Exhibit 99.1
Management’s Discussion & Analysis
As at May 10, 2018
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the first quarter of 2018 relative to the same quarter in 2017; and its financial position as at March 31, 2018 relative to December 31, 2017. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. The Company’s activities are carried out through six business segments: Emera Florida and New Mexico, Nova Scotia Power Inc., Emera Maine, Emera Caribbean, Emera Energy and Corporate and Other.
This discussion and analysis should be read in conjunction with the Emera Incorporated unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2018; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2017. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’snon-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. Emera’s rate-regulated subsidiaries and investments include:
Emera Rate-Regulated Subsidiary or Equity Investment | Accounting Policies Approved/Examined By | |
| Subsidiary | ||
| Tampa Electric – Electric Division of Tampa Electric Company (“TEC”) | Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”) | |
| Peoples Gas System (“PGS”) – Gas Division of TEC | FPSC | |
| SeaCoast Gas Transmission, LLC (“SeaCoast”) | FPSC | |
| New Mexico Gas Company, Inc. (“NMGC”) | New Mexico Public Regulation Commission (“NMPRC”) | |
| Nova Scotia Power Inc. (“NSPI”) | Nova Scotia Utility and Review Board (“UARB”) | |
| Emera Maine | Maine Public Utilities Commission (“MPUC”) and FERC | |
| Barbados Light & Power Company Limited (“BLPC”) | Fair Trading Commission, Barbados | |
| Grand Bahama Power Company Limited (“GBPC”) | The Grand Bahama Port Authority (“GBPA”) | |
| Dominica Electricity Services Ltd. (“Domlec”) | Independent Regulatory Commission, Dominica (“IRC”) | |
| Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) | National Energy Board (“NEB”) | |
| Equity Investments | ||
| NSP Maritime Link Inc. (“NSPML”) | UARB | |
| Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline LLC (“M&NP”) | NEB and FERC | |
| Labrador Island Link Limited Partnership (“LIL”) | Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”) | |
| St. Lucia Electricity Services Limited (“Lucelec”) | National Utility Regulatory Commission (“NURC”) |
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All amounts are in Canadian dollars (“CAD”), except for the Emera Florida and New Mexico, Emera Maine and Emera Caribbean sections of the MD&A, which are reported in US dollars (“USD”), unless otherwise stated.
Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR atwww.sedar.com.
TABLE OF CONTENTS
Forward-looking Information | 3 | |
Introduction and Strategic Overview | 3 | |
Non-GAAP Financial Measures | 5 | |
Consolidated Financial Review | 7 | |
Significant Items Affecting Earnings | 7 | |
Consolidated Financial Highlights | 7 | |
Consolidated Income Statement and Operating Cash Flow Highlights | 8 | |
Business Overview and Outlook | 10 | |
Emera Florida and New Mexico | 10 | |
NSPI | 12 | |
Emera Maine | 12 | |
Emera Caribbean | 13 | |
Emera Energy | 13 | |
Corporate and Other | 14 | |
Consolidated Balance Sheet Highlights | 16 | |
Developments | 17 | |
Outstanding Common Stock Data | 17 | |
Emera Florida and New Mexico | 18 | |
NSPI | 21 | |
Emera Maine | 23 | |
Emera Caribbean | 24 | |
Emera Energy | 26 | |
Corporate and Other | 28 | |
Liquidity and Capital Resources | 29 | |
Consolidated Cash Flow Highlights | 29 | |
Contractual Obligations | 30 | |
Debt Management | 31 | |
Guarantees and Letters of Credit | 32 | |
Transactions with Related Parties | 32 | |
Risk Management and Financial Instruments | 33 | |
Disclosure and Internal Controls | 35 | |
Critical Accounting Estimates | 35 | |
Changes in Accounting Policies and Practices | 35 | |
Summary of Quarterly Results | 38 |
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FORWARD-LOOKING INFORMATION
This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, business prospects and opportunities and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “budget”, “forecast”, “might”, “will”, “would”, “targets” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.
The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations are discussed in the Business Overview and Outlook section of the MD&A and may also include: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; capital market and liquidity risk; future dividend growth; timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; weather; commodity price risk; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; credit risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and availability of labour and management resources.
Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.
INTRODUCTION AND STRATEGIC OVERVIEW
Emera is a geographically diverse energy and services company. The Company has investments in electricity generation, transmission and distribution and gas transmission and distribution, predominantly within rate-regulated utilities which support strong, consistent earnings and cash flow. Emera seeks to provide its customers with reliable, cost-effective and sustainable energy products and services, and provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States and the Caribbean.
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For investors, Emera seeks to deliver consistent earnings, cash flow and long-term growth, and accordingly, the primary measures of performance are annual dividend growth, earnings per common share growth, adjusted earnings per common share growth (anon-GAAP measure described in theNon-GAAP Financial Measures section below) and total shareholder return. The Company targets eight per cent annual dividend growth through 2020. Emera targets achieving a minimum of 75 per cent of its adjusted net income from its rate regulated utilities and a long-term average dividend payout ratio of 70 to 75 per cent of adjusted net income. The company expects that its dividend payout ratio will likely be higher than its long-term target over the next few years.
Energy markets worldwide, in particular across North America, are undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure, lower-cost natural gas, growing demand for new electric heating and cooling solutions, the requirement for large-scale transmission projects to deliver new energy sources to customers, technological developments, and environmental concerns. These environmental concerns include a desire to reduce emissions of carbon dioxide and other greenhouse gases and the potential system impacts of climate change, including changes in global and regional weather patterns, changes in the frequency and intensity of extreme weather events, and rising sea levels. At the core of Emera’s electric utilities strategy is identifying opportunities to invest in the transition from higher-carbon methods of electricity generation to lower-carbon alternatives, and the related transmission and distribution infrastructure to deliver that energy to market. Emera’s strategy for its gas utilities is to invest in infrastructure renewal and expansion within existing service territories.
The energy sector continues to be impacted by mandated and incented carbon reductions throughout North America and in the Caribbean. It is unclear whether economic volatility, government policy and lower fossil fuel prices will slow the pace of this change in the industry. Investment in wind, solar, and hydro generation, natural gas and new transmission infrastructure is likely to continue across the sector despite any cost differential with more carbon-intensive generating options. The capital spending requirements related to these investments will need to be managed within the context of overall energy pricing.
In Florida, the Company is investing in a number of initiatives, including solar generation and natural gas infrastructure that would reduce carbon emissions. In Nova Scotia, the Company has invested in wind energy, biomass and hydroelectricity and is on track to meet a minimum 40 per cent renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers.
Emera is investing in electricity transmission to deliver new renewable energy to market. Emera’s ownership in the Maritime Link and Labrador Island Link projects will contribute to the transformation of the electricity market in the Atlantic provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, the Atlantic provinces will benefit from enhanced connection to the northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.
Emera Energy is a physical energy marketing and trading business, complemented by a portfolio of competitive electricity generation facilities. A substantial portion of Emera Energy’s activities are in northeastern North America, and its market knowledge, focus on customer service and robust risk management are key success factors. Unlike the vast majority of Emera’s businesses, Emera Energy is not rate-regulated.
Emera’s ability to achieve its strategy is a result of its ability to apply a collaborative approach to strategic partnerships, ability to find creative solutions within and across multiple jurisdictions and its experience dealing with complex projects and investment structures. The Company will continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability. From time to time, Emera will make acquisitions, both regulated and unregulated, where the business or asset acquired aligns with Emera’s strategic initiatives and delivers shareholder value.
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To ensure stability in the utilities’ net income and cash flows, Emera employs operating and governance models that focus on safety and operational excellence, a customer focus through service reliability and rate stability, constructive regulatory approaches, and proactive stakeholder engagement.
In delivering on its strategic objectives, Emera has grown its asset base. Over the last 10 years, Emera’s ability to generate cash and to raise the capital necessary to fund investments has been a strong enabler of the Company’s growth. Cash flow from operations and access to debt and equity capital markets will continue to play a role in financing the Company’s future growth. Maintaining strong, investment grade credit ratings is an important component of Emera’s financing strategy.
The energy industry is seasonal in nature. Seasonal patterns and other weather events, including the number and severity of storms, can affect demand for energy and cost of service. Similarly,mark-to-market adjustments and foreign currency exchange can have a material impact on the financial results for a specific period. Results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.
The effect of foreign currency exchange on Emera’s net income is noteworthy, as it is expected that approximately 70 per cent of Emera’s adjusted net income will be derived from subsidiaries with a US functional currency. Emera‘s consolidated net income and cash flows will be impacted by movements in the US dollar relative to the Canadian dollar. In general, Emera benefits from a weakening Canadian dollar and is adversely impacted by a strengthening Canadian dollar.
NON-GAAP FINANCIAL MEASURES
Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates thenon-GAAP measures by adjusting certain GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period. These measures are discussed and reconciled below.
Adjusted Net Income
For the first quarters of 2018 and 2017, Emera calculated an adjusted net income measure by excluding the effect of:
| • | themark-to-market adjustments related to Emera’sheld-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered; |
| • | themark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp Power Company LLC (“Bear Swamp”); |
| • | the amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions; |
| • | themark-to-market adjustments related to an interest rate swap in Brunswick Pipeline; and |
| • | themark-to-market adjustments related to equity securities held in Emera Caribbean and Corporate and Other. |
Management believes excluding from net income the effect of thesemark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows and the ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors exclude these adjustments for evaluation of performance and incentive compensation.
Mark-to-market adjustments are further discussed in the Consolidated Financial Review, Emera Energy, Emera Caribbean and Corporate and Other sections.
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In Q4 2017, due to the enactment of the US Tax Cuts and Jobs Act of 2017, the Company recorded anon-cash income tax expense resulting from the provisional revaluation of the existing USnon-regulated net deferred income tax assets. The effect of this provisional revaluation was excluded from the calculation of 2017 adjusted net income. The Company continues to analyze certain aspects of the Act, including the valuation of refundable alternative minimum tax credits, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by the Company during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”). No measurement period adjustments have been recognized during the first quarter of 2018.
The following reconciles reported net income attributable to common shareholders, to adjusted net income attributable to common shareholders; and reported earnings per common share – basic, to adjusted earnings per common share – basic:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2018 | 2017 | ||||||
| Net income attributable to common shareholders | $ | 271 | $ | 312 | ||||
| After-taxmark-to-market gain (loss) | $ | 69 | $ | 160 | ||||
| Adjusted net income attributable to common shareholders | $ | 202 | $ | 152 | ||||
| Earnings per common share – basic | $ | 1.17 | $ | 1.48 | ||||
| Adjusted earnings per common share – basic | $ | 0.87 | $ | 0.72 | ||||
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is anon-GAAP financial measure used by Emera. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital and finance working capital requirements.
