Fortis Reports First Quarter Earnings of $162 Million
(firmenpresse) - ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 05/03/16 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS), a leader in the North American electric and gas utility industry, released its first quarter results today. The Corporation's net earnings attributable to common equity shareholders were $162 million, or $0.57 per common share, compared to $198 million, or $0.72 per common share, for the first quarter of 2015.
On an adjusted basis, net earnings attributable to common equity shareholders for the first quarter were $190 million, or $0.67 per common share, an increase of $11 million, or $0.02 per common share, over the first quarter of 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 months ended March 31, 2016.
"We have had a strong start to the year," said Mr. Barry Perry, President and Chief Executive Officer of Fortis. "We continued to make progress on our capital program and business initiatives and our financial results were on track as we reap the benefits of our diversified portfolio of utilities.
"In the first quarter we also announced the acquisition of ITC in an accretive transaction valued at approximately US$11.3 billion. ITC - a high quality transmission business in the heart of the Midwest United States - will increase our earnings growth rate, support our dividend growth guidance and provide further diversification of our utility portfolio," concluded Mr. Perry.
Stable first quarter earnings and cash flow; capital expenditure plan on track
Execution of growth strategy
On February 9, 2016, Fortis announced the acquisition of ITC Holdings Corp. ("ITC") in a transaction (the "Acquisition") valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. ITC is the largest independent electric transmission company in the United States. Under the terms of the transaction, ITC shareholders will receive US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$6.9 billion, and Fortis will assume approximately US$4.4 billion of ITC consolidated indebtedness.
In April 2016 Fortis announced that it reached a definitive agreement with an affiliate of GIC Private Limited, Singapore's sovereign wealth fund, to acquire a 19.9% equity interest in ITC for aggregate consideration of US$1.228 billion in cash upon the closing of the Acquisition. This completes a significant component of the ITC Acquisition financing plan. The closing of the Acquisition is subject to ITC and Fortis shareholder approvals, the satisfaction of other customary closing conditions, and certain regulatory, state and federal approvals. The closing of the Acquisition is expected to occur in late 2016.
On April 1, 2016, Fortis completed the acquisition of the Aitken Creek gas storage facility in British Columbia ("Aitken Creek") for approximately US$266 million. Aitken Creek is the only underground 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.
Construction continues on Tilbury 1A in British Columbia, the Corporation's largest ongoing capital project, at an estimated cost of $440 million. Approximately $352 million has been invested in Tilbury 1A to the end of the first quarter of 2016 and the facility is expected to be in service around the end of 2016.
The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia. Woodfibre LNG has received an export license from the National Energy Board and received various environmental assessment approvals, which are significant milestones. FortisBC Energy's potential pipeline expansion, which is subject to various environmental approvals, is conditional on Woodfibre LNG proceeding with its LNG export facility. A final investment decision by Woodfibre LNG is targeted for late 2016.
Regulatory proceedings
Fortis continues to navigate ongoing regulatory proceedings and is focused on maintaining constructive regulatory relationships and outcomes across its utilities.
The most significant regulatory proceeding underway is Tucson Electric Power Company's ("TEP") general rate application, in which TEP has requested new retail rates to be effective January 1, 2017, using the year ended 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 has increased from 43.5% to approximately 50%. UNS Electric and Newfoundland Power are also awaiting the outcomes of general rate applications. The Corporation's utilities in British Columbia and Alberta are currently participating in generic cost of capital proceedings initiated by the respective regulators.
Outlook
Fortis expects to close the Acquisition of ITC by the end of 2016. 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. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix.
Over the five-year period through 2020, excluding ITC, the Corporation's capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase rate base to more than $20 billion in 2020. Fortis expects long-term sustainable growth in rate base, resulting from investment in its existing utility operations and strategic acquisitions, to support continuing growth in earnings and dividends.
Fortis continues to target 6% average annual dividend growth through 2020. 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 plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence. The Acquisition of ITC supports this dividend guidance.
Teleconference to Discuss First Quarter 2016 Results
A teleconference and webcast will be held on May 3 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 first quarter 2016 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 June 3, 2016. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 88662322.
