Fortis Reports 2016 Earnings of $585 million and Fourth Quarter 2016 Earnings of $189 million
(firmenpresse) - ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 02/16/17 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS)(NYSE: FTS), a leader in the North American regulated electric and gas utility industry, released its 2016 annual results today. The Corporation's net earnings attributable to common equity shareholders for 2016 were $585 million, or $1.89 per common share, compared to $728 million, or $2.61 per common share, for 2015. For the fourth quarter of 2016, net earnings attributable to common equity shareholders were $189 million, or $0.49 per common share, compared to $135 million, or $0.48 per common share, for the same period in 2015. Year over year results were impacted by the Corporation's acquisition of electric transmission company ITC Holdings Corp. ("ITC") in 2016, and gains on the sale of non-core assets in 2015.
On an adjusted basis, net earnings attributable to common equity shareholders for 2016 were $721 million, or $2.33 per common share, an increase of $0.22 per common share, or 10%, compared to 2015. On an adjusted basis, for the fourth quarter of 2016, net earnings attributable to common equity shareholders were $246 million, or $0.64 per common share, an increase of $0.13 per common share, or 25%, compared to the same period in 2015. A reconciliation of adjusted net earnings and adjusted earnings per common share is provided in the Corporation's 2016 Management Discussion and Analysis.
"Fortis had another year of transformation in 2016," said Barry Perry, President and Chief Executive Officer, Fortis. "We announced and quickly closed the acquisition of ITC, the largest independent electric transmission company in the United States, and listed on the New York Stock Exchange, allowing Fortis to access the largest pool of capital in the world. We also received constructive regulatory decisions in a number of jurisdictions, which position us well for continued regulatory stability."
A transformative acquisition
On October 14, 2016, Fortis closed the acquisition of ITC in a transaction valued at approximately US$11.8 billion ($15.7 billion). Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion. Details on the financing of the acquisition, including the minority investment by GIC Private Limited, are included in the Corporation's 2016 Management Discussion and Analysis.
ITC owns and operates high-voltage transmission lines serving a system peak load exceeding 26,000 megawatts along approximately 25,000 kilometres in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from approximately 570 generating stations to local distribution facilities connected to ITC's systems. ITC's rates are regulated by the United States Federal Energy Regulatory Commission ("FERC").
"Our strong financial performance for 2016 was driven by our low-risk and highly diversified portfolio of utilities. The addition of ITC dramatically increased our North American footprint and provides even greater stability in our business, with its predictable and stable cash flows," explained Mr. Perry. "ITC was immediately accretive to earnings per common share, excluding acquisition-related expenses, and we remain confident that this transaction will be nicely accretive in 2017."
Adjusted earnings per share and cash flow increase significantly
Execution of growth strategy
Consolidated capital expenditures for 2016 of $2.1 billion were higher than the Corporation's forecast of $1.9 billion, driven by capital spending at ITC from the date of acquisition. With ITC now included, gross consolidated capital expenditures for 2017 are expected to be approximately $3.0 billion.
Construction continues on the Tilbury liquefied natural gas ("LNG") facility expansion in British Columbia, the Corporation's largest ongoing capital project, at an estimated capital cost of $400 million, before AFUDC and development costs. The commissioning and start-up phase of this regulated project commenced in the fourth quarter of 2016, with an expected in-service date of mid-2017.
The Corporation continues to invest in four Multi-Value Projects ("MVPs") at ITC, which are regional electric transmission projects that have been identified by Midcontinent Independent System Operator ("MISO") to address system capacity needs and reliability in various states. The MVPs are in various stages of construction and include construction of new breaker stations, new transmission lines and the extension of existing substations. Approximately US$43 million was invested in the MVPs from the date of acquisition of ITC and an additional US$272 million is expected to be spent in 2017. Three of the MVPs are expected to be completed by the end of 2018, with the fourth scheduled for completion in 2023.
In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. Specifically, the Corporation continues to pursue LNG infrastructure investment opportunities in British Columbia, including the potential pipeline expansion to the proposed Woodfibre LNG export facility and further expansion of its Tilbury LNG facility. Two other significant electric transmission investment opportunities include the Lake Erie Connector project at ITC, which would connect the Ontario and PJM grids for the first time, and the Wataynikaneyap Power project in Northwestern Ontario. Fortis and its utilities are focused on achieving key milestones in 2017 to advance these opportunities.
Regulatory proceedings
In 2016, the Corporation's utilities made significant progress on a number of key regulatory proceedings, providing stability for the utilities in the near term. In addition to the proceedings noted below, Generic Cost of Capital Proceedings concluded in British Columbia and Alberta in the second half of 2016.