Adjusted EBITDA is anon-GAAP financial measure used by Emera. Similar to adjusted net income calculations described above, this measure represents EBITDA absent the income effect of Emera’smark-to-market adjustments.
The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies but, in management’s view, appropriately reflects Emera’s specific operating performance. These measures are not intended to replace “Net income attributable to common shareholders” which, as determined in accordance with GAAP, is an indicator of operating performance.
The following is a reconciliation of reported net income to EBITDA and Adjusted EBITDA.
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Net income(1) | $ | 278 | $ | 322 | ||||
| Interest expense, net | 175 | 175 | ||||||
| Income tax expense (recovery) | 65 | 112 | ||||||
| Depreciation and amortization | 223 | 217 | ||||||
| EBITDA | 741 | 826 | ||||||
| Mark-to-market gain (loss), excluding income tax and interest | 100 | 232 | ||||||
| Adjusted EBITDA | $ | 641 | $ | 594 | ||||
(1) Net income is income beforeNon-controlling interest in subsidiaries and Preferred stock dividends.
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CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Q1 Earnings
2018 Earnings Impact ofAfter-TaxMark-to-Market Gains and Losses
After-taxmark-to-market gains decreased $91 million to $69 million in 2018 compared to a $160 million gain for the same period in 2017. The decrease, related to Emera Energy, is due to changes in existing positions on long-term natural gas contracts in the first quarter of 2017 and a larger reversal ofmark-to-market losses in the first quarter of 2017 compared to 2018, partially offset by lower amortization of gas transportation assets in 2018.
Consolidated Financial Highlights
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Adjusted Net Income | ||||||||
| Emera Florida and New Mexico | $ | 90 | $ | 79 | ||||
| NSPI | 65 | 70 | ||||||
| Emera Maine | 10 | 13 | ||||||
| Emera Caribbean | 5 | 7 | ||||||
| Emera Energy | 55 | 10 | ||||||
| Corporate and Other | (23) | (27) | ||||||
| Adjusted net income attributable to common shareholders | $ | 202 | $ | 152 | ||||
| After-taxmark-to-market gain | 69 | 160 | ||||||
| Net income attributable to common shareholders | $ | 271 | $ | 312 | ||||
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2018 | 2017 | ||||||
| Operating revenues | $ | 1,807 | $ | 1,857 | ||||
| Income from operations | 490 | 588 | ||||||
| Net income attributable to common shareholders | 271 | 312 | ||||||
| After-taxmark-to-market gain | 69 | 160 | ||||||
| Adjusted net income attributable to common shareholders | 202 | 152 | ||||||
| Earnings per common share – basic | $ | 1.17 | $ | 1.48 | ||||
| Earnings per common share – diluted | $ | 1.17 | $ | 1.47 | ||||
| Adjusted earnings per common share – basic | $ | 0.87 | $ | 0.72 | ||||
| Dividends per common share declared | $ | 0.5650 | $ | 0.5225 | ||||
| Adjusted EBITDA | $ | 641 | $ | 594 | ||||
The following table highlights the significant changes in adjusted net income from 2017 to 2018.
| ||
For the | Three months ended | |
| millions of Canadian dollars | March 31 | |
| Adjusted net income – 2017 | $ 152 | |
| Emera Energy | 45 | |
| Emera Florida and New Mexico | 11 | |
| NSPML and LIL equity earnings | 9 | |
| NSPI | (5) | |
| Other | (10) | |
| Adjusted net income – 2018 | $ 202 | |
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For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Operating cash flow before changes in working capital | $ | 444 | $ | 348 | ||||
| Change in working capital | (11) | (182) | ||||||
| Operating cash flow | $ | 433 | $ | 166 | ||||
| Investing cash flow | $ | (387) | $ | (381) | ||||
| Financing cash flow | $ | (124) | $ | 66 | ||||
As at | March 31 | December 31 | ||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Total assets | $ | 29,287 | $ | 28,771 | ||||
| Total long-term debt (including current portion) | $ | 14,138 | $ | 13,881 | ||||
Q1 Consolidated Income Statement and Operating Cash Flow Highlights
Operational Results
Income from operations decreased $98 million to $490 million in Q1 2018 compared to $588 million in Q1 2017. Absentmark-to-market decreases of $130 million, income from operations increased $32 million mainly due to the increased contribution from Emera Energy, partially offset by decreased contribution from Emera Florida and New Mexico before netting of tax reform benefits.
Total operating revenues decreased $50 million to $1,807 million in Q1 2018 compared to $1,857 million in Q1 2017. Absentmark-to-market decreases of $129 million, operating revenues increased $79 million due to:
| • | $43 million increase in marketing and trading margin at Emera Energy Services “EES” driven primarily by the impact of cold weather in 2018; |
| • | $28 million increase in NSPI revenues as a result of increased sales volumes due to load growth, and the refund to customers of prior year’s over-recovery of fuel costs in 2017. These were partially offset by decreased sales volume due to warmer weather and the impact of the Maritime Link interim assessment; and |
| • | $18 million increase in Emera Florida and New Mexico as a result of higher electric and gas sales volumes mainly due to weather, partially offset by the impact of a stronger CAD. |
Total operating expenses increased $48 million to $1,317 million in Q1 2018 compared to $1,269 million in Q1 2017 due to:
| • | $37 million increase at Emera Florida and New Mexico due to increased operating, maintenance and general expenses (“OM&G”) at TEC as a result of the regulatory agreement to net storm costs and 2018 tax reform benefits. The increase was also due to higher cost of natural gas in Florida and New Mexico due to higher sales, partially offset by the impact of a stronger CAD; |
| • | $30 million increase at NSPI due to increased fuel costs as a result of increased commodity pricing and a change in generation mix due to increased purchased power. In addition, fuel costs increased due to the payment of the Maritime Link Assessment; and |
| • | $26 million decrease at Bayside Power due to decreased natural gas purchases reflecting the renegotiation of the Bayside Power power purchase agreement (“PPA”) for the winter of 2017/2018. |
Income from equity investments
Income from equity investments increased $11 million to $37 million in Q1 2018 compared to $26 million in Q1 2017 mainly due to higher earnings from NSPML.
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Income tax expense
Income tax expense decreased $47 million to $65 million in Q1 2018 compared to $112 million in Q1 2017 primarily due to decreased earnings before provision for income taxes and the reduction of the US federal corporate income tax rate.
Net cash provided by operating activities
Net cash provided by operating activities in Q1 2018 increased $267 million to $433 million compared to $166 million during the same period in 2017.
Cash from operations before changes in working capital increased $96 million. This was due to increased marketing and trading margin at EES, increased capacity payments at New England Gas Generating Facilities (“NEGG”) and fewer refunds associated with over-recovered clause recoveries in 2018 at Emera Florida and New Mexico.
Changes in working capital increased operating cash flows by $171 million. This increase was mainly due to changes in cash collateral at Emera Energy, and favourable changes in accounts payable and accounts receivable at Emera Florida and New Mexico. These were partially offset by changes in the cash collateral position on derivative instruments at NSPI.
Effect of Foreign Currency Translation
Emera operates globally, including in Canada, the US and various Caribbean countries. As such, the Company generates revenues and incurs expenses denominated in local currencies which are translated into Canadian dollars for financial reporting. Changes in translation rates, particularly in the value of the US dollar against the Canadian dollar, can positively or adversely affect results.
Earnings from Emera’s foreign operations are translated into Canadian dollars. In general, Emera’s earnings benefit from a weakening Canadian dollar and are adversely impacted by a strengthening Canadian dollar. The impact of foreign exchange in any period is driven by rate changes, the timing of earnings from foreign operations during the period and the percentage of earnings from foreign operations in the period.
Results of operations from foreign operations are translated at the weighted average rate of exchange and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/US exchange rates for 2018 and 2017 are as follows:
| | Three months ended March 31 | | | Year ended December 31 | | |||||||
| 2018 | 2017 | 2017 | ||||||||||
| Weighted average CAD/USD exchange rate | $ | 1.26 | $ | 1.32 | $ | 1.30 | ||||||
| Period end CAD/USD exchange rate | $ | 1.29 | $ | 1.33 | $ | 1.25 | ||||||
The strengthening of the CAD decreased earnings and adjusted earnings by $10 million and $7 million respectively in Q1 2018 compared to Q1 2017.
Consistent with the Company’s risk management policies, Emera partially manages currency risks through matching US denominated debt to finance its US operations and uses short-term foreign currency derivative instruments to hedge specific transactions. Emera does not utilize derivative financial instruments for foreign currency trading or speculative purposes.
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The table below includes Emera’s significant segments whose contributions to adjusted earnings are recorded in US dollar currency.
| Three months ended | ||||||||
| March 31 | ||||||||
| millions of US dollars | 2018 | 2017 | ||||||
| Emera Florida and New Mexico | $ | 72 | $ | 60 | ||||
| Emera Maine | 8 | 10 | ||||||
| Emera Caribbean | 3 | 5 | ||||||
| Emera Energy(1) | 40 | 7 | ||||||
| 123 | 82 | |||||||
| Corporate and Other(2) | (33) | $ | (29) | |||||
| Total | $ | 90 | $ | 53 | ||||
Weighted average foreign exchange rate for period | $ | 1.26 | $ | 1.32 | ||||
(1) Includes Emera Energy’s US dollar adjusted net income from Emera Energy Services, NEGG and Bear Swamp.
(2) Corporate and Other includes interest expense on US dollar denominated debt, net of interest income on an intercompany US dollar loan to Emera Energy.
(3) Amounts above do not include the impact ofmark-to-market.
BUSINESS OVERVIEW AND OUTLOOK
Emera continues to analyze certain aspects of the US Tax Cuts and Jobs Act of 2017 including interest deductibility and the valuation of refundable alternative minimum tax credits. The Company believes that the majority of its US based financing interest can be properly allocable, in accordance with the Act, to its US regulated utilities and is therefore exempt from interest deductibility limitations.
Emera Florida and New Mexico
Emera Florida and New Mexico includes TECO Energy, the parent company of TEC, NMGC and TECO Finance. TEC consists of two divisions; Tampa Electric, a vertically-integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida; and PGS, a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas, serving customers in Florida. NMGC is a regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico.
Emera Florida and New Mexico’s earnings are most directly impacted by the rate of return on equity and the capital structures approved by the FPSC and NMPRC, the prudent management of operating costs, the approved recovery of regulatory deferrals, weather and its impact on energy demand, and the timing and amount of capital expenditures.
