Emera Inc 6-K, filed May 18, 2020
Emera Inc (EMA)
About this 6-K
Emera Inc filed this 6-K on May 18, 2020.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16
UNDER THE SECURITIES EXCHANGE ACT OF 1934
For the month of May, 2020
Commission File Number: 000-54516
Emera Incorporated
(Exact name of registrant as specified in its charter)
5151 Terminal Road
Halifax NS B3J 1A1
Canada
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☑
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| EMERA INCORPORATED | ||||||
| Date: May 18, 2020
|
By:
|
\s\ Stephen D. Aftanas | ||||
| Name: Stephen D. Aftanas | ||||||
| Title: Corporate Secretary | ||||||
EXHIBIT INDEX
| Exhibit No. |
Description | |
| 99.1 | Emera Incorporated Management’s Discussion and Analysis for the three month period ended March 31, 2020 | |
| 99.2 | Emera Incorporated Unaudited Condensed Consolidated Interim Financial Statements for the three month period ended March 31, 2020 | |
| 99.3 | Form 52-109F2 Certification of Interim Filings by the Chief Executive Officer | |
| 99.4 | Form 52-109F2 Certification of Interim Filings by the Chief Financial Officer | |
| 99.5 | Emera Incorporated Earnings Coverage Ratio for the Twelve Months Ended March 31, 2020 | |
| 99.6 | Emera Incorporated Media Release dated May 13, 2020 | |
Table of Contents
Exhibit 99.1
Management’s Discussion & Analysis
As at May 12, 2020
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 2020 relative to the same quarter in 2019; and its financial position as at March 31, 2020 relative to December 31, 2019. 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 five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, 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, 2020; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2019. 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’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At March 31, 2020, 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”) | |
| Nova Scotia Power Inc. (“NSPI”) | Nova Scotia Utility and Review Board (“UARB”) | |
| Barbados Light & Power Company Limited (“BLPC”) | Fair Trading Commission, Barbados (“FTC”) | |
| Grand Bahama Power Company Limited (“GBPC”) | The Grand Bahama Port Authority (“GBPA”) | |
| Dominica Electricity Services Ltd. (“Domlec”) | Independent Regulatory Commission, Dominica (“IRC”) | |
| Peoples Gas System (“PGS”) – Gas Division of TEC | FPSC | |
| New Mexico Gas Company, Inc. (“NMGC”) | New Mexico Public Regulation Commission (“NMPRC”) | |
| SeaCoast Gas Transmission, LLC (“SeaCoast”) | FPSC | |
| Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) | Canadian Energy Regulator (“CER”) | |
|
Equity Investments |
||
| NSP Maritime Link Inc. (“NSPML”) | UARB | |
| 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”) | |
| Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”) | CER and FERC | |
1
Table of Contents
On March 24, 2020, the Company completed the sale of Emera Maine. Refer to the “Significant Items Affecting Q1 Earnings” and “Developments” sections for further details.
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Other Electric Utilities and Gas Utilities and Infrastructure 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 at www.sedar.com.
2
Table of Contents
| Forward-looking Information |
4 | |||
| Introduction and Strategic Overview |
4 | |||
| Non-GAAP Financial Measures |
6 | |||
| Consolidated Financial Review |
7 | |||
| Significant Items Affecting Q1 Earnings |
7 | |||
| Consolidated Financial Highlights by Business Segment |
8 | |||
| Consolidated Income Statement Highlights |
9 | |||
| Business Overview and Outlook |
12 | |||
| COVID-19 Pandemic |
12 | |||
| Florida Electric Utility |
13 | |||
| Canadian Electric Utilities |
14 | |||
| Other Electric Utilities |
16 | |||
| Gas Utilities and Infrastructure |
17 | |||
| Other |
18 | |||
| Consolidated Balance Sheet Highlights |
19 | |||
| Developments |
20 | |||
| Outstanding Common Stock Data |
20 | |||
| Financial Highlights |
21 | |||
| Florida Electric Utility |
21 | |||
| Canadian Electric Utilities |
23 | |||
| Other Electric Utilities |
25 | |||
| Gas Utilities and Infrastructure |
27 | |||
| Other |
29 | |||
| Liquidity and Capital Resources |
31 | |||
| Consolidated Cash Flow Highlights |
32 | |||
| Contractual Obligations |
33 | |||
| Debt Management |
34 | |||
| Credit Ratings |
35 | |||
| Guarantees and Letters of Credit |
35 | |||
| Transactions with Related Parties |
36 | |||
| Risk Management and Financial Instruments |
36 | |||
| Disclosure and Internal Controls |
39 | |||
| Critical Accounting Estimates |
39 | |||
| Changes in Accounting Policies and Practices |
40 | |||
| Future Accounting Pronouncements |
41 | |||
| Summary of Quarterly Results |
41 | |||
3
Table of Contents
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”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs 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; liquidity and capital market risk; future dividend growth; timing and costs associated with certain capital investment; 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; global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; counterparty 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; uncertainties associated with infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic; 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
Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the United States and the Caribbean. Cost-of-service utilities provide essential gas and electric services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus is to safely deliver cleaner, affordable and reliable energy to its customers.
Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have experienced stable regulatory policies and economic conditions.
4
Table of Contents
Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.
Emera has a $7.5 billion capital investment plan over the 2020-to-2022 period and the potential for additional capital opportunities of $200 million to $500 million over the forecast period, resulting in a forecasted rate base growth of 8 per cent through to 2022. Management continues to review the timing of capital expenditures in light of the evolving COVID-19 pandemic. This plan includes significant investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. This planned capital investment is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan will predominantly be funded in the equity capital markets through the dividend reinvestment plan and the issuance of common and preferred equity. Maintaining investment-grade credit ratings is a priority of management.
Emera has provided annual dividend growth guidance of four to five per cent through to 2022. The Company targets a long-term dividend payout ratio of 70 to 75 per cent, and while the payout ratio is likely to exceed that target in the forecast period, it is expected to return to that range over time.
Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income and cash flows are impacted by movements in the US dollar relative to the Canadian dollar and benefit from a weaker Canadian dollar. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investment and other factors mean that results in any one quarter are not necessarily indicative of results in any other quarter or for the year as a whole.
Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, complex regulatory environments and the trend towards de-carbonization. Renewable generation and battery storage are becoming both more affordable and efficient. Climate change and extreme weather are shaping how utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance reliability. Emera sees opportunity in these trends. Emera’s strategy is to fund investments in renewable and technology assets which protect the environment and benefit customers through fuel or operating cost savings.
For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, the ongoing construction of solar generation at Tampa Electric, and the modernization of the Big Bend Power Station at Tampa Electric. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of finding cleaner ways to meet the energy needs of its customers while keeping rates affordable.
Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships with regulators, stakeholders and the communities where we operate.
5
Table of Contents
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 the non-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
Emera calculates an adjusted net income measure by excluding the effect of mark-to-market (“MTM”) adjustments and impacts in Q1 2020 of the gain on sale of Emera Maine and the impairment losses on certain other assets.
The MTM adjustments are a result of the following:
| • | the mark-to-market adjustments related to Emera’s held-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; |
| • | the mark-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; |
| • | the mark-to-market adjustments related to an interest rate swap in Brunswick Pipeline; |
| • | the mark-to-market adjustments related to equity securities held in BLPC and Emera Reinsurance, a captive reinsurance company in the Other segment; and |
| • | the mark-to-market adjustments related to Emera’s foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure. |
Management believes excluding from net income the effect of these mark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows and ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors exclude these mark-to-market adjustments for evaluation of performance and incentive compensation.
Refer to the “Consolidated Financial Review” section and the “Financial Highlights” sections for Other Electric Utilities and Other segments, for further details on mark-to-market adjustments.
In Q1 2020, the Company completed the sale of Emera Maine and recognized impairment losses on certain other assets. Management believes excluding these from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. Refer to the “Significant Items Affecting Q1 Earnings” and “Developments” sections for further details related to the sale of Maine. While we have excluded the gain on sale from adjusted earnings, earnings for the Other Electric Utilities segment will not include earnings from Maine for the balance of the year, which were $27 million USD in 2019.
6
Table of Contents
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) | 2020 | 2019 | ||||||
| Net income attributable to common shareholders |
$ | 523 | $ | 312 | ||||
| Gain on sale and impairment charges, net of tax |
$ | 298 | $ | - | ||||
|
After-tax mark-to-market gain |
$ | 32 | $ | 88 | ||||
| Adjusted net income attributable to common shareholders |
$ | 193 | $ | 224 | ||||
| Earnings per common share – basic |
$ | 2.14 | $ | 1.32 | ||||
| Adjusted earnings per common share – basic |
$ | 0.79 | $ | 0.95 | ||||
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-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 a non-GAAP financial measure used by Emera. Similar to adjusted net income calculations described above, this measure represents EBITDA absent the income effect of Emera’s mark-to-market and amortization adjustments, and the gain on sale and impairment charges, recognized in Q1 2020, as discussed above.
The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies but, in management’s view, appropriately reflect 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 | 2020 | 2019 | ||||||
| Net income (1) |
$ | 535 | $ | 324 | ||||
| Interest expense, net |
184 | 189 | ||||||
| Income tax expense |
306 | 82 | ||||||
| Depreciation and amortization |
231 | 224 | ||||||
| EBITDA |
1,256 | 819 | ||||||
| Gain on sale and impairment charges |
564 | - | ||||||
| Mark-to-market gain, excluding income tax and interest |
45 | 126 | ||||||
| Adjusted EBITDA |
$ | 647 | $ | 693 | ||||
(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.
Significant Items Affecting Q1 Earnings
Gain on Sale and Impairment Charges
On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of $2.0 billion ($1.4 billion USD). A gain on sale of $586 million ($321 million after tax or $1.31 per common share), net of transaction costs, was recognized in “Other income” on the Condensed Consolidated Statements of Income. Refer to the “Developments” section for further details. In addition, impairment charges of $22 million ($23 million after tax) were recognized on certain other assets in Q1 2020.
7
Table of Contents
Earnings Impact of After-Tax Mark-to-Market Gains and Losses
After-tax mark-to-market gains decreased $56 million to $32 million in 2020 compared to $88 million in 2019, mainly due higher amortization of gas transportation assets in 2020 and larger reversal of mark-to-market losses in 2019, partially offset by changes in existing positions on gas contracts in Emera Energy. The decrease is also due to mark-to-market losses related to foreign exchange cash flow hedges entered in Q1 2020 to manage foreign exchange earnings exposure.
Q1 2019 Sale of NEGG and Bayside facilities
In Q1 2020, earnings contribution from Emera Energy Generation was $24 million lower than in 2019 due to the sale of the New England Gas Generating (“NEGG”) and Bayside generation facilities completed in March 2019.
Consolidated Financial Highlights by Business Segment
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Adjusted Net Income |
||||||||
| Florida Electric Utility |
$ | 79 | $ | 61 | ||||
| Canadian Electric Utilities |
92 | 96 | ||||||
| Other Electric Utilities |
20 | 16 | ||||||
| Gas Utilities and Infrastructure |
70 | 67 | ||||||
| Other |
(68 | ) | (16 | ) | ||||
| Adjusted net income attributable to common shareholders |
$ | 193 | $ | 224 | ||||
| Gain on sale and impairment charges, net of tax |
298 | - | ||||||
| After-tax mark-to-market gain |
32 | 88 | ||||||
| Net income attributable to common shareholders |
$ | 523 | $ | 312 | ||||
The following table highlights significant changes in adjusted net income from 2019 to 2020.
| For the | Three months ended | |||
| millions of Canadian dollars | March 31 | |||
| Adjusted net income – 2019 |
$ | 224 | ||
| Florida Electric Utility - increased earnings due to favourable weather, customer growth and higher contribution from solar projects | 18 | |||
| Recognition of corporate income tax recovery deferred as a regulatory liability in 2018 at BLPC | 10 | |||
| Decreased earnings at Emera Energy Services | (9 | ) | ||
| 2019 gain on sale of property in Florida | (10 | ) | ||
| Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities due to the Q1 2020 reduction in the Nova Scotia provincial corporate income tax rate | (14 | ) | ||
| Decreased earnings from Emera Energy Generation due to the sale of NEGG and Bayside generation facilities in Q1 2019 | (24 | ) | ||
| Other variances | (2 | ) | ||
| Adjusted net income – 2020 | $ | 193 | ||
Refer to the “Financial Highlights” section for further details of reportable segment contributions.
8
Table of Contents
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Operating cash flow before changes in working capital |
$ | 502 | $ | 418 | ||||
| Change in working capital |
(74 | ) | (16 | ) | ||||
| Operating cash flow |
$ | 428 | $ | 402 | ||||
| Investing cash flow |
$ | 746 | $ | 298 | ||||
| Financing cash flow |
$ | 165 | $ | (35 | ) | |||
| As at | March 31 | December 31 | ||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Total assets |
$ | 33,856 | $ | 31,842 | ||||
| Total long-term debt (including current portion) |
$ | 14,777 | $ | 14,180 | ||||
Refer to the “Consolidated Cash Flow Highlights” section for further discussion of cash flow.
Consolidated Income Statement Highlights
| For the millions of Canadian dollars (except per share amounts) |
Three months ended March 31 | Variance | ||||||||||
| 2020 | 2019 | |||||||||||
| Operating revenues |
$ | 1,637 | $ | 1,818 | $ | (181 | ) | |||||
| Operating expenses |
1,216 | 1,276 | 60 | |||||||||
| Income from operations |
421 | 542 | (121 | ) | ||||||||
| Income from equity investments |
41 | 40 | 1 | |||||||||
| Other income (expenses), net |
563 | 13 | 550 | |||||||||
| Interest expense, net |
184 | 189 | 5 | |||||||||
| Income tax expense |
306 | 82 | (224 | ) | ||||||||
| Net income |
535 | 324 | 211 | |||||||||
| Net income attributable to common shareholders |
523 | 312 | 211 | |||||||||
| Gain on sale and impairment charges, net of tax |
298 | - | 298 | |||||||||
|
After-tax mark-to-market gain |
32 | 88 | (56 | ) | ||||||||
| Adjusted net income attributable to common shareholders |
$ | 193 | $ | 224 | $ | (31 | ) | |||||
| Earnings per common share – basic |
$ | 2.14 | $ | 1.32 | $ | 0.82 | ||||||
| Earnings per common share – diluted |
$ | 2.13 | $ | 1.32 | $ | 0.81 | ||||||
| Adjusted earnings per common share – basic |
$ | 0.79 | $ | 0.95 | $ | (0.16 | ) | |||||
| Dividends per common share declared |
$ | 0.6125 | $ | 0.5875 | $ | 0.0250 | ||||||
| Adjusted EBITDA |
$ | 647 | $ | 693 | $ | (46 | ) | |||||
Operating Revenues
For the first quarter of 2020, operating revenues decreased $181 million compared to the first quarter of 2019. Absent decreased mark-to-market gains of $61 million, operating revenues decreased $120 million due to:
| • | $112 million decrease in the Other segment due to the sale of NEGG and Bayside in Q1 2019; |
| • | $21 million decrease in Gas Utilities and Infrastructure due to lower clause-related revenues at PGS and NMGC, unfavourable weather at NMGC and lower off-system sales at PGS; |
| • | $13 million decrease in marketing and trading margin at Emera Energy due to less favourable market conditions; and |
| • | $12 million decrease in Other Electric Utilities at Emera Maine from lower loads due to weather. |
9
Table of Contents
These impacts were partially offset by increases of:
| • | $15 million at NSPI due to the reduced Maritime Link assessment included in 2019 rates to be returned to customers in subsequent years, and increased fuel related pricing. This was partially offset by lower sales volumes, primarily due to weather; and |
| • | $19 million in the Florida Electric Utility segment due to increased base revenues related to favourable weather, customer growth, the in-service of solar generation projects and the impact of a weaker CAD. |
Operating Expenses
For the first quarter of 2020, operating expenses decreased $60 million compared to the first quarter of 2019 due to:
| • | $81 million decrease in the Other segment due to the sale of NEGG and Bayside in Q1 2019; and |
| • | $20 million decrease in the Gas Utilities and Infrastructure segment due to lower regulated cost of natural gas reflecting lower commodity costs at PGS and NMGC. |
These impacts were partially offset by an increase of:
| • | $23 million in the Canadian Electric Utility segment due to changes in the fuel adjustment mechanism and increased operating, maintenance and general (“OM&G”) expenses in NSPI. |
Other Income (Expenses), Net
The increase in other income (expenses), net for the first quarter in 2020, compared to the first quarter of 2019, was primarily due to the pre-tax gain on sale of Emera Maine, partially offset by impairment charges on certain other assets recognized in Q1 2020.
Income Tax Expense
The increase in income tax expense for the first quarter of 2020 compared to the first quarter of 2019 was primarily due to the gain on sale of Emera Maine and the revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020. This was partially offset by decreased income before provision for income taxes, excluding the gain on sale of Emera Maine, and the recognition of corporate income tax recovery deferred as a regulatory liability in 2018 at BLPC.
Net Income and Adjusted Net Income Attributable to Common Shareholders
For the first quarter of 2020, net income attributable to common shareholders was favourably impacted by the $321 million after-tax gain on sale of Emera Maine, and unfavourably impacted by the $56 million decrease in after-tax mark-to-market gains primarily related to Emera Energy and after-tax impairment charges. Absent the net gain on sale of Emera Maine, the unfavourable mark-to-market changes and impairment charges recognized in Q1 2020, adjusted net income attributable to common shareholders decreased $31 million. The decrease was due to lower contributions from Emera Energy (as a result of the sale of NEGG in Q1 2019 and decreased marketing and trading margin), revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate and the 2019 gain on sale of property in Florida. These were partially offset by an increased contribution from Tampa Electric and recognition of deferred income tax at BLPC.
10
Table of Contents
Earnings and Adjusted Earnings per Common Share – Basic
Earnings per common share – basic were higher for the first quarter due to higher earnings as discussed above. Adjusted earnings per common share – basic were lower for the first quarter due to lower earnings as discussed above and the impact of the increase in the weighted average shares outstanding.
Effect of Foreign Currency Translation
Emera operates internationally, 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, the percentage of earnings from foreign operations in the period and the impact of foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure.
Results of 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 2020 and 2019 are as follows:
| Three months ended March 31 |
Year ended December 31 |
|||||||||||
| 2020 | 2019 | 2019 | ||||||||||
| Weighted average CAD/USD |
$ | 1.34 | $ | 1.33 | $ | 1.33 | ||||||
| Period end CAD/USD exchange rate |
$ | 1.42 | $ | 1.34 | $ | 1.30 | ||||||
Weakening of the CAD exchange rates increased earnings by $5 million and adjusted earnings by $1 million in Q1 2020 compared to Q1 2019.
Consistent with the Company’s risk management policies, Emera partially manages currency risks through matching US denominated debt to finance its US operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. Emera does not utilize derivative financial instruments for foreign currency trading or speculative purposes.
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 | 2020 | 2019 | ||||||
| Florida Electric Utility |
$ | 59 | $ | 46 | ||||
| Other Electric Utilities |
15 | 12 | ||||||
| Gas Utilities and Infrastructure (1) |
45 | 45 | ||||||
| 119 | 103 | |||||||
| Other segment (2) |
(23 | ) | (16 | ) | ||||
| Total (3) |
$ | 96 | $ | 87 | ||||
(1) Includes US dollar net income from PGS, NMGC, SeaCoast and M&NP.
(2) Includes Emera Energy’s US dollar adjusted net income from Emera Energy Services, Bear Swamp, interest expense on Emera Inc.’s US dollar denominated debt and in 2019 net income from NEGG.
(3) Amounts above do not include the impact of mark-to-market.
11
Table of Contents
In Q1 2020, the ongoing COVID-19 pandemic impacted all the service territories in which Emera operates. To date, COVID-19 has not had a material financial impact on the Company, Emera’s utilities provide essential services and continue to operate and meet customer demand. The Company’s top priority continues to be the health and safety of its customers and employees. Management continues to closely monitor developments related to COVID-19.
Governments world-wide have implemented measures intended to address the pandemic. These measures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial spaces and industrial facilities, shutdowns, shelter-in-place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility and weakness. Governments and central banks are implementing measures designed to stabilize economic conditions.
Emera has activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.
The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. The Company has updated its principal risks to reflect this uncertainty. Refer to the “Risk Management and Financial Instruments” section and note 21 in the condensed consolidated financial statements for this risk update. The Company has disclosed the impact of this uncertainty on its accounting estimates used in the preparation of the financial statements. Refer to the “Critical Accounting Estimates” section, and the “Use of Management Estimates” section of note 1 in the condensed consolidated financial statements for further details.
