6-K
Emera Inc (EMA)
UNITED STATES
SECURITIESAND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM6-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 August, 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 ofprincipal 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: August 17, 2020 | By: | \s\ Stephen D. Aftanas |
| Name: Stephen D. Aftanas | ||
| Title: Corporate Secretary |
EXHIBIT INDEX
EX-99.1
Exhibit 99.1
Management’s Discussion & Analysis
As at August 11, 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 second quarter and year-to-date of 2020 relative to the same periods in 2019; and its financial position as at June 30, 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 six months ended June 30, 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 June 30, 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<br>(“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<br>(“M&NP”) | CER and FERC |
1
On March 24, 2020, the Company completed the sale of Emera Maine. Refer to the “Significant Items Affecting 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<br> Measures | 6 |
| Consolidated Financial Review | 8 |
| Significant Items Affecting Earnings | 8 |
| Consolidated Financial Highlights by Business Segment | 8 |
| Consolidated Income Statement Highlights | 10 |
| Business Overview and Outlook | 14 |
| COVID-19 Pandemic | 14 |
| Florida Electric Utility | 16 |
| Canadian Electric Utilities | 17 |
| Other Electric Utilities | 19 |
| Gas Utilities and Infrastructure | 20 |
| Other | 21 |
| Consolidated Balance Sheet Highlights | 22 |
| Developments | 23 |
| Outstanding Stock Data | 23 |
| Financial Highlights | 24 |
| Florida Electric Utility | 24 |
| Canadian Electric Utilities | 27 |
| Other Electric Utilities | 30 |
| Gas Utilities and Infrastructure | 32 |
| Other | 34 |
| Liquidity and Capital Resources | 36 |
| Consolidated Cash Flow Highlights | 37 |
| Contractual Obligations | 39 |
| Debt Management | 40 |
| Credit Ratings | 41 |
| Guarantees and Letters of Credit | 41 |
| Transactions with Related Parties | 42 |
| Risk Management and Financial Instruments | 42 |
| Disclosure and Internal Controls | 45 |
| Critical Accounting Estimates | 45 |
| Changes in Accounting Policies and<br>Practices | 46 |
| Future Accounting Pronouncements | 47 |
| Summary of Quarterly Results | 48 |
3
FORWARD-LOOKING INFORMATION
This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, business prospects and opportunities and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “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 ANDSTRATEGIC 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 generally experienced stable regulatory policies and economic conditions.
4
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 through and beyond 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
NON-GAAP FINANCIAL MEASURES
Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates 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 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<br>Emera’s held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural<br>gas is sourced and where it is delivered; |
|---|---|
| ● | the mark-to-market adjustments included in<br>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<br>transactions; |
| --- | --- |
| ● | the mark-to-market adjustments related to<br>an interest rate swap in Brunswick Pipeline; |
| --- | --- |
| ● | the mark-to-market adjustments related to<br>equity securities held in BLPC and Emera Reinsurance, a captive reinsurance company in the Other segment; and |
| --- | --- |
| ● | the mark-to-market adjustments related to<br>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 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 Earnings” and “Developments” sections for further details related to the sale of Emera Maine. While the gain on sale has been excluded from adjusted earnings, earnings for the Other Electric Utilities segment will not include earnings from Emera Maine for the last three quarters of 2020, which were $27 million USD in 2019.
6
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<br>millions of Canadian dollars (except per share amounts) | Three months ended<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| 2020 | 2019 | 2020 | 2019 | |||||
| Net income attributable to common<br>shareholders | $ | 58 | $ | 103 | $ | 581 | $ | 415 |
| Gain on sale and impairment charges, net of<br>tax | **** | (15) | - | **** | 283 | - | ||
| After-tax<br>mark-to-market gain (loss) | **** | (45) | (27) | **** | (13) | 61 | ||
| Adjusted net income attributable to common<br>shareholders | $ | 118 | $ | 130 | $ | 311 | $ | 354 |
| Earnings per common share –<br>basic | $ | 0.24 | $ | 0.43 | $ | 2.37 | $ | 1.75 |
| Adjusted earnings per common share –<br>basic | $ | 0.48 | $ | 0.54 | $ | 1.27 | $ | 1.49 |
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 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<br>millions of Canadian dollars | Three months ended<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| 2020 | 2019 | 2020 | 2019 | |||||
| Net income (1) | $ | 81 | $ | 116 | $ | 616 | $ | 440 |
| Interest expense, net | **** | 173 | 185 | **** | 357 | 374 | ||
| Income tax expense (recovery) | **** | (1) | (15) | **** | 305 | 67 | ||
| Depreciation and amortization | **** | 216 | 228 | **** | 447 | 452 | ||
| EBITDA | **** | 469 | 514 | **** | 1,725 | 1,333 | ||
| Gain on sale and impairment charges, excluding<br>income tax | **** | (4) | - | **** | 560 | - | ||
| Mark-to-market gain (loss), excluding income tax and interest | **** | (65) | (41) | **** | (20) | 85 | ||
| Adjusted EBITDA | $ | 538 | $ | 555 | $ | 1,185 | $ | 1,248 |
(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.
7
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Earnings
Sale ofEmera Maine, 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). In Q1 2020, a gain on sale of $321 million after tax ($1.31 per common share), net of transaction costs, was recognized. Refer to the “Developments” section for further details.
In Q2 2020, an adjustment of $12 million after tax was recognized as a result of finalizing the gain calculation, such that the final year-to-date gain on sale was $309 million after tax ($1.26 per common share).
As a result of the sale, earnings contribution from Emera Maine was $12 million lower in Q2 2020 than in Q2 2019 and $16 million lower year-to-date.
In addition, impairment charges of $3 million after tax in Q2 2020 and $26 million after tax year-to-date were recognized on certain other assets.
Earnings Impact of After-Tax Mark-to-Market Gains and Losses
After-tax mark-to-market losses increased $18 million to $45 million in Q2 2020, compared to $27 million in Q2 2019. This increase was due to changes in existing positions on gas contracts and higher amortization of gas transportation assets in 2020, partially offset by gains related to foreign exchange cash flow hedges entered in 2020 to manage foreign exchange earnings exposure. Year-to-date, after-tax mark-to-market decreased $74 million to a $13 million loss in 2020, compared to a $61 million gain in 2019. This decrease was due to 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.
Q1 2019 Sale of NEGG and Bayside facilities
Earnings contribution from Emera Energy Generation was $21 million lower year-to-date than in 2019 due to the sale of the New England Gas Generating (“NEGG”) and Bayside generation facilities in March 2019.
Consolidated Financial Highlights by Business Segment
| For the<br>millions of Canadian dollars | Three months ended<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| Adjusted net income | 2020 | 2019 | 2020 | 2019 | ||||
| Florida Electric Utility | $ | 146 | $ | 125 | $ | 225 | $ | 186 |
| Canadian Electric Utilities | **** | 37 | 42 | **** | 129 | 138 | ||
| Other Electric Utilities | **** | (1) | 23 | **** | 19 | 39 | ||
| Gas Utilities and Infrastructure | **** | 27 | 40 | **** | 97 | 107 | ||
| Other | **** | (91) | (100) | **** | (159) | (116) | ||
| Adjusted net income attributable to common<br>shareholders | $ | 118 | $ | 130 | $ | 311 | $ | 354 |
| Gain on sale and impairment charges, net of<br>tax | **** | (15) | - | **** | 283 | - | ||
| After-tax<br>mark-to-market gain (loss) | **** | (45) | (27) | **** | (13) | 61 | ||
| Net income attributable to common<br>shareholders | $ | 58 | $ | 103 | $ | 581 | $ | 415 |
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The following table highlights significant changes in adjusted net income from 2019 to 2020.
| For themillions of Canadian dollars | Six months ended<br>June 30 | ||
|---|---|---|---|
| Adjusted net income – 2019 | 130 | $ | 354 |
| Increased earnings at Tampa Electric in both periods due to customer growth, increased sales to residential customers, higher allowance for funds used during construction<br>(“AFUDC”) earnings from the Big Bend modernization and solar projects, lower operating, maintenance and general (“OM&G”) expenses, in-service of solar generation and lower depreciation<br>and amortization expense as a result of a regulatory settlement. In addition, favourable weather contributed to the year-over-year increase | 21 | 39 | |
| Increased earnings at Emera Energy Services due to favourable hedges, lower fixed commitments for gas transportation and storage assets and more favourable market<br>conditions | 9 | - | |
| Decreased earnings at NSPI due to the impacts of COVID-19 on sales volumes, unfavourable weather in Q1 2020, a corporate income tax<br>recovery in Q2 2019 related to a change in legislation which impacted the timing of property, plant and equipment deductions, a higher effective tax rate and higher storm costs | (6) | (11) | |
| Timing of preferred share dividend declaration | (11) | (11) | |
| 2019 recognition of tax reform benefits from 2018 in NMGC | (12) | (12) | |
| 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<br>tax rate | - | (14) | |
| Lower earnings contribution from the Caribbean utilities in both periods due to the impacts of COVID-19 at BLPC and C and the<br>continued recovery from Hurricane Dorian at C. Year-over-over year decrease partially offset by recognition of corporate income tax recovery of 10 million deferred as a regulatory liability in 2018 at BLPC | (12) | (4) | |
| Lower earnings contribution from Emera Maine due to the sale in Q1 2020 | (12) | (16) | |
| Decreased earnings year-over-year from Emera Energy Generation due to the sale of New England Gas Generating Facilities (“NEGG”) and Bayside generation<br>facilities in March 2019 | 3 | (21) | |
| Other variances | 8 | 7 | |
| Adjusted net income – 2020 | 118 | $ | 311 |
All values are in US Dollars.
Refer to the “Financial Highlights” section for further details of reportable segment contributions.
| For the<br><br><br>millions of Canadian dollars | Six months ended June 30 | |||
|---|---|---|---|---|
| 2020 | 2019 | |||
| Operating cash flow before changes in working<br>capital | $ | 816 | $ | 775 |
| Change in working capital | **** | (75) | 32 | |
| Operating cash flow | $ | 741 | $ | 807 |
| Investing cash flow | $ | 78 | $ | (264) |
| Financing cash flow | $ | (712) | $ | (515) |
| As at | June 30 | December 31 | ||
| millions of Canadian dollars | 2020 | 2019 | ||
| Total assets | $ | 31,879 | $ | 31,842 |
| Total long-term debt (including current<br>portion) | $ | 14,304 | $ | 14,180 |
Refer to the “Consolidated Cash Flow Highlights” section for further discussion of cash flow.
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Consolidated Income Statement Highlights
| For the millions of<br>Canadian dollars (except per share amounts) | Three months ended<br>June 30 | Variance | Six months ended<br>June 30 | Variance | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2020 | 2019 | 2020 | 2019 | |||||||||
| Operating revenues | $ | 1,169 | $ | 1,378 | $ | (209) | $ | 2,806 | $ | 3,196 | $ | (390) |
| Operating expenses | **** | 980 | 1,138 | 158 | **** | 2,196 | 2,414 | 218 | ||||
| Income from operations | **** | 189 | 240 | (51) | **** | 610 | 782 | (172) | ||||
| Income from equity investments | **** | 40 | 40 | - | **** | 81 | 80 | 1 | ||||
| Other income (expenses), net | **** | 24 | 6 | 18 | **** | 587 | 19 | 568 | ||||
| Interest expense, net | **** | 173 | 185 | 12 | **** | 357 | 374 | 17 | ||||
| Income tax expense (recovery) | **** | (1) | (15) | (14) | **** | 305 | 67 | (238) | ||||
| Net income | **** | 81 | 116 | (35) | **** | 616 | 440 | 176 | ||||
| Net income attributable to common<br>shareholders | **** | 58 | 103 | (45) | **** | 581 | 415 | 166 | ||||
| Gain on sale and impairment charges, net of<br>tax | **** | (15) | - | (15) | **** | 283 | - | 283 | ||||
| After-tax<br>mark-to-market gain (loss) | **** | (45) | (27) | (18) | **** | (13) | 61 | (74) | ||||
| Adjusted net income attributable to common<br>shareholders | $ | 118 | $ | 130 | $(12) | $ | 311 | $ | 354 | $ | (43) | |
| Earnings per common share – basic | $ | 0.24 | $ | 0.43 | $ | (0.19) | $ | 2.37 | $ | 1.75 | $ | 0.62 |
| Earnings per common share – diluted | $ | 0.23 | $ | 0.43 | $ | (0.20) | $ | 2.35 | $ | 1.74 | $ | 0.61 |
| Adjusted earnings per common share –<br>basic | $ | 0.48 | $ | 0.54 | $ | (0.06) | $ | 1.27 | $ | 1.49 | $ | (0.22) |
| Dividends per common share declared | $ | 1.2250 | $ | 0.5875 | $ | 0.6375 | $ | 1.8375 | $ | 1.1750 | $ | 0.6625 |
| Adjusted EBITDA | $ | 538 | $ | 555 | $ | (17) | $ | 1,185 | $ | 1,248 | $ | (63) |
Operating Revenues
For the second quarter of 2020, operating revenues decreased $209 million compared to the second quarter in 2019. Absent increased mark-to-market losses of $48 million, operating revenues decreased $161 million due to:
| ● | $69 million decrease in the Florida Electric Utility segment due to lower clause revenues as a result of lower fuel<br>costs, partially offset by increased base revenues from customer growth, a greater mix of residential sales and the in-service of additional solar generation projects; |
|---|---|
| ● | $66 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020;<br> |
| --- | --- |
| ● | $29 million decrease in the Gas Utilities and Infrastructure segment as a result of NMGC’s recognition of tax<br>reform benefits in 2019, lower clause-related revenues and lower off-system sales at PGS, partially offset by customer growth at PGS; and |
| --- | --- |
| ● | $27 million decrease in the Other Electric Utilities segment, mainly due to lower fuel revenue as a result of lower<br>fuel prices, the impact of the COVID-19 pandemic at GBPC and BLPC, and the impact of Hurricane Dorian at GBPC. |
| --- | --- |
These impacts were partially offset by an increase of:
| ● | $15 million in marketing and trading margin at Emera Energy due to favourable hedges, lower fixed commitments and more<br>favourable market conditions. |
|---|
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Year-to-date in 2020, operating revenues decreased $390 million compared to the same period in 2019. Absent increased mark-to-market losses of $107 million, operating revenues decreased by $283 million due to:
| ● | $112 million decrease in the Other segment due to the sale of NEGG and Bayside in Q1 2019; |
|---|---|
| ● | $78 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020;<br> |
| --- | --- |
| ● | $54 million decrease in the Gas Utilities and Infrastructure segment as a result of NMGC’s recognition of tax<br>reform benefits in 2019, lower clause-related revenues and lower off-system sales at PGS, partially offset by customer growth at PGS; |
| --- | --- |
| ● | $50 million decrease at Florida Electric Utility due to lower clause revenue primarily as a result of lower fuel<br>costs, partially offset by increased base revenues from in-service of solar generation projects, customer growth, a greater mix of residential sales and favourable weather; and |
| --- | --- |
| ● | $26 million decrease in the Other Electric Utilities segment, mainly due to lower fuel revenue as a result of lower<br>fuel prices, the impact of the COVID-19 pandemic at GBPC and BLPC, and the impact of Hurricane Dorian at GBPC. |
| --- | --- |
These impacts were partially offset by an increase of:
| ● | $23 million at NSPI in the Canadian Electric Utilities segment due to the higher Maritime Link assessment included in<br>revenue compared to 2019 and increased fuel costs. This was partially offset by decreased sales volumes primarily due to the impact of the COVID-19 pandemic and weather. |
|---|
Operating Expenses
For the second quarter of 2020, operating expenses decreased $158 million compared to the second quarter of 2019. Absent increased mark-to-market gains of $3 million, operating expenses decreased $155 million due to:
| ● | $87 million decrease at Florida Electric Utility due to lower regulated fuel for generation and purchased power as a<br>result of lower natural gas prices and increased use of solar and gas generation; |
|---|---|
| ● | $47 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020; and<br> |
| --- | --- |
| ● | $16 million decrease in the Gas Utilities and Infrastructure segment due to lower regulated cost of natural gas<br>reflecting lower commodity costs at PGS and NMGC and lower volume of off-system sales at PGS. |
| --- | --- |
Year-to-date, operating expenses decreased $218 million compared to the same period of 2019. Absent decreased mark-to-market losses of $3 million, operating expenses decreased $215 million due to:
| ● | $85 million decrease at Florida Electric Utility due to lower regulated fuel for generation and purchased power as a<br>result of lower natural gas prices and increased use of solar and gas generation; |
|---|---|
| ● | $83 million decrease in the Other segment as a result of the sale of NEGG in Q1 2019; |
| --- | --- |
| ● | $53 million decrease in the Other Electric Utilities segment primarily due to the sale of Emera Maine in Q1 2020; and<br> |
| --- | --- |
| ● | $39 million decrease in the Gas Utilities and Infrastructure segment due to lower regulated cost of natural gas<br>reflecting lower commodity costs at PGS and NMGC and lower volume of off-system sales at PGS. |
| --- | --- |
11
These impacts were partially offset by an increase of:
| ● | $29 million at Canadian Electric Utilities primarily due to changes in regulatory deferrals and increased OM&G<br>expenses at NSPI. |
|---|
Other Income (Expenses), Net
The increase in other income (expenses), net for the second quarter in 2020 was primarily due to gains related to foreign exchange cash flow hedges entered in 2020 to manage foreign exchange earnings exposure. The increase year-to-date in 2020 was primarily due to the pre-tax gain on sale of Emera Maine, partially offset by impairment charges on certain other assets.
Interest Expense, Net
Interest expense, net was lower for the second quarter and year-to-date compared to 2019 due to repayment of debt and lower interest rates.
Income Tax Expense (Recovery)
The decrease in income tax recovery for the second quarter in 2020, compared to the same period in 2019 was primarily due to final adjustments related to sale of Emera Maine. The increase in income tax expense year-to-date 2020, compared to the same period in 2019, was primarily due to the gain on sale of Emera Maine and the revaluation of net deferred income tax assets resulting from 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.
Net Income and Adjusted Net Income Attributable to Common Shareholders
For the second quarter of 2020, net income attributable to common shareholders was unfavourably impacted by the $18 million increase in after-tax mark-to-market losses, primarily related to Emera Energy, and unfavourably impacted by the change in the after-tax gain on sale of Emera Maine and impairment charges. Absent the mark-to-market changes and the changes in net gain on sale of Emera Maine and impairment charges, adjusted net income attributable to common shareholders decreased $12 million. The decrease was due to lower earnings contribution from Emera Maine as a result of the sale, lower earnings contribution from the Caribbean utilities due to the impacts of COVID-19 and the recovery from Hurricane Dorian, 2019 recognition of tax reform benefits at NMGC, and timing of preferred share dividend declaration. These decreases were offset by increased contributions from Florida Electric Utility and Emera Energy Services.
Year-to-date in 2020, net income attributable to common shareholders was favourably impacted by the $309 million after-tax gain on sale of Emera Maine, and unfavourably impacted by the $74 million increase in after-tax mark-to-market losses 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, adjusted net income attributable to common shareholders decreased $43 million. The decrease was due to lower earnings contribution from Emera Maine as a result of the sale in Q1 2020, lower earnings contribution from the Caribbean utilities due to the impacts of COVID-19 and the recovery from Hurricane Dorian, lower contributions from Emera Energy (as a result of the sale of NEGG in Q1 2019), revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate, 2019 recognition of tax reform benefits in NMGC, lower earnings contribution from NSPI, timing of preferred share dividend declaration 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.
12
Earnings and Adjusted Earnings per Common Share – Basic
Earnings per common share – basic and adjusted earnings per common share – basic were lower for the second quarter due to decreased earnings as discussed above and the impact of the increase in the weighted average common shares outstanding.
Earnings per common share – basic was higher year-to-date due to increased earnings as discussed above, partially offset by impact of the increase in the weighted average common shares outstanding. Adjusted earnings per common share – basic was lower year-to-date due to decreased earnings as discussed above and the impact of the increase in the weighted average common 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 | Six months ended | Year ended | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| June 30 | June 30 | December 31 | ||||||||
| **** | 2020 | 2019 | **** | 2020 | 2019 | 2019 | ||||
| Weighted average CAD/USD exchange rate | $ | 1.39 | $ | 1.34 | $ | 1.37 | $ | 1.33 | $ | 1.33 |
| Period end CAD/USD exchange rate | $ | 1.36 | $ | 1.31 | $ | 1.36 | $ | 1.31 | $ | 1.30 |
Weakening of the CAD exchange rates increased earnings by $9 million and adjusted earnings by $3 million in Q2 2020 compared to Q2 2019. The weakening of the CAD exchange rates increased earnings by $14 million and adjusted earnings by $4 million year-to-date in 2020, compared to the same period in 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 uses 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.
13
The table below includes Emera’s significant segments whose contributions to adjusted earnings are recorded in US dollar currency.
| Three months ended | Six months ended | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| millions of US dollars | June 30 | June 30 | ||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||
| Florida Electric Utility | $ | 106 | **** | $ | 93 | $ | 165 | **** | $ | 139 | ||
| Other Electric Utilities | **** | (1 | ) | 17 | **** | 14 | **** | 29 | ||||
| Gas Utilities and Infrastructure (1) | **** | 14 | **** | 25 | **** | 59 | **** | 70 | ||||
| **** | 119 | **** | 135 | **** | 238 | **** | 238 | |||||
| Other segment (2) | **** | (40 | ) | (59 | ) | **** | (63 | ) | (75 | ) | ||
| Total (3) | $ | 79 | **** | $ | 76 | $ | 175 | **** | $ | 163 |
(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 and 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.