The Florida utilities anticipate earning within their allowed ROE ranges in 2018 and expect rate base and earnings to be higher than prior years. Tampa Electric expects customer growth rates in 2018 to be in line with 2017, reflecting economic growth in Florida. PGS expects customer growth rates in 2018 to be higher than 2017, reflecting economic growth and the optimization of existing opportunities as the utility increases its market penetration in Florida. Assuming normal weather, sales volumes are expected to increase consistent with customer growth.
In September 2017, Tampa Electric announced its intention to invest approximately $850 million USD over four years in new utility-scale solar photovoltaic projects across its service territory. On November 6, 2017, the FPSC approved a settlement agreement allowing a base rate adjustment that provides for the recovery, uponin-service, of up to 600 MW of investments in utility-scale solar projects that will be phased in from late 2018 through early 2021. On December 12, 2017 Tampa Electric filed a petition along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 solar base rate adjustment representing 145 MW and $24 million USD in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018.
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In September 2017, Tampa Electric was impacted by Hurricane Irma and incurred costs for restoration estimated to be $103 million USD. The amount charged to the storm reserve exceeded the balance in the reserve by $46 million USD. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated restoration costs in excess of the storm reserve for several named storms and to replenish the balance in the reserve to the $56 million USD level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018.
On December 22, 2017, US federal tax reform changes were signed into legislation. The Tampa Electric solar settlement agreement provides for the impacts of tax reform to be offset by a reduction in base revenues through the adjustment of customer rates within 120 days of when tax reform became law. On January 9, 2018, the Florida Office of Public Counsel (“OPC”) filed a petition with the FPSC requesting the FPSC to address tax reform benefits for all utilities in Florida without an existing tax reform settlement provision.
On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that authorizes the utility to net the estimated amount of storm cost recovery against its return of estimated 2018 tax reform benefits to customers. As a result, in Q1 2018, Tampa Electric recorded OM&G expense and a regulatory liability of $19 million USD in order to offset tax reform benefits in the first quarter. This deferral was recorded as a result of deferring the impact of the first quarter as the effective date of the agreement is April 1, 2018. The regulatory liability will be amortized over the remainder of 2018 as a credit against the recognition of storm expense, beginning on April 1, 2018. Tampa Electric’s final storm costs subject to netting and final impact of tax reform on base rates will be determined in separate regulatory proceedings. Any difference will be trued up and recovered from or returned to customers in 2019. Beginning in January 2019, Tampa Electric will reflect the full amount of tax reform in its base rates, provided that the FPSC’s determinations have been finalized. Hearings on the tax reform amounts for all state utilities are tentatively scheduled for the second half of 2018. PGS will address the impacts of tax reform through their normal regulatory process.
NMGC expects earnings to be higher than the prior year due to the effects of colder weather throughout the first quarter of 2018 and tax reform. Customer growth rates are expected to be consistent with 2017, reflecting expectations for housing starts and new connections. NMGC filed a rate case, including the impact of tax reform, on February 26, 2018 with new rates anticipated to be effective approximately twelve months from the filing date subject to NMPRC approval.
In 2018, Emera Florida and New Mexico expects to invest approximately $1.4 billion USD, including allowance for funds used during construction (“AFUDC”), in capital projects compared to $700 million USD in 2017. Capital projects support normal system reliability and growth at the three utilities, including capital projects at Tampa Electric for transmission and distribution storm hardening. The increase over 2017 is primarily due to the investment in the solar photovoltaic projects at Tampa Electric.
PGS will make investments to expand its system and support customer growth, including potential investments in the construction of compressed natural gas fueling stations, renewable natural gas and combined heat and power facilities, and continue with replacement of obsolete plastic, cast iron and bare steel pipe.
NMGC will continue to invest in system improvements by replacing legacy pipe and making pipeline integrity management improvements.
On April 4, 2018, SeaCoast, a subsidiary of TECO Energy executed an agreement with Seminole Electric Cooperative, Inc. (“Seminole”) to provide long-term firm gas transportation service to Seminole’s newgas-fired generating facility being constructed in Putnam County, Florida. SeaCoast will construct and operate atwenty-one mile30-inch pipeline lateral that is anticipated to go into service in 2022. The estimated capital investment for this project is projected to be in the range of $100 million to $120 million USD with the majority of the investment expected in 2020 and 2021.
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NSPI
NSPI is a fully-integrated regulated electric utility. It is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to customers. NSPI’s earnings are most directly impacted by the range of ROE and capital structure approved by the UARB, the prudent management and approved recovery of operating costs, load demand, weather, the approved recovery of regulatory deferrals and the timing and amount of capital expenditures.
NSPI anticipates earning within its allowed ROE range in 2018 and expects modest rate base growth which will deliver a similar modest increase in earnings.
NSPI is subject to environmental regulations as set by both the Province of Nova Scotia and the Government of Canada. The Company continues to work with both levels of government to comply with these regulations, maximizing efficiency of emission control measures and minimizing customer cost. NSPI anticipates that any costs prudently incurred to achieve the legislated reductions will be recoverable from customers under NSPI’s regulatory framework.
In February 2018, the Government of Canada introduced proposed changes to the GHG Coal regulations designed to remove coal fired generation by 2030, subject to equivalency agreements. They introduced a regulation specifying the emission intensities required for new gas fired generation and for boiler conversions from coal to gas. The Government of Canada has also started discussions on a carbon pricing backstop and a Clean Fuel Standard. The backstop would apply in jurisdictions with no carbon pricing systems and also“top-up” systems that did not meet established benchmarks. The future earnings impact of the carbon emission reduction strategy being developed from thePan-Canadian Framework on Clean Growth and Climate Change is unknown.
In 2018, NSPI expects to invest approximately $360 million, including AFUDC, in capital projects compared to $392 million in 2017. Capital will primarily be invested in projects which will support normal system reliability, with the decrease from 2017 driven by a reduction in information technology investment.
Emera Maine
Emera Maine is a transmission and distribution electric utility in the State of Maine. Emera Maine’s earnings are most directly impacted by the combined impacts of the range of rates of ROE and rate base approved by its regulators, the prudent management and approved recovery of operating costs, load (including the effects of weather), and the timing and amount of capital expenditures.
Emera Maine’s 2018 rate base is expected to grow modestly due to ongoing investment in transmission and distribution infrastructure, resulting in modest growth in earnings.
There are currently four pending complaints filed with the FERC to challenge theISO-New England(“ISO-NE”) Open Access Transmission Tariff-allowed base ROE. On June 19, 2014, in connection with the first complaint, the FERC set the base ROE at 10.57 per cent and capped the total ROE, including the effect of incentive adders, at 11.74 per cent. On April 14, 2017, the U.S. Court of Appeals for the District of Columbia Circuit vacated this order and remanded the case to the FERC for further proceedings. No changes in reserves have been made as a result of the Court of Appeals vacating the FERC Order, as the outcome is considered uncertain. A decision on the second and third complaints is expected in 2018. On March 27, 2018, the FERC issued an Initial Decision on the fourth complaint concluding that the currently-filed base ROE of 10.57 per cent, which with incentive adders may reach a maximum ROE of 11.74 per cent, is not unjust and unreasonable. A final decision on this complaint is expected in 2018. For further discussion on the complaints, see note 18 to the condensed consolidated financial statements for the first quarter of 2018.
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In 2018, Emera Maine expects to invest approximately $70 million USD (2017 – $61 million USD) primarily on transmission and distribution capital projects.
Emera Caribbean
Emera Caribbean includes Emera (Caribbean) Incorporated (“ECI”) and its wholly owned subsidiaries:
| • | BLPC, a vertically integrated utility that is the provider of electricity in Barbados; |
| • | GBPC, a vertically integrated utility and the sole provider of electricity on Grand Bahama Island; |
| • | a 51.9 per cent interest in Domlec, an integrated utility on the island of Dominica; and |
| • | a 19.1 per cent equity interest in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia. |
On January 15, 2018, Emera completed the acquisition of the common shares held by the minority shareholders of ICD Utilities Limited (“ICDU”), increasing the Company’s interest in GBPC from 80.4 per cent to 100 per cent.
Earnings from Emera Caribbean are most directly impacted by rates of return on rate base approved by their regulators, capital structure, prudent management and approved recovery of operating costs, sales volumes and the timing and scale of capital expenditures.
Emera Caribbean’s 2018 earnings are expected to increase over the prior year. Earnings from GBPC are expected to increase due to recovering load after the short-term decline from Hurricane Matthew in 2016. Domlec is expecting a loss for 2018 consistent with 2017 as it continues to execute its Hurricane Maria restoration plan. The increase at GBPC will be partially offset by lower earnings from BLPC due to increased interest expense as the utility rebalances its capital structure.
On April 13, 2018, the Barbados Fair Trading Commission approved BLPC’s application to recover the estimated $12 million USD in costs associated with the commissioning of a 5 MW energy storage device (“ESD”) over a period of ten years. Recovery, including a return on capital, will commence through the fuel clause adjustment for an initial period of three years, starting September 1, 2018. The ESD is expected to enhance grid resilience, reliability and lower fuel costs to customers.
Emera Caribbean plans to invest approximately $110 million USD in capital programs in 2018 (2017 - $54 million USD) including increased spending on cleaner energy and grid modernization initiatives and ongoing restoration of the Domlec system. BLPC will invest in an LED street lighting project, installation of Advanced Metering Infrastructure (“AMI”) meters and energizing the first utility-scale battery storage on the island of Barbados. GBPC will begin the first phase of its AMI implementation and invest in its grid modernization battery storage project in late 2018, with final commissioning scheduled for early 2019.
Emera Energy
Emera Energy includes EES, a wholly owned physical energy marketing and trading business; Emera Energy Generation (“EEG”), a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada; and an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.
Earnings from EES are generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 generally providing the greatest opportunity for earnings. Under normal market conditions, the business is generally expected to deliver adjusted net earnings of $15 to $30 million USD, with the opportunity for upside when market conditions present.
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Earnings from EEG’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural gas and the absolute price of natural gas as the marginal fuel in the supply stack, and capacity pricing inISO-NE for NEGG. Efficient operations of the fleet to ensure unit availability, cost management, and effective commercial management are key success factors. EEG earnings are expected to be higher in 2018 as they benefit from higher capacity prices and fewer outage days, all other things being equal.
In 2018, Emera Energy expects to invest approximately $40 million (2017 – $47 million) in capital projects related to its generating assets to continue to improve reliability.
Corporate and Other
Corporate
Corporate encompasses certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition-related costs and corporate human resource activities. It also includes interest revenue on intercompany financings recorded in “Intercompany revenue” and costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.