Potential future impacts on the business are anticipated to include the following:
| • | Lower earnings as a result of lower sales volumes due to economic slowdowns. Commercial and industrial sales are generally expected to be lower, with this decrease partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. To date, the Company is generally experiencing reductions to weather-adjusted load in the range of 4-to-6 per cent for most of its utilities; |
| • | Delays of capital projects as a result of construction shutdowns, government restrictions on non-essential capital work, travel restrictions for contractors or supply chain disruptions. Capital project delays have been minimal to date; |
| • | Deferral of and adjustment to regulatory filings, hearings, decisions and recovery periods; and |
| • | Decreased cash flow from operations due to lower earnings and slower collection of accounts receivable. Emera’s utilities are working with customers on relief initiatives in response to the effect on customers’ ability to pay and their need for continued service. These initiatives include the suspension of disconnection for non-payment of bills and the development of payment arrangements if necessary. In certain service territories, collection may be further delayed due to curfew restrictions and temporary short-term closure of locations able to receive in-person payments. |
12
Table of Contents
Refer to the outlook sections by segment below for discussion of utility-specific impacts. These segment outlooks are based on the information currently available, however, the total impact of COVID-19 is unknown at this time due to uncertainties related to the duration and severity of the pandemic.
Depending on the duration of the COVID-19 pandemic, the forecasted capital expenditures disclosed below may be delayed due to supply chain disruptions, travel restrictions for contractors or the deferral of non-essential capital work, if required. The Company currently expects to continue to have adequate liquidity given its cash position, existing bank facilities, and access to capital, but will continue to monitor the impact of COVID-19 on future cash flows. Refer to the “Liquidity and Capital Resources” section for further details.
Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida.
Tampa Electric currently anticipates earning within its allowed ROE range in 2020 and expects rate base to be higher than 2019. Favourable weather in Q1 2020 has more than offset the impacts on revenues as a result of COVID-19. Based on Q1 results and current estimates of COVID-19 impacts, and assuming normal weather for the remainder of the year, Tampa Electric expects customer growth rates and volumes to be negatively impacted by expected declines in economic activity in Florida, resulting in overall sales volumes for the year being similar or slightly lower than in 2019. However, current expected outcomes and actual results may differ given the many uncertainties related to the pandemic and its economic impact.
On October 3, 2019, the FPSC issued a rule to implement a storm protection plan cost recovery clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. The FPSC is expected to rule on the plan in late 2020.
On April 28, 2020 the FPSC approved Tampa Electric’s request for a mid-course adjustment to its fuel and capacity charges due to a decline in expected fuel commodity and capacity costs in 2020. The adjustment will be effective beginning with June 2020 customer bills and will result in lower rates for the balance of the year, including an acceleration of the return of these savings in the first three months.
On February 18, 2020, Tampa Electric announced its intention to invest approximately $800 million USD in an additional 600 MW of new utility-scale solar photovoltaic projects by the end of 2023. Refer to the “Developments” section for further details.
Planned capital expenditures in the Florida Electric Utility segment for 2020 remain unchanged at approximately $1.0 billion USD (2019 - $1.1 billion USD), including AFUDC. Capital projects include solar investments, continuation of the modernization of the Big Bend Power Station, storm hardening investments, and advanced metering infrastructure (“AMI”).
13
Table of Contents
Canadian Electric Utilities includes:
| • | NSPI, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia; and |
| • | ENL, a holding company with equity investments in NSPML and LIL, two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador. |
| • | The Maritime Link entered service on January 15, 2018 and provides for the transmission of energy between Newfoundland and Nova Scotia, as well as improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. The Maritime Link will transmit at greater capacity when the Muskrat Falls hydroelectricity generation project is complete. |
| • | Construction of the LIL is complete and Nalcor Energy (“Nalcor”) recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL, however, there has been a suspension of on-site commissioning in response to the COVID-19 pandemic. |
NSPI
NSPI anticipates earning within its allowed ROE range in 2020. Sales volumes and earnings are expected to be lower than 2019 due to the impact of the COVID-19 pandemic on Nova Scotia’s economy. NSPI expects a decrease in sales volumes primarily in the commercial and industrial classes, partially offset by an increase in residential sales volumes, which have a higher contribution to fixed cost recovery. The anticipated deferral of capital investment, discussed below, will have a corresponding decreasing effect on NSPI’s expected rate base growth in the current year.
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these laws and regulations, to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated reductions will be recoverable under NSPI’s regulatory framework.
In Q1 2020, NSPI received its 2020 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These 2020 allowances will be used in 2020 or allocated within the initial four-year compliance period that ends in 2022. At March 31, 2020, NSPI is on track to meet the requirements of the program. NSPI anticipates that any prudently incurred costs required to comply with the Government of Canada’s laws and regulations, and the Nova Scotia Cap-and-Trade Program Regulations, will be recoverable under NSPI’s regulatory framework.
Over the past several years, the requirement to reduce Nova Scotia’s reliance upon higher carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a significant investment in renewable energy sources and purchasing renewable energy from independent power producers. NSPI will have an increase in energy from renewable sources upon delivery of the Nova Scotia block (“NS Block”) of electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project.
14
Table of Contents
On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. Due to the unpredictability of the course of the pandemic, Nalcor is currently unable to provide an updated construction schedule. Refer to the “ENL – Impact of COVID-19 on Muskrat Falls and LIL” section below for further details. Should there be a delay in the delivery of the NS Block beyond 2020, NSPI’s ability to achieve the provincially legislated target of 40 per cent electricity generated from renewable sources in 2020 could require the sourcing of alternate qualifying energy. NSPI is working with the provincial government on options to address this potential risk.
As a result of the measures taken to limit the spread of COVID-19, there are restrictions on completing non-essential capital projects. NSPI anticipates this will result in a reduction in its 2020 capital investments from $375 million to approximately $275 million. The $100 million of capital investments will be deferred to 2021 and 2022. Capital investment for 2019, including AFUDC, was $396 million.
ENL
Equity earnings from NSPML and LIL are expected to be higher in 2020, compared to 2019. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.
NSPML
Equity earnings contributions from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.
NSPML has UARB approval to collect approximately $145 million (2019—$111 million) from NSPI for the recovery of costs associated with the Maritime Link in 2020, which is included in NSPI rates. NSPML expects to file a final capital cost application for the Maritime Link with the UARB upon commencement of the NS Block of energy from Muskrat Falls. As a result of the potential delay of the NS Block, NSPML’s final capital cost application will be delayed. Consequently, NSPML anticipates making an application with the UARB in 2020 to reset rates for recovery of costs in 2021.
In 2020, NSPML expects to invest approximately $20 million (2019—$28 million) in capital.
LIL
Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $591 million, comprised of $410 million in equity contribution and $181 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after all Lower Churchill projects, including Muskrat Falls, are completed.
Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, and until that point Emera will continue to record AFUDC earnings.
15
Table of Contents
Impact of COVID-19 on Muskrat Falls and LIL
On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor has declared force majeure under various project contracts, including formal notification to NSPML. Due to the unpredictable nature of the COVID-19 pandemic, Nalcor is currently unable to provide an updated completion schedule for Muskrat Falls or LIL until there is greater certainty. Nalcor has expressed its desire to resume work at site as soon as it is safe to do so for its employees, contractors and associated communities.
Other Electric Utilities includes:
| • | Emera Maine, a regulated transmission and distribution electric utility in the state of Maine. On March 24, 2020, Emera completed the sale of Emera Maine. Refer to the “Developments” section for further details. |
| • | Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities, BLPC, a vertically integrated regulated electric utility on the island of Barbados, and GBPC, a vertically integrated regulated electric utility on Grand Bahama Island. ECI also holds: |
| • | a 51.9 per cent interest in Domlec, a vertically integrated regulated electric utility on the island of Dominica; and |
| • | a 19.5 per cent interest in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia. |
Removing the impact of the GBPC impairment charge recognized in 2019, Other Electric Utilities’ earnings are expected to decrease over the prior year. This decrease is due to lower earnings contribution from Emera Maine as a result of the sale in March 2020, and lower earnings from the Caribbean utilities.
Earnings from the Caribbean utilities are expected to be lower due to the impact of COVID-19 on local economies. Tourism and associated support businesses have been significantly impacted by the suspension of international travel, with many businesses temporarily closed. As a result, earnings from both BLPC and Domlec are expected to be lower than in 2019. The expected decrease in BLPC’s earnings will be partially offset by the Q1 2020 recognition of a $6.9 million USD corporate income tax recovery which was deferred as a regulatory liability in 2018. GBPC’s earnings are expected to be consistent with 2019 earnings which were lower than normal as a result of Hurricane Dorian. The impact of COVID-19 on GBPC is expected to be partially offset by recovery of load following Hurricane Dorian. The decrease in earnings from the Caribbean utilities is expected to be in the range of approximately $3 million to $8 million USD depending on the extent and duration of the pandemic’s impact on local economies.
On April 16, 2020, S&P Global Ratings (“S&P”) lowered its long-term foreign and local currency ratings on The Bahamas. The downgrade was driven by the uncertainty around the duration of the COVID-19 pandemic and the strength of the recovery. The downgrade is not currently expected to have a material financial impact on GBPC.
On September 1, 2019, Hurricane Dorian struck Grand Bahama Island causing significant damage across the island. In January 2020, the GBPA approved the recovery of approximately $15 million USD of restoration costs related to GBPC’s self-insured assets. As of March 31, 2020, $13 million USD of these costs were incurred, and recorded as a regulatory asset. Recovery of the regulatory asset, due to start on April 1, 2020, has been temporarily suspended as a result of the economic impacts of COVID-19 on Grand Bahama.
16
Table of Contents
In 2020, capital expenditures in the Other Electric Utilities segment are forecasted to be approximately $130 million USD (including $14 million USD invested in Emera Maine projects supporting normal system reliability prior to completion of the sale) (2019 – $150 million USD). Completion of BLPC’s 33MW diesel engine installation, expected by mid-2020, will be delayed until travel restrictions, implemented by the government in response to COVID-19, are lifted for construction work.
Gas Utilities and Infrastructure
Gas Utilities and Infrastructure includes:
| • | PGS, a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida; |
| • | NMGC, a regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico; |
| • | SeaCoast, a regulated intrastate natural gas transmission company offering services in Florida; |
| • | Brunswick Pipeline, a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States; and |
| • | Emera’s non-consolidated investment in M&NP. |
Earnings from the gas utilities are anticipated to be lower than in 2019 due to impact of the COVID-19 pandemic.
PGS anticipates earning below its allowed ROE range in 2020. PGS sales volumes are expected to be lower than in 2019 as a result of the economic impact of COVID-19 in Florida. Beginning mid-March, PGS sales volumes have shown a decreasing trend as a result of the impact of government quarantine measures on commercial activity and tourism. Prior to the impact of COVID-19, PGS anticipated it would earn below its allowed ROE range in 2020 primarily due to significant capital investments and related growth in rate base. Therefore, as a result of forecasted revenue requirements being higher than what is in current rates, on February 7, 2020, PGS notified the FPSC that it was planning to file a base rate proceeding in April 2020 for new rates effective January 2021. Due to the COVID-19 pandemic, in early April 2020, PGS requested and received an extension from the FPSC to file this proceeding by June 8, 2020.
NMGC anticipates earning at or slightly below its allowed ROE in 2020 and expects rate base to be higher than 2019. Assuming normal weather, NMGC sales volumes are expected to decrease, as 2019 energy sales benefited from favourable weather in the first half of the year. NMGC sales volumes to date have not been significantly impacted by COVID-19. Depending on the duration of COVID-19 related restrictions, industrial and commercial sales volumes are expected to decrease. Earnings from NMGC are also expected to be lower as a result of the 2019 recognition of tax reform benefits, and the approved change in treatment of net operating loss (“NOL”) carryforwards in 2019, which contributed a total of $14 million USD to earnings last year.
In 2020, capital expenditures in the Gas Utilities and Infrastructure segment are expected to be approximately $600 million USD (2019 - $331 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will complete the Santa Fe Mainline Looping project in 2020 and will continue to invest in system improvements. SeaCoast will continue to invest in the Seminole Pipeline and the Callahan Pipeline with approximately $100 million USD expected to be invested in 2020. The Seminole and Callahan Pipelines remain on schedule with total costs of approximately $110 million USD and $32 million USD, respectively.
17
Table of Contents
The Other segment includes those business operations that, in a normal year, are below the required threshold for reporting as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments.
Business operations in Other include Emera Energy, which consists of:
| • | Emera Energy Services (“EES”), a wholly owned physical energy marketing and trading business; |
| • | Brooklyn Power Corporation (“Brooklyn Energy’), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; 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. |
In 2019, the Company completed the sale of assets previously reported in this segment including the sale of its NEGG and Bayside facilities in March 2019 and the sale of its Emera Utility Services equipment and inventory in December 2019. These operations contributed $20 million to earnings in 2019.
Corporate items included in the Other segment are 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, corporate human resources activities, acquisition and disposition related costs, gains or losses on select assets sales, and gains or losses on foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure. It includes interest revenue on intercompany financings recorded in “Intercompany revenue” and interest expense on corporate debt in both Canada and the US. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.
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. The business is generally expected to deliver annual adjusted net earnings of $15 to $30 million USD ($45 to $70 million USD of margin), with the opportunity for upside when market conditions present. EES expects that the COVID-19 related economic slowdown could impact gas supply/demand and result in lower absolute pricing and volatility in its core geography for some months. This would reduce opportunity for the business, which the Company expects would result in earnings at the lower end of the normal range in 2020.
The Other segment is expected to contribute positively to earnings in 2020 due to the gain on sale of Emera Maine recognized in earnings in Q1 2020. Absent this gain, the adjusted net loss from the Other segment is expected to increase over the prior year. This increase is primarily due to decreased tax recoveries and increased interest due to increased borrowings. The decrease in tax recoveries is due to the revaluation of deferred income tax assets at the lower Nova Scotia corporate income tax rate enacted in March 2020. These impacts are anticipated to be partially offset by increased EES contribution.
In 2020, capital expenditures in the Other segment are expected to be approximately $40 million (2019 - $63 million), including investment in contracted energy infrastructure.
18
Table of Contents
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2019 and March 31, 2020 include:
| millions of Canadian dollars | Increase (Decrease) |
Explanation | ||||
| Assets | ||||||
| Cash and cash equivalents | $ | 1,331 | Increased due to proceeds on the sale of Emera Maine and cash from operations, partially offset by additions of property, plant and equipment and dividends on common stock. | |||
| Regulatory assets (current and long-term) | 68 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates. | ||||
| Receivables and other assets (current and long-term) | 121 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, reclassification of corporate alternative minimum tax credit carryforwards from deferred income tax liabilities, increased cash collateral position on derivative instruments at NSPI and the seasonality of business at NSPI. This is partially offset by lower commodity prices at Emera Energy. | ||||
| Assets held for sale (current and long-term), net of liabilities | (691 | ) | Decreased due to the completion of the sale of Emera Maine. | |||
| Property, plant and equipment, net of accumulated depreciation and amortization | 1,679 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates and additions at Tampa Electric, PGS and NSPI. | ||||
| Goodwill | 538 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates. | ||||
| Liabilities and Equity |
|
|||||
| Short-term debt and long-term debt (including current portion) | 1,271 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, and increased borrowings under Tampa Electric’s committed credit facilities. These were partially offset by payment of long-term debt at TECO Finance. | ||||
| Accounts payable | (96 | ) | Decreased due to lower commodity prices at Emera Energy, payments for solar projects and the Big Bend modernization at Tampa Electric, and timing of payments at NSPI. These were partially offset by the effect of a weaker CAD on the translation of Emera’s foreign affiliates. | |||
| Deferred income tax liabilities, net of deferred income tax assets | 371 | Increased due to net utilization of tax loss carryforwards primarily related to the sale of Emera Maine, tax deductions in excess of accounting depreciation related to property, plant and equipment and the effect of a weaker CAD on the translation of Emera’s foreign subsidiaries. The increase is partially offset by the revaluation of net deferred income tax liabilities resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020. | ||||
| Regulatory liabilities (current and long-term) | 217 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, increased cost recovery clauses at Tampa Electric and increased deferrals related to derivative instruments at NSPI. | ||||
| Other liabilities (current and long-term) | 223 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, higher accrued interest on long-term debt at Tampa Electric and Corporate and investment tax credits related to solar projects at Tampa Electric. | ||||
19
Table of Contents
| Common stock | 124 | Increased due to shares issued under Emera’s at-the-market equity plan, stock options exercised and the dividend reinvestment plan. | ||||
| Accumulated other comprehensive income | 612 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates. | ||||
| Retained earnings | 367 | Increased due to the gain on sale of Emera Maine and net income in excess of dividends paid. | ||||
Sale of Emera Maine
On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of $2.0 billion ($1.4 billion USD), including cash proceeds of $1.4 billion, transferred debt and a working capital adjustment. A gain on sale of $586 million ($321 million after tax), net of transaction costs, was recognized in the Other segment and included in “Other income” on the Condensed Consolidated Statements of Income. Proceeds from the sale are being used to support capital investment opportunities within Emera’s regulated utilities and to reduce corporate debt.
Tampa Electric Solar Investment
On February 18, 2020, Tampa Electric announced its intention to invest approximately $800 million USD in an additional 600 MW of new utility-scale solar photovoltaic projects by the end of 2023. On completion of these projects, approximately 22 per cent or 1,250 MW of Tampa Electric’s total generating capacity will be solar.
| Common stock Issued and outstanding: |
millions of shares |
millions of Canadian dollars |
||||||
| Balance, December 31, 2018 |
234.12 | $ | 5,816 | |||||
| Conversion of Convertible Debentures |
0.03 | 1 | ||||||
| Issuance of common stock |
1.77 | 99 | ||||||
| Issued for cash under Purchase Plans at market rate |
3.99 | 202 | ||||||
| Discount on shares purchased under Dividend Reinvestment Plan |
- | (7 | ) | |||||
| Options exercised under senior management stock option plan |
2.57 | 104 | ||||||
| Employee Share Purchase Plan |
- | 1 | ||||||
| Balance, December 31, 2019 |
242.48 | $ | 6,216 | |||||
| Issuance of common stock (1) |
0.98 | 58 | ||||||
| Issued for cash under Purchase Plans at market rate |
0.83 | 49 | ||||||
| Discount on shares purchased under Dividend Reinvestment Plan |
- | (1 | ) | |||||
| Options exercised under senior management stock option plan |
0.36 | 17 | ||||||
| Employee Share Purchase Plan |
- | 1 | ||||||
| Balance, March 31, 2020 |
244.65 | $ | 6,340 | |||||
(1) In Q1 2020, 982,982 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $59.79 per share for gross proceeds of $58.8 million ($58 million net of issuance costs). As at March 31, 2020, an aggregate gross sales limit of $441.2 million remains available for issuance under the ATM program.
As at May 8, 2020 the amount of issued and outstanding common shares was 244.7 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, 2020 was 244.7 million (2019 – 236.4 million).
20
Table of Contents
All amounts are reported in USD, unless otherwise stated.
| For the millions of US dollars (except per share amounts) |
Three months ended March 31 |
|||||||
| 2020 | 2019 | |||||||
| Operating revenues – regulated electric |
$ | 421 | $ | 412 | ||||
| Regulated fuel for generation and purchased power |
106 | 115 | ||||||
| Contribution to consolidated net income |
$ | 59 | $ | 46 | ||||
| Contribution to consolidated net income – CAD |
$ | 79 | $ | 61 | ||||
| Contribution to consolidated earnings per common share – basic – CAD |
$ | 0.32 | $ | 0.26 | ||||
| Net income weighted average foreign exchange rate – CAD/USD |
$ | 1.34 | $ | 1.33 | ||||
| EBITDA |
$ | 184 | $ | 166 | ||||
| EBITDA – CAD |
$ | 248 | $ | 221 | ||||
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 – 2019 |
$ 46 | |||
| Increased operating revenues—see Operating Revenues—Regulated Electric below |
9 | |||
| Decreased fuel for generation and purchased power—see Regulated Fuel for Generation and Purchased Power below | 9 | |||
| Increased depreciation and amortization due to increased property, plant and equipment |
(4 | ) | ||
| Increased other income as a result of higher AFUDC earnings due to the construction of solar projects and Big Bend modernization project | 3 | |||
| Increased interest expense to support ongoing capital investment activity |
(3 | ) | ||
| Other |
(1 | ) | ||
| Contribution to consolidated net income – 2020 |
$ 59 | |||
Florida Electric Utility’s CAD contribution to consolidated net income increased $18 million to $79 million in Q1 2020, compared to $61 million in Q1 2019. Earnings increased due to higher base revenues as a result of favourable weather, customer growth and the in-service of solar generation projects. This increase was partially offset by higher depreciation expense and higher interest expense as a result of higher capital investments.
The impact of the change in the foreign exchange rate increased Q1 2020 CAD earnings by $1 million.
Operating Revenues – Regulated Electric
Electric revenues increased $9 million to $421 million in Q1 2020 compared to $412 million in Q1 2019. Revenues increased due to higher base revenues related to favourable weather, customer growth and the in-service of solar generation projects, partially offset by lower clause revenues. A significant portion of the weather impact occurred during the last half of March 2020 resulting in an increase in unbilled revenues in Q1 2020, compared to Q1 2019. While operating revenues include both billed and unbilled
21
Table of Contents
revenues, Q1 2020 electric sales volumes, in the table below, do not reflect this increase as they are calculated based on billed hours only.