BUSINESS OVERVIEW AND OUTLOOK
COVID-19 Pandemic
During the three and six months ended June 30, 2020, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. Emera has experienced some reduced load and incremental operating expenses as a result of COVID-19. The impact varies by utility, however on a consolidated basis there has not been a material impact to consolidated net earnings to date, primarily due a favourable change to the mix of sales to residential customer classes. Favourable weather, in particular in Florida, has further reduced the consolidated impact. 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 and supporting the communities Emera operates in. 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 and governments and central banks are implementing measures designed to stabilize economic conditions. The pace and strength of economic recovery is uncertain and may vary among jurisdictions.
In March 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.
While there has not been a material financial impact to the Company overall to date, as expected, commercial and industrial sales are generally lower. This decrease has been partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. For the six months ended June 30, 2020, on a consolidated basis, the Company has not incurred a significant amount of incremental costs as a result of the pandemic and no costs have been deferred.
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Emera’s utilities are working with customers on relief initiatives in response to the effect of the pandemic on customers’ ability to pay and their need for continued service. To date, these initiatives include the temporary suspension of disconnection for non-payment of bills and the development of payment arrangements where necessary. In Q2 2020, the Company’s utilities experienced an increase in the aging of customer receivables resulting from the suspension of disconnections. To date, there have been no significant customer defaults as a result of bankruptcies with many secured by deposits. As of June 30, 2020, adjustments to the allowance for doubtful accounts have not had a significant impact on earnings. The full impact of potential credit losses due to customer non-payment is not known at this time. The utilities are continuing to monitor customer accounts and are continuing to work with customers on payment arrangements. Many of Emera’s utilities expect to end their temporary suspension of disconnections for non-payment in Q3 2020.
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. In Q1, 2020, the Company 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 continued economic slowdowns and the pace and strength of economic<br>recovery; |
|---|---|
| ● | Delays of capital projects as a result of construction shutdowns, government restrictions on<br>non-essential capital work, travel restrictions for contractors or supply chain disruptions. Capital project delays and supply chain disruptions 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 or increased credit<br>losses. |
| --- | --- |
Refer to the outlook sections by segment below for 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.
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Florida Electric Utility
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. An increase in residential sales and favourable weather in the first half of 2020 have more than offset the impacts of a decrease in other revenue classes as a result of COVID-19. The number of customers increased by 2 per cent from June 30, 2019. Tampa Electric’s volumes could be negatively impacted by declines in future economic activity in Florida due to COVID-19 impacts, resulting in overall sales volumes for the year being similar or slightly lower than in 2019. 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 (“SPP”) 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. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million USD base rate reduction for costs previously recovered in base rates related to SPP programs beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 million USD in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million USD of costs reduced from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery will begin in January 2021. Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025.
The June 9, 2020 settlement agreement approved by the FPSC disclosed above also included approval of Tampa Electric’s petition to eliminate its $16 million USD accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020. As stipulated in the settlement, $8 million USD of this credit was recognized in Q2 2020 with the remaining $8 million USD to be recognized over the remainder of 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 was effective beginning with June 2020 customer bills and will result in lower fuel and capacity clause rates to customers for the remainder of 2020, including an acceleration of the return of these savings in the three months starting June 2020.
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 remains 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”).
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Canadian Electric Utilities
Canadian Electric Utilities includes:
| ● | NSPI, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of<br>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<br>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<br>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<br>project is complete. |
| --- | --- |
| ● | Construction of the LIL is complete and Nalcor Energy (“Nalcor”) recognized the first flow of energy from<br>Labrador to Newfoundland in June 2018. Nalcor has resumed its work towards commissioning the LIL after a temporary suspension of work, in March 2020, in response to the COVID-19 pandemic.<br> |
| --- | --- |
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 and due to unfavourable weather year-to-date. In the first half of 2020, absent the impact of weather, NSPI has experienced a decrease in sales volumes in the commercial and industrial classes, partially offset by an increase in residential sales volumes, which have a higher contribution to fixed cost recovery. NSPI anticipates the overall decrease in sales volumes to continue throughout 2020 depending on the pace of economic recovery. The 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. Currently, 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.
17
On March 17, 2020, Nalcor announced that it had paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. Nalcor resumed work in May 2020 and is assessing the impact of the construction pause on its completion schedule. Refer to the “ENL – Impact of COVID-19 on Muskrat Falls and LIL” section below for further details. NSPI’s ability to achieve the provincially legislated target of 40 per cent electricity generated from renewable sources in 2020 will be impacted should there be a delay in the delivery of the NS Block beyond 2020. On May 15, 2020, the provincial government provided NSPI with an alternative compliance plan if the Company is unable to meet the provincially legislated target. The alternative compliance plan requires NSPI to supply customers with at least 40 per cent of energy generated from renewable sources over the 2020 to 2022 three-year period. NSPI expects to achieve this alternative compliance standard.
As a result of the measures taken to limit the spread of COVID-19, NSPI’s forecasted 2020 capital investments was decreased from $375 million to approximately $305 million. The remaining $70 million of capital investments will be deferred to 2021 and 2022. Capital investment in 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, on July 31, 2020, NSPML filed an interim assessment application with the UARB requesting recovery of 2021 costs of approximately $172 million from NSPI.
In 2020, NSPML expects to invest approximately $10 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 $603 million, comprised of $410 million in equity contribution and $193 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.
18
Impact of COVID-19 on Muskrat Falls and LIL
On March 17, 2020, Nalcor announced that it had 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 declared force majeure under various project contracts, including formal notification to NSPML. Nalcor resumed work in May 2020 and is assessing the impact of the construction pause on its completion schedule.
Other Electric Utilities
Other Electric Utilities includes:
| ● | Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities, BLPC, a vertically<br>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<br> |
| --- | --- |
| ● | a 19.5 per cent interest in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia.<br> |
| --- | --- |
| ● | Emera Maine, a regulated transmission and distribution electric utility in the state of Maine. On March 24, 2020,<br>Emera completed the sale of Emera Maine. Refer to the “Developments” section for further details. |
| --- | --- |
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 which depend heavily on tourism. Tourism and associated support businesses have been significantly impacted by the suspension of international travel. Travel restrictions are gradually being eased but the strength and pace of recovery of the tourism sector is uncertain. 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.
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 June 30, 2020, $14 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. This recovery is now expected to start on October 1, 2020.
In 2020, capital expenditures in the Other Electric Utilities segment are forecasted to be approximately $135 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 33 MW diesel engine installation, expected in mid-2020, was temporarily delayed as a result of government-imposed travel restrictions and is now targeted for the end of 2020.
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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<br>in Florida; |
|---|---|
| ● | NMGC, a regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas<br>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. 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 in support of reliability and overall system growth. In addition, 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 decreased as a result of the impact of government measures on commercial customers and reduced tourism. Therefore, as a result of forecasted revenue requirements being higher than what is in current rates, on June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. The new rates would be expected to result in an increase in revenue of approximately $62 million USD annually.
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 $630 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 $105 million USD and $32 million USD, respectively.
20
Other
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;<br> |
|---|---|
| ● | Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass<br>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<br>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. Absent this gain and impairment losses recognized in 2020, the adjusted net loss from the Other segment is expected to decrease over the prior year. This decrease is primarily due to lower interest expense and increased EES contribution, partially offset by decreased tax recoveries. 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.
In 2020, capital expenditures in the Other segment are expected to be approximately $40 million (2019 - $63 million).
21
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2019 and June 30, 2020 include:
| millions of Canadian dollars | Increase<br>(Decrease) | Explanation | |
|---|---|---|---|
| Assets | |||
| Cash and cash equivalents | $ | 63 | Increased due to proceeds on the sale of Emera Maine and cash from operations. This was partially offset by additions of property, plant and equipment, repayment of<br>Emera’s committed credit facilities, net repayment of debt at TECO Finance and Tampa Electric and dividends on common stock. |
| Receivables and other assets (current and long-term) | **** | (142) | Decreased due to lower gas transportation assets at Emera Energy, lower commodity prices and volumes at Emera Energy and a refund of prior year income taxes receivable at<br>NSPI. This was partially offset by the reclassification of corporate alternative minimum tax carryforwards from deferred income tax liabilities and the effect of a weaker CAD on the translation of Emera’s foreign affiliates. |
| Assets held for sale (current and long-term), net of liabilities | **** | (691) | Decreased due to completion of the sale of Emera Maine. |
| Property, plant and equipment, net of accumulated depreciation and amortization | **** | 1,496 | 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 | **** | 287 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates. |
| Liabilities and Equity | |||
| Accounts payable | **** | (122) | Decreased due to lower commodity prices and volumes at Emera Energy and NMGC, and timing of payments at NSPI. This was partially offset by the effect of a weaker CAD on the<br>translation of Emera’s foreign affiliates. |
| Deferred income tax liabilities, net of deferred income tax assets | **** | 298 | 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<br>property, plant and equipment and the effect of a weaker CAD on the translation of Emera’s foreign subsidiaries. The increase was partially offset by the revaluation of net deferred income tax liabilities resulting from enactment of a lower<br>Nova Scotia provincial corporate income tax rate in Q1 2020. |
| Derivative instruments (current and long-term) | **** | (99) | Decreased due to reversal of 2019 contracts, partially offset by new contracts at Emera Energy. |
| Regulatory liabilities (current and long-term) | **** | 90 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates. |
| Other liabilities (current and long-term) | **** | 239 | Increased due to the timing of Emera’s dividend payments, investment tax credits related to solar projects at Tampa Electric and the effect of a weaker CAD on the<br>translation of Emera’s foreign affiliates. |
| Common stock | **** | 219 | Increased due to shares issued under Emera’s at-the-market equity plan, stock options<br>exercised and the dividend reinvestment plan. |
| Accumulated other comprehensive income | **** | 318 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates. |
| Retained earnings | **** | 125 | Increased due to the gain on sale of Emera Maine and net income in excess of dividends paid. |
22
DEVELOPMENTS
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 $321 million after tax, net of transaction costs, was recognized in the Other segment. In Q2 2020, an adjustment of $12 million after tax was recognized as a result of finalizing the gain calculation, including the finalization of working capital adjustments, such that the final year-to-date gain on the sale of Emera Maine was $309 million after tax. 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.
Appointments
Executive
Effective June 1, 2020, Rick Janega was appointed interim President and CEO of NSPI. Mr. Janega is also currently Emera’s Chief Operating Officer, Electric Utilities, Canada US Northeast and Caribbean, and Chief Executive Officer of ENL.
OUTSTANDING STOCK DATA
Common stock
| Issued and outstanding: | millions of<br>shares | millions of Canadian<br>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<br>rate | 3.99 | 202 | |||
| Discount on shares purchased under Dividend<br>Reinvestment Plan | - | (7 | ) | ||
| Options exercised under senior management stock<br>option plan | 2.57 | 104 | |||
| Employee Share Purchase Plan | - | 1 | |||
| Balance, December 31, 2019 | 242.48 | $ | 6,216 | ||
| Issuance of common stock (1) | 1.73 | 99 | |||
| Issued for cash under Purchase Plans at market<br>rate | 1.81 | 101 | |||
| Discount on shares purchased under Dividend<br>Reinvestment Plan | - | (2 | ) | ||
| Options exercised under senior management stock<br>option plan | 0.42 | 20 | |||
| Employee Share Purchase Plan | - | 1 | |||
| Balance, June 30, 2020 | **** | 246.44 | $ | 6,435 | **** |
(1) In Q2 2020, 745,121 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $55.33 per share for gross proceeds of $41.2 million ($40.7 million net of issuance costs). During the six months ended June 30, 2020, 1,728,103 common shares were issued under Emera’s ATM program at an average price of $57.87 per share for gross proceeds of $100 million ($98.7 million net of issuance costs). As at June 30, 2020, an aggregate gross sales limit of $400 million remains available for issuance under the ATM program.
As at August 7, 2020, the amount of issued and outstanding common shares was 246.6 million.
23
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 June 30, 2020 was 246.7 million (2019 – 239.2 million) and for the six months ended June 30, 2020 was 245.7 million (2019 – 237.8 million).
Cumulative Preferred Stock
For details regarding cumulative preferred stock refer to note 27 in Emera’s 2019 annual audited financial statements, with updates as noted below:
On July 9, 2020, Emera announced that it would not redeem the currently outstanding Cumulative Rate Reset Preferred Shares, Series A (“Series A Shares”) or the Cumulative Floating Rate First Preferred Shares, Series B (“Series B Shares”) on August 15, 2020 (the “Conversion Date”). There are currently 3,864,636 Series A Shares and 2,135,364 Series B Shares outstanding.
On July 16, 2020, Emera announced a dividend rate of 2.182 per cent per annum on the Series A Shares during the five-year period commencing on August 15, 2020 and ending on (and inclusive of) August 14, 2025 ($0.1364 per Series A Share per quarter). Emera also announced a dividend rate of 2.021 per cent on the Series B Shares for the three-month period commencing on August 15, 2020 and ending on (and inclusive of) November 14, 2020 ($0.1274 per Series B Share for the quarter).
During the conversion period between July 16, 2020 and July 31, 2020, the holders of Series A Shares had the right, at their option to convert all or any of their Series A Shares, on a one-for-one basis, into Series B Shares and the holders of Series B Shares had the right, at their option to convert all or any of their Series B Shares, on a one-for-one basis, into Series A Shares. On the Conversion Date, Emera expects that there will be 4,866,814 Series A Shares and 1,133,186 Series B Shares outstanding.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
All amounts are reported in USD, unless otherwise stated.
| For the<br> <br>millions of<br>US dollars (except per share amounts) | Three months ended<br>June 30 | Six months ended<br><br><br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| 2020 | 2019 | 2020 | 2019 | |||||
| Operating revenues – regulated<br>electric | $ | 454 | $ | 521 | $ | 875 | $ | 933 |
| Regulated fuel for generation and purchased<br>power | **** | 93 | 156 | **** | 199 | 271 | ||
| Contribution to consolidated net income | $ | 106 | $ | 93 | $ | 165 | $ | 139 |
| Contribution to consolidated net income –<br>CAD | $ | 146 | $ | 125 | $ | 225 | $ | 186 |
| Contribution to consolidated earnings per common<br>share – basic – CAD | $ | 0.59 | $ | 0.52 | $ | 0.92 | $ | 0.78 |
| Net income weighted average foreign exchange rate<br>– CAD/USD | $ | 1.38 | $ | 1.34 | $ | 1.37 | $ | 1.34 |
| EBITDA | $ | 236 | $ | 226 | $ | 420 | $ | 392 |
| EBITDA – CAD | $ | 326 | $ | 301 | $ | 574 | $ | 522 |
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Net Income
Highlights of the net income changes are summarized in the following table:
| For the<br>millions of US dollars | ||
|---|---|---|
| Contribution to consolidated net income –<br>2019 | 93 | $ 139 |
| Decreased operating revenues - see Operating<br>Revenues - Regulated Electric below | (67) | (58) |
| Decreased fuel for generation and purchased<br>power - see Regulated Fuel for Generation and Purchased Power below | 63 | 72 |
| Decreased OM&G expenses | 8 | 6 |
| Decreased depreciation and amortization due to<br>8 million credit to amortization expense recognized in Q2 2020 for Tampa Electric’s accumulated amortization<br>reserve surplus for intangible software assets offset by increased depreciation due<br>to increased property, plant and equipment | 3 | (1) |
| Increased other income as a result of higher<br>AFUDC earnings due to the Big Bend Power Station modernization and solar projects | 3 | 6 |
| Other | 3 | 1 |
| Contribution to consolidated net income<br>– 2020 | 106 | $ 165 |
All values are in US Dollars.
Florida Electric Utility’s CAD contribution to consolidated net income increased $21 million in Q2 2020, compared to Q2 2019. Earnings increased due to higher AFUDC earnings as a result of the Big Bend modernization and solar projects, lower OM&G expenses, higher base revenues and lower depreciation and amortization expense. Operating revenues decreased due to lower clause revenues, however, base revenues increased as a result of customer growth, a greater mix of sales to residential customers and the in-service of solar generation projects.
Year-to-date, Florida Electric Utility’s CAD contribution to consolidated net income increased $39 million in 2020. Earnings increased due to higher base revenues, higher AFUDC earnings and lower OM&G expenses. Operating revenues decreased due to lower clause revenues, however, base revenues increased as a result of the in-service of solar generation projects, customer growth, a greater mix of residential sales and favourable weather.
The impact of the change in the foreign exchange rate increased CAD earnings for the three and six months ended June 30, 2020 by $5 million and $6 million, respectively.
Operating Revenues – Regulated Electric
Electric revenues decreased $67 million to $454 million in Q2 2020, compared to $521 million in Q2 2019 due to lower clause revenues as a result of a decrease in fuel cost, partially offset by increased base revenues from customer growth, a greater mix of residential sales and the in-service of additional solar generation projects.
Year-to-date, electric revenues decreased $58 million to $875 million in 2020, compared to $933 million for the same period in 2019 due to lower clause revenue primarily as a result of a decrease in fuel cost and lower other operating revenues as a result of fewer reconnection fees from the suspension of disconnects for non-payment of bills. The year-to-date decrease in revenues was partially offset by increased base revenues from in-service of solar generation projects, customer growth, a greater mix of residential sales and favourable weather.
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Electric revenues and sales volumes are summarized in the following tables by customer class:
| Q2 Electric Revenues<br><br><br>millions of US dollars | ||||
|---|---|---|---|---|
| 2020 | 2019 | |||
| Residential | $ | 254 | $ | 261 |
| Commercial | **** | 121 | 141 | |
| Industrial | **** | 32 | 42 | |
| Other (1) | **** | 47 | 77 | |
| Total | $ | 454 | $ | 521 |
(1) Other includes sales to public authorities, off-system sales to other utilities, unbilled revenues and regulatory deferrals related to clauses.
| YTD Electric Revenues<br><br><br>millions of US dollars | ||||
|---|---|---|---|---|
| 2020 | 2019 | |||
| Residential | $ | 459 | $ | 467 |
| Commercial | **** | 246 | 261 | |
| Industrial | **** | 69 | 76 | |
| Other (1) | **** | 101 | 129 | |
| Total | $ | 875 | $ | 933 |
(1) Other includes sales to public authorities, off-system sales to other utilities, unbilled revenues and regulatory deferrals related to clauses.
| Q2 Electric Sales Volumes (1)<br><br><br>Gigawatt hours (“GWh”) | ||
|---|---|---|
| 2020 | 2019 | |
| Residential | 2,518 | 2,366 |
| Commercial | 1,431 | 1,543 |
| Industrial | 452 | 539 |
| Other | 450 | 506 |
| Total | 4,851 | 4,954 |
(1) Electric sales volumes are calculated based on billed hours only. GWh related to unbilled revenues are excluded.
| YTD Electric Sales Volumes (1)<br><br><br>GWh | ||
|---|---|---|
| 2020 | 2019 | |
| Residential | 4,398 | 4,305 |
| Commercial | 2,804 | 2,913 |
| Industrial | 949 | 1,001 |
| Other | 916 | 967 |
| Total | 9,067 | 9,186 |
(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 $63 million to $93 million in Q2 2020, compared to $156 million in Q2 2019. Year-to-date, regulated fuel for generation and purchased power decreased $72 million to $199 million in 2020, compared to $271 million in the same period in 2019. The decrease in both periods was due to lower natural gas prices and increased use of zero fuel cost solar generation.
| Q2 Production Volumes<br><br><br>GWh **** | ||||
|---|---|---|---|---|
| 2020 | 2019 | |||
| Natural gas | 4,150 | 4,665 | ||
| Coal | 78 | 364 | ||
| Solar | 350 | 225 | ||
| Purchased power | 820 | 328 | ||
| Total | 5,398 | 5,582 | ||
| YTD Production Volumes<br><br><br>GWh **** | ||||
| --- | --- | --- | ||
| 2020 | 2019 | |||
| Natural gas | 8,255 | 8,433 | ||
| Coal | 259 | 672 | ||
| Solar | 584 | 377 | ||
| Purchased power | 856 | 423 | ||
| Total | 9,954 | 9,905 | ||
| Q2 Average Fuel Costs | ||||
| --- | --- | --- | --- | --- |
| US dollars | 2020 | 2019 | ||
| Dollars per Megawatt hour<br>(“MWh”) | $ | 17 | $ | 28 |
| YTD Average Fuel Costs | ||||
| --- | --- | --- | --- | --- |
| US dollars | 2020 | 2019 | ||
| Dollars per MWh | $ | 20 | $ | 27 |
Average fuel cost per MWh decreased in Q2 2020 and year-to-date, compared to the same periods in 2019, primarily due to increased use of lower-cost natural gas and zero fuel cost solar generation.
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Canadian Electric Utilities
| For the<br> <br>millions of Canadian dollars (except per share<br>amounts) | Three months ended<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| Operating revenues – regulated electric | $ | 335 | $ | 327 | $ | 793 | $ | 770 |
| Regulated fuel for generation and purchased power (1) | **** | 146 | 141 | **** | 340 | 333 | ||
| Income from equity investments | **** | 24 | 23 | **** | 51 | 48 | ||
| Contribution to consolidated net income | $ | 37 | $ | 42 | $ | 129 | $ | 138 |
| Contribution to consolidated earnings per common share –<br>basic | $ | 0.15 | $ | 0.18 | $ | 0.53 | $ | 0.58 |
| EBITDA | $ | 134 | $ | 128 | $ | 327 | $ | 324 |
(1) Regulated fuel for generation and purchased power includes NSPI’s FAM and fixed cost deferrals on the Condensed Consolidated Statements of Income, however it is excluded in the segment overview.
