6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of November, 2020

Commission File Number: 000-54516

Emera Incorporated

(Exact name of registrant as specified in its charter)

5151 Terminal Road

Halifax NS B3J 1A1

Canada

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F  ☐            Form 40-F  ☑

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):  ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):  ☐

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	EMERA INCORPORATED
Date: November 17, 2020	By:	\s\ Stephen D. Aftanas
		Name: Stephen D. Aftanas
		Title: Corporate Secretary

EXHIBIT INDEX

Exhibit No.	Description
99.1	Emera Incorporated Management’s Discussion and Analysis of financial position and results of operations as at and for the three and nine month periods ended September 30, 2020
99.2	Emera Incorporated Unaudited Condensed Consolidated Interim Financial Statements for the three and nine month periods ended September 30, 2020
99.3	Form 52-109F2 Certification of Interim Filings by the Chief Executive Officer
99.4	Form 52-109F2 Certification of Interim Filings by the Chief Financial Officer
99.5	Emera Incorporated Earnings Coverage Ratio for the Twelve Months Ended September 30, 2020
99.6	Emera Incorporated Media Release dated November 13, 2020

EX-99.1

Exhibit 99.1

Management’s Discussion & Analysis

As at November 12, 2020

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the third quarter and year-to-date of 2020 relative to the same periods in 2019; and its financial position as at September 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 nine months ended September 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 September 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 (“FERC”)
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Barbados Light & Power Company Limited (“BLPC”)	Fair Trading Commission, Barbados (“FTC”)
Grand Bahama Power Company Limited (“GBPC”)	The Grand Bahama Port Authority (“GBPA”)
Dominica Electricity Services Ltd. (“Domlec”)	Independent Regulatory Commission, Dominica (“IRC”)
Peoples Gas System (“PGS”) – Gas Division of TEC	FPSC
New Mexico Gas Company, Inc. (“NMGC”)	New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC (“SeaCoast”)	FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)	Canadian Energy Regulator (“CER”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)	UARB
Labrador Island Link Limited Partnership (“LIL”)	Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”)
St. Lucia Electricity Services Limited (“Lucelec”)	National Utility Regulatory Commission (“NURC”)
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”)	CER and FERC

1

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 Measures	6
Consolidated Financial Review	7
Significant Items Affecting Earnings	7
Consolidated Financial Highlights by Business Segment	8
Consolidated Income Statement Highlights	10
Business Overview and Outlook	15
COVID-19 Pandemic	15
Florida Electric Utility	16
Canadian Electric Utilities	17
Other Electric Utilities	19
Gas Utilities and Infrastructure	20
Other	22
Consolidated Balance Sheet Highlights	23
Developments	24
Outstanding Stock Data	25
Financial Highlights	26
Florida Electric Utility	26
Canadian Electric Utilities	28
Other Electric Utilities	31
Gas Utilities and Infrastructure	34
Other	36
Liquidity and Capital Resources	38
Consolidated Cash Flow Highlights	39
Contractual Obligations	41
Debt Management	42
Credit Ratings	43
Guarantees and Letters of Credit	43
Transactions with Related Parties	44
Risk Management and Financial Instruments	44
Disclosure and Internal Controls	47
Critical Accounting Estimates	47
Changes in Accounting Policies and Practices	48
Future Accounting Pronouncements	49
Summary of Quarterly Results	50

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 AND STRATEGIC OVERVIEW

Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the United States and the Caribbean. Cost-of-service utilities provide essential gas and electric services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus is to safely deliver cleaner, affordable and reliable energy to its customers.

Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have 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 $7.4 billion capital investment plan over the 2021-to-2023 period and the potential for additional capital opportunities of $1.2 billion over the same period, resulting in a forecasted rate base growth of 7.5 per cent to 8.5 per cent through to 2023. 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 decarbonization. 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 impairment losses on certain other assets.

The MTM adjustments are a result of the following:

• the mark-to-market adjustments related to Emera’s held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered;

• the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp Power Company LLC (“Bear Swamp”);

• the amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions;

• the mark-to-market adjustments related to an interest rate swap in Brunswick Pipeline;

• the mark-to-market adjustments related to equity securities held in BLPC and Emera Reinsurance, a captive reinsurance company in the Other segment; and

• the mark-to-market adjustments related to Emera’s foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure.

Management believes excluding from net income the effect of these mark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows and ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors exclude these mark-to-market adjustments for evaluation of performance and incentive compensation.

Refer to the “Consolidated Financial Review” section and the “Financial Highlights” sections for Other Electric Utilities and Other segments, for further details on mark-to-market adjustments.

In 2020, the Company recognized a gain on the completion of the sale of Emera Maine and 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	Three months ended				Nine months ended
millions of Canadian dollars (except per share amounts)	September 30				September 30
	2020		2019		2020		2019
Net income attributable to common shareholders	$	84	$	55	$	665	$	470
Gain on sale and impairment charges, net of tax		-		-		283		-
After-tax mark-to-market gain (loss)		(82)		(67)		(95)		(6)
Adjusted net income attributable to common shareholders	$	166	$	122	$	477	$	476
Earnings per common share – basic	$	0.34	$	0.23	$	2.70	$	1.97
Adjusted earnings per common share – basic	$	0.67	$	0.51	$	1.93	$	1.99

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	Three months ended				Nine months ended
millions of Canadian dollars	September 30				September 30
	2020		2019		2020		2019
Net income (1)	$	84	$	78	$	700	$	518
Interest expense, net		163		183		520		557
Income tax expense (recovery)		(21)		(49)		284		18
Depreciation and amortization		217		226		664		678
EBITDA		443		438		2,168		1,771
Gain on sale and impairment charges, excluding income tax		-		-		560		-
Mark-to-market gain (loss), excluding income tax and interest		(116)		(96)		(136)		(11)
Adjusted EBITDA	$	559	$	534	$	1,744	$	1,782

(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Sale of Emera 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). A gain on sale of $585 million ($309 million after tax, or $1.26 per common share), net of transaction costs, was recognized in “Other Income” on the Condensed Consolidated Statements of Income. Refer to the “Developments” section for further details.

7

As a result of the sale, earnings contribution from Emera Maine was $16 million lower in Q3 2020 than in Q3 2019 and $32 million lower year-to-date.

In addition, impairment charges of $25 million ($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 $15 million to $82 million in Q3 2020, compared to $67 million in Q3 2019. This increase was due to changes in existing positions on gas contracts and higher amortization of gas transportation assets in 2020. Year-to-date, after-tax mark-to-market losses increased $89 million to $95 million in 2020, compared to a $6 million loss in 2019. This increase was due to higher amortization of gas transportation assets in 2020 and a larger reversal of mark-to-market losses in 2019.

Earnings Impact of Q1 2019 Sale of NEGG and Bayside Facilities

Earnings contribution from Emera Energy Generation was $22 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.

2019

GBPC Hurricane Dorian Restoration

In Q3 2019, Hurricane Dorian struck Grand Bahama Island as a Category 5 hurricane, causing significant damage across the island. Emera’s Q3 2019 earnings decreased by approximately $16 million ($0.07 per common share) compared to Q3 2018 as a result of the impact of the hurricane. GBPC’s earnings decreased by $7 million in Q3 2019 compared to Q3 2018 due to reduced load as storm restoration efforts were underway. In addition, Emera recorded a corporate loss of $9 million in Q3 2019, in the Other segment, for the corporate share of the unrecoverable loss on GBPC’s facilities.

Consolidated Financial Highlights by Business Segment

For the	Three months ended				Nine months ended
millions of Canadian dollars	September 30				September 30
Adjusted net income	2020		2019		2020		2019
Florida Electric Utility	$	175	$	153	$	400	$	339
Canadian Electric Utilities		35		33		164		171
Other Electric Utilities		6		23		25		62
Gas Utilities and Infrastructure		20		25		117		132
Other		(70)		(112)		(229)		(228)
Adjusted net income attributable to common shareholders	$	166	$	122	$	477	$	476
Gain on sale and impairment charges, net of tax		-		-		283		-
After-tax mark-to-market gain (loss)		(82)		(67)		(95)		(6)
Net income attributable to common shareholders	$	84	$	55	$	665	$	470

8

The following table highlights significant changes in adjusted net income attributable to common shareholders from 2019 to 2020.

For the millions of Canadian dollars	Three months ended September 30		Nine months ended September 30
Adjusted net income – 2019		$            122		$            476
Increased earnings at Tampa Electric in both periods due to the in-service of solar generation, higher allowance for funds used during construction (“AFUDC”) earnings from the Big Bend modernization and solar projects, increased sales to residential customers, favourable weather, customer growth, and a credit to depreciation and amortization expense as a result of a regulatory settlement		22		61
Timing of preferred share dividend declaration		22		11
Recognition of corporate income tax recovery deferred as a regulatory liability in 2018 at BLPC		-		10
2019 recognition of corporate loss for the share of the unrecoverable loss on GBPC’s facilities related to Hurricane Dorian		9		9
Increased earnings at Emera Energy Services in Q3 2020 due to lower fixed commitments for gas transportation and storage assets and periods of increased volatility which improved market opportunity. Year-to-date the increase was due to more favourable hedges, partially offset by less favourable winter market conditions in Q1 2020		9		9
Decreased earnings at NSPI due to higher income tax expense and lower commercial sales related to COVID-19 in both periods, the quarter-over-quarter impact of the reversal of fixed cost deferrals in Q3 2019 and unfavourable weather year-to-date. The decrease in both periods was partially offset by increased residential sales related to COVID-19 and decreased operating, maintenance and general (“OM&G”) expense		(2)		(13)
Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities due to the Q1 2020 reduction in the Nova Scotia provincial corporate income tax rate		-		(14)
Lower earnings contribution from the Caribbean utilities due to lower sales related to the impact of the COVID-19 pandemic and continued recovery from Hurricane Dorian at GBPC		(1)		(15)
Q3 2019 recognition of tax benefits related to change in treatment of net operating loss (“NOL”) carryforwards and tax reform benefits recognized in Q2 2019 in NMGC		(7)		(19)
Decreased earnings due to the sale of Emera Maine in Q1 2020 and the sale of Emera Energy’s New England Gas Generating Facilities (“NEGG”) and Bayside generation facilities in Q1 2019		(17)		(54)
Other variances		9		16
Adjusted net income – 2020		$            166		$            477

Refer to the “Financial Highlights” section for further details of reportable segment contributions.

9

For the millions of Canadian dollars	Nine months ended September 30
	2020		2019
Operating cash flow before changes in working capital	$	1,101	$	1,182
Change in working capital		139		128
Operating cash flow	$	1,240	$	1,310
Investing cash flow	$	(536)	$	(786)
Financing cash flow	$	(595)	$	(546)
As at	September 30		December 31
millions of Canadian dollars	2020		2019
Total assets	$	31,918	$	31,842
Total long-term debt (including current portion)	$	14,085	$	14,180

Refer to the “Consolidated Cash Flow Highlights” section for further discussion of cash flow.

Consolidated Income Statement Highlights

For the millions of Canadian dollars (except per share amounts)	Three months ended September 30				Variance		Nine months ended September 30				Variance
	2020		2019				2020		2019
Operating revenues	$	1,163	$	1,299	$	(136)	$	3,969	$	4,495	$	(526)
Operating expenses		990		1,117		127		3,186		3,531		345
Income from operations		173		182		(9)		783		964		(181)
Income from equity investments		32		38		(6)		113		118		(5)
Other income (expenses), net		21		(8)		29		608		11		597
Interest expense, net		163		183		20		520		557		37
Income tax expense (recovery)		(21)		(49)		(28)		284		18		(266)
Net income		84		78		6		700		518		182
Net income attributable to common shareholders		84		55		29		665		470		195
Gain on sale and impairment charges, net of tax		-		-		-		283		-		283
After-tax mark-to-market gain (loss)		(82)		(67)		(15)		(95)		(6)		(89)
Adjusted net income attributable to common shareholders	$	166	$	122	$	44	$	477	$	476	$	1
Earnings per common share – basic	$	0.34	$	0.23	$	0.11	$	2.70	$	1.97	$	0.73
Earnings per common share – diluted	$	0.34	$	0.23	$	0.11	$	2.69	$	1.96	$	0.73
Adjusted earnings per common share – basic	$	0.67	$	0.51	$	0.16	$	1.93	$	1.99	$	(0.06)
Dividends per common share declared	$	-	$	1.2000	$	(1.2000)	$	1.8375	$	2.3750	$	(0.5375)
Adjusted EBITDA	$	559	$	534	$	25	$	1,744	$	1,782	$	(38)

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Operating Revenues

For the third quarter of 2020, operating revenues decreased $136 million compared to the third quarter in 2019. Absent increased mark-to-market losses of $29 million, operating revenues decreased $107 million due to:

• $68 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020;

• $64 million decrease in the Florida Electric Utility segment due to lower clause revenues as a result of a decrease in fuel costs, partially offset by the in-service of solar generation projects, customer growth, a greater mix of residential sales and favourable weather;

• $16 million decrease in the Other Electric Utilities segment due to lower fuel revenue as a result of lower fuel prices, the impact of the COVID-19 pandemic at GBPC and BLPC, and the impact of Hurricane Dorian at GBPC; and

• $12 million decrease in the Gas Utilities and Infrastructure segment as a result of lower clause-related revenues, lower off-system sales and lower commercial sales related to the COVID-19 pandemic at PGS, partially offset by customer growth at PGS.

These impacts were partially offset by increases of:

• $28 million at NSPI in the Canadian Electric Utilities segment due to higher Maritime Link assessment revenue compared to 2019 and higher sales volumes related to the impact of the COVID-19 pandemic on residential customers; and

• $11 million in marketing and trading margin at Emera Energy due to lower fixed commitments for gas transportation and storage assets and increased periods of volatility in Q3 2020, compared to Q3 2019, which improved market opportunity.

