjustment recognized in the first half of 2015 that related to 2013 and 2014.
Earnings
The decrease in earnings for the quarter and year to date was due to higher operating expenses, the $2 million negative capital tracker revenue adjustment recognized in the third quarter of 2016, as discussed above, and lower average energy consumption, partially offset by rate base growth and growth in the number of customers. The decrease in earnings year to date was also due to the $9 million positive capital tracker revenue adjustment recognized in the first half of 2015, as discussed above.
FORTISBC ELECTRIC (1)
Electricity Sales
The decrease in electricity sales for the quarter and year to date was mainly due to lower average consumption as a result of changes in temperatures.
Revenue
The increase in revenue for the quarter and year to date was driven by increases in base electricity rates and surplus capacity sales, partially offset by a decrease in electricity sales. Revenue year to date was also favourably impacted by higher contribution from non-regulated operating, maintenance and management services associated with the Waneta Expansion.
Earnings
The increase in earnings for the quarter was primarily due to approximately $2 million associated with the timing of quarterly earnings compared to the same period in 2015, as a result of the impact of regulatory deferral mechanisms and the timing of power purchase costs in 2015. An increase in base electricity rates effective January 1, 2015 was established to recover higher power purchase costs, which commenced in the second quarter of 2015. As a result, net earnings were higher in the first quarter of 2015 and the timing effect reversed in the third and fourth quarters of 2015. Also contributing to the increase in earnings was lower operating and maintenance expenses and rate base growth.
The decrease in earnings year to date was primarily due to approximately $4 million associated with the timing of quarterly earnings compared to the same period in 2015, as discussed above for the quarter. The decrease was partially offset by higher earnings from non-regulated operating, maintenance and management services, lower operating and maintenance expenses, and rate base growth.
EASTERN CANADIAN ELECTRIC UTILITIES (1)
Electricity Sales
Electricity sales for the quarter were comparable to the same period last year. Lower average consumption by commercial customers in Newfoundland was largely offset by higher average consumption by residential customers in Ontario due to warmer temperatures.
The decrease in electricity sales year to date was primarily due to lower average consumption by residential customers in all regions, mainly due to warmer temperatures. The decrease was partially offset by customer growth in Newfoundland.
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 at Newfoundland Power and FortisOntario, partially offset by lower electricity sales.
Earnings
Earnings for the quarter and year to date were comparable with the same periods in 2015. The quarterly impact of the timing of earnings at Newfoundland Power was partially offset by a decrease in the allowed ROE effective January 1, 2016. The year to date impact of approximately $1 million in business development costs in Ontario in the second quarter of 2015 was partially offset by lower electricity sales.
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. Overall warmer temperatures, which increased air conditioning load, also contributed to the year-to-date increase.
Revenue
The decrease in revenue for the quarter and year to date was mainly due to the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities, partially offset by electricity sales growth. The translation of US dollar-denominated revenue had a $5 million favourable impact on revenue year to date.
Earnings
The increase in earnings for the quarter and year to date was primarily due to equity income from Belize Electricity and electricity sales growth. Favourable foreign exchange of approximately $3 million associated with the translation of US dollar-denominated earnings and higher capitalized interest at Caribbean Utilities also contributed to the year-to-date increase. The increase was partially offset by higher depreciation.
NON-REGULATED - ENERGY INFRASTRUCTURE (1)
Energy Sales
The increase in energy sales for the quarter was primarily due to increased production in Belize due to higher rainfall, partially offset by lower energy sales due to the sale of generation assets in February 2016.
The increase in energy sales year to date was driven by the Waneta Expansion, which commenced production in April 2015, and increased production in Belize. The increase was partially offset by lower energy sales due to the sale of generation assets in 2015 and February 2016.
Revenue
The increase in revenue for the quarter was driven by the acquisition of Aitken Creek in April 2016, and increased production in Belize.
The increase in revenue year to date was driven by Aitken Creek and the Waneta Expansion, which commenced production in April 2015. The impacts of increased production in Belize and approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue were partially offset by lower revenue due to the sale of generation assets.
Earnings
The decrease in earnings for the quarter was primarily due to the recognition of an after-tax gain of approximately $5 million on the sale of generation assets in the third quarter of 2015. The decrease was partially offset by contribution of $1 million from Aitken Creek, net of an after-tax $1 million unrealized loss on the mark-to-market of derivatives, and increased production in Belize.