Canadian Electric Utilities’ contribution is summarized in the following table:
| For the<br> <br>millions of Canadian dollars | Three months ended<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| NSPI | $ | 13 | $ | 19 | $ | 78 | $ | 90 |
| Equity investment in NSPML | **** | 12 | 12 | **** | 27 | 26 | ||
| Equity investment in LIL | **** | 12 | 11 | **** | 24 | 22 | ||
| Contribution to consolidated net income | $ | 37 | $ | 42 | $ | 129 | $ | 138 |
Net Income
Highlights of the net income changes are summarized in the following table:
| For the<br> <br>millions of Canadian dollars | Three months ended<br>June 30 | Six months ended<br>June 30 | ||
|---|---|---|---|---|
| Contribution to consolidated net income – 2019 | $ | 42 | $ | 138 |
| Increased operating revenues - see Operating Revenues – Regulated Electric below | 8 | 23 | ||
| Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power<br>below | (5) | (7) | ||
| Increased FAM and fixed cost deferrals year-over-year primarily due to the refund to customers of prior<br>years’ over-recovery of fuel costs partially offset by the over-recovery of current period fuel costs | 2 | (12) | ||
| Increased OM&G expenses primarily due to higher storm restoration costs, higher costs for information<br>technology, lower administrative overhead allocated to property, plant and equipment, COVID-19 pandemic response costs, community support contributions and an increased allowance for doubtful accounts. These<br>increases were partially offset by lower costs for power generation, vegetation management and lower demand side management (“DSM”) program costs | (1) | (6) | ||
| Q2 2019 corporate income tax recovery due to enactment of tax legislation related to timing of deductions of<br>property, plant and equipment | (8) | - | ||
| Increased income taxes primarily due to lower tax deductions in excess of accounting depreciation related to<br>property, plant and equipment | (3) | (11) | ||
| Other | 2 | 4 | ||
| Contribution to consolidated net income – 2020 | $ | 37 | $ | 129 |
27
Canadian Electric Utilities’ contribution to consolidated net income decreased in Q2 2020 and year-to-date due to lower contribution from NSPI. Quarter-to-date, the decrease was due to the impacts of COVID-19 on sales volumes, increased income taxes reflecting a Q2 2019 corporate income tax recovery due to enactment of tax legislation and a higher effective tax rate, and higher storm costs, partially offset by regulatory deferral timing. Year-to-date, the decrease was due to the impacts of COVID-19 and unfavourable weather on sales volumes, increased income taxes reflecting a higher effective tax rate, and higher storm costs, partially offset by regulatory deferral timing. The timing of regulatory deferrals causes quarterly earnings volatility, while full year results are more predictable.
NSPI
Operating Revenues –Regulated Electric
Operating revenues increased $8 million to $335 million in Q2 2020, compared to $327 million in Q2 2019 Year-to-date operating revenues increased $23 million to $793 million compared to $770 million for the same period in 2019. The increase in both periods was due to higher Maritime Link assessment included in revenue compared to 2019, increased fuel-related pricing, and increased residential class sales volume growth. This was partially offset by decreased commercial, industrial and other class sales volumes due to the impact of the COVID-19 pandemic. Year-to-date, sales volumes also decreased due to weather.
Electric revenues and sales volumes are summarized in the following tables by customer class:
| Q2 Electric Revenues<br><br><br>millions of Canadian dollars | ||||
|---|---|---|---|---|
| 2020 | 2019 | |||
| Residential | $ | 182 | $ | 165 |
| Commercial | **** | 90 | 94 | |
| Industrial | **** | 51 | 53 | |
| Other | **** | 6 | 8 | |
| Total | $ | 329 | $ | 320 |
| YTD Electric Revenues<br><br><br>millions of Canadian dollars | ||||
| --- | --- | --- | --- | --- |
| 2020 | 2019 | |||
| Residential | $ | 446 | $ | 417 |
| Commercial | **** | 210 | 207 | |
| Industrial | **** | 107 | 108 | |
| Other | **** | 17 | 24 | |
| Total | $ | 780 | $ | 756 |
| Q2 Electric Sales Volumes<br><br><br>GWh | ||||
| --- | --- | --- | ||
| 2020 | 2019 | |||
| Residential | 1,035 | 1,023 | ||
| Commercial | 621 | 714 | ||
| Industrial | 510 | 591 | ||
| Other | 36 | 57 | ||
| Total | 2,202 | 2,385 | ||
| YTD Electric Sales Volumes<br><br><br>GWh | ||||
| --- | --- | --- | ||
| 2020 | 2019 | |||
| Residential | 2,595 | 2,644 | ||
| Commercial | 1,481 | 1,598 | ||
| Industrial | 1,098 | 1,188 | ||
| Other | 112 | 200 | ||
| Total | 5,286 | 5,630 |
Regulated Fuel for Generation and Purchased Power
Regulated fuel for generation and purchased power increased $5 million to $146 million in Q2 2020 compared to $141 million in Q2 2019. Year-to-date regulated fuel for generation and purchased power increased $7 million to $340 million compared to $333 million in the same period in 2019. The increase was primarily due to a change in generation mix, partially offset by decreased sales volumes.
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| Q2 Production Volumes<br><br><br>GWh | ||||
|---|---|---|---|---|
| 2020 | 2019 | |||
| Coal | **** | 549 | 787 | |
| Natural gas | **** | 552 | 352 | |
| Oil and petcoke | **** | 264 | 313 | |
| Purchased power – other | **** | 195 | 229 | |
| Total non-renewables | **** | 1,560 | 1,681 | |
| Wind and hydro | **** | 319 | 410 | |
| Purchased power – Independent Power<br>Producers (“IPP”) | **** | 309 | 266 | |
| Purchased power – Community Feed-in Tariff<br>program (“COMFIT”) | **** | 146 | 130 | |
| Biomass | **** | 30 | 30 | |
| Total renewables | **** | 804 | 836 | |
| Total production volumes | **** | 2,364 | 2,517 | |
| YTD Production Volumes<br><br><br>GWh | ||||
| --- | --- | --- | --- | --- |
| 2020 | 2019 | |||
| Coal | **** | 2,144 | 2,633 | |
| Natural gas | **** | 1,026 | 596 | |
| Oil and petcoke | **** | 546 | 628 | |
| Purchased power – other | **** | 314 | 370 | |
| Total non-renewables | **** | 4,030 | 4,227 | |
| Wind and hydro | **** | 660 | 781 | |
| Purchased power – IPP | **** | 644 | 636 | |
| Purchased power – COMFIT | **** | 293 | 293 | |
| Biomass | **** | 41 | 45 | |
| Total renewables | **** | 1,638 | 1,755 | |
| Total production volumes | **** | 5,668 | 5,982 | |
| Q2 Average Fuel Costs | ||||
| --- | --- | --- | --- | --- |
| 2020 | 2019 | |||
| Dollars per MWh | **** | 62 | 56 | |
| YTD Average Fuel Costs | ||||
| --- | --- | --- | --- | --- |
| 2020 | 2019 | |||
| Dollars per MWh | **** | 60 | 56 |
Average fuel cost per MWh increased in Q2 2020 and year-to-date, compared to the same periods in 2019 primarily due to a change in generation mix resulting in higher natural gas consumption and lower generation from NSPI-owned hydro and wind, which have no fuel cost component. This was partially offset by lower generation from solid fuel and a decrease in purchased power.
NSPI’s FAM regulatory liability balance decreased $9 million from $115 million at December 31, 2019 to $106 million at June 30, 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.
29
Other Electric Utilities
All amounts are reported in USD, unless otherwise stated.
On March 24, 2020, Emera completed the sale of Emera Maine. Refer to the “Significant Items Affecting Earnings” and “Developments” sections for further details.
| Three months ended | Six months ended | |||||||
|---|---|---|---|---|---|---|---|---|
| For the | June 30 | June 30 | ||||||
| millions of US dollars (except per share<br>amounts) | **** | 2020 | 2019 | **** | 2020 | 2019 | ||
| Operating revenues – regulated<br>electric | $ | 69 | $ | 141 | $ | 196 | $ | 277 |
| Regulated fuel for generation and purchased power<br>(1) | **** | 27 | 54 | **** | 77 | 103 | ||
| Adjusted contribution to consolidated net<br>income | $ | (1) | $ | 17 | $ | 14 | $ | 29 |
| Adjusted contribution to consolidated net income<br>– CAD | $ | (1) | $ | 23 | $ | 19 | $ | 39 |
| After-tax<br>equity securities mark-to-market gain (loss) | **** | 2 | 1 | **** | - | 2 | ||
| Contribution to consolidated net income | $ | 1 | $ | 18 | $ | 14 | $ | 31 |
| Contribution to consolidated net income –<br>CAD | $ | 2 | $ | 23 | $ | 19 | $ | 41 |
| Adjusted contribution to consolidated earnings per common share – basic – CAD | $ | - | $ | 0.10 | $ | 0.08 | $ | 0.16 |
| Contribution to consolidated earnings per common<br>share – basic – CAD | $ | 0.01 | $ | 0.10 | $ | 0.08 | $ | 0.17 |
| Net income weighted average foreign exchange rate<br>– CAD/USD | $ | 1.39 | $ | 1.32 | $ | 1.37 | $ | 1.32 |
| Adjusted EBITDA | $ | 16 | $ | 50 | $ | 56 | $ | 97 |
| Adjusted EBITDA – CAD | $ | 22 | $ | 68 | $ | 76 | $ | 130 |
(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 | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of US dollars | June 30 | June 30 | ||||||
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| Emera Maine | $ | - | $ | 9 | $ | 4 | $ | 17 |
| ECI | **** | (1) | 8 | **** | 10 | 12 | ||
| Adjusted contribution to consolidated netincome | $ | (1) | $ | 17 | $ | 14 | $ | 29 |
Net Income
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Six months ended | ||
|---|---|---|---|---|
| millions of US dollars | June 30 | June 30 | ||
| Contribution to consolidated net income –<br>2019 | $ | 18 | $ | 31 |
| Decreased operating revenues - see Operating Revenues - Regulated Electric below | (23) | (23) | ||
| Regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below | 18 | 16 | ||
| Increased income tax recovery primarily due to recognition of a previously deferred corporate income tax recovery related to enactment of a lower corporate income tax rate<br>in December 2018 at BLPC | - | 7 | ||
| Impact of sale of Emera Maine, net of<br>tax | (9) | (13) | ||
| Other | (3) | (4) | ||
| Contribution to consolidated net income –2020 | $ | 1 | $ | 14 |
30
Excluding the change in mark-to-market, Other Electric Utilities CAD contribution to consolidated net income decreased $24 million in Q2 2020, compared to Q2 2019. Year-to-date, the CAD contribution decreased $20 million compared to 2019. Lower contribution from Emera Maine as a result of the sale in Q1 2020 decreased earnings in both periods. ECI’s contribution decreased in both periods as a result of lower revenue at GBPC and BLPC due to the impact of the COVID-19 pandemic and lower revenue at GBPC due to the impact of Hurricane Dorian. Year-to-date, the decrease was partially offset by recognition of a previously deferred corporate income tax recovery related to enactment of a lower corporate income tax rate in December 2018 at BLPC.
The foreign exchange rate had minimal impact for the three months ended June 30 and year-to-date 2020.
Operating Revenues – Regulated Electric
Operating revenues decreased $72 million to $69 million in Q2 2020, compared to $141 million in Q2 2019. Year-to-date revenues decreased $81 million to $196 million compared to $277 million in the same period in 2019. The decreases in both periods were as a result of the sale of Emera Maine in Q1 2020, lower fuel revenue as a result of lower fuel prices, the impact of the COVID-19 pandemic at GBPC and BLPC on commercial customers, and the impact of Hurricane Dorian at GBPC.
Electric revenues and sales volumes for ECI’s utilities are summarized in the following tables by customer class:
Q2 Electric Revenues
millions of USD
| 2020 | 2019 | |||
|---|---|---|---|---|
| Residential | $ | 26 | $ | 30 |
| Commercial | **** | 34 | 54 | |
| Industrial | **** | 5 | 5 | |
| Other | **** | 4 | 4 | |
| Total | $ | 69 | $ | 93 |
YTD Electric Revenues
millions of USD
| 2020 | 2019 | |||
|---|---|---|---|---|
| Residential | $ | 53 | $ | 57 |
| Commercial | **** | 81 | 99 | |
| Industrial | **** | 11 | 11 | |
| Other | **** | 7 | 7 | |
| Total | $ | 152 | $ | 174 |
Q2 Electric Sales Volumes
| GWh | 2020 | 2019 | ||
|---|---|---|---|---|
| Residential | **** | 122 | 118 | |
| Commercial | **** | 144 | 191 | |
| Industrial | **** | 19 | 21 | |
| Other | **** | 5 | 4 | |
| Total | **** | 290 | 334 |
YTD Electric Sales Volumes
| GWh | 2020 | 2019 | ||
|---|---|---|---|---|
| Residential | **** | 232 | 225 | |
| Commercial | **** | 317 | 366 | |
| Industrial | **** | 42 | 44 | |
| Other | **** | 10 | 8 | |
| Total | **** | 601 | 643 |
Regulated Fuel for Generation and Purchased Power
Regulated fuel for generation and purchased power decreased $27 million to $27 million in Q2 2020, compared to $54 million in Q2 2019. Year-to-date, regulated fuel for generation and purchased power decreased $26 million to $77 million compared to $103 million in the same period in 2019. These decreases in both periods were as a result of the sale of Emera Maine in Q1 2020 and lower fuel costs at BLPC.
31
Production volumes and average fuel costs for ECI’s utilities are summarized in the following tables:
| Q2 Production Volumes | ||||
|---|---|---|---|---|
| GWh | ||||
| 2020 | 2019 | |||
| Oil | **** | 291 | 343 | |
| Hydro | **** | 4 | 6 | |
| Solar | **** | 3 | 4 | |
| Purchased power | **** | 14 | 8 | |
| Total | **** | 312 | 361 | |
| Q2 Average Fuel Costs | ||||
| US dollars | 2020 | 2019 | ||
| Dollars per MWh | **** | 87 | 123 | |
| YTD Production Volumes | ||||
| --- | --- | --- | --- | --- |
| GWh | ||||
| 2020 | 2019 | |||
| Oil | **** | 602 | 662 | |
| Hydro | **** | 8 | 10 | |
| Solar | **** | 8 | 9 | |
| Purchased power | **** | 25 | 16 | |
| Total | **** | 643 | 697 | |
| YTD Average Fuel Costs | ||||
| US dollars | 2020 | 2019 | ||
| Dollars per MWh | **** | 105 | 120 |
Average fuel cost per MWh decreased in Q2 2020 and year-to-date, compared to the same periods in 2019, due to lower oil prices.
Gas Utilities and Infrastructure
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of US dollars (except per share amounts) | June 30 | June 30 | ||||||
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| Operating revenues – regulated gas<br>(1) | $ | 150 | $ | 179 | $ | 400 | $ | 448 |
| Operating revenues – non-regulated | **** | 3 | 3 | **** | 6 | 6 | ||
| Total operating revenue | $ | 153 | $ | 182 | $ | 406 | $ | 454 |
| Regulated cost of natural gas | **** | 30 | 45 | **** | 111 | 148 | ||
| Income from equity investments | **** | 4 | 5 | **** | 7 | 10 | ||
| Contribution to consolidated net income | $ | 18 | $ | 31 | $ | 71 | $ | 82 |
| Contribution to consolidated net income –<br>CAD | $ | 27 | $ | 40 | $ | 97 | $ | 107 |
| Contribution to consolidated earnings per common<br>share – basic – CAD | $ | 0.11 | $ | 0.17 | $ | 0.39 | $ | 0.45 |
| Net income weighted average foreign exchange rate<br>– CAD/USD | $ | 1.39 | $ | 1.34 | $ | 1.35 | $ | 1.33 |
| EBITDA | $ | 58 | $ | 74 | $ | 161 | $ | 176 |
| EBITDA – CAD | $ | 82 | $ | 98 | $ | 219 | $ | 233 |
(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2019 - $10 million) for the three months ended June 30, 2020 and $22 million (2019 - $21 million) for the six months ended June 30, 2020, 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 | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of US dollars | June 30 | June 30 | ||||||
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| PGS | $ | 11 | $ | 14 | $ | 29 | $ | 32 |
| NMGC | **** | - | 9 | **** | 23 | 32 | ||
| Other | **** | 7 | 8 | **** | 19 | 18 | ||
| Contribution to consolidated netincome | $ | 18 | $ | 31 | $ | 71 | $ | 82 |
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Net Income
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Six months ended | ||
|---|---|---|---|---|
| millions of US dollars | June 30 | June 30 | ||
| Contribution to consolidated net income –2019 | $ | 31 | $ | 82 |
| Decreased gas operating revenues - see Operating Revenues - Regulated Gas below | (20) | (39) | ||
| Decreased gas operating revenues as a result of recognition of tax reform benefits at NMGC in Q2 2019 | (9) | (9) | ||
| Decreased cost of natural gas sold - see Regulated Cost of Natural Gas below | 15 | 37 | ||
| Other | 1 | - | ||
| Contribution to consolidated net income– 2020 | $ | 18 | $ | 71 |
Gas Utilities and Infrastructure’s CAD contribution to consolidated net income decreased $13 million compared to Q2 2019. Year-to-date, Gas Utilities and Infrastructure’s CAD contribution to consolidated net income decreased $10 million compared to 2019. Decreases in both periods were due to NMGC’s recognition of tax reform benefits in Q2 2019, lower base revenues at PGS due to the impacts of COVID-19 on commercial sales, and higher OM&G expenses and depreciation expenses at PGS. These decreases were partially offset by higher customer growth and higher return on investment in Cast Iron/Bare Steel replacement rider at PGS and lower OM&G expenses and depreciation rates at NMGC.
The foreign exchange rate had minimal impact for the three months ended June 30, 2020 and year-to-date 2020.
Operating Revenues – Regulated Gas
Gas Utilities and Infrastructure’s operating revenues decreased $29 million to $150 million in Q2 2020, compared to $179 million in Q2 2019. Year-to-date operating revenues decreased $48 million to $400 million, compared to $448 million in the same period in 2019. The decreases in both periods were a result of lower clause-related revenues, lower off-system sales at PGS and the regulatory approval allowing NMGC to retain $9 million USD in tax reform benefits in 2019, partially offset by customer growth at PGS.
Gas revenues and sales volumes are summarized in the following tables by customer class:
| Q2 Gas Revenues | ||||
|---|---|---|---|---|
| millions of US dollars | ||||
| 2020 | 2019 | |||
| Residential | $ | 67 | $ | 70 |
| Commercial | **** | 37 | 46 | |
| Industrial (1) | **** | 10 | 10 | |
| Other (2) | **** | 25 | 43 | |
| Total (3) | $ | 139 | $ | 169 |
(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 – $10 million).
| YTD Gas Revenues | ||||
|---|---|---|---|---|
| millions of US dollars | ||||
| 2020 | 2019 | |||
| Residential | $ | 193 | $ | 212 |
| Commercial | **** | 104 | 119 | |
| Industrial (1) | **** | 20 | 19 | |
| Other (2) | **** | 61 | 77 | |
| Total (3) | $ | 378 | $ | 427 |
(1) Industrial includes sales to power generation customers.
(2) Other includes off-system sales to other utilities and various other items.
(3) Excludes $22 million of finance income from Brunswick Pipeline (2019 – $21 million).
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| Q2 Gas Volumes | ||||
|---|---|---|---|---|
| Therms (millions) | ||||
| 2020 | 2019 | |||
| Residential | **** | 63 | 65 | |
| Commercial | **** | 146 | 177 | |
| Industrial | **** | 394 | 383 | |
| Other | **** | 74 | 75 | |
| Total | **** | 677 | 700 | |
| YTD Gas Volumes | ||||
| --- | --- | --- | --- | --- |
| Therms (millions) | ||||
| 2020 | 2019 | |||
| Residential | **** | 235 | 240 | |
| Commercial | **** | 397 | 440 | |
| Industrial | **** | 781 | 720 | |
| Other | **** | 171 | 136 | |
| Total | **** | 1,584 | 1,536 |
Regulated Cost of Natural Gas
Regulated cost of natural gas decreased $15 million to $30 million in Q2 2020, compared to $45 million in Q2 2019. Year-to-date, regulated cost of natural gas decreased $37 million to $111 million in Q2 2020, compared to $148 million in the same period in 2019. The decrease in both periods was due to lower commodity costs at PGS and NMGC and lower volume of off-system sales at PGS.
Gas sales by type are summarized in the following table:
| Q2 Gas Volumes by Type | ||||
|---|---|---|---|---|
| Therms (millions) | ||||
| 2020 | 2019 | |||
| System supply | **** | 126 | 141 | |
| Transportation | **** | 551 | 559 | |
| Total | **** | 677 | 700 | |
| YTD Gas Volumes by Type | ||||
| --- | --- | --- | --- | --- |
| Therms (millions) | ||||
| 2020 | 2019 | |||
| System supply | **** | 401 | 409 | |
| Transportation | **** | 1,183 | 1,127 | |
| Total | **** | 1,584 | 1,536 |
Other
| Three months ended | Six months ended | |||||||
|---|---|---|---|---|---|---|---|---|
| For the | June 30 | June 30 | ||||||
| millions of Canadian dollars (except per share<br>amounts) | **** | 2020 | 2019 | **** | 2020 | 2019 | ||
| Marketing and trading margin (1) (2) | $ | (13) | $ | (28) | $ | 28 | $ | 26 |
| Electricity and capacity sales (3) | **** | 2 | - | **** | 6 | 116 | ||
| Other<br>non-regulated operating revenue | **** | 4 | 8 | **** | 9 | 18 | ||
| Total operating revenues – non-regulated | $ | (7) | $ | (20) | $ | 43 | $ | 160 |
| Intercompany revenue (4) | **** | 4 | 4 | **** | 7 | 13 | ||
| Non-regulated fuel for generation and purchased power (5) | **** | 3 | 2 | **** | 7 | 66 | ||
| Income from equity investments | **** | 8 | 9 | **** | 17 | 17 | ||
| Interest expense, net | **** | 76 | 82 | **** | 158 | 175 | ||
| Adjusted contribution to consolidated net income<br>(loss) | $ | (91) | $ | (100) | $ | (159) | $ | (116) |
| Gain on sale and impairment charges, net of<br>tax | **** | (15) | - | **** | 283 | - | ||
| After-tax<br>derivative mark-to-market gain (loss) | **** | (48) | (27) | **** | (13) | 59 | ||
| Contribution to consolidated net income<br>(loss) | $ | (154) | $ | (127) | $ | 111 | $ | (57) |
| Adjusted contribution to consolidated earnings<br>per common share – basic | $ | (0.37) | $ | (0.42) | $ | (0.65) | $ | (0.49) |
| Contribution to consolidated earnings per common<br>share – basic | $ | (0.62) | $ | (0.53) | $ | 0.45 | $ | (0.24) |
| Adjusted EBITDA | $ | (20) | $ | (41) | $ | (3) | $ | 49 |
(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a pre-tax mark-to-market loss of $87 million in Q2 2020 (2019 – $39 million loss) and a loss of $24 million year-to-date (2019 – $83 million gain).