FORWARD-LOOKING INFORMATION
The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. The MD&A should be read in conjunction with the interim unaudited consolidated financial statements and notes thereto for the three months ended March 31, 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 the MD&A has been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") and is presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation. The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs based on information currently available. The forward-looking information in the MD&A includes, but is not limited to, statements related to the acquisition of ITC Holdings Corp. ("ITC"), the expected timing and conditions precedent to the closing of the acquisition of ITC, including shareholder approvals of both ITC and Fortis, regulatory approvals, governmental approvals and other customary closing conditions; the expectation that Fortis will borrow funds and sell 19.9% of ITC to a minority investor to satisfy its obligation to pay the cash portion of the purchase price, and will issue securities to pay the balance of the purchase price; the assumption of ITC debt and expected maintenance of investment-grade credit ratings; the impact of the acquisition on the Corporation's earnings, midyear rate base, credit rating and estimated enterprise value; the expectation that the acquisition of ITC will be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses, and that the acquisition will support the average annual dividend growth target of Fortis; the expectation that the Corporation will become a U.S. Securities and Exchange Commission registrant and have its common shares listed on the New York Stock Exchange in connection with the acquisition of ITC; the annualized 2016 common share dividend; targeted annual dividend growth through 2020; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the expectation that midyear rate base will increase from 2016 to 2020;
the Corporation's forecast gross consolidated capital expenditures for 2016 and total capital spending over the five-year period from 2016 through 2020; 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 and additional opportunities including electric transmission, LNG and renewable-related infrastructure and generation; the expectation that Hawaiian Electric Company would be the primary offtaker of LNG from a further expansion of Tilbury; 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 2016 capital expenditure programs, operating and interest costs, and dividend payments; the expected consolidated fixed-term debt maturities and repayments in 2016 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 2016; the intent of management to hedge future exchange rate fluctuations and monitor its foreign currency exposure; the expectation of FortisAlberta to recognize capital tracker revenue in 2016 and that adjustments to capital tracker revenue will be considered in the 2017 Annual Rates Application; the settlement of Springerville Unit 1 litigation and the timing and conditions precedent to the closing of the settlement, including regulatory approval and satisfaction of closing conditions; 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.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; 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; no material change in public policies and directions by governments that could materially negatively affect the Corporation; 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; continued maintenance of information technology infrastructure; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. Key risk factors for 2016 include, but are not limited to: uncertainty regarding the completion of the acquisition of ITC, including but not limited to, the receipt of shareholder approvals of ITC and Fortis, the receipt of regulatory and other governmental approvals, the availability of financing sources at the desired time or at all, on cost-efficient or commercially reasonable terms and the satisfaction or waiver of certain other conditions to closing; 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, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is a leader in the North American electric and gas utility business, with total assets of approximately $28 billion and fiscal 2015 revenue of $6.7 billion. The Corporation's asset mix is approximately 96% regulated (70% electric, 26% gas), with the remaining 4% comprised of non-regulated energy infrastructure. The Corporation's regulated utilities serve more than 3 million customers across Canada, the United States and the Caribbean.
Year-to-date March 31, 2016, the Corporation's electricity distribution systems met a combined peak demand of 8,182 megawatts ("MW") and its gas distribution system met a peak day demand of 1,335 terajoules. For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 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
Pending Acquisition of ITC Holdings Corp.: On February 9, 2016, Fortis and ITC Holdings Corp. ("ITC") (NYSE: ITC) entered into an agreement and plan of merger pursuant to which Fortis will acquire ITC in a transaction (the "Acquisition") valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. Under the terms of the transaction, ITC shareholders will receive US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$6.9 billion, and Fortis will assume approximately US$4.4 billion of ITC consolidated indebtedness.
ITC is the largest independent electric transmission company in the United States. 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 is a public utility limited to transmission ownership in Wisconsin. ITC's tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC"), which has been one of the most consistently supportive utility regulators in North America providing reasonable returns and equity ratios. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag.
The closing of the Acquisition is subject to ITC and Fortis shareholder approvals, the satisfaction of other customary closing conditions, and certain regulatory, state and federal approvals including, among others, those of FERC, the Committee on Foreign Investment in the United States, and the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act. The closing of the Acquisition is expected to occur in late 2016.
The pending Acquisition is expected to be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix. On a pro forma basis, 2016 forecast midyear rate base of Fortis is expected to increase by approximately $8 billion to approximately $26 billion, as a result of the Acquisition. Following the Acquisition, Fortis will be one of the top 15 North American public utilities ranked by enterprise value.
