Fortis Reports Second Quarter Earnings of $107 Million
(firmenpresse) - ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 07/29/16 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS), a leader in the North American electric and gas utility industry, released its second quarter results today. The Corporation's net earnings attributable to common equity shareholders for the second quarter were $107 million, or $0.38 per common share, compared to $244 million, or $0.88 per common share, for the second quarter of 2015. On a year-to-date basis, earnings were $269 million, or $0.95 per common share, compared to $442 million, or $1.59 per common share, for 2015. The most significant difference in quarterly and year-to-date earnings compared to 2015 related to the gains on sale of assets recognized in the second quarter of 2015.
On an adjusted basis, net earnings attributable to common equity shareholders for the second quarter were $131 million, or $0.46 per common share, an increase of $8 million, or $0.02 per common share, over the second quarter of 2015. On a year-to-date basis, adjusted earnings were $321 million, or $1.13 per common share, an increase of $19 million, or $0.04 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 six months ended June 30, 2016.
Strong second quarter earnings and cash flow; capital expenditure plan on track
"Our diversified portfolio of utilities continues to deliver strong results," said Mr. Barry Perry, President and Chief Executive Officer of Fortis. "Additionally, we expect the acquisition of ITC to further strengthen and diversify our business, as well as accelerate our growth. In the second quarter we achieved a number of significant milestones related to closing of the acquisition."
A transformative acquisition
In February 2016 Fortis announced the acquisition of ITC Holdings Corp. ("ITC") in a transaction (the "Acquisition") valued at approximately US$11.3 billion. ITC is the largest independent electric transmission company in the United States.
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 closing of the Acquisition. This completes a significant component of the ITC Acquisition financing plan.
In May 2016 and June 2016, both Fortis and ITC received shareholder approvals to proceed with the Acquisition. The transaction review by the Committee on Foreign Investment in the United States was completed in July 2016. The closing of the Acquisition remains subject to certain regulatory, state and federal approvals including, among others, those of the United States Federal Energy Regulatory Commission ("FERC") and the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act, and the satisfaction of other customary closing conditions. The FERC and all of the state regulatory applications associated with the transaction were filed in the second quarter of 2016. The closing of the Acquisition is expected to occur in late 2016.
Execution of growth strategy
On April 1, 2016, Fortis completed the acquisition of Aitken Creek for approximately $349 million (US$266 million), plus working gas inventory. 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 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 $368 million has been invested in Tilbury 1A to the end of the second quarter of 2016 and the facility is expected to be in service in the first quarter of 2017.
The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including FortisBC Energy's potential pipeline expansion to the Woodfibre LNG export facility. Woodfibre LNG has obtained an export license from the National Energy Board and received various environmental assessment approvals. FortisBC Energy also received environmental assessment approval from the Squamish First Nation during the second quarter of 2016. The potential pipeline expansion has an estimated total project cost of $600 million. A final investment decision by Woodfibre LNG is targeted for late 2016.
Regulatory proceedings
In addition to the ongoing work to secure regulatory approval for the acquisition of ITC, Fortis is actively engaged with all of its existing regulators and is focused on maintaining constructive regulatory relationships and outcomes across its utilities.
The most significant regulatory proceeding underway remains Tucson Electric Power Company's ("TEP") general rate application. 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%.
In the second quarter, Newfoundland Power received a decision on its general rate application, which resulted in a decrease in the allowed rate of return on common shareholder's equity to 8.50% from 8.80%, effective January 1, 2016. UNS Electric is awaiting the outcome of its general rate application and the Corporation's utilities in British Columbia and Alberta are undergoing 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 over $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 program, 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.
"Our business continues to grow in 2016 and results in 2017 will benefit from the expected outcome of the TEP general rate case, the impact of ITC and continued growth of our underlying business," said Mr. Perry. "Over the long term, we are well positioned to enhance value for shareholders through the execution of our capital plan, the balance and strength of our diversified portfolio of businesses, as well as growth opportunities within our franchise regions," 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 six months ended June 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 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, 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. 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: statements related to the acquisition of ITC Holdings Corp. ("ITC"), the expected timing and conditions precedent to the closing of the acquisition of ITC, regulatory approvals, governmental approvals and other customary closing conditions; the expectation that Fortis will borrow funds to satisfy its obligation to pay the cash portion 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 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 have its common shares listed on the New York Stock Exchange; 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, expansion of the Tilbury liquefied natural gas ("LNG") facility, including Tilbury 1A, the potential 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 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 borrowing under the Corporation's committed credit facility may be required from time to time to support the servicing of debt and the payment of dividends; 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 over the next five years; the intention of management to refinance long-term committed credit facilities with long-term permanent financing; 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 throughout 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 the Springerville Unit 1 litigation and the timing and conditions precedent to the closing of the settlement, including regulatory approval and satisfaction of customary 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.