The decrease in earnings year to date was primarily due to the recognition of after-tax gains of approximately $27 million and $5 million on the sale of generation assets in the second and third quarters of 2015, respectively, and lower earnings due to the sale of generation assets. The decrease was partially offset by the Waneta Expansion, which commenced production in April 2015, contribution of $3 million from Aitken Creek, net of an after-tax $3 million unrealized loss on the mark-to-market of derivatives, increased production in Belize, and approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings.
NON-REGULATED - NON-UTILITY (1)
Revenue
The decrease in revenue for the quarter and year to date was due to the sale of commercial real estate and hotel assets in 2015.
Earnings
The decrease in earnings for the quarter and year to date was due to the sale of commercial real estate and hotel assets in 2015. In the third quarter of 2015, a $5 million positive adjustment was recognized, largely related to a deferred income tax recovery associated with the sale of hotel assets. Year-to-date 2015, an after-tax net gain of approximately $101 million was recognized related to the sale of commercial real estate and hotel assets.
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 $34 million for the quarter compared to $31 million for the same period in 2015. A decrease in revenue due to lower related-party interest income, mainly due to the sale of commercial real estate and hotel assets in 2015, and higher preference share dividends, mainly due to approximately $3 million of costs associated with the redemption of First Preference Shares, Series E in September 2016, was largely offset by lower operating expenses and a higher income tax recovery. The decrease in operating expenses was mainly due to lower share-based compensation expenses and a decrease in legal fees, largely as a result of the settlement of expropriation matters in the third quarter of 2015.
Excluding the above-noted items, net Corporate and Other expenses were $106 million year to date compared to $100 million for the same period in 2015. The increase was primarily due to lower revenue, as discussed above for the quarter, and higher finance charges, due to the impact of no longer capitalizing interest upon the completion of the Waneta Expansion in April 2015 and the impact of unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense, partially offset by lower interest on the Corporation's credit facility. The increase was partially offset by other income associated with the release of provisions on the wind-up of a partnership in the first quarter of 2016, lower operating expenses, largely as a result of a corporate donation of $3 million ($2 million after tax) in the second quarter of 2015, and a higher income tax recovery.
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 2015 Annual MD&A. The following summarizes the significant ongoing regulatory proceedings and significant decisions and applications for the Corporation's regulated utilities year-to-date 2016.
UNS Energy
General Rate Applications
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 the year ended June 30, 2015 as a historical test year. The key provisions of the rate request included: (i) a non-fuel base revenue 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; (iii) a common equity component of capital structure of approximately 50%; (iv) a cost of equity of 10.35% and an average cost of debt of 4.32%; and (v) 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 has increased from 43.5% to approximately 50%.
In August 2016 TEP entered into a partial settlement agreement with several parties regarding TEP's revenue requirement in its pending rate case. The terms of the settlement agreement include: (i) an increase in non-fuel base revenue of US$81.5 million, including US$15 million of operating costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016; (ii) a 7.04% return on original cost rate base, including a cost of equity of 9.75% and an embedded cost of long-term debt of 4.32%; (iii) a common equity component of capital structure of approximately 50%; and (iv) the adoption of proposed depreciation rates which reflect a reduction in the depreciable life for San Juan Unit 1. Certain aspects of the GRA, including net metering and rate design for distributed generation customers, have been deferred to a second rate case proceeding, which is expected to begin in the first quarter of 2017. Hearings before an Administrative Law Judge ("ALJ") were held in September 2016 with a Recommended Opinion and Order expected in the fourth quarter of 2016. That recommendation is then subject to review and approval by the ACC before new rates can become effective. TEP requested new rates to be implemented by January 1, 2017.
In May 2015 UNS Electric filed a GRA requesting new retail rates to be effective May 1, 2016, using 2014 as a historical test year. The nature of UNS Electric's GRA was similar to that of TEP. In July 2016 the presiding ALJ issued a Recommended Opinion and Order that was subsequently approved by the ACC in August 2016. The approved order included a US$15 million non-fuel base revenue increase and an allowed ROE of 9.50% on a common equity component of capital structure of 52.8%. New rates were implemented in August 2016.
FERC Order
In 2015 TEP reported to FERC that it had not filed on a timely basis certain FERC jurisdictional agreements and, at that time, TEP made compliance filings, including the filing of several TEP transmission service agreements, the majority of which were entered into before the acquisition of UNS Energy by Fortis in 2014, that contained certain deviations from TEP's standard form of service agreement. In April 2016 FERC issued an order relating to the late-filed transmission service agreements, which directed TEP to issue time value refunds to the counterparties of the agreements. TEP accrued $18 million (US$13 million), or $11 million (US$8 million) after tax, in the first quarter of 2016. As authorized in the order, TEP reviewed its refund calculations, including losses incurred as a result of the calculated refund, and determined the refund amount to be US$3 million. TEP filed a refund report, including the updated calculations, with FERC in July 2016.