The financing of the Acquisition has been structured to allow Fortis to maintain investment-grade credit ratings and maintain the Corporation's existing capital structure. Financing of the cash portion of the Acquisition purchase price will be achieved primarily through the issuance of approximately US$2 billion of Fortis debt and the sale of 19.9% of ITC to a minority investor. In April 2016 Fortis announced that it reached a definitive agreement with an affiliate of GIC Private Limited ("GIC"), Singapore's sovereign wealth fund, to acquire a 19.9% equity interest in ITC for aggregate consideration of US$1.228 billion in cash upon the closing of the Acquisition. This completes a significant component of the ITC Acquisition financing plan.
Upon completion of the Acquisition, ITC will become a subsidiary of Fortis and approximately 27% of the common shares of Fortis will be held by ITC shareholders. In connection with the Acquisition, Fortis intends to become a U.S. Securities and Exchange Commission ("SEC") registrant and list its common shares on the New York Stock Exchange. Fortis will continue to have its shares listed on the Toronto Stock Exchange. In March 2016 the Corporation filed with the SEC a registration statement on Form F-4, including a proxy statement of ITC and a prospectus of Fortis, and in April 2016 the Corporation filed Amendment No. 1 to Form F-4. These filings are available at and under Fortis' issuer profile at .
Acquisition of Aitken Creek Gas Storage Facility
On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC ("ACGS") from Chevron Canada Properties Ltd. ("Chevron") for approximately US$266 million. For further details on the acquisition refer to the "Subsequent Events" section of this MD&A.
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 first quarters ended March 31, 2016 and 2015 are provided in the following table.
Revenue
The decrease in revenue was mainly due to the flow through in customer rates of lower energy supply costs at FortisBC Energy and Central Hudson, and a decrease in non-utility revenue due to the sale of commercial real estate and hotel assets in 2015. The decrease was partially offset by favourable foreign exchange associated with the translation of US dollar-denominated revenue and contribution from the Waneta Expansion hydroelectric generating station ("Waneta Expansion").
Energy Supply Costs
The decrease in energy supply costs was primarily due to lower commodity costs at FortisBC Energy and Central Hudson, partially offset by unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs.
Operating Expenses
The decrease in operating expenses 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 unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses and general inflationary and employee-related cost increases.
Depreciation and Amortization
The increase in depreciation was primarily due to unfavourable foreign exchange associated with the translation of US dollar-denominated depreciation, continued investment in energy infrastructure at the Corporation's regulated utilities and depreciation associated with the Waneta Expansion. The 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, was primarily due to acquisition-related expenses of approximately $20 million ($17 million after tax) recognized in the first quarter of 2016 associated with the pending Acquisition of ITC, and the impact of a foreign exchange gain of $9 million recognized in the first quarter of 2015 associated with the Corporation's previous US dollar-denominated long-term other asset that represented the book value of its expropriated investment in Belize Electricity Limited ("Belize Electricity"). The decrease was partially offset by a higher equity component of allowance for funds used during construction ("AFUDC").
Finance Charges
The increase in finance charges was primarily due to unfavorable foreign exchange associated with the translation of US-dollar denominated interest expense.
Income Tax Expense
The decrease in income tax expense was primarily due to lower earnings before income taxes.
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 provide useful information to investors 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 was mainly due to: (i) contribution of $4 million from the Waneta Expansion, which came online in early April 2015, and increased production in Belize due to higher rainfall; (ii) favourable foreign exchange associated with US dollar-denominated earnings; (iii) a higher AFUDC at FortisBC Energy; and (iv) strong performance from the utilities in the Caribbean. The increase was partially offset by the timing of quarterly earnings at FortisBC Electric compared to the first quarter of 2015, and higher Corporate and Other expenses.
Adjusted earnings per common share were $0.02 per common share higher than the first quarter of 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.
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
Electricity Sales & Gas Volumes
The decrease in electricity sales was primarily due to lower short-term wholesale and mining retail sales, as a result of less favorable commodity prices compared to the first quarter of 2015. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings. The decrease was partially offset by an increase in residential and commercial retail electricity sales due to warmer temperatures, which increased air conditioning load.
Gas volumes were comparable with the first quarter of 2015.