Year-to-date in 2020, operating revenues decreased $526 million compared to the same period in 2019. Absent increased mark-to-market losses of $138 million, operating revenues decreased by $388 million due to:

• $147 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020;

• $114 million decrease at Florida Electric Utility due to lower clause revenue, as a result of a decrease in fuel costs, partially offset by the in-service of solar generation projects, a greater mix of residential sales, favourable weather and customer growth;

• $110 million decrease in the Other segment due to the sale of NEGG and Bayside facilities in Q1 2019;

• $66 million decrease in the Gas Utilities and Infrastructure segment as a result of lower clause-related revenues, lower off-system sales at PGS, and NMGC’s recognition of tax reform benefits in 2019, partially offset by customer growth at PGS; and

• $41 million decrease in the Other Electric Utilities segment due to lower fuel revenue as a result of lower fuel prices, the impact of COVID-19 pandemic at GBPC and BLPC and the impact of Hurricane Dorian at GBPC.

These impacts were partially offset by an increase of:

• $51 million at NSPI in the Canadian Electric Utilities segment due to higher Maritime Link assessment revenue compared to 2019, increased fuel costs, and higher residential sales volumes, partially offset by decreased commercial, other and industrial sales volumes primarily due to the impact of the COVID-19 pandemic and unfavourable weather.

11

Operating Expenses

For the third quarter of 2020, operating expenses decreased $127 million compared to the third quarter of 2019. Absent increased mark-to-market gain of $1 million, operating expenses decreased $128 million due to:

• $85 million decrease at Florida Electric Utility due to lower regulated fuel for generation and purchased power as a result of lower natural gas prices and increased use of solar generation;

• $46 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020; and

• $14 million decrease in the Gas Utilities and Infrastructure segment due to lower regulated cost of natural gas reflecting lower commodity costs at PGS and NMGC, and lower volume of commercial and off-system sales at PGS.

These impacts were partially offset by an increase of:

• $20 million at NSPI in the Canadian Electric Utilities segment primarily due to changes in regulatory deferrals, increased fuel for generation and purchased power mainly due to increased commodity prices, partially offset by decreased OM&G expenses.

Year-to-date, operating expenses decreased $345 million compared to the same period of 2019. Absent increased mark-to-market gain of $4 million, operating expenses decreased $349 million due to:

• $171 million decrease at Florida Electric Utility due to lower natural gas prices and increased use of solar generation;

• $99 million decrease in the Other Electric Utilities segment primarily due to the sale of Emera Maine in Q1 2020;

• $80 million decrease in the Other segment as a result of the sale of NEGG in Q1 2019; and

• $51 million decrease in the Gas Utilities and Infrastructure segment due to lower commodity costs at PGS and NMGC, and lower volume of commercial and off-system sales at PGS.

These impacts were partially offset by an increase of:

• $49 million in NSPI in the Canadian Electric Utilities segment primarily due to changes in regulatory deferrals and increased fuel for generation and purchased power due to change in generation mix and increased commodity prices, partially offset by decreased sales volumes and decreased OM&G expenses.

Other Income (Expenses), Net

The increase in other income (expenses), net for the third quarter in 2020 was primarily due to the corporate share of unrecoverable loss at GBPC facilities in 2019 related to Hurricane Dorian and increased AFUDC equity earnings in 2020 primarily related to the Big Bend Modernization and solar projects at Tampa Electric. 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 third quarter and year-to-date compared to 2019 due to lower interest rates and repayment of corporate debt.

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Income Tax Expense (Recovery)

The decrease in income tax recovery for the third quarter in 2020, compared to the same period in 2019, was primarily due to increased income before provision for income taxes, decreased deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities, and a change in treatment of NMGC NOL carryforwards in Q3 2019. 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.

Net Income and Adjusted Net Income Attributable to Common Shareholders

For the third quarter of 2020, net income attributable to common shareholders was unfavourably impacted by the $15 million increase in after-tax mark-to-market losses, primarily related to Emera Energy. Absent the mark-to-market changes, adjusted net income attributable to common shareholders increased $44 million. The increase was due to increased contributions from Florida Electric Utility and Emera Energy Services, timing of preferred stock dividends, and the 2019 Corporate share of the unrecoverable loss at GBPC related to Hurricane Dorian. These were partially offset by lower earnings contribution from Emera Maine as a result of its sale and the 2019 recognition of tax benefits at NMGC.

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 $89 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 increased $1 million. The increase was due to higher earnings contribution from Florida Electric Utility, timing of preferred share dividends and the 2019 Corporate share of uncoverable loss at GBPC related to Hurricane Dorian. This was partially offset by lower earnings at Emera Maine as a result of its sale in Q1 2020, reduced earnings at NEGG as a result of their sale in Q1 2019, lower earnings contribution from NSPI, revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate and the 2019 recognition of tax reform benefits in NMGC.

Earnings and Adjusted Earnings per Common Share – Basic

Earnings per common share – basic and adjusted earnings per common share were higher for the third quarter due to increased earnings as discussed above, partially offset by 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 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.

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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 September 30				Nine months ended September 30				Year ended December 31
	2020		2019		2020		2019		2019
Weighted average CAD/USD exchange rate	$	1.33	$	1.32	$	1.35	$	1.33	$	1.33
Period end CAD/USD exchange rate	$	1.33	$	1.32	$	1.33	$	1.32		$1.30

Weakening of the CAD exchange rates increased earnings by $4 million and adjusted earnings by $2 million in Q3 2020 compared to Q3 2019. The weakening of the CAD exchange rates increased earnings by $18 million and adjusted earnings by $6 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.

The table below includes Emera’s significant segments whose contributions to adjusted earnings are recorded in US dollar currency.

millions of US dollars	Three months ended September 30				Nine months ended September 30
		2020		2019		2020		2019
Florida Electric Utility	$	131	$	116	$	296	$	255
Other Electric Utilities		5		18		19		47
Gas Utilities and Infrastructure (1)		8		12		67		82
		144		146		382		384
Other segment (2)		(44)		(56)		(107)		(131)
Total (3)	$	100	$	90	$	275	$	253

(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.

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BUSINESS OVERVIEW AND OUTLOOK

COVID-19 Pandemic

During the three and nine months ended September 30, 2020, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. 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.

The pandemic has generally resulted in lower load and higher operating costs than what otherwise would have been experienced at the Company’s utilities. Some of Emera’s utilities have been impacted more than others. However, on a consolidated basis these unfavourable impacts have not had a material financial impact to net earnings to date primarily due to a favourable change to the mix of sales to residential customer classes. Lower commercial and industrial sales have been partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. Favourable weather, in particular in Florida, has further reduced the consolidated impact. The Company has not incurred or deferred for future recovery a significant amount of incremental costs as a result of the pandemic. Capital project delays and supply chain disruptions have been minimal to date. 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 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. In jurisdictions where it is safe to do so, some parts of the business have commenced a workplace re-entry strategy. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

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 have included the temporary suspension of disconnection for non-payment of bills and the development of payment arrangements where necessary. In Q3 2020, most of Emera’s utilities resumed disconnection processes for non-payment. As a result of the temporary suspension of disconnections, the Company’s utilities experienced an increase in the aging of customer receivables. This trend has begun to reverse as normal disconnection processes resume. To date, there have been no significant customer defaults as a result of bankruptcies with many accounts being secured by deposits. As of September 30, 2020, adjustments to the allowance for credit losses have not had a material 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.

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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 interim 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 interim financial statements for further details.

Potential future impacts on the business may include the following:

• Lower earnings as a result of lower sales volumes due to continued economic slowdowns and the pace and strength of economic recovery;

• Delays of capital projects as a result of construction shutdowns, government restrictions on non-essential capital work, travel restrictions for contractors or supply chain disruptions;

• 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 losses.

To date, the above have not had a material financial impact on the Company. Future impacts on the business will depend on future developments, including the duration and severity of the pandemic and the pace and strength of the economic recovery.

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.

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 year-to-date in 2020 have more than offset the impacts of a decrease in other customer classes as a result of COVID-19. In addition, the number of customers increased by 2 per cent in 2020, primarily in the residential class. Expected outcomes and actual results may differ given the many uncertainties related to the pandemic and its economic impact.

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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 SPP program costs previously recovered in base rates 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 removed from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery will begin in January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and 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, Tampa Electric recognized $4 million USD of this credit in Q3 2020 and $12 million USD year-to-date, with the remaining $4 million USD to be recognized in Q4 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 resulting in lower fuel and capacity clause rates to customers for the remainder of 2020, and included 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”).

Canadian Electric Utilities

Canadian Electric Utilities includes:

• NSPI, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia; and

• ENL, a holding company with equity investments in NSPML and LIL, two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador.

• The Maritime Link entered service on January 15, 2018 and provides for the transmission of energy between Newfoundland and Nova Scotia, as well as improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. The Maritime Link will transmit at greater capacity when the Muskrat Falls hydroelectricity generation project is complete.

• Construction of the LIL is complete and Nalcor Energy (“Nalcor”) recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor has resumed its work towards commissioning the LIL after a temporary suspension of work, in March 2020, in response to the COVID-19 pandemic.

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NSPI

NSPI anticipates earnings near the low end of 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. Absent the impact of weather, NSPI has experienced a decrease in sales volumes in the commercial, industrial and other 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 significant investments 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.

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 continues to work toward construction completion and project commissioning in 2021. Refer to the “ENL – Impact of COVID-19 on Muskrat Falls and LIL” section below for further details. Due to the delay of the NS Block, NSPI will not achieve the provincially legislated target of 40 per cent of electric sales generated from renewable sources in 2020. This would have given rise to non-compliance except for the fact that on May 15, 2020, the provincial government provided NSPI with an alternative compliance plan, as permitted by the legislation, which 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 investment was decreased from $375 million pre-COVID-19 to approximately $310 million. The remaining $65 million of capital investments will be deferred to 2021 and 2022. Capital investment in 2019, including AFUDC, was $396 million.

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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. On July 31, 2020, NSPML filed an interim assessment application with the UARB requesting recovery of 2021 costs of approximately $172 million, resulting in an additional $27 million to be collected from NSPI. A decision from the UARB is expected in Q4 2020. 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.

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 $615 million, comprised of $410 million in equity contribution and $205 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.

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. Nalcor achieved first power on the first of four generators at Muskrat Falls on September 22, 2020 and continues to work toward project commissioning in 2021.

Other Electric Utilities

Other Electric Utilities includes:

• Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities, BLPC, a vertically integrated regulated electric utility on the island of Barbados, and GBPC, a vertically integrated regulated electric utility on Grand Bahama Island. ECI also holds:

• a 51.9 per cent interest in Domlec, a vertically integrated regulated electric utility on the island of Dominica; and

• a 19.5 per cent interest in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia.

• Emera Maine, a regulated transmission and distribution electric utility in the state of Maine. On March 24, 2020, Emera completed the sale of Emera Maine. Refer to the “Developments” section for further details.

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Removing the impact of the GBPC impairment charge recognized in 2019, Other Electric Utilities’ 2020 earnings are expected to decrease over the prior year. This decrease is due to lower earnings contribution from Emera Maine as a result of its sale in March 2020, and lower earnings from the Caribbean utilities primarily related to the COVID-19 pandemic.

Earnings from the Caribbean utilities are expected to be lower in 2020 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 at BLPC and GBPC 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 ($10 million CAD) corporate income tax recovery which was deferred as a regulatory liability in 2018. The impact of COVID-19 on GBPC is expected to be partially offset by recovery of load following Hurricane Dorian. GBPC’s 2019 earnings were lower than normal as a result of Hurricane Dorian.

On November 6, 2020, BLPC notified the FTC that it plans to file a general rate review application with the FTC in Q1 2021.

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 September 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 January 1, 2021.

In 2020, capital expenditures in the Other Electric Utilities segment are forecasted to be approximately $110 million USD, including $14 million USD invested in Emera Maine projects supporting normal system reliability prior to completion of its 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 2021.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes:

• PGS, a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida;

• NMGC, a regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico;

• SeaCoast, a regulated intrastate natural gas transmission company offering services in Florida;

• Brunswick Pipeline, a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States; and

• Emera’s non-consolidated investment in M&NP.

Earnings from the gas utilities are anticipated to be lower than in 2019 due to impact of the COVID-19 pandemic.

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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, while residential customer growth has been particularly strong in 2020, PGS’ overall sales volumes are expected to be lower than in 2019 as a result of the economic impact of COVID-19 in Florida decreasing sales to commercial customers. Beginning mid-March, PGS sales volumes decreased as a result of the impact of government measures and economic conditions 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.

On October 22, 2020, PGS filed a settlement agreement for approval with the FPSC. The settlement agreement allows for an increase in base rates of $58 million USD annually effective January 2021. The $58 million USD increase includes $24 million USD previously recovered through the cast iron and bare steel replacement rider. The settlement agreement includes an allowed regulatory ROE range of 8.90 per cent to 11.00 per cent with a 9.90 per cent midpoint (2020 - 9.25 per cent to 11.75 per cent with a 10.75 per cent midpoint). The settlement agreement provides PGS with the ability to reverse a total of $34 million USD of accumulated depreciation through 2023 and sets new depreciation rates going into effect January 1, 2021. These depreciation rates are comparatively consistent with PGS’ current overall average depreciation rate. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE falls below 8.90 per cent before that time, with an allowed equity capital structure of 54.7 per cent. The settlement agreement further addresses tax rate changes. PGS will quantify the future impact of decreases in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in PGS’ next base rate proceeding. A decision from the FPSC is expected in 2020.

NMGC anticipates earning near 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 2019. 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 NOL carryforwards in 2019, which contributed a total of $14 million USD to earnings last year.

On December 23, 2019, NMGC filed a future year rate case for new rates effective January 2021. On August 25, 2020, NMGC filed a settlement agreement with the NMPRC and, on October 20, 2020, a hearing in front of the Hearing Examiner was held. The proposed new rates reflect the recovery of capital investment in pipelines and related infrastructure and would be expected to result in an increase in revenue of approximately $5 million USD annually. A decision from the NMPRC is expected in 2020.

In 2020, capital expenditures in the Gas Utilities and Infrastructure segment are expected to be approximately $600 million USD (2019 - $331 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will complete the Santa Fe Mainline Looping project in 2020 and will continue to invest in system improvements. SeaCoast will continue to invest in the Seminole Pipeline and the Callahan Pipeline with approximately $90 million USD expected to be invested in 2020. The Seminole and Callahan Pipelines remain on schedule with total costs of approximately $100 million USD and $30 million USD, respectively.