In February 2017, Tucson Electric Power Company ("TEP") received a rate order regarding its general rate application filed in November 2015, based on a historical test year ended June 30, 2015. The rate order approved new rates effective on or before March 1, 2017 and includes an increase in non-fuel base revenue of US$81.5 million, an allowed rate of return on common shareholder's equity ("ROE") of 9.75%, and a common equity component of capital structure of approximately 50%. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.6 billion and the common equity component of capital structure has increased from 43.5% to approximately 50%.
In September 2016, ITC received an order from FERC regarding one of two third-party complaints requesting that FERC find the MISO regional base ROE for all MISO transmission owners, including ITC's MISO-member regulated utilities, to no longer be just and reasonable. The two complaints cover the period from November 2013 through May 2016. The FERC order on the first complaint set the base ROE at 10.32%, with a maximum ROE of 11.35%, and established that those rates are to be used prospectively until a new approved rate is established for the second complaint. In June 2016 the presiding Administrative Law Judge ("ALJ") issued an initial decision on the second complaint, which recommended a base ROE of 9.70%, with a maximum ROE of 10.68%, which is a recommendation to FERC. A decision from FERC on the second complaint is expected in 2017.
The utilities continue to be actively engaged with all of their regulators and are focused on maintaining constructive regulatory relationships and outcomes.
"With our broad utility footprint, a strong base capital plan, and several large projects that could provide upside to our capital plan, we believe that we will deliver superior, risk-adjusted returns for our shareholders, while delivering safe, reliable and cost-effective energy service to our customers," concluded Mr. Perry.
Outlook
The Corporation's results for 2017 will benefit from the impact of ITC, the outcome of the TEP general rate case and continued growth of the underlying business. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital plan, the balance and strength of its diversified portfolio of utility businesses, as well as growth opportunities within its franchise regions.
Over the five-year period through 2021, the Corporation's capital program is expected to be approximately $13 billion, allowing rate base to reach almost $30 billion in 2021. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends.
Fortis has targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital expenditure program, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence.
Management Discussion and Analysis
For the year ended December 31, 2016
Dated February 15, 2017
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 Audited Consolidated Financial Statements and notes thereto for the year ended December 31, 2016. Financial information for 2016 and comparative periods 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 the 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: the expectation that the acquisition of ITC Holdings Corp.
("ITC") will be accretive to earnings per common share in 2017; the Corporation's business model provides superior transparency and best serves the interest of customers; target average annual dividend growth through 2021; the Corporation's forecast midyear rate base through 2021; expected compound annual growth rate in rate base through 2019; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the Corporation's forecast gross consolidated and segmented capital expenditures for 2017 and from 2017 to 2021; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas ("LNG") facility, ITC Multi-Value Projects, the 34.5 to 69 kilovolt Conversion Project, the Gas Main Replacement Program, the Lower Mainland System Upgrade, the Pole Management Program, and additional opportunities including the pipeline expansion to the Woodfibre LNG site, the Wataynikaneyap Project and the Lake Erie Connector Project; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; expected consolidated fixed term debt maturities and repayments in 2017 and over the next five years; the expectation that the Corporation and its utilities will have reasonable access to long-term capital in 2017;
the expectation that the Corporation will repay borrowings under the equity bridge facility using proceeds from a common equity offering in 2017; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; 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 cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions will 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 and advances from minority investors; the expectation that borrowings under the Corporation's committed credit facility may be required from time to time to support the servicing of debt and payment of dividends; 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 intent of management to refinance certain borrowings under Corporation's and subsidiaries' long-term committed credit facilities with long-term permanent financing; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2017; the expectation that the Corporation may enter into forward foreign exchange contracts and utilize certain derivatives as cash flow hedges of its exposure to foreign currency risk to a greater extent than in the past; the expectation that long-term debt will not be settled prior to maturity; 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; Tucson Electric Power Company's expected share of mine reclamation costs; the expectation that any increases or decreases in defined benefit net pension cost at the regulated utilities for 2017 will be recovered from or refunded to customers in rates; 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 changes in tax laws; 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 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 and no material breach of cyber-security; 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 2017 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at 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; uncertainty related to proposed tax reform in the United States; risk associated with the impacts of less favourable economic conditions on the Corporation's results of operations; risk that the expected benefits of the acquisition of ITC may fail to materialize, or may not occur within the time periods anticipated; risk associated with the Corporation's ability to comply with Section 404(a) of the Sarbanes-Oxley Act of 2002 and the related rules of the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board; risk associated with the completion of the Corporation's 2017 capital expenditures plan, including completion of major capital projects in the timelines anticipated and at the expected amounts; and uncertainty in the timing and access to capital markets to arrange sufficient and cost-effective financing to finance, among other things, capital expenditures and the repayment of maturing debt.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
CORPORATE OVERVIEW
Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $48 billion and fiscal 2016 revenue of $6.8 billion. More than 8,000 employees of the Corporations serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. In 2016 the Corporation's electricity systems met a combined peak demand of 33,021 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,586 terajoules.