Revenue
The increase in revenue was due to approximately $41 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, an increase in lost fixed-cost recovery revenue, and higher residential and commercial retail electricity sales. The increase was partially offset by lower wholesale electricity sales and $18 million (US$13 million), or $11 million (US$8 million) after tax, in FERC ordered transmission refunds associated with late-filed transmission service agreements. For details on this regulatory order, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Earnings
The decrease in earnings was primarily due to $11 million (US$8 million) in FERC ordered transmission refunds, as discussed above, and higher operating expenses. The decrease was partially offset by approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, an increase in lost fixed-cost recovery revenue, and higher residential and commercial retail electricity sales.
CENTRAL HUDSON
Electricity Sales & Gas Volumes
The decrease in electricity sales and gas volumes was primarily due to warmer temperatures.
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 decrease in revenue was mainly due to the recovery from customers of lower commodity costs, which were mainly due to lower wholesale prices. The decrease was partially offset by $11 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue and an increase in base electricity rates effective July 1, 2015.
Earnings
The increase in earnings was primarily due to approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings. The impact of an increase in base electricity rates effective July 1, 2015 was largely offset by the timing of operating expenses.
REGULATED GAS UTILITY - CANADIAN
Gas Volumes
The increase in gas volumes was primarily due to higher average consumption as a result of colder temperatures.
Revenue
The decrease in revenue 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 higher gas volumes.
Earnings
The increase in earnings was primarily due to higher AFUDC and the timing of regulatory flow-through deferral amounts.
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
Energy Deliveries
The decrease in energy deliveries 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 and farm and irrigation customers, mainly due to warmer temperatures. The decrease was partially offset by higher energy deliveries to residential and commercial customers due to customer growth.
Revenue
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.
The decrease in revenue was primarily due to the impact of a $10 million positive capital tracker revenue adjustment recognized in the first quarter of 2015 that related to 2013 and 2014. The decrease was partially offset by 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 customers and higher revenue related to flow-through costs to customers.
Earnings
The decrease in earnings was mainly due to the $10 million positive capital tracker revenue adjustment recognized in the first quarter of 2015, as discussed above.
Electricity Sales
The increase in electricity sales was mainly due to higher average consumption as a result of colder temperatures.
Revenue
The increase in revenue 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 associated with the Waneta Expansion.
Earnings
The decrease in earnings was primarily due to approximately $9 million associated with the timing of quarterly earnings compared to the first quarter of 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. These costs 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. The decrease was partially offset by higher earnings from non-regulated operating, maintenance and management services.
Electricity Sales
The decrease in electricity sales was primarily due to lower average consumption by residential customers in Ontario and on Prince Edward Island due to warmer temperatures.
Revenue
The increase in revenue 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
The decrease in earnings of less than $1 million was primarily due to timing differences at Newfoundland Power.
Electricity Sales
The increase in electricity sales was primarily due to overall warmer temperatures, which increased air conditioning load, and growth in the number of customers as a result of increased economic activity.
Revenue
The decrease in revenue was mainly due to the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities. The decrease was partially offset by approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, and electricity sales growth.
Earnings
The increase in earnings was due to approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, equity income from Belize Electricity, electricity sales growth, and an increase in capitalized interest at Caribbean Utilities. The increase was partially offset by higher depreciation.
Energy Sales
The increase in energy sales was driven by the Waneta Expansion, which commenced production in early April 2015 and reported energy sales of 26 GWh for the first quarter of 2016. Increased production in Belize due to higher rainfall also contributed to the increase.
Revenue
The increase in revenue was driven by the Waneta Expansion, which recognized revenue of $19 million for the first quarter of 2016. Increased production in Belize and favourable foreign exchange associated with the translation of US dollar-denominated revenue of approximately $1 million also contributed to the increase.
Earnings
The increase in earnings was primarily due to earnings contribution of $4 million from the Waneta Expansion, increased production in Belize, and approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings.
Net Corporate and Other expenses were impacted by the following items, which were included in other income, net of expenses:
Excluding the above-noted items, net Corporate and Other expenses were $34 million for the first quarter of 2016 compared to $30 million for the first quarter of 2015. The increase in net Corporate and Other expenses was primarily due to lower revenue and higher operating expenses and finance charges, partially offset by other income associated with the release of provisions on the wind-up of a partnership and a higher income tax recovery.
The decrease in revenue was primarily due to lower related-party interest income, mainly due to the sale of commercial real estate and hotel assets in June 2015 and October 2015, respectively.
The increase in operating expenses was mainly due to higher share-based compensation expenses, largely as a result of share price appreciation, and other general inflationary increases.