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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;

• Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and

• an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

In 2019, the Company completed the sale of assets previously reported in this segment including the sale of its NEGG and Bayside facilities in March 2019 and the sale of its Emera Utility Services equipment and inventory in December 2019. These operations contributed $20 million to earnings in 2019.

Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, corporate human resources activities, acquisition and disposition related costs, gains or losses on select assets sales, and gains or losses on foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure. It includes interest revenue on intercompany financings recorded in “Intercompany revenue” and interest expense on corporate debt in both Canada and the US. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Earnings from EES are generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 generally providing the greatest opportunity for earnings. Under normal market conditions, 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. While the COVID-19 related economic slowdown has not had a material impact on EES earnings to date, the business continues to experience a challenging market environment of low absolute natural gas pricing and volatility in its core geographies. Assuming that continues to be the case in Q4 2020, EES expects to outperform 2019, but could fall short of the low end of its normal range for 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 be consistent with the prior year. This is primarily due to lower interest expense and increased EES contribution being offset by decreased tax recoveries and lower earnings contribution due to the sale of NEGG in 2019. The decrease in tax recoveries is due to the revaluation of net 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 $25 million (2019 - $63 million).

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CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2019 and September 30, 2020 include:

millions of Canadian dollars	Increase (Decrease)			Explanation
Assets
Cash and cash equivalents	$	64		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, net repayment of debt at TECO Finance, net repayment of Emera committed credit facilities and dividends on common stock.
Receivables and other assets (current and long-term)		(132	)	Decreased due to seasonality of the business at NSPI and NMGC, 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 NSPI. This was partially offset by the reclassification of corporate alternative minimum tax carryforwards from deferred income tax liabilities, higher revenues and increased aging of receivables due to the temporary suspension of disconnections for non-payment of bills at Tampa Electric and the effect of a weaker CAD on the translation of Emera’s foreign affiliate.
Assets held for sale (current and long-term), net of liabilities		(691	)	Decreased due to the sale of Emera Maine.
Property, plant and equipment, net of accumulated depreciation and amortization		1,597		Increased due to additions at Tampa Electric, PGS and NSPI and the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Goodwill		158		Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		(87	)	Decreased due to net repayments on committed credit facilities at TECO Finance and Emera, and net repayment of long-term debt at TECO Finance. This was partially offset by a net issuance on committed credit facilities at Tampa Electric and the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Deferred income tax liabilities, net of deferred income tax assets		302		Increased due to net utilization of tax loss carryforwards primarily related to the sale of Emera Maine, tax deductions in excess of accounting depreciation related to property, plant and equipment and the effect of a weaker CAD on the translation of Emera’s foreign subsidiaries. The increase was partially offset by the revaluation of net deferred income tax liabilities resulting from enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020.
Derivative instruments (current and long-term)		66		Increased due to new contracts at Emera Energy, partially offset by the reversal of 2019 contracts at Emera Energy and the settlement of contracts at NSPI.
Regulatory liabilities (current and long-term)		(59	)	Decreased due to changes in the fuel adjustment mechanism deferral and derivative instrument deferrals at NSPI and decreased deferred income tax regulatory liabilities primarily due to increased amortization of excess deferred income taxes related to US Tax Reform at Tampa Electric, PGS and NMGC. This was partially offset by the effect of a weaker CAD on the translation of Emera’s foreign affiliates.

23

Other liabilities (current and long-term)	163	Increased due to investment tax credits related to solar projects at Tampa Electric, timing of interest payments on corporate debt and the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Common stock	325	Increased due to shares issued under Emera’s at-the-market equity plan, the dividend reinvestment plan and stock options exercised.
Accumulated other comprehensive income	168	Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Retained earnings	209	Increased due to the gain on sale of Emera Maine, offset by dividends paid in excess of net income.

DEVELOPMENTS

Increase in Common Dividend

On September 16, 2020, Emera’s Board of Directors approved an increase in the annual common share dividend rate to $2.55 from $2.45. The first payment will be effective November 16, 2020. Emera also reaffirmed its four to five per cent annual dividend growth rate target through to 2022.

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 $309 million after tax, net of transaction costs, was recognized in the Other segment. 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 October 14, 2020, Peter Gregg was appointed President and CEO of NSPI. Most recently, Mr. Gregg was the President and CEO of the Independent Electricity System Operator in Ontario. Mr. Gregg succeeded Richard Janega, who was appointed interim President and CEO of NSPI effective June 1, 2020. Mr. Janega is Emera’s Chief Operating Officer, Electric Utilities, Canada, US Northeast and Caribbean.

24

OUTSTANDING STOCK DATA

Common stock

Issued and outstanding:	millions of shares		millions of Canadian dollars
Balance, December 31, 2018		234.12	$	5,816
Conversion of Convertible Debentures		0.03		1
Issuance of common stock (1)		1.77		99
Issued for cash under Purchase Plans at market rate		3.99		202
Discount on shares purchased under Dividend Reinvestment Plan		-		(7	)
Options exercised under senior management stock option plan		2.57		104
Employee Share Purchase Plan		-		1
Balance, December 31, 2019		242.48	$	6,216
Issuance of common stock (2)		2.71		151
Issued for cash under Purchase Plans at market rate		2.82		155
Discount on shares purchased under Dividend Reinvestment Plan		-		(3	)
Options exercised under senior management stock option plan		0.42		20
Employee Share Purchase Plan		-		2
Balance, September 30, 2020		248.43	$	6,541

(1) In Q3 2019 and in the nine months ended September 30, 2019, 880,912 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $56.76 per share for gross proceeds of $50 million ($49 million net of issuance costs).

(2) In Q3 2020, 980,500 common shares were issued under Emera’s ATM program at an average price of $54.43 per share for gross proceeds of $53 million ($53 million net of issuance costs). During the nine months ended September 30, 2020, 2,708,603 common shares were issued under Emera’s ATM program at an average price of $56.62 per share for gross proceeds of $153 million ($151 million net of issuance costs). As at September 30, 2020, an aggregate gross sales limit of $347 million remains available for issuance under the ATM program.

As the Q3 2020 dividends were declared by the Board of Directors and recognized in Q2 2020, there were no common or preferred share dividends recognized in Q3 2020.

As at November 9, 2020, the amount of issued and outstanding common shares was 249.4 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended September 30, 2020 was 248.4 million (2019 – 241.0 million) and for the nine months ended September 30, 2020 was 246.6 million (2019 – 238.9 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 it would not redeem the 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 17, 2020, Emera announced 128,610 of its 3,864,636 issued and outstanding Series A Shares were tendered for conversion into Series B Shares and 1,130,788 of its 2,135,364 issued and outstanding Series B Shares were tendered for conversion into Series A Shares, all on a one-for-one basis. As a result of the conversion, Emera has 4,866,814 Series A Shares and 1,133,186 Series B Shares issued and 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 which commenced on August 15, 2020 and ends 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 which commenced on August 15, 2020 and ends on (and inclusive of) November 14, 2020 ($0.1274 per Series B Share for the quarter).

25

FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.

For the	Three months ended				Nine months ended
millions of US dollars (except per share amounts)			September 30				September 30
		2020		2019		2020		2019
Operating revenues – regulated electric		$          506		$          559		$        1,381		$        1,492
Regulated fuel for generation and purchased power		102		168		301		439
Contribution to consolidated net income		$          131		$          116		$           296		$           255
Contribution to consolidated net income – CAD		$          175		$          153		$           400		$           339
Contribution to consolidated earnings per common share – basic – CAD		$         0.70		$         0.63		$          1.62		$          1.42
Net income weighted average foreign exchange rate – CAD/USD		$         1.33		$         1.32		$          1.35		$          1.33
EBITDA		$          270		$          249		$           690		$           641
EBITDA – CAD		$          359		$          331		$           933		$           853

Net Income

Highlights of the net income changes are summarized in the following table:

For the	Three months ended		Nine months ended
millions of US dollars	September 30		September 30
Contribution to consolidated net income – 2019		$          116		$          255
Decreased operating revenues – see Operating Revenues – Regulated Electric below		(53)		(111)
Decreased fuel for generation and purchased power – see Regulated Fuel for Generation and Purchased Power below		66		138
Increased depreciation and amortization due to increased property, plant and equipment partially offset by a $4 million in Q3 2020 ($12 million year-to-date) credit to amortization expense recognized for Tampa Electric’s accumulated amortization reserve surplus for intangible software assets		(2)		(3)
Increased other income as a result of higher AFUDC earnings due to the Big Bend Power Station modernization and solar projects		4		10
Other		-		7
Contribution to consolidated net income – 2020		$          131		$          296

Florida Electric Utility’s CAD contribution to consolidated net income increased $22 million in Q3 2020, compared to Q3 2019. Year-to-date, the CAD contribution to consolidated net income increased $61 million in 2020 compared to the same period in 2019. The increase in both periods was due to increased base revenues and higher AFUDC earnings as a result of the Big Bend modernization and solar projects. Operating revenues decreased due to lower clause revenues; however, base revenues increased as a result of the in-service of solar generation projects, a greater mix of residential sales, favourable weather and customer growth.

The impact of the change in the foreign exchange rate increased CAD earnings for the three and nine months ended September 30, 2020 by $1 million and $7 million, respectively.

26

Operating Revenues – Regulated Electric

Electric revenues decreased $53 million to $506 million in Q3 2020, compared to $559 million in Q3 2019 due to lower clause revenues as a result of a decrease in fuel cost, partially offset by the in-service of solar generation projects, customer growth, a greater mix of residential sales and favourable weather.

Year-to-date, electric revenues decreased $111 million to $1,381 million in 2020, compared to $1,492 million for the same period in 2019 due to lower clause revenues as a result of a decrease in fuel cost. The year-to-date decrease in revenues was partially offset by increased base revenues from in-service of solar generation projects, a greater mix of residential sales, favourable weather and customer growth.

Electric revenues and sales volumes are summarized in the following tables by customer class:

Q3 Electric Revenues
millions of US dollars
	2020		2019
Residential	$	303	$	325
Commercial		128		160
Industrial		30		41
Other (1)		45		33
Total	$	506	$	559
(1) Other includes sales to public authorities, off-system sales to other utilities, unbilled revenues and regulatory deferrals related to clauses.
Q3 Electric Sales Volumes (1)
Gigawatt hours (“GWh”)
	2020		2019
Residential		3,259		2,976
Commercial		1,728		1,791
Industrial		482		519
Other		527		548
Total		5,996		5,834
(1) Electric sales volumes are calculated based on billed hours only. GWh related to unbilled revenues are excluded.

YTD Electric Revenues
millions of US dollars
	2020		2019
Residential	$	762	$	792
Commercial		374		421
Industrial		99		117
Other (1)		146		162
Total	$	1,381	$	1,492
(1) Other includes sales to public authorities, off-system sales to other utilities, unbilled revenues and regulatory deferrals related to clauses.
YTD Electric Sales Volumes (1)
GWh
	2020		2019
Residential		7,657		7,281
Commercial		4,532		4,704
Industrial		1,431		1,520
Other		1,443		1,515
Total		15,063		15,020
(1) Electric sales volumes are calculated based on billed hours only. GWh related to unbilled revenues are excluded.

27

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $66 million to $102 million in Q3 2020, compared to $168 million in Q3 2019. Year-to-date, regulated fuel for generation and purchased power decreased $138 million to $301 million in 2020, compared to $439 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.

Q3 Production Volumes
GWh
	2020		2019
Natural gas		4,652		5,006
Coal		301		219
Solar		304		210
Purchased power		910		657
Total		6,167		6,092
Q3 Average Fuel Costs
US dollars	2020		2019
Dollars per Megawatt hour (“MWh”)	$	17	$	28

YTD Production Volumes
GWh
	2020		2019
Natural gas		12,907		13,439
Coal		560		891
Solar		888		587
Purchased power		1,766		1,080
Total		16,121		15,997
YTD Average Fuel Costs
US dollars	2020		2019
Dollars per MWh	$	19	$	27

Average fuel cost per MWh decreased in Q3 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.

Canadian Electric Utilities

For the	Three months ended				Nine months ended
millions of Canadian dollars (except per share amounts)			September 30				September 30
		2020		2019		2020		2019
Operating revenues – regulated electric	$	324	$	296	$	1,117	$	1,066
Regulated fuel for generation and purchased power (1)		162		147		502		480
Income from equity investments		24		20		75		68
Contribution to consolidated net income	$	35	$	33	$	164	$	171
Contribution to consolidated earnings per common share – basic	$	0.14	$	0.14	$	0.67	$	0.72
EBITDA	$	130	$	117	$	457	$	441
(1) Regulated fuel for generation and purchased power includes NSPI’s Fuel Adjustment Mechanism (“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	Three months ended				Nine months ended
millions of Canadian dollars			September 30				September 30
		2020		2019		2020		2019
NSPI	$	11	$	13	$	89	$	103
Equity investment in NSPML		11		9		38		35
Equity investment in LIL		13		11		37		33
Contribution to consolidated net income	$	35	$	33	$	164	$	171

28

Net Income

Highlights of the net income changes are summarized in the following table:

For the	Three months ended			Nine months ended
millions of Canadian dollars	September 30			September 30
Contribution to consolidated net income – 2019	$	33		$	171
Increased operating revenues - see Operating Revenues – Regulated Electric below		28			51
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		(15	)		(22	)
Increased primarily due to a reversal of fixed cost deferrals in 2019 and increased FAM expense. Year-over-year decrease due to the refund to customers of prior years’ over-recovery of fuel costs, partially offset by the over-recovery of current period fuel costs		(28	)		(40	)
Decreased OM&G expense quarter-over-quarter primarily due to lower storm restoration costs, and lower costs for power generation and vegetation management. These decreases were partially offset by lower administrative overhead allocated to property, plant and equipment, COVID-19 pandemic response costs and decreased demand side management (“DSM”) program costs due to lower program costs. Year-over-year this decrease was also offset by higher information technology costs		23			17
Increased income from equity investments due to timing of OM&G expenses at NSPML and increased AFUDC earnings from LIL		4			6
Increased income taxes primarily due to lower tax deductions in excess of accounting depreciation related to property, plant and equipment		(11	)		(22	)
Other		1			3
Contribution to consolidated net income – 2020	$	35		$	164

Canadian Electric Utilities’ contribution to consolidated net income increased in Q3 2020, compared to Q3 2019, due to decreased OM&G expense, higher residential electric sales at NSPI and higher equity earnings at ENL, partially offset by lower recoveries of regulatory deferrals, reversal of fixed cost deferral in 2019 and increased income taxes resulting from lower tax deductions in excess of accounting depreciation related to property, plant and equipment.