(3) Electricity and capacity sales exclude a pre-tax mark-to-market of nil in Q2 2020 (2019 – nil) and year-to-date of nil (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 gain of $2 million in Q2 2020 (2019 – $1 million loss) and year-to-date nil (2019 – $3 million loss).
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Other’s adjusted contribution is summarized in the following table:
| For the | Three months ended | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | June 30 | June 30 | ||||||
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| Emera Energy | $ | (7) | $ | (19) | $ | 14 | $ | 33 |
| Corporate | **** | (84) | (81) | **** | (173) | (148) | ||
| Other | **** | - | - | **** | - | (1) | ||
| Adjusted contribution to consolidated netincome (loss) | $ | (91) | $ | (100) | $ | (159) | $ | (116) |
Net Income
Highlights of the net income changes are summarized in the following table:
| For the | Six months ended | ||
|---|---|---|---|
| millions of Canadian dollars | June 30 | ||
| Contribution to consolidated net income (loss)<br>– 2019 | (127) | $ | (57) |
| Increased marketing and trading margin - see<br>Emera Energy | 15 | 2 | |
| Increased OM&G expenses | (2) | (11) | |
| Decreased other income due to 2019 gain on sale of property in Florida, net of tax | - | (10) | |
| Decreased interest expense primarily due to lower interest rates and repayment of long-term debt | 6 | 11 | |
| 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<br>recovery related to mark-to-market | - | (11) | |
| Decreased income tax recovery quarter-over-quarter, primarily due to decreased losses before provision for income taxes, partially offset by the impact of effective state<br>tax rates. Increased income tax recovery year-over-year, primarily due to the impact of effective state tax rates | (4) | 10 | |
| Increased preferred stock dividends due to timing | (11) | (11) | |
| Impact of sale of NEGG and Bayside Power, net of<br>tax | 3 | (21) | |
| Gain on sale of Maine and impairment charges, net<br>of tax | (15) | 283 | |
| Increased mark-to-market loss, net of tax, quarter-over-quarter, primarily due to changes in<br>existing positions and higher amortization of gas transportation assets in 2020. These were partially offset by gains related to foreign exchange cash flow hedges entered in 2020 to manage foreign exchange earnings exposure. Year-over-year mark-to-market, net of tax, decreased due to 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 | (21) | (74) | |
| Other | 2 | - | |
| Contribution to consolidated net income<br>(loss) – 2020 | (154) | $ | 111 |
All values are in US Dollars.
Excluding the increase in mark-to-market loss, gain on sale, and impairment charges recognized on certain other assets, Other’s contribution to consolidated net income increased $9 million to a loss of $91 million in Q2 2020, compared to the same period in 2019. Year-to-date Other’s contribution decreased $43 million to a loss of $159 million compared to 2019. In Q2 2020, the increase was due to higher marketing and trading margin and lower interest, partially offset by timing of preferred stock dividends and lower income tax recovery. Year-over-year, the decrease was due to the impact of the sale of NEGG and Bayside Power, timing of preferred stock dividends, revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, higher OM&G expenses and the 2019 sale of property in Florida. These decreases were partially offset by increased income tax recovery due to the impact of effective state tax rates and lower interest.
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Emera Energy
Marketing and trading margin increased $15 million to a loss of $13 million in Q2 2020, compared to a loss of $28 million in Q2 2019.This increase was due to favourable hedges, lower fixed commitments for gas transportation and storage assets and more favourable market conditions, specifically increased volatility in Q2 2020, compared to Q2 2019.
Year-to-date, margin increased $2 million to $28 million in 2020, compared to $26 million for the same period in 2019 with Q2 2020 favourable margin offset by lower margin in Q1 2020.
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.
During the three and six months ended June 30, 2020, the effects of the ongoing COVID-19 pandemic and resulting government measures to address this pandemic have resulted in economic slowdowns in all markets served by Emera. The pace and strength of economic recovery is uncertain and may vary among jurisdictions.
Emera has experienced some reduced load and incremental operating expenses as a result of COVID-19. The impact varies by utility, however on a consolidated basis there has not been a material impact to consolidated net earnings to date. Refer to the “Business Overview and Outlook – COVID-19 Pandemic” section for further discussion. The ongoing economic impact of the pandemic may affect customers’ ability to pay. In Q2 2020, the Company’s utilities experienced an increase in the aging of customer receivables resulting from the suspension of disconnections. To date, there have been no significant customer defaults as a result of bankruptcies with many secured by deposits. The full impact of potential credit losses due to customer non-payment is not known at this time. The utilities are continuing to monitor customer accounts and are continuing to work with customers on payment arrangements. Many of Emera’s utilities expect to end their temporary suspension of disconnections for non-payment in Q3 2020.
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 has flexibility with respect to its capital investment plan and will continue to monitor current events and related impacts of COVID-19.
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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 COVID-19 related market disruptions. Refer to the “Risk Management and Financial Instruments” section for updated risk disclosure.
Emera has credit facilities with varying maturities that cumulatively provide $3.3 billion of credit, with approximately $1.7 billion undrawn and available at June 30, 2020. The Company was holding a cash balance of $338 million at June 30, 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 June 30, 2020, Emera had $149 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 can secure their remaining AMT credits in their 2019 filings. The Company has filed for this refund and expects to receive it in 2020.
Consolidated Cash FlowHighlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the six months ended June 30, 2020 and 2019 include:
| millions of Canadian dollars | 2020 | 2019 | Change | ||||||
|---|---|---|---|---|---|---|---|---|---|
| Cash, cash equivalents, restricted cash and<br>assets held for sale, beginning of period | $ | 274 | **** | $ | 372 | $ | (98 | ) | |
| Provided by (used in): | |||||||||
| Operating cash flow before change in working<br>capital | **** | 816 | **** | 775 | 41 | ||||
| Change in working capital | **** | (75 | ) | 32 | (107 | ) | |||
| Operating activities | **** | 741 | **** | 807 | (66 | ) | |||
| Investing activities | **** | 78 | **** | (264 | ) | 342 | |||
| Financing activities | **** | (712 | ) | (515 | ) | (197 | ) | ||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash included in assets held for sale | **** | (43 | ) | (16 | ) | (27 | ) | ||
| Cash, cash equivalents, and restricted cash, end<br>of period | $ | 338 | **** | $ | 384 | $ | (46 | ) |
Cash Flow from Operating Activities
Net cash provided by operating activities decreased $66 million to $741 million for the six months ended June 30, 2020, compared to $807 million for the same period in 2019.
Cash from operations before changes in working capital increased $41 million. The increase was primarily due to higher base revenue and over-recovery from customers on clause related costs at Tampa Electric. This was partially offset by lower earnings at NSPI and the impact of the sale of Emera Maine in Q1 2020.
Changes in working capital decreased operating cash flows by $107 million. The decrease was due to a refund of $146 million ($109 million USD) of alternative minimum tax credit carryforwards in April 2019 and unfavourable changes in cash collateral at Emera Energy. This was partially offset by favourable changes in cash collateral at NSPI, and the receipt of a 2019 income tax refund at NSPI in 2020.
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Cash Flow from Investing Activities
Net cash provided by investing activities increased $342 million to $78 million for the six months ended June 30, 2020, compared to cash used of $264 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 $860 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 2020.
Capital expenditures for the six months ended June 30, 2020, including AFUDC, were $1,343 million compared to $1,130 million for the same period in 2019. Details of the 2020 capital spend by segment are shown below:
| ● | $711 million - Florida Electric Utility (2019 – $647 million); |
|---|---|
| ● | $176 million - Canadian Electric Utilities (2019 – $159 million); |
| --- | --- |
| ● | $93 million - Other Electric Utilities (2019 – $83 million); |
| --- | --- |
| ● | $361 million - Gas Utilities and Infrastructure (2019 – $185 million); and |
| --- | --- |
| ● | $2 million - Other (2019 – $56 million). |
| --- | --- |
Cash Flow from Financing Activities
Net cash used in financing activities increased $197 million to $712 million for the six months ended June 30, 2020, compared to $515 million for the same period in 2019. The increase was due to net repayment of debt at TECO Finance and Tampa Electric, higher net repayments of Emera’s committed credit facilities and lower proceeds from the issuance of long-term debt at NSPI. These were partially offset by a 2019 repayment of corporate long-term debt, lower net repayments of committed credit facilities at NSPI and issuance of common shares under Emera’s ATM program.
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Contractual Obligations
As at June 30, 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 | $ | 37 | $ | 1,752 | $ | 435 | $ | 834 | $ | 687 | $ | 10,673 | $ | 14,418 |
| Interest payment obligations (1) | 327 | 617 | 582 | 559 | 543 | 7,188 | 9,816 | |||||||
| Purchased power (2) | 142 | 217 | 218 | 216 | 219 | 1,905 | 2,917 | |||||||
| Transportation (3) | 296 | 430 | 379 | 316 | 283 | 2,673 | 4,377 | |||||||
| Pension and post-retirement obligations<br>(4) | 14 | 34 | 30 | 29 | 99 | 264 | 470 | |||||||
| Capital projects (5) | 251 | 166 | 112 | 93 | - | - | 622 | |||||||
| Fuel, gas supply and storage | 274 | 217 | 41 | 6 | 1 | - | 539 | |||||||
| Asset retirement obligations | 2 | 27 | 1 | 1 | 1 | 364 | 396 | |||||||
| Long-term service agreements (6) | 52 | 23 | 23 | 21 | 29 | 70 | 218 | |||||||
| Equity investment commitments (7) | - | 240 | - | - | - | - | 240 | |||||||
| Leases and other (8) | 10 | 20 | 19 | 19 | 16 | 131 | 215 | |||||||
| Demand side management | 17 | 41 | 43 | - | - | - | 101 | |||||||
| Long-term payable | 2 | 5 | 5 | 5 | - | - | 17 | |||||||
| $ | 1,424 | $ | 3,789 | $ | 1,888 | $ | 2,099 | $ | 1,878 | $ | 23,268 | $ | 34,346 |
(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 June 30, 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 $418 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 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 declared force majeure under various project contracts, including formal notification to NSPML. Nalcor resumed work in May 2020 and is assessing the impact of the construction pause on its completion schedule.
NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls. On July 31, 2020, NSPML filed an interim assessment application with the UARB requesting recovery of 2021 costs of approximately $172 million from NSPI, with a decision expected in Q4 2020.
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 June 30, 2020, $53 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.
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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.
Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $3.3 billion committed syndicated revolving bank lines of credit in either CAD or USD per the table below.
| millions of dollars | RevolvingCreditFacilities | Utilized | UndrawnandAvailable | ||||
|---|---|---|---|---|---|---|---|
| Emera Inc. – Unsecured committed revolving<br>credit facility | June 2024 | $ | 900 | $ | 415 | $ | 485 |
| Emera Inc. – Unsecured non-revolving facility | December 2020 | 400 | 400 | - | |||
| TECO Finance, Inc. – in – Unsecured<br>committed revolving credit facility | March 2022 | 400 | 203 | 197 | |||
| NSPI – Unsecured committed revolving credit<br>facility | October 2024 | 600 | 40 | 560 | |||
| TEC – in – Unsecured committed<br>revolving credit facility (1) | March 2022 | 400 | 195 | 205 | |||
| TEC – in – Accounts receivable<br>collateralized borrowing facility (1) | March 2021 | 150 | - | 150 | |||
| TEC – in – Unsecured non-revolving facility (1) | February 2021 | 300 | 300 | - | |||
| NMGC – in – Unsecured committed<br>revolving credit facility | March 2022 | 125 | 30 | 95 | |||
| Other – in – Unsecured committed<br>revolving credit facilities | Various | 32 | 22 | 10 |
All values are in US Dollars.
(1) These facilities are available for use by Tampa Electric and PGS. At June 30, 2020, Tampa Electric had utilized $368 million USD and PGS had utilized $127 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 June 30, 2020.
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.
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Other Electric Utilities
On May 20, 2020, GBPC entered into a $22 million USD non-revolving term loan with a maturity date of May 20, 2025. The loan bears interest at a rate of 90-day LIBOR plus a margin. On May 22, 2020, proceeds from this loan were used to repay $22 million USD senior notes upon maturity.
On May 20, 2020, GBPC entered into a $15 million BSD ($15 million USD) non-revolving term loan with a maturity date of May 20, 2025. The loan bears interest at a rate of 4.00 per cent.
On May 18, 2020, BLPC received an advance of $27 million BBD ($13 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. At June 30, 2020, $67 million BBD ($33 million USD) was drawn against this facility.
Other
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. Using funds from the sale of Emera Maine, on April 3, 2020, TECO Energy/Finance repaid $200 million USD of the term loan and the remaining $300 million USD was repaid on June 30, 2020.
On March 13, 2020, TECO Finance repaid a $300 million USD note upon maturity. The note was repaid using existing credit facilities.
Credit Ratings
On July 8, 2020, Fitch Ratings assigned a first-time long-term issuer default rating of BBB+ to NMGC. The rating outlook is stable.
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.
Guaranteesand 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 updates as noted below:
The Company has standby letters of credit and surety bonds in the amount of $35 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.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2021. The amount committed as at June 30, 2020 was $63 million (December 31, 2019 - $52 million).
On May 15, 2020, the Company issued a guarantee of up to $60 million USD relating to outstanding notes of GBPC. The guarantee was reduced to $35 million USD upon repayment of certain notes, by GBPC, on May 22, 2020.
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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<br>Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $27 million for the three months ended June 30, 2020 (2019 - $27 million) and $55 million for the six months ended<br>June 30, 2020 (2019 - $54 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<br>Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $3 million for the three months ended June 30, 2020 (2019 - $16 million) and $11 million for the six<br>months ended June 30, 2020 (2019 - $34 million). |
|---|
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at June 30, 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.
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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 onthe Balance Sheets
The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:
| As at | June 30 | December 31 | |||
|---|---|---|---|---|---|
| millions of Canadian dollars | **** | 2020 | 2019 | ||
| Derivative instrument liabilities (current and<br>long-term liabilities) | $ | (1) | $ | (1 | ) |
| Net derivative instrument liabilities | $ | (1) | $ | (1 | ) |
Hedging Impact Recognized in Net Income
The Company recognized gains (losses) related to the effective portion of hedging relationships under the following categories:
| For the | Three months ended | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | June 30 | June 30 | ||||||
| **** | 2020 | 2019 | 2020 | 2019 | ||||
| Operating revenues – regulated | $ | (1) | $ | - | $ | (2) | $ | (2) |
| Effective net losses | $ | (1) | $ | - | $ | (2) | $ | (2) |
The effective net gains (losses) reflected in the above table would be offset in net income by the hedged item realized in the period.
Regulatory Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:
| As at | June 30 | December 31 | |||
|---|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | |||
| Derivative instrument assets (current and other<br>assets) | $ | 28 | $ | 28 | |
| Regulatory assets (current and other<br>assets) | **** | 90 | 80 | ||
| Derivative instrument liabilities (current and<br>long-term liabilities) | **** | (91) | (78 | ) | |
| Regulatory liabilities (current and long-term<br>liabilities) | **** | (29) | (42 | ) | |
| Net liability | $ | (2) | $ | (12 | ) |
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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 | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | June 30 | June 30 | ||||||
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| Regulated fuel for generation and purchased<br>power (1) | $ | (5) | $ | 3 | $ | (10) | $ | 7 |
| Net gains (losses) | $ | (5) | $ | 3 | $ | (10) | $ | 7 |
(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.
HFT Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to HFT derivatives:
| As at | June 30 | December 31 | |||
|---|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | |||
| Derivative instrument assets (current and other<br>assets) | $ | 43 | $ | 58 | |
| Derivative instrument liabilities (current and<br>long-term liabilities) | **** | (170) | (291 | ) | |
| Net derivative instrument liability | $ | (127) | $ | (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 | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | June 30 | June 30 | ||||||
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| Operating revenue - non-regulated | $ | 10 | $ | 45 | $ | 222 | $ | 249 |
| Non-regulated fuel for purchased power | **** | - | (3) | **** | (4) | (5) | ||
| Net gains | $ | 10 | $ | 42 | $ | 218 | $ | 244 |
Other Derivatives Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to other derivatives:
| As at | June 30 | December 31 | |||
|---|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | |||
| Derivative instrument assets (current and other<br>assets) | $ | 9 | **** | $ | 1 |
| Derivative instrument liabilities (current and<br>long-term liabilities) | **** | (9 | ) | - | |
| Net derivative instrument assets | $ | - | **** | $ | 1 |
Other Derivatives Recognized in Net Income
The Company recognized in net income the following gains (losses) related to other derivatives:
| For the | Three months ended | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | June 30 | June 30 | ||||||
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| Operating, maintenance and general | $ | (6) | $ | 9 | $ | (7) | $ | 23 |
| Other income (expense) | **** | 10 | - | **** | - | - | ||
| Total gains (losses) | $ | 4 | $ | 9 | $ | (7) | $ | 23 |
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DISCLOSURE AND INTERNAL CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National 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 June 30, 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 June 30, 2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with 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 June 30, 2020.
Goodwill Impairment Assessments
Management considered whether the potential impacts of the COVID-19 pandemic on future earnings required testing for goodwill impairment in Q2 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 June 30, 2020.
As of June 30, 2020, $6.0 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 June 30, 2020, $73 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 Q2 2020.
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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 June 30, 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 $3 million ($3 million after tax) and $25 million ($26 million after tax) were recognized on certain assets for the three and six months ended June 30, 2020, respectively.
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.
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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 RateReform 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.
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
In August 2020, the FASB issued ASU 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40). The standard reduces the number of accounting models for convertible debenture debt instruments and convertible preferred stock, in addition to amending disclosure requirements. The standard also updates guidance for the derivative scope exception for contracts in an entity’s own equity and the related earnings per share guidance. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2021. Early adoption is permitted, but no earlier than fiscal years beginning after December 15, 2020. The standard will be applied through either a modified retrospective method of transition or a fully retrospective method of transition. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements.
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SUMMARY OF QUARTERLY RESULTS
| For the quarter ended<br> <br>millions of<br>Canadian dollars | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (except per share amounts) | 2020 | 2020 | 2019 | 2019 | 2019 | 2019 | 2018 | 2018 | ||||||||
| Operating revenues | $ | 1,169 | $ | 1,637 | $ | 1,616 | $ | 1,299 | $ | 1,378 | $ | 1,818 | $ | 1,799 | $ | 1,495 |
| Net income attributable to common<br>shareholders | **** | 58 | 523 | 193 | 55 | 103 | 312 | 231 | 118 | |||||||
| Adjusted net income attributable to common<br>shareholders | **** | 118 | 193 | 145 | 122 | 130 | 224 | 167 | 191 | |||||||
| Earnings per common share – basic | **** | 0.24 | 2.14 | 0.79 | 0.23 | 0.43 | 1.32 | 0.98 | 0.51 | |||||||
| Earnings per common share – diluted | **** | 0.23 | 2.13 | 0.80 | 0.23 | 0.43 | 1.32 | 0.98 | 0.50 | |||||||
| Adjusted earnings per common share –<br>basic | **** | 0.48 | 0.79 | 0.60 | 0.51 | 0.54 | 0.95 | 0.71 | 0.82 |
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.