Other
Other includes consolidated investments in Brunswick Pipeline, Emera Reinsurance Limited and Emera Utility Services Inc. It also includesnon-consolidated investments in NSPML (100 per cent equity investment), LIL (49.4 per cent equity investment) and M&NP (12.9 per cent equity investment). Investments in NSPML, LIL and M&NP are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.
Corporate and Other’s contribution to consolidated net income is expected to be higher in 2018, primarily due to increased contributions from ENL (see below for further discussion on Maritime Link and Labrador Island Link) and higher tax recoveries due to thenon-cash tax expense recognized in 2017 as a result of US tax reform. This is partially offset by increased interest expense and lower income tax recoveries in 2018 as a result of the lower US federal corporate income tax rate.
Corporate and Other, excluding companies accounted for as equity investments, expects to spend approximately $40 million on capital projects in 2018 (2017 - $21 million).
ENL
ENL holds equity investments in NSPML and LIL.
NSPML
The Maritime Link entered service on January 15, 2018. NSPML completed the project on time and on budget. Electricity is being transmitted between Newfoundland and Nova Scotia and the Maritime Link is providing service to electricity customers in both provinces. In Q1 2018, NSPML has begun recording cash earnings and collecting UARB approved cash payments from NSPI. Prior to Q1 2018, NSPML recordednon-cash AFUDC earnings as it was under construction. All major contracts have been concluded. NSPML’s focus is on safely operating the Maritime Link in an efficient manner.
Future earnings contributions from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. The approved ROE is 9 per cent. Emera’s equity earnings are expected to be higher in 2018 than in 2017 as the Maritime Link is now complete.
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In 2018, ENL expects to invest approximately $20 million in capital related to final construction costs.
LIL
Future earnings from the LIL investment are dependent on the amount and timing of additional equity contributions and the approved ROE. Emera’s total equity investment is forecasted to be $534 million by the end of 2018, comprised of $410 million in equity contribution and an estimated $124 million of accumulated equity earnings. Emera’s total equity contribution in the LIL is estimated to be approximately $600 million by 2020 when all Lower Churchill projects, including Muskrat Falls, are forecasted by Nalcor Energy to be placed in service. No further equity contributions are forecasted until 2020.
Nalcor Energy is forecasting that construction of the LIL will be completedmid-2018. Cash earnings and return of equity are forecasted by Nalcor Energy to begin in late 2020.
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CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2017 and March 31, 2018 include:
| millions of Canadian dollars | Increase (Decrease) | Explanation | ||||
| Assets | ||||||
| Cash and cash equivalents | $ | (71) | Decreased primarily due to additions of property, plant and equipment, payment of common dividends and changes in borrowings, partially offset with increased cash from operations and proceeds of debt at Emera Florida and New Mexico. | |||
| Derivative instruments (current and long-term) | (56) | Decreased due to lower commodity prices and settlements of derivative instruments at NSPI. | ||||
| Property, plant and equipment, net of accumulated depreciation | 485 | Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries, and additions at the regulated utilities. | ||||
| Investments subject to significant influence | 68 | Increased due to investment in NSPML. | ||||
| Goodwill | 162 | Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries. | ||||
| Receivables and other assets (current and long-term) | (63) | Decreased due to lower cash collateral positions at Emera Energy, partially offset with gas transportation assets at Emera Energy and seasonal trends of business at NSPI and TEC. | ||||
| Liabilities and Equity | ||||||
| Short-term debt and long-term debt (including current portion) | 318 | Increased due to the effect of a stronger USD on foreign currency debt. This was partially offset by repayment of committed credit facilities and changes in short term debt at Emera Florida and New Mexico. | ||||
| Accounts payable | (213) | Decreased due to lower commodity prices at Emera Energy, lower cash collateral positions on derivative instruments at NSPI, and lower accruals at TEC for restoration costs after Hurricane Irma. | ||||
| Deferred income tax liabilities, net of deferred income tax assets | 109 | Increased due to tax deductions in excess of accounting depreciation related to property, plant and equipment and the effect of a stronger USD on the translation of Emera’s foreign subsidiaries. | ||||
| Derivative instruments (current and long-term) | (66) | Decreased due to reversal of 2017 AMA MTM losses, partially offset by new contracts at Emera Energy. | ||||
| Other liabilities (current and long-term) | 55 | Increased due to timing of interest payments on long-term debt. | ||||
| Common stock | 73 | Increased due to the dividend reinvestment program and issuance of common stock for the purchase of additional shares of ICDU. | ||||
| Accumulated other comprehensive income | 147 | Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries. | ||||
| Retained earnings | 148 | Increased due to net income in excess of dividends paid. | ||||
| Non-controlling interest in subsidiaries | (53) | Decreased due to increased ownership in GBPC. | ||||
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DEVELOPMENTS
Tampa Electric Tax Reform and Storm Settlement
On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that authorizes the utility to net the estimated amount of storm cost recovery against the return of estimated 2018 tax reform benefits to customers. Refer to the “Business Overview and Outlook”, “Emera Florida and New Mexico” section for further details.
NSPML
The Maritime Link entered service on January 15, 2018 enabling the transmission of electricity between Newfoundland and Nova Scotia. In Q1 2018, NSPML has begun recording cash earnings and collecting UARB approved cash payments from NSPI. Prior to Q1 2018, NSPML recordednon-cash AFUDC earnings as it was under construction. Refer to the “Business Overview and Outlook”, “Corporate and Other - ENL” section for further details.
OUTSTANDING COMMON STOCK DATA
Common stock Issued and outstanding: | | millions of shares | | | millions of Canadian | | ||||||
| Balance, December 31, 2016 | 210.02 | $ | 4,738 | |||||||||
| Conversion of Convertible Debentures | 0.15 | 6 | ||||||||||
| Issuance of common stock | 14.61 | 680 | ||||||||||
| Issued for cash under Purchase Plans at market rate | 3.89 | 182 | ||||||||||
| Discount on shares purchased under Dividend Reinvestment Plan | - | (9 | ) | |||||||||
| Options exercised under senior management stock option plan | 0.10 | 3 | ||||||||||
| Employee Share Purchase Plan | - | 1 | ||||||||||
| Balance, December 31, 2017 | 228.77 | $ | 5,601 | |||||||||
| Conversion of Convertible Debentures(1) | 0.01 | - | ||||||||||
| Issuance of common stock(2) | 0.45 | 22 | ||||||||||
| Issued for cash under Purchase Plans at market rate | 1.27 | 53 | ||||||||||
| Discount on shares purchased under Dividend Reinvestment Plan | - | (2 | ) | |||||||||
| Options exercised under senior management stock option plan | 0.02 | - | ||||||||||
| Balance, March 31, 2018 | 230.52 | $ | 5,674 | |||||||||
(1) As at March 31, 2018, a total of 52.15 million common shares of the Company were issued, representing conversion into common shares of more than 99.9 per cent of the Convertible Debentures.
(2) In Q1 2018, Emera issued 0.45 million common shares to facilitate the creation and issuance of 1.8 million depository receipts in connection with the ICDU share acquisition. The depository receipts are listed on the Bahamas International Securities Exchange.
As at April 26, 2018 the amount of issued and outstanding common shares was 230.6 million.
The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended March 31, 2018 was 231.0 million (2017 – 211.6 million).
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EMERA FLORIDA AND NEW MEXICO
Financial Highlights
All amounts are reported in USD, unless otherwise stated.
For the millions of US dollars (except per share amounts) | | Three months ended March 31 | | |||||
| 2018 | 2017 | |||||||
| Operating revenues – regulated electric | $ | 459 | $ | 441 | ||||
| Operating revenues – regulated gas | 253 | 227 | ||||||
| Operating revenues –non-regulated | 4 | 4 | ||||||
| Total operating revenues | 716 | 672 | ||||||
| Regulated fuel for generation and purchased power | 135 | 138 | ||||||
| Regulated cost of natural gas | 110 | 95 | ||||||
| Contribution to consolidated net income | $ | 72 | $ | 60 | ||||
| Contribution to consolidated net income – CAD | $ | 90 | $ | 79 | ||||
| Contribution to consolidated earnings per common share – basic - CAD | $ | 0.39 | $ | 0.37 | ||||
| Net income weighted average foreign exchange rate – CAD/USD | $ | 1.25 | $ | 1.32 | ||||
| EBITDA | $ | 236 | $ | 240 | ||||
| EBITDA – CAD | $ | 298 | $ | 317 | ||||
Net Income
Highlights of the net income changes are summarized in the following table:
For the millions of US dollars | | Three months ended March 31 | | |
| Contribution to consolidated net income – 2017 | $ | 60 | ||
| Increased operating revenues - see Operating Revenues - Regulated Electric below | 18 | |||
| Increased operating revenues - see Operating Revenues - Regulated Gas below | 26 | |||
| Decreased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below | 3 | |||
| Increased cost of natural gas sold - see Regulated Cost of Natural Gas below | (15) | |||
| Increased OM&G expenses, primarily due to Tampa Electric’s regulatory agreement to net storm costs and 2018 tax reform benefits and timing of generation outages | (29) | |||
| Increased depreciation and amortization due to normal asset growth and timing of PGS’ amortization of regulatory asset associated with manufactured gas plant environmental remediation costs | (8) | |||
| Increased provincial, state and municipal taxes due to higher franchise fees and gross receipts tax | (4) | |||
| Decreased income tax expense primarily due to the reduction of the US federal corporate income tax rate and decreased income before the provision for income taxes | 20 | |||
| Other | 1 | |||
| Contribution to consolidated net income – 2018 | $ | 72 |
Emera Florida and New Mexico’s CAD adjusted contribution to consolidated net income increased $11 million to $90 million in Q1 2018 from $79 million during the same period in 2017 primarily due to the impact of weather driven load and tax reform benefits. The impact of the change in the foreign exchange rate decreased CAD adjusted earnings by $5 million compared to Q1 2017.
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Emera Florida and New Mexico’s contribution is summarized in the following table:
For the millions of US dollars | | Three months ended March 31 | | |||||
| 2018 | 2017 | |||||||
| Tampa Electric | $ | 48 | $ | 43 | ||||
| PGS | 15 | 14 | ||||||
| NMGC | 19 | 13 | ||||||
| Other(1) | (10) | (10) | ||||||
| Contribution to consolidated net income | $ | 72 | $ | 60 | ||||
(1) Other includes TECO Finance and administration costs.