Year-to-date, the decrease in contribution to consolidated net income was due to the unfavourable impacts of increased income tax expense, as discussed above, weather and decreased commercial, other and industrial sales volumes related to the impact of the COVID-19 pandemic, partially offset by decreased OM&G expense and increased residential sales volumes related to the impact of the COVID-19 pandemic at NSPI and higher equity earnings at ENL.

NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $28 million to $324 million in Q3 2020, compared to $296 million in Q3 2019 due to a higher Maritime Link assessment included in revenue compared to 2019, increased residential sales volumes related to the impact of the COVID-19 pandemic and increased fuel-related pricing. This was partially offset by decreased commercial sales volumes primarily due to the impact of the COVID-19 pandemic. Year-to-date, operating revenues increased $51 million to $1,117 million compared to $1,066 million for the same period in 2019 due to a higher Maritime Link assessment included in revenue compared to 2019, increased fuel-related pricing, and higher residential sales volumes, partially offset by decreased commercial, other and industrial sales volumes primarily due to the impact of the COVID-19 pandemic and unfavourable weather.

29

Electric revenues and sales volumes are summarized in the following tables by customer class:

Q3 Electric Revenues
millions of Canadian dollars
	2020		2019
Residential	$	161	$	135
Commercial		93		91
Industrial		57		52
Other		7		11
Total	$	318	$	289
Q3 Electric Sales Volumes
GWh
	2020		2019
Residential		898		810
Commercial		657		707
Industrial		614		629
Other		37		72
Total		2,206		2,218

YTD Electric Revenues
millions of Canadian dollars
	2020		2019
Residential	$	607	$	552
Commercial		303		298
Industrial		164		160
Other		24		35
Total	$	1,098	$	1,045
YTD Electric Sales Volumes
GWh
	2020		2019
Residential		3,493		3,454
Commercial		2,138		2,305
Industrial		1,712		1,817
Other		149		272
Total		7,492		7,848

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $15 million to $162 million in Q3 2020 compared to $147 million in Q3 2019. Year-to-date, regulated fuel for generation and purchased power increased $22 million to $502 million compared to $480 million in the same period in 2019. The increase was primarily due to increased commodity prices and a change in generation mix, partially offset by decreased sales volumes.

Q3 Production Volumes
GWh
	2020		2019
Coal		949		918
Natural gas		495		451
Oil and petcoke		247		204
Purchased power – other		114		277
Total non-renewables		1,805		1,850
Purchased power – Independent Power Producers (“IPP”)		253		195
Wind and hydro		126		202
Purchased power – Community Feed-in Tariff program (“COMFIT”)		109		96
Biomass		44		14
Total renewables		532		507
Total production volumes		2,337		2,357
Q3 Average Fuel Costs
		2020		2019
Dollars per MWh		69		62

YTD Production Volumes
GWh
	2020		2019
Coal		3,093		3,551
Natural gas		1,521		1,047
Oil and petcoke		793		832
Purchased power – other		428		647
Total non-renewables		5,835		6,077
Purchased power – IPP		897		831
Wind and hydro		786		983
Purchased power – COMFIT		402		389
Biomass		85		59
Total renewables		2,170		2,262
Total production volumes		8,005		8,339
YTD Average Fuel Costs
		2020		2019
Dollars per MWh		63		58

Average fuel cost per MWh increased in Q3 2020 and year-to-date, compared to the same periods in 2019 primarily due to increased commodity pricing and a change in generation mix resulting from 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.

30

NSPI’s FAM regulatory liability balance decreased $33 million from $115 million at December 31, 2019 to $82 million at September 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.

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				Nine months ended
For the			September 30				September 30
millions of US dollars (except per share amounts)	2020		2019		2020		2019
Operating revenues – regulated electric		$           79	$	144		$          275	$	421
Regulated fuel for generation and purchased power (1)		33		55		110		158
Adjusted contribution to consolidated net income		$             5	$	18		$             19	$	47
Adjusted contribution to consolidated net income – CAD		$             6	$	23		$             25	$	62
After-tax equity securities mark-to-market gain (loss)		–		–		–		2
Contribution to consolidated net income		$             5	$	18		$             19	$	49
Contribution to consolidated net income – CAD		$             6	$	23		$             25	$	64
Adjusted contribution to consolidated earnings per common share – basic – CAD		$        0.02	$	0.10		$          0.10	$	0.26
Contribution to consolidated earnings per common share – basic – CAD		$        0.02	$	0.10		$          0.10	$	0.27
Net income weighted average foreign exchange rate – CAD/USD		$        1.33	$	1.33		$          1.36	$	1.33
Adjusted EBITDA		$           21	$	52		$             77	$	149
Adjusted EBITDA – CAD		$           26	$	67		$           102	$	197
(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				Nine months ended
millions of US dollars			September 30				September 30
	2020		2019		2020		2019
Emera Maine		$             –	$	11		$               4	$	28
ECI		5		7		15		19
Adjusted contribution to consolidated net income		$             5	$	18		$             19	$	47

31

Net Income

Highlights of the net income changes are summarized in the following table:

For the	Three months ended		Nine months ended
millions of US dollars	September 30		September 30
Contribution to consolidated net income – 2019	$	18	$	49
Decreased operating revenues – see Operating Revenues – Regulated Electric below		(13)		(36)
Regulated fuel for generation – see Regulated Fuel for Generation and Purchased Power below		12		28
Increased income tax recovery primarily due to recognition of a previously deferred corporate income tax recovery in Q1 2020 related to enactment of a lower corporate income tax rate in December 2018 at BLPC		–		7
Impact of sale of Emera Maine, net of tax		(11)		(24)
Other		(1)		(5)
Contribution to consolidated net income – 2020	$	5	$	19

Excluding the change in mark-to-market, Other Electric Utilities CAD contribution to consolidated net income decreased $17 million in Q3 2020, compared to Q3 2019. Year-to-date, the CAD contribution decreased $37 million in 2020 compared to the same period in 2019. Lower contribution from Emera Maine as a result of its sale in Q1 2020 decreased earnings in both periods. ECI’s year-to-date contribution decreased due to lower commercial and industrial sales, partially offset by increased sales to residential customers due to the impact of the COVID-19 pandemic and due to the continued recovery from Hurricane Dorian at GBPC. 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 September 30 and year-to-date 2020.

Operating Revenues – Regulated Electric

Operating revenues decreased $65 million to $79 million in Q3 2020, compared to $144 million in Q3 2019. Year-to-date revenues decreased $146 million to $275 million compared to $421 million in the same period in 2019. Decreases in both periods were a result of the sale of Emera Maine in Q1 2020, lower fuel revenue at BLPC as a result of lower fuel prices, lower commercial and industrial sales partially offset by increased sales to residential customers due to the impact of the COVID-19 pandemic in the Caribbean, and the continued recovery from the impact of Hurricane Dorian at GBPC. GBPC’s revenue in Q3 2020 was slightly higher than in Q3 2019; however, Q3 2019 revenues were low due to the impact of Hurricane Dorian in September 2019.

Electric revenues and sales volumes for ECI’s utilities are summarized in the following tables by customer class:

Q3 Electric Revenues
millions of USD
	2020		2019
Residential	$	31	$	33
Commercial		40		50
Industrial		5		4
Other		3		5
Total	$	79	$	92

YTD Electric Revenues
millions of USD
	2020		2019
Residential	$	84	$	90
Commercial		121		149
Industrial		16		15
Other		10		12
Total	$	231	$	266

32

Q3 Electric Sales Volumes
GWh	2020		2019
Residential		137		122
Commercial		164		188
Industrial		19		16
Other		6		3
Total		326		329

YTD Electric Sales Volumes
GWh	2020		2019
Residential		369		347
Commercial		481		554
Industrial		61		59
Other		16		11
Total		927		971

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $22 million to $33 million in Q3 2020, compared to $55 million in Q3 2019. Year-to-date, regulated fuel for generation and purchased power decreased $48 million to $110 million compared to $158 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 and lower fuel costs at BLPC.

Production volumes and average fuel costs for ECI’s utilities are summarized in the following tables:

Q3 Production Volumes
GWh
	2020	2019
Oil	331	344
Hydro	4	5
Solar	5	5
Purchased power	15	9
Total	355	363
Q3 Average Fuel Costs
US dollars	2020	2019
Dollars per MWh	92	124

YTD Production Volumes
GWh
	2020	2019
Oil	933	1,006
Hydro	12	15
Solar	13	14
Purchased power	40	25
Total	998	1,060
YTD Average Fuel Costs
US dollars	2020	2019
Dollars per MWh	101	121

Average fuel cost per MWh decreased in Q3 2020 and year-to-date, compared to the same periods in 2019, due to lower oil prices.

33

Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.

For the	Three months ended						Nine months ended
millions of US dollars (except per share amounts)	September 30						September 30
	2020			2019			2020		2019
Operating revenues – regulated gas (1)	$	146		$	156		$	546	$	604
Operating revenues – non-regulated		3			3			9		9
Total operating revenue	$	149		$	159		$	555	$	613
Regulated cost of natural gas		30			40			141		188
Income from equity investments		3			4			10		14
Contribution to consolidated net income	$	16		$	20		$	87	$	102
Contribution to consolidated net income – CAD	$	20		$	25		$	117	$	132
Contribution to consolidated earnings per common share – basic – CAD	$	0.08		$	0.10		$	0.47	$	0.55
Net income weighted average foreign exchange rate – CAD/USD	$	1.32		$	1.34		$	1.35	$	1.33
EBITDA	$	52		$	51		$	213	$	227
EBITDA – CAD	$	69		$	66		$	288	$	299
(1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2019 – $13 million) for the three months ended September 30, 2020 and $34 million (2019 – n$34 million) for the nine months ended September 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						Nine months ended
millions of US dollars	September 30						September 30
	2020			2019			2020		2019
PGS	$	10		$	10		$	39	$	42
NMGC		(5	)		(1	)		18		31
Other		11			11			30		29
Contribution to consolidated net income	$	16		$	20		$	87	$	102

Net Income

Highlights of the net income changes are summarized in the following table:

For the	Three months ended			Nine months ended
millions of US dollars	September 30			September 30
Contribution to consolidated net income – 2019	$	20		$	102
Decreased gas operating revenues – see Operating Revenues – Regulated Gas below		(10	)		(49	)
Decreased gas operating revenues as a result of recognition of tax reform benefits at NMGC in Q2 2019		—			(9	)
Recognition of tax benefits related to change in treatment of NOL carryforwards at NMGC in Q3 2019		(5	)		(5	)
Decreased cost of natural gas sold – See Regulated Cost of Natural Gas below		10			47
Other		1			1
Contribution to consolidated net income – 2020	$	16		$	87

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Gas Utilities and Infrastructure’s CAD contribution to consolidated net income decreased $5 million compared to Q3 2019. Year-to-date, Gas Utilities and Infrastructure’s CAD contribution to consolidated net income decreased $15 million compared to 2019. The decrease in both periods was due to NMGC’s recognition of tax benefits related to the change in treatment of NOL carryforwards in Q3 2019 and lower PGS base revenues due to the impacts of COVID-19 on commercial sales. The decrease was partially offset by higher customer growth, increased AFUDC earnings and higher return on investment in the cast iron and bare steel replacement rider at PGS and lower OM&G expenses at NMGC. Year-to-date, the decrease was also due to NMGC’s recognition of tax reform benefits in Q2 2019.

The foreign exchange rate had minimal impact for the three months ended September 30, 2020 and year-to-date 2020.

Operating Revenues – Regulated Gas

Gas Utilities and Infrastructure’s operating revenues decreased $10 million to $146 million in Q3 2020, compared to $156 million in Q3 2019. Year-to-date operating revenues decreased $58 million to $546 million, compared to $604 million in the same period in 2019. The decrease in both periods resulted from lower clause-related revenues, lower off-system sales at PGS and lower commercial sales related to the COVID-19 pandemic at PGS. This decrease was partially offset by customer growth at PGS. Year-to-date the decrease was also due to the regulatory approval allowing NMGC to retain $9 million USD in tax reform benefits in Q2 2019.

Gas revenues and sales volumes are summarized in the following tables by customer class:

Q3 Gas Revenues
millions of US dollars
		2020		2019
Residential	$	57	$	58
Commercial		40		43
Industrial (1)		10		9
Other (2)		27		33
Total (3)	$	134	$	143

(1) Industrial includes sales to power generation customers.

(2) Other includes off-system sales to other utilities and various other items.

(3) Excludes $12 million of finance income from Brunswick Pipeline (2019 – $13 million).

YTD Gas Revenues
millions of US dollars
		2020		2019
Residential	$	250	$	270
Commercial		144		162
Industrial (1)		30		28
Other (2)		88		110
Total (3)	$	512	$	570

(1) Industrial includes sales to power generation customers.

(2) Other includes off-system sales to other utilities and various other items.

(3) Excludes $34 million of finance income from Brunswick Pipeline (2019 – $34 million).

Q3 Gas Volumes
Therms (millions)
	2020	2019
Residential	38	35
Commercial	150	165
Industrial	417	386
Other	68	93
Total	673	679

YTD Gas Volumes
Therms (millions)
	2020	2019
Residential	273	275
Commercial	547	605
Industrial	1,198	1,106
Other	239	229
Total	2,257	2,215

Regulated Cost of Natural Gas

Regulated cost of natural gas decreased $10 million to $30 million in Q3 2020, compared to $40 million in Q3 2019. Year-to-date, regulated cost of natural gas decreased $47 million to $141 million in Q3 2020, compared to $188 million in the same period in 2019. The decrease in both periods was due to lower commodity costs at PGS and NMGC, lower volume of commercial sales and lower volume of off-system sales at PGS.