The Corporation's main business, utility operations, is highly regulated and the earnings of the Corporation's utilities are primarily 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") may depend 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, as applicable; (vi) regulatory lag in the case of a historical test year; and (vii) foreign exchange rates. 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.
Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated energy infrastructure, which is treated as a separate segment. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation.
The following summary describes the operations included in each of the Corporation's reportable segments.
REGULATED UTILITIES
Electric & Gas Utilities - United States
Gas & Electric Utilities - Canadian
Electric Utilities - Caribbean
The Electric Utilities - Caribbean segment includes the Corporation's approximate 60% controlling ownership interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities") (December 31, 2015 - 60%), Fortis Turks and Caicos, and the Corporation's 33% equity investment in Belize Electricity Limited ("Belize Electricity"). Caribbean Utilities is an integrated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands, serving approximately 29,000 customers. The Company has an installed diesel-powered generating capacity of 161 MW. Caribbean Utilities is a public company traded on the Toronto Stock Exchange ("TSX") (TSX: CUP.U). Fortis Turks and Caicos is comprised of two integrated electric utilities serving approximately 15,000 customers on certain islands in Turks and Caicos. The utilities have a combined diesel-powered generating capacity of 82 MW. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize.
NON-REGULATED - ENERGY INFRASTRUCTURE
Non-Regulated - Energy Infrastructure is primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility ("Aitken Creek"). Generating assets in British Columbia include the Corporation's 51% controlling ownership interest in the 335-MW Waneta Expansion, conducted through the Waneta Expansion Limited Partnership ("Waneta Partnership"), with CPC/CBT holding the remaining 49% interest. The output is sold to BC Hydro and FortisBC Electric under 40-year contracts. Generating assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW, conducted through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL"). The output is sold to Belize Electricity under 50-year power purchase agreements ("PPAs"). Aitken Creek Gas Storage ULC ("ACGS"), acquired by Fortis in April 2016, owns 93.8% of 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.
In 2016 the Corporation sold its 16-MW run-of-river Walden hydroelectric generating facility ("Walden") and in 2015 the Corporation sold its non-regulated generation assets in Upstate New York and Ontario.
NON-REGULATED - NON-UTILITY
The Non-Utility segment previously included Fortis Properties Corporation ("Fortis Properties"). Fortis Properties completed the sale of its commercial real estate and hotel assets in 2015.
CORPORATE AND OTHER
The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments. The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses of FortisBC Holdings Inc. ("FHI"), CH Energy Group, Inc. ("CH Energy Group"), and UNS Energy Corporation. Also included in the Corporate and Other segment are the financial results of FortisBC Alternative Energy Services Inc. ("FAES"). FAES is a wholly owned subsidiary of FHI that provides alternative energy solutions, including thermal-energy and geo-exchange systems.
CORPORATE STRATEGY
Fortis is a leader in the North American utility industry and its strategic vision is to provide safe, reliable and cost-effective energy service to customers, while delivering long-term profitable growth. The Corporation is a well-diversified, regulated, primarily wires and gas distribution business characterized by low-risk, stable and predictable earnings and cash flows.
Earnings per common share and total shareholder return are the primary measures of financial performance. Over the 10-year period ended December 31, 2016, earnings per common share of Fortis grew at a compound annual growth rate of 5.2%, on an adjusted basis. Over the same period, Fortis delivered an average annualized total return to shareholders of 7.3%, exceeding the S&P/TSX Capped Utilities and S&P/TSX Composite Indices, which delivered average annualized performance of 5.7% and 4.7%, respectively, over the same period.
The Corporation is committed to achieving long-term sustainable growth in rate base, assets and earnings resulting from investment in existing utility operations. Management remains focused on executing the consolidated capital program and pursuing additional investment opportunities within existing service territories. Fortis has also demonstrated its ability to acquire regulated utilities in North America. The Corporation's standalone operating model positions it well for future investment opportunities in existing and new franchise areas. The Corporation maintains a small head office and its utilities are operated on a substantially autonomous basis. Each of the utilities has its own management team and most have oversight by a Board of Directors comprised of a majority of independent directors. Given that regulatory oversight is usually state or provincially based, the Corporation believes this model provides superior transparency and best serves the interests of customers.
KEY TRENDS, RISKS AND OPPORTUNITIES
Energy Industry Developments: The North American energy industry continues to transform. There is continued focus on clean energy and energy conservation initiatives, while balancing technology advancements and changes in customer needs. Notwithstanding the changes occurring in the utility industry, safety, reliability and serving customers at the lowest reasonable cost remain at the forefront of the utility industry's focus.