Increases in operating unit contributions to consolidated net income are mainly due to higher sales volumes from favourable weather in Florida and New Mexico, higher base rates related to the Polk Power Station expansion at TEC, and tax reform benefits realized in NMGC and PGS. These are partially offset by increased depreciation at TEC. Refer to the “Business Overview and Outlook”, “Emera Florida and New Mexico” and “Developments” sections.
Operating Revenues – Regulated Electric
Electric revenues increased $18 million to $459 million in Q1 2018 compared to $441 million in Q1 2017, primarily as a result of higher sales volumes due to more favourable weather and higher base rates as the base rate increase related to the Polk Power Station expansion went into effectmid-January 2017.
Electric revenues are summarized in the following by customer class:
Q1 Electric Revenues
| millions of US dollars | ||||||||
| 2018 | 2017 | |||||||
| Residential | $ | 230 | $ | 198 | ||||
| Commercial | 132 | 131 | ||||||
| Industrial | 38 | 39 | ||||||
| Other(1) | 59 | 73 | ||||||
| Total | $ | 459 | $ | 441 | ||||
| (1) Other includes sales to public authorities,off-system sales to other utilities and regulatory deferrals related to clauses. | ||||||||
Q1 Electric Sales Volumes
| Gigawatt hours (“GWh”) | ||||||||
| 2018 | 2017 | |||||||
| Residential | 2,021 | 1,761 | ||||||
| Commercial | 1,404 | 1,431 | ||||||
| Industrial | 473 | 504 | ||||||
| Other | 448 | 386 | ||||||
| Total | 4,346 | 4,082 | ||||||
Operating Revenues – Regulated Gas
Gas revenues increased $26 million to $253 million in Q1 2018 compared to $227 million in Q1 2017 primarily due to higher sales volumes resulting from colder weather for both Florida and New Mexico in Q1 2018.
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Gas revenues are summarized in the following tables by customer class:
Q1 Gas Revenues
| millions of US dollars | ||||||||
| 2018 | 2017 | |||||||
| Residential | $ | 142 | $ | 128 | ||||
| Commercial | 74 | 67 | ||||||
| Industrial(1) | 9 | 8 | ||||||
| Other(2) | 28 | 24 | ||||||
| Total | $ | 253 | $ | 227 | ||||
| (1) Industrial includes sales to power generation customers. | ||||||||
| (2) Other includesoff-system sales to other utilities and various other items. | ||||||||
Q1 Gas Sales Volumes | ||||||||
| Therms (millions) | ||||||||
| 2018 | 2017 | |||||||
| Residential | 156 | 138 | ||||||
| Commercial | 245 | 223 | ||||||
| Industrial | 317 | 299 | ||||||
| Other | 50 | 40 | ||||||
| Total | 768 | 700 | ||||||
Regulated Fuel for Generation, Purchased Power and Cost of Natural Gas
Electric Capacity
Regulated fuel for generation and purchased power decreased $3 million to $135 million in Q1 2018 compared to $138 million in Q1 2017 primarily due to a shift in generation mix from higher cost coal generation to lower cost natural gas generating units and purchased power, which offset impacts of higher sales volumes.
Q1 Production Volumes | ||||||||
| GWh | ||||||||
| 2018 | 2017 | |||||||
| Natural gas | 3,445 | 2,275 | ||||||
| Coal | 635 | 1,608 | ||||||
| Oil and petcoke | 231 | 295 | ||||||
| Solar | 10 | 9 | ||||||
| Purchased power | 163 | 76 | ||||||
| Total production volumes | 4,484 | 4,263 | ||||||
Q1 Average Fuel Costs/Megawatt hour (“MWh”) | ||||||||
| US dollars | 2018 | 2017 | ||||||
| Dollars per MWh | $ | 30 | 32 | |||||
Average fuel cost per MWh decreased in Q1 2018 compared to Q1 2017, primarily due to a shift in generation mix as discussed above.
Cost of Natural Gas
Regulated cost of natural gas increased $15 million to $110 million in Q1 2018 compared to $95 million in Q1 2017 primarily as a result of higher sales volumes due to colder weather in both Florida and New Mexico, partially offset by lower commodity pricing in New Mexico in Q1 2018.
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Gas sales by type are summarized in the following table:
| Q1 Gas Sales Volumes by Type | ||||||||||||||||||||||||
| Therms (millions) | 2018 | 2017 | ||||||||||||||||||||||
| System supply | 247 | 209 | ||||||||||||||||||||||
| Transportation | 521 | 491 | ||||||||||||||||||||||
| Total | 768 | 700 | ||||||||||||||||||||||
NSPI
Financial Highlights
For the | Three months ended March 31 | |||||||||||
| millions of Canadian dollars (except per share amounts) | 2018 | 2017 | ||||||||||
| Operating revenues – regulated electric | $ | 424 | $ | 396 | ||||||||
| Regulated fuel for generation and purchased power (1) | 175 | 139 | ||||||||||
| Contribution to consolidated net income | $ | 65 | $ | 70 | ||||||||
| Contribution to consolidated earnings per common share - basic | $ | 0.28 | $ | 0.33 | ||||||||
| EBITDA | $ | 156 | $ | 157 | ||||||||
(1) Regulated fuel for generation and purchased power includes the Fuel Adjustment Mechanism on the Condensed Consolidated Income Statement, however it is excluded in the segment overview.
Net Income
Highlights of the net income changes are summarized in the following table:
For the millions of Canadian dollars | | Three months ended March 31 | | |||||
| Contribution to consolidated net income – 2017 | $ | 70 | ||||||
| Increased operating revenues – see Operating Revenues – Regulated Electric below | 28 | |||||||
| Increased regulated fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below | (36 | ) | ||||||
| Decreased fuel adjustment mechanism (“FAM”) and fixed cost deferrals due to decreased current year over-recovery of fuel costs partially offset by the 2017 refund to customers of 2016 fuel costs | 11 | |||||||
| Increased OM&G expenses mostly due to storm costs partially offset by higher administrative overhead allocated to capital due to higher capital spending | (4 | ) | ||||||
| Other | (4 | ) | ||||||
| Contribution to consolidated net income – 2018 | $ | 65 | ||||||
NSPI’s contribution to consolidated net income decreased primarily due to storm costs.
Operating Revenues – Regulated Electric
Operating revenues increased $28 million to $424 million in Q1 2018 compared to $396 million in Q1 2017. Revenues increased as a result of refund to customers of over-recovery of 2016 fuel costs in 2017, increased sales volume due to load growth, and an increase due to fuel related electricity pricing effective January 1, 2018. This was partially offset by a decrease in sales volume due to warmer weather in Q1 2018 and to the recovery of the reduced Maritime Link assessment to be returned to customers in 2019.
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Electric revenues are summarized in the following tables by customer class:
Q1 Electric Revenues | ||||||||
| millions of Canadian dollars | ||||||||
| 2018 | 2017 | |||||||
| Residential | $ | 236 | $ | 228 | ||||
| Commercial | 110 | 103 | ||||||
| Industrial | 57 | 46 | ||||||
| Other | 14 | 11 | ||||||
| Total | $ | 417 | $ | 388 | ||||
Q1 Electric Sales Volumes | ||||||||
| GWh | ||||||||
| 2018 | 2017 | |||||||
| Residential | 1,518 | 1,511 | ||||||
| Commercial | 854 | 851 | ||||||
| Industrial | 624 | 601 | ||||||
| Other | 115 | 96 | ||||||
| Total | 3,111 | 3,059 | ||||||
Regulated Fuel for Generation and Purchased Power
Regulated fuel for generation and purchased power increased $36 million to $175 million in Q1 2018 compared to $139 million in Q1 2017 primarily due to increased sales volumes, increased commodity pricing, change in generation mix and payment of the Maritime Link assessment.
|
| |||||||
Q1 Production Volumes | ||||||||
| GWh | ||||||||
| 2018 | 2017 | |||||||
| Coal | 1,646 | 1,661 | ||||||
| Natural gas | 161 | 251 | ||||||
| Oil and petcoke | 456 | 349 | ||||||
| Purchased power – other | 88 | 97 | ||||||
| Totalnon-renewables | 2,351 | 2,358 | ||||||
| Wind and hydro – renewables | 385 | 376 | ||||||
| Purchased power – IPP | 386 | 370 | ||||||
| Purchased power – CommunityFeed-in Tariff program | 164 | 145 | ||||||
| Biomass – renewables | 40 | 43 | ||||||
| Total renewables | 975 | 934 | ||||||
| Total production volumes | 3,326 | 3,292 | ||||||
| Q1 Average Fuel Costs/MWh | ||||||||
| 2018 | 2017 | |||||||
| Dollars per MWh | $ | 53 | $ | 42 | ||||
Average fuel cost per MWh increased in Q1 2018 compared to Q1 2017 primarily due to increased commodity pricing, change in generation mix and payment of the Maritime Link assessment.
NSPI’s FAM regulatory liability balance has increased $4 million from $177 million at December 31, 2017 to $181 million at March 31, 2018 primarily due to the 2018 impact of the Maritime Link assessment and increased interest on FAM. This was partially offset as a result of theone-time refund to customers of the 2017 Maritime Link assessment.
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EMERA MAINE
Financial Highlights
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended March 31 | |||||||||||
| millions of US dollars (except per share amounts) | 2018 | 2017 | ||||||||||
| Operating revenues – regulated electric | $ | 57 | $ | 60 | ||||||||
| Regulated fuel for generation and purchased power (1) | 14 | 15 | ||||||||||
| Contribution to consolidated net income | $ | 8 | $ | 10 | ||||||||
| Contribution to consolidated net income – CAD | $ | 10 | $ | 13 | ||||||||
| Contribution to consolidated earnings per common share – basic – CAD | $ | 0.04 | $ | 0.06 | ||||||||
| Net income weighted average foreign exchange rate – CAD/USD | $ | 1.26 | $ | 1.32 | ||||||||
| EBITDA | $ | 25 | $ | 30 | ||||||||
| EBITDA – CAD | $ | 31 | $ | 39 | ||||||||
(1) Regulated fuel generation and purchased power includes transmission pool expense. | ||||||||||||
Net Income
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | |||
| millions of US dollars | March 31 | |||
| Contribution to consolidated net income – 2017 | $ | 10 | ||
| Decreased operating revenues - see Operating Revenues - Regulated Electric below | (3) | |||
| Decreased regulated fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below | 1 | |||
| Increased OM&G primarily due to storm restoration work, lower capitalized overheads as a result of lower capital spending partly due to storms and higher medical costs | (5) | |||
| Decreased income tax expense primarily due to the reduction of the US federal corporate income tax rate and decreased earnings before provision for income taxes | 5 | |||
| Contribution to consolidated net income – 2018 | $ | 8 | ||
Emera Maine’s CAD contribution to consolidated net income decreased by $3 million to $10 million in Q1 2018 compared to $13 million in Q1 2017. The foreign exchange rate had minimal impact for the three months ended March 31, 2018.