The increase in finance charges was primarily due to the impact of no longer capitalizing interest upon the completion of the Waneta Expansion in April 2015. The impact of unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense was largely offset by lower interest on the Corporation's credit facilities.
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 in the first quarter of 2016.
UNS Energy
General Rate Applications
In November 2015 TEP, UNS Energy's largest utility, filed a general rate application ("GRA") with the Arizona Corporation Commission 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 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; (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 May 2015 UNS Electric filed a GRA requesting new retail rates to be effective May 1, 2016, using 2014 as a historical test year. A hearing on UNS Electric's application concluded in March 2016 and a decision is expected in the third quarter of 2016. The nature of UNS Electric's GRA was similar to that of TEP. A decision on TEP's application is expected in the fourth quarter of 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 necessary compliance filings, including the filing of several TEP transmission service agreements entered into between 2003 and 2015 that contained certain deviations from TEP's standard form of service agreement. In April 2016 FERC issued an order relating to late-filed transmission service agreements, which directs TEP to issue time value refunds to the relevant counterparties to the agreements in an amount up to $18 million (US$13 million). The refund was recognized in the first quarter of 2016, resulting in a reduction of earnings of $11 million (US$8 million) after tax. TEP is reviewing the calculation of the ordered refunds to determine if issuing the refunds would cause TEP to have provided service at a loss under each transmission service agreement, in which case the refund amount maybe reduced. Refunds are due to the relevant counterparties within 30 days from the issuance of the FERC order and a refund report must be filed with FERC within 30 days thereafter. TEP can appeal the order within 60 days from the date issued. The results of the compliance filings are still being reviewed by FERC and, as a result, FERC could also impose civil penalties on TEP.
FortisAlberta
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 February 2016 the 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 expects to file a 2015 True-Up Application in the second quarter of 2016, with a decision expected in the first quarter of 2017.
FortisAlberta expects to recognize capital tracker revenue of $65 million for 2016, down $7 million from the amount previously requested in the 2016-2017 Capital Tracker Application to reflect actual capital expenditures and associated financing costs compared to forecast. In April 2016 FortisAlberta filed its Compliance Filing related to the February 2016 capital tracker decision and a decision is expected in the second half of 2016.
FortisAlberta expects that the adjustments to capital tracker revenue, as discussed above, will be considered in the 2017 Annual Rates Application, to be filed in September 2016, and reflected in customer rates effective January 1, 2017.
Utility Asset Disposition Matters
In November 2015 the utilities in Alberta filed an application with the Supreme Court of Canada (the "Supreme Court") seeking leave to appeal the Supreme Court's September 2015 decision, which implied that the shareholder is responsible for the cost of stranded assets. In April 2016 the Supreme Court dismissed the leave to appeal application. This decision has no immediate impact on FortisAlberta's financial position; however, it exposes the Company to the risk that unrecovered costs associated with utility assets deemed by the Alberta Utilities Commission to have been subject to an extraordinary retirement will not be recoverable from customers.
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 to set customer rates effective July 1, 2016. In March 2016 the Company filed a revised 2016/2017 GRA, proposing an overall average increase in electricity rates of 2.5% effective July 1, 2016. The GRA includes a full review of Newfoundland Power's costs, including cost of capital. A public hearing was completed in April 2016 and a decision on the application is expected by the end of the second quarter of 2016.
In October 2015 Maritime Electric filed a GRA with the Island Regulatory and Appeals Commission ("IRAC") to set customer rates effective March 1, 2016, on expiry of the Prince Edward Island Energy Accord. In January 2016 Maritime Electric and the Government of Prince Edward Island entered into a 2016 General Rate Agreement covering the three-year period from March 1, 2016 through February 28, 2019. In February 2016 IRAC issued an order effective March 1, 2016 that reflected the terms of the Agreement. The order provides for an allowed ROE capped at 9.35% on an average common equity component of capital structure of approximately 40% for 2016 through 2018.
Significant Regulatory Proceedings
The following table summarizes significant ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's regulated utilities.
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between March 31, 2016 and December 31, 2015.
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the three months ended March 31, 2016, as compared to the same period in 2015, followed by a discussion of the nature of the variances in cash flows.