Electric revenues and sales volumes are summarized in the following tables by customer class:
| Q1 Electric Revenues millions of US dollars |
||||||||
| 2020 | 2019 | |||||||
| Residential |
$ | 205 | $ | 206 | ||||
| Commercial |
125 | 120 | ||||||
| Industrial |
37 | 34 | ||||||
| Other (1) |
54 | 52 | ||||||
| Total |
$ | 421 | $ | 412 | ||||
(1) Other includes sales to public authorities, off-system sales to other utilities, unbilled revenues and regulatory deferrals related to clauses.
| Q1 Electric Sales Volumes (1) Gigawatt hours (“GWh”) |
||||||||
| 2020 | 2019 | |||||||
| Residential |
1,880 | 1,939 | ||||||
| Commercial |
1,373 | 1,370 | ||||||
| Industrial |
497 | 462 | ||||||
| Other |
466 | 461 | ||||||
| Total |
4,216 | 4,232 | ||||||
(1) Electric sales volumes are calculated based on billed hours only. GWh related to unbilled revenues are excluded.
Regulated Fuel for Generation and Purchased Power
Regulated fuel for generation and purchased power decreased $9 million to $106 million in Q1 2020, compared to $115 million in Q1 2019, due to increased use of lower-cost natural gas and increased solar generation.
| Q1 Production Volumes GWh |
||||||||
| 2020 | 2019 | |||||||
| Natural gas |
4,105 | 3,768 | ||||||
| Solar |
234 | 152 | ||||||
| Coal |
181 | 308 | ||||||
| Purchased power |
36 | 95 | ||||||
| Total |
4,556 | 4,323 | ||||||
| Q1 Average Fuel Costs |
||||||||
| US dollars |
2020 | 2019 | ||||||
| Dollars per Megawatt hour (“MWh”) |
$ | 23 | $ | 27 | ||||
Average fuel cost per MWh decreased in Q1 2020, compared to Q1 2019, primarily due to increased use of lower-cost natural gas and zero fuel cost solar generation.
22
Table of Contents
| For the |
Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2020 | 2019 | ||||||
| Operating revenues – regulated electric |
$ | 458 | $ | 443 | ||||
| Regulated fuel for generation and purchased power (1) |
194 | 192 | ||||||
| Income from equity investments |
27 | 25 | ||||||
| Contribution to consolidated net income |
$ | 92 | $ | 96 | ||||
| Contribution to consolidated earnings per common share - basic |
$ | 0.38 | $ | 0.41 | ||||
| EBITDA |
$ | 193 | $ | 196 | ||||
(1) Regulated fuel for generation and purchased power includes NSPI’s FAM and fixed cost deferrals on the Condensed Consolidated Income Statement, however it is excluded in the segment overview.
Canadian Electric Utilities’ contribution is summarized in the following table:
| For the millions of Canadian dollars |
Three months ended March 31 |
|||||||
| 2020 | 2019 | |||||||
| NSPI |
$ | 65 | $ | 71 | ||||
| Equity investment in NSPML |
15 | 14 | ||||||
| Equity investment in LIL |
12 | 11 | ||||||
| Contribution to consolidated net income |
$ | 92 | $ | 96 | ||||
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 – 2019 |
$ | 96 | ||
| Increased operating revenues - see Operating Revenues - Regulated Electric below |
15 | |||
| Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below | (2 | ) | ||
| Increased FAM and fixed cost deferrals primarily due to the refund to customers of prior years’ over-recovery of fuel costs and reduced Maritime Link Assessment, partially offset by the over-recovery of current period fuel costs | (14 | ) | ||
| Increased OM&G expenses primarily due to higher storm recovery costs, higher costs for information technology, an increased allowance for doubtful accounts and contributions for community support related to the COVID-19 pandemic response | (7 | ) | ||
| Income from equity investments - see Electric Utilities contribution below |
2 | |||
| Other |
2 | |||
| Contribution to consolidated net income – 2020 |
$ | 92 | ||
Canadian Electric Utilities’ contribution to consolidated net income decreased in Q1 2020 due to lower contribution from NSPI. This decrease was mainly due to higher OM&G costs and lower sales volumes, primarily due to weather, partially offset by regulatory deferral timing. The timing of regulatory deferrals causes quarterly earnings volatility, while full year results are more predictable. Q1 2020 income from equity earnings was consistent with Q1 2019.
23
Table of Contents
NSPI
Operating Revenues – Regulated Electric
Operating revenues increased $15 million to $458 million in Q1 2020 compared to $443 million in Q1 2019. Revenues increased due to the reduced Maritime Link assessment included in 2019 rates to be returned to customers in subsequent years, and increased fuel-related pricing. This was partially offset by decreased sales volumes due to weather, decreased export sales and decreased other, industrial and commercial class sales volumes.
Electric revenues and sales volumes are summarized in the following tables by customer class:
| Q1 Electric Revenues |
| |||||||
| millions of Canadian dollars | ||||||||
| 2020 | 2019 | |||||||
| Residential |
$ | 264 | $ | 252 | ||||
| Commercial |
120 | 113 | ||||||
| Industrial |
56 | 55 | ||||||
| Other |
11 | 16 | ||||||
| Total |
$ | 451 | $ | 436 | ||||
| Q1 Electric Sales Volumes |
| |||||||
| GWh | ||||||||
| 2020 | 2019 | |||||||
| Residential |
1,560 | 1,621 | ||||||
| Commercial |
860 | 884 | ||||||
| Industrial |
588 | 597 | ||||||
| Other |
76 | 143 | ||||||
| Total |
3,084 | 3,245 | ||||||
Regulated Fuel for Generation and Purchased Power
Regulated fuel for generation and purchased power increased $2 million to $194 million in Q1 2020 compared to $192 million in Q1 2019, primarily due to a change in generation mix, partially offset by decreased commodity prices and decreased sales volumes.
| Q1 Production Volumes |
| |||||||
| GWh | ||||||||
| 2020 | 2019 | |||||||
| Coal |
1,595 | 1,846 | ||||||
| Natural Gas |
474 | 244 | ||||||
| Oil and petcoke |
282 | 315 | ||||||
| Purchased power – other |
119 | 141 | ||||||
| Total non-renewables |
2,470 | 2,546 | ||||||
| Wind and hydro |
341 | 371 | ||||||
| Purchased power – IPP |
335 | 370 | ||||||
| Purchased power – Community Feed-in Tariff program |
147 | 163 | ||||||
| Biomass |
11 | 15 | ||||||
| Total renewables |
834 | 919 | ||||||
| Total production volumes |
3,304 | 3,465 | ||||||
|
Q1 Average Fuel Costs |
| |||||||
| 2020 | 2019 | |||||||
| Dollars per MWh |
$ | 59 | $ | 55 | ||||
24
Table of Contents
Average fuel cost per MWh increased in Q1 2020, compared to Q1 2019, primarily due to a change in generation mix resulting from higher natural gas consumption partially offset by lower generation from solid fuel and a decrease in purchased power.
NSPI’s FAM regulatory liability balance decreased $3 million from $115 million at December 31, 2019 to $112 million at March 31, 2020 primarily due to the refund of prior years’ over-recovery of fuel costs and reduced Maritime Link assessment to customers. This was partially offset by over-recovery of current period fuel costs.
All amounts are reported in USD, unless otherwise stated.
On March 24, 2020, Emera completed the sale of Emera Maine. The Company continued to record depreciation on these assets through the transaction closing date, as the depreciation continued to be reflected in customer rates and was reflected in the carryover basis of the assets on close. Refer to the “Significant Items Affecting Q1 Earnings” and “Developments” sections for further details.
| For the | Three months ended March 31 | |||||||
| millions of US dollars (except per share amounts) | 2020 | 2019 | ||||||
| Operating revenues – regulated electric |
$ | 127 | $ | 136 | ||||
| Regulated fuel for generation and purchased power (1) |
50 | 49 | ||||||
| Adjusted contribution to consolidated net income |
$ | 15 | $ | 12 | ||||
| Adjusted contribution to consolidated net income - CAD |
$ | 20 | $ | 16 | ||||
| After-tax equity securities mark-to-market gain (loss) |
(2 | ) | 1 | |||||
| Contribution to consolidated net income |
$ | 13 | $ | 13 | ||||
| Contribution to consolidated net income – CAD |
$ | 17 | $ | 18 | ||||
| Adjusted contribution to consolidated earnings per common share – basic – CAD |
$ | 0.08 | $ | 0.07 | ||||
| Contribution to consolidated earnings per common share – basic – CAD |
0.07 | $ | 0.08 | |||||
| Net income weighted average foreign exchange rate – CAD/USD |
$ | 1.37 | $ | 1.33 | ||||
| Adjusted EBITDA |
$ | 40 | $ | 47 | ||||
| Adjusted EBITDA - CAD |
$ | 54 | $ | 62 | ||||
(1) Regulated fuel for generation and purchased power includes transmission pool expense.
Other Electric Utilities’ adjusted contribution is summarized in the following table:
| For the | Three months ended | |||||||
| millions of US dollars | March 31 | |||||||
| 2020 | 2019 | |||||||
| Emera Maine |
$ | 4 | $ | 8 | ||||
| ECI |
11 | 4 | ||||||
| Adjusted contribution to consolidated net income |
$ | 15 | $ | 12 | ||||
25
Table of Contents
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 – 2019 |
$ | 13 | ||
| Operating revenues - see Operating Revenues - Regulated Electric below |
(9 | ) | ||
| Regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below |
(1 | ) | ||
| Increased income tax recovery primarily due to the recognition of a previously deferred corporate income tax recovery related to the enactment of a lower corporate income tax rate in December 2018 at BLPC | 7 | |||
| Other |
3 | |||
| Contribution to consolidated net income – 2020 |
$ | 13 | ||
Excluding the change in mark-to-market, Other Electric Utilities’ CAD contribution to consolidated net income increased by $4 million to $20 million in Q1 2020, compared to $16 million in Q1 2019. ECI’s contribution increased due to recognition of a previously deferred corporate income tax recovery related to the enactment of a lower corporate income tax rate in December 2018 at BLPC. Emera Maine contribution decreased due to unseasonably warm weather and lower regional transmission revenues. The foreign exchange rate had minimal impact on Other Electric Utilities for the three months ended March 31, 2020.
Operating Revenues – Regulated Electric
Operating revenues decreased $9 million to $127 million in Q1 2020 compared to $136 million in Q1 2019, primarily due to unseasonably warm weather at Emera Maine and lower sales at GBPC due to the impact of Hurricane Dorian. These were partially offset by increased sales volumes at Domlec and BLPC and higher fuel revenue at BLPC.
Electric revenues are summarized in the following tables by customer class:
| Q1 Electric Revenues | ||||||||
| millions of US dollars | ||||||||
| 2020 | 2019 | |||||||
| Residential |
$ | 46 | $ | 51 | ||||
| Commercial |
59 | 60 | ||||||
| Industrial |
9 | 9 | ||||||
| Other (1) |
13 | 16 | ||||||
| Total |
$ | 127 | $ | 136 | ||||
(1) Other revenue includes amounts recognized relating to Emera Maine’s FERC transmission rate refunds and other transmission revenue adjustments.
| Q1 Electric Sales Volumes | ||||||||
| GWh | 2020 | 2019 | ||||||
| Residential |
331 | 339 | ||||||
| Commercial |
358 | 369 | ||||||
| Industrial |
122 | 112 | ||||||
| Other |
7 | 7 | ||||||
| Total |
818 | 827 | ||||||
26
Table of Contents
Regulated Fuel for Generation and Purchased Power
Regulated fuel for generation and purchased power increased $1 million to $50 million in Q1 2020, compared to $49 million in Q1 2019 due to higher hedged commodity prices at GBPC.
| Q1 Production Volumes | ||||||||
| GWh | ||||||||
| 2020 | 2019 | |||||||
| Oil |
311 | 319 | ||||||
| Hydro |
4 | 4 | ||||||
| Solar |
5 | 5 | ||||||
| Purchased power |
11 | 8 | ||||||
| Total |
331 | 336 | ||||||
| (1) Production volumes relate to ECI only. |
| |||||||
|
Q1 Average Fuel Costs |
||||||||
| US dollars |
2020 | 2019 | ||||||
| Dollars per MWh |
$ | 122 | $ | 116 | ||||
(2) Average fuel costs relate to ECI only.
Average fuel cost per MWh increased in Q1 2020, compared to Q1 2019, as a result of usage of higher cost fuel and volatility in fuel market negatively impacting hedged fuel at GBPC.
Gas Utilities and Infrastructure
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended | |||||||
| millions of US dollars (except per share amounts) | March 31 | |||||||
| 2020 | 2019 | |||||||
| Operating revenues – regulated gas (1) |
$ | 250 | $ | 269 | ||||
| Operating revenues – non-regulated |
3 | 3 | ||||||
| Total operating revenue |
253 | 272 | ||||||
| Regulated cost of natural gas |
81 | 103 | ||||||
| Income from equity investments |
3 | 5 | ||||||
| Contribution to consolidated net income |
$ | 53 | $ | 51 | ||||
| Contribution to consolidated net income – CAD |
$ | 70 | $ | 67 | ||||
| Contribution to consolidated earnings per common share – basic - CAD |
$ | 0.29 | $ | 0.28 | ||||
| Net income weighted average foreign exchange rate – CAD/USD |
$ | 1.33 | $ | 1.33 | ||||
| EBITDA |
$ | 103 | $ | 102 | ||||
| EBITDA – CAD |
$ | 137 | $ | 135 | ||||
(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2019 – $11 million), however, it is excluded from the gas revenues analysis below.
Gas Utilities and Infrastructure’s contribution is summarized in the following table:
| For the | Three months ended | |||||||
| millions of US dollars | March 31 | |||||||
| 2020 | 2019 | |||||||
| PGS |
$ | 18 | $ | 18 | ||||
| NMGC |
23 | 23 | ||||||
| Other |
12 | 10 | ||||||
| Contribution to consolidated net income |
$ | 53 | $ | 51 | ||||
27
Table of Contents
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 – 2019 |
$ | 51 | ||
| Decreased gas operating revenues—see Operating Revenues—Regulated Gas below |
(19 | ) | ||
| Decreased cost of natural gas sold—see Regulated Cost of Natural Gas below |
22 | |||
| Increased OM&G expenses due to lower capitalized construction overheads at NMGC related to capital project timing, and increased labour and contractor costs at PGS as a result of its growing distribution system | (3 | ) | ||
| Other |
2 | |||
| Contribution to consolidated net income – 2020 |
$ | 53 | ||
Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $3 million to $70 million in Q1 2020 compared to $67 million in Q1 2019. Earnings from PGS and NMGC were consistent quarter-over-quarter as customer growth, higher return on investment in Cast Iron/Bare Steel replacement rider at PGS and lower NMGC depreciation rates were offset by unfavourable weather at NMGC, higher OM&G expenses, and higher depreciation at PGS.
The foreign exchange rate had minimal impact for the three months ended March 31, 2020.
Operating Revenues – Regulated Gas
Operating revenues decreased $19 million to $250 million in Q1 2020 compared to $269 million in Q1 2019. This decrease resulted from lower clause-related revenues at PGS and NMGC, unfavourable weather in New Mexico and lower off-system sales at PGS, partially offset by customer growth at PGS.
Gas revenues and sales volumes are summarized in the following tables by customer class:
| Q1 Gas Revenues | ||||||||
| millions of US dollars | ||||||||
| 2020 | 2019 | |||||||
| Residential |
$ | 126 | $ | 142 | ||||
| Commercial |
67 | 73 | ||||||
| Industrial (1) |
10 | 9 | ||||||
| Other (2) |
36 | 34 | ||||||
| Total (3) |
$ | 239 | $ | 258 | ||||
(1) Industrial includes sales to power generation customers.
(2) Other includes off-system sales to other utilities and various other items.
(3) Excludes $11 million of finance income from Brunswick Pipeline (2019 – $11 million).
| Q1 Gas Volumes | ||||||||
| Therms (millions) | ||||||||
| 2020 | 2019 | |||||||
| Residential |
172 | 175 | ||||||
| Commercial |
251 | 263 | ||||||
| Industrial |
387 | 337 | ||||||
| Other |
97 | 61 | ||||||
| Total |
907 | 836 | ||||||
Regulated Cost of Natural Gas
Regulated cost of natural gas decreased $22 million to $81 million in Q1 2020, compared to $103 million in Q1 2019, due to lower commodity costs at PGS and NMGC.
28
Table of Contents
Gas sales by type are summarized in the following table:
| Q1 Gas Volumes by Type | ||||||||
| Therms (millions) | ||||||||
| 2020 | 2019 | |||||||
| System supply |
275 | 268 | ||||||
| Transportation |
632 | 568 | ||||||
| Total |
907 | 836 | ||||||
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2020 | 2019 | ||||||
| Marketing and trading margin (1) (2) |
$ | 41 | $ | 54 | ||||
| Electricity and capacity sales (3) |
4 | 116 | ||||||
| Other non-regulated operating revenue |
5 | 10 | ||||||
| Total operating revenues – non-regulated |
50 | 180 | ||||||
| Intercompany revenue (4) |
3 | 9 | ||||||
|
Non-regulated fuel for generation and purchased power (5) |
4 | 64 | ||||||
| Income from equity investments |
9 | 8 | ||||||
| Interest expense, net |
82 | 93 | ||||||
| Adjusted contribution to consolidated net income (loss) |
$ | (68 | ) | $ | (16 | ) | ||
| Gain on sale and impairment charges, net of tax |
298 | - | ||||||
| After-tax derivative mark-to-market gain |
$ | 35 | $ | 86 | ||||
| Contribution to consolidated net income |
$ | 265 | $ | 70 | ||||
| Adjusted contribution to consolidated earnings per common share – basic |
$ | (0.28 | ) | $ | (0.07 | ) | ||
| Contribution to consolidated earnings per common share – basic |
$ | 1.08 | $ | 0.30 | ||||
| Adjusted EBITDA |
$ | 17 | $ | 90 | ||||
(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a pre-tax mark-to-market gain of $63 million for the quarter ended March 31, 2020 (2019 - $122 million gain).
(3) Electricity and capacity sales exclude a pre-tax mark-to-market loss of nil for the quarter ended March 31, 2020 (2019 - $2 million gain).
(4) Intercompany revenue consists of interest from Brunswick Pipeline and M&NP.
(5) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market loss of $2 million for the quarter ended March 31, 2020 (2019 - $2 million loss).
Other’s adjusted contribution is summarized in the following table:
| For the | Three months ended | |||||||
| millions of Canadian dollars | March 31 | |||||||
| 2020 | 2019 | |||||||
| Emera Energy |
$ | 21 | $ | 52 | ||||
| Corporate |
(89 | ) | (67 | ) | ||||
| Other |
- | (1 | ) | |||||
| Adjusted contribution to consolidated net income (loss) |
$ | (68 | ) | $ | (16 | ) | ||
29
Table of Contents
Net Income
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | |||
| millions of Canadian dollars | March 31 | |||
| Contribution to consolidated net income – 2019 |
$ | 70 | ||
| Gain on sale and impairment charges, net of tax |
298 | |||
| Decreased mark-to-market gain, net of tax, primarily due to higher amortization of gas transportation assets in 2020, larger reversal of mark-to-market losses in 2019 and losses related to foreign exchange cash flow hedges entered in Q1 2020 to manage foreign exchange earnings exposure, partially offset by changes in existing positions on gas contracts | (53 | ) | ||
| Impact of 2019 sale of NEGG and Bayside Power, net of tax | (24 | ) | ||
| Decreased marketing and trading margin - see Emera Energy | (13 | ) | ||
| Revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, including $2 million recovery related to mark-to-market | (11 | ) | ||
| Decrease in other income due to 2019 gain on sale of property in Florida, net of tax | (10 | ) | ||
| Increased OM&G primarily due to performance based compensation, partially offset by lower expenses due to the sale of Emera Utility Services assets in 2019 | (5 | ) | ||
| Increased income tax recovery primarily due to increased losses before provision for income taxes and the impact of effective state tax rates | 13 | |||
| Contribution to consolidated net income – 2020 |
$ | 265 | ||
Excluding the decrease in mark-to-market gain, the gain on sale and impairment charges recognized on certain other assets, Other’s contribution to consolidated net income decreased $52 million to a loss of $68 million for Q1 2020, compared to Q1 2019. This was primarily due to the impact of the sale of NEGG and Bayside Power in 2019, decreased marketing and trading margin, revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, the 2019 sale of property in Florida and increased OM&G in Corporate. These were partially offset by lower income taxes due to lower earnings and the impact of effective state tax rates.