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EX-99.2
Exhibit 99.2
EMERA INCORPORATED
Unaudited CondensedConsolidated
Interim Financial Statements
June 30, 2020 and 2019
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Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| For the<br><br><br>millions of Canadian dollars (except per share amounts) | Three months ended<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| 2020 | 2019 | 2020 | 2019 | |||||
| Operating revenues | ||||||||
| Regulated electric | $ | 1,057 | $ | 1,209 | $ | 2,251 | $ | 2,378 |
| Regulated gas | **** | 207 | 234 | **** | 538 | 586 | ||
| Non-regulated | **** | (95) | (65) | **** | 17 | 232 | ||
| Total operating revenues (note 6) | **** | 1,169 | 1,378 | **** | 2,806 | 3,196 | ||
| Operating expenses | ||||||||
| Regulated fuel for generation and purchased power | **** | 312 | 418 | **** | 722 | 819 | ||
| Regulated cost of natural gas | **** | 40 | 61 | **** | 149 | 197 | ||
| Non-regulated fuel for<br>generation and purchased power | **** | - | 3 | **** | 4 | 67 | ||
| Operating, maintenance and general | **** | 334 | 343 | **** | 712 | 709 | ||
| Provincial, state and municipal taxes | **** | 78 | 85 | **** | 162 | 170 | ||
| Depreciation and amortization | **** | 216 | 228 | **** | 447 | 452 | ||
| Total operating expenses | **** | 980 | 1,138 | **** | 2,196 | 2,414 | ||
| Income from operations | **** | 189 | 240 | **** | 610 | 782 | ||
| Income from equity investments (note 7) | **** | 40 | 40 | **** | 81 | 80 | ||
| Other income (expenses), net (note 8) | **** | 24 | 6 | **** | 587 | 19 | ||
| Interest expense, net | **** | 173 | 185 | **** | 357 | 374 | ||
| Income before provision for incometaxes | **** | 80 | 101 | **** | 921 | 507 | ||
| Income tax expense (recovery) (note 9) | **** | (1) | (15) | **** | 305 | 67 | ||
| Net income | **** | 81 | 116 | **** | 616 | 440 | ||
| Non-controlling interest in subsidiaries | **** | - | 1 | **** | 1 | 2 | ||
| Preferred stock dividends | **** | 23 | 12 | **** | 34 | 23 | ||
| Net income attributable to commonshareholders | $ | 58 | $ | 103 | $ | 581 | $ | 415 |
| Weighted average shares of common stock outstanding (in millions)<br>(note 11) | ||||||||
| Basic | **** | 246.7 | 239.2 | **** | 245.7 | 237.8 | ||
| Diluted | **** | 248.0 | 239.8 | **** | 247.0 | 238.4 | ||
| Earnings per common share (note 11) | ||||||||
| Basic | $ | 0.24 | $ | 0.43 | $ | 2.37 | $ | 1.75 |
| Diluted | $ | 0.23 | $ | 0.43 | $ | 2.35 | $ | 1.74 |
| Dividends per common share declared | $ | 1.2250 | $ | 0.5875 | $ | 1.8375 | $ | 1.1750 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| For the<br> <br>millions of<br>Canadian dollars | Three months ended<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| 2020 | 2019 | 2020 | 2019 | |||||
| Net income | $ | 81 | $ | 116 | $ | 616 | $ | 440 |
| Other comprehensive income (loss), net of tax | ||||||||
| Foreign currency translation adjustment<br>(1) | **** | (365) | (175) | **** | 396 | (338) | ||
| Unrealized gains (losses) on net investment<br>hedges (2) (3) | **** | 66 | 33 | **** | (75) | 67 | ||
| Cash flow hedges | ||||||||
| Net derivative gains (losses) | **** | 1 | 1 | **** | (2) | 3 | ||
| Less: reclassification adjustment for losses (gains) included in<br><br><br>income | **** | 1 | - | **** | 2 | 2 | ||
| Net effects of cash flow hedges | **** | 2 | 1 | **** | - | 5 | ||
| Net change in unrecognized pension and<br>post-retirement benefit obligation (4) | **** | 3 | 4 | **** | (2) | 8 | ||
| Other comprehensive income (loss) (5) | **** | (294) | (137) | **** | 319 | (258) | ||
| Comprehensive income (loss) | **** | (213) | (21) | **** | 935 | 182 | ||
| Comprehensive income (loss) attributable to non-controlling interest | **** | - | - | **** | 2 | 1 | ||
| Comprehensive income (loss) of EmeraIncorporated | $ | (213) | $ | (21) | $ | 933 | $ | 181 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
(1) Net of tax recovery of $7 million (2019 - nil) for the three months ended June 30, 2020 and tax expense of $6 million (2019 – nil) for the six months ended June 30, 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 expense of nil (2019 - nil) for the three months ended June 30, 2020 and tax recovery of $1 million (2019 – nil) for the six months ended June 30, 2020.
(4) Net of tax expense of nil (2019 - nil) for the three months ended June 30, 2020 and tax expense of nil (2019 – $1 million tax expense) for the six months ended June 30, 2020.
(5) Net of tax recovery of $7 million (2019 - nil) for the three months ended June 30, 2020 and tax expense of $5 million (2019 – $1 million tax expense) for the six months ended June 30, 2020.
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Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at<br>millions of Canadian dollars | December 31<br>2019 | ||
|---|---|---|---|
| Assets | |||
| Current assets | |||
| Cash and cash equivalents | 285 | $ | 222 |
| Restricted cash (note 24) | 53 | 51 | |
| Inventory | 474 | 467 | |
| Derivative instruments (notes 13 and 14) | 48 | 54 | |
| Regulatory assets (note 15) | 133 | 121 | |
| Receivables and other current assets (note 17) | 1,325 | 1,486 | |
| Assets held for sale (note 4) | - | 85 | |
| 2,318 | 2,486 | ||
| Property, plant and equipment, net of accumulated depreciation and amortization of 8,807 and 8,295, respectively | 19,663 | 18,167 | |
| Other assets | |||
| Deferred income taxes | 188 | 186 | |
| Derivative instruments (notes 13 and 14) | 32 | 33 | |
| Regulatory assets (note 15) | 1,426 | 1,431 | |
| Net investment in direct financing lease | 469 | 473 | |
| Investments subject to significant influence (note 7) | 1,342 | 1,312 | |
| Goodwill | 6,122 | 5,835 | |
| Other long-term assets | 319 | 300 | |
| Assets held for sale (note 4) | - | 1,619 | |
| 9,898 | 11,189 | ||
| Total assets | 31,879 | $ | 31,842 |
All values are in US Dollars.
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Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited) – Continued
| As at<br> <br>millions of<br>Canadian dollars | June 30<br><br><br>2020 | December 31<br>2019 | ||
|---|---|---|---|---|
| Liabilities and Equity | ||||
| Current liabilities | ||||
| Short-term debt (note 19) | $ | 1,394 | $ | 1,537 |
| Current portion of long-term debt (note 20) | **** | 716 | 501 | |
| Accounts payable | **** | 996 | 1,118 | |
| Derivative instruments (notes 13 and 14) | **** | 184 | 268 | |
| Regulatory liabilities (note 15) | **** | 265 | 295 | |
| Other current liabilities | **** | 499 | 333 | |
| Liabilities associated with assets held for sale (note 4) | **** | - | 114 | |
| **** | 4,054 | 4,166 | ||
| Long-term liabilities | ||||
| Long-term debt (note 20) | **** | 13,588 | 13,679 | |
| Deferred income taxes | **** | 1,585 | 1,285 | |
| Derivative instruments (notes 13 and 14) | **** | 87 | 102 | |
| Regulatory liabilities (note 15) | **** | 2,006 | 1,886 | |
| Pension and post-retirement liabilities (note 18) | **** | 458 | 460 | |
| Other long-term liabilities | **** | 837 | 764 | |
| Long-term liabilities associated with assets held for sale (note<br>4) | **** | - | 899 | |
| **** | 18,561 | 19,075 | ||
| Equity | ||||
| Common stock (note 10) | **** | 6,435 | 6,216 | |
| Cumulative preferred stock (note 22) | **** | 1,004 | 1,004 | |
| Contributed surplus | **** | 78 | 78 | |
| Accumulated other comprehensive income (note 12) | **** | 413 | 95 | |
| Retained earnings | **** | 1,298 | 1,173 | |
| Total Emera Incorporated equity | **** | 9,228 | 8,566 | |
| Non-controlling interest in<br>subsidiaries | **** | 36 | 35 | |
| Total equity | **** | 9,264 | 8,601 | |
| Total liabilities and equity | $ | 31,879 | $ | 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 |
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Emera Incorporated
Condensed Consolidated Statements of Cash Flows (Unaudited)
| For the | Six months ended June 30 | |||
|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | ||
| Operating activities | ||||
| Net income | $ | 616 | $ | 440 |
| Adjustments to reconcile net income to net cash<br>provided by operating activities: | ||||
| Depreciation and amortization | **** | 457 | 457 | |
| Income from equity investments, net of dividends | **** | (42) | (38) | |
| Allowance for equity funds used during construction | **** | (20) | (8) | |
| Deferred income taxes, net | **** | 338 | 51 | |
| Net change in pension and post-retirement liabilities | **** | (10) | (8) | |
| Regulated fuel adjustment mechanism | **** | (9) | (1) | |
| Net change in fair value of derivative instruments | **** | (108) | (148) | |
| Net change in regulatory assets and liabilities | **** | 16 | (5) | |
| Net change in capitalized transportation capacity | **** | 134 | 40 | |
| Gain on sale (excluding transaction costs) and impairment<br>charges | **** | (578) | **** | - |
| Other operating activities, net | **** | 22 | (5) | |
| Changes in<br>non-cash working capital (note 23) | **** | (75) | 32 | |
| Net cash provided by operatingactivities | **** | 741 | 807 | |
| Investing activities | ||||
| Proceeds from dispositions (note 4) | **** | 1,401 | 860 | |
| Additions to property, plant and<br>equipment | **** | (1,323) | (1,122) | |
| Other investing activities | **** | - | (2) | |
| Net cash provided by (used in) investingactivities | **** | 78 | (264) | |
| Financing activities | ||||
| Change in short-term debt, net | **** | 79 | 162 | |
| Proceeds from short-term debt with maturities greater than 90<br>days | **** | 399 | **** | - |
| Repayment of short-term debt with maturities greater than 90<br>days | **** | (688) | **** | - |
| Proceeds from long-term debt, net of issuance costs | **** | 422 | 442 | |
| Retirement of long-term debt | **** | (477) | (684) | |
| Net repayments under committed credit facilities | **** | (335) | (302) | |
| Issuance of common stock, net of issuance costs | **** | 123 | 91 | |
| Dividends on common stock | **** | (205) | (181) | |
| Dividends on preferred stock | **** | (23) | (23) | |
| Other financing activities | **** | (7) | (20) | |
| Net cash used in financingactivities | **** | (712) | (515) | |
| Effect of exchange rate changes on cash, cash<br>equivalents, and restricted cash | **** | (43) | (16) | |
| Net increase in cash, cash equivalents,restricted cash and assets held for sale | **** | 64 | 12 | |
| Cash, cash equivalents, restricted cash and<br>assets held for sale, beginning of period | **** | 274 | 372 | |
| Cash, cash equivalents, restricted cash and<br>assets held for sale, end of period | $ | 338 | $ | 384 |
| Cash, cash equivalents, restricted cash and assets held for sale consistsof: | ||||
| Cash | $ | 281 | $ | 325 |
| Short-term investments | **** | 4 | 7 | |
| Restricted cash | **** | 53 | 51 | |
| Assets held for sale | **** | - | 1 | |
| Cash, cash equivalents, restricted cash, and<br>assets held for sale | $ | 338 | $ | 384 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
54
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| millions of Canadian dollars | PreferredStock | ContributedSurplus | AccumulatedOtherComprehensiveIncome (Loss)(“AOCI”) | RetainedEarnings | Non-ControllingInterest | TotalEquity | |||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended<br>June 30, 2020 | |||||||||||||
| Balance, March 31, 2020 | 6,340 | $ | 1,004 | $ | 78 | $ | 707 | $ | 1,540 | $ | 36 | $ | 9,705 |
| Net income of Emera Incorporated | - | **** | - | **** | - | **** | - | **** | 81 | **** | - | **** | 81 |
| Other comprehensive income (loss), net of tax recovery of 7 million | - | **** | - | **** | - | **** | (294) | **** | - | **** | - | **** | (294) |
| Dividends declared on preferred stock (1) | - | **** | - | **** | - | **** | - | **** | (23) | **** | - | **** | (23) |
| Dividends declared on common stock (1.2250/share) | - | **** | - | **** | - | **** | - | **** | (300) | **** | - | **** | (300) |
| Common stock issued under purchase plan | 51 | **** | - | **** | - | **** | - | **** | - | **** | - | **** | 51 |
| Issuance of common stock, net of after-tax issuance costs | 41 | **** | - | **** | - | **** | - | **** | - | **** | - | **** | 41 |
| Senior management stock options exercised | 3 | **** | - | **** | - | **** | - | **** | - | **** | - | **** | 3 |
| Balance, June 30, 2020 | 6,435 | $ | 1,004 | $ | 78 | $ | 413 | $ | 1,298 | $ | 36 | $ | 9,264 |
| millions of Canadian dollars | |||||||||||||
| For the six months ended June 30,<br>2020 | |||||||||||||
| Balance, December 31, 2019 | 6,216 | $ | 1,004 | $ | 78 | $ | 95 | $ | 1,173 | $ | 35 | $ | 8,601 |
| Net income of Emera Incorporated | - | **** | - | **** | - | **** | - | **** | 615 | **** | 1 | **** | 616 |
| Other comprehensive income (loss), net of tax<br>expense of 5 million | - | **** | - | **** | - | **** | 318 | **** | - | **** | 1 | **** | 319 |
| Dividends declared on preferred stock (2) | - | **** | - | **** | - | **** | - | **** | (34) | **** | - | **** | (34) |
| Dividends declared on common stock (1.8375/share) | - | **** | - | **** | - | **** | - | **** | (449) | **** | - | **** | (449) |
| Common stock issued under purchase plan | 99 | **** | - | **** | - | **** | - | **** | - | **** | - | **** | 99 |
| Issuance of common stock, net of after-tax issuance costs | 99 | **** | - | **** | - | **** | - | **** | - | **** | - | **** | 99 |
| Senior management stock options exercised | 20 | **** | - | **** | (1) | **** | - | **** | - | **** | - | **** | 19 |
| Adoption of credit losses accounting standard (note 2) | - | **** | - | **** | - | **** | - | **** | (7) | **** | - | **** | (7) |
| Other | 1 | **** | - | **** | 1 | **** | - | **** | - | **** | (1) | **** | 1 |
| Balance, June 30, 2020 | 6,435 | $ | 1,004 | $ | 78 | $ | 413 | $ | 1,298 | $ | 36 | $ | 9,264 |
All values are in US Dollars.
The accompanying notes are an integral part of these condensed consolidated financial statements.
(1) Series A; $0.31940/share, Series B; $0.35010/share, Series C; $0.59012/share, Series E; $0.56250/share, Series F; $0.525260/share and Series H; $0.61250/share
(2) Series A; $0.47910/share, Series B; $0.56910/share, Series C; $0.88518/share, Series E; $0.84375/share, Series F; $0.79089/share and Series H; $0.91875
55
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| millions of Canadian dollars | PreferredStock | ContributedSurplus | AccumulatedOtherComprehensiveIncome (Loss)(“AOCI”) | RetainedEarnings | Non-ControllingInterest | TotalEquity | |||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended<br>June 30, 2019 | |||||||||||||
| Balance, March 31, 2019 | 5,899 | $ | 1,004 | $ | 82 | $ | 217 | $ | 1,249 | $ | 40 | $ | 8,491 |
| Net income of Emera Incorporated | - | - | - | - | 115 | 1 | 116 | ||||||
| Other comprehensive income (loss), net of tax expense of nil | - | - | - | (136) | - | (1) | (137) | ||||||
| Dividends declared on preferred stock (1) | - | - | - | - | (12) | - | (12) | ||||||
| Dividends declared on common stock (0.5875/share) | - | - | - | - | (140) | - | (140) | ||||||
| Issuance of preferred shares of C, net of issuance costs | 14 | 14 | |||||||||||
| Redemption of preferred shares of C | (19) | (19) | |||||||||||
| Common stock issued under purchase plan | 50 | - | - | - | - | - | 50 | ||||||
| Senior management stock options<br>exercised | 61 | - | (3) | - | - | - | 58 | ||||||
| Balance, June 30, 2019 | 6,010 | $ | 1,004 | $ | 79 | $ | 81 | $ | 1,212 | $ | 35 | $ | 8,421 |
| millions of Canadian dollars | |||||||||||||
| For the six months ended<br>June 30, 2019 | |||||||||||||
| Balance, December 31, 2018 | 5,816 | $ | 1,004 | $ | 84 | $ | 338 | $ | 1,075 | $ | 41 | $ | 8,358 |
| Net income of Emera Incorporated | - | - | - | - | 438 | 2 | 440 | ||||||
| Other comprehensive income (loss), net of tax expense of 1 million | - | - | - | (257) | - | (1) | (258) | ||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (23) | - | (23) | ||||||
| Dividends declared on common stock (1.1750/share) | - | - | - | - | (278) | - | (278) | ||||||
| Issuance of preferred shares of C, net of issuance costs | 14 | 14 | |||||||||||
| Redemption of preferred shares of C | (19) | (19) | |||||||||||
| Common stock issued under purchase plan | 101 | - | - | - | - | - | 101 | ||||||
| Senior management stock option exercised | 93 | - | (5) | - | - | - | 88 | ||||||
| Other | - | - | - | - | - | (2) | (2) | ||||||
| Balance, June 30, 2019 | 6,010 | $ | 1,004 | $ | 79 | $ | 81 | $ | 1,212 | $ | 35 | $ | 8,421 |
All values are in US Dollars.
The accompanying notes are an integral part of these condensed consolidated financial statements.
(1) Series A; $0.15970/share, Series B; $0.21150/share, Series C; $0.29506/share, Series E; $0.28125/share, Series F; $0.265625/share and Series H; $0.306250/share
(2) Series A; $0.31940/share, Series B; $0.43210/share, Series C; $0.59012/share, Series E; $0.56250/share, Series F; $0.53125/share and Series H; $0.61250/share
56
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at June 30, 2020 and 2019
1. SUMMARY OF SIGNIFICANT ACCOUNTINGPOLICIES
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 June 30, 2020, Emera’s reportable segments include the following:
| ● | Florida Electric Utility, which consists of Tampa Electric, a vertically integrated regulated electric utility in West<br>Central Florida. |
|---|---|
| ● | Canadian Electric Utilities, which includes: |
| --- | --- |
| ● | Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity<br>supplier in Nova Scotia; and |
| --- | --- |
| ● | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission investments related<br>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<br>$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<br>on January 15, 2018; and |
| --- | --- |
| ● | a 49.2 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a<br>$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<br>the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL. In response to the COVID-19 pandemic, on March 17, 2020 Nalcor announced that<br>it had paused construction activities at the Muskrat Falls site. Nalcor resumed work in May 2020 and is assessing the impact of the construction pause on its completion schedule. Refer to note 21 for further details. |
| --- | --- |
| ● | Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated<br>electric utilities that include: |
| --- | --- |
| ● | The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility<br>on the island of Barbados; |
| --- | --- |
| ● | Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama<br>Island; |
| --- | --- |
| ● | a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated regulated<br>electric utility on the island of Dominica; and |
| --- | --- |
| ● | a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically<br>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.
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| ● | 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;<br> |
| --- | --- |
| ● | SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering<br>services in Florida; |
| --- | --- |
| ● | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a<br>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 June 30, 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<br>and provides related energy asset management services; |
| --- | --- |
| ● | Brooklyn Power Corporation (“Brooklyn Energy”), a power plant in Brooklyn, Nova Scotia; and<br> |
| --- | --- |
| ● | a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a pumped storage<br>hydroelectric facility in northwestern Massachusetts. |
| --- | --- |
| ● | Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates,<br>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<br>of Emera; |
| --- | --- |
| ● | Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and<br> |
| --- | --- |
| ● | 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.
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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.
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.
During the three months and six months ended June 30, 2020, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. Emera has experienced some reduced load and incremental operating expenses as a result of COVID-19. The impact varies by utility, however on a consolidated basis there has not been a material impact to consolidated net earnings to date, primarily due a favourable change to the mix of sales to residential customer classes. Favourable weather, in particular in Florida, has further reduced the consolidated impact. 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. The pace and strength of economic recovery is uncertain and may vary among jurisdictions.
Management has analyzed the impact of the COVID-19 pandemic on its estimates and judgements and concluded that no material adjustments are required for the three months and six months ended June 30, 2020.
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Goodwill Impairment Assessments
Management considered whether the potential impacts of the COVID-19 pandemic on future earnings required testing for goodwill impairment in Q2 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 June 30, 2020.
As of June 30, 2020, $6.0 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 June 30, 2020, $73 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 the three months and six months ended June 30, 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 June 30, 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 $3 million ($3 million after tax) and $25 million ($26 million after tax) were recognized on certain assets for the three months and six months ended June 30, 2020, respectively.
Pension and OtherPost-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.
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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 aging and collectability of customer receivables.
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.
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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 RateReform 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.
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
In August 2020, the FASB issued ASU 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40). The standard reduces the number of accounting models for convertible debenture debt instruments and convertible preferred stock, in addition to amending disclosure requirements. The standard also updates guidance for the derivative scope exception for contracts in an entity’s own equity and the related earnings per share guidance. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2021. Early adoption is permitted, but no earlier than fiscal years beginning after December 15, 2020. The standard will be applied through either a modified retrospective method of transition or a fully retrospective method of transition. The Company is currently evaluating the impact of adoption of the standard 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 working capital adjustments. A gain on disposition of $585 million ($309 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.
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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<br>Electric<br>Utility | Canadian<br>Electric<br>Utilities | Other<br>Electric<br>Utilities | Gas Utilities<br>and<br>Infrastructure | Other | Inter-<br>Segment<br>Eliminations | Total | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended June 30, 2020 | |||||||||||||||
| Operating revenues from external customers (1) | $ | 627 | $ | 335 | $ | 95 | $ | 212 | $ | (100) | $ | - | $ | 1,169 | |
| Inter-segment revenues (1) | 1 | - | - | 2 | 6 | (9) | - | ||||||||
| Total operating revenues | 628 | 335 | 95 | 214 | (94) | (9) | 1,169 | ||||||||
| Regulated fuel for generation and purchased power | 130 | 146 | 37 | - | - | (1) | 312 | ||||||||
| Regulated cost of natural gas | - | - | - | 40 | - | - | 40 | ||||||||
| Depreciation and amortization | 112 | 58 | 16 | 28 | 2 | - | 216 | ||||||||
| Interest expense, net | 39 | 35 | 7 | 15 | 76 | 1 | 173 | ||||||||
| Internally allocated interest (2) | - | - | - | 4 | (4) | - | - | ||||||||
| Operating, maintenance and general (“OM&G”) | 132 | 69 | 36 | 79 | 22 | (4) | 334 | ||||||||
| Gain on sale and impairment charges | - | - | - | - | (4) | - | (4) | ||||||||
| Income tax expense (recovery) | 28 | 4 | - | 8 | (41) | - | (1) | ||||||||
| Net income (loss) attributable to common shareholders | 146 | 37 | 2 | 27 | (154) | - | 58 | ||||||||
| For the six months ended June 30, 2020 | |||||||||||||||
| Operating revenues from external customers (1) | 1,192 | 793 | 266 | 546 | 9 | - | 2,806 | ||||||||
| Inter-segment revenues (1) | 3 | - | - | 5 | 10 | (18) | - | ||||||||
| Total operating revenues | 1,195 | 793 | 266 | 551 | 19 | (18) | 2,806 | ||||||||
| Regulated fuel for generation and purchased power | 272 | 350 | 104 | - | - | (4) | 722 | ||||||||
| Regulated cost of natural gas | - | - | - | 149 | - | - | 149 | ||||||||
| Depreciation and amortization | 228 | 116 | 44 | 55 | 4 | - | 447 | ||||||||
| Interest expense, net | 79 | 70 | 20 | 30 | 158 | - | 357 | ||||||||
| Internally allocated interest (2) | - | - | - | 7 | (7) | - | - | ||||||||
| OM&G | 270 | 148 | 83 | 163 | 57 | (9) | 712 | ||||||||
| Gain on sale and impairment charges | - | - | - | - | 560 | - | 560 | ||||||||
| Income tax expense (recovery) | 42 | 12 | (8) | 30 | 229 | - | 305 | ||||||||
| Net income attributable to common shareholders | 225 | 129 | 19 | 97 | 111 | - | 581 | ||||||||
| As at June 30, 2020 | |||||||||||||||
| Total assets | 17,592 | 6,769 | 1,470 | 5,991 | 1,175 | (1,118) | ^(3)^ | 31,879 |
(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.