The desire for cleaner energy continues to gain momentum throughout North America. Government and regulatory policy in Canada and the United States is being directed at environmental protection, requiring utilities to develop and execute plans to cost-effectively reduce carbon emissions. Such environmental regulations create additional opportunities to expand investment in new generation sources, including natural gas and solar and wind generation, as well as infrastructure to interconnect renewable energy sources to the grid. The Corporation's regulated utilities are well positioned and actively involved in pursuing these opportunities.
Technological development, particularly in the area of distributed generation, continues to play a significant role in the transformation of the utility industry. The move towards cleaner energy has created an increase in the use of distributed generation, particularly solar generation, by customers. This creates a shift in the role of the utility to be a distribution grid network integrator and facilitator, and will require utilities of the future to be able to dispatch and control customer distributed energy resources and integrate those sources into the grid. Distributed generation creates an opportunity for investment in distribution automation, management systems and other grid-modernizing technology. It also presents challenges in the rate designs for distributed generation and other customers to ensure fairness in pricing across all customers. The Corporation's utilities are working with their regulators to address such rate design issues.
Customer expectations on grid resiliency continue to increase. This expectation, in combination with the aging infrastructure of electric and gas utilities in North America, creates an opportunity for increased capital investment. The construction of new infrastructure, such as pipelines and transmission lines, is becoming increasingly challenged by the public, particularly environmental activists. Constructive and collaborative relationships with regulators, policy makers and customers will be critical to the continued long-term success of utilities.
Industry consolidation, particularly in the United States, is continuing with the number of investor-owned utilities decreasing. Consolidation is being driven by a low cost of capital environment, and the need for utilities to sustain earnings growth in an economy that is characterized by low sales growth. The Corporation's proven track record of successfully acquiring and integrating utilities, as well as its standalone business operating model, positions it well in this environment.
Despite the challenges facing the utility industry, Fortis is well positioned to capitalize on any resulting opportunities. Its decentralized structure and customer-focused business culture will support the efforts required to meet evolving customer expectations and to work with policy makers and regulators on solutions that are financially sustainable for the utilities. Leveraging those relationships to remain in front of these evolving challenges will be essential to meeting the industry challenges.
Regulation: The Corporation's key business risk is regulation. Each of the Corporation's utilities is subject to regulation by the regulatory body in its respective operating jurisdiction. Relationships with the regulatory authorities are managed at the local utility level. Commitment by the Corporation's utilities to provide safe and reliable service, operational excellence and promote positive customer and regulatory relations is important to ensure supportive regulatory relationships and obtain full cost recovery and competitive returns for the Corporation's shareholders.
In 2016, the Corporation's utilities made significant progress on a number of key regulatory proceedings, providing stability for the utilities in the near term. In addition to the proceedings noted below, Generic Cost of Capital ("GCOC") Proceedings concluded in British Columbia and Alberta in the second half of 2016.
In February 2017, the ACC issued a Rate Order in TEP's general rate application ("GRA") filed in November 2015, based on a historical test year ended June 30, 2015. The Rate Order approved rates effective on or before March 1, 2017. The provisions of the Rate Order include, but are not limited to an increase in non-fuel base revenue of US$81.5 million, an allowed ROE of 9.75%, and a common equity component of capital structure of approximately 50%.
In September 2016, ITC received an order from the United States Federal Energy Regulatory Commission ("FERC") regarding one of two third-party complaints requesting that FERC find the Midcontinent Independent System Operator ("MISO") regional base ROE for all MISO transmission owners, including ITC's MISO-member regulated utilities, to no longer be just and reasonable. The two complaints cover the period from November 2013 through May 2016. The FERC order on the first complaint set the base ROE at 10.32%, with a maximum ROE of 11.35%, and established that those rates are to be used prospectively until a new approved rate is established for the second complaint. In June 2016 the presiding Administrative Law Judge ("ALJ") issued an initial decision on the second complaint, which recommended a base ROE of 9.70%, with a maximum ROE of 10.68%, which is a recommendation to FERC. A decision from FERC on the second complaint is expected in 2017.
The utilities continue to be actively engaged with all of their regulators and are focused on maintaining constructive regulatory relationships and outcomes.
For a further discussion of material regulatory decisions and applications and regulatory risk, refer to the "Regulatory Highlights" and "Business Risk Management" sections of this MD&A.
Capital Expenditure Program and Rate Base Growth: The Corporation's regulated midyear rate base for 2016 was $24.3 billion, including ITC. Over the five-year period through 2021, the Corporation's capital program is expected to be approximately $13 billion. This investment in energy infrastructure is expected to increase rate base to almost $30 billion in 2021 and produce a five-year compound annual growth rate in rate base of approximately 4%. The three-year compound annual growth rate in rate base through 2019 is expected to be over 5%, reflecting greater visibility in capital expenditures in the next three years. Fortis expects this capital investment to support growth in earnings and dividends.