Emera Energy
Marketing and trading margin decreased $13 million to $41 million in Q1 2020 compared to $54 million in Q1 2019 as a result of less favourable market conditions, specifically warmer than normal weather, lower natural gas prices and low volatility when compared to 2019.
30
Table of Contents
LIQUIDITY AND CAPITAL RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate 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 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, and maintain their credit metrics.
In Q1 2020, the impact of the COVID-19 pandemic and resulting government measures to address this pandemic have resulted in economic slowdowns in all markets served by Emera. Currently, COVID-19 has not had a material financial impact on the Company. Refer to the “Outlook” section for discussion by utility. The impact of COVID-19 may result in decreased cash flow from operations due to the potential of lower sales and slower collection of accounts receivable. The extent of the future impact of COVID-19 on the Company’s operating cash flow cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. The Company currently expects to continue to have adequate liquidity given its cash position, existing bank facilities, and access to capital, but will continue to monitor the impact of COVID-19 on future cash flows.
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has a $7.5 billion capital investment plan over the 2020-to-2022 period and the potential for additional capital opportunities of $200 million to $500 million over the forecast period. This plan includes significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. Capital expenditures at the regulated utilities are subject to regulatory approval. The extent of the future impact of COVID-19 on the profile of the Company’s capital plan cannot be predicted at this time due to reasons discussed earlier. The Company possesses flexibility with respect to its capital investment plan and will continue to monitor current events and related impacts of COVID-19.
Emera plans to use cash from operations, debt raised at the utilities and proceeds from the Emera Maine sale, to support normal operations, repayment of existing debt and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital investment plan will predominantly be funded in the equity capital markets through the dividend reinvestment plan and the issuance of common and preferred equity. The Company’s future access to capital may be impacted by possible continued COVID-19 related market disruptions. Refer to the “Risk Management and Financial Instruments” section for updated risk disclosure.
As at March 31, 2020, the Company was holding a cash balance of $1.6 billion. Emera also has credit facilities with varying maturities that cumulatively provide $3.8 billion of credit, with approximately $1.3 billion undrawn and available at March 31, 2020. Refer to the “Debt Management” section below for further details. Refer to notes 19 and 20 in the condensed consolidated financial statements for additional information regarding the credit facilities.
As at March 31, 2020, Emera had $155 million CAD ($109 million USD) in receivables related to the expected refund of alternative minimum tax credit carryforwards. Under the provisions of the United States Coronavirus Aid, Relief, and Economic Security (CARES) Act, Emera’s US businesses are allowed to secure their remaining AMT credits in their 2019 filings. The Company has filed for this refund and expects to receive it in 2020.
31
Table of Contents
Consolidated Cash Flow Highlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 2020 and 2019 include:
| millions of Canadian dollars | 2020 | 2019 | Change | |||||||||||||||||
| Cash, cash equivalents, restricted cash and assets held for sale, beginning of period |
$ | 274 | $ | 372 | $ | (98 | ) | |||||||||||||
| Provided by (used in): |
||||||||||||||||||||
| Operating cash flow before change in working capital |
502 | 418 | 84 | |||||||||||||||||
| Change in working capital |
(74 | ) | (16 | ) | (58 | ) | ||||||||||||||
| Operating activities |
428 | 402 | 26 | |||||||||||||||||
| Investing activities |
746 | 298 | 448 | |||||||||||||||||
| Financing activities |
165 | (35 | ) | 200 | ||||||||||||||||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash included in assets held for sale | (6 | ) | (5 | ) | (1 | ) | ||||||||||||||
| Cash, cash equivalents, and restricted cash, end of period |
$ | 1,607 | $ | 1,032 | $ | 575 | ||||||||||||||
Cash Flow from Operating Activities
Net cash provided by operating activities increased $26 million to $428 million for the three months ended March 31, 2020, compared to $402 million for the same period in 2019.
Cash from operations before changes in working capital increased $84 million. The increase was primarily due to higher over-recovery from customers on clause related costs at Tampa Electric.
Changes in working capital decreased operating cash flows by $58 million. The decrease was due to unfavourable changes in cash collateral at Emera Energy and NSPI. This was partially offset by timing of accounts payable at NSPI and Tampa Electric, and decreased fuel inventory at NSPI.
Cash Flow used in Investing Activities
Net cash provided by investing activities increased $448 million to $746 million for the three months ended March 31, 2020, compared to $298 million for the same period in 2019. In 2020, Emera received proceeds of $1.4 billion on the sale of Emera Maine compared to proceeds of $861 million on dispositions in 2019, primarily from the sale of the NEGG and Bayside facilities. This increase in proceeds was partially offset by higher capital expenditures in Q1 2020.
Capital expenditures for the three months ended March 31, 2020, including AFUDC, were $663 million compared to $561 million for the same period in 2019. Details of the 2020 capital spend by segment are shown below:
| • | $356 million - Florida Electric Utility (2019 – $306 million); |
| • | $93 million - Canadian Electric Utilities (2019 – $71 million); |
| • | $46 million - Other Electric Utilities (2019 – $38 million); |
| • | $167 million - Gas Utilities and Infrastructure (2019 – $94 million); and |
| • | $1 million - Other (2019 – $52 million). |
32
Table of Contents
Cash Flow from Financing Activities
Net cash provided by financing activities increased $200 million to $165 million for the three months ended March 31, 2020, compared to net cash used in financing activities of $35 million for the same period in 2019. The increase was due to proceeds from committed credit facilities at Tampa Electric, the 2019 net repayment of Emera’s committed credit facilities and issuance of common shares under Emera’s ATM program. These were partially offset by repayment of debt at TECO Finance.
As at March 31, 2020, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:
| millions of Canadian dollars | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total | |||||||||||||||||||||
| Long-term debt principal |
$ | 83 | $ | 1,821 | $ | 449 | $ | 833 | $ | 1,065 | $ | 10,644 | $ | 14,895 | ||||||||||||||
| Interest payment obligations (1) |
617 | 638 | 602 | 576 | 556 | 7,141 | 10,130 | |||||||||||||||||||||
| Purchased power (2) |
197 | 218 | 247 | 268 | 282 | 1,993 | 3,205 | |||||||||||||||||||||
| Transportation (3) |
423 | 429 | 374 | 312 | 288 | 2,999 | 4,825 | |||||||||||||||||||||
| Pension and post-retirement obligations (4) |
20 | 33 | 29 | 29 | 98 | 261 | 470 | |||||||||||||||||||||
| Capital projects (5) |
414 | 135 | 111 | 94 | - | - | 754 | |||||||||||||||||||||
| Fuel, gas supply and storage |
363 | 133 | 28 | 5 | 1 | - | 530 | |||||||||||||||||||||
| Asset retirement obligations |
2 | 35 | 1 | 1 | 1 | 366 | 406 | |||||||||||||||||||||
| Long-term service agreements (6) |
62 | 23 | 22 | 19 | 19 | 71 | 216 | |||||||||||||||||||||
| Equity investment commitments (7) |
- | 240 | - | - | - | - | 240 | |||||||||||||||||||||
| Leases and other (8) |
13 | 20 | 20 | 18 | 19 | 114 | 204 | |||||||||||||||||||||
| Demand side management |
24 | 41 | 43 | - | - | - | 108 | |||||||||||||||||||||
| Long-term payable |
4 | 5 | 5 | 5 | - | - | 19 | |||||||||||||||||||||
| $ | 2,222 | $ | 3,771 | $ | 1,931 | $ | 2,160 | $ | 2,329 | $ | 23,589 | $ | 36,002 | |||||||||||||||
(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, 2020, 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) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
(5) Includes $485 million of commitments related to Tampa Electric’s solar, Big Bend Power Station modernization and AMI projects.
(6) 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.
(7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership.
(8) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.
On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor has declared force majeure under various project contracts, including formal notification to NSPML. Due to the unpredictable nature of the COVID-19 pandemic, Nalcor is currently unable to provide an updated completion schedule for Muskrat Falls or LIL until there is greater certainty. Nalcor has expressed its desire to resume work at site as soon as it is safe to do so for its employees, contractors and associated communities.
NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls. NSPML anticipates making an application with the UARB in 2020 with respect to recovery of 2021 costs.
33
Table of Contents
NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years from its January 15, 2018 in-service date. The UARB approved payment for 2020 is $145 million subject to a $10 million holdback and as at March 31, 2020, $26 million has been paid. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include the $145 million approved for 2020 and estimated amounts of $164 million and $162 million for 2021 and 2022, respectively. These estimated amounts are subject to review and approval by the UARB. The timing and amounts payable to NSPML for the remainder of the 37-year commitment period are dependent on regulatory filings with the UARB.
Emera has committed to obtain certain transmission rights for Nalcor Energy, if requested, to enable them to transmit energy which is not otherwise used in Newfoundland or Nova Scotia. This energy could be transmitted from Nova Scotia to New England energy markets beginning at first commercial power of the Muskrat Falls hydroelectric generating facility and related transmission assets when Nalcor commences delivery of the NS Block, and continuing for 50 years. As transmission rights are contracted, Emera includes the obligations within “Leases and other” in the above table.
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $3.8 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 Inc. – Unsecured committed revolving credit facility |
June 2024 | $ | 900 | $ | 453 | $ | 447 | |||||||||||||||||||||
| Emera Inc. – Unsecured non-revolving facility |
December 2020 | 400 | 400 | - | ||||||||||||||||||||||||
| TECO Finance, Inc. – in USD – Unsecured committed revolving credit facility |
March 2022 | 400 | 360 | 40 | ||||||||||||||||||||||||
| TECO Finance, Inc. – in USD – Unsecured non-revolving facility |
July 2020 | 500 | 500 | - | ||||||||||||||||||||||||
| NSPI – Unsecured committed revolving credit facility |
October 2024 | 600 | 398 | 202 | ||||||||||||||||||||||||
| TEC – in USD – Unsecured committed revolving credit facility (1) |
March 2022 | 400 | 31 | 369 | ||||||||||||||||||||||||
| TEC – in USD – Accounts receivable collateralized borrowing facility (1) |
March 2021 | 150 | 74 | 76 | ||||||||||||||||||||||||
| TEC – in USD – Unsecured non-revolving facility (1) |
February 2021 | 300 | 300 | - | ||||||||||||||||||||||||
| NMGC – in USD – Unsecured committed revolving credit facility |
March 2022 | 125 | 1 | 124 | ||||||||||||||||||||||||
| Other – in USD – Unsecured committed revolving credit facilities |
Various | 32 | 22 | 10 | ||||||||||||||||||||||||
(1) These facilities are available for use by Tampa Electric and PGS. At March 31, 2020, Tampa Electric had utilized $313 million USD and PGS had utilized $92 million USD of the facilities.
Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly, and the Company is in compliance with its covenant requirements as at March 31, 2020.
34
Table of Contents
Recent significant financing activities for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On February 6, 2020, TEC entered into a $300 million USD non-revolving credit agreement with a maturity date of February 4, 2021. The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at LIBOR, prime rate or the federal funds rate, plus a margin.
Canadian Electric Utilities
On April 24, 2020, NSPI completed a $300 million 30-year unsecured notes issuance. The notes bear interest at a rate of 3.31 per cent and have a maturity date of April 25, 2050.
Other Electric Utilities
On February 19, 2020, BLPC received its first advance of $40 million BBD ($20 million USD) on a $110 million BBD ($55 million USD) non-revolving term loan. The loan bears interest at a rate of 2.05 per cent and has a 5-year term.
Other
On April 3, 2020, TECO Energy/Finance repaid $200 million USD of its $500 million Non-Revolving Term Loan that is due to mature on July 3, 2020. This partial repayment was made from proceeds of the Emera Maine sale.
On March 13, 2020, TECO Finance repaid a $300 million USD note upon maturity. The note was repaid using existing credit facilities.
On February 28, 2020, TECO Energy/Finance extended the maturity date of its $500 million USD credit facility from March 5, 2020 to July 3, 2020. There were no other significant changes in commercial terms from the prior agreement.
On March 24, 2020, S&P changed its issuer rating for Emera and TECO to BBB from BBB+ and at the same time changed the outlook on both to stable from negative. S&P also affirmed its BBB+ issuer ratings for TEC and NSPI and changed the outlook on both to stable from negative.
Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2019 audited annual consolidated financial statements, with an update as noted below:
The Company has standby letters of credit and surety bonds in the amount of $74 million USD (December 31, 2019—$82 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.
The Company is in the process of issuing a guarantee of up to $60 million USD relating to outstanding notes of GBPC. The guarantee will reduce to no more than $35 million USD upon repayment of certain notes that are due May 22, 2020.
35
Table of Contents
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 to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-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 assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $28 million for the three months ended March 31, 2020 (2019—$27 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. |
Refer to the “Business Overview and Outlook—Canadian Electric Utilities—ENL” and “Contractual Obligations” sections for further details.
| • | Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $8 million for the three months ended March 31, 2020 (2019 - $18 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2020 and at December 31, 2019.
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 2019 annual MD&A, except for the following:
Public Health Risk
An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19 pandemic, or a fear of any of the foregoing, could adversely impact the Company, including by causing operating, supply chain and project development delays and disruptions, labour shortages and shutdowns (including as a result of government regulation and prevention measures), which could have a negative impact on the Company’s operations.
Any adverse changes in general economic and market conditions arising as a result of a public health threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which could result in a material adverse effect on the Company’s business.
36
Table of Contents
The extent of the evolving COVID-19 pandemic and its future impact on the Company is uncertain. The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat. The Company’s top priority continues to be the health and safety of its customers and employees. In Q1 2020, Emera activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.
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 millions of Canadian dollars |
March 31 2020 |
December 31 2019 |
||||||
| Derivative instrument liabilities (current and long-term liabilities) |
$ | (3 | ) | $ | (1 | ) | ||
| Net derivative instrument liabilities |
$ | (3 | ) | $ | (1 | ) | ||
Hedging Impact Recognized in Net Income
The Company recognized losses related to the effective portion of hedging relationships under the following categories:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Operating revenues – regulated |
$ | (1 | ) | $ | (2 | ) | ||
| Effective net losses |
$ | (1 | ) | $ | (2 | ) | ||
The effectiveness 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 | 2020 | 2019 | ||||||
| Derivative instrument assets (current and other assets) |
$ | 49 | $ | 28 | ||||
| Regulatory assets (current and other assets) |
131 | 80 | ||||||
| Derivative instrument liabilities (current and long-term liabilities) |
(131 | ) | (78 | ) | ||||
| Regulatory liabilities (current and long-term liabilities) |
(56 | ) | (42 | ) | ||||
| Net liability |
$ | (7 | ) | $ | (12 | ) | ||
37
Table of Contents
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 | 2020 | 2019 | ||||||
| Regulated fuel for generation and purchased power (1) |
$ | (5 | ) | $ | 4 | |||
| Net gains (losses) |
$ | (5 | ) | $ | 4 | |||
(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 | 2020 | 2019 | ||||||
| Derivative instrument assets (current and other assets) |
$ | 64 | $ | 58 | ||||
| Derivative instrument liabilities (current and long-term liabilities) |
(183 | ) | (291 | ) | ||||
| Net derivative instrument liability |
$ | (119 | ) | $ | (233 | ) | ||
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 | 2020 | 2019 | ||||||
| Operating revenues – non-regulated |
$ | 212 | $ | 149 | ||||
|
Non-regulated fuel for generation and purchased power |
(4 | ) | (2 | ) | ||||
| Net gains |
$ | 208 | $ | 147 | ||||
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 | 2020 | 2019 | ||||||
| Derivative instrument assets (current and other assets) |
$ | 2 | $ | 1 | ||||
| Derivative instrument liabilities (current and long-term liabilities) |
(11 | ) | - | |||||
| Net derivative instrument assets (liabilities) |
$ | (9 | ) | $ | 1 | |||
Other Derivatives Recognized in Net Income
The Company recognized in net income the following gains (losses) related to other derivatives:
| For the millions of Canadian dollars |
Three months ended March 31 |
|||||||
| 2020 | 2019 | |||||||
| Operating, maintenance and general |
$ | (1 | ) | $ | 14 | |||
| Other income (expense) |
(10 | ) | - | |||||
| Total gains (losses) |
$ | (11 | ) | $ | 14 | |||
38
Table of Contents
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 Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). 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, 2020, 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, 2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. 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. 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, with any adjustments recognized in income in the year they arise. Management has analyzed the impact of the COVID-19 pandemic on its estimates and judgements and concluded that no material adjustments are required at March 31, 2020.
Goodwill Impairment Assessments
Management considered whether the potential impacts of the COVID-19 pandemic on future earnings required testing for goodwill impairment in Q1 2020 and determined that it is more likely than not that the fair value of reporting units that include goodwill exceeded their respective carrying amounts as of March 31, 2020.
As of March 31, 2020, $6.3 billion of Emera’s goodwill was related to TECO Energy (Tampa Electric, PGS and NMGC reporting units). Given the significant excess of fair value over carrying amounts calculated for these reporting units as of the last quantitative test performed in Q4 2019, management does not expect the COVID-19 pandemic to have an impact on the goodwill associated with these reporting units.
As of March 31, 2020, $76 million of Emera’s goodwill was related to GBPC. The calculated goodwill for this reporting unit is more sensitive to changes in forecasted future earnings. Adverse impacts to earnings in the future as a result of COVID-19 could cause impairment, however, the impact of COVID-19 on future earnings cannot be reasonably determined or estimated at this time. No impairment has been recorded in Q1 2020.
39
Table of Contents
Long-Lived Assets Impairment Assessments
Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at March 31, 2020, there are no indications of impairment of Emera’s long-lived assets. The impact of COVID-19 could cause the Company to impair long-lived assets in the future, however, there is currently no indication that future cash flows would be impacted to a point where the Company’s long-lived assets would not be recoverable.
Impairment charges of $22 million ($23 million after tax) were recognized on certain assets in Q1 2020.
Pension and Other Post-Retirement Employee Benefits
The COVID-19 pandemic could impact key actuarial assumptions used to account for employee post-retirement benefits including the anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation, benefit costs and annual pension funding requirements. Fluctuations in actual equity market returns and changes in interest rates as a result of the COVID-19 pandemic may also result in changes to pension costs and funding in future periods.
The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these estimates.
CHANGES IN ACCOUNTING POLICIES AND PRACTICES
The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2020, are described as follows:
Measurement of Credit Losses on Financial Instruments
The Company adopted Accounting Standard Update (“ASU”) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. The adoption of the standard resulted in a $7 million decrease to retained earnings in the condensed consolidated financial statements as of January 1, 2020.
40
Table of Contents
Future Accounting Pronouncements
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”). The ASUs that have been issued, but are not yet effective, are consistent with those disclosed in the Company’s 2019 audited consolidated financial statements, with updates noted below.
Facilitation of the Effects of Reference Rate Reform on Financial Reporting
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The standard provides optional expedients and exceptions for applying USGAAP to contract modifications and hedging relationships that reference LIBOR or another rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The Company is currently evaluating the impact of adoption of the standard, if elected, on its consolidated financial statements.
| For the quarter ended millions of dollars |
Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | ||||||||||||||||||||||||
| (except per share amounts) | 2020 | 2019 | 2019 | 2019 | 2019 | 2018 | 2018 | 2018 | ||||||||||||||||||||||||
| Operating revenues |
$ | 1,637 | $ | 1,616 | $ | 1,299 | $ | 1,378 | $ | 1,818 | $ | 1,799 | $ | 1,495 | $ | 1,423 | ||||||||||||||||
| Net income attributable to common shareholders |
523 | 193 | 55 | 103 | 312 | 231 | 118 | 90 | ||||||||||||||||||||||||
| Adjusted net income attributable to common shareholders |
193 | 145 | 122 | 130 | 224 | 167 | 191 | 111 | ||||||||||||||||||||||||
| Earnings per common share - basic |
2.14 | 0.79 | 0.23 | 0.43 | 1.32 | 0.98 | 0.51 | 0.38 | ||||||||||||||||||||||||
| Earnings per common share - diluted |
2.13 | 0.80 | 0.23 | 0.43 | 1.32 | 0.98 | 0.50 | 0.38 | ||||||||||||||||||||||||
| Adjusted earnings per common share - basic |
0.79 | 0.60 | 0.51 | 0.54 | 0.95 | 0.71 | 0.82 | 0.48 | ||||||||||||||||||||||||
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 demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the “Significant Items Affecting Earnings” section. In 2020, quarterly results may also be affected by the impact of the COVID-19 pandemic. Refer to the “Business Overview and Outlook” section for further details.