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Gas sales by type are summarized in the following table:

Q3 Gas Volumes by Type
Therms (millions)
	2020	2019
System supply	92	110
Transportation	581	569
Total	673	679

YTD Gas Volumes by Type
Therms (millions)
	2020	2019
System supply	493	519
Transportation	1,764	1,696
Total	2,257	2,215

Other

	Three months ended						Nine months ended
For the				September 30						September 30
millions of Canadian dollars (except per share amounts)		2020			2019			2020			2019
Marketing and trading margin (1) (2)	$	(12	)	$	(23	)	$	16		$	3
Electricity and capacity sales (3)		6			-			12			116
Other non-regulated operating revenue		4			12			13			30
Total operating revenues – non-regulated	$	(2	)	$	(11	)	$	41		$	149
Intercompany revenue (4)		3			4			10			17
Non-regulated fuel for generation and purchased power (5)		5			-			12			66
Income from equity investments		-			8			17			25
Interest expense, net		72			81			230			256
Adjusted contribution to consolidated net income (loss)	$	(70	)	$	(112	)	$	(229	)	$	(228	)
Gain on sale and impairment charges, net of tax		-			-			283			-
After-tax derivative mark-to-market gain (loss)		(82	)		(67	)		(95	)		(8	)
Contribution to consolidated net income (loss)	$	(152	)	$	(179	)	$	(41	)	$	(236	)
Adjusted contribution to consolidated earnings per common share – basic	$	(0.28	)	$	(0.46	)	$	(0.93	)	$	(0.95	)
Contribution to consolidated earnings per common share – basic	$	(0.61	)	$	(0.74	)	$	(0.17	)	$	(0.99	)
Adjusted EBITDA	$	(22	)	$	(42	)	$	(25	)	$	7
(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 $131 million in Q3 2020 (2019 - $102 million loss) and a loss of $155 million year-to-date (2019 – $19 million loss). (3) Electricity and capacity sales exclude a pre-tax mark-to-market of nil in Q3 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 $3 million in Q3 2020 (2019 - $2 million gain) and a gain of $3 million year-to-date (2019 – $1 million loss).

Other’s adjusted contribution is summarized in the following table:

For the	Three months ended						Nine months ended
millions of Canadian dollars				September 30						September 30
		2020			2019			2020			2019
Emera Energy	$	(12	)	$	(14	)	$	2		$	19
Corporate		(57	)		(99	)		(230	)		(247	)
Other		(1	)		1			(1	)		-
Adjusted contribution to consolidated net income (loss)	$	(70	)	$	(112	)	$	(229	)	$	(228	)

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Net Income

Highlights of the net income changes are summarized in the following table:

For the	Three months ended			Nine months ended
millions of Canadian dollars	September 30			September 30
Contribution to consolidated net income (loss) – 2019	$	(179	)	$	(236	)
Increased marketing and trading margin - see Emera Energy		11			13
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		9			20
Revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, including $2 million recovery related to mark-to-market		-			(11	)
Decreased income tax recovery primarily due to decreased losses before provision for income taxes, partially offset by the impact of Emera’s effective state tax rate		(12	)		(2	)
Decreased preferred stock dividends due to timing		22			11
Impact of sale of NEGG and Bayside Power, net of tax		(1	)		(22	)
Gain on sale of Maine and impairment charges, net of tax		-			283
Increased mark-to-market loss, net of tax, quarter-over-quarter, primarily due to changes in existing positions and higher amortization of gas transportation assets in 2020. Increased mark-to-market loss, net of tax, year-over-year due to higher amortization on gas transportation assets in 2020 and a larger reversal of mark-to-market losses in 2019		(15	)		(89	)
2019 corporate share of the unrecoverable loss at GBPC facilities		9			9
Decreased income from Bear Swamp equity investment due to reduced energy deliveries resulting from a third-party transmission line outage, lower New England capacity prices and less favourable energy market conditions		(8	)		(8	)
Other		12			1
Contribution to consolidated net income (loss) – 2020	$	(152	)	$	(41	)

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 $42 million to a loss of $70 million in Q3 2020, compared to the same period in 2019. Year-to-date, Other’s contribution decreased $1 million to a loss of $229 million compared to 2019. Year-to-date and quarter-over quarter, the increases were due to timing of preferred stock dividends, higher marketing and trading margin, lower interest and the recognition of the corporate share of the unrecoverable loss on GBPC’s facilities in 2019, partially offset by lower income tax recovery. Year-over-year, the decrease was also due to the impact of the sale of NEGG and Bayside Power, revaluation of net deferred income tax assets resulting from the Q1 2020 enactment of a lower Nova Scotia provincial corporate income tax rate and the 2019 sale of property in Florida.

Emera Energy

Marketing and trading margin increased $11 million to a loss of $12 million in Q3 2020, compared to a loss of $23 million in Q3 2019 due to lower fixed commitments for gas transportation and storage assets and increased periods of volatility in Q3 2020, compared to Q3 2019, which improved market opportunity.

Year-to-date, margin increased $13 million to $16 million in 2020, compared to $3 million for the same period in 2019. This increase was due to more favourable hedges in 2020 compared to 2019, partially offset by less favourable winter market conditions, specifically warmer than normal weather, lower natural gas prices and low volatility in Q1 2020 when compared to Q1 2019.

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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 nine months ended September 30, 2020, the effects of the ongoing COVID-19 pandemic including the 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.

The pandemic has generally resulted in lower load and higher operating costs than what otherwise would have been experienced at the Company’s utilities. Some of Emera’s utilities have been impacted more than others. However, on a consolidated basis, these unfavourable impacts have not had 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. As a result of the temporary suspension of disconnections, the Company’s utilities experienced an increase in the aging of customer receivables. This trend has begun to reverse as normal disconnection processes resume. To date, there have been no significant customer defaults as a result of bankruptcies with many customer accounts secured by deposits. The full impact of potential credit losses due to customer non-payment is not known at this time; however, at September 30, 2020, the increase in allowance for credit losses related to the increase in the aging of customer receivables was not material. The utilities are continuing to monitor customer accounts and are continuing to work with customers on payment arrangements.

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 $7.4 billion capital investment plan over the 2021-to-2023 period and the potential for additional capital opportunities of $1.2 billion over the same 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.

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.

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Emera has credit facilities with varying maturities that cumulatively provide $3.3 billion of credit, with approximately $1.6 billion undrawn and available at September 30, 2020. The Company was holding a cash balance of $335 million at September 30, 2020. Refer to the “Debt Management” section below for further details. Refer to notes 19 and 20 in the condensed consolidated interim financial statements for additional information regarding the credit facilities.

As at September 30, 2020, Emera had $145 million CAD ($109 million USD) in receivables and other current assets related to the expected refund of alternative minimum tax credit carryforwards. The Company received this refund in October 2020.

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the nine months ended September 30, 2020 and 2019 include:

millions of Canadian dollars	2020		2019		Change
Cash, cash equivalents, restricted cash and assets held for sale, beginning of period	$	274	$	372	$	(98)
Provided by (used in):
Operating cash flow before change in working capital		1,101		1,182		(81)
Change in working capital		139		128		11
Operating activities		1,240		1,310		(70)
Investing activities		(536)		(786)		250
Financing activities		(595)		(546)		(49)
Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash included in assets held for sale		(48)		(13)		(35)
Cash, cash equivalents, and restricted cash, end of period	$	335	$	337		$            (2)

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $70 million to $1,240 million for the nine months ended September 30, 2020, compared to $1,310 million for the same period in 2019.

Cash from operations before changes in working capital decreased $81 million. The decrease was primarily due to the impact of the sale of Emera Maine in Q1 2020, lower earnings at NSPI, and lower over-recovery from customers of clause-related costs at Tampa Electric and PGS. This was partially offset by higher base revenue at Tampa Electric.

Changes in working capital increased operating cash flows by $11 million. The increase was due to favourable changes in cash collateral at NSPI, and the receipt of a 2019 income tax refund at NSPI in 2020. This was partially offset by a refund of $146 million ($109 million USD) of alternative minimum tax credit carryforwards received in April 2019, decrease in fuel inventory at NSPI, and unfavourable changes in cash collateral at Emera Energy.

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Cash Flow from Investing Activities

Net cash used in investing activities decreased $250 million to $536 million for the nine months ended September 30, 2020, compared to cash used of $786 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 $866 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 nine months ended September 30, 2020, including AFUDC, were $1,967 million compared to $1,662 million for the same period in 2019. Details of the 2020 capital spend by segment are shown below:

• $1,029 million - Florida Electric Utility (2019 – $919 million);

• $253 million - Canadian Electric Utilities (2019 – $263 million);

• $124 million - Other Electric Utilities (2019 – $127 million);

• $559 million - Gas Utilities and Infrastructure (2019 – $295 million); and

• $2 million - Other (2019 – $58 million).

Cash Flow from Financing Activities

Net cash used in financing activities increased $49 million to $595 million for the nine months ended September 30, 2020, compared to $546 million for the same period in 2019. The increase was due to net repayment of debt at TECO Finance, higher net repayments of Emera and NSPI’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.

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Contractual Obligations

As at September 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	$	28	$	1,715	$	425	$	833	$	691	$	10,504	$	14,196
Interest payment obligations (1)		264		607		574		550		535		7,082		9,612
Purchased power (2)		74		218		218		216		219		2,024		2,969
Transportation (3)		157		467		396		337		307		3,028		4,692
Pension and post-retirement obligations (4)		7		33		29		29		97		259		454
Capital projects (5)		222		195		104		91		-		-		612
Fuel, gas supply and storage		177		240		44		6		1		-		468
Asset retirement obligations		2		24		1		1		1		382		411
Long-term service agreements (6)		13		30		30		27		25		96		221
Equity investment commitments (7)		-		-		240		-		-		-		240
Leases and other (8)		4		19		18		18		16		128		203
Demand side management		8		42		43		-		-		-		93
Long-term payable		1		5		5		5		-		-		16
	$	957	$	3,595	$	2,127	$	2,113	$	1,892	$	23,503	$	34,187

(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 September 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 $422 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. Nalcor achieved first power on the first of four generators at Muskrat Falls on September 22, 2020 and continues to work toward project commissioning in 2021.

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, resulting in an additional $27 million to be collected from NSPI. A decision from the UARB is 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 September 30, 2020, $79 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 amounts of $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts included in the NSPI fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. The timing and amounts payable to NSPML for the remainder of the 37-year commitment period are dependent on regulatory filings with the UARB.

41

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	Maturity		Revolving Credit Facilities		Utilized		Undrawn and Available
Emera Inc. – Unsecured committed revolving credit facility		June 2024	$	900	$	456	$	444
Emera Inc. – Unsecured non-revolving facility		December 2020		400		400		-
TECO Finance, Inc. – in USD – Unsecured committed revolving credit facility		March 2022		400		301		99
NSPI – Unsecured committed revolving credit facility		October 2024		600		4		596
TEC – in USD – Unsecured committed revolving credit facility (1)		March 2022		400		196		204
TEC – in USD – Accounts receivable collateralized borrowing facility (1)		March 2021		150		40		110
TEC – in USD – Unsecured non-revolving facility (1)		February 2021		300		300		-
NMGC – in USD – Unsecured committed revolving credit facility		March 2022		125		12		113
Other – in USD – Unsecured committed revolving credit facilities		Various		32		21		11

(1) These facilities are available for use by Tampa Electric and PGS. At September 30, 2020, Tampa Electric had utilized $392 million USD and PGS had utilized $144 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 September 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.

42

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.

At September 30, 2020, BLPC had drawn $67 million BBD ($33 million USD) against a $110 million BBD ($55 million USD) non-revolving term loan. The loan bears interest at a rate of 2.05 per cent and has a 5-year term.

Other

On 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.

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 $54 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 September 30, 2020 was $63 million (December 31, 2019 - $52 million).

Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The guarantee for the notes will expire in May 2023.

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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 Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $27 million for the three months ended September 30, 2020 (2019 - $26 million) and $82 million for the nine months ended September 30, 2020 (2019 - $80 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.

Refer to the “Business Overview and Outlook - Canadian Electric Utilities - ENL” and “Contractual Obligations” sections for further details.

• Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $2 million for the three months ended September 30, 2020 (2019 - $16 million) and $13 million for the nine months ended September 30, 2020 (2019 - $50 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at September 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.

44

The extent of the evolving COVID-19 pandemic and its future impact on the Company is uncertain. The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat. The Company’s top priority continues to be the health and safety of its customers and employees. In Q1 2020, Emera activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

Hedging Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:

As at millions of Canadian dollars	September 30 2020		December 31 2019
Derivative instrument liabilities (current and long-term liabilities)	$	-	$	(1)
Net derivative instrument liabilities	$	-	$	(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 millions of Canadian dollars	Three months ended September 30				Nine months ended September 30
	2020		2019		2020		2019
Operating revenues – regulated	$	-	$	(1)	$	(2)	$	(3)
Effective net losses	$	-	$	(1)	$	(2)	$	(3)

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 millions of Canadian dollars		September 30 2020		December 31 2019
Derivative instrument assets (current and other assets)	$	27	$	28
Regulatory assets (current and other assets)		68		80
Derivative instrument liabilities (current and long-term liabilities)		(68)		(78)
Regulatory liabilities (current and long-term liabilities)		(25)		(42)
Net asset (liability)	$	2	$	(12)

45

Regulatory Impact Recognized in Net Income

The Company recognized the following net gains (losses) related to derivatives receiving regulatory deferral as follows:

For the millions of Canadian dollars	Three months ended September 30				Nine months ended September 30
	2020		2019		2020		2019
Regulated fuel for generation and purchased power (1)	$	(8)	$	-	$	(18)	$	7
Net gains (losses)	$	(8)	$	-	$	(18)	$	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 millions of Canadian dollars	September 30 2020		December 31 2019
Derivative instrument assets (current and other assets)	$	51	$	58
Derivative instrument liabilities (current and long-term liabilities)		(365)		(291)
Net derivative instrument liability	$	(314)	$	(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 millions of Canadian dollars	Three months ended September 30				Nine months ended September 30
	2020		2019		2020		2019
Operating revenue - non-regulated	$	(187)	$	(69)	$	35	$	180
Non-regulated fuel for purchased power		1		1		(3)		(4)
Net gains (losses)	$	(186)	$	(68)	$	32	$	176

Other Derivatives Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to other derivatives:

As at millions of Canadian dollars	September 30 2020		December 31 2019
Derivative instrument assets (current and other assets)	$	11	$	1
Derivative instrument liabilities (current and long-term liabilities)		(3)		-
Net derivative instrument assets	$	8	$	1

Other Derivatives Recognized in Net Income

The Company recognized in net income the following gains (losses) related to other derivatives:

For the millions of Canadian dollars	Three months ended September 30				Nine months ended September 30
	2020		2019		2020		2019
Operating, maintenance and general	$	4	$	11	$	(3)	$	34
Other income (expense)		5		-		5		-
Total gains	$	9	$	11	$	2	$	34

46

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 September 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 September 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, allowance for credit losses, 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 September 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 Q3 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 September 30, 2020.