For further information on the Corporation's consolidated capital expenditure program and rate base of its regulated utilities, refer to the "Liquidity and Capital Resources - Capital Expenditure Program" section of this MD&A.
Access to Capital and Liquidity: The Corporation's regulated utilities require ongoing access to long-term capital to fund investments in infrastructure necessary to provide service to customers. Long-term capital required to carry out the utility capital expenditure programs is mostly obtained at the regulated utility level. The regulated utilities usually issue debt at terms ranging between 5 and 40 years. As at December 31, 2016, almost 80% of the Corporation's consolidated long-term debt, excluding borrowings under long-term committed credit facilities, had maturities beyond five years. Management expects consolidated fixed-term debt maturities and repayments to average approximately $680 million annually over the next five years.
To help ensure uninterrupted access to capital and sufficient liquidity to fund capital programs and working capital requirements, the Corporation and its subsidiaries have approximately $6.0 billion in credit facilities, of which approximately $3.7 billion was unused as at December 31, 2016. Based on current credit ratings and capital structures, the Corporation and its subsidiaries expect to continue to have reasonable access to long-term capital in 2017.
Dividend Increases: Dividends paid per common share increased to $1.53 in 2016. In 2016 Fortis increased its quarterly dividend per common share by almost 7% to $0.40 per quarter, or $1.60 on an annualized basis. This continues the Corporation's record of raising its annualized dividend to common shareholders for 43 consecutive years, the record for a public corporation in Canada.
Fortis also extended its dividend guidance, targeting average annual dividend per common share growth of 6% through 2021. This guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at its utilities, the successful execution of its $13 billion five-year capital expenditure plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of assets and record of operational excellence.
SIGNIFICANT ITEMS
Acquisition of ITC: On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion ($15.7 billion) on closing, including approximately US$4.8 billion ($6.3 billion) of ITC consolidated indebtedness. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC. For additional information on ITC, refer to the "Segmented Results of Operations - Regulated Electric & Gas Utilities - United States" section of this MD&A.
Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion ($9.4 billion). The net cash consideration totalled approximately US$3.5 billion ($4.7 billion) and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes in October 2016; (ii) net proceeds from GIC's US$1.228 billion minority investment, which includes a shareholder note of US$199 million; and (iii) drawings of approximately US$404 million ($535 million) under the Corporation's non-revolving term senior unsecured equity bridge credit facility. On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.5 billion ($4.7 billion), based on the closing price for Fortis common shares of $40.96 and the closing foreign exchange rate of US$1.00=CAD$1.32 on October 13, 2016. The financing of the acquisition was structured to allow Fortis to maintain investment-grade credit ratings.
Fortis and ITC shareholders approved the acquisition at shareholder meetings held in May and June 2016, respectively. All required regulatory, state and federal approvals associated with the acquisition were received prior to closing. In connection with the acquisition, on May 17, 2016, Fortis became a United States Securities and Exchange Commission ("SEC") registrant and, on October 14, 2016, commenced trading its common shares on the New York Stock Exchange. Fortis continues to list its shares on the TSX.
Acquisition-related expenses totalling $118 million ($90 million after tax) were recognized in earnings in 2016 (2015 - $10 million ($7 million after tax)). For additional details on the acquisition-related expenses refer to the "Segmented Results of Operations - Corporate and Other" section of this MD&A. Earnings of ITC from the date of acquisition were reduced by US$21 million ($27 million) in after-tax expenses associated with the accelerated vesting of the Company's stock-based compensation awards as a result of the acquisition, of which the Corporation's share was US$17 million ($22 million).
Acquisition of Aitken Creek Gas Storage Facility
On April 1, 2016, Fortis acquired Aitken Creek from Chevron Canada Properties Ltd. for approximately $349 million (US$266 million), plus the cost of working gas inventory. The net cash purchase price was initially financed through US dollar-denominated borrowings under the Corporation's committed revolving credit facility.
ACGS owns 93.8% of 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.
SUMMARY FINANCIAL HIGHLIGHTS
Net Earnings Attributable to Common Equity Shareholders: Fortis achieved net earnings attributable to common equity shareholders of $585 million in 2016 compared to $728 million in 2015. Results reflect the acquisition of ITC in 2016, including acquisition-related expenses, and gains on the sale of non-core assets in 2015. On an adjusted basis, net earnings attributable to common equity shareholders for 2016 were $721 million, an increase of $132 million, or approximately 22%, compared to 2015. The increase was driven by the acquisition of ITC, strong performance at most of the Corporation's regulated utilities, contribution from Aitken Creek and favourable foreign exchange associated with US dollar-denominated earnings. A reconciliation of adjusted net earnings attributable to common equity shareholders and adjusted earnings per common share is provided in "Consolidated Results of Operations" section of this MD&A.