41
Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
March 31, 2020 and 2019
42
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2020 | 2019 | ||||||
| Operating revenues |
||||||||
| Regulated electric |
$ | 1,194 | $ | 1,169 | ||||
| Regulated gas |
331 | 352 | ||||||
| Non-regulated |
112 | 297 | ||||||
| Total operating revenues (note 6) |
1,637 | 1,818 | ||||||
| Operating expenses |
||||||||
| Regulated fuel for generation and purchased power |
410 | 401 | ||||||
| Regulated cost of natural gas |
109 | 136 | ||||||
| Non-regulated fuel for generation and purchased power |
4 | 64 | ||||||
| Operating, maintenance and general |
378 | 366 | ||||||
| Provincial, state and municipal taxes |
84 | 85 | ||||||
| Depreciation and amortization |
231 | 224 | ||||||
| Total operating expenses |
1,216 | 1,276 | ||||||
| Income from operations |
421 | 542 | ||||||
| Income from equity investments (note 7) |
41 | 40 | ||||||
| Other income (expenses), net (note 8) |
563 | 13 | ||||||
| Interest expense, net |
184 | 189 | ||||||
| Income before provision for income taxes |
841 | 406 | ||||||
| Income tax expense (note 9) |
306 | 82 | ||||||
| Net income |
535 | 324 | ||||||
|
Non-controlling interest in subsidiaries |
1 | 1 | ||||||
| Preferred stock dividends |
11 | 11 | ||||||
| Net income attributable to common shareholders |
$ | 523 | $ | 312 | ||||
| Weighted average shares of common stock outstanding (in millions) (note 11) |
||||||||
| Basic |
244.7 | 236.4 | ||||||
| Diluted |
245.2 | 237.0 | ||||||
| Earnings per common share (note 11) |
||||||||
| Basic |
$ | 2.14 | $ | 1.32 | ||||
| Diluted |
$ | 2.13 | $ | 1.32 | ||||
| Dividends per common share declared |
$ | 0.6125 | $ | 0.5875 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
43
Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Net income |
$ | 535 | $ | 324 | ||||
| Other comprehensive income (loss), net of tax |
||||||||
| Foreign currency translation adjustment (1) |
761 | (163 | ) | |||||
| Unrealized gains (losses) on net investment hedges (2)(3) |
(141 | ) | 34 | |||||
| Cash flow hedges |
||||||||
| Net derivative gains |
(3 | ) | 2 | |||||
| Less: reclassification adjustment for gains included in income |
1 | 2 | ||||||
| Net effects of cash flow hedges |
(2 | ) | 4 | |||||
| Net change in unrecognized pension and post-retirement benefit obligation (4) |
(5 | ) | 4 | |||||
| Other comprehensive income (loss) (5) |
613 | (121 | ) | |||||
| Comprehensive income |
1,148 | 203 | ||||||
| Comprehensive income attributable to non-controlling interest |
2 | 1 | ||||||
| Comprehensive Income of Emera Incorporated |
$ | 1,146 | $ | 202 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
1) Net of tax expense of $13 million (2019 - nil) for the three months ended March 31, 2020.
2) The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations.
3) Net of tax recovery of $1 million (2019 - nil) for the three months ended March 31, 2020.
4) Net of tax expense of nil (2019 - $1 million expense) for the three months ended March 31, 2020.
5) Net of tax expense of $12 million (2019 - $1 million tax expense) for the three months ended March 31, 2020.
44
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at millions of Canadian dollars |
March 31 2020 |
December 31 2019 |
||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 1,553 | $ | 222 | ||||
| Restricted cash (note 23) |
54 | 51 | ||||||
| Inventory |
431 | 467 | ||||||
| Derivative instruments (notes 13 and 14) |
68 | 54 | ||||||
| Regulatory assets (note 15) |
156 | 121 | ||||||
| Receivables and other current assets (note 17) |
1,605 | 1,486 | ||||||
| Assets held for sale (note 4) |
- | 85 | ||||||
| 3,867 | 2,486 | |||||||
| Property, plant and equipment, net of accumulated depreciation and amortization of $8,927 and $8,295, respectively | 19,846 | 18,167 | ||||||
| Other assets |
||||||||
| Deferred income taxes |
144 | 186 | ||||||
| Derivative instruments (notes 13 and 14) |
47 | 33 | ||||||
| Regulatory assets (note 15) |
1,464 | 1,431 | ||||||
| Net investment in direct financing lease |
477 | 473 | ||||||
| Investments subject to significant influence (note 7) |
1,336 | 1,312 | ||||||
| Goodwill |
6,373 | 5,835 | ||||||
| Other long-term assets |
302 | 300 | ||||||
| Assets held for sale (note 4) |
- | 1,619 | ||||||
| 10,143 | 11,189 | |||||||
| Total assets |
$ | 33,856 | $ | 31,842 | ||||
45
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited) – Continued
| As at millions of Canadian dollars |
March 31 2020 |
December 31 2019 |
||||||
| Liabilities and Equity |
||||||||
| Current liabilities |
||||||||
| Short-term debt (note 19) |
$ | 2,211 | $ | 1,537 | ||||
| Current portion of long-term debt (note 20) |
379 | 501 | ||||||
| Accounts payable |
1,022 | 1,118 | ||||||
| Derivative instruments (notes 13 and 14) |
215 | 268 | ||||||
| Regulatory liabilities (note 15) |
310 | 295 | ||||||
| Other current liabilities |
486 | 333 | ||||||
| Liabilities associated with assets held for sale (note 4) |
- | 114 | ||||||
| 4,623 | 4,166 | |||||||
| Long-term liabilities |
||||||||
| Long-term debt (note 20) |
14,398 | 13,679 | ||||||
| Deferred income taxes |
1,614 | 1,285 | ||||||
| Derivative instruments (notes 13 and 14) |
113 | 102 | ||||||
| Regulatory liabilities (note 15) |
2,088 | 1,886 | ||||||
| Pension and post-retirement liabilities (note 18) |
481 | 460 | ||||||
| Other long-term liabilities |
834 | 764 | ||||||
| Long-term liabilities associated with assets held for sale (note 4) |
- | 899 | ||||||
| 19,528 | 19,075 | |||||||
| Equity |
||||||||
| Common stock (note 10) |
6,340 | 6,216 | ||||||
| Cumulative preferred stock |
1,004 | 1,004 | ||||||
| Contributed surplus |
78 | 78 | ||||||
| Accumulated other comprehensive income (note 12) |
707 | 95 | ||||||
| Retained earnings |
1,540 | 1,173 | ||||||
| Total Emera Incorporated equity |
9,669 | 8,566 | ||||||
| Non-controlling interest in subsidiaries |
36 | 35 | ||||||
| Total equity |
9,705 | 8,601 | ||||||
| Total liabilities and equity |
$ | 33,856 | $ | 31,842 | ||||
Commitments and contingencies (note 21)
The accompanying notes are an integral part of these condensed consolidated financial statements.
Approved on behalf of the Board of Directors
|
“M. Jacqueline Sheppard” |
“Scott Balfour” | |
| Chair of the Board |
President and Chief Executive Officer | |
46
Emera Incorporated
Condensed Consolidated Statements of Cash Flows (Unaudited)
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Operating activities |
||||||||
| Net income |
$ | 535 | $ | 324 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
235 | 228 | ||||||
| Income from equity investments, net of dividends |
(19) | (22) | ||||||
| Allowance for equity funds used during construction |
(9) | (4) | ||||||
| Deferred income taxes, net |
352 | 68 | ||||||
| Net change in pension and post-retirement liabilities |
(6) | (3) | ||||||
| Regulated fuel adjustment mechanism |
(3) | (4) | ||||||
| Net change in fair value of derivative instruments |
(95) | (114) | ||||||
| Net change in regulatory assets and liabilities |
15 | (7) | ||||||
| Net change in capitalized transportation capacity |
62 | (25) | ||||||
| Gain on sale (excluding transaction costs) and impairment charges |
(582) | — | ||||||
| Other operating activities, net |
17 | (23) | ||||||
| Changes in non-cash working capital (note 22) |
(74) | (16) | ||||||
| Net cash provided by operating activities |
428 | 402 | ||||||
| Investing activities |
||||||||
| Proceeds from dispositions (note 4) |
1,403 | 861 | ||||||
| Additions to property, plant and equipment |
(654) | (557) | ||||||
| Other investing activities |
(3) | (6) | ||||||
| Net cash provided by investing activities |
746 | 298 | ||||||
| Financing activities |
||||||||
| Change in short-term debt, net |
156 | 188 | ||||||
| Proceeds from short-term debt with maturities greater than 90 days |
399 | — | ||||||
| Proceeds from long-term debt, net of issuance costs |
57 | — | ||||||
| Retirement of long-term debt |
(436) | (9) | ||||||
| Net borrowings (repayments) under committed credit facilities |
29 | (142) | ||||||
| Issuance of common stock, net of issuance costs |
77 | 32 | ||||||
| Dividends on common stock |
(104) | (90) | ||||||
| Dividends on preferred stock |
(11) | (11) | ||||||
| Other financing activities |
(2) | (3) | ||||||
| Net cash provided by (used in) financing activities |
165 | (35) | ||||||
| Effect of exchange rate changes on cash, cash equivalents, and restricted cash |
(6) | (5) | ||||||
| Net increase in cash, cash equivalents and restricted cash |
1,333 | 660 | ||||||
| Cash, cash equivalents, restricted cash and assets held for sale, beginning of period |
274 | 372 | ||||||
| Cash, cash equivalents and restricted cash, end of period |
$ | 1,607 | $ | 1,032 | ||||
| Cash, cash equivalents, and restricted cash consists of: |
||||||||
| Cash |
$ | 1,553 | $ | 332 | ||||
| Short-term investments |
— | 647 | ||||||
| Restricted cash |
54 | 53 | ||||||
| Cash, cash equivalents, and restricted cash |
$ | 1,607 | $ | 1,032 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
47
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| millions of Canadian dollars | Common Stock |
Preferred Stock |
Contributed Surplus |
Accumulated Other Comprehensive Income (Loss) (“AOCI”) |
Retained Earnings |
Non- Controlling Interest |
Total Equity |
|||||||||||||||||||||
| For the three months ended March 31, 2020 |
| |||||||||||||||||||||||||||
| Balance, December 31, 2019 |
$ | 6,216 | $ | 1,004 | $ | 78 | $ | 95 | $ | 1,173 | $ | 35 | $ | 8,601 | ||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 534 | 1 | 535 | |||||||||||||||||||||
| Other comprehensive income (loss), net of tax expense of $12 million | - | - | - | 612 | - | 1 | 613 | |||||||||||||||||||||
| Dividends declared on preferred stock (1) | - | - | - | - | (11) | - | (11) | |||||||||||||||||||||
| Dividends declared on common stock ($0.6125/share) | - | - | - | - | (149) | - | (149) | |||||||||||||||||||||
| Common stock issued under purchase plan | 48 | - | - | - | - | - | 48 | |||||||||||||||||||||
| Issuance of common stock, net of after-tax issuance costs | 58 | - | - | - | - | - | 58 | |||||||||||||||||||||
| Senior management stock options exercised | 17 | - | (1) | - | - | - | 16 | |||||||||||||||||||||
| Adoption of credit losses accounting standard (note 2) | (7) | (7) | ||||||||||||||||||||||||||
| Other |
1 | - | 1 | - | (1) | 1 | ||||||||||||||||||||||
| Balance, March 31, 2020 |
$ | 6,340 | $ | 1,004 | $ | 78 | $ | 707 | $ | 1,540 | $ | 36 | $ | 9,705 | ||||||||||||||
| millions of Canadian dollars |
||||||||||||||||||||||||||||
| Balance, December 31, 2018 |
$ | 5,816 | $ | 1,004 | $ | 84 | $ | 338 | $ | 1,075 | $ | 41 | $ | 8,358 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 323 | 1 | 324 | |||||||||||||||||||||
| Other comprehensive income (loss), net of tax expense of $1 million | - | - | - | (121) | - | - | (121) | |||||||||||||||||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (11) | - | (11) | |||||||||||||||||||||
| Dividends declared on common stock ($0.5875/share) | - | - | - | - | (138) | - | (138) | |||||||||||||||||||||
| Common stock issued under purchase plan | 51 | - | - | - | - | - | 51 | |||||||||||||||||||||
| Senior management stock option exercised | 32 | - | (2) | - | - | - | 30 | |||||||||||||||||||||
| Other |
- | - | - | - | - | (2) | (2) | |||||||||||||||||||||
| Balance, March 31, 2019 |
$ | 5,899 | $ | 1,004 | $ | 82 | $ | 217 | $ | 1,249 | $ | 40 | $ | 8,491 | ||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
(1) Series A; $0.1597/share, Series B; $0.2190/share, Series C; $.29506/share, Series E; $0.28125/share, Series F; $0.265625/share and Series H; $0.30625/share
(2) Series A; $0.1597/share, Series B; $0.2206/share, Series C; $.29506/share, Series E; $0.28125/share, Series F; $0.265625/share and Series H; $0.30625/share
48
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at March 31, 2020 and 2019
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, and gas transmission and distribution.
At March 31, 2020, Emera’s reportable segments include the following:
| • | Florida Electric Utility, which consists of Tampa Electric, a vertically integrated regulated electric utility in West Central Florida. |
| • | Canadian Electric Utilities, which includes: |
| • | Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia; and |
| • | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission investments related to an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy. ENL’s two investments are: |
| • | a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.6 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project went in service on January 15, 2018; and |
| • | a 49.5 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and Nalcor recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL, however, there has been a suspension of on-site commissioning in response to the COVID-19 pandemic. On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the novel coronavirus COVID-19 (“COVID-19”) pandemic. Refer to note 21 for further details. |
| • | Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include: |
| • | The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados; |
| • | Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island; |
| • | a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated regulated electric utility on the island of Dominica; and |
| • | a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia. |
On March 24, 2020, Emera completed the sale of Emera Maine which was previously included in the Other Electric Utilities segment. Refer to note 4 for further information.
| • | Gas Utilities and Infrastructure, which includes: |
| • | Peoples Gas System (“PGS”), a regulated gas distribution utility operating across Florida; |
| • | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico; |
| • | SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida; |
49
| • | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada, which expires in 2034; and |
| • | a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas throughout markets in Atlantic Canada and the northeastern United States. |
At March 31, 2020, Emera’s investments in other energy-related non-regulated companies (included within the Other reportable segment) include the following:
| • | Emera Energy, which consists of: |
| • | Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; |
| • | Brooklyn Power Corporation (“Brooklyn Energy”), a power plant in Brooklyn, Nova Scotia; and |
| • | a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a pumped storage hydroelectric facility in northwestern Massachusetts. |
| • | Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost-efficient management of risk and deductible levels across Emera; |
| • | Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera; |
| • | Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and |
| • | other investments. |
In 2019, the Company completed the sale of assets previously included in the Other segment, including the sale of Emera Energy’s New England Gas Generating (“NEGG”) and Bayside facilities, and Emera Utility Services equipment and inventory.
Basis of Presentation
These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2019, except as described in note 2.
In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2020.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
50
Use of Management Estimates
The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. 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. 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, with any adjustments recognized in income in the year they arise.
In Q1 2020, the ongoing COVID-19 pandemic impacted all the service territories in which Emera operates. Currently, COVID-19 has not had a material financial impact on the Company, Emera’s utilities provide essential services and continue to operate and meet customer demand. Governments world-wide have implemented measures intended to address the pandemic. These measures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial spaces and industrial facilities, shutdowns, shelter-in-place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility and weakness. Governments and central banks are implementing measures designed to stabilize economic conditions.
Management has analyzed the impact of the COVID-19 pandemic on its estimates and judgements and concluded that no material adjustments are required at March 31, 2020.
Goodwill Impairment Assessments
Management considered whether the potential impacts of the COVID-19 pandemic on future earnings required testing for goodwill impairment in Q1 2020 and determined that it is more likely than not that the fair value of reporting units that include goodwill exceeded their respective carrying amounts as of March 31, 2020.
As of March 31, 2020, $6.3 billion of Emera’s goodwill was related to TECO Energy (Tampa Electric, PGS and NMGC reporting units). Given the significant excess of fair value over carrying amounts calculated for these reporting units as of the last quantitative test performed in Q4 2019, management does not expect the COVID-19 pandemic to have an impact on the goodwill associated with these reporting units.
As of March 31, 2020, $76 million of Emera’s goodwill was related to GBPC. The calculated goodwill for this reporting unit is more sensitive to changes in forecasted future earnings. Adverse impacts to earnings in the future as a result of COVID-19 could cause impairment, however, the impact of COVID-19 on future earnings cannot be reasonably determined or estimated at this time. No impairment has been recorded in Q1 2020.
Long-Lived Assets Impairment Assessments
Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at March 31, 2020, there are no indications of impairment of Emera’s long-lived assets. The impact of COVID-19 could cause the Company to impair long-lived assets in the future, however, there is currently no indication that future cash flows would be impacted to a point where the Company’s long-lived assets would not be recoverable.
Impairment charges of $22 million ($23 million after tax) were recognized on certain assets in Q1 2020.
51
Pension and Other Post-Retirement Employee Benefits
The COVID-19 pandemic could impact key actuarial assumptions used to account for employee post-retirement benefits including the anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation, benefit costs and annual pension funding requirements. Fluctuations in actual equity market returns and changes in interest rates as a result of the COVID-19 pandemic may also result in changes to pension costs and funding in future periods.
The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these estimates.
Seasonal Nature of Operations
Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity and gas sales, and related transmission and distribution, vary over the year. 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. Certain quarters may also be impacted by weather and the number and severity of storms. In 2020, quarterly results may also be affected by the impact of the COVID-19 pandemic.
Receivables and Allowance for Doubtful Accounts
Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.
The Company is exposed to credit risk with respect to amounts receivable from customers. Credit assessments may be conducted on new customers. Deposits are requested on accounts as required. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis.
Management estimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.
The potential future economic impact of COVID-19, in the service territories in which Emera operates, may impact the collectability of customer receivables.
52
2. CHANGE IN ACCOUNTING POLICY
The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2020, are described as follows:
Measurement of Credit Losses on Financial Instruments
The Company adopted Accounting Standard Update (“ASU”) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. The adoption of the standard resulted in a $7 million decrease to retained earnings in the condensed consolidated financial statements as of January 1, 2020.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”). The ASUs that have been issued, but are not yet effective, are consistent with those disclosed in the Company’s 2019 audited consolidated financial statements, with updates noted below.
Facilitation of the Effects of Reference Rate Reform on Financial Reporting
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The standard provides optional expedients and exceptions for applying USGAAP to contract modifications and hedging relationships that reference LIBOR or another rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The Company is currently evaluating the impact of adoption of the standard, if elected, on its consolidated financial statements.
4. DISPOSITIONS
On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of approximately $2.0 billion including cash proceeds of $1.4 billion, transferred debt and a working capital adjustment. A gain on disposition of $586 million ($321 million after tax) net of transaction costs, was recognized in the Other segment and included in “Other income” on the Condensed Consolidated Statements of Income.
Emera Maine’s assets and liabilities were classified as held for sale at March 25, 2019. The Company continued recording depreciation on these assets through the transaction closing date, as the depreciation continued to be reflected in customer rates and was reflected in the carryover basis of the assets on completion of the sale. A total of $53 million of depreciation and amortization was recorded on these assets from March 25, 2019, the date they were classified as held for sale, until the date of the sale. $39 million of the $53 million was recorded in 2019. Emera Maine’s assets and liabilities were included in the Company’s Other Electric Utilities segment.
53
5. SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. Emera’s five reportable segments are Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.
| millions of Canadian dollars | Florida Electric Utility |
Canadian Electric Utilities |
Other Electric Utilities |
Gas Utilities and Infrastructure |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||
| For the three months ended March 31, 2020 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 565 | $ | 458 | $ | 171 | $ | 334 | $ | 109 | $ | - | $ | 1,637 | ||||||||||||||
| Inter-segment revenues (1) | 2 | - | - | 3 | 4 | (9) | - | |||||||||||||||||||||
| Total operating revenues | 567 | 458 | 171 | 337 | 113 | (9) | 1,637 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power | 142 | 204 | 67 | - | - | (3) | 410 | |||||||||||||||||||||
| Regulated cost of natural gas | - | - | - | 109 | - | - | 109 | |||||||||||||||||||||
| Depreciation and amortization | 116 | 58 | 28 | 27 | 2 | - | 231 | |||||||||||||||||||||
| Interest expense, net | 40 | 35 | 13 | 15 | 82 | (1) | 184 | |||||||||||||||||||||
| Internally allocated interest (2) | - | - | - | 3 | (3) | - | - | |||||||||||||||||||||
| Operating, maintenance and general (“OM&G”) | 138 | 79 | 47 | 84 | 35 | (5) | 378 | |||||||||||||||||||||
| Gain on sale and impairment charges | - | - | - | - | 564 | - | 564 | |||||||||||||||||||||
| Income tax expense (recovery) | 14 | 8 | (8) | 22 | 270 | - | 306 | |||||||||||||||||||||
| Net income attributable to common shareholders | 79 | 92 | 17 | 70 | 265 | - | 523 | |||||||||||||||||||||
| As at March 31, 2020 |
|
|||||||||||||||||||||||||||
| Total assets | 18,008 | 6,879 | 1,534 | 6,026 | 2,598 | (1,189) | (3) | 33,856 | ||||||||||||||||||||
| For the three months ended March 31, 2019 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | 545 | 442 | 182 | 356 | 294 | - | 1,819 | |||||||||||||||||||||
| Inter-segment revenues (1) | 3 | 1 | - | 6 | 10 | (21) | (1) | |||||||||||||||||||||
| Total operating revenues | 548 | 443 | 182 | 362 | 304 | (21) | 1,818 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power | 152 | 188 | 66 | - | - | (5) | 401 | |||||||||||||||||||||
| Regulated cost of natural gas | - | - | - | 136 | - | - | 136 | |||||||||||||||||||||
| Depreciation and amortization | 109 | 56 | 29 | 27 | 3 | - | 224 | |||||||||||||||||||||
| Interest expense, net | 38 | 35 | 13 | 16 | 87 | - | 189 | |||||||||||||||||||||
| Internally allocated interest (2) | - | - | - | 3 | (3) | - | - | |||||||||||||||||||||
| OM&G | 133 | 74 | 49 | 78 | 45 | (13) | 366 | |||||||||||||||||||||
| Income tax expense (recovery) | 13 | 8 | 3 | 21 | 37 | - | 82 | |||||||||||||||||||||
| Net income attributable to common shareholders | 61 | 96 | 18 | 67 | 70 | - | 312 | |||||||||||||||||||||
| As at December 31, 2019 |
|
|||||||||||||||||||||||||||
| Total assets |
16,214 | 6,717 | 3,069 | 5,489 | 1,459 | (1,106) | (3) | 31,842 | ||||||||||||||||||||
(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs.