Operating Activities: Cash flow from operating activities was $33 million higher quarter over quarter. The increase was primarily due to favourable changes in long-term regulatory deferrals at FortisBC Energy. The increase was partially offset by unfavourable changes in working capital, mainly associated with accounts payable and current regulatory deferrals at FortisBC Energy and Newfoundland Power.
Investing Activities: Cash used in investing activities was $140 million lower quarter over quarter. The decrease was primarily due to lower capital spending at UNS Energy, FortisBC Energy and FortisAlberta. The decrease in capital spending at UNS Energy was mainly due to the purchase of an additional ownership interest in the Springerville Unit 1 generating facility in the first quarter of 2015 upon expiry of the lease arrangement. The decrease in capital spending at FortisBC Energy was mainly due to lower capital expenditures related to the Tilbury liquefied natural gas facility expansion ("Tilbury 1A"). At FortisAlberta, the decrease was mainly due to lower Alberta Electric System Operator ("AESO") contributions and lower capital expenditures for customer growth.
Financing Activities: Cash provided by financing activities was $222 million lower quarter over quarter. The decrease was primarily due to lower proceeds from the issuance of long-term debt, partially offset by lower repayments of long-term debt and higher net borrowings under committed credit facilities.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net borrowings (repayments) under committed credit facilities for the quarter compared to the same period last year are summarized in the following tables.
Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation's committed credit facility.
Common share dividends paid in the first quarter of 2016 were $77 million, net of $29 million of dividends reinvested, compared to $60 million, net of $34 million of dividends reinvested, paid in the first quarter of 2015. The dividend paid per common share for the first quarter of 2016 was $0.375 compared to $0.34 for the first quarter of 2015. The weighted average number of common shares outstanding for the first quarter of 2016 was 282.4 million compared to 276.7 million for the first quarter of 2015.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter as at March 31, 2016, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2015 Annual MD&A and below, where applicable.
Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2015 Annual MD&A.
For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program not included in the preceding Contractual Obligations table, refer to the "Capital Expenditure Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated electric and gas utilities require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 35% common equity, 65% debt and preferred equity, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
Excluding capital lease and finance obligations, the Corporation's capital structure as at March 31, 2016 was 53.5% debt, 8.7% preference shares and 37.8% common shareholders' equity (December 31, 2015 - 53.8% debt, 8.5% preference shares and 37.7% common shareholders' equity).
CREDIT RATINGS
The Corporation's credit ratings are as follows:
The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and management's commitment to maintaining reasonable levels of debt at the holding company level. In February 2016, after the announcement by Fortis that it had entered into an agreement to acquire ITC, S&P affirmed the Corporation's long-term corporate credit rating at A-, revised its unsecured debt credit rating to BBB+ from A-, and revised its outlook on the Corporation to negative from stable. Similarly, in February 2016 DBRS placed the Corporation's credit rating under review with negative implications.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $426 million in gross consolidated capital expenditures by segment year-to-date 2016 is provided in the following table.
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from those forecast.
Gross consolidated capital expenditures for 2016 are forecast to be approximately $1.9 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2015 Annual MD&A, with the exception of those noted below for FortisAlberta and UNS Energy.
Capital expenditures at FortisAlberta are expected to be lower than the original forecast of $441 million, primarily due to lower AESO contributions and as a result of the current economic downturn in Alberta. Capital expenditures for 2016 at UNS Energy are expected to be higher than the original forecast, primarily due to a settlement agreement with third-party owners of Springerville Unit 1 to purchase the third-party owners' 50.5% undivided interest in Springerville Unit 1 for US$85 million. The purchase is expected to close in the second quarter of 2016. For a discussion of the nature of the Springerville Unit 1 litigation, refer to the "Critical Accounting Estimates" section of this MD&A.
FortisBC Energy's construction of Tilbury 1A in Delta, British Columbia is ongoing. Key construction activities during the first quarter included completion of the liquefied natural gas ("LNG") storage tank roof, continued construction of the liquefaction process area and commencement of work on the internal LNG storage tank. Tilbury 1A will be included in regulated rate base and is estimated to cost approximately $440 million, including an equity component of AFUDC. It will include a second LNG tank and a new liquefier, both expected to be in service around the end of 2016. Approximately $352 million has been invested in Tilbury 1A to the end of the first quarter of 2016.