Basic Earnings per Common Share: Basic earnings per common share were $1.89 in 2016 compared to $2.61 in 2015. On an adjusted basis, basic earnings per common share were $2.33 for 2016, an increase of $0.22, or 10%, compared to 2015. The increase was driven by accretion associated with the acquisition of ITC in October 2016, including the impact of finance charges associated with the acquisition and the increase in the weighted average number of common shares outstanding. The impact of the other above-noted items on adjusted earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding associated with the Corporation's dividend reinvestment and share plans.
A graph is available at the following address:
Cash Flow from Operating Activities: Cash flow from operating activities was $1.9 billion for 2016, an increase of $0.2 billion, or 13%, compared to 2015. The increase was primarily due to higher cash earnings at the regulated utilities, driven by the acquisition of ITC, partially offset by the Corporation's acquisition-related expenses. Favourable changes in long-term regulatory deferrals were partially offset by unfavourable changes in working capital.
A graph is available at the following address:
Dividends: Dividends paid per common share increased to $1.53 in 2016, 9% higher than $1.40 in 2015. During 2016 Fortis increased its quarterly dividend per common share by almost 7% to $0.40 per quarter. The Corporation's dividend payout ratio was 81.0% in 2016 compared to 53.6% in 2015. On an adjusted basis, the dividend payout ratio was 65.7% in 2016 compared to 66.4% in 2015.
A graph is available at the following address:
Total Assets: Total assets increased 66% to approximately $47.9 billion at the end of 2016 compared to approximately $28.8 billion at the end of 2015. The growth in total assets was driven by the acquisition of ITC in October 2016 and continued investment in energy infrastructure, driven by capital spending at the regulated utilities and the acquisition of Aitken Creek, partially offset by unfavourable foreign exchange on the translation of US dollar-denominated assets.
A graph is available at the following address:
Gross Capital Expenditures: Consolidated capital expenditures, before customer contributions, were $2.1 billion in 2016 compared to $2.2 billion in 2015. Consolidated capital expenditures for 2016 were higher than the Corporation's forecast of $1.9 billion. The higher-than-forecast capital investments were driven by capital spending at ITC from the date of acquisition. For a detailed discussion of the Corporation's consolidated capital expenditure program, refer to the "Liquidity and Capital Resources - Capital Expenditure Program" section of this MD&A.
Long-Term Capital: In October 2016, to finance a portion of the acquisition of ITC, the Corporation issued approximately 114.4 million common shares to shareholders of ITC, representing share consideration of approximately $4.7 billion (US$3.5 billion). The net cash consideration totalled approximately $4.7 billion (US$3.5 billion) and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes in October 2016; (ii) net proceeds from GIC's US$1.228 billion minority investment, which includes a shareholder note of US$199 million; and (iii) drawings of approximately US$404 million ($535 million) under the Corporation's non-revolving term senior unsecured equity bridge credit facility.
In addition to financing associated with the acquisition of ITC, the Corporation and its regulated utilities raised over $1.5 billion in long-term debt in 2016, largely in support of energy infrastructure investment, including the acquisition of Aitken Creek in April 2016, and for regularly scheduled debt repayments. In September 2016, the Corporation redeemed all of the First Preference Shares, Series E for $200 million.
For further information, refer to the "Liquidity and Capital Resources - Summary of Consolidated Cash Flows" section of this MD&A.
CONSOLIDATED RESULTS OF OPERATIONS
Revenue
The increase in revenue was driven by the acquisition of ITC in October 2016, contribution from Aitken Creek, and favourable foreign exchange associated with the translation of US dollar-denominated revenue. The increase was partially offset by lower non-utility revenue due to the sale of commercial real estate and hotel assets in 2015 and the flow through in customer rates of lower overall energy supply costs.
Energy Supply Costs
The decrease in energy supply costs was mainly due to lower overall commodity costs. 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 increase in operating expenses was primarily due to the acquisition of ITC, including acquisition-related expenses, operating expenses at Aitken Creek, unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses and general inflationary and employee-related cost increases. The increase was partially offset by a decrease in non-utility operating expenses due to the sale of commercial real estate and hotel assets in 2015.
Depreciation and Amortization
The increase in depreciation and amortization was primarily due to the acquisition of ITC, continued investment in energy infrastructure at the Corporation's regulated utilities, depreciation at Aitken Creek, and unfavourable foreign exchange associated with the translation of US dollar-denominated depreciation. The increase was partially offset by lower non-utility depreciation due to the sale of commercial real estate and hotel assets in 2015.
Other Income (Expenses), Net
The decrease in other income, net of expenses, was primarily due to a net gain of approximately $109 million ($101 million after tax), net of expenses, related to the sale of commercial real estate and hotel assets in 2015 and a gain of approximately $56 million ($32 million after tax), net of expenses and foreign exchange impacts, on the sale of non-regulated generation assets in 2015.