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 regarding the completion of the acquisition of ITC, including but not limited to, 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, 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 electric and gas utility business, with total assets of approximately $29 billion and fiscal 2015 revenue of $6.7 billion. The Corporation's asset mix is approximately 94% regulated (69% electric, 25% gas), with the remaining 6% 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 June 30, 2016, the Corporation's electricity distribution systems met a combined peak demand of 9,433 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 and six months ended June 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
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.
In May 2016 and June 2016, both Fortis and ITC received shareholder approvals to proceed with the Acquisition. The transaction review by the Committee on Foreign Investment in the United States was completed in July 2016. The closing of the Acquisition remains subject to certain regulatory, state and federal approvals including, among others, those of FERC and the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act, and the satisfaction of other customary closing conditions. The FERC and all of the state regulatory applications associated with the transaction were filed in the second quarter of 2016. 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 $7.5 billion to approximately $25 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 closing of the Acquisition. This completes a significant component of the ITC Acquisition financing plan.
In July 2016 Fortis entered into forward-starting deal-contingent interest rate swap contracts with notional amounts totalling US$1.25 billion. These derivatives have been designated as a hedge of a portion of the cash flow risk associated with the expected issuance of long-term debt to finance a portion of the cash purchase price of the Acquisition. For further details on these contracts, refer to the "Financial Instruments" section of this MD&A.
In February 2016 the Corporation obtained a total of US$3.7 billion in commitments for non-revolving term credit facilities as bridge financing for the pending Acquisition of ITC. For further details on these Acquisition credit facilities, refer to the "Credit Facilities" section of this MD&A.
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 has become a U.S. Securities and Exchange Commission ("SEC") registrant and intends to list its common shares on the New York Stock Exchange. Fortis will continue to have its shares listed on the Toronto Stock Exchange. In May 2016 the SEC granted effectiveness of the Corporation's registration statement on Form F-4, which included a proxy statement of ITC and a prospectus of Fortis. This final registration statement is 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. 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 second quarter and year-to-date periods ended June 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, the flow through in customer rates of lower energy supply costs at FortisBC Energy, UNS Energy and Central Hudson, and lower wholesale electricity sales at UNS Energy. The decrease was partially offset by favourable foreign exchange associated with the translation of US dollar-denominated revenue and contribution from Aitken Creek, which was acquired in April 2016.
Energy Supply Costs
The decrease in energy supply costs for the quarter and year to date was mainly due to lower commodity costs at FortisBC Energy, UNS Energy and Central Hudson and a decrease in purchased power at UNS Energy due to lower wholesale electricity sales. The decrease was partially offset by energy supply costs at Aitken Creek and 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 unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses, acquisition-related expenses of $19 million ($15 million after tax) and $35 million ($29 million after tax) for the second quarter and year-to-date 2016, respectively, associated with the pending Acquisition of ITC, and general inflationary and employee-related cost increases.
Depreciation and Amortization
The increase in depreciation for the quarter and year to date was primarily due to unfavourable foreign exchange associated with the translation of US dollar-denominated depreciation and continued investment in energy infrastructure at the Corporation's regulated utilities. 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, for the quarter and year to date was primarily due to a net gain of approximately $111 million ($96 million after tax), net of expenses, related to the sale of commercial real estate and hotel assets and a gain of approximately $51 million ($27 million after tax), net of expenses and foreign exchange impacts, on the sale of generation assets, both recognized in the second quarter of 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, which totalled approximately $10 million ($7 million after tax) and $14 million ($10 million after tax) for the second quarter and year-to-date 2016, respectively. The impact of unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense also contributed to the increase.