Operating Revenues – Regulated Electric
Emera Maine’s operating revenues – regulated electric include sales of electricity and other services as summarized in the following table:
For the | Three months ended March 31 |
| ||||||||
| millions of US dollars | 2018 | 2017 | ||||||||
| Electric revenues | $ | 42 | $ | 44 | ||||||
| Transmission pool revenues | 11 | 12 | ||||||||
| Resale of purchased power | 4 | 4 | ||||||||
| Operating revenues – regulated electric | $ | 57 | $ | 60 | ||||||
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Electric revenues are summarized in the following tables by customer class:
Q1 Electric Revenues millions of US dollars | ||||||||||||||||||||||||||||||||
| 2018 | 2017 | |||||||||||||||||||||||||||||||
| Residential | $ | 22 | $ | 22 | ||||||||||||||||||||||||||||
| Commercial | 15 | 15 | ||||||||||||||||||||||||||||||
| Industrial | 3 | 4 | ||||||||||||||||||||||||||||||
| Other (1) | 2 | 3 | ||||||||||||||||||||||||||||||
| Total | $ | 42 | $ | 44 | ||||||||||||||||||||||||||||
(1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.
Q1 Electric Sales Volumes
| GWh | 2018 | 2017 | ||||||||||||||||||
| Residential | 227 | 223 | ||||||||||||||||||
| Commercial | 194 | 195 | ||||||||||||||||||
| Industrial | 81 | 82 | ||||||||||||||||||
| Other | 3 | 4 | ||||||||||||||||||
| Total | 505 | 504 | ||||||||||||||||||
EMERA CARIBBEAN
Financial Highlights
All amounts are reported in USD, unless otherwise stated.
For the |
| Three months ended March 31 |
| |||||||||
| millions of US dollars (except per share amounts) | 2018 | 2017 | ||||||||||
| Operating revenues – regulated electric | $ | 80 | $ | 79 | ||||||||
| Regulated fuel for generation and purchased power | 40 | 36 | ||||||||||
| Adjusted contribution to consolidated net income - USD | $ | 4 | $ | 5 | ||||||||
| Adjusted contribution to consolidated net income - CAD | $ | 5 | $ | 7 | ||||||||
| After-tax equity securitiesmark-to-market gain (loss) | $ | (1) | $ | — | ||||||||
| Contribution to consolidated net income - USD | $ | 3 | $ | 5 | ||||||||
| Contribution to consolidated net income – CAD | $ | 4 | $ | 7 | ||||||||
| Adjusted contribution to consolidated earnings per common share – basic – CAD | $ | 0.02 | $ | 0.03 | ||||||||
| Contribution to consolidated earnings per common share – basic – CAD | $ | 0.02 | $ | 0.03 | ||||||||
| Net income weighted average foreign exchange rate – CAD/USD | $ | 1.26 | $ | 1.33 | ||||||||
| Adjusted EBITDA - USD | $ | 20 | $ | 23 | ||||||||
| Adjusted EBITDA - CAD | $ | 25 | $ | 30 | ||||||||
Net Income
Highlights of the net income changes are summarized in the following table:
For the | Three months ended | |||||||
| millions of US dollars | March 31 | |||||||
| Contribution to consolidated net income – 2017 | $ | 5 | ||||||
| Increased operating revenues - see Operating Revenues - Regulated Electric below | 1 | |||||||
| Increased regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below | (4) | |||||||
| Other | 1 | |||||||
| Contribution to consolidated net income – 2018 | $ | 3 | ||||||
24
Emera Caribbean’s CAD contribution to consolidated net income decreased by $3 million to $4 million in Q1 2018 compared to $7 million in Q1 2017 primarily as a result of lower sales volumes due to the impact of Hurricane Maria. The foreign exchange rate had minimal impact for the three months ended March 31, 2018.
Operating Revenues – Regulated Electric
Operating revenues increased $1 million to $80 million in Q1 2018 compared to $79 million in Q1 2017 due to increased fuel charge as a result of higher fuel prices in 2018 at BLPC, partially offset by lower sales volumes at Domlec due to the impact of Hurricane Maria.
Electric revenues are summarized in the following tables by customer class:
Q1 Electric Revenues | ||||||||
| millions of USD | ||||||||
| 2018 | 2017 | |||||||
| Residential | $ | 25 | $ | 25 | ||||
| Commercial | 47 | 45 | ||||||
| Industrial | 6 | 6 | ||||||
| Other | 1 | 1 | ||||||
| Total | $ | 79 | $ | 77 | ||||
Q1 Electric Sales Volumes | ||||||||
| GWh | ||||||||
| 2018 | 2017 | |||||||
| Residential | 101 | 108 | ||||||
| Commercial | 173 | 178 | ||||||
| Industrial | 21 | 22 | ||||||
| Other | 3 | 4 | ||||||
| Total | 298 | 312 | ||||||
Regulated Fuel for Generation and Purchased Power
Regulated fuel for generation and purchased power increased $4 million to $40 million in Q1 2018 compared to $36 million in Q1 2017 primarily due to higher oil prices.
Q1 Production Volumes | ||||||||
| GWh | ||||||||
| 2018 | 2017 | |||||||
| Oil | 309 | 324 | ||||||
| Hydro | 4 | 9 | ||||||
| Solar | 4 | 5 | ||||||
| Purchased power | 6 | 5 | ||||||
| Total | 323 | 343 | ||||||
| Q1 Average Fuel Costs/MWh | ||||||||
| USD | 2018 | 2017 | ||||||
| Dollars per MWh | $ | 124 | $ | 105 | ||||
Average fuel cost per MWh increased in Q1 2018 compared to Q1 2017 as a result of higher oil prices.
25
EMERA ENERGY
Financial Highlights
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2018 | 2017 | ||||||
| Marketing and trading margin (1) (2) | $ | 69 | $ | 26 | ||||
| Electricity and capacity sales (3) | 122 | 114 | ||||||
| Total operating revenues –non-regulated | 191 | 140 | ||||||
| Non-regulated fuel for generation and purchased power (4) | 68 | 87 | ||||||
| Adjusted contribution to consolidated net income | $ | 55 | $ | 10 | ||||
| After-tax derivativemark-to-market gain | $ | 70 | $ | 160 | ||||
| Contribution to consolidated net income | $ | 125 | $ | 170 | ||||
| Adjusted contribution to consolidated earnings per common share – basic | $ | 0.24 | $ | 0.05 | ||||
| Contribution to consolidated earnings per common share – basic | $ | 0.54 | $ | 0.80 | ||||
| Adjusted EBITDA | ||||||||
Emera Energy Services | $ | 56 | $ | 21 | ||||
Emera Energy Generation | 36 | 11 | ||||||
Equity Investment in Bear Swamp | 7 | (1) | ||||||
| Total | $ | 99 | $ | 31 | ||||
(1) Marketing and trading margin represents Emera Energy Service’s purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes apre-taxmark-to-market gain of $64 million for the quarter ended March 31, 2018 (2017 - $237 million gain).
(3) Electricity and capacity sales exclude apre-taxmark-to-market gain of $37 million for the quarter ended March 31, 2018 (2017 - $7 million loss).
(4)Non-regulated fuel for generation and purchased power excludes apre-taxmark-to-market of nil for the quarter ended March 31, 2018 (2017 - $1 million gain).
| For the | Three months ended | |||
| millions of Canadian dollars | March 31 | |||
| Contribution to consolidated net income – 2017 | $ | 170 | ||
| Increased marketing and trading margin – see Emera Energy Services below | 43 | |||
| Increased electricity and capacity sales - see Emera Energy Generation below | 8 | |||
| Decreasednon-regulated fuel for generation and purchased power - see Emera Energy Generation below | 19 | |||
| Increased income tax expense mainly due to increased income before provision for income taxes | (21) | |||
| Decreasedmark-to-market gain, net of tax primarily due to changes in existing positions on long-term natural gas contracts in 2017 and a larger reversal ofmark-to-market losses in 2017 compared to 2018, partially offset by lower amortization of gas transportation assets in 2018 | (90) | |||
| Other | (4) | |||
| Contribution to consolidated net income – 2018 | $ | 125 | ||
Excluding the decrease inmark-to-market gain, Emera Energy’s contribution to consolidated net income increased as a result of the favourable impact of cold weather and increased capacity prices.
26
Emera Energy Services
Marketing and Trading Margin
Marketing and trading margin increased $43 million to $69 million in Q1 2018 compared to $26 million in Q1 2017. This increase is the result of the favourable impact of cold weather in early 2018 in several of Emera Energy Services’ key market areas, which resulted in higher market prices and volatility that led to higher natural gas margins. The early 2018 activity also provided favourable hedging opportunities for the remainder of the quarter.
Emera Energy Generation
Electricity and Capacity Sales
For the | Three months ended March 31 | |||||||||||||||||||||||
| millions of Canadian dollars | New England | Maritime Canada | Total | |||||||||||||||||||||
| 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | |||||||||||||||||||
| Electricity sales | $ | 80 | $ | 65 | $ | 15 | $ | 38 | $ | 95 | $ | 103 | ||||||||||||
| Capacity sales | 27 | 11 | - | - | 27 | 11 | ||||||||||||||||||
| Electricity and capacity sales | $ | 107 | $ | 76 | $ | 15 | $ | 38 | $ | 122 | $ | 114 | ||||||||||||
Non-Regulated Fuel for Generation and Purchased Power
|
| |||||||||||||||||||||||
For the | Three months ended March 31 | |||||||||||||||||||||||
| millions of Canadian dollars | New England | Maritime Canada | Total | |||||||||||||||||||||
| 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | |||||||||||||||||||
| Non-regulated fuel for generation and purchased power | $ | 67 | $ | 58 | $ | 3 | $ | 28 | $ | 70 | $ | 86 | ||||||||||||
Emera Energy evaluates electricity sales andnon-regulated fuel for generation and purchased power on a combined basis for its NEGG facilities because the sales price of electricity and the cost of natural gas used to generate it are highly correlated in that market. NEGG’s electricity sales net ofnon-regulated fuel for generation and purchased power was $13 million in Q1 2018, compared to $7 million in Q1 2017. This increase is due to higher realized electricity pricing, reflecting more favourable market conditions and an increase in volumes produced, reflecting the impact of the unplanned outage at Bridgeport Energy inmid-March 2017.
Capacity sales increased $16 million to $27 million in Q1 2018 from $11 million in Q1 2017, due to higher capacity prices that came into effect for NEGG in June 2017.