Finance Charges
The increase in finance charges was primarily due to the acquisition of ITC, including acquisition-related fees associated with the Corporation's acquisition credit facilities and deal-contingent interest rate swap contracts, and interest expense on debt issued to complete the financing of the acquisition. 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 was primarily due to lower earnings before income taxes, mainly due to acquisition-related expenses in 2016 and the net gains on the sale of commercial real estate, hotel and non-regulated generation assets in 2015.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings per Common Share
Fortis supplements the use of US GAAP financial measures with non-US GAAP financial measures, including adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share. The Corporation refers to these measures as non-US GAAP financial measures since they are not required by, or presented in accordance with, US GAAP.
The Corporation defines: (i) adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes help investors better evaluate results of operations; and (ii) adjusted basic earnings per common share as adjusted net earnings attributable to common equity shareholders divided by the weighted average number of common shares outstanding. The most directly comparable US GAAP measures to adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share are net earnings attributable to common equity shareholders and basic earnings per common share.
The following table provides a reconciliation of the non-US GAAP financial measures and each of the adjusting items are discussed in the segmented results of operations for the respective reporting segments. The adjusting items do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar measures presented by other companies.
Adjusted Net Earnings Attributable to Common Equity Shareholders
The increase in adjusted net earnings attributable to common equity shareholders was driven by earnings contribution of $81 million at ITC from the date of acquisition in October 2016. The increase was also due to: (i) strong performance at most of the Corporation's regulated utilities driven by UNS Energy, largely due to the settlement of Springerville Unit 1 matters, Central Hudson, due to an increase in delivery revenue, a higher allowance for funds used during construction ("AFUDC") at FortisBC Energy, and stronger performance from the Caribbean; (ii) favourable foreign exchange associated with US dollar-denominated earnings; and (iii) contribution from Aitken Creek and higher earnings at the Waneta Expansion, which commenced production in early April 2015. The increase was partially offset by: (i) higher Corporate and Other expenses, largely due to finance charges associated with the acquisition of ITC; (ii) the sale of commercial real estate and hotel assets in 2015; and (iii) lower earnings at FortisAlberta mainly due to lower average energy consumption and higher operating expenses.
Adjusted Basic Earnings per Common Share
The increase in adjusted earnings per common share was driven by accretion associated with the acquisition of ITC, including the impact of finance charges associated with the acquisition and the increase in the weighted average number of common shares outstanding. The impact of the other above-noted items on adjusted earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding associated with the Corporation's dividend reinvestment and share plans.
SEGMENTED RESULTS OF OPERATIONS
The following is a discussion of the financial results of the Corporation's reporting segments. A discussion of the material regulatory decisions and applications pertaining to the Corporation's regulated utilities is provided in the "Regulatory Highlights" section of this MD&A.
REGULATED UTILITIES
The Corporation's primary business is the ownership and operation of regulated utilities. In 2016 earnings from regulated utilities represented approximately 93% (2015 - 92%, excluding the gains on sale of non-core assets) of the Corporation's earnings from its operating segments (excluding Corporate and Other segment expenses). Total regulated assets represented 97% of the Corporation's total assets as at December 31, 2016 (December 31, 2015 - 96%).
REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES
Regulated Electric & Gas Utilities - United States earnings for 2016 were $328 million (2015 - $253 million), which represented approximately 43% (2015 - 37%) of the Corporation's total regulated earnings. Total segment assets were approximately $30.1 billion as at December 31, 2016 (December 31, 2015 - $12.1 billion), which represented approximately 65% of the Corporation's total regulated assets as at December 31, 2016 (December 31, 2015 - 44%). The increases were driven by the acquisition of ITC.
ITC
Revenue
ITC derives the majority of its revenue from providing transmission, scheduling, control and dispatch services over its transmission systems to its customers and other entities that provide electricity to end-use customers. Revenue was US$250 million ($334 million) from the date of acquisition. On an annual basis, revenue was US$1,125 million for 2016 compared to US$1,045 million for 2015. Revenue for both years was reduced due to the recognition of refund liabilities, largely related to base ROE complaints, which totalled US$80 million for 2016 and US$115 million for 2015. The refund liabilities for both years included amounts related to prior periods. Excluding the impact of the refund liabilities, ITC's revenue increased by US$45 million, driven by higher network revenue and regional cost-sharing revenue largely due to rate base growth.
Earnings
Earnings contribution from ITC was US$44 million ($59 million) from the date of acquisition. Earnings of ITC from the date of acquisition were reduced by US$21 million ($27 million) in after-tax expenses associated with the accelerated vesting of the Company's stock-based compensation awards as a result of the acquisition, of which the Corporation's share was US$17 million ($22 million).