Income Tax Expense
The decrease in income tax expense for the quarter and year to date was primarily due to lower earnings before income taxes, primarily due to the net gains on the sale of commercial real estate and hotel assets and generation assets recognized in the second quarter of 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; (ii) contribution of $4 million from Aitken Creek, which was acquired in early April 2016; (iii) favourable foreign exchange associated with US dollar-denominated earnings; and (iv) the timing of quarterly earnings at FortisBC Electric compared to the second quarter of 2015. The increase was partially offset by lower earnings at FortisAlberta, due to higher operating expenses and lower average energy consumption, and the sale of commercial real estate and hotel assets in 2015.
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, including a higher allowance for funds used during construction ("AFUDC") at FortisBC Energy and equity income of $2 million from Belize Electricity Limited ("Belize Electricity"); (ii) favourable foreign exchange associated with US dollar-denominated earnings; and (iii) contribution of $4 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 timing of quarterly earnings at FortisBC Electric compared to the same period in 2015; (ii) lower earnings at FortisAlberta, due to higher operating expenses and lower average energy consumption; (iii) the sale of commercial real estate and hotel assets 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 $0.04 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.
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
Electricity Sales & Gas Volumes
The decrease in electricity sales for the quarter and year to date was primarily due to lower short-term wholesale and mining retail sales, 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 for the quarter and year to date was partially offset by higher residential retail electricity sales, mainly due to warmer temperatures in the second quarter, which increased air conditioning load, and cooler temperatures in the first quarter, 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 lower short-term wholesale electricity sales and the flow through to customers of lower purchased power and fuel supply costs. The decrease was partially offset by approximately $18 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 retail electricity sales.
The increase in revenue year to date was due to approximately $59 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 retail electricity sales. The increase was partially offset by $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, lower short-term wholesale electricity sales and the flow through to customers of lower purchased power and fuel supply costs. For details on the FERC order, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Earnings
The increase in earnings for the quarter was primarily due to approximately $3 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, lower deferred income tax expense, higher lost fixed-cost recovery revenue and higher residential retail electricity sales. The increase was partially offset by higher operating expenses.
The decrease in earnings year to date 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 $5 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, higher lost fixed-cost recovery revenue, higher residential retail electricity sales, and lower deferred income tax expense.
Electricity Sales & Gas Volumes
The decrease in electricity sales and gas volumes for the quarter and year to date 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 for the quarter and year to date was mainly due to the recovery from customers of lower commodity costs, which were mainly due to lower wholesale prices, and the impact of energy-efficiency incentives earned during the first half of 2015 upon achieving energy saving targets established by the regulator. The decrease was partially offset by approximately $5 million and $16 million of favourable foreign exchange for the quarter and year to date, respectively, 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 for the quarter and year to date was primarily due to approximately $1 million and $3 million, respectively, of favourable foreign exchange associated with the translation of US dollar-denominated earnings and an increase in base electricity rates effective July 1, 2015, partially offset by the impact of energy-efficiency incentives earned during the first half of 2015, as discussed above.
REGULATED GAS UTILITY - CANADIAN
Gas Volumes
The decrease in gas volumes for the quarter was primarily due to lower average consumption as a result of warmer temperatures. The increase in gas volumes year to date was due to higher average consumption during the first quarter as a result of 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, partially offset by an increase in customer delivery rates effective January 1, 2016. Lower gas volumes had an unfavourable impact on revenue for the quarter, while higher gas volumes increased revenue year to date. The timing of regulatory flow-through deferral amounts also had a favourable impact on revenue year to date.
Earnings
The increase in earnings for the quarter and year to date was primarily due to higher AFUDC, partially offset by higher operating expenses. Also contributing to the increase in earnings year to date was 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 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. 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 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 quarter 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 and lower average energy consumption. The decrease in earnings year to date was primarily due to the $9 million positive capital tracker revenue adjustment recognized in the first quarter of 2015, as discussed above.
Electricity Sales
The decrease in electricity sales for the quarter and year to date was mainly due to lower average consumption in the second quarter as a result of warmer temperatures. The decrease year to date was partially offset by higher average consumption in the first quarter as a result of colder 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 $3 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 rate base growth.
The decrease in earnings year to date was primarily due to approximately $6 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. The decrease year to date was partially offset by higher earnings from non-regulated operating, maintenance and management services and rate base growth.
Electricity Sales
The increase in electricity sales for the quarter was primarily due to customer growth in Newfoundland, partially offset by lower average consumption in Newfoundland and Ontario.