The reduction in electricity sales andnon-regulated fuel for generation and purchased power in Maritime Canada in Q1 2018 reflects renegotiation of the Bayside Power PPA for the winter of 2017/2018, providing the counterparty with increased dispatch flexibility, while maintaining the net revenue stream for the facility.
Operating Statistics
For the | Three months ended March 31 | |||||||||||||||||||||||
| Sales Volumes (GWh) (1) | Plant Availability (%) (2) | Net Capacity Factor (%) (3) | ||||||||||||||||||||||
| 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | |||||||||||||||||||
| New England | 1,311 | 935 | 97.0% | 87.7% | 54.4% | 38.8% | ||||||||||||||||||
| Maritime Canada | 280 | 555 | 97.5% | 99.6% | 40.5% | 80.3% | ||||||||||||||||||
| Total | 1,591 | 1,490 | 97.1% | 90.3% | 51.3% | 48.3% | ||||||||||||||||||
(1) Sales volumes represent the actual electricity output of the plants.
(2) Plant availability represents the percentage of time in the period that the plant was available to generate power regardless of whether it was running. Effectively, it represents 100% availability reduced by planned and unplanned outages.
(3) Net capacity factor is the ratio of the utilization of an asset as compared to its maximum capability, within a particular time frame. It is generally a function of plant availability and plant economicsvis-à-vis the market.
27
CORPORATE AND OTHER
Financial Highlights
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2018 | 2017 | ||||||
| Operating revenues – regulated gas | $ | 13 | $ | 13 | ||||
| Non-regulated operating revenue | 10 | 16 | ||||||
| Total operating revenue | $ | 23 | $ | 29 | ||||
| Intercompany revenue (1) | 9 | 10 | ||||||
| Income from equity investments | 31 | 22 | ||||||
| Interest expense, net | 73 | 73 | ||||||
| Contribution to consolidated net income (loss) | $ | (23) | $ | (27) | ||||
| Contribution to consolidated earnings per common share – basic | $ | (0.10) | $ | (0.13) | ||||
| Adjusted EBITDA | $ | 40 | $ | 31 | ||||
(1) Intercompany revenue consists of interest from Brunswick Pipeline, M&NP and EEG.
Net Income
Highlights of the income changes are summarized in the following table:
For the millions of Canadian dollars | | Three months ended March 31 | | |||||
| Contribution to consolidated net income (loss) – 2017 | $ |
| (27) | |||||
| Decreasednon-regulated operating revenue due to decreased project activity in Emera Utility Services | (6) | |||||||
| Decreased OM&G | 5 | |||||||
| Income from equity investments - see Income from Equity Investments below | 9 | |||||||
| Decreased income tax recovery primarily due to the reduction of the US federal corporate income tax rate and decreased losses before the provision for income taxes | (5) | |||||||
| Other | 1 | |||||||
| Contribution to consolidated net income (loss) – 2018 | $ | (23) | ||||||
Corporate and Other’s contribution to consolidated net income increased primarily due to higher equity cash earnings from NSPML
Income from Equity Investments
Income from equity investments are summarized in the following table:
For the millions of Canadian dollars | | Three months ended March 31 | | |||||||||
| 2018 | 2017 | |||||||||||
| LIL | $ | 10 | $ | 9 | ||||||||
| NSPML | 15 | 7 | ||||||||||
| M&NP | 6 | 6 | ||||||||||
| Income from equity investments | $ | 31 | $ | 22 | ||||||||
In Q1 2018, NSPML has begun recording cash earnings and collecting UARB approved cash payments from NSPI. Prior to Q1 2018, NSPML recordednon-cash AFUDC earnings as it was under construction.
28
LIQUIDITY AND CAPITAL RESOURCES
The Company generates cash primarily through its investments in various regulated andnon-regulated energy related entities and investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’snon-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate sufficient cash include general economic downturns in markets served by Emera, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets and changes in environmental legislation. Emera’s subsidiaries maintain solid credit metrics and are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment.
Consolidated Cash Flow Highlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 2018 and 2017 include:
| millions of Canadian dollars | 2018 | 2017 | Change | |||||||||||||||||||||
| Cash, cash equivalents and restricted cash, beginning of period | $ | 503 | $ | 491 | $ | 12 | ||||||||||||||||||
| Provided by (used in): | ||||||||||||||||||||||||
| Operating cash flow before change in working capital | 444 | 348 | 96 | |||||||||||||||||||||
| Change in working capital | (11) | (182) | 171 | |||||||||||||||||||||
| Operating activities | 433 | 166 | 267 | |||||||||||||||||||||
| Investing activities | (387) | (381) | (6) | |||||||||||||||||||||
| Financing activities | (124) | 66 | (190) | |||||||||||||||||||||
| Effect of exchange rate changes on cash and cash equivalents | 10 | (2) | 12 | |||||||||||||||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | 435 | $ | 340 | $ | 95 |
Cash Flow from Operating Activities
Refer to the Consolidated Income Statement and Operating Cash Flow Highlights earlier in the document for details.
Cash Flow Used In Investing Activities
Net cash used in investing activities increased $6 million to $387 million for the three months ended March 31, 2018 compared to $381 million during Q1 2017 due to an increase in capital expenditures, partially offset by reduced investment in LIL in 2018 as compared to 2017.
Capital expenditures for Q1 2018, including AFUDC and net of proceeds from disposal of assets, were $349 million compared to $305 million during the same period in 2017. Details of the capital spend are shown below:
| • | $231 million at Emera Florida and New Mexico (2017 – $205 million); |
| • | $71 million at NSPI (2017 – $60 million); |
| • | $16 million at Emera Maine (2017 – $18 million); |
| • | $14 million at Emera Caribbean (2017 – $9 million); |
| • | $5 million at Emera Energy (2017 – $11 million); |
| • | $12 million in Corporate and Other (2017 – $2 million) |
29
Cash Flow from Financing Activities
Net cash used in financing activities increased $190 million to $124 million for Q1 2018 compared to net cash provided by financing activities $66 million for the same period in 2017. The increase was due to repayments on committed credit facilities, repayment of short-term debt at Emera Florida and New Mexico and the 2017 issuance of long-term debt at GBPC.
Contractual Obligations
As at March 31, 2018, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:
| millions of Canadian dollars | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | |||||||||||||||||||||
| Long-term debt principal | $ | 757 | $ | 1,145 | $ | 595 | $ | 2,245 | $ | 481 | $ | 8,986 | $ | 14,209 | ||||||||||||||
| Interest payment obligations (1) | 476 | 586 | 542 | 504 | 458 | 5,605 | 8,171 | |||||||||||||||||||||
| Purchased power (2) | 177 | 219 | 216 | 212 | 210 | 2,227 | 3,261 | |||||||||||||||||||||
| Transportation (3) | 385 | 326 | 281 | 195 | 184 | 1,493 | 2,864 | |||||||||||||||||||||
Pension and post-retirement obligations (4) | 84 | 38 | 38 | 39 | 39 | 751 | 989 | |||||||||||||||||||||
| Capital projects | 577 | 202 | 31 | 12 | - | - | 822 | |||||||||||||||||||||
| Fuel and gas supply | 377 | 185 | 51 | 41 | 4 | - | 658 | |||||||||||||||||||||
| Long-term service agreements (5) | 54 | 81 | 36 | 35 | 41 | 195 | 442 | |||||||||||||||||||||
| Asset retirement obligations | 2 | 1 | 1 | 43 | 1 | 381 | 429 | |||||||||||||||||||||
| Equity investment commitments (6) | 20 | 5 | 190 | - | - | - | 215 | |||||||||||||||||||||
| Leases and other (7) | 42 | 14 | 12 | 8 | 7 | 66 | 149 | |||||||||||||||||||||
| Demand side management | 42 | 28 | 18 | 18 | 18 | - | 124 | |||||||||||||||||||||
| Long-term payable | 3 | 4 | 5 | 5 | 5 | 5 | 27 | |||||||||||||||||||||
| Convertible debentures | - | - | - | - | - | 3 | 3 | |||||||||||||||||||||
| $ | 2,996 | $ | 2,834 | $ | 2,016 | $ | 3,357 | $ | 1,448 | $ | 19,712 | $ | 32,363 |
(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2018, including any expected required payment under associated swap agreements.
(2) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.
(3) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
(4) Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2017. Credited service and earnings are assumed to be crystallized as at December 31, 2017. The Company’s contractual obligations for post-retirement(non-pension) benefits assumes members must be age 55 or over (50 for TECO Energy) as at December 31, 2017 to be eligible. As the defined benefit pension plans currently undergo regular reviews to revise contribution requirements and members are still accruing service under the plans, actual future contributions to the plans will differ from the amounts shown.
(5) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.
(6) Emera has a commitment under the Federal Loan Guarantee to complete construction of the Maritime Link. The project has been placed in service and remaining costs relate to construction close out. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership. The amounts forecasted are a combination of investments in both projects.
(7) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.
NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years. The UARB has approved NSPI to pay NSPML approximately $110 million and $111 million in 2018 and 2019, respectively. After 2019, the timing and amounts payable to NSPML will be subject to a regulatory filing with the UARB which will be filed no later than 2019.
30
Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $3.4 billion committed syndicated revolving bank lines of credit in either CAD or USD, per the table below.
| millions of dollars | Maturity | Revolving Credit Facilities | Utilized | Undrawn and Available | ||||||||||||
| Emera – Operating and acquisition credit facility | June 2020 – Revolver | $ | 900 | $ | 116 | $ | 784 | |||||||||
| Emera Florida and New Mexico - in USD - credit facilities | | November 2018 - March 2022 |
| 1,800 | 1,009 | 791 | ||||||||||
| NSPI – Operating credit facility | | October 2021 – Revolver | 600 | 361 | 239 | |||||||||||
| Emera Maine – in USD – Operating credit facility | | September 2019 – Revolver | | 80 | 57 | 23 | ||||||||||
| Other – in USD – Operating credit facilities | Various | 32 | 10 | 22 | ||||||||||||
Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements as at March 31, 2018.
Recent financing activities for Emera and its subsidiaries are discussed below.
Emera Florida and New Mexico
On April 10, 2018, TECO Energy/Finance repaid a $250 million USD note upon maturity. The note was repaid using funds from existing credit facilities and cash on hand.
On March 23, 2018, TEC extended the maturity date of its $150 million USD accounts receivable collateralized borrowing facility from March 23, 2018 to March 22, 2021. There were no other changes in commercial terms.
On March 7, 2018, TECO Energy/Finance increased its $300 million USD revolving credit facility by $100 million USD to $400 million USD. There were no other changes in commercial terms.