As of September 30, 2020, $5.9 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 September 30, 2020, $72 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 for the three and nine months ended September 30, 2020 associated with this goodwill.

47

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 September 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 $nil and $25 million ($26 million after tax) were recognized on certain assets for the three and nine months ended September 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 interim financial statements as of January 1, 2020.

48

Future Accounting Pronouncements

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”). The ASUs that have been issued, but are not yet effective, are consistent with those disclosed in the Company’s 2019 audited consolidated financial statements, with updates noted below.

Facilitation of the Effects of Reference Rate Reform on Financial Reporting

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The standard provides optional expedients and exceptions for applying USGAAP to contract modifications and hedging relationships that reference LIBOR or another rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The Company implemented a project plan in Q2 2020 and has identified impacted financial instruments which primarily include debt and hedging contracts. The Company is in the process of 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.

Guaranteed Debt Securities Disclosure Requirements

In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762. The change in the standard aligns with new SEC rules relating to changes to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain narrative disclosures and permitting the disclosures to be made outside of the financial statements. The guidance will be effective for annual reports filed for fiscal years ending after January 4, 2021, with early adoption permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

49

SUMMARY OF QUARTERLY RESULTS
For the quarter ended millions of Canadian dollars	Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4
(except per share amounts)	2020		2020		2020		2019		2019		2019		2019		2018
Operating revenues	$	1,163	$	1,169	$	1,637	$	1,616	$	1,299	$	1,378	$	1,818	$	1,799
Net income attributable to common shareholders		84		58		523		193		55		103		312		231
Adjusted net income attributable to common shareholders		166		118		193		145		122		130		224		167
Earnings per common share – basic		0.34		0.24		2.14		0.79		0.23		0.43		1.32		0.98
Earnings per common share – diluted		0.34		0.23		2.13		0.80		0.23		0.43		1.32		0.98
Adjusted earnings per common share – basic		0.67		0.48		0.79		0.60		0.51		0.54		0.95		0.71

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 include the impact of the COVID-19 pandemic commencing in March 2020. Refer to the “Business Overview and Outlook” section for further details.

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EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

September 30, 2020 and 2019

51

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

For the millions of Canadian dollars (except per share amounts)	Three months ended September 30				Nine months ended September 30
	2020		2019		2020		2019
Operating revenues
Regulated electric	$	1,101	$	1,220	$	3,352	$	3,598
Regulated gas		192		199		730		785
Non-regulated		(130)		(120)		(113)		112
Total operating revenues (note 6)		1,163		1,299		3,969		4,495
Operating expenses
Regulated fuel for generation and purchased power		319		388		1,041		1,207
Regulated cost of natural gas		40		52		189		249
Non-regulated fuel for generation and purchased power		(1)		(4)		3		63
Operating, maintenance and general		334		367		1,046		1,076
Provincial, state and municipal taxes		81		88		243		258
Depreciation and amortization		217		226		664		678
Total operating expenses		990		1,117		3,186		3,531
Income from operations		173		182		783		964
Income from equity investments (note 7)		32		38		113		118
Other income (expenses), net (note 8)		21		(8)		608		11
Interest expense, net		163		183		520		557
Income before provision for income taxes		63		29		984		536
Income tax expense (recovery) (note 9)		(21)		(49)		284		18
Net income		84		78		700		518
Non-controlling interest in subsidiaries		-		1		1		3
Preferred stock dividends		-		22		34		45
Net income attributable to common shareholders	$	84	$	55	$	665	$	470
Weighted average shares of common stock outstanding (in millions) (note 11)
Basic		248.4		241.0		246.6		238.9
Diluted		248.7		242.4		247.0		240.3
Earnings per common share (note 11)
Basic	$	0.34	$	0.23	$	2.70	$	1.97
Diluted	$	0.34	$	0.23	$	2.69	$	1.96
Dividends per common share declared	$	-	$	1.2000	$	1.8375	$	2.3750

The accompanying notes are an integral part of these condensed consolidated financial statements.

52

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

For the millions of Canadian dollars	Three months ended September 30				Nine months ended September 30
	2020		2019		2020		2019
Net income	$	84	$	78	$	700	$	518
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment (1)		(189)		95		207		(243)
Unrealized gains (losses) on net investment hedges (2) (3)		34		(19)		(41)		48
Cash flow hedges
Net derivative gains (losses)		1		-		(1)		3
Less: reclassification adjustment for losses (gains) included in income		-		1		2		3
Net effects of cash flow hedges		1		1		1		6
Net change in unrecognized pension and post-retirement benefit obligation (4)		4		3		2		11
Other comprehensive income (loss) (5)		(150)		80		169		(178)
Comprehensive income (loss)		(66)		158		869		340
Comprehensive income (loss) attributable to non-controlling interest		-		1		2		2
Comprehensive income (loss) of Emera Incorporated	$	(66)	$	157	$	867	$	338

The accompanying notes are an integral part of these condensed consolidated financial statements.

(1) Net of tax recovery of $4 million (2019 - nil) for the three months ended September 30, 2020 and tax expense of $2 million (2019 – nil) for the nine months ended September 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 September 30, 2020 and tax recovery of $1 million (2019 – nil) for the nine months ended September 30, 2020.

(4) Net of tax expense of nil (2019 - nil) for the three months ended September 30, 2020 and tax expense of nil (2019 – $1 million tax expense) for the nine months ended September 30, 2020.

(5) Net of tax recovery of $4 million (2019 - nil) for the three months ended September 30, 2020 and tax expense of $1 million (2019 – $1 million tax expense) for the nine months ended September 30, 2020.

53

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

As at millions of Canadian dollars	September 30 2020		December 31 2019
Assets
Current assets
Cash and cash equivalents	$	286	$	222
Restricted cash (note 24)		49		51
Inventory		475		467
Derivative instruments (notes 13 and 14)		61		54
Regulatory assets (note 15)		126		121
Receivables and other current assets (note 17)		1,313		1,486
Assets held for sale (note 4)		-		85
		2,310		2,486
Property, plant and equipment, net of accumulated depreciation and amortization of $8,846 and $8,295, respectively		19,764		18,167
Other assets
Deferred income taxes		238		186
Derivative instruments (notes 13 and 14)		28		33
Regulatory assets (note 15)		1,421		1,431
Net investment in direct financing lease		470		473
Investments subject to significant influence (note 7)		1,353		1,312
Goodwill		5,993		5,835
Other long-term assets		341		300
Assets held for sale (note 4)		-		1,619
		9,844		11,189
Total assets	$	31,918	$	31,842

54

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued

As at millions of Canadian dollars	September 30 2020		December 31 2019
Liabilities and Equity
Current liabilities
Short-term debt (note 19)	$	1,545	$	1,537
Current portion of long-term debt (note 20)		700		501
Accounts payable		1,094		1,118
Derivative instruments (notes 13 and 14)		331		268
Regulatory liabilities (note 15)		187		295
Other current liabilities		427		333
Liabilities associated with assets held for sale (note 4)		-		114
		4,284		4,166
Long-term liabilities
Long-term debt (note 20)		13,385		13,679
Deferred income taxes		1,639		1,285
Derivative instruments (notes 13 and 14)		105		102
Regulatory liabilities (note 15)		1,935		1,886
Pension and post-retirement liabilities (note 18)		434		460
Other long-term liabilities		833		764
Long-term liabilities associated with assets held for sale (note 4)		-		899
		18,331		19,075
Equity
Common stock (note 10)		6,541		6,216
Cumulative preferred stock (note 22)		1,004		1,004
Contributed surplus		78		78
Accumulated other comprehensive income (note 12)		263		95
Retained earnings		1,382		1,173
Total Emera Incorporated equity		9,268		8,566
Non-controlling interest in subsidiaries		35		35
Total equity		9,303		8,601
Total liabilities and equity	$	31,918	$	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

55

Emera Incorporated Condensed Consolidated Statements of Cash Flows (Unaudited)
For the	Nine months ended September 30
millions of Canadian dollars	2020		2019
Operating activities
Net income	$	700	$	518
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		678		684
Income from equity investments, net of dividends		(58)		(60)
Allowance for equity funds used during construction		(32)		(14)
Deferred income taxes, net		322		82
Net change in pension and post-retirement liabilities		(20)		(26)
Regulated fuel adjustment mechanism		(33)		(20)
Net change in fair value of derivative instruments		66		(51)
Net change in regulatory assets and liabilities		(53)		19
Net change in capitalized transportation capacity		69		42
Gain on sale (excluding transaction costs) and impairment charges		(578)		-
Other operating activities, net		40		8
Changes in non-cash working capital (note 23)		139		128
Net cash provided by operating activities		1,240		1,310
Investing activities
Proceeds from dispositions (note 4)		1,401		866
Additions to property, plant and equipment		(1,935)		(1,647)
Other investing activities		(2)		(5)
Net cash used in investing activities		(536)		(786)
Financing activities
Change in short-term debt, net		252		(188)
Proceeds from short-term debt with maturities greater than 90 days		399		-
Repayment of short-term debt with maturities greater than 90 days		(688)		-
Proceeds from long-term debt, net of issuance costs		422		841
Retirement of long-term debt		(485)		(851)
Net repayments under committed credit facilities		(326)		(165)
Issuance of common stock, net of issuance costs		181		151
Dividends on common stock		(309)		(278)
Dividends on preferred stock		(33)		(34)
Other financing activities		(8)		(22)
Net cash used in financing activities		(595)		(546)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(48)		(13)
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale		61		(35)
Cash, cash equivalents, restricted cash and assets held for sale, beginning of period		274		372
Cash, cash equivalents, restricted cash and assets held for sale, end of period	$	335	$	337
Cash, cash equivalents, restricted cash and assets held for sale consists of:
Cash	$	265	$	266
Short-term investments		21		7
Restricted cash		49		63
Assets held for sale		-		1
Cash, cash equivalents, restricted cash, and assets held for sale	$	335	$	337

The accompanying notes are an integral part of these condensed consolidated financial statements.

56

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss) (“AOCI”)		Retained Earnings		Non- Controlling Interest		Total Equity
For the three months ended September 30, 2020
Balance, June 30, 2020	$	6,435	$	1,004	$	78	$	413	$	1,298	$	36	$	9,264
Net income of Emera Incorporated		-		-		-		-		84		-		84
Other comprehensive income (loss), net of tax recovery of $4 million		-		-		-		(150)		-		-		(150)
Common stock issued under purchase plan		53		-		-		-		-		-		53
Issuance of common stock, net of after-tax issuance costs		52		-		-		-		-		-		52
Other		1		-		-		-		-		(1)		-
Balance, September 30, 2020	$	6,541	$	1,004	$	78	$	263	$	1,382	$	35	$	9,303
millions of Canadian dollars
For the nine months ended September 30, 2020
Balance, December 31, 2019	$	6,216	$	1,004	$	78	$	95	$	1,173	$	35	$	8,601
Net income of Emera Incorporated		-		-		-		-		699		1		700
Other comprehensive income (loss), net of tax expense of $1 million		-		-		-		168		-		1		169
Dividends declared on preferred stock (1)		-		-		-		-		(34)		-		(34)
Dividends declared on common stock ($1.8375/share)		-		-		-		-		(449)		-		(449)
Common stock issued under purchase plan		152		-		-		-		-		-		152
Issuance of common stock, net of after-tax issuance costs		151		-		-		-		-		-		151
Senior management stock options exercised		20		-		(1)		-		-		-		19
Adoption of credit losses accounting standard (note 2)		-		-		-		-		(7)		-		(7)
Other		2		-		1		-		-		(2)		1
Balance, September 30, 2020	$	6,541	$	1,004	$	78	$	263	$	1,382	$	35	$	9,303

The accompanying notes are an integral part of these condensed consolidated financial statements.

(1)    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

57

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss) (“AOCI”)		Retained Earnings		Non- Controlling Interest		Total Equity
For the three months ended September 30, 2019
Balance, June 30, 2019	$	6,010	$	1,004	$	79	$	81	$	1,212	$	35	$	8,421
Net income of Emera Incorporated		-		-		-		-		77		1		78
Other comprehensive income (loss), net of tax expense of nil		-		-		-		80		-		-		80
Dividends declared on preferred stock (1)		-		-		-		-		(22)		-		(22)
Dividends declared on common stock ($1.2000/share)		-		-		-		-		(287)		-		(287)
Common stock issued under purchase plan		45		-		-		-		-		-		45
Issuance of common stock, net of after-tax issuance costs		49										-		49
Senior management stock options exercised		10		-		(1)		-		-		-		9
Other		1		-		-		-		-		(1)		-
Balance, September 30, 2019	$	6,115	$	1,004	$	78	$	161	$	980	$	35	$	8,373
millions of Canadian dollars
For the nine months ended September 30, 2019
Balance, December 31, 2018	$	5,816	$	1,004	$	84	$	338	$	1,075	$	41	$	8,358
Net income of Emera Incorporated		-		-		-		-		515		3		518
Other comprehensive income (loss), net of tax expense of $1 million		-		-		-		(177)		-		(1)		(178)
Dividends declared on preferred stock (2)		-		-		-		-		(45)		-		(45)
Dividends declared on common stock ($2.3750/share)		-		-		-		-		(565)		-		(565)
Issuance of preferred shares of GBPC, net of issuance costs		-		-		-		-		-		14		14
Redemption of preferred shares of GBPC		-		-		-		-		-		(19)		(19)
Common stock issued under purchase plan		146		-		-		-		-		-		146
Issuance of common stock, net of after-tax issuance costs		49		-		-		-		-		-		49
Senior management stock option exercised		103		-		(6)		-		-		-		97
Other		1		-		-		-		-		(3)		(2)
Balance, September 30, 2019	$	6,115	$	1,004	$	78	$	161	$	980	$	35	$	8,373

The accompanying notes are an integral part of these condensed consolidated financial statements.