63
| millions of Canadian dollars | Florida<br>Electric<br>Utility | Canadian<br>Electric<br>Utilities | Other<br>Electric<br>Utilities | Gas Utilities<br>and<br>Infrastructure | Other | Inter-<br>Segment<br>Eliminations | Total | |||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended June 30, 2019 | ||||||||||||||
| Operating revenues from external customers<br>(1) | $ | 694 | $ | 327 | $ | 188 | $ | 238 | $ | (70) | $ | - | $ | 1,377 |
| Inter-segment revenues (1) | 3 | - | - | 5 | 11 | (18) | 1 | |||||||
| Total operating revenues | 697 | 327 | 188 | 243 | (59) | (18) | 1,378 | |||||||
| Regulated fuel for generation and purchased<br>power | 209 | 143 | 71 | - | - | (5) | 418 | |||||||
| Regulated cost of natural gas | - | - | - | 61 | - | - | 61 | |||||||
| Depreciation and amortization | 113 | 57 | 29 | 27 | 2 | - | 228 | |||||||
| Interest expense, net | 38 | 37 | 13 | 15 | 82 | - | 185 | |||||||
| Internally allocated interest (2) | - | - | - | 4 | (4) | - | - | |||||||
| OM&G | 139 | 69 | 46 | 75 | 29 | (15) | 343 | |||||||
| Income tax expense (recovery) | 26 | (7) | 3 | 13 | (50) | - | (15) | |||||||
| Net income (loss) attributable to common<br>shareholders | 125 | 42 | 23 | 40 | (127) | - | 103 | |||||||
| For the six months ended June 30, 2019 | ||||||||||||||
| Operating revenues from external customers****(1) | 1,239 | 769 | 370 | 594 | 224 | - | 3,196 | |||||||
| Inter-segment revenues (1) | 6 | 1 | - | 11 | 21 | (39) | - | |||||||
| Total operating revenues | 1,245 | 770 | 370 | 605 | 245 | (39) | 3,196 | |||||||
| Regulated fuel for generation and purchased<br>power | 361 | 331 | 137 | - | - | (10) | 819 | |||||||
| Regulated cost of natural gas | - | - | - | 197 | - | - | 197 | |||||||
| Depreciation and amortization | 221 | 113 | 58 | 54 | 6 | - | 452 | |||||||
| Interest expense, net | 77 | 72 | 26 | 30 | 169 | - | 374 | |||||||
| Internally allocated interest (2) | - | - | - | 7 | (7) | - | - | |||||||
| OM&G | 272 | 142 | 95 | 154 | 74 | (28) | 709 | |||||||
| Income tax expense (recovery) | 39 | 1 | 6 | 34 | (13) | - | 67 | |||||||
| Net income (loss) attributable to common<br>shareholders | 186 | 138 | 41 | 107 | (57) | - | 415 | |||||||
| 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.
64
6. REVENUE
The following disaggregates the Company’s revenue by major source:
| millions of Canadian dollars | Florida<br>Electric<br>Utility | Canadian<br>Electric<br>Utilities | Other<br>Electric<br>Utilities | Gas Utilities<br>and<br>Infrastructure | Other | Inter-SegmentEliminations | Total | |||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended June 30, 2020 | ||||||||||||||
| Regulated | ||||||||||||||
| Electric Revenue | ||||||||||||||
| Residential | $ | 352 | $ | 182 | $ | 36 | $ | - | $ | 570 | ||||
| Commercial | 168 | 90 | 46 | - | 304 | |||||||||
| Industrial | 44 | 51 | 7 | - | 102 | |||||||||
| Other electric and regulatory deferrals | 61 | 6 | 2 | - | 69 | |||||||||
| Other (1) | 3 | 6 | 4 | - | 12 | |||||||||
| Regulated electric revenue | 628 | 335 | 95 | - | 1,057 | |||||||||
| Gas Revenue | ||||||||||||||
| Residential | - | - | - | 93 | 93 | |||||||||
| Commercial | - | - | - | 50 | 50 | |||||||||
| Industrial | - | - | - | 14 | 13 | |||||||||
| Finance income (2)(3) | - | - | - | 15 | 15 | |||||||||
| Other | - | - | - | 37 | 36 | |||||||||
| Regulated gas revenue | - | - | - | 209 | 207 | |||||||||
| Non-Regulated | ||||||||||||||
| Marketing and trading margin (4) | - | - | - | - | (13) | |||||||||
| Energy sales (4) | - | - | - | - | (2) | |||||||||
| Other | - | - | - | 5 | 9 | |||||||||
| Mark-to-market (3) | - | - | - | - | (89) | |||||||||
| Non-regulated revenue | - | - | - | 5 | (95) | |||||||||
| Total operatingrevenues | $ | 628 | $ | 335 | $ | 95 | $ | 214 | (94) | (9) | $ | 1,169 | ||
| For the six months ended June 30, 2020 | ||||||||||||||
| Regulated | ||||||||||||||
| Electric Revenue | ||||||||||||||
| Residential | $ | 627 | $ | 446 | $ | 97 | $ | - | $ | 1,170 | ||||
| Commercial | 336 | 210 | 126 | - | 672 | |||||||||
| Industrial | 94 | 107 | 19 | - | 220 | |||||||||
| Other electric and regulatory deferrals | 129 | 17 | 5 | - | 151 | |||||||||
| Other (1) | 9 | 13 | 19 | - | 38 | |||||||||
| Regulated electric revenue | 1,195 | 793 | 266 | - | 2,251 | |||||||||
| Gas Revenue | ||||||||||||||
| Residential | - | - | - | 261 | 261 | |||||||||
| Commercial | - | - | - | 141 | 141 | |||||||||
| Industrial | - | - | - | 27 | 26 | |||||||||
| Finance income (2)(3) | - | - | - | 30 | 30 | |||||||||
| Other | - | - | - | 84 | 80 | |||||||||
| Regulated gas revenue | - | - | - | 543 | 538 | |||||||||
| Non-Regulated | ||||||||||||||
| Marketing and trading margin (4) | - | - | - | - | 28 | |||||||||
| Energy sales (4) | - | - | - | - | (2) | |||||||||
| Other | - | - | - | 8 | 17 | |||||||||
| Mark-to-market (3) | - | - | - | - | (26) | |||||||||
| Non-regulated revenue | - | - | - | 8 | 17 | |||||||||
| Total operatingrevenues | $ | 1,195 | $ | 793 | $ | 266 | $ | 551 | **** | (18) | $ | 2,806 |
All values are in US Dollars.
(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.
65
| millions of Canadian dollars | Florida<br>Electric<br>Utility | Canadian<br>Electric<br>Utilities | Other<br>Electric<br>Utilities | Gas Utilities<br>and<br>Infrastructure | Other | Inter-<br>Segment<br>Eliminations | Total | |||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended June 30, 2019 | ||||||||||||||
| Regulated | ||||||||||||||
| Electric Revenue | ||||||||||||||
| Residential | $ | 348 | $ | 165 | $ | 65 | $ | - | $ | - | $ | 578 | ||
| Commercial | 187 | 94 | 91 | - | - | 372 | ||||||||
| Industrial | 56 | 53 | 11 | - | - | 120 | ||||||||
| Other electric and regulatory deferrals | 100 | 8 | 4 | - | - | 112 | ||||||||
| Other (1) | 6 | 7 | 17 | - | (3) | 27 | ||||||||
| Regulated electric revenue | 697 | 327 | 188 | - | (3) | 1,209 | ||||||||
| Gas Revenue | ||||||||||||||
| Residential | - | - | - | 93 | - | 93 | ||||||||
| Commercial | - | - | - | 61 | - | 61 | ||||||||
| Industrial | - | - | - | 13 | - | 13 | ||||||||
| Finance income (2)(3) | - | - | - | 15 | - | 15 | ||||||||
| Other | - | - | - | 57 | (5) | 52 | ||||||||
| Regulated gas revenue | - | - | - | 239 | (5) | 234 | ||||||||
| Non-Regulated | ||||||||||||||
| Marketing and trading margin (4) | - | - | - | - | - | (28) | ||||||||
| Energy sales (4) | - | - | - | - | (2) | - | ||||||||
| Capacity | - | - | - | - | - | (2) | ||||||||
| Other | - | - | - | 4 | (8) | 4 | ||||||||
| Mark-to-market (3) | - | - | - | - | - | (39) | ||||||||
| Non-regulated revenue | - | - | - | 4 | (10) | (65) | ||||||||
| Total operatingrevenues | $ | 697 | $ | 327 | $ | 188 | $ | 243 | (59) | $ (18) | $ | 1,378 | ||
| For the six months ended June 30, 2019 | ||||||||||||||
| Regulated | ||||||||||||||
| Electric Revenue | ||||||||||||||
| Residential | $ | 622 | $ | 417 | $ | 133 | $ | - | $ | - | $ | 1,172 | ||
| Commercial | 347 | 207 | 171 | - | - | 725 | ||||||||
| Industrial | 102 | 108 | 23 | - | - | 233 | ||||||||
| Other electric and regulatory deferrals | 162 | 24 | 7 | - | - | 193 | ||||||||
| Other (1) | 12 | 14 | 36 | - | (7) | 55 | ||||||||
| Regulated electric revenue | 1,245 | 770 | 370 | - | (7) | 2,378 | ||||||||
| Gas Revenue | ||||||||||||||
| Residential | - | - | - | 282 | - | 282 | ||||||||
| Commercial | - | - | - | 159 | - | 159 | ||||||||
| Industrial | - | - | - | 25 | - | 25 | ||||||||
| Finance income (2)(3) | - | - | - | 29 | - | 29 | ||||||||
| Other | - | - | - | 102 | (11) | 91 | ||||||||
| Regulated gas revenue | - | - | - | 597 | (11) | 586 | ||||||||
| Non-Regulated | ||||||||||||||
| Marketing and trading margin (4) | - | - | - | - | - | 26 | ||||||||
| Energy sales (4) | - | - | - | - | (6) | 74 | ||||||||
| Capacity | - | - | - | - | - | 36 | ||||||||
| Other | - | - | - | 8 | (15) | 11 | ||||||||
| Mark-to-market (3) | - | - | - | - | - | 85 | ||||||||
| Non-regulated revenue | - | - | - | 8 | (21) | 232 | ||||||||
| Total operatingrevenues | $ | 1,245 | $ | 770 | $ | 370 | $ | 605 | $ (39) | $ | 3,196 |
All values are in US Dollars.
(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.
66
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 June 30, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was $351 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.
7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
| Carrying Value<br>as at | Equity Income<br>for the<br>three months ended<br>June 30 | Equity Income<br>for the<br>six months ended<br>June 30 | Percentage<br>of<br>Ownership | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| June 30 | December 31 | |||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | 2020 | 2019 | 2020 | |||||||
| LIL (1) | $ | 603 | $ | 579 | $ | 12 | $ | 11 | $ | 24 | $ | 22 | 49.2 | |
| NSPML | **** | 558 | 554 | **** | 12 | 12 | **** | 27 | 26 | 100.0 | ||||
| M&NP (2) | **** | 137 | 138 | **** | 4 | 6 | **** | 9 | 12 | 12.9 | ||||
| Lucelec (2) | **** | 44 | 41 | **** | 1 | 1 | **** | 2 | 2 | 19.5 | ||||
| Bear Swamp (3) | **** | - | - | **** | 11 | 10 | **** | 19 | 18 | 50.0 | ||||
| $ | 1,342 | $ | 1,312 | $ | 40 | $ | 40 | $ | 81 | $ | 80 |
(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 Q4 2015. Bear Swamp’s credit investment balance of $132 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 24). NSPML’s consolidated summarized balance sheet is as follows:
| As at | June 30 | December 31 | ||
|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | ||
| Balance Sheet | ||||
| Current assets | $ | 66 | $ | 69 |
| Property, plant and equipment | **** | 1,650 | 1,671 | |
| Regulatory assets | **** | 206 | 177 | |
| Non-current assets | **** | 32 | 32 | |
| Total assets | $ | 1,954 | $ | 1,949 |
| Current liabilities | $ | 60 | $ | 23 |
| Long-term debt | **** | 1,248 | 1,288 | |
| Non-current liabilities | **** | 88 | 84 | |
| Equity | **** | 558 | 554 | |
| Total liabilities and equity | $ | 1,954 | $ | 1,949 |
67
8. OTHER INCOME (EXPENSES), NET
| For the<br>millions of Canadian dollars | Three months ended<br>June 30 | Six months ended<br>June 30 | |||||||
|---|---|---|---|---|---|---|---|---|---|
| 2020 | 2019 | 2020 | 2019 | ||||||
| Gain on sale and impairment charges (1) | $ | (4 | ) | - | **** | 560 | - | ||
| Allowance for equity funds used during<br>construction | **** | 11 | **** | 4 | **** | 20 | 8 | ||
| Other | **** | 17 | **** | 2 | **** | 7 | 11 | ||
| $ | 24 | **** | $ | 6 | $ | 587 | $ | 19 |
(1) Refer to note 4 for further details related to the gain on sale of Maine
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<br>millions of Canadian dollars | Three months ended<br><br><br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| 2020 | 2019 | 2020 | 2019 | |||||
| Income before provision for income taxes | $ | 80 | $ | 101 | $ | 921 | $ | 507 |
| Statutory income tax rate | **** | 29.5% | 31% | **** | 29.5% | 31% | ||
| Income taxes, at statutory income tax<br>rate | **** | 24 | 31 | **** | 272 | 157 | ||
| Additional impact from the sale of Emera<br>Maine | **** | 10 | - | **** | 102 | - | ||
| Amortization of deferred income tax regulatory<br>liabilities | **** | (11) | (11) | **** | (27) | (16) | ||
| Deferred income taxes on regulated income<br>recorded as regulatory assets and regulatory liabilities | **** | (6) | (13) | **** | (27) | (34) | ||
| Foreign tax rate variance | **** | (8) | (13) | **** | (17) | (25) | ||
| Revaluation of deferred income taxes due to<br>change in Nova Scotia tax rate | **** | - | - | **** | 12 | - | ||
| Tax effect of equity earnings | **** | (4) | (4) | **** | (8) | (9) | ||
| Other | **** | (6) | (5) | **** | (2) | (6) | ||
| Income tax expense (recovery) | $ | (1) | $ | (15) | $ | 305 | $ | 67 |
| Effective income tax rate | **** | (1)% | (15)% | **** | 33% | 13% |
The increase in the effective income tax rate was primarily due to the sale of Emera Maine. Year-over-year, the increase was also due to lower deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities.
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 per cent to 14 per cent. As a result, the Company’s combined Canadian federal and provincial statutory income tax rate was reduced from 31 per cent to 29.5 per cent for 2020 and further reduced to 29 per cent for subsequent years.
As a result of the enactment of the Financial Measures Act in Q1 2020, 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.
68
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.
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) | 1.73 | 99 | ||
| Issued for cash under Purchase Plans at market<br>rate | 1.81 | 101 | ||
| Discount on shares purchased under Dividend<br>Reinvestment Plan | - | (2 | ||
| Options exercised under senior management share<br>option plan | 0.42 | 20 | ||
| Employee Share Purchase Plan | - | 1 | ||
| Balance, June 30, 2020 | **** | 246.44 | **** | 6,435 |
All values are in US Dollars.
(1) In Q2 2020, 745,121 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $55.33 per share for gross proceeds of $41.2 million ($40.7 million net of issuance costs). During the six months ended June 30, 2020, 1,728,103 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $57.87 per share for gross proceeds of $100 million ($98.7 million net of issuance costs). As at June 30, 2020, an aggregate gross sales limit of $400 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<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars (except per share amounts) | 2020 | 2019 | 2020 | 2019 | ||||
| Numerator | ||||||||
| Net income attributable to common<br>shareholders | $ | 58.0 | $ | 103.5 | $ | 581.1 | $ | 415.3 |
| Diluted numerator | **** | 58.0 | 103.5 | **** | 581.1 | 415.3 | ||
| Denominator | ||||||||
| Weighted average shares of common stock<br>outstanding | **** | 245.4 | 237.7 | **** | 244.4 | 236.3 | ||
| Weighted average deferred share units<br>outstanding | **** | 1.3 | 1.5 | **** | 1.3 | 1.5 | ||
| Weighted average shares of common stock<br>outstanding – basic | **** | 246.7 | 239.2 | **** | 245.7 | 237.8 | ||
| Stock-based compensation | **** | 0.4 | 0.5 | **** | 0.4 | 0.5 | ||
| Dividend reinvestment plan | **** | 0.9 | - | **** | 0.9 | - | ||
| Convertible Debentures | **** | - | 0.1 | **** | - | 0.1 | ||
| Weighted average shares of common stockoutstanding – diluted | **** | 248.0 | 239.8 | **** | 247.0 | 238.4 | ||
| Earnings per common share | ||||||||
| Basic | $ | 0.24 | $ | 0.43 | $ | 2.37 | $ | 1.75 |
| Diluted | $ | 0.23 | $ | 0.43 | $ | 2.35 | $ | 1.74 |
69
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<br>(loss) gain on<br>translation of<br>self-sustaining<br>foreign<br>operations | Net change in<br>net investment<br>hedges | (Losses)<br>gains on<br>derivatives<br>recognized<br>as cash flow<br>hedges | Net change<br>in available-<br><br><br>for-sale<br>investments | Net change in<br>unrecognized<br>pension and<br>post-<br>retirement<br>benefit costs | Total AOCI | ||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the six months ended<br>June 30, 2020 | ||||||||||||
| Balance, January 1, 2020 | $ | 253 | $ | 4 | $ | (1) | $ | (1) | $ | (160) | $ | 95 |
| Other comprehensive income (loss) before reclassifications | **** | 395 | **** | (75) | **** | (2) | **** | - | **** | - | **** | 318 |
| Amounts reclassified from accumulated other comprehensive income loss (gain) | **** | - | **** | - | **** | 2 | **** | - | **** | (2) | **** | - |
| Net current period other comprehensive income (loss) | **** | 395 | **** | (75) | **** | - | **** | - | **** | (2) | **** | 318 |
| Balance, June 30, 2020 | $ | 648 | $ | (71) | $ | (1) | $ | (1) | $ | (162) | $ | 413 |
| For the six months ended June 30, 2019 | ||||||||||||
| Balance, January 1, 2019 | $ | 654 | $ | (74) | $ | (7) | $ | (1) | $ | (234) | $ | 338 |
| Other comprehensive income (loss) before reclassifications | (337) | 67 | 3 | - | - | (267) | ||||||
| Amounts reclassified from accumulated other comprehensive income loss (gain) | - | - | 2 | - | 8 | 10 | ||||||
| Net current period other comprehensive income (loss) | (337) | 67 | 5 | - | 8 | (257) | ||||||
| Balance, June 30, 2019 | $ | 317 | $ | (7) | $ | (2) | $ | (1) | $ | (226) | $ | 81 |
The reclassifications out of accumulated other comprehensive income (loss) are as follows:
| For the | Three months ended<br>June 30 | Six months ended<br>June 30 | |||||||
|---|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | |||||
| Affected line item in the<br><br><br>Consolidated Financial Statements | Amounts reclassified from AOCI | ||||||||
| Losses (gain) on derivatives recognized as cash flow hedges | |||||||||
| Foreign exchange<br><br><br>forwards | Operating revenue – regulated | $ | 1 | $ | - | $ | 2 | $ | 2 |
| Total | $ | 1 | $ | - | $ | 2 | $ | 2 | |
| Net change in unrecognized pension and post-retirement benefit costs | |||||||||
| Actuarial losses (gains) | OM&G | $ | 3 | $ | 4 | $ | 6 | $ | 9 |
| Amounts reclassified<br><br><br>into obligations | Pension and post-retirement liabilities | **** | - | - | **** | (8) | - | ||
| Total before tax | **** | 3 | 4 | **** | (2) | 9 | |||
| Income tax expense (recovery) | **** | - | - | **** | - | (1) | |||
| Total net of tax | $ | 3 | $ | 4 | $ | (2) | $ | 8 | |
| Total reclassifications out of AOCI, net of tax, for the period | $ | 4 | $ | 4 | $ | - | $ | 10 |
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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;<br> |
|---|---|
| ● | 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<br>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<br>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<br>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<br>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<br>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<br>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<br>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<br>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<br>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<br>accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. |
| --- | --- |
71
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
| Derivative Assets | Derivative Liabilities | |||||||
|---|---|---|---|---|---|---|---|---|
| As at | June 30 | December 31 | June 30 | December 31 | ||||
| millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | ||||
| Cash flow hedges | ||||||||
| Foreign exchange forwards | $ | - | $ | - | $ | 1 | $ | 1 |
| **** | - | - | **** | 1 | 1 | |||
| Regulatory deferral | ||||||||
| Commodity swaps and forwards | ||||||||
| Coal purchases | **** | 9 | 8 | **** | 33 | 39 | ||
| Power purchases | **** | 12 | 23 | **** | 45 | 36 | ||
| Natural gas purchases and sales | **** | 5 | 2 | **** | 5 | 5 | ||
| Heavy fuel oil purchases | **** | - | 1 | **** | 15 | - | ||
| Foreign exchange forwards | **** | 11 | 2 | **** | 1 | 6 | ||
| **** | 37 | 36 | **** | 99 | 86 | |||
| HFT derivatives | ||||||||
| Power swaps and physical contracts | **** | 11 | 19 | **** | 15 | 22 | ||
| Natural gas swaps, futures, forwards, physical<br>contracts | **** | 116 | 151 | **** | 240 | 381 | ||
| **** | 127 | 170 | **** | 255 | 403 | |||
| Other derivatives | ||||||||
| Equity derivatives | **** | - | 1 | **** | 5 | - | ||
| Foreign exchange forwards | **** | 9 | - | **** | 4 | - | ||
| **** | 9 | 1 | **** | 9 | - | |||
| Total gross current derivatives | **** | 173 | 207 | **** | 364 | 490 | ||
| Impact of master netting agreements with<br>intent to settle net or simultaneously | **** | (93) | (120) | **** | (93) | (120) | ||
| **** | 80 | 87 | **** | 271 | 370 | |||
| Current | **** | 48 | 54 | **** | 184 | 268 | ||
| Long-term | **** | 32 | 33 | **** | 87 | 102 | ||
| Total derivatives | $ | 80 | $ | 87 | $ | 271 | $ | 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 | June 30 | December 31 | June 30 | December 31 | ||||
| millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | ||||
| Regulatory deferral | $ | 9 | $ | 8 | $ | 9 | $ | 8 |
| HFT derivatives | **** | 84 | 112 | **** | 84 | 112 | ||
| Total impact of master netting agreements with intent to settle<br>net or simultaneously | $ | 93 | $ | 120 | $ | 93 | $ | 120 |
72
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:
| Three months ended | Six months ended | |||||||
|---|---|---|---|---|---|---|---|---|
| For the | June 30 | June 30 | ||||||
| millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | ||||
| Foreign Exchange<br>Forwards | Foreign Exchange<br>Forwards | |||||||
| Realized gain (loss) in operating revenue –<br>regulated | $ | (1) | $ | - | $ | (2) | $ | (2) |
| Total gains (losses) in net income | $ | (1) | $ | - | $ | (2) | $ | (2) |
| As at<br>millions of Canadian dollars | June 302020 | December 31<br>2019 | ||||||
| Foreign Exchange Forwards | ||||||||
| Total unrealized gain (loss) in AOCI –<br>net of tax | $ | (1) | $ | (1) |
The Company expects $1 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.