On an annual basis, earnings of ITC were US$246 million for 2016 compared to US$242 million for 2015. Earnings for 2016 were reduced by after-tax acquisition-related expenses of US$69 million, including the accelerated vesting of the Company's stock-based compensation awards, as discussed above. Excluding the acquisition-related expenses, earnings of ITC increased by US$73 million. The increase was driven by rate base growth, higher AFUDC, and lower income tax expense.
UNS ENERGY
Electricity Sales & Gas Volumes
The decrease in electricity sales was primarily due to lower mining retail and short-term wholesale sales, both due to the impact of less favourable commodity prices compared to 2015. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings. Gas volumes were comparable with 2015.
Revenue
The decrease in revenue was mainly due to the flow through to customers of lower purchased power and fuel supply costs, lower mining retail and short-term wholesale electricity sales, and approximately $29 million (US$22 million), or $18 million (US$13 million) after tax, in FERC ordered transmission refunds. The decrease was partially offset by approximately $47 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, $17 million (US$13 million), or $10 million (US$8 million) after tax, in revenue related to the settlement of Springerville Unit 1, and an increase in lost fixed-cost recovery revenue.
Earnings
The increase in earnings was primarily due to the settlement of Springerville Unit 1, lower deferred income tax expense, approximately $6 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, and an increase in lost fixed-cost recovery revenue. The increase was partially offset by FERC ordered transmission refunds, higher operating expenses and depreciation and amortization.
CENTRAL HUDSON
Electricity Sales & Gas Volumes
The decrease in electricity sales was mainly due to lower average consumption as a result of changes in temperatures, partially offset by the timing of customer billings as a result of regulatory approval to increase billing frequency to monthly, effective July 1, 2016. Gas volumes were comparable with 2015.
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 overall 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 higher delivery revenue from increases in base electricity rates effective July 1, 2015 and July 1, 2016 and approximately $20 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The increase in earnings was primarily due to increases in delivery revenue, approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, and lower-than-expected operating expenses. The increase was partially offset by the impact of energy-efficiency incentives earned during the first half of 2015, as discussed above.
REGULATED GAS & ELECTRIC UTILITIES - CANADIAN
Regulated Gas & Electric Utilities - Canadian earnings for 2016 were $390 million (2015 - $390 million), which represented approximately 51% of the Corporation's total regulated earnings (2015 - 58%). Total segment assets were approximately $14.8 billion as at December 31, 2016 (December 31, 2015 - $14.2 billion), which represented approximately 32% of the Corporation's total regulated assets as at December 31, 2016 (December 31, 2015 - 52%). The decrease in percentage of regulated earnings and assets as compared to 2015 were due to the acquisition of ITC.
FORTISBC ENERGY
Gas Volumes
The increase in gas volumes was primarily due to customer growth, higher average consumption by residential and commercial customers in 2016 due to colder temperatures, and higher volumes for transportation customers due to certain transportation customers switching to natural gas compared to alternative fuel sources.
Revenue
The decrease in revenue 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 and higher gas volumes.
Earnings
The increase in earnings was primarily due to higher AFUDC associated with the Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury LNG Facility Expansion"), and operating expense savings, net of the earnings sharing mechanism. Changes in consumption levels and the commodity cost of natural gas do not materially impact earnings as a result of regulatory deferral mechanisms.
FORTISALBERTA
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, commercial and irrigation customers, mainly due to changes in weather. The decrease was partially offset by higher energy deliveries to residential customers due to growth in the number of customers.
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 increase in revenue 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 customers and higher revenue related to flow-through costs to customers. The increase was partially offset by the impact of a $9 million positive capital tracker revenue adjustment recognized in 2015 that related to 2013 and 2014, lower average consumption, and a $3 million negative capital tracker revenue adjustment as a result of the outcome of the 2016 GCOC Proceeding in Alberta.
Earnings
The decrease in earnings was mainly due to the $9 million positive capital tracker revenue adjustment recognized in the first half of 2015, lower average energy consumption, and higher operating expenses. The decrease was partially offset by rate base growth, tempered by the impact of the 2016 GCOC Proceeding, and growth in the number of customers.
FORTISBC ELECTRIC
Electricity Sales
Electricity sales were comparable with 2015.
Revenue
The increase in revenue was driven by increases in base electricity rates and surplus capacity sales. Higher contribution from non-regulated operating, maintenance and management services associated with the Waneta Expansion also favourably impacted revenue.
Earnings
The increase in earnings was primarily due to higher earnings from non-regulated operating, maintenance and management services, and rate base growth.
EASTERN CANADIAN ELECTRIC UTILITIES
Electricity Sales
The decrease in electricity sales 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 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 increase in earnings was primarily due to rate base growth and lower-than-forecast expenses at Newfoundland Power, and lower business developme
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