(1)    Series A; $0.31940/share, Series B; $0.44060/share, Series C; $0.59012/share, Series E; $0.56250/share, Series F; $0.53125/share and Series H; $0.61250/share

(2)    Series A; $0.63880/share, Series B; $0.87270/share, Series C; $1.18024/share, Series E; $1.12500/share, Series F; $1.06250/share and Series H; $1.25500/share

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Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at September 30, 2020 and 2019

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, and gas transmission and distribution.

At September 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 Central Florida.

• Canadian Electric Utilities, which includes:

• Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia; and

• Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission investments related to an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy. ENL’s two investments are:

• a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.6 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project went in service on January 15, 2018; and

• a 48.7 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and Nalcor recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL. In response to the COVID-19 pandemic, on March 17, 2020 Nalcor announced that it had paused construction activities at the Muskrat Falls site. Nalcor resumed work in May 2020 and continues to work toward project commissioning in 2021. Refer to note 21 for further details.

• Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include:

• The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados;

• Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island;

• a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated regulated electric utility on the island of Dominica; and

• a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia.

On March 24, 2020, Emera completed the sale of Emera Maine which was previously included in the Other Electric Utilities segment. Refer to note 4 for further information.

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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;

• SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida;

• Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada, which expires in 2034; and

• a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas throughout markets in Atlantic Canada and the northeastern United States.

At September 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 and provides related energy asset management services;

• Brooklyn Power Corporation (“Brooklyn Energy”), a power plant in Brooklyn, Nova Scotia; and

• a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a pumped storage hydroelectric facility in northwestern Massachusetts.

• Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost-efficient management of risk and deductible levels across Emera;

• Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera;

• Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and

• other investments.

In 2019, the Company completed the sale of assets previously included in the Other segment, including Emera Energy’s New England Gas Generating (“NEGG”) and Bayside facilities, and Emera Utility Services equipment and inventory.

Basis of Presentation

These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2019, except as described in note 2.

In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2020.

All dollar amounts are presented in Canadian dollars, unless otherwise indicated.

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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, allowance for credit losses, 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 and nine months ended September 30, 2020, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. The pandemic has generally resulted in lower load and higher operating costs than what otherwise would have been experienced at the Company’s utilities. Some of Emera’s utilities have been impacted more than others. However, on a consolidated basis these unfavourable impacts have not had a material financial impact to net earnings to date primarily due to a favourable change to the mix of sales to residential customer classes. Lower commercial and industrial sales have been partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. 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. 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 and nine months ended September 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 Q3 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 September 30, 2020.

As of September 30, 2020, $5.9 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 September 30, 2020, $72 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 and nine months ended September 30, 2020 associated with this goodwill.

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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 September 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 $nil and $25 million ($26 million after tax) were recognized on certain assets for the three and nine months ended September 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.

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 include the impact of the COVID-19 pandemic commencing in March 2020.

Receivables and Allowance for Credit Losses

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 credit losses related to 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 credit 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, has impacted the aging of customer receivables resulting in higher allowances for credit losses related to customer receivables.

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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 interim financial statements as of January 1, 2020.

3.   FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”). The ASUs that have been issued, but are not yet effective, are consistent with those disclosed in the Company’s 2019 audited consolidated financial statements, with updates noted below.

Facilitation of the Effects of Reference Rate Reform on Financial Reporting

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The standard provides optional expedients and exceptions for applying USGAAP to contract modifications and hedging relationships that reference LIBOR or another rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The Company implemented a project plan in Q2 2020 and has identified impacted financial instruments which primarily include debt and hedging contracts. The Company is in the process of 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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Guaranteed Debt Securities Disclosure Requirements

In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762. The change in the standard aligns with new SEC rules relating to changes to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain narrative disclosures and permitting the disclosures to be made outside of the financial statements. The guidance will be effective for annual reports filed for fiscal years ending after January 4, 2021, with early adoption permitted. 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 Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations			Total
For the three months ended September 30, 2020
Operating revenues from external customers (1)	$	672	$	324	$	105	$	196	$	(134)	$	-		$	1,163
Inter-segment revenues (1)		2		-		-		1		1		(4)			-
Total operating revenues		674		324		105		197		(133)		(4)			1,163
Regulated fuel for generation and purchased power		135		143		44		-		-		(3)			319
Regulated cost of natural gas		-		-		-		40		-		-			40
Depreciation and amortization		115		59		13		28		2		-			217
Interest expense, net		37		35		6		13		72		-			163
Internally allocated interest (2)		-		-		-		3		(3)		-			-
Operating, maintenance and general (“OM&G”)		137		66		37		79		17		(2)			334
Gain on sale and impairment charges		-		-		-		-		-		-			-
Income tax expense (recovery)		33		1		-		6		(61)		-			(21)
Net income (loss) attributable to common shareholders		175		35		6		20		(152)		-			84
For the nine months ended September 30, 2020
Operating revenues from external customers (1)		1,864		1,117		371		742		(125)		-			3,969
Inter-segment revenues (1)		5		-		-		6		11		(22)			-
Total operating revenues		1,869		1,117		371		748		(114)		(22)			3,969
Regulated fuel for generation and purchased power		407		493		148		-		-		(7)			1,041
Regulated cost of natural gas		-		-		-		189		-		-			189
Depreciation and amortization		343		175		57		83		6		-			664
Interest expense, net		116		105		26		43		230		-			520
Internally allocated interest (2)		-		-		-		10		(10)		-			-
OM&G		407		214		120		242		74		(11)			1,046
Gain on sale and impairment charges		-		-		-		-		560		-			560
Income tax expense (recovery)		75		13		(8)		36		168		-			284
Net income (loss) attributable to common shareholders		400		164		25		117		(41)		-			665
As at September 30, 2020
Total assets		17,449		6,721		1,456		6,064		1,354		(1,126)	(3)		31,918

(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.

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millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations			Total
For the three months ended September 30, 2019
Operating revenues from external customers (1)	$	735	$	296	$	189	$	203	$	(124)	$	-		$	1,299
Inter-segment revenues (1)		3		-		-		6		11		(20)			-
Total operating revenues		738		296		189		209		(113)		(20)			1,299
Regulated fuel for generation and purchased power		222		100		73		-		-		(7)			388
Regulated cost of natural gas		-		-		-		52		-		-			52
Depreciation and amortization		112		58		26		28		2		-			226
Interest expense, net		39		36		13		14		81		-			183
Internally allocated interest (2)		-		-		-		4		(4)		-			-
OM&G		136		88		46		81		29		(13)			367
Income tax expense (recovery)		26		(10)		4		(3)		(66)		-			(49)
Net income (loss) attributable to common shareholders		153		33		23		25		(179)		-			55
For the nine months ended September 30, 2019
Operating revenues from external customers (1)		1,974		1,065		559		797		100		-			4,495
Inter-segment revenues (1)		9		1		-		17		32		(59)			-
Total operating revenues		1,983		1,066		559		814		132		(59)			4,495
Regulated fuel for generation and purchased power		583		431		210		-		-		(17)			1,207
Regulated cost of natural gas		-		-		-		249		-		-			249
Depreciation and amortization		333		171		84		82		8		-			678
Interest expense, net		116		108		39		44		250		-			557
Internally allocated interest (2)		-		-		-		11		(11)		-			-
OM&G		408		230		141		235		103		(41)			1,076
Income tax expense (recovery)		65		(9)		10		31		(79)		-			18
Net income (loss) attributable to common shareholders		339		171		64		132		(236)		-			470
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.

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6.   REVENUE

The following disaggregates the Company’s revenue by major source:

millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total
For the three months ended September 30, 2020
Regulated
Electric Revenue
Residential	$	404	$	161	$	41	$	-	$	-	$	-	$	606
Commercial		170		93		54		-		-		-		317
Industrial		41		57		6		-		-		-		104
Other electric and regulatory deferrals		54		7		3		-		-		-		64
Other (1)		5		6		1		-		-		(2)		10
Regulated electric revenue		674		324		105		-		-		(2)		1,101
Gas Revenue
Residential		-		-		-		77		-		-		77
Commercial		-		-		-		52		-		-		52
Industrial		-		-		-		13		-		-		13
Finance income (2)(3)		-		-		-		15		-		-		15
Other		-		-		-		36		-		(1)		35
Regulated gas revenue		-		-		-		193		-		(1)		192
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		(12)		-		(12)
Energy sales (4)		-		-		-		-		6		(4)		2
Other		-		-		-		4		4		-		8
Mark-to-market (3)		-		-		-		-		(131)		3		(128)
Non-regulated revenue		-		-		-		4		(133)		(1)		(130)
Total operating revenues	$	674	$	324	$	105	$	197	$	(133)	$	(4)	$	1,163
For the nine months ended September 30, 2020
Regulated
Electric Revenue
Residential	$	1,031	$	607	$	138	$	-	$	-	$	-	$	1,776
Commercial		506		303		180		-		-		-		989
Industrial		135		164		25		-		-		-		324
Other electric and regulatory deferrals		183		24		8		-		-		-		215
Other (1)		14		19		20		-		-		(5)		48
Regulated electric revenue		1,869		1,117		371		-		-		(5)		3,352
Gas Revenue
Residential		-		-		-		338		-		-		338
Commercial		-		-		-		193		-		-		193
Industrial		-		-		-		40		-		(1)		39
Finance income (2)(3)		-		-		-		45		-		-		45
Other		-		-		-		120		-		(5)		115
Regulated gas revenue		-		-		-		736		-		(6)		730
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		16		-		16
Energy sales (4)		-		-		-		-		12		(12)		-
Other		-		-		-		12		13		-		25
Mark-to-market (3)		-		-		-		-		(155)		1		(154)
Non-regulated revenue		-		-		-		12		(114)		(11)		(113)
Total operating revenues	$	1,869	$	1,117	$	371	$	748	$	(114)	$	(22)	$	3,969

(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.

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millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total
For the three months ended September 30, 2019
Regulated
Electric Revenue
Residential	$	430	$	135	$	70	$	-	$	-	$	-	$	635
Commercial		212		91		85		-		-		-		388
Industrial		53		52		10		-		-		2		117
Other electric and regulatory deferrals		38		11		5		-		-		(2)		52
Other (1)		5		7		19		-		-		(3)		28
Regulated electric revenue		738		296		189		-		-		(3)		1,220
Gas Revenue
Residential		-		-		-		75		-		-		75
Commercial		-		-		-		59		-		-		59
Industrial		-		-		-		12		-		-		12
Finance income (2)(3)		-		-		-		15		-		-		15
Other		-		-		-		44		-		(6)		38
Regulated gas revenue		-		-		-		205		-		(6)		199
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		(23)		-		(23)
Energy sales (4)		-		-		-		-		(2)		(1)		(3)
Capacity		-		-		-		-		2		-		2
Other		-		-		-		4		12		(10)		6
Mark-to-market (3)		-		-		-		-		(102)		-		(102)
Non-regulated revenue		-		-		-		4		(113)		(11)		(120)
Total operating revenues	$	738	$	296	$	189	$	209	$	(113)	$	(20)	$	1,299
For the nine months ended September 30, 2019
Regulated
Electric Revenue
Residential	$	1,052	$	552	$	203	$	-	$	-	$	-	$	1,807
Commercial		559		298		256		-		-		-		1,113
Industrial		155		160		33		-		-		2		350
Other electric and regulatory deferrals		200		35		12		-		-		(2)		245
Other (1)		17		21		55		-		-		(10)		83
Regulated electric revenue		1,983		1,066		559		-		-		(10)		3,598
Gas Revenue
Residential		-		-		-		357		-		-		357
Commercial		-		-		-		218		-		-		218
Industrial		-		-		-		37		-		-		37
Finance income (2)(3)		-		-		-		44		-		-		44
Other		-		-		-		146		-		(17)		129
Regulated gas revenue		-		-		-		802		-		(17)		785
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		3		-		3
Energy sales (4)		-		-		-		-		78		(7)		71
Capacity		-		-		-		-		38		-		38
Other		-		-		-		12		30		(25)		17
Mark-to-market (3)		-		-		-		-		(17)		-		(17)
Non-regulated revenue		-		-		-		12		132		(32)		112
Total operating revenues	$	1,983	$	1,066	$	559	$	814	$	132	$	(59)	$	4,495

(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.

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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 September 30, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was $334 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

					Equity Income				Equity Income
	Carrying Value				for the				for the				Percentage
	as at				three months ended				nine months ended				of
	September 30		December 31		September 30				September 30				Ownership
millions of Canadian dollars	2020		2019		2020		2019		2020		2019		2020
LIL (1)	$	615	$	579	$	13	$	11	$	37	$	33		48.7
NSPML		560		554		11		9		38		35		100.0
M&NP (2)		133		138		5		5		14		17		12.9
Lucelec (2)		45		41		1		-		3		2		19.5
Bear Swamp (3)		-		-		2		11		21		29		50.0
Other Investments		-		-		-		2		-		2
	$	1,353	$	1,312	$	32	$	38	$	113	$	118

(1) Emera indirectly owns 100 per cent of the LIL Class B units, which comprises 24.9 per cent of the total units issued. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments.

(2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method.