(3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.
54
6. REVENUE
The following disaggregates the Company’s revenue by major source:
| millions of Canadian dollars | Florida Electric Utility |
Canadian Electric Utilities |
Other Electric Utilities |
Gas Utilities and Infrastructure |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||
| For the three months ended March 31, 2020 |
| |||||||||||||||||||||||||||
| Regulated |
||||||||||||||||||||||||||||
| Electric Revenue |
||||||||||||||||||||||||||||
| Residential |
$ |
275 |
|
$ |
264 |
|
$ |
61 |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
$ |
600 |
| |||||||
| Commercial |
|
168 |
|
|
120 |
|
|
80 |
|
|
- |
|
|
- |
|
|
- |
|
|
368 |
| |||||||
| Industrial |
|
50 |
|
|
56 |
|
|
12 |
|
|
- |
|
|
- |
|
|
- |
|
|
118 |
| |||||||
| Other electric and regulatory deferrals |
|
68 |
|
|
11 |
|
|
3 |
|
|
- |
|
|
- |
|
|
- |
|
|
82 |
| |||||||
| Other (1) |
|
6 |
|
|
7 |
|
|
15 |
|
|
- |
|
|
- |
|
|
(2) |
|
|
26 |
| |||||||
| Regulated electric revenue |
|
567 |
|
|
458 |
|
|
171 |
|
|
- |
|
|
- |
|
|
(2) |
|
|
1,194 |
| |||||||
| Gas Revenue |
||||||||||||||||||||||||||||
| Residential |
|
- |
|
|
- |
|
|
- |
|
|
168 |
|
|
- |
|
|
- |
|
|
168 |
| |||||||
| Commercial |
|
- |
|
|
- |
|
|
- |
|
|
91 |
|
|
- |
|
|
- |
|
|
91 |
| |||||||
| Industrial |
|
- |
|
|
- |
|
|
- |
|
|
13 |
|
|
- |
|
|
- |
|
|
13 |
| |||||||
| Finance income (2)(3) |
|
- |
|
|
- |
|
|
- |
|
|
15 |
|
|
- |
|
|
- |
|
|
15 |
| |||||||
| Other |
|
- |
|
|
- |
|
|
- |
|
|
47 |
|
|
- |
|
|
(3) |
|
|
44 |
| |||||||
| Regulated gas revenue |
|
- |
|
|
- |
|
|
- |
|
|
334 |
|
|
- |
|
|
(3) |
|
|
331 |
| |||||||
| Non-Regulated |
||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
41 |
|
|
- |
|
|
41 |
| |||||||
| Energy sales (4) |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
4 |
|
|
(4) |
|
|
- |
| |||||||
| Capacity |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
| |||||||
| Other |
|
- |
|
|
- |
|
|
- |
|
|
3 |
|
|
5 |
|
|
- |
|
|
8 |
| |||||||
| Mark-to-market (3) |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
63 |
|
|
- |
|
|
63 |
| |||||||
| Non-regulated revenue |
|
- |
|
|
- |
|
|
- |
|
|
3 |
|
|
113 |
|
|
(4) |
|
|
112 |
| |||||||
| Total operating revenues |
$ |
567 |
|
$ |
458 |
|
$ |
171 |
|
$ |
337 |
|
$ |
113 |
|
$ |
(9) |
|
$ |
1,637 |
| |||||||
(1) Other includes rental revenues, which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
55
| millions of Canadian dollars | Florida Electric Utility |
Canadian Electric Utilities |
Other Electric Utilities |
Gas Utilities and Infrastructure |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||
| For the three months ended March 31, 2019 |
| |||||||||||||||||||||||||||
| Regulated |
||||||||||||||||||||||||||||
| Electric Revenue |
||||||||||||||||||||||||||||
| Residential |
$ |
274 |
|
$ |
252 |
|
$ |
68 |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
$ |
594 |
| |||||||
| Commercial |
|
160 |
|
|
113 |
|
|
80 |
|
|
- |
|
|
- |
|
|
- |
|
|
353 |
| |||||||
| Industrial |
|
46 |
|
|
55 |
|
|
12 |
|
|
- |
|
|
- |
|
|
- |
|
|
113 |
| |||||||
| Other electric and regulatory deferrals |
|
62 |
|
|
16 |
|
|
3 |
|
|
- |
|
|
- |
|
|
- |
|
|
81 |
| |||||||
| Other (1) |
|
6 |
|
|
7 |
|
|
19 |
|
|
- |
|
|
- |
|
|
(4) |
|
|
28 |
| |||||||
| Regulated electric revenue |
|
548 |
|
|
443 |
|
|
182 |
|
|
- |
|
|
- |
|
|
(4) |
|
|
1,169 |
| |||||||
| Gas Revenue |
||||||||||||||||||||||||||||
| Residential |
|
- |
|
|
- |
|
|
- |
|
|
189 |
|
|
- |
|
|
- |
|
|
189 |
| |||||||
| Commercial |
|
- |
|
|
- |
|
|
- |
|
|
98 |
|
|
- |
|
|
- |
|
|
98 |
| |||||||
| Industrial |
|
- |
|
|
- |
|
|
- |
|
|
12 |
|
|
- |
|
|
- |
|
|
12 |
| |||||||
| Finance income (2)(3) |
|
- |
|
|
- |
|
|
- |
|
|
14 |
|
|
- |
|
|
- |
|
|
14 |
| |||||||
| Other |
|
- |
|
|
- |
|
|
- |
|
|
45 |
|
|
- |
|
|
(6) |
|
|
39 |
| |||||||
| Regulated gas revenue |
|
- |
|
|
- |
|
|
- |
|
|
358 |
|
|
- |
|
|
(6) |
|
|
352 |
| |||||||
| Non-Regulated |
||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
54 |
|
|
- |
|
|
54 |
| |||||||
| Energy sales (4) |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
78 |
|
|
(4) |
|
|
74 |
| |||||||
| Capacity |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
38 |
|
|
- |
|
|
38 |
| |||||||
| Other |
|
- |
|
|
- |
|
|
- |
|
|
4 |
|
|
10 |
|
|
(7) |
|
|
7 |
| |||||||
| Mark-to-market (3) |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
124 |
|
|
- |
|
|
124 |
| |||||||
| Non-regulated revenue |
|
- |
|
|
- |
|
|
- |
|
|
4 |
|
|
304 |
|
|
(11) |
|
|
297 |
| |||||||
| Total operating revenues |
$ |
548 |
|
$ |
443 |
|
$ |
182 |
|
$ |
362 |
|
$ |
304 |
|
|
$ (21 |
) |
$ |
1,818 |
| |||||||
(1) Other includes rental revenues, which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
Remaining Performance Obligations
Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of March 31, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was $368 million (December 31, 2019 – $347 million). As allowed by the practical expedient in ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2033.
56
7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
|
Carrying Value as at |
Equity Income For the three months ended March 31 |
Percentage Ownership |
||||||||||||||||||
| March 31 | December 31 | |||||||||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | 2020 | |||||||||||||||
| LIL (1) |
$ | 591 | $ | 579 | $ | 12 | $ | 11 | 49.5 | |||||||||||
| NSPML |
557 | 554 | 15 | 14 | 100.0 | |||||||||||||||
| M&NP (2) |
143 | 138 | 5 | 6 | 12.9 | |||||||||||||||
| Lucelec (2) |
45 | 41 | 1 | 1 | 19.5 | |||||||||||||||
| Bear Swamp (3) |
- | - | 8 | 8 | 50.0 | |||||||||||||||
| $ | 1,336 | $ | 1,312 | $ | 41 | $ | 40 | |||||||||||||
(1) Emera indirectly owns 100 per cent of the LIL Class B units, which comprises 24.9 per cent of the total units issued. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments.
(2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method.
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $145 million (2019 - $137 million) is recorded in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 23). NSPML’s consolidated summarized balance sheet is as follows:
| As at | March 31 | December 31 | ||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Balance Sheet |
||||||||
| Current assets |
$ | 80 | $ | 69 | ||||
| Property, plant and equipment |
1,660 | 1,671 | ||||||
| Regulatory assets |
188 | 177 | ||||||
|
Non-current assets |
32 | 32 | ||||||
| Total assets |
$ | 1,960 | $ | 1,949 | ||||
| Current liabilities |
$ | 32 | $ | 23 | ||||
| Long-term debt |
1,288 | 1,288 | ||||||
|
Non-current liabilities |
83 | 84 | ||||||
| Equity |
557 | 554 | ||||||
| Total liabilities and equity |
$ | 1,960 | $ | 1,949 | ||||
8. OTHER INCOME (EXPENSES), NET
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Gain on sale and impairment charges (1) |
$ | 564 | $ | - | ||||
| Allowance for equity funds used during construction |
9 | 4 | ||||||
| Other |
(10 | ) | 9 | |||||
| $ | 563 | $ | 13 | |||||
(1) Refer to note 4 for further details related to the gain on sale
57
9. INCOME TAXES
The income tax provision differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Income before provision for income taxes |
$ | 841 | $ | 406 | ||||
| Statutory income tax rate |
29.5% | 31% | ||||||
| Income taxes, at statutory income tax rate |
248 | 126 | ||||||
| Additional impact from the sale of Emera Maine |
92 | - | ||||||
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities |
(21) | (21) | ||||||
| Amortization of deferred income tax regulatory liabilities |
(16) | (9) | ||||||
| Revaluation of deferred income taxes due to change in Nova Scotia tax rate |
12 | - | ||||||
| Foreign tax rate variance |
(9) | (12) | ||||||
| Other |
- | (2) | ||||||
| Income tax expense |
$ | 306 | $ | 82 | ||||
| Effective income tax rate |
36% | 20% | ||||||
The increase in the effective income tax rate was primarily due to the sale of Emera Maine and the revaluation of deferred income taxes as a result of the decrease in the Nova Scotia provincial corporate income tax rate, as discussed below.
On March 10, 2020, Bill 243 of the Nova Scotia Financial Measures (2020) Act (“the Financial Measures Act”) was enacted, which included a reduction in the Nova Scotia provincial corporate income tax rate from 16% to 14%. As a result, the Company’s combined Canadian federal and provincial statutory income tax rate was reduced from 31% to 29.5% for 2020 and further reduced to 29% for subsequent years.
As a result of the enactment of the Financial Measures Act, the Company was required to revalue certain of its Canadian deferred income tax assets and liabilities based on the new tax rates. The Company recorded a reduction of $52 million to its net deferred income tax liabilities and an offsetting reduction to its net deferred income tax regulatory asset, as the benefit of lower net deferred income tax liabilities is expected to be returned to customers in future years. The Company also recognized a $12 million income tax expense in Q1 2020 as a result of the revaluation of certain net deferred income tax assets.
On March 25, 2020, Bill C-13, the Canadian COVID-19 Emergency Response Act (“the COVID-19 Act”) was enacted, guaranteeing rapid implementation and administration of measures to protect Canadians’ health and safety, and stabilize the economy. In addition, the Government of Canada announced the opportunity for businesses to defer certain tax payments. The Company does not anticipate any material impacts from the COVID-19 Act or the Government of Canada’s additional announcements.
On March 27, 2020, the United States Coronavirus Aid, Relief, and Economic Security (CARES) Act (“the CARES Act”) was signed into legislation. The CARES Act includes several business provisions including deferral of employer payroll taxes, an employee retention payroll tax credit, temporary changes to business interest expense disallowance rules, changes to net operating loss carryback and limitation rules and corporate alternative minimum tax (“AMT”) relief. Under the new AMT provisions, companies can accelerate the refund of AMT credit carryforwards. In Q1 2020, the Company reclassified $77 million of AMT credit carryforwards from deferred income tax assets to receivables and other current assets as it expects to receive the refund in 2020. The Company does not anticipate any other material impacts from the CARES Act.
58
10. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
| Issued and outstanding: | millions of shares | millions of Canadian dollars | ||||||
| Balance, December 31, 2019 |
242.48 | $ 6,216 | ||||||
| Issuance of common stock (1) |
0.98 | 58 | ||||||
| Issued for cash under Purchase Plans at market rate |
0.83 | 49 | ||||||
| Discount on shares purchased under Dividend Reinvestment Plan |
- | (1 | ) | |||||
| Options exercised under senior management share option plan |
0.36 | 17 | ||||||
| Employee Share Purchase Plan |
- | 1 | ||||||
| Balance, March 31, 2020 |
244.65 | $ 6,340 | ||||||
(1) In Q1 2020, 982,982 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $59.79 per share for gross proceeds of $58.8 million ($58 million net of issuance costs). As at March 31, 2020, an aggregate gross sales limit of $441.2 million remains available for issuance under the ATM program.
11. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2020 | 2019 | ||||||
| Numerator |
||||||||
| Net income attributable to common shareholders |
$ | 523.1 | $ | 311.8 | ||||
| Diluted numerator |
523.1 | 311.8 | ||||||
| Denominator |
||||||||
| Weighted average shares of common stock outstanding |
243.4 | 234.9 | ||||||
| Weighted average deferred share units outstanding |
1.3 | 1.5 | ||||||
| Weighted average shares of common stock outstanding – basic |
244.7 | 236.4 | ||||||
| Stock-based compensation |
0.5 | 0.5 | ||||||
| Convertible Debentures |
- | 0.1 | ||||||
| Weighted average shares of common stock outstanding – diluted |
245.2 | 237.0 | ||||||
| Earnings per common share |
||||||||
| Basic |
$ | 2.14 | $ | 1.32 | ||||
| Diluted |
$ | 2.13 | $ | 1.32 | ||||
59
12. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss), net of tax, are as follows:
| millions of Canadian dollars | Unrealized (loss) gain on translation of self-sustaining foreign operations |
Net change in net investment hedges |
(Losses) gains on derivatives recognized as cash flow hedges |
Net change in sale |
Net change in unrecognized pension and post- retirement benefit costs |
Total AOCI | ||||||||||||||||||
| For the three months ended March 31, 2020 |
| |||||||||||||||||||||||
| Balance, January 1, 2020 |
$ | 253 | $ | 4 | $ | (1) | $ | (1) | $ | (160) | $ | 95 | ||||||||||||
| Other comprehensive income (loss) before reclassifications | 760 | (141) | (3) | - | - | 616 | ||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive income loss (gain) | - | - | 1 | - | (5) | (4) | ||||||||||||||||||
| Net current period other comprehensive income (loss) | 760 | (141) | (2) | - | (5) | 612 | ||||||||||||||||||
| Balance, March 31, 2020 | $ | 1,013 | $ | (137) | $ | (3) | $ | (1) | $ | (165) | $ | 707 | ||||||||||||
| For the three months ended March 31, 2019 |
| |||||||||||||||||||||||
| Balance, January 1, 2019 | $ | 654 | $ | (74) | $ | (7) | $ | (1) | $ | (234) | $ | 338 | ||||||||||||
| Other comprehensive income (loss) before reclassifications | (163) | 34 | 2 | - | - | (127) | ||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive income loss (gain) | - | - | 2 | - | 4 | 6 | ||||||||||||||||||
| Net current period other comprehensive income (loss) | (163) | 34 | 4 | - | 4 | (121) | ||||||||||||||||||
| Balance, March 31, 2019 | $ | 491 | $ | (40) | $ | (3) | $ | (1) | $ | (230) | $ | 217 | ||||||||||||
The reclassifications out of accumulated other comprehensive income (loss) are as follows:
| For the | Three months ended March 31 | |||||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||||
|
|
Affected line item in the Consolidated Financial Statements |
Amounts reclassified from AOCI |
||||||||
| Losses (gain) on derivatives recognized as cash flow hedges | ||||||||||
| Foreign exchange forwards |
Operating revenue - regulated | $ | 1 | $ | 2 | |||||
| Total | $ | 1 | 2 | |||||||
| Net change in unrecognized pension and post-retirement benefit costs | ||||||||||
| Actuarial losses (gains) | OM&G | $ | 3 | $ | 5 | |||||
| Amounts reclassified into obligations |
Pension and post-retirement benefits | (8) | - | |||||||
| Total before tax | (5) | 5 | ||||||||
| Income tax recovery (expense) | - | (1) | ||||||||
| Total net of tax | $ | (5) | $ | 4 | ||||||
| Total reclassifications out of AOCI, net of tax, for the period | $ | (4) | $ | 6 | ||||||
60
13. DERIVATIVE INSTRUMENTS
The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:
| • | commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations; |
| • | foreign exchange fluctuations on foreign currency denominated purchases and sales |
| • | interest rate fluctuations on debt securities; and |
| • | share price fluctuations on stock-based compensation. |
The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:
| 1. | Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exception if the criteria are no longer met. |
| 2. | Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. |
Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.
| 3. | Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Tampa Electric and PGS have no derivatives related to hedging as a result of a Florida Public Service Commission approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. |
| 4. | Derivatives that do not meet any of the above criteria are designated as held-for-trading (“HFT”) derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. |
61
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| As at | March 31 | December 31 | March 31 | December 31 | ||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | ||||||||||||
| Cash flow hedges | ||||||||||||||||
| Foreign exchange forwards |
$ | - | $ | - | $ | 3 | $ | 1 | ||||||||
| - | - | 3 | 1 | |||||||||||||
| Regulatory deferral | ||||||||||||||||
| Commodity swaps and forwards |
||||||||||||||||
| Coal purchases |
14 | 8 | 49 | 39 | ||||||||||||
| Power purchases |
12 | 23 | 57 | 36 | ||||||||||||
| Natural gas purchases and sales |
2 | 2 | 8 | 5 | ||||||||||||
| Heavy fuel oil purchases |
- | 1 | 31 | - | ||||||||||||
| Foreign exchange forwards |
35 | 2 | - | 6 | ||||||||||||
| 63 | 36 | 145 | 86 | |||||||||||||
| HFT derivatives |
||||||||||||||||
| Power swaps and physical contracts |
21 | 19 | 27 | 22 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts |
138 | 151 | 251 | 381 | ||||||||||||
| 159 | 170 | 278 | 403 | |||||||||||||
| Other derivatives |
||||||||||||||||
| Equity derivatives and interest rate swaps |
1 | 1 | - | - | ||||||||||||
| Foreign exchange forwards |
1 | - | 11 | - | ||||||||||||
| 2 | 1 | 11 | - | |||||||||||||
| Total gross current derivatives |
224 | 207 | 437 | 490 | ||||||||||||
| Impact of master netting agreements with intent to settle net or simultaneously |
(109) | (120) | (109) | (120) | ||||||||||||
| 115 | 87 | 328 | 370 | |||||||||||||
| Current |
68 | 54 | 215 | 268 | ||||||||||||
| Long-term |
47 | 33 | 113 | 102 | ||||||||||||
| Total derivatives |
$ | 115 | $ | 87 | $ | 328 | $ | 370 | ||||||||
Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
Details of master netting agreements, shown net on the Condensed Consolidated Balance Sheets, are summarized in the following table:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| As at | March 31 | December 31 | March 31 | December 31 | ||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | ||||||||||||
| Regulatory deferral |
$ | 14 | $ | 8 | $ | 14 | $ | 8 | ||||||||
| HFT derivatives |
95 | 112 | 95 | 112 | ||||||||||||
| Total impact of master netting agreements with intent to settle net or simultaneously |
$ | 109 | $ | 120 | $ | 109 | $ | 120 | ||||||||
62
Cash Flow Hedges
The Company has foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.