As at June 30, 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 | $ | 12 |
Regulatory Deferral
The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:
| For the | Three months ended June 30 | |||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | ||||||
| **** | Commodityswaps andforwards | **** | Foreignexchangeforwards | Commodity<br>swaps and<br>forwards | Foreign<br>exchange<br>forwards | |||
| Unrealized gain (loss) in regulatory<br>assets | $ | 24 | $ | (1) | $ | (52) | $ | (6) |
| Unrealized gain (loss) in regulatory<br>liabilities | **** | 7 | **** | (20) | 13 | (3) | ||
| Realized (gain) loss in regulatory<br>assets | **** | 1 | **** | - | - | - | ||
| Realized (gain) loss in regulatory<br>liabilities | **** | 3 | **** | - | (1) | - | ||
| Realized (gain) loss in inventory (1) | **** | 3 | **** | (2) | (6) | (3) | ||
| Realized (gain) loss in regulated fuel for<br>generation and purchased power (2) | **** | 7 | **** | (2) | - | (3) | ||
| Total change in derivative<br>instruments | $ | 45 | $ | (25) | $ | (46) | $ | (15) |
(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.
73
| For the | Six months ended June 30 | |||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | ||||||
| Commodityswaps andforwards | Foreignexchangeforwards | Commodity<br>swaps and<br>forwards | Foreign<br>exchange<br>forwards | |||||
| Unrealized gain (loss) in regulatory<br>assets | $ | (50) | $ | 5 | $ | (46) | $ | (7) |
| Unrealized gain (loss) in regulatory<br>liabilities | **** | (3) | **** | 15 | (6) | (8) | ||
| Realized (gain) loss in regulatory<br>assets | **** | 1 | **** | - | - | - | ||
| Realized (gain) loss in regulatory<br>liabilities | **** | 10 | **** | - | 4 | - | ||
| Realized (gain) loss in inventory (1) | **** | 3 | **** | (3) | (24) | (8) | ||
| Realized (gain) loss in regulated fuel for<br>generation and purchased power (2) | **** | 13 | **** | (3) | (2) | (5) | ||
| Total change in derivative<br>instruments | $ | (26) | $ | 14 | $ | (74) | $ | (28) |
(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 June 30, 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) | 5 | 17 |
| Power (MWh) | - | 3 |
| Heavy fuel oil (bbls) | - | 1 |
| Coal (metric tonnes) | - | 1 |
Foreign Exchange Swaps and Forwards
As at June 30, 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<br>dollars) | 78 | $ | 259 |
| Weighted average rate | 1.3240 | 1.3381 | |
| % of requirements | 67% | 67% |
All values are in US Dollars.
The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required.
74
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.
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
| For the | Three months ended | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | June 30 | June 30 | ||||||
| 2020 | 2019 | 2020 | 2019 | |||||
| Power swaps and physical contracts in non-regulated operating revenues | $ | (1) | $ | 2 | $ | - | $ | 2 |
| Natural gas swaps, forwards, futures and physical<br>contracts in non-regulated operating revenues | **** | 11 | 43 | **** | 222 | 247 | ||
| Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power | **** | - | (3) | **** | (4) | (5) | ||
| $ | 10 | $ | 42 | $ | 218 | $ | 244 |
As at June 30, 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) | 338 | 151 | 56 | 41 | 26 | |||||
| Natural gas sales (Mmbtu) | 316 | 102 | 13 | 4 | 2 | |||||
| Power purchases (MWh) | 2 | - | - | - | - | |||||
| Power sales (MWh) | 2 | - | - | - | - |
Other Derivatives
As at June 30, 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 $215 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 June 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | |||||||
| **** | ForeignExchangeForwards | **** | **** | Foreign<br>Exchange<br>Forwards | Equity<br>Derivatives | ||||
| Unrealized gain (loss) in operating, maintenance<br>and general | $ | - | **** | (6) | $ | - | $ | 9 | |
| Unrealized gain (loss) in other income<br>(expense) | **** | 13 | **** | **** | - | - | |||
| Realized gain (loss) in other income<br>(expense) | **** | (3 | ) | - | - | ||||
| Total gains (losses) in net income | $ | 10 | **** | (6) | $ | - | $ | 9 |
All values are in US Dollars.
75
| For the | Six months ended June 30 | |||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | ||||||
| **** | ForeignExchangeForwards | **** | EquityDerivatives | Foreign<br>Exchange<br>Forwards | Equity<br>Derivatives | |||
| Unrealized gain (loss) in operating, maintenance<br>and general | $ | - | $ | (7) | $ | - | $ | 23 |
| Unrealized gain (loss) in other income<br>(expense) | **** | 4 | **** | - | - | - | ||
| Realized gain (loss) in other income<br>(expense) | **** | (4) | **** | - | - | - | ||
| Total gains (losses) in net income | $ | - | $ | (7) | $ | - | $ | 23 |
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.
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 June 30, 2020, the Company had $162 million (December 31, 2019 - $115 million) in financial assets considered to be past due, which have been outstanding for an average 70 days. The fair value of these financial assets is $144 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.
76
Cash Collateral
The Company’s cash collateral positions consisted of the following:
| As at<br><br><br>millions of Canadian dollars | June 302020 | December 31<br>2019 | ||
|---|---|---|---|---|
| Cash collateral provided to others | $ | 110 | $ | 101 |
| Cash collateral received from others | **** | 4 | 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 June 30, 2020, the total fair value of these derivatives, in a liability position, was $271 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.
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<br>and locational basis differentials. |
|---|---|
| ● | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions<br>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<br>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.
77
The following tables set out the classification of the methodology used by the Company to fair value its derivatives:
| As at | June 30, 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 | **** | 3 | **** | 2 | **** | - | **** | 5 |
| Foreign exchange forwards | **** | - | **** | 11 | **** | - | **** | 11 |
| **** | 15 | **** | 13 | **** | - | **** | 28 | |
| HFT derivatives | ||||||||
| Power swaps and physical contracts | **** | 3 | **** | 1 | **** | 1 | **** | 5 |
| Natural gas swaps, futures, forwards, physical contracts and related transportation | **** | - | **** | 27 | **** | 11 | **** | 38 |
| **** | 3 | **** | 28 | **** | 12 | **** | 43 | |
| Other derivatives | ||||||||
| Foreign exchange forwards | **** | - | **** | 9 | **** | - | **** | 9 |
| **** | - | **** | 9 | **** | - | **** | 9 | |
| Total assets | **** | 18 | **** | 50 | **** | 12 | **** | 80 |
| Liabilities | ||||||||
| Cash flow hedges | ||||||||
| Foreign exchange forwards | **** | - | **** | 1 | **** | - | **** | 1 |
| **** | - | **** | 1 | **** | - | **** | 1 | |
| Regulatory deferral | ||||||||
| Commodity swaps and forwards | ||||||||
| Coal purchases | **** | - | **** | 24 | **** | - | **** | 24 |
| Power purchases | **** | 45 | **** | - | **** | - | **** | 45 |
| Heavy fuel oil purchases | **** | 6 | **** | 9 | **** | - | **** | 15 |
| Natural gas purchases and sales | **** | 3 | **** | 3 | **** | - | **** | 6 |
| Foreign exchange forwards | **** | - | **** | 1 | **** | - | **** | 1 |
| **** | 54 | **** | 37 | **** | - | **** | 91 | |
| HFT derivatives | ||||||||
| Power swaps and physical contracts | **** | 7 | **** | 1 | **** | - | **** | 8 |
| Natural gas swaps, futures, forwards and physical contracts | **** | 9 | **** | 7 | **** | 146 | **** | 162 |
| **** | 16 | **** | 8 | **** | 146 | **** | 170 | |
| Other derivatives | ||||||||
| Foreign exchange forwards | **** | - | **** | 4 | **** | - | **** | 4 |
| Equity derivatives | **** | 5 | **** | - | **** | - | **** | 5 |
| **** | 5 | **** | 4 | **** | - | **** | 9 | |
| Total liabilities | **** | 75 | **** | 50 | **** | 146 | **** | 271 |
| Net assets (liabilities) | $ | (57) | $ | - | $ | (134) | $ | (191) |
78
| 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<br>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 June 30, 2020 was as follows:
| HFT Derivatives | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | Power | Natural<br><br><br>gas | Total | ||||||
| Balance, beginning of period | $ | 4 | **** | $ | 15 | **** | $ | 19 | **** |
| Total realized and unrealized losses included in non-regulated operating revenues | **** | (1 | ) | **** | (4 | ) | **** | (5 | ) |
| Net transfers out of Level 3 | **** | (2 | ) | **** | - | **** | **** | (2 | ) |
| Balance, June 30, 2020 | $ | 1 | **** | $ | 11 | **** | $ | 12 | **** |
79
The change in the fair value of the Level 3 financial liabilities for the three months ended June 30, 2020 was as follows:
| HFT Derivatives | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | Power | Natural<br>gas | Total | ||||||
| Balance, beginning of period | $ | 3 | **** | $ | 152 | **** | $ | 155 | **** |
| Total realized and unrealized losses included in non-regulated operating revenues | **** | (2 | ) | **** | (6 | ) | **** | (8 | ) |
| Net transfers out of Level 3 | **** | (1 | ) | **** | - | **** | **** | (1 | ) |
| Balance, June 30, 2020 | $ | - | **** | $ | 146 | **** | $ | 146 | **** |
The change in the fair value of the Level 3 financial assets for the six months ended June 30, 2020 was as follows:
| HFT Derivatives | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | Power | Natural<br>gas | Total | ||||||
| Balance, beginning of period | $ | 1 | **** | $ | 14 | **** | $ | 15 | **** |
| Total realized and unrealized gains (losses)<br>included in non-regulated operating revenues | **** | 2 | **** | **** | (3 | ) | **** | (1 | ) |
| Net transfers out of Level 3 | **** | (2 | ) | **** | - | **** | **** | (2 | ) |
| Balance, June 30, 2020 | $ | 1 | **** | $ | 11 | **** | $ | 12 | **** |
The change in the fair value of the Level 3 financial liabilities for the six months ended June 30, 2020 was as follows:
| HFT Derivatives | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | Power | Natural<br>gas | Total | ||||||
| Balance, beginning of period | $ | - | **** | $ | 249 | **** | $ | 249 | **** |
| Total realized and unrealized gains (losses)<br>included in non-regulated operating revenues | **** | 1 | **** | **** | (103 | ) | **** | (102 | ) |
| Net transfers out of Level 3 | **** | (1 | ) | **** | - | **** | **** | (1 | ) |
| Balance, June 30, 2020 | $ | - | **** | $ | 146 | **** | $ | 146 | **** |
The Company evaluates observable inputs of market data on a quarterly basis to determine if transfers between levels is appropriate. For the three and six months ended June 30, 2020, transfers out of Level 3 were a result of an increase in observable inputs.
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.
80
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 | June 30, 2020 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | FairValue | Valuation<br><br><br>Technique | Unobservable Input | Weighted<br><br><br>Range average (1) | |||||
| Assets | |||||||||
| HFT derivatives – | $ | 1 | Modelled pricing | Third-party pricing | $17.50-$62.90 | $29.66 | |||
| Power swaps and | Probability of default | 0.02%-22.18% | 9.25% | ||||||
| physical contracts | Discount rate | 0.01%-0.87% | 0.44% | ||||||
| HFT derivatives – | **** | 7 | Modelled pricing | Third-party pricing | $1.10-$4.10 | $2.03 | |||
| Natural gas swaps, futures, | Probability of default | 0.01%-28.01% | 3.77% | ||||||
| forwards, physical contracts | Discount rate | 0.00%-7.36% | 0.29% | ||||||
| **** | 4 | Modelled pricing | Third-party pricing | $1.21-$8.28 | $3.27 | ||||
| Basis adjustment | $0.00-$1.27 | $0.73 | |||||||
| Probability of default | 0.34%-16.25% | 6.81% | |||||||
| Discount rate | 0.00%-0.63% | 0.25% | |||||||
| Total assets | $ | 12 | |||||||
| Liabilities | |||||||||
| HFT derivatives – | **** | 138 | Modelled pricing | Third-party pricing | $1.10-$7.22 | $3.60 | |||
| Natural gas swaps, futures, | Own credit risk | 0.14%-28.01% | 5.43% | ||||||
| forwards and physical contracts | Discount rate | 0.00%-7.73% | 0.54% | ||||||
| **** | 8 | Modelled pricing | Third-party pricing | $0.77-$8.28 | $3.37 | ||||
| Basis adjustment | $0.00-$1.27 | $0.62 | |||||||
| Own credit risk | 0.34%-11.79% | 3.03% | |||||||
| Discount rate | 0.00%-0.59% | 0.24% | |||||||
| Total liabilities | $ | 146 | |||||||
| Net assets (liabilities) | $ | (134) |
(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 | ||||||
| June 30, 2020 | $ | 14,304 | $ | 16,735 | $ | - | $ | 16,205 | $ | 530 | $ | 16,735 |
| 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 gain of $66 million was recorded in Other Comprehensive Income for the three months ended June 30, 2020 (2019 – $33 million gain after-tax). An after-tax foreign currency loss of $75 million was recorded in Other Comprehensive Income for the six months ended June 30, 2020 (2019 – $67 million gain after-tax).
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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<br> <br>millions of Canadian<br>dollars | June 30<br><br><br>2020 | December 31<br>2019 | ||
|---|---|---|---|---|
| Regulatory assets | ||||
| Deferred income tax regulatory assets | $ | 863 | $ | 862 |
| Pension and post-retirement medical plan | **** | 390 | 380 | |
| Deferrals related to derivative instruments | **** | 91 | 81 | |
| Storm restoration regulatory asset | **** | 41 | 38 | |
| Environmental remediations | **** | 29 | 26 | |
| Stranded cost recovery | **** | 28 | 27 | |
| Demand side management (“DSM”) deferral | **** | 17 | 19 | |
| Unamortized defeasance costs | **** | 16 | 19 | |
| Cost recovery clauses | **** | 9 | 13 | |
| Other | **** | 75 | 87 | |
| $ | 1,559 | $ | 1,552 | |
| Current | $ | 133 | $ | 121 |
| Long-term | **** | 1,426 | 1,431 | |
| Total regulatory assets | $ | 1,559 | $ | 1,552 |
| Regulatory liabilities | ||||
| Deferred income tax regulatory liabilities | $ | 1,005 | $ | 985 |
| Accumulated reserve - cost of removal | **** | 929 | 891 | |
| Regulated fuel adjustment mechanism | **** | 106 | 115 | |
| Cost recovery clauses | **** | 99 | 53 | |
| Storm reserve | **** | 65 | 62 | |
| Self-insurance fund (note 24) | **** | 30 | 29 | |
| Deferrals related to derivative instruments | **** | 29 | 42 | |
| Other | **** | 8 | 4 | |
| $ | 2,271 | $ | 2,181 | |
| Current | $ | 265 | $ | 295 |
| Long-term | **** | 2,006 | 1,886 | |
| Total regulatory liabilities | $ | 2,271 | $ | 2,181 |
Tampa Electric
On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) 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. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million USD base rate reduction for costs previously recovered in base rates related to SPP programs beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 million USD in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million USD of costs reduced from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery will begin in January 2021. Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025.
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The June 9, 2020 settlement agreement approved by the FPSC disclosed above also included approval of Tampa Electric’s petition to eliminate its $16 million USD accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020. As stipulated in the settlement, $8 million USD of this credit was recognized in Q2 2020 with the remaining $8 million USD to be recognized over the remainder of 2020.
On June 1, 2020, as part of its Big Bend Power Station modernization project, Tampa Electric retired Unit 1 components that will not be used in the modernized plant. At June 1, 2020, the balance sheet included $304 million ($223 million USD) and $123 million ($90 million USD) in property, plant and equipment and accumulated depreciation, respectively, related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021 early as part of the modernization project.
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 was 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.
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 June 30, 2020, $14 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. This recovery is now expected to start on October 1, 2020.
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| 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<br>Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $27 million for the three months ended June 30, 2020 (2019 - $27 million) and $55 million for the six months ended<br>June 30, 2020 (2019 - $54 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<br>Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $3 million for the three months ended June 30, 2020 (2019 - $16 million) and $11 million for the six<br>months ended June 30, 2020 (2019 - $34 million). |
| --- | --- |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at June 30, 2020 and at December 31, 2019.
| 17. | RECEIVABLES AND OTHER CURRENT ASSETS |
|---|
Receivables and other current assets consisted of the following:
| As at<br><br><br>millions of Canadian dollars | **** | June 302020 | December 31<br>2019 | |
|---|---|---|---|---|
| Customer accounts receivable – billed | $ | 527 | $ | 603 |
| Customer accounts receivable – unbilled | **** | 239 | 265 | |
| Allowance for doubtful accounts | **** | (19) | (9) | |
| Capitalized transportation capacity (1) | **** | 145 | 272 | |
| Income tax receivable | **** | 156 | 118 | |
| Prepaid expenses | **** | 104 | 48 | |
| Other | **** | 173 | 189 | |
| $ | 1,325 | $ | 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.
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| 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 20 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<br><br><br>millions of Canadian dollars | Three months ended<br>June 30 | Six months ended<br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| **** | 2020 | 2019 | **** | 2020 | 2019 | |||
| Defined benefit pension plans | ||||||||
| Service cost | $ | 12 | $ | 12 | $ | 24 | $ | 24 |
| Non-service cost | ||||||||
| Interest cost | **** | 21 | 26 | **** | 43 | 52 | ||
| Expected return on plan assets | **** | (36) | (38) | **** | (73) | (75) | ||
| Current year amortization of: | ||||||||
| Actuarial losses | **** | 3 | 4 | **** | 7 | 8 | ||
| Regulatory asset | **** | 7 | 5 | **** | 14 | 10 | ||
| Settlements and curtailments | **** | - | 1 | **** | - | 1 | ||
| Total non-service costs | **** | (5) | (2) | **** | (9) | (4) | ||
| Total defined benefit pensionplans | **** | 7 | 10 | **** | 15 | 20 | ||
| Non-pension benefit plans | ||||||||
| Service cost | **** | 1 | 1 | **** | 2 | 2 | ||
| Non-service cost | ||||||||
| Interest cost | **** | 3 | 3 | **** | 6 | 7 | ||
| Expected return on plan assets | **** | (1) | - | **** | (1) | (1) | ||
| Current year amortization of: | ||||||||
| Regulatory asset | **** | - | (1) | **** | - | (3) | ||
| Total non-service<br>costs | **** | 2 | 2 | **** | 5 | 3 | ||
| Total non-pensionbenefit plans | **** | 3 | 3 | **** | 7 | 5 | ||
| Total defined benefit plans | $ | 10 | $ | 13 | $ | 22 | $ | 25 |
Emera’s contributions related to these defined-benefit plans for the three months ended June 30, 2020 were $14 million (2019 – $18 million), and for the six months ended June 30, 2020 were $30 million (2019 – $34 million). Annual employer contributions to the defined benefit pension plans are estimated to be $39 million for 2020.