Caribbean Utilities was the successful bidder for new generation capacity and entered into a design-build contract agreement to cover the purchase and turnkey installation of two 18.5 MW diesel-generating units, one 2.7 MW waste heat recovery steam turbine and associated auxiliary equipment. Key construction activities during the first quarter focused on preparations to install the two diesel-generating units. The project cost is estimated at US$85 million and the plant is expected to be commissioned by June 2016. Approximately US$62 million has been invested to date.
Over the five-year period through 2020, gross consolidated capital expenditures are expected to be approximately $9 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 39% at U.S. Regulated Electric & Gas Utilities; 37% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 18% at Canadian Regulated Gas Utility; 5% at Caribbean Regulated Electric Utilities; and the remaining 1% at non-regulated operations. Capital expenditures at the regulated utilities are subject to regulatory approval. Over the five-year period, on average annually, the approximate breakdown of the total capital spending to be incurred is as follows: 50% for sustaining capital expenditures, 35% to meet customer growth, and 15% for facilities, equipment, vehicles, information technology and other assets.
ADDITIONAL INVESTMENT OPPORTUNITIES
In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities, as discussed below, are not included in the Corporation's base capital expenditure forecast and also exclude the pending Acquisition of ITC.
The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including a pipeline expansion to the proposed Woodfibre LNG site near Squamish, British Columbia and a further expansion of Tilbury. In December 2014 FortisBC Energy received an Order in Council from the Government of British Columbia effectively exempting these projects from further regulatory approval by the British Columbia Utilities Commission.
The pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG export facility. The Woodfibre LNG plant has obtained an export license from the National Energy Board and received environmental assessment approvals from the Squamish First Nation, the British Columbia Environmental Assessment Office, and the Canadian Environmental Assessment Agency. These approvals are significant milestones. In addition, FortisBC Energy's pipeline expansion, at an estimated total project cost of up to $600 million, is subject to various environmental approvals. A final investment decision by Woodfibre LNG is targeted for late 2016.
A further expansion of Tilbury is conditional upon having long-term energy supply contracts in place for the offtake of 70% of the additional liquefaction capacity, on average, for the first 15 years of operation. FortisBC Energy has a conditional agreement with Hawaiian Electric Company that would meet this requirement, subject to the regulatory approval process in Hawaii. The Corporation continues to have discussions with Hawaiian Electric Company, which is expected to be the primary offtaker, regarding the viability and scope of the project. Any resulting agreement would be subject to the approval of the Hawaii Public Utilities Commission.
The Corporation also has other significant opportunities that have not yet been included in the Corporation's capital expenditure forecast including, but not limited to, the New York Transco, LLC at Central Hudson to address transmission constraints in New York; renewable energy alternatives at UNS Energy; Wataynikaneyap transmission line to connect remote First Nations communities at FortisOntario; further gas infrastructure opportunities at FortisBC Energy; and potential further consolidation of Rural Electrification Associations at FortisAlberta.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of subsidiary operating cash flows, with varying levels of residual cash flows available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, equity injections from Fortis and long-term debt offerings.
The Corporation's ability to service its debt obligations and pay dividends on its common shares and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. The Corporation's regulated subsidiaries may be subject to restrictions that may limit their ability to distribute cash to Fortis. These include restrictions by certain regulators limiting the amount of annual dividends and restrictions by certain lenders limiting the amount of debt to total capitalization at the subsidiaries. In addition, there are practical limitations on using the net assets of each of the Corporation's regulated operating subsidiaries to pay dividends based on management's intent to maintain the regulator-approved capital structures for each of its regulated operating subsidiaries. The Corporation does not expect that maintaining the targeted capital structure of its regulated operating subsidiaries will have an impact on its ability to pay dividends in the foreseeable future.
Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. The subsidiaries expect to be able to source the cash required to fund their 2016 capital expenditure programs. For a discussion of the Corporation's cash flow requirements associated with the pending Acquisition of ITC, refer to the "Significant Items" section of this MD&A.
In April 2015 FortisBC Energy filed a short-form base shelf prospectus to establish a Medium-Term Note Debenture Program, under which the Company may issue debentures in an aggregate principal amount of up to $1 billion during the 25-month life of the shelf prospectus. In April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million at 2.58% and 30-year $150 million at 3.67% under the base shelf prospectus. The net proceeds will be used to repay credit facility borrowings and finance the Company's capital expenditure program.
As at March 31, 2016, management expects consolidated fixed-term debt maturities and repayments to average approximately $240 million annually over the next five years. The combination of available credit facilities and relatively low annual d
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