The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:
| For the millions of Canadian dollars |
Three months ended March 31 | |||||||
| 2020 | 2019 | |||||||
| |
Foreign exchange forwards |
| ||||||
| Realized gain (loss) in operating revenue – regulated |
$ | (1) | $ | (2) | ||||
| Total gains (losses) in net income |
$ | (1) | $ | (2) | ||||
| As at millions of Canadian dollars |
March 31 2020 |
December 31 2019 |
||||||
| |
Foreign exchange forwards |
| ||||||
| Total unrealized gain (loss) in AOCI – effective portion, net of tax |
$ | (3) | $ | (1) | ||||
The Company expects $3 million of unrealized loss currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.
As at March 31, 2020, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:
| millions |
2020 | |||
| Foreign exchange forwards (USD) sales |
$ | 21 | ||
Regulatory Deferral
The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:
| For the millions of Canadian dollars | Three months ended March 31, 2020 | |||||||
| |
Commodity swaps and forwards |
|
|
Foreign exchange forwards |
| |||
| Unrealized gain (loss) in regulatory assets |
$ | (74) | $ | 6 | ||||
| Unrealized gain (loss) in regulatory liabilities |
(10) | 35 | ||||||
| Realized (gain) loss in regulatory liabilities |
7 | - | ||||||
| Realized (gain) loss in inventory (1) |
- | (1) | ||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) |
6 | (1) | ||||||
| Total change in derivative instruments |
$ | (71) | $ | 39 | ||||
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) 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.
63
| For the millions of Canadian dollars |
Three months ended March 31, 2019 | |||||||
| |
Commodity swaps and forwards |
|
|
Foreign exchange forwards |
| |||
| Unrealized gain (loss) in regulatory assets |
$ 6 | $ | (1) | |||||
| Unrealized gain (loss) in regulatory liabilities |
(19) | (5) | ||||||
| Realized (gain) loss in regulatory assets |
5 | - | ||||||
| Realized (gain) loss in inventory (1) |
(18) | (5) | ||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) |
(2) | (2) | ||||||
| Total change in derivative instruments |
$ (28) | $ | (13) | |||||
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) 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.
Commodity Swaps and Forwards
As at March 31, 2020, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:
| 2020 | 2021-2022 | |||||||
| millions |
Purchases | Purchases | ||||||
| Natural Gas (Mmbtu) |
3 | 10 | ||||||
| Power (MWh) |
1 | 3 | ||||||
| Heavy fuel oil (bbls) |
- | 1 | ||||||
| Coal (metric tonnes) |
- | 1 | ||||||
Foreign Exchange Swaps and Forwards
As at March 31, 2020, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated as regulated deferral that are expected to settle as outlined below:
| 2020 | 2021-2022 | |||||||
| Foreign exchange contracts (millions of US dollars) |
$ | 120 | $ | 208 | ||||
| Weighted average rate |
1.2925 | 1.3272 | ||||||
| % of USD requirements |
67% | 55% | ||||||
The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required.
Held-for-Trading Derivatives
In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures, to economically hedge those physical contracts. These derivatives are all considered HFT.
64
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Power swaps and physical contracts in non-regulated operating revenues |
$ | 1 | $ | (3 | ) | |||
| Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues |
211 | 152 | ||||||
| Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power |
(4 | ) | (2 | ) | ||||
| $ | 208 | $ | 147 | |||||
As at March 31, 2020, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
| millions |
2020 | 2021 | 2022 | 2023 | 2024 | |||||||||||||||
| Natural gas purchases (Mmbtu) |
421 | 119 | 56 | 41 | 26 | |||||||||||||||
| Natural gas sales (Mmbtu) |
386 | 75 | 11 | 3 | 2 | |||||||||||||||
| Power purchases (MWh) |
2 | - | - | - | - | |||||||||||||||
| Power sales (MWh) |
2 | - | - | - | - | |||||||||||||||
Other Derivatives
As at March 31, 2020, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and foreign exchange forwards in place to manage cash flow risk associated with forecasted US dollar cash inflows. The equity derivative hedges the return on 2.8 million shares and extends until December of 2020. The foreign exchange forwards have a combined notional amount of $247 million and expire in 2020 through 2021.
The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives:
| For the | Three months ended March 31 | |||||||||||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||||||||||
| |
Foreign Exchange Forwards |
|
|
Equity Derivatives |
|
|
Foreign Exchange Forwards |
|
|
Equity Derivatives |
| |||||
| Unrealized gain (loss) in operating, maintenance and general |
$ | - | $ | (1 | ) | $ | - | $ | 14 | |||||||
| Unrealized gain (loss) in other income (expense) |
(9 | ) | - | - | - | |||||||||||
| Realized gain (loss) in other income (expense) |
(1 | ) | - | - | - | |||||||||||
| Total gains (losses) in net income |
$ | (10 | ) | $ | (1 | ) | $ | - | $ | 14 | ||||||
Credit Risk
The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts.
65
The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.
It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable, or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.
As at March 31, 2020, the Company had $121 million (December 31, 2019 - $115 million) in financial assets considered to be past due, which have been outstanding for an average 57 days. The fair value of these financial assets is $110 million (December 31, 2019 - $106 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue.
Cash Collateral
The Company’s cash collateral positions consisted of the following:
| As at millions of Canadian dollars |
March 31 2020 |
December 31 2019 |
||||||
| Cash collateral provided to others |
$ | 166 | $ | 101 | ||||
| Cash collateral received from others |
2 | 2 | ||||||
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.
As at March 31, 2020, the total fair value of these derivatives, in a liability position, was $328 million (December 31, 2019 – $370 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.
66
14. FAIR VALUE MEASUREMENTS
The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 13), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:
Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.
Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:
| ● | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. |
| ● | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. |
| ● | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the fair value measurement.
67
The following tables set out the classification of the methodology used by the Company to fair value its derivatives:
| As at | March 31, 2020 | |||||||||||||||
| millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral |
||||||||||||||||
| Commodity swaps and forwards |
||||||||||||||||
| Power purchases |
$ | 12 | $ | - | $ | - | $ | 12 | ||||||||
| Natural gas purchases and sales |
- | 2 | - | 2 | ||||||||||||
| Foreign exchange forwards |
- | 35 | - | 35 | ||||||||||||
| 12 | 37 | - | 49 | |||||||||||||
| HFT derivatives |
||||||||||||||||
| Power swaps and physical contracts |
3 | - | 4 | 7 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation | (4) | 46 | 15 | 57 | ||||||||||||
| (1) | 46 | 19 | 64 | |||||||||||||
| Other derivatives |
||||||||||||||||
| Foreign exchange forwards |
- | 1 | - | 1 | ||||||||||||
| Equity derivatives |
1 | - | - | 1 | ||||||||||||
| 1 | 1 | - | 2 | |||||||||||||
| Total assets |
12 | 84 | 19 | 115 | ||||||||||||
| Liabilities |
||||||||||||||||
| Cash flow hedges |
||||||||||||||||
| Foreign exchange forwards |
- | 3 | - | 3 | ||||||||||||
| - | 3 | - | 3 | |||||||||||||
| Regulatory deferral |
||||||||||||||||
| Commodity swaps and forwards |
||||||||||||||||
| Coal purchases |
- | 35 | - | 35 | ||||||||||||
| Power purchases |
57 | - | - | 57 | ||||||||||||
| Heavy fuel oil purchases |
8 | 23 | - | 31 | ||||||||||||
| Natural gas purchases and sales |
6 | 2 | - | 8 | ||||||||||||
| 71 | 60 | - | 131 | |||||||||||||
| HFT derivatives |
||||||||||||||||
| Power swaps and physical contracts |
9 | 1 | 3 | 13 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts | 2 | 16 | 152 | 170 | ||||||||||||
| 11 | 17 | 155 | 183 | |||||||||||||
| Other derivatives |
||||||||||||||||
| Foreign exchange forwards |
- | 11 | - | 11 | ||||||||||||
| - | 11 | - | 11 | |||||||||||||
| Total liabilities |
82 | 91 | 155 | 328 | ||||||||||||
| Net assets (liabilities) |
$ | (70) | $ | (7) | $ | (136) | $ | (213) | ||||||||
68
| As at | December 31, 2019 | |||||||||||||||
| millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral |
||||||||||||||||
| Commodity swaps and forwards |
||||||||||||||||
| Power purchases |
23 | - | - | 23 | ||||||||||||
| Natural gas purchases and sales |
- | 2 | - | 2 | ||||||||||||
| Heavy fuel oil purchases |
- | 1 | - | 1 | ||||||||||||
| Foreign exchange forwards |
- | 2 | - | 2 | ||||||||||||
| 23 | 5 | - | 28 | |||||||||||||
| HFT derivatives |
||||||||||||||||
| Power swaps and physical contracts |
1 | 3 | 1 | 5 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation | (7) | 46 | 14 | 53 | ||||||||||||
| (6) | 49 | 15 | 58 | |||||||||||||
| Other derivatives |
||||||||||||||||
| Equity derivatives |
1 | - | - | 1 | ||||||||||||
| 1 | - | - | 1 | |||||||||||||
| Total assets |
18 | 54 | 15 | 87 | ||||||||||||
| Liabilities |
||||||||||||||||
| Cash flow hedges |
||||||||||||||||
| Foreign exchange forwards |
- | 1 | - | 1 | ||||||||||||
| - | 1 | - | 1 | |||||||||||||
| Regulatory deferral |
||||||||||||||||
| Commodity swaps and forwards |
||||||||||||||||
| Coal purchases |
- | 31 | - | 31 | ||||||||||||
| Power purchases |
36 | - | - | 36 | ||||||||||||
| Natural gas purchased and sales |
3 | 2 | - | 5 | ||||||||||||
| Foreign exchange forwards |
- | 6 | - | 6 | ||||||||||||
| 39 | 39 | - | 78 | |||||||||||||
| HFT derivatives |
||||||||||||||||
| Power swaps and physical contracts |
5 | 2 | - | 7 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
2 | 33 | 249 | 284 | ||||||||||||
| 7 | 35 | 249 | 291 | |||||||||||||
| Total liabilities |
46 | 75 | 249 | 370 | ||||||||||||
| Net assets (liabilities) |
$ | (28) | $ | (21) | $ | (234) | $ | (283) | ||||||||
The change in the fair value of the Level 3 financial assets for the three months ended March 31, 2020 was as follows:
| HFT Derivatives | ||||||||||||
| millions of Canadian dollars | Power | Natural gas |
Total | |||||||||
| Balance, beginning of period |
$ | 1 | $ | 14 | $ | 15 | ||||||
| Total realized and unrealized gains (losses) included in non-regulated operating revenues |
3 | 1 | 4 | |||||||||
| Balance, March 31, 2020 |
$ | 4 | $ | 15 | $ | 19 | ||||||
The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 2020 was as follows:
| HFT Derivatives | ||||||||||||
| millions of Canadian dollars | Power | Natural gas |
Total | |||||||||
| Balance, beginning of period |
$ | - | $ | 249 | $ | 249 | ||||||
| Total realized and unrealized gains (losses) included in non-regulated operating revenues |
3 | (97) | (94) | |||||||||
| Balance, March 31, 2020 |
$ | 3 | $ | 152 | $ | 155 | ||||||
69
Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.
The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:
| As at | March 31, 2020 | |||||||||||||||||||||||||||
| millions of Canadian dollars | Fair Value |
Valuation Technique |
Unobservable Input | Range | Weighted average (1) |
|||||||||||||||||||||||
| Assets |
||||||||||||||||||||||||||||
| HFT derivatives – Power swaps and physical contracts |
$ | 4 | Modelled pricing | Third-party pricing | $0.06-$64.15 | $9.38 | ||||||||||||||||||||||
| Probability of default | 0.01%-1.05% | 0.11% | ||||||||||||||||||||||||||
| Discount rate | 0.08%-1.78% | 0.64% | ||||||||||||||||||||||||||
| HFT derivatives – Natural gas swaps, futures, forwards, physical contracts |
8 | Modelled pricing | Third-party pricing | $1.11-$3.17 | $1.81 | |||||||||||||||||||||||
| Probability of default | 0.01%-2.56% | 0.10% | ||||||||||||||||||||||||||
| Discount rate | 0.00%-8.51% | 0.67% | ||||||||||||||||||||||||||
| 7 | Modelled pricing | Third-party pricing | $1.22-$8.25 | $3.25 | ||||||||||||||||||||||||
| Basis adjustment | $0.00-$1.17 | $0.75 | ||||||||||||||||||||||||||
| Probability of default | 0.01%-3.46% | 1.15% | ||||||||||||||||||||||||||
| Discount rate | 0.00%-1.37% | 0.62% | ||||||||||||||||||||||||||
| Total assets |
$ | 19 | ||||||||||||||||||||||||||
| Liabilities |
||||||||||||||||||||||||||||
| HFT derivatives – |
$ | 3 | Modelled pricing | Third-party pricing | $1.13-$64.15 | $9.73 | ||||||||||||||||||||||
| Power swaps and |
Own credit risk | 0.01%-1.05% | 0.09% | |||||||||||||||||||||||||
| physical contracts |
Discount rate | 0.08%-1.78% | 0.63% | |||||||||||||||||||||||||
| HFT derivatives – Natural gas swaps, futures, forwards and physical contracts |
139 | Modelled pricing | Third-party pricing | $1.11-$7.45 | $2.89 | |||||||||||||||||||||||
| Own credit risk | 0.01%-2.56% | 0.17% | ||||||||||||||||||||||||||
| Discount rate | 0.00%-7.3% | 0.63% | ||||||||||||||||||||||||||
| 13 | Modelled pricing | Third-party pricing | $0.85-$8.25 | $3.87 | ||||||||||||||||||||||||
| Basis adjustment | $0.00-$1.17 | $0.54 | ||||||||||||||||||||||||||
| Own credit risk | 0.01%-1.72% | 0.08% | ||||||||||||||||||||||||||
| Discount rate | 0.00%-1.28% | 0.69% | ||||||||||||||||||||||||||
| Total liabilities |
$ | 155 | ||||||||||||||||||||||||||
| Net assets (liabilities) |
$ | (136 | ) | |||||||||||||||||||||||||
(1) Unobservable inputs were weighted by the relative fair value of the instruments
The financial liabilities included on the Condensed Consolidated Balance Sheets that are not measured at fair value consisted of long-term debt, as follows:
| As at |
||||||||||||||||||||||||
| millions of Canadian dollars | Carrying Amount |
Fair Value | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||
| March 31, 2020 |
$ | 14,777 | $ | 15,602 | $ | - | $ | 15,075 | $ | 527 | $ | 15,602 | ||||||||||||
| December 31, 2019 |
$ | 14,180 | $ | 16,049 | $ | - | $ | 15,598 | $ | 451 | $ | 16,049 | ||||||||||||
The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. An after-tax foreign currency loss of $141 million was recorded in Other Comprehensive Income for the three months ended March 31, 2020 (2019 – $34 million gain after-tax).
70
15. REGULATORY ASSETS AND LIABILITIES
A summary of the Company’s regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 15 in Emera’s 2019 annual audited consolidated financial statements.
| As at millions of Canadian dollars |
March 31 2020 |
December 31 2019 |
||||||
| Regulatory assets |
||||||||
| Deferred income tax regulatory assets |
$ | 852 | $ | 862 | ||||
| Pension and post-retirement medical plan |
409 | 380 | ||||||
| Deferrals related to derivative instruments |
132 | 81 | ||||||
| Storm restoration regulatory asset |
43 | 38 | ||||||
| Stranded cost recovery |
29 | 27 | ||||||
| Environmental remediations |
29 | 26 | ||||||
| Demand side management (“DSM”) deferral |
18 | 19 | ||||||
| Unamortized defeasance costs |
17 | 19 | ||||||
| Cost recovery clauses |
4 | 13 | ||||||
| Other |
87 | 87 | ||||||
| $ | 1,620 | $ | 1,552 | |||||
| Current |
$ | 156 | $ | 121 | ||||
| Long-term |
1,464 | 1,431 | ||||||
| Total regulatory assets |
$ | 1,620 | $ | 1,552 | ||||
| Regulatory liabilities |
||||||||
| Deferred income tax regulatory liabilities |
$ | 1,051 | $ | 985 | ||||
| Accumulated reserve - cost of removal |
970 | 891 | ||||||
| Regulated fuel adjustment mechanism |
112 | 115 | ||||||
| Cost recovery clauses |
108 | 53 | ||||||
| Storm reserve |
68 | 62 | ||||||
| Deferrals related to derivative instruments |
56 | 42 | ||||||
| Self-insurance fund (note 23) |
31 | 29 | ||||||
| Other |
2 | 4 | ||||||
| $ | 2,398 | $ | 2,181 | |||||
| Current |
$ | 310 | $ | 295 | ||||
| Long-term |
2,088 | 1,886 | ||||||
| Total regulatory liabilities |
$ | 2,398 | $ | 2,181 | ||||
Tampa Electric
On April 28, 2020, the FPSC approved Tampa Electric’s request for a mid-course adjustment to its fuel and capacity charges due to a decline in expected fuel commodity and capacity costs in 2020. The adjustment will be effective beginning with June 2020 customer bills.
BLPC
In December 2018, as a result of the enactment of the Income Tax Amendment Act in Barbados, BLPC was required to remeasure its deferred income tax liability at a new lower corporate income tax rate. At that time, BLPC deferred $6.9 million USD of the recovery, all of which was recognized in earnings in Q1 2020.
71
Grand Bahama Power Company
On September 1, 2019, Hurricane Dorian struck Grand Bahama Island causing significant damage across the island. In January 2020, the GBPA approved the recovery of approximately $15 million USD of restoration costs related to GBPC’s self-insured assets. As of March 31, 2020, $13 million USD of these costs were incurred, and recorded as a regulatory asset. Recovery of the regulatory asset, due to start on April 1, 2020, has been temporarily suspended as a result of the potential economic impacts of COVID-19 on Grand Bahama.
16. RELATED PARTY TRANSACTIONS
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 to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-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 assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $28 million for the three months ended March 31, 2020 (2019 - $27 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. |
| ● | Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $8 million for the three months ended March 31, 2020 (2019 - $18 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2020 and at December 31, 2019.
17. RECEIVABLES AND OTHER CURRENT ASSETS
Receivables and other current assets consisted of the following:
| As at millions of Canadian dollars |
March 31 2020 |
December 31 2019 |
||||||
| Customer accounts receivable – billed | $ | 590 | $ | 603 | ||||
| Customer accounts receivable – unbilled | 269 | 265 | ||||||
| Allowance for doubtful accounts | (13) | (9) | ||||||
| Capitalized transportation capacity (1) | 234 | 272 | ||||||
| Income tax receivable | 189 | 118 | ||||||
| Prepaid expenses | 82 | 48 | ||||||
| Other | 254 | 189 | ||||||
| $ | 1,605 | $ | 1,486 | |||||
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.
72
18. EMPLOYEE BENEFIT PLANS
Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, Dominica and Grand Bahama Island. For details of the Company’s employee benefit plan, refer to note 19 in Emera’s 2019 annual audited consolidated financial statements. Refer to note 1 “Use of Management Estimates – Pension and Other Post-Retirement Employee Benefits”.
Emera’s net periodic benefit cost included the following:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Defined benefit pension plans |
||||||||
| Service cost |
$ | 12 | $ | 12 | ||||
| Non-service cost |
||||||||
| Interest cost |
22 | 26 | ||||||
| Expected return on plan assets |
(37) | (37) | ||||||
| Current year amortization of: |
||||||||
| Actuarial losses |
4 | 5 | ||||||
| Regulatory asset |
7 | 4 | ||||||
| Total non-service costs |
(4) | (2) | ||||||
| Total defined benefit pension plans |
8 | 10 | ||||||
| Non-pension benefits plan |
||||||||
| Service cost |
1 | 1 | ||||||
| Non-service cost |
||||||||
| Interest cost |
3 | 4 | ||||||
| Expected return on plan assets |
- | (1) | ||||||
| Current year amortization of: |
||||||||
| Regulatory asset |
- | (2) | ||||||
| Total non-service costs |
3 | 1 | ||||||
| Total non-pension benefits plans |
4 | 2 | ||||||
| Total defined benefit plans |
$ | 12 | $ | 12 | ||||
Emera’s contributions related to these defined-benefit plans for the three months ended March 31, 2020 were $16 million (2019 - $16 million). Annual employer contributions to the defined benefit pension plans are estimated to be $39 million for 2020.
19. SHORT-TERM DEBT
Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt refer to note 22 in Emera’s 2019 annual audited consolidated financial statements, and below for 2020 short-term debt financing activity.
Recent Significant Financing Activity by Segment
Florida Electric Utilities
On February 6, 2020, TEC entered into a $300 million USD non-revolving credit agreement with a maturity date of February 4, 2021. The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at LIBOR, prime rate or the federal funds rate, plus a margin.
73
Other
On April 3, 2020, TECO Energy/Finance repaid $200 million USD of its $500 million Non-Revolving Term Loan that is due to mature on July 3, 2020. This partial repayment was made from proceeds of the Emera Maine sale.