In October 2016, in response to TEP's filed refund report, FERC issued an additional order which: (i) rejected the filed refund report; (ii) directed TEP to recalculate and pay additional time value refunds within 30 days; and (iii) file a revised report with FERC within 30 days thereafter. TEP has the right to seek rehearing of this order within 30 days of issuance. As a result of this order and ongoing discussions with the Office of Enforcement, TEP accrued an additional $11 million (US$9 million), or $7 million (US$5 million) after tax, in the third quarter of 2016. TEP paid time value refunds of US$3 million year-to-date 2016 and an additional US$14 million in October 2016.
In June 2016, to preserve its rights, TEP petitioned the District of Columbia Circuit Court of Appeals to review the refund order. In July 2016 TEP filed an unopposed motion to hold the appeal, which the Court has since granted. As a result of the October order issued by FERC, TEP intends to pursue the appeal. In addition, FERC's Office of Enforcement is reviewing the matter, and FERC could impose civil penalties on TEP as a result of this review. At this time, TEP cannot predict the outcome of these matters or the range of possible recoveries or additional losses, if any.
FortisBC Energy and FortisBC Electric
Generic Cost of Capital Proceeding
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. In August 2016 the British Columbia Utilities Commission issued its decision, which reaffirmed FEI as the benchmark utility and established that the ROE and common equity component of capital structure for the benchmark utility would remain unchanged at 8.75% and 38.5%, respectively, both effective January 1, 2016. As FEI is the benchmark utility, FortisBC Electric's allowed ROE also remains unchanged at 9.15%.
FortisAlberta
Capital Tracker Applications
In February 2016 the Alberta Utilities Commission ("AUC") issued its decision related to FortisAlberta's 2014 True-Up and 2016-2017 Capital Tracker Applications, resulting in a capital tracker revenue adjustment of less than $1 million in the first quarter of 2016. Capital tracker revenue related to 2015 is subject to change and FortisAlberta filed a 2015 True-Up Application in June 2016, with a decision expected in the first quarter of 2017.
In April 2016 FortisAlberta filed its Compliance Filing related to the February 2016 capital tracker decision, which was approved by the AUC in September 2016, including approval of capital tracker revenue of $71 million and $90 million for 2016 and 2017, respectively. The adjustments to capital tracker revenue have been included in the 2017 Annual Rates Application, as discussed below. Any further differences between 2016 capital tracker revenue collected from customers and actual capital expenditures will be included in 2017 applications to be refunded to or collected from customers in 2018.
FortisAlberta expects to recognize capital tracker revenue of $60 million for 2016, down $11 million from the $71 million approved in the Compliance Filing, which reflects actual capital expenditures and associated financing costs compared to forecast, and the impact of the 2016 GCOC Decision, as discussed below.
2017 Annual Rates Application Proceeding
In September 2016 FortisAlberta filed its 2017 Annual Rates Application requesting new rates to be effective, on an interim basis, for January 1, 2017. The key provisions of the rate application include a decrease of approximately 2.4% to the distribution component of customer rates reflecting: (i) a combined inflation and productivity factor of negative 1.9%; (ii) a K factor placeholder of $90 million, which is 100% of the depreciation and return associated with the 2017 forecast capital tracker expenditures; (iii) a refund of $13 million representing the difference between the 2013 through 2016 K factor amounts applied for, or approved, and the amounts collected from customers, including associated carrying costs; (iv) a refund of less than $1 million of K factor carrying costs; and (v) a net collection of Y factor amounts of approximately $1 million. A decision on the 2017 Annual Rates Application is expected in the fourth quarter of 2016.
Generic Cost of Capital Proceeding
In October 2016 the AUC issued its decision related to FortisAlberta's 2016 and 2017 GCOC Proceeding, establishing that FortisAlberta's allowed ROE remain unchanged at 8.30% for 2016 and increase to 8.50% for 2017. The decision also set the common equity component of capital structure at 37%, effective January 1, 2016, down from 40% approved on an interim basis. Changes in FortisAlberta's allowed ROE and common equity component of capital structure impact only the portion of rate base that is funded by capital tracker revenue.
Utility Asset Disposition Matters
In November 2015 the utilities in Alberta filed an ap
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