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. Higher electricity sales had a favourable impact on revenue for the quarter, while lower electricity sales decreased revenue year to date.
Earnings
Earnings for the quarter and year to date were comparable with the same periods in 2015. The impact of a decrease in the allowed ROE at Newfoundland Power effective January 1, 2016 was largely offset by the impact of approximately $1 million in business development costs in Ontario in the second quarter of 2015.
Electricity Sales
The increase in electricity sales for the quarter and year to date 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 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. The decrease was partially offset by approximately $3 million and $8 million of favourable foreign exchange for the quarter and year to date, respectively, associated with the translation of US dollar-denominated revenue, and electricity sales growth.
Earnings
The increase in earnings for the quarter and year to date was primarily due to approximately $1 million and $3 million, respectively, of favourable foreign exchange associated with the translation of US dollar-denominated earnings, electricity sales growth and an increase in capitalized interest at Caribbean Utilities. Equity income from Belize Electricity also had a favourable impact on earnings year to date. The increase in earnings for the quarter and year to date was partially offset by higher depreciation.
Energy Sales
The increase in energy sales for the quarter was primarily due to the Waneta Expansion, as a result of a planned outage in the second quarter of 2015. The increase was partially offset by lower energy sales due to the sale of generation assets in 2015 and February 2016, and decreased production in Belize due to lower rainfall.
The increase in energy sales year to date was driven by the Waneta Expansion, which commenced production in early April 2015, and increased production in Belize due to higher rainfall in the first quarter of 2016. 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 early April 2016, which recognized revenue of $26 million for the second quarter of 2016, and increased production at the Waneta Expansion. The increase was partially offset by decreased production in Belize and the sale of generation assets.
The increase in revenue year to date was driven by the acquisition of Aitken Creek, as discussed above for the quarter, and the Waneta Expansion, which commenced production in early 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 and year to date was primarily due to the recognition of an after-tax gain of approximately $27 million (US$22 million), net of expenses and foreign exchange impacts, on the sale of generation assets in the second quarter of 2015. Excluding the gain, earnings for the quarter and year to date increased by $1 million and $9 million, respectively. The variance explanations below exclude the impact of the gain.
The increase in earnings for the quarter was primarily due to contribution of $2 million from Aitken Creek, net of an after-tax $2 million unrealized loss on the mark-to-market of derivatives, and increased production at the Waneta Expansion. The increase was partially offset by decreased production in Belize and the sale of generation assets.
The increase in earnings year to date was primarily due to the Waneta Expansion, which commenced production in early April 2015, and contribution from Aitken Creek, as discussed above for the quarter. The impacts of increased production in Belize and approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings were partially offset by lower earnings due to the sale of generation assets.
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 second quarter of 2015, an after-tax net gain of approximately $96 million was recognized related to the sale of commercial real estate and hotel assets.
Net Corporate and Other expenses were impacted by the following items:
Excluding the above-noted items, net Corporate and Other expenses were $38 million for the quarter compared to $39 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, was largely offset by lower operating expenses. The decrease in operating expenses was mainly due to a $3 million ($2 million after tax) corporate donation in the second quarter of 2015.
Excluding the above-noted items, net Corporate and Other expenses were $72 million year to date compared to $69 million for the same period in 2015. The increase was primarily due to: (i) lower revenue, as discussed above for the quarter; (ii) 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 facilities; and (iii) an increase in operating expenses, mainly due to higher share-based compensation expenses, largely as a result of share price appreciation, and other general inflationary increases, partially offset by a corporate donation in the second quarter of 2015, as discussed above for the quarter. The increase was partially offset by other income associated with the release of provisions on the wind-up of a partnership 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 in the first half 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 ("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 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%. Following the review of intervener direct testimony, TEP filed rebuttal testimony in July 2016. In rebuttal testimony, TEP revised its rate request to reflect a US$101 million increase in base retail rates, proposed a 7.16% return on original cost rate base, proposed a cost of equity of 10.00%, and a recovery of operating expenses on the third-party owners' portion of Springerville Unit 1 through base rates. A decision on TEP's application is expected in the fourth quarter of 2016.