On February 28, 2020, TECO Energy/Finance extended the maturity date of its $500 million USD credit facility from March 5, 2020 to July 3, 2020. There were no other significant changes in commercial terms from the prior agreement.
20. LONG-TERM DEBT
For details regarding long-term debt, refer to note 24 in Emera’s 2019 annual audited consolidated financial statements, and below for 2020 long-term debt financing activity.
Recent Significant Financing Activity by Segment
Canadian Electric Utilities
On April 24, 2020, NSPI completed a $300 million 30-year unsecured notes issuance. The notes bear interest at a rate of 3.31 per cent and have a maturity date of April 25, 2050.
Other Electric Utilities
On February 19, 2020, BLPC received its first advance of $40 million BBD ($20 million USD) on a $110 million BBD ($55 million USD) non-revolving term loan. The loan bears interest at a rate of 2.05 per cent and has a 5-year term.
Other
On March 13, 2020, TECO Finance repaid a $300 million USD note upon maturity. The note was repaid using existing credit facilities.
74
21. COMMITMENTS AND CONTINGENCIES
| A. | Commitments |
As at March 31, 2020, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
| millions of Canadian dollars | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total | |||||||||||||||||||||
| Purchased power (1) |
$ | 197 | $ | 218 | $ | 247 | $ | 268 | $ | 282 | $ | 1,993 | $ | 3,205 | ||||||||||||||
| Transportation (2) |
423 | 429 | 374 | 312 | 288 | 2,999 | 4,825 | |||||||||||||||||||||
| Capital projects (3) |
414 | 135 | 111 | 94 | - | - | 754 | |||||||||||||||||||||
| Fuel, gas supply and storage |
363 | 133 | 28 | 5 | 1 | - | 530 | |||||||||||||||||||||
| Long-term service agreements (4) |
62 | 23 | 22 | 19 | 19 | 71 | 216 | |||||||||||||||||||||
| Equity investment commitments (5) |
- | 240 | - | - | - | - | 240 | |||||||||||||||||||||
| Leases and other (6) |
13 | 20 | 20 | 18 | 19 | 114 | 204 | |||||||||||||||||||||
| Demand side management |
24 | 41 | 43 | - | - | - | 108 | |||||||||||||||||||||
| $ | 1,496 | $ | 1,239 | $ | 845 | $ | 716 | $ | 609 | $ | 5,177 | $ | 10,082 | |||||||||||||||
(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
(3) Includes $485 million of commitments related to Tampa Electric’s solar, Big Bend Power Station modernization and AMI projects.
(4) 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.
(5) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership.
(6) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.
On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor has declared force majeure under various project contracts, including formal notification to NSPML. Due to the unpredictable nature of the COVID-19 pandemic, Nalcor is currently unable to provide an updated completion schedule for Muskrat Falls or LIL until there is greater certainty. Nalcor has expressed its desire to resume work at site as soon as it is safe to do so for its employees, contractors and associated communities.
NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls. NSPML anticipates making an application with the UARB in 2020 with respect to recovery of 2021 costs.
NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years from its January 15, 2018 in-service date. The UARB approved payment for 2020 is $145 million subject to a $10 million holdback and as at March 31, 2020, $26 million has been paid. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include the $145 million approved for 2020 and estimated amounts of $164 million and $162 million for 2021 and 2022, respectively. These estimated amounts are subject to review and approval by the UARB. The timing and amounts payable to NSPML for the remainder of the 37-year commitment period are dependent on regulatory filings with the UARB.
Emera has committed to obtain certain transmission rights for Nalcor Energy, if requested, to enable them to transmit energy which is not otherwise used in Newfoundland or Nova Scotia. This energy could be transmitted from Nova Scotia to New England energy markets beginning at first commercial power of the Muskrat Falls hydroelectric generating facility and related transmission assets when Nalcor commences delivery of the NS Block, and continuing for 50 years. As transmission rights are contracted, Emera includes the obligations within “Leases and other” in the above table.
75
| B. | Legal Proceedings |
TECO Guatemala Holdings (“TGH”)
In 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (“Guatemala”) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus two per cent. This award was upheld in subsequent annulment proceedings in 2016 and, in addition, TGH’s application for partial annulment of the award was granted, and Guatemala was ordered to pay certain costs relating to the annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding.
On September 23, 2016, TGH filed a request for resubmission to arbitration. A new tribunal was constituted, and the matter was fully briefed. A hearing was held in March 2019 and a decision is expected from the tribunal in 2020. In addition, TGH sued Guatemala in Washington, D.C. court to enforce the $21 million USD owing. Guatemala’s motion to dismiss the enforcement action was denied. On October 1, 2019, the court granted TGH’s motion for summary judgment which will allow TGH to seek collection of the award plus interest when the order is final. Guatemala has appealed that decision. Results to date do not reflect any benefit.
Superfund and Former Manufactured Gas Plant Sites
TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at March 31, 2020, TEC has estimated its financial liability to be $30 million ($21 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Condensed Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.
The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.
Emera Maine
On March 24, 2020, the Company completed the sale of Emera Maine. Emera has no remaining obligations with respect to the legal proceedings previously disclosed in note 26 of Emera’s 2019 annual audited consolidated financial statements. No new or additional reserves were made in Q1 2020 with respect to any of the four complaints filed with the Federal Energy Regulatory Commission.
76
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.
| C. | Principal Financial Risks and Uncertainties |
Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are discussed in note 13 and note 14.
Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management.
Public Health Risk
An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19 pandemic, or a fear of any of the foregoing, could adversely impact the Company, including by causing operating, supply chain and project development delays and disruptions, labour shortages and shutdowns (including as a result of government regulation and prevention measures), which could have a negative impact on the Company’s operations.
Any adverse changes in general economic and market conditions arising as a result of a public health threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which could result in a material adverse effect on the Company’s business.
The extent of the evolving COVID-19 pandemic and its future impact on the Company is uncertain. The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat. The Company’s top priority continues to be the health and safety of its customers and employees. In Q1 2020, Emera activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.
Foreign Exchange Risk
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.
Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange.
77
The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.
Liquidity and Capital Market Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, select asset sales, short-term credit facilities, and ongoing access to capital markets. Cash flows generated from the sale of select assets are dependent on the market for the assets, acceptable pricing and the timing of the close of any sales. The Company reasonably expects liquidity sources to exceed capital needs.
Emera’s access to capital and cost of borrowing is subject to a number of risk factors including financial market conditions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in property, plant and equipment. Emera is subject to risk with changes in interest rates that could have an adverse effect on the cost of financing. Inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan. The Company’s future access to capital and cost of borrowing may be impacted by possible continued COVID-19 related market disruptions.
Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. Emera manages this risk by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings.
The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation, preferred share units and deferred share units.
Interest Rate Risk
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. Future interest rates may be impacted by possible continued COVID-19 related market disruptions.
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives.
78
Commodity Price Risk
A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs.
Income Tax Risk
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results.
| D. | Guarantees and Letters of Credit |
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2019 audited annual consolidated financial statements, with an update as noted below:
The Company has standby letters of credit and surety bonds in the amount of $74 million USD (December 31, 2019 -$82 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.
The Company is in the process of issuing a guarantee of up to $60 million USD relating to outstanding notes of GBPC. The guarantee will reduce to no more than $35 million USD upon repayment of certain notes that are due May 22, 2020.
22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Changes in non-cash working capital: |
||||||||
| Inventory |
$ | 60 | $ | 57 | ||||
| Receivables and other current assets |
(84) | 151 | ||||||
| Accounts payable |
(168) | (265) | ||||||
| Other current liabilities |
118 | 41 | ||||||
| Total non-cash working capital |
$ | (74) | $ | (16) | ||||
|
Supplemental disclosure of non-cash activities: |
||||||||
| Common share dividends reinvested |
$ | 45 | $ | 48 | ||||
| Decrease (increase) in accrued capital expenditures |
$ | 23 | $ | (18) | ||||
79
23. VARIABLE INTEREST ENTITIES
The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”) or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities.
VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method.
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of Maritime Link. Thus, Emera began recording Maritime Link as an equity investment.
BLPC has established a Self-Insurance Fund (“SIF”), primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as an “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.
The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.
The following table provides information about Emera’s portion of material unconsolidated VIEs:
| As at | March 31, 2020 | December 31, 2019 | ||||||||||||||
| millions of Canadian dollars | Total assets |
Maximum exposure to loss |
Total assets |
Maximum exposure to loss |
||||||||||||
| Unconsolidated VIEs in which Emera has variable interests |
||||||||||||||||
| NSPML (equity accounted) |
$ | 557 | $ | 22 | $ | 554 | $ | 23 | ||||||||
80
24. COMPARATIVE INFORMATION
These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.
25. SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 12, 2020, the date the financial statements were issued.
81
Exhibit 99.3
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Scott Balfour, President and Chief Executive Officer of Emera Incorporated, certify the following:
1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended March 31, 2020.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2020 and ended on March 31, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: May 12, 2020 |
| “Scott Balfour”
|
|
Scott Balfour President and Chief Executive Officer |
Exhibit 99.4
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Greg Blunden, Chief Financial Officer of Emera Incorporated, certify the following:
1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended March 31, 2020.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2020 and ended on March 31, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: May 12, 2020 |
| “Greg Blunden”
|
|
Greg Blunden Chief Financial Officer |
Exhibit 99.5
Emera Incorporated
Earnings Coverage Ratio
Pursuant to Section 8.4 of National Instrument 44-102, this updated calculation of the earnings coverage ratio is filed as an exhibit to the unaudited condensed consolidated financial statements of Emera Incorporated (“Emera”) for the three months ended March 31, 2020.
The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month peroid ended March 31, 2020.
| Twelve months ended March 31, 2020 | |||||
| Earnings Coverage (1) |
2.39 | ||||
(1) Earnings coverage is equal to consolidated net income attributable to common shareholders plus: income taxes, interest on debt, amortization of debt financing costs, allowance for funds used during construction and preferred share dividends declared during the period together with undeclared preferred share dividends, if any, divided by the sum of interest on debt, amortization of debt financing costs, allowance for funds used during construction, capitalized interest and preferred dividends grossed up to a before-tax equivalent using an effective tax rate of 28.7 per cent.
Emera’s dividend requirements on all of its preferred shares, grossed up to a before-tax equivalent using an effective income tax rate of 28.7 per cent, amounted to $65 million for the twelve months ended March 31, 2020. Emera’s interest requirements for the twelve months ended March 31, 2020 amounted to $748 million. Emera’s consolidated income before interest and income tax for the twelve months ended March 31, 2020 was $1,938 million, which is 2.39 times Emera’s aggregate preferred dividends and interest requirements for this period.
Exhibit 99.6
Emera Reports 2020 First Quarter Financial Results
HALIFAX, Nova Scotia — Today Emera (TSX: EMA) announced financial results for the first quarter of 2020.
Q1 2020 Highlights:
Reported Net Income
| • | Q1 2020 reported net income was $523 million, or $2.14 per common share, compared with net income of $312 million, or $1.32 per common share, in Q1 2019. |
Adjusted Net Income (1)
| • | Q1 2020 adjusted net income was $193 million, or $0.79 per common share, compared with $224 million, or $0.95 per common share, in Q1 2019. |
Significant Items Affecting Reported and Adjusted Net Income
| • | Q1 2020 reported earnings included $321 million, net of tax and transaction costs, of earnings related to the gain on sale of the Emera Maine business. |
| • | Q1 2019 adjusted earnings included $24 million from the New England Gas Generation (“NEGG”) and Bayside generation facilities which were sold in Q1 2019 and a $10 million gain on sale of property in Florida. |
| • | Q1 2020 adjusted earnings were reduced by $14 million from the revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities due to the reduction in the Nova Scotia provincial corporate income tax rate. |
| • | Q1 2020 adjusted earnings included $10 million from the recognition of corporate income tax recovery deferred as a regulatory liability at BLPC. |
Cash Flow
| • | Q1 2020 cash flow, before changes in working capital, increased by $84 million to $502 million, compared with $418 million in Q1 2019. |
(1) See “Non-GAAP Measures” noted below.
“I am proud of our employees who remain focused on the health and safety of their colleagues, communities and customers as they deliver the essential energy services we all rely on during this global pandemic. On behalf of the team at Emera, our thoughts are with those affected by COVID-19 and we are pleased to do our part to assist the most vulnerable in our communities,” says Scott Balfour, President and Chief Executive Officer of Emera Inc. “While Emera will experience some short-term impacts to our business, our long-term outlook is positive and we are well positioned to continue to serve our customers and communities, and create value for our shareholders.”
1
Financial Highlights:
| For the | Three months ended | |||||||
| millions of Canadian dollars (except per share amounts) | March 31 | |||||||
|
|
||||||||
| 2020 | 2019 | |||||||
|
|
||||||||
| Net income attributable to common shareholders |
$ | 523 | $ | 312 | ||||
|
|
||||||||
| Gain on sale and impairment charges, net of tax |
$ | 298 | - | |||||
| After-tax mark-to-market gain |
32 | 88 | ||||||
|
|
||||||||
| Adjusted net income attributable to common shareholders (1)(2) |
$ | 193 | $ | 224 | ||||
|
|
||||||||
| Earnings per common share – basic |
$ | 2.14 | $ | 1.32 | ||||
| Adjusted earnings per common share – basic (1)(2) |
$ | 0.79 | $ | 0.95 | ||||
|
|
||||||||
| Weighted average shares of common stock outstanding – basic (millions of shares) |
245 | 236 | ||||||
(1) See “Non-GAAP Measures” noted below
(2) Adjusted net income and adjusted earnings per common share exclude the effect of mark-to-market adjustments, gain on sale and impairment charges
After-tax mark-to-market gains decreased $56 million to $32 million in 2020 compared to $88 million in 2019, mainly due higher amortization of gas transportation assets in 2020 and larger reversal of mark-to-market losses in 2019, partially offset by changes in existing positions on gas contracts in Emera Energy. The decrease is also due to mark-to-market losses related to foreign exchange cash flow hedges entered in Q1 2020 to manage foreign exchange earnings exposure.
In Q1 2020 Emera completed the sale of Emera Maine and recorded a gain on sale of $586 million ($321 million after tax), net of transaction costs. In addition, impairment charges of $22 million ($23 million after tax) were recognized on certain other assets in Q1 2020.
Weakening of the CAD exchange rates increased earnings by $5 million and adjusted earnings by $1 million in Q1 2020 compared to Q1 2019.
Consolidated Financial Review:
The following table highlights significant changes in adjusted net income from Q1 2019 to 2020 in the first quarter.
| For the | Three months ended | |||
| millions of Canadian dollars | March 31 | |||
|
|
||||
| Adjusted net income – 2019 (1)(2) |
$ | 224 | ||
| Florida Electric Utility – increased earnings due to favourable weather, customer growth and higher contribution from solar projects | 18 | |||
| Recognition of corporate income tax recovery deferred as a regulatory liability in 2018 at BLPC |
10 | |||
| Decreased earnings at Emera Energy Services |
(9) | |||
| 2019 gain on sale of property in Florida |
(10) | |||
| Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities due to the Q1 2020 reduction in the Nova Scotia provincial corporate income tax rate | (14) | |||
| Decreased earnings from Emera Energy Generation due to the sale of New England Gas Generating Facilities (“NEGG”) and Bayside generation facilities in Q1 2019 | (24) | |||
|
|
||||
| Other variances |
(2) | |||
|
|
||||
| Adjusted net income – 2020 (1)(2) |
$ | 193 | ||
|
|
||||
(1) See “Non-GAAP Measures” noted below
(2) Excludes the effect of mark-to-market adjustments, gain on sale and impairment charges, net of tax
2
Segmented Results:
| For the | Three months ended March 31 |
|||||||
| millions of Canadian dollars (except per share amounts) | 2020 | 2019 | ||||||
|
|
||||||||
| Adjusted net income (1) |
||||||||
| Florida Electric Utility |
$ | 79 | $ | 61 | ||||
| Canadian Electric Utilities |
92 | 96 | ||||||
| Other Electric Utilities (2) |
20 | 16 | ||||||
| Gas Utilities and Infrastructure |
70 | 67 | ||||||
| Other (2) |
(68) | (16) | ||||||
|
|
||||||||
| Adjusted net income (1) |
$ | 193 | $ | 224 | ||||
|
|
||||||||
| Gain on sale and impairment charges, net of tax |
298 | - | ||||||
| After-tax mark-to-market gain |
32 | 88 | ||||||
|
|
||||||||
| Net income attributable to common shareholders |
$ | 523 | $ | 312 | ||||
|
|
||||||||
| EPS (basic) |
$ | 2.14 | $ | 1.32 | ||||
|
|
||||||||
| Adjusted EPS (basic) (1)(2) |
$ | 0.79 | $ | 0.95 | ||||
|
|
||||||||
(1) See “Non-GAAP Measures” noted below.
(2) Excludes the effect of mark-to-market adjustments, gain on sale and impairment charges, net of tax
Florida Electric Utility’s CAD net income increased by $18 million to $79 million in Q1 2020, compared to $61 million in Q1 2019 due to higher base revenues as a result of favourable weather, customer growth and the in-service of solar generation projects. This increase was partially offset by higher depreciation expense and higher interest expense as the result of higher capital investments.
Canadian Electric Utilities’ net income decreased by $4 million to $92 million, compared to $96 million in Q1 2019 due to lower contribution from NSPI. This decrease was mainly due to higher OM&G costs and lower sales volumes, primarily due to weather partially offset by regulatory deferral timing.
Other Electric Utilities’ CAD net income, adjusted to exclude mark-to-market, increased by $4 million to $20 million in Q1 2020, compared to $16 million in Q1 2019 due to the recognition of a previously deferred corporate income tax recovery related to the enactment of a lower corporate income tax rate in December 2018 at BLPC. Emera Maine contribution decreased due to unseasonably warm weather and lower regional transmission revenues.
Gas Utilities and Infrastructure’s CAD net income increased by $3 million to $70 million in Q1 2020, compared to $67 million in Q1 2019. Earnings from PGS and NMGC were consistent quarter-over-quarter as customer growth, higher return on investment in Cast Iron/Bare Steel replacement rider at PGS and lower NMGC depreciation rates were offset by warmer weather at NMGC, higher OM&G expenses, and higher depreciation at PGS.
Other’s net loss, adjusted to exclude mark-to-market, gain on sale and impairment charges, net of tax increased by $52 million to $68 million in Q1 2020, compared to $16 million in Q1 2020. due to the impact of the sale of NEGG and Bayside Power in Q1 2019, decreased marketing and trading margin, revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, the 2019 sale of property in Florida and increased OM&G in Corporate. These were partially offset by lower income taxes due to lower earnings and the impact of effective state tax rates.
Non-GAAP 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 the non-GAAP measures by adjusting certain GAAP and non-GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period. Refer to the Non-GAAP Financial Measures section of our Management’s Discussion and Analysis (“MD&A”) for further discussion of these items.
3
Forward Looking Information
This news release contains forward-looking information within the meaning of applicable securities laws. By its nature, forward-looking information requires Emera to make assumptions and is subject to inherent risks and uncertainties. These statements reflect Emera management’s current beliefs and are based on information currently available to Emera management. There is a risk that predictions, forecasts, conclusions and projections that constitute forward-looking information will not prove to be accurate, that Emera’s assumptions may not be correct and that actual results may differ materially from such forward-looking information. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Business Risks and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR at www.sedar.com.
Teleconference Call
The company will be hosting a teleconference today, May 13, 2020 at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q1 2020 financial results.
Analysts and other interested parties in North America are invited to participate by dialing 1-866-521-4909. International parties are invited to participate by dialing 1-647-427-2311. Participants should dial in at least 10 minutes prior to the start of the call. No passcode is required.
A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available two hours after the conclusion of the call until April 13, 2020, by dialing 1-800-585-8367 and entering passcode 5146398.
About Emera
Emera Inc. is a geographically diverse energy and services company headquartered in Halifax, Nova Scotia, with approximately $34 billion in assets and 2019 revenues of more than $6.1 billion. The company primarily invests in regulated electricity generation and electricity and gas transmission and distribution with a strategic focus on transformation from high carbon to low carbon energy sources. Emera has investments throughout North America, and in four Caribbean countries. Emera’s common and preferred shares are listed on the Toronto Stock Exchange and trade respectively under the symbol EMA, EMA.PR.A, EMA.PR.B, EMA.PR.C, EMA.PR.E, EMA.PR.F and EMA.PR.H. Depositary receipts representing common shares of Emera are listed on the Barbados Stock Exchange under the symbol EMABDR and on The Bahamas International Securities Exchange under the symbol EMAB. Additional Information can be accessed at www.emera.com or at www.sedar.com.
Emera Inc.
Investor Relations:
Ken McOnie, VP, Investor Relations and Treasurer
902-428-6945
ken.mconie@emera.com
Scott Hastings, Senior Director, Capital Markets
902-474-4787
scott.hastings@emera.com
Media:
902-222-2683
media@emera.com
4