On March 7, 2018, TECO Energy/Finance increased its $400 million USD term bank credit facility by $100 million USD to $500 million USD, and extended the maturity date from March 8, 2018 to March 8, 2019. There were no other changes in commercial terms.
ECI
On January 12, 2018, a wholly owned indirect subsidiary of ECI entered into a five year $18 million Bahamian dollar loan agreement with an interest rate of 4.00 per cent and maturity date of January 12, 2023.
31
Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2017 annual MD&A, with updates as noted below.
TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian was obligated to file, in respect of each mining permit, applications in connection with the change of control with the appropriate governmental entities. As each application was approved, Cambrian was required to post a bond or other appropriate collateral in order to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. As at March 31, 2018, TECO Energy had remaining indemnified bonds totaling $5 million ($4 million USD). In April 2018, all of the indemnified bonds were released and returned.
Emera has standby letters of credit in the amount of $37 million USD to third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have aone-year term and are renewed annually as required.
TRANSACTIONS WITH RELATED PARTIES
In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered tonon-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions betweennon-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.
Significant transactions between Emera and its associated companies are as follows:
| • | Transactions between NSPI and NSPML related to the Maritime Link Interim Assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Operating expenses, Regulated fuel for generation and purchased power, totalling $24 million for the three months ended March 31, 2018 (2017 – nil). NSPML is considered an equity investment and therefore, the corresponding earnings related to this revenue is reflected in Income from equity investments. Refer to the “Business Overview and Outlook”, “Corporate and Other – ENL” and “Contractual Obligations” sections for further details. |
| • | Natural gas transportation capacity revenues from M&NP are reported in the Condensed Consolidated Statements of Income. Revenues from M&NP, reported in Operating revenue -non-regulated, totalled $10 million for the three months ended March 31, 2018 (2017 - $10 million). |
There are no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2018 and December 31, 2017.
32
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2017 annual MD&A.
Hedging Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:
As at | March 31 |
| December 31 |
| ||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||
| Derivative instrument assets (current and other assets) | $ | 1 | $ | 7 | ||||||||
| Derivative instrument liabilities (current and long-term liabilities) | (5) | (7) | ||||||||||
| Net derivative instrument assets (liabilities) | $ | (4) | $ | - | ||||||||
Hedging Impact Recognized in Net Income
The Company recognized gains (losses) related to the effective portion of hedging relationships under the following categories:
For the | Three months ended March 31 | |||||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||
| Operating revenues – regulated | $ | 2 | $ | (3) | ||||||||
| Non-regulated fuel for generation and purchased power | 4 | 4 | ||||||||||
| Effective net gains (losses) | $ | 6 | $ | 1 | ||||||||
The effectiveness gains (losses) reflected in the above table would be offset in net income by the hedged item realized in the period.
Regulatory Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:
As at | March 31 |
| December 31 |
| ||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||
| Derivative instrument assets (current and other assets) | $ | 135 | $ | 181 | ||||||||
| Regulatory assets (current and other assets) | 15 | 13 | ||||||||||
| Derivative instrument liabilities (current and long-term liabilities) | (16) | (13) | ||||||||||
| Regulatory liabilities (current and long-term liabilities) | (138) | (183) | ||||||||||
| Net asset (liability) | $ | (4) | $ | (2) | ||||||||
33
Regulatory Impact Recognized in Net Income
The Company recognized the following net gains (losses) related to derivatives receiving regulatory deferral as follows:
For the | Three months ended March 31 | |||||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||
| Regulated fuel for generation and purchased power (1) | $ | 4 | $ | 7 | ||||||||
| Net gains (losses) | $ | 4 | $ | 7 | ||||||||
(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.
HFT Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to HFT derivatives:
|
| |||||||||||
As at | March 31 | December 31 | ||||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||
| Derivative instruments assets (current and other assets) | $ | 60 | $ | 63 | ||||||||
| Derivative instruments liabilities (current and long-term liabilities) | (223) | (290) | ||||||||||
| Net derivative instrument assets (liabilities) | $ | (163) | $ | (227) | ||||||||
HFT Items Recognized in Net Income
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:
|
| |||||||||||
For the | Three months ended March 31 | |||||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||
| Operating revenues –non-regulated | $ | 128 | $ | 324 | ||||||||
| Non-regulated fuel for generation and purchased power | (2) | 2 | ||||||||||
| Net gains (losses) | $ | 126 | $ | 326 | ||||||||
Other Derivatives Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to other derivatives:
|
| |||||||||||
As at | March 31 | December 31 | ||||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||
| Derivative instrument assets (current and other assets) | $ | 1 | $ | 2 |
| |||||||
| Net derivative instrument assets (liabilities) | $ | 1 | $ | 2 | ||||||||
Other Derivatives Recognized in Net Income
The Company has realized and unrealized gains (losses) with respect to cash flow hedges for which documentation requirements have not been met of nil for the three months ended March 31, 2018 (2017 – nil).
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DISCLOSURE AND INTERNAL CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI52-109”). The Company’s internal control framework is based on the criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at March 31, 2018, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.
There were no changes in the Company’s ICFR during the quarter ended March 31, 2018 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made.
Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, capitalized overhead and valuation of financial instruments. Actual results may differ significantly from these estimates. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in the Company’s 2017 annual MD&A.
CHANGES IN ACCOUNTING POLICIES AND PRACTICES
The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2018, are described as follows:
Revenue from Contracts with Customers
On January 1, 2018, the Company adopted Accounting Standard Updates (“ASU”)2014-09, Revenue from Contracts with Customers and all the related amendments, which created a new, principle-based revenue recognition framework. The standard has been codified as Accounting Standards Codification (“ASC”) Topic 606. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance requires additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.
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The Company adopted ASC 606 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting practices. The adoption of ASC 606 resulted in no adjustments to the Company’s opening retained earnings as of the adoption date or the Company’s Condensed Consolidated Income Statement for the three months ended March 31, 2018. The impact of the adoption of the new standard is expected to be immaterial to the Company’s net income on an ongoing basis.
Recognition and Measurement of Financial Assets and Financial Liabilities
On January 1, 2018, the Company adopted ASU2016-01,Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities and all the related amendments. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.
The standard requires investments in equity securities, except those accounted for under the equity method of accounting or those that result in consolidation, to be measured at fair value. The Company has elected to measure equity securities that do not have a readily determinable fair value at cost minus impairment (if any), plus or minus observable price changes resulting from transactions for the identical or a similar investment of the same issuer. The standard eliminates theavailable-for-sale classification for equity investments that recognized changes in the fair value as a component of other comprehensive income, resulting in all changes in fair value being recognized in net income. The increase in volatility of Other income (expense), net as a result of the remeasurement of equity investments is expected to be immaterial to the Company’s net income on an ongoing basis. A cumulative-effect adjustment of $4 million was made to retained earnings in the Condensed Consolidated Balance Sheet as of January 1, 2018.
Clarifying the Definition of a Business
In January 2017, the FASB issued ASU2017-01,Clarifying the Definition of a Business. The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and is required to be applied prospectively. The Company adopted ASU2017-01 effective January 1, 2018. There was no impact on the consolidated financial statements as a result of the adoption of this standard
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
In March 2017, the FASB issued ASU2017-07,Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component is eligible for capitalization as property, plant and equipment under this guidance. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization.
The Company adopted ASU2017-07 effective January 1, 2018 and March 31, 2017 balances have been retrospectively restated in the Consolidated Statements of Income. The amounts were determined by means of a practical expedient which allows the Company to use the amounts disclosed in its pension and other postretirement benefit plan note for the prior comparative periods as the estimation basis for applying the retrospective presentation requirements. This change resulted in $7 million of costs, previously presented within “Operating, maintenance and general”, being reclassified to “Other income (expense), net” in the Consolidated Statements of Income for the period ended March 31, 2017.
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Future Accounting Pronouncements
The Company considers the applicability and impact of all ASUs issued by Financial Accounting Standards Board (the “FASB”). The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in the 2017 audited consolidated financial statements, with updates noted below.
Leases
In February 2016, the FASB issued ASU2016-02,Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as assets and liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted and is required to be applied using a modified retrospective approach. The Company will not early adopt the standard.
In January 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. The Company expects to elect this practical expedient. In November 2017, the FASB voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The amendment is expected to be finalized in Q2 2018. The Company expects to elect this practical expedient.
The Company expects that the standard will affect its financial position by increasing the assets and liabilities recorded relating to its operating leases, however, the ultimate impact of the new standard on the Company’s financial statements and disclosures has not yet been determined. In 2017, the Company developed and began execution of a project plan which included holding training sessions with key stakeholders throughout the organization and gathering detailed information on existing lease arrangements. Remaining activities to be performed include evaluating the available implementation alternatives, calculating the lease asset and liability balances associated with individual contractual arrangements and assessing the disclosure requirements. The Company continues to monitor FASB amendments to ASC Topic 842.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
In February 2018, the FASB issued ASUNo. 2018-02,Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The standard allows reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the US Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive income. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.
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SUMMARY OF QUARTERLY RESULTS
For the quarter ended millions of dollars (except per share amounts) | Q1 2018 | Q4 2017 | Q3 2017 | Q2 2017 | Q1 2017 | Q4 2016 | Q3 2016 | Q2 2016 | ||||||||||||||||||||||||
| Operating revenues | $ | 1,807 | $ | 1,473 | $ | 1,427 | $ | 1,469 | $ | 1,857 | $ | 1,513 | $ | 1,387 | $ | 499 | ||||||||||||||||
| Net income (loss) attributable to common shareholders | 271 | (228) | 81 | 101 | 312 | 70 | (95) | 208 | ||||||||||||||||||||||||
| Adjusted net income attributable to common shareholders | 202 | 137 | 118 | 117 | 152 | 104 | 14 | 238 | ||||||||||||||||||||||||
| Earnings per common share – basic | 1.17 | (1.06) | 0.38 | 0.47 | 1.48 | 0.34 | (0.52) | 1.39 | ||||||||||||||||||||||||
| Earnings per common share – diluted | 1.17 | (1.06) | 0.38 | 0.47 | 1.47 | 0.34 | (0.52) | 1.38 | ||||||||||||||||||||||||
| Adjusted earnings per common share – basic | 0.87 | 0.64 | 0.55 | 0.55 | 0.72 | 0.51 | 0.08 | 1.59 | ||||||||||||||||||||||||
Quarterly operating revenues and adjusted net income attributable to common shareholders are affected by seasonality. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect the demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the Significant Items Affecting Earnings section andmark-to-market adjustments.
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