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 Administrative Law Judge ("ALJ") issued a Recommended Opinion and Order that will be considered by the ACC. The key provisions of the order included approval of a US$15 million non-fuel base rate increase and an allowed ROE of 9.50%. A decision by the ACC is expected in the third 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 the late-filed transmission service agreements, which directed TEP to issue time value refunds to the relevant counterparties to the agreements in an amount up to $18 million (US$13 million), or $11 million (US$8 million) after tax. TEP accrued this amount in the first quarter of 2016. As specified in the order, TEP reviewed its calculations of the ordered refunds and determined the refund amount to be US$3 million, which was paid to the relevant counterparties in June 2016. TEP filed a refund report with FERC in July 2016. The amount of refunds paid is subject to final approval by FERC and may be modified if FERC does not accept TEP's refund report.
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 in abeyance, which the Court has since granted. 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
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.
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 Court of Appeal of Alberta'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 AUC to have been subject to an extraordinary retirement will not be recoverable from customers.
Next Generation PBR Proceeding
In May 2015 the AUC initiated a generic proceeding to establish parameters for the next term of PBR, being the five-year period from 2018 to 2022. The AUC is assessing three main issues: (i) rebasing and the going-in rates for the next PBR term; (ii) the productivity factor; and (iii) the ongoing treatment of capital. In March 2016 FortisAlberta, along with other Alberta utilities, submitted common expert evidence to the AUC on the design of the next PBR term. At that time, FortisAlberta also submitted Company-specific evidence for the implementation of the next PBR term. A hearing was held in July 2016 with a decision expected by the end of 2016.
Eastern Canadian Electric Utilities
In June 2016 the Newfoundland and Labrador Board of Commissioners of Public Utilities issued an order on Newfoundland Power's 2016/2017 GRA, with new customer rates effective July 1, 2016. The order, which established the cost of capital for rate-making purposes for 2016 through 2018, resulted in a decrease in the allowed ROE to 8.50% from 8.80%, effective January 1, 2016, on a 45% common equity component of capital structure. Newfoundland Power is required to file its next GRA for 2019 on or before June 1, 2018.
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 June 30, 2016 and December 31, 2015.
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the three and six months ended June 30, 2016, as compared to the same periods in 2015, followed by a discussion of the nature of the variances in cash flows.
Operating Activities: Cash flow from operating activities for the quarter and year to date were comparable with the same periods in 2015. Higher cash earnings were largely offset by changes in working capital and long-term regulatory deferrals.
Investing Activities: Cash used in investing activities was $627 million higher for the quarter and $487 million higher year to date compared to the same periods in 2015. The increase was primarily due to proceeds received from the sale of commercial real estate assets and generation assets in the second quarter of 2015 of approximately $430 million and $77 million (US$63 million), respectively, and the acquisition of Aitken Creek in April 2016 for a net cash purchase price of $318 million. The increase for the quarter and year to date was partially offset by 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 additional ownership interests in the Springerville Unit 1 generating facility and previously leased coal-handling assets in the first and second quarters of 2015, respectively. The decrease in capital spending at FortisBC Energy was mainly due to lower capital expenditures related to the Tilbury liquefied natural gas ("LNG") 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 $214 million higher quarter over quarter. The increase was primarily due to higher proceeds from the issuance of long-term debt, higher net borrowings under committed credit facilities, partially offset by higher repayments of short-term borrowings at FortisBC Energy.
Cash provided by financing activities was $8 million lower year to date compared to the same period in 2015. The decrease was primarily due to lower proceeds from the issuance of long-term debt and higher repayments of short-term borrowings at FortisBC Energy, partially offset by higher net borrowings under committed credit facilities and lower repayments of long-term debt and capital lease and finance obligations.
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 and year to date compared to the same periods last year are summarized in the following tables.
Borrowings under credit facilities by the utilities are primarily in support of their 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 second quarter of 2016 were $70 million, net of $36 million of dividends reinvested, compared to $55 million, net of $40 million of dividends reinvested, paid in the second quarter of 2015. Common share dividends paid year-to-date 2016 were $147 million, net of $65 million in dividends reinvested, compared to $115 million, net of $74 million of dividends reinvested, paid year-to-date 2015. The dividend paid per common share for each of the first and second quarters of 2016 was $0.375 compared to $0.34 for each of the first and second quarters of 2015. The weighted average number of common shares outstanding for the second quarter and year-to-date 2016 was 283.7 million and 283.0 million, respectively, compared to 277.9 millio
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