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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 ElectricUtilities
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.
Other
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. Using funds from the sale of Emera Maine, on April 3, 2020, TECO Energy/Finance repaid $200 million USD of the term loan and the remaining $300 million USD was repaid on June 30, 2020.
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 May 20, 2020, GBPC entered into a $22 million USD non-revolving term loan with a maturity date of May 20, 2025. The loan bears interest at a rate of 90-day LIBOR plus a margin. On May 22, 2020, proceeds from this loan were used to repay $22 million USD senior notes upon maturity.
On May 20, 2020, GBPC entered into a $15 million BSD ($15 million USD) non-revolving term loan with a maturity date of May 20, 2025. The loan bears interest at a rate of 4.00 per cent.
On May 18, 2020, BLPC received an advance of $27 million BBD ($13 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. At June 30, 2020, $67 million BBD ($33 million USD) was drawn against this facility.
Other
On March 13, 2020, TECO Finance repaid a $300 million USD note upon maturity. The note was repaid using existing credit facilities.
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21. COMMITMENTS AND CONTINGENCIES
| A. | Commitments |
|---|
As at June 30, 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) | $ | 142 | $ | 217 | $ | 218 | $ | 216 | $ | 219 | $ | 1,905 | $ | 2,917 |
| Transportation (2) | 296 | 430 | 379 | 316 | 283 | 2,673 | 4,377 | |||||||
| Capital projects (3) | 251 | 166 | 112 | 93 | – | – | 622 | |||||||
| Fuel, gas supply and storage | 274 | 217 | 41 | 6 | 1 | – | 539 | |||||||
| Long-term service agreements (4) | 52 | 23 | 23 | 21 | 29 | 70 | 218 | |||||||
| Equity investment commitments (5) | – | 240 | – | – | – | – | 240 | |||||||
| Leases and other (6) | 10 | 20 | 19 | 19 | 16 | 131 | 215 | |||||||
| Demand side management | 17 | 41 | 43 | – | – | – | 101 | |||||||
| $ | 1,042 | $ | 1,354 | $ | 835 | $ | 671 | $ | 548 | $ | 4,779 | $ | 9,229 |
(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 $418 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 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 declared force majeure under various project contracts, including formal notification to NSPML. Nalcor resumed work in May 2020 and is assessing the impact of the construction pause on its completion schedule.
NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls. On July 31, 2020, NSPML filed an interim assessment application with the UARB requesting recovery of 2021 costs of approximately $172 million from NSPI, with a decision expected in Q4 2020.
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 June 30, 2020, $53 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.
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| 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. On May 13, 2020, the second tribunal awarded TGH additional damages and costs against Guatemala of more than $35 million USD plus interest.
In addition, TGH sued Guatemala in Washington, D.C. court to enforce the previously awarded $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 ManufacturedGas 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 June 30, 2020, TEC has estimated its financial liability to be $29 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.
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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 2020 with respect to any of the four complaints filed with the Federal Energy Regulatory Commission.
Other LegalProceedings
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.
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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.
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.
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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.
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 updates as noted below:
The Company has standby letters of credit and surety bonds in the amount of $35 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.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2021. The amount committed as at June 30, 2020 was $63 million (December 31, 2019 - $52 million).
On May 15, 2020, the Company issued a guarantee of up to $60 million USD relating to outstanding notes of GBPC. The guarantee was reduced to $35 million USD upon repayment of certain notes, by GBPC, on May 22, 2020.
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22. CUMULATIVE PREFERRED STOCK
For details regarding cumulative preferred stock refer to note 27 in Emera’s 2019 annual audited financial statements, with updates as noted below:
On July 9, 2020, Emera announced that it would not redeem the currently outstanding Cumulative Rate Reset Preferred Shares, Series A (“Series A Shares”) or the Cumulative Floating Rate First Preferred Shares, Series B (“Series B Shares”) on August 15, 2020 (the “Conversion Date”). There are currently 3,864,636 Series A Shares and 2,135,364 Series B Shares outstanding.
On July 16, 2020, Emera announced a dividend rate of 2.182 per cent per annum on the Series A Shares during the five-year period commencing on August 15, 2020 and ending on (and inclusive of) August 14, 2025 ($0.1364 per Series A Share per quarter). Emera also announced a dividend rate of 2.021 per cent on the Series B Shares for the three-month period commencing on August 15, 2020 and ending on (and inclusive of) November 14, 2020 ($0.1274 per Series B Share for the quarter).
During the conversion period between July 16, 2020 and July 31, 2020, the holders of Series A Shares had the right, at their option to convert all or any of their Series A Shares, on a one-for-one basis, into Series B Shares and the holders of Series B Shares had the right, at their option to convert all or any of their Series B Shares, on a one-for-one basis, into Series A Shares. On the Conversion Date, Emera expects that there will be 4,866,814 Series A Shares and 1,133,186 Series B Shares outstanding.
23. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the | Six months ended June 30 | |||
|---|---|---|---|---|
| millions of Canadian dollars | 2020 | 2019 | ||
| Changes in non-cash working capital: | ||||
| Inventory | $ | 5 | $ | 8 |
| Receivables and other current assets | **** | 81 | 349 | |
| Accounts payable | **** | (144) | (279) | |
| Other current liabilities | **** | (17) | (46) | |
| Total non-cash working<br>capital | $ | (75) | $ | 32 |
| Supplemental disclosure of non-cash activities: | ||||
| Dividends payable | $ | 162 | $ | - |
| Common share dividends reinvested | $ | 93 | $ | 96 |
| Decrease (increase) in accrued capital expenditures | $ | 38 | $ | (10) |
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24. 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 VIE’s. 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 the 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 “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 | June 30, 2020 | December 31, 2019 | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars | Totalassets | Maximumexposure toloss | Total<br>assets | Maximum<br>exposure to<br>loss | ||||
| Unconsolidated VIEs in which Emera has variable interests | ||||||||
| NSPML (equity accounted) | $ | 558 | $ | 20 | $ | 554 | $ | 23 |
25. 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.
26. SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through August 11, 2020, the date the financial statements were issued.
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EX-99.3
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:
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 June 30, 2020.
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.
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.
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.
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<br> |
|---|---|
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the<br>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<br>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<br>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<br>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<br>filings; and |
| --- | --- |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the<br>issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
| --- | --- |
- Reporting changesin ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2020 and ended on June 30, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: August 11, 2020 |
|---|
| “Scott Bafour” |
| Scott Balfour<br><br><br>President and Chief Executive Officer |
EX-99.4
Exhibit 99.4
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Greg Blunden, Chief Financial Officer of Emera Incorporated, **** certify the following:
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 June 30, 2020.
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.
Fairpresentation: 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.
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.
- 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<br> |
|---|---|
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the<br>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<br>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<br>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<br>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<br>filings; and |
| --- | --- |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the<br>issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
| --- | --- |
- Reporting changesin ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2020 and ended on June 30, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: August 11, 2020 |
|---|
| “Greg Blunden” |
| Greg Blunden<br> <br>Chief Financial Officer |
EX-99.5
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 six months ended June 30, 2020.
The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended June 30, 2020.
| Twelve months ended<br><br><br>June 30, 2020 | |
|---|---|
| Earnings Coverage ^(1)^ | 2.33 |
^(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 29.4 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 29.4 per cent, amounted to $79 million **** for the twelve months ended June 30, 2020. Emera’s interest requirements for the twelve months ended June 30, 2020 amounted to $738 million. Emera’s consolidated income before interest and income tax for the twelve months ended June 30, 2020 was $1,905 million, which is 2.33 times Emera’s aggregate preferred dividends and interest requirements for this period.
EX-99.6
Exhibit 99.6
Emera Reports 2020 Second Quarter Financial Results
HALIFAX, Nova Scotia — Today Emera (TSX: EMA) announced financial results for the second quarter of 2020.
Q2 2020 and Year-to-Date Highlights:
Reported Net Income
| ● | Q2 2020 reported net income was $58 million, or $0.24 per common share, compared with net income of $103 million,<br>or $0.43 per common share, in Q2 2019. |
|---|---|
| ● | Year-to-date reported net income was<br>$581 million, or $2.37 per common share, compared with net income of $415 million, or $1.75 per common share, in the 2019 period. |
| --- | --- |
Adjusted Net Income ^(1)^
| ● | Q2 2020 adjusted net income was $118 million, or $0.48 per common share, compared with $130 million, or $0.54 per<br>common share, in Q2 2019. |
|---|---|
| ● | Year-to-date adjusted net income was<br>$311 million, or $1.27 per common share, compared with $354 million, or $1.49 per common share, in the 2019 period. |
| --- | --- |
“As our communities continue to deal with the challenges of the global pandemic, our employees remain focused on safely providing the essential energy to our customers,” says Scott Balfour, President and Chief Executive Officer of Emera. “Our businesses delivered solid financial results this quarter and as we look forward, Emera remains committed to our long-term strategy and capital program which are focused on safely delivering cleaner, affordable and reliable energy.”
Significant Items Affecting Reported and Adjusted Net Income
| ● | Reported earnings for the quarter included a $12 million adjustment to the gain on sale of Emera Maine bringing the<br>final year-to-date gain to $309 million, net of tax and transaction costs. In addition, impairment charges of $3 million quarter-to-date and $26 million year-to date after-tax were recognized on certain assets. |
|---|---|
| ● | Adjusted earnings were impacted by asset sales, including Emera Maine, the New England Gas Generating (“NEGG”)<br>and Bayside generation facilities (the “Gas Plants”), and the property in Florida: |
| --- | --- |
| o | Earnings contribution from Emera Maine was $12 million lower in Q2 2020 than in Q2 2019 and $16 million<br>lower year-to-date due to the sale of Emera Maine in March 2020. |
| --- | --- |
| o | Earnings contribution from Emera Energy Generation was $21 million lower year-to-date than in 2019 due to the sale of the Gas Plants in March 2019. |
| --- | --- |
| o | 2019 year-to-date adjusted net<br>earnings included a $10 million gain on sale of property in Florida. |
| --- | --- |
| ● | Emera’s earnings for the quarter were also impacted by items that are not expected to recur: |
| --- | --- |
| o | Q2 2020 results were lower by $11 million due to the timing of the approval of preferred dividends. In 2019,<br>these dividends approved were expensed in Q3. |
| --- | --- |
| o | Q2 2019 adjusted net earnings included $12 million due to the 2019 recognition of tax reform benefits at New<br>Mexico Gas Company (“NMGC”). |
| --- | --- |
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| ● | Emera’s earnings year-to-date, were<br>also impacted by items that are not expected to recur: |
|---|---|
| o | 2020 year-to-date adjusted earnings<br>were lower by $14 million due to the revaluation of net deferred income tax assets and liabilities due to the reduction in the Nova Scotia provincial corporate income tax rate, recorded in Q1. |
| --- | --- |
| o | 2020 year-to-date adjusted earnings<br>were higher due to the recognition of corporate income tax recovery of $10 million deferred as a regulatory liability at Barbados Light & Power Company Limited (“BLPC”). |
| --- | --- |
Cash Flow
| ● | Year-to-date operating cash flow, before<br>changes in working capital, increased by $41 million to $816 million, compared with $775 million in the 2020 period. |
|---|
^(1)^ See “Non-GAAP Measures” noted below.
FinancialHighlights:
| For the | Three months ended | Six months ended | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars (except per share amounts) | June 30 | June 30 | ||||||
| 2020 | 2019 | 2020 | 2019 | |||||
| Net income attributable to common shareholders | $ | 58 | $ | 103 | $ | 581 | $ | 415 |
| Gain on sale and impairment charges, net of tax | $ | (15) | - | $ | 283 | - | ||
| After-tax mark-to-market gain (loss) | **** | (45) | (27) | **** | (13) | 61 | ||
| Adjusted net income attributable to common shareholders^(1)(2)^ | $ | 118 | $ | 130 | $ | 311 | $ | 354 |
| Earnings per common share – basic | $ | 0.24 | $ | 0.43 | $ | 2.37 | $ | 1.75 |
| Adjusted earnings per common share – basic<br>^(1)(2)^ | $ | 0.48 | $ | 0.54 | $ | 1.27 | $ | 1.49 |
| Weighted average shares of common stock outstanding - basic (millions of shares) | **** | 247 | 239 | **** | 246 | 238 |
^(1)^ See “Non-GAAPMeasures” noted below
^(2)^ Adjusted net income and adjusted earnings per common shareexclude the effect of mark-to-market adjustments, gain on sale and impairment charges
Emera’s adjusted earnings and adjusted earnings per share increased for the quarter and year-to-date when normalized for the impacts of the one-time items, and asset sales referenced above ($35 million or $0.15 earnings per share for the quarter and $52 million for the year-to-date or $0.22 earnings per share). The increase earnings and earnings per share in these periods was driven by favourable results at Tampa Electric, partially offset by reduced earnings at NSP and Emera Caribbean.
After-tax mark-to-market losses increased $18 million to $45 million in Q2 2020, compared to $27 million in Q2 2019. This increase was due to changes in existing positions on gas contracts and higher amortization of gas transportation assets in 2020, partially offset by gains related to foreign exchange cash flow hedges entered in 2020 to manage foreign exchange earnings exposure. Year-to-date, after-tax mark-to-market decreased $74 million to a $13 million loss in 2020, compared to a $61 million gain in 2019. This decrease was due to 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 and gains related to foreign exchange cash flow hedges
The weakening of the CAD exchange rates increased earnings by $9 million and adjusted earnings by $3 million in Q2 2020 compared to Q2 2019. The weakening of the CAD exchange rates increased earnings
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by $14 million and adjusted earnings by $4 million year-to-date in 2020 compared to the same period in 2019.
Consolidated Financial Review:
The following table highlights significant changes in adjusted net income from 2019 to 2020 in the second quarter and year-to-date periods.
| For the | ||
|---|---|---|
| millions of Canadian dollars | ||
| Adjusted net income – 2019(1)(2) | 130 | $ 354 |
| Increased earnings at Tampa Electric in both periods due to customer growth, increased sales to residential customers, higher allowance<br>for funds used during construction (“AFUDC”) earnings from the Big Bend modernization and solar projects, lower operating, maintenance and general (“OM&G”) expenses, in-service of solar<br>generation and lower depreciation and amortization expense as a result of a regulatory settlement. In addition, favourable weather contributed to the year-over-year increase | 21 | 39 |
| Increased earnings at Emera Energy Services due to favourable hedges, lower fixed commitments for gas transportation and storage assets<br>and more favorable market conditions | 9 | - |
| Decreased earnings at Nova Scotia Power Inc. (“NSPI”) due to the impacts of COVID-19 on<br>sales volumes, unfavourable weather in Q1 2020, a corporate income tax recovery in Q2 2019 related to a change in legislation which impacted the timing of property, plant and equipment deductions, a higher effective tax rate and higher storm<br>costs | (6) | (11) |
| Timing of preferred share dividend declaration | (11) | (11) |
| 2019 recognition of tax reform benefits from 2018 in NMGC | (12) | (12) |
| Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities due to the Q1 2020 reduction in the Nova<br>Scotia provincial corporate income tax rate | - | (14) |
| Lower earnings contribution from the Caribbean utilities in both periods due to the impacts of<br>COVID-19 at BLPC and Grand Bahama Power Company Limited (“C”) and the continued recovery from Hurricane Dorian at C. Year-over-over year decrease partially offset by recognition of corporate<br>income tax recovery of 10 million deferred as a regulatory liability in 2018 at BLPC | (12) | (4) |
| Lower earnings contribution from Emera Maine due to the sale in Q1 2020 | (12) | (16) |
| Decreased earnings year-over year from Emera Energy Generation due to the sale of Gas Plants in March 2019 | 3 | (21) |
| Other variances | 8 | 7 |
| Adjusted net income – 2020(1)(2) | 118 | $ 311 |
All values are in US Dollars.
^(1)^ See “Non-GAAP Measures”noted below
^(2)^ Excludes the effect ofmark-to-market adjustments, gain on sale and impairment charges, net of tax
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Segmented Results:
| For the | Three months ended<br>June 30 | Six Months ended<br><br><br>June 30 | ||||||
|---|---|---|---|---|---|---|---|---|
| millions of Canadian dollars (except per share amounts) | 2020 | 2019 | 2020 | 2019 | ||||
| Adjusted net income ^^^(1)^ | ||||||||
| Florida Electric Utility | $ | 146 | $ | 125 | $ | 225 | $ | 186 |
| Canadian Electric Utilities | **** | 37 | 42 | **** | 129 | 138 | ||
| Other Electric Utilities ^(2)^ | **** | (1) | 23 | **** | 19 | 39 | ||
| Gas Utilities and Infrastructure | **** | 27 | 40 | **** | 97 | 107 | ||
| Other ^(2)^ | **** | (91) | (100) | **** | (159) | (116) | ||
| Adjusted net income ^(1)^ | $ | 118 | $ | 130 | $ | 311 | $ | 354 |
| Gain on sale and impairment charges, net of tax | **** | (15) | - | **** | 283 | - | ||
| After-tax mark-to-market gain (loss) | **** | (45) | (27) | **** | (13) | 61 | ||
| Net income attributable to common shareholders | $ | 58 | $ | 103 | $ | 581 | $ | 415 |
| EPS (basic) | $ | 0.24 | $ | 0.43 | $ | 2.37 | $ | 1.75 |
| Adjusted EPS (basic) ^(1)(2)^ | $ | 0.48 | $ | 0.54 | $ | 1.27 | $ | 1.49 |
^(1)^ See “Non-GAAP Measures”noted below.
^(2)^ Excludes the effect ofmark-to-market adjustments, gain on sale and impairment charges, net of tax
Florida Electric Utility ’ s **** CAD net income increased by $21 million to $146 million in Q2 2020, compared to $125 million in Q2 2019.Earnings increased due to higher AFUDC earnings as a result of the Big Bend modernization and solar projects, lower OM&G expenses, higher base revenues and lower depreciation and amortization expense. Operating revenues decreased due to lower clause revenues, however, base revenues increased as a result of customer growth, a greater mix of sales to residential customers and the in-service of solar generation projects. Year-to-date, Florida Electric Utility’s CAD net income increased by $39 million to $225 million, compared to $186 million in 2019. Earnings increased due to higher base revenues, higher AFUDC earnings and lower OM&G expenses. Operating revenues decreased due to lower clause revenues, however, base revenues increased as a result of the in-service of solar generation projects, customer growth, a greater mix of residential sales and favourable weather.
Canadian Electric Utilities ’ net income decreased by $5 million to $37 million, compared to $42 million in Q2 2019. Year-to-date, Canadian Electric Utilities’ net income was $129 million, compared to $138 million in 2019 period. The decrease in both periods was due to lower contribution from NSPI. Quarter-to-date, the decrease was due to the impacts of COVID-19 on sales volumes, increased income taxes reflecting a Q2 2019 corporate income tax recovery due to enactment of tax legislation and a higher effective tax rate, and higher storm costs, partially offset by regulatory deferral timing. Year-to-date, the decrease was due to the impacts of COVID-19 and unfavourable weather on sales volumes, increased income taxes reflecting a higher effective tax rate, and higher storm costs, partially offset by regulatory deferral timing The timing of regulatory deferrals causes quarterly earnings volatility, while full year results are more predictable.
Other Electric Utilities’ CAD net income, adjusted to exclude mark-to-market, decreased by $24 million to a loss of $1 million in Q2 2020, compared to $23 million in Q2 2019. Year-to-date, Other Electric Utilities’ CAD net income, adjusted to exclude mark-to-market, decreased by $20 million to $19 million, compared to $39 million in 2019. Lower contribution from Emera Maine as a result of the sale in Q1 2020 decreased earnings in both periods. Emera Caribbean’s contribution decreased in both periods as a result of lower revenue due to the impact of the COVID-19 pandemic and lower revenue at GBPC due to the impact of Hurricane Dorian. Year-to-date, the decrease was partially offset by 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.
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Gas Utilities and Infrastructure’s CAD net income decreased by $13 million to $27 million in Q2 2020, compared to $40 million in Q2 2019. Year-to-date, Gas Utilities and Infrastructure’s CAD net income decreased by $10 million to $97 million, compared to $107 million in 2019. Decreases in both periods were due to NMGC’s recognition of tax reform benefits in Q2 2019, lower base revenues at PGS due to the impacts of COVID-19 on commercial sales, and higher OM&G expenses and depreciation expenses at PGS. These decreases were partially offset by higher customer growth and higher return on investment in Cast Iron/Bare Steel replacement rider at PGS and lower OM&G expenses and depreciation rates at NMGC.
Other’s net loss, adjusted to exclude after-tax mark-to-market and the after-tax gain on sale and impairment charges recognized on certain other assets decreased by $9 million to $91 million in Q2 2019, compared to $100 million in Q2 2019. Year-to-date, Other’s contribution decreased $43 million to a loss of $159 million compared to a loss of $116 million in 2019. In Q2 2020, the decreased losses were due to higher marketing and trading margin and lower interest, partially offset by timing of preferred stock dividends and lower income tax recovery. Year-over-year the increased losses were due to the impact of the sale of NEGG and Bayside Power, timing of preferred stock dividends, revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, higher OM&G and the 2019 sale of property in Florida. These decreases were partially offset by increased income tax recovery due to the impact of effective state tax rates and lower interest.
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.
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.
5
Teleconference Call
The company will be hosting a teleconference today, Wednesday, August 12, 2020 at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q2 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 pass code 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 September 15, 2020, by dialing 1-800-585-8367 and entering pass code 9866959.
About Emera
Emera Inc. is a geographically diverse energy and services company headquartered in Halifax, Nova Scotia, with approximately $32 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
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