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $130 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	September 30		December 31
millions of Canadian dollars	2020		2019
Balance Sheet
Current assets	$	72	$	69
Property, plant and equipment		1,641		1,671
Regulatory assets		223		177
Non-current assets		32		32
Total assets	$	1,968	$	1,949
Current liabilities	$	66	$	23
Long-term debt		1,248		1,288
Non-current liabilities		94		84
Equity		560		554
Total liabilities and equity	$	1,968	$	1,949

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8.   OTHER INCOME (EXPENSES), NET

For the	Three months ended				Nine months ended
millions of Canadian dollars	September 30				September 30
	2020		2019		2020		2019
Gain on sale and impairment charges (1)	$	-	$	-	$	560	$	-
Allowance for equity funds used during construction		12		6		32		14
Other		9		(14)		16		(3)
	$	21	$	(8)	$	608	$	11

(1) Refer to note 4 for further details related to the gain on sale of Emera 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	Three months ended						Nine months ended
millions of Canadian dollars	September 30						September 30
	2020			2019			2020			2019
Income before provision for income taxes	$	63		$	29		$	984		$	536
Statutory income tax rate		29.5	%		31	%		29.5	%		31	%
Income taxes, at statutory income tax rate		18			9			290			166
Additional impact from the sale of Emera Maine		-			-			102			-
Amortization of deferred income tax regulatory liabilities		(14)			(13)			(41)			(29)
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(8)			(16)			(35)			(50)
Foreign tax rate variance		(10)			(15)			(27)			(40)
Tax effect of equity earnings		(4)			(3)			(12)			(12)
Change in treatment of NMGC net operating loss carryforwards		-			(7)			-			(7)
Other		(3)			(4)			7			(10)
Income tax expense (recovery)	$	(21)		$	(49)		$	284		$	18
Effective income tax rate		(33)	%		(169)	%		29	%		3	%

The year-over-year increase in the effective income tax rate was primarily due to the sale of Emera Maine. Quarter-over-quarter, the increase was due to increased income before provision for income taxes, decreased deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities and a change in treatment of NMGC net operating loss carryforwards in Q3 2019.

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.

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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. There have been no material impacts to Emera’s financial position from the COVID-19 Act or the Government of Canada’s additional announcements.

On March 27, 2020, the United States Coronavirus Aid, Relief, and Economic Security (CARES) Act (“the CARES Act”) was signed into law. 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. As a result, in Q1 2020, the Company reclassified $77 million of AMT credit carryforwards from deferred income tax assets to receivables and other current assets. As at September 30, 2020, the Company had $145 million in receivables and other current assets related to refundable AMT credit carryforwards. This refund was received on October 22, 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) (2)		2.71		151
Issued for cash under Purchase Plans at market rate		2.82		155
Discount on shares purchased under Dividend Reinvestment Plan		-		(3)
Options exercised under senior management share option plan		0.42		20
Employee Share Purchase Plan		-		2
Balance, September 30, 2020		248.43	$	6,541

(1) In Q3 2019 and in the nine months ended September 30, 2019, 880,912 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $56.76 per share for gross proceeds of $50 million ($49 million net of issuance costs).

(2) In Q3 2020, 980,500 common shares were issued under Emera’s ATM program at an average price of $54.43 per share for gross proceeds of $53 million ($53 million net of issuance costs). During the nine months ended September 30, 2020, 2,708,603 common shares were issued under Emera’s ATM program at an average price of $56.62 per share for gross proceeds of $153 million ($151 million net of issuance costs). As at September 30, an aggregate gross sales limit of $347 million remains available for issuance under the ATM program.

As the Q3 2020 dividends were declared by the Board of Directors and recognized in Q2 2020, there were no common share dividends recognized in Q3 2020.

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11.   EARNINGS PER SHARE

The following table reconciles the computation of basic and diluted earnings per share:

For the	Three months ended				Nine months ended
millions of Canadian dollars (except per share amounts)	September 30				September 30
	2020		2019		2020		2019
Numerator
Net income attributable to common shareholders	$	84.3	$	55.0	$	665.4	$	470.3
Diluted numerator		84.3		55.0		665.4		470.3
Denominator
Weighted average shares of common stock outstanding		247.1		239.5		245.3		237.4
Weighted average deferred share units outstanding		1.3		1.5		1.3		1.5
Weighted average shares of common stock outstanding – basic		248.4		241.0		246.6		238.9
Stock-based compensation		0.3		0.6		0.4		0.6
Dividend reinvestment plan		-		0.8		-		0.8
Weighted average shares of common stock outstanding – diluted		248.7		242.4		247.0		240.3
Earnings per common share
Basic	$	0.34	$	0.23	$	2.70	$	1.97
Diluted	$	0.34	$	0.23	$	2.69	$	1.96

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12.   ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income (loss), net of tax, are as follows:

millions of Canadian dollars	Unrealized (loss) gain on translation of self-sustaining foreign operations		Net change in net investment hedges		(Losses) gains on derivatives recognized as cash flow hedges		Net change in available- for-sale investments		Net change in unrecognized pension and post- retirement benefit costs		Total AOCI
For the nine months ended September 30, 2020
Balance, January 1, 2020	$	253	$	4	$	(1)	$	(1)	$	(160)	$	95
Other comprehensive income (loss) before reclassifications		206		(41)		(1)		-		-		164
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		2		-		2		4
Net current period other comprehensive income (loss)		206		(41)		1		-		2		168
Balance, September 30, 2020	$	459	$	(37)	$	-	$	(1)	$	(158)	$	263
For the nine months ended September 30, 2019
Balance, January 1, 2019	$	654	$	(74)	$	(7)	$	(1)	$	(234)	$	338
Other comprehensive income (loss) before reclassifications		(242)		48		3		-		-		(191)
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		3		-		11		14
Net current period other comprehensive income (loss)		(242)		48		6		-		11		(177)
Balance, September 30, 2019	$	412	$	(26)	$	(1)	$	(1)	$	(223)	$	161

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The reclassifications out of accumulated other comprehensive income (loss) are as follows:

For the		Three months ended September 30				Nine months ended September 30
millions of Canadian dollars		2020		2019		2020		2019
	Affected line item in the Consolidated Financial Statements	Amounts reclassified from AOCI
Losses (gain) on derivatives recognized as cash flow hedges
Foreign exchange forwards	Operating revenue – regulated	$	-	$	1	$	2	$	3
Total		$	-	$	1	$	2	$	3
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses (gains)	Other income (expenses), net	$	5	$	4	$	11	$	12
Past service costs (gains)	Other income (expenses), net		(1)		(1)		(1)		(1)
Amounts reclassified into obligations	Pension and post-retirement liabilities		-		1		(8)		1
Total before tax			4		4		2		12
	Income tax recovery		-		-		-		(1)
Total net of tax		$	4	$	4	$	2	$	11
Total reclassifications out of AOCI, net of tax, for the period		$	4	$	5	$	4	$	14

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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;

• foreign exchange fluctuations on foreign currency denominated purchases and sales;

• interest rate fluctuations on debt securities; and

• share price fluctuations on stock-based compensation.

The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:

1. Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exception if the criteria are no longer met.

2. Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized.

Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

3. Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Tampa Electric and PGS have no derivatives related to hedging as a result of a Florida Public Service Commission approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022.

4. Derivatives that do not meet any of the above criteria are designated as held-for-trading (“HFT”) derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

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Derivative assets and liabilities relating to the foregoing categories consisted of the following:

	Derivative Assets				Derivative Liabilities
As at	September 30		December 31		September 30		December 31
millions of Canadian dollars	2020		2019		2020		2019
Cash flow hedges
Foreign exchange forwards	$	-	$	-	$	-	$	1
		-		-		-		1
Regulatory deferral
Commodity swaps and forwards
Coal purchases		2		8		20		39
Power purchases		17		23		35		36
Natural gas purchases and sales		10		2		2		5
Heavy fuel oil purchases		1		1		12		-
Foreign exchange forwards		1		2		3		6
		31		36		72		86
HFT derivatives
Power swaps and physical contracts		11		19		11		22
Natural gas swaps, futures, forwards, physical contracts		108		151		422		381
		119		170		433		403
Other derivatives
Equity derivatives		-		1		2		-
Foreign exchange forwards		11		-		1		-
		11		1		3		-
Total gross current derivatives		161		207		508		490
Impact of master netting agreements with intent to settle net or simultaneously		(72)		(120)		(72)		(120)
		89		87		436		370
Current		61		54		331		268
Long-term		28		33		105		102
Total derivatives	$	89	$	87	$	436	$	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	September 30		December 31		September 30		December 31
millions of Canadian dollars	2020		2019		2020		2019
Regulatory deferral	$	4	$	8	$	4	$	8
HFT derivatives		68		112		68		112
Total impact of master netting agreements with intent to settle net or simultaneously	$	72	$	120	$	72	$	120

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Cash Flow Hedges

The Company has foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.

The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:

For the	Three months ended September 30				Nine months ended September 30
millions of Canadian dollars	2020		2019		2020		2019
		Foreign Exchange Forwards				Foreign Exchange Forwards
Realized (loss) in operating revenue – regulated	$	-	$	(1)	$	(2)	$	(3)
Total (losses) in net income	$	-	$	(1)	$	(2)	$	(3)
As at millions of Canadian dollars	September 30 2020				December 31 2019
						Foreign Exchange Forwards
Total unrealized (loss) in AOCI – net of tax			$	-			$	(1)

In Q3 2020, the Company reclassified $1 million of unrealized losses into net income due to the settlement of the underlying hedged transactions.

As at September 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	$	4

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 September 30
millions of Canadian dollars				2020						2019
	Commodity swaps and forwards			Foreign exchange forwards			Commodity swaps and forwards			Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	9		$	(2	)	$	(25	)	$	5
Unrealized gain (loss) in regulatory liabilities		11			(10	)		10			2
Realized gain in regulatory assets		(1	)		-			-			-
Realized (gain) loss in regulatory liabilities		3			-			(3	)		-
Realized (gain) loss in inventory (1)		3			-			(4	)		(1	)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		8			-			1			(1	)
Total change in derivative instruments	$	33		$	(12	)	$	(21	)	$	5

(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.

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For the	Nine months ended September 30
millions of Canadian dollars				2020						2019
	Commodity swaps and forwards			Foreign exchange forwards			Commodity swaps and forwards			Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	(41	)	$	3		$	(71	)	$	(2	)
Unrealized gain (loss) in regulatory liabilities		8			5			4			(6	)
Realized (loss) in regulatory liabilities		13			-			1			-
Realized (gain) loss in inventory (1)		6			(3	)		(28	)		(9	)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		21			(3	)		(1	)		(6	)
Total change in derivative instruments	$	7		$	2		$	(95	)	$	(23	)

(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 September 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)	7	21
Power (MWh)	-	3
Heavy fuel oil (bbls)	-	1
Coal (metric tonnes)	-	1

Foreign Exchange Swaps and Forwards

As at September 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 dollars)	$	45	$	259
Weighted average rate		1.3377		1.3381
% of USD requirements		59%		61%

The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required.

Held-for-Trading Derivatives

In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures, to economically hedge those physical contracts. These derivatives are all considered HFT.

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The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:

For the	Three months ended						Nine months ended
millions of Canadian dollars	September 30						September 30
	2020			2019			2020			2019
Power swaps and physical contracts in non-regulated operating revenues	$	(1	)	$	(2	)	$	(1	)	$	-
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		(186	)		(67	)		36			180
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		1			1			(3	)		(4	)
	$	(186	)	$	(68	)	$	32		$	176

As at September 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)	168	240	57	41	26
Natural gas sales (Mmbtu)	192	280	50	9	1
Power purchases (MWh)	1	1	-	-	-
Power sales (MWh)	1	-	-	-	-

Other Derivatives

As at September 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 $209 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 September 30
millions of Canadian dollars				2020					2019
		Foreign Exchange Forwards			Equity Derivatives			Foreign Exchange Forwards		Equity Derivatives
Unrealized gain in operating, maintenance and general	$	-		$	4		$	-	$	11
Unrealized gain in other income (expense)		5			-			-		-
Total gains in net income	$	5		$	4		$	-	$	11
For the				Nine months ended September 30
millions of Canadian dollars				2020					2019
		Foreign Exchange Forwards			Equity Derivatives			Foreign Exchange Forwards		Equity Derivatives
Unrealized gain (loss) in operating, maintenance and general	$	-		$	(3	)	$	-	$	34
Unrealized gain in other income (expense)		9			-			-		-
Realized (loss) in other income (expense)		(4	)		-			-		-
Total gains (losses) in net income	$	5		$	(3	)	$	-	$	34

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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 September 30, 2020, the Company had $146 million (December 31, 2019 - $115 million) in financial assets considered to be past due, which have been outstanding for an average 76 days. The fair value of these financial assets is $120 million (December 31, 2019 - $106 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.

Cash Collateral

The Company’s cash collateral positions consisted of the following:

As at millions of Canadian dollars	September 30 2020		December 31 2019
Cash collateral provided to others	$	86	$	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.

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As at September 30, 2020, the total fair value of these derivatives, in a liability position, was $436 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 and locational basis differentials.

● The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

● The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the fair value measurement.

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The following tables set out the classification of the methodology used by the Company to fair value its derivatives:

As at	September 30, 2020
millions of Canadian dollars	Level 1			Level 2			Level 3			Total
Assets
Regulatory deferral
Commodity swaps and forwards
Power purchases	$	16		$	-		$	-		$	16
Natural gas purchases and sales		4			6			-			10
Foreign exchange forwards		-			1			-			1
		20			7			-			27
HFT derivatives
Power swaps and physical contracts		4			1			1			6
Natural gas swaps, futures, forwards, physical contracts and related transportation		2			28			15			45
		6			29			16			51
Other derivatives
Foreign exchange forwards		-			11			-			11
		-			11			-			11
Total assets		26			47			16			89
Liabilities
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-			18			-			18
Power purchases		34			-			-			34
Heavy fuel oil purchases		5			6			-			11
Natural gas purchases and sales		-			2			-			2
Foreign exchange forwards		-			3			-			3
		39			29			-			68
HFT derivatives
Power swaps and physical contracts		4			1			1			6
Natural gas swaps, futures, forwards and physical contracts		3			29			327			359
		7			30			328			365
Other derivatives
Foreign exchange forwards		-			1			-			1
Equity derivatives		2			-			-			2
		2			1			-			3
Total liabilities		48			60			328			436
Net assets (liabilities)	$	(22	)	$	(13	)	$	(312	)	$	(347	)

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As at	December 31, 2019
millions of Canadian dollars	Level 1			Level 2			Level 3			Total
Assets
Regulatory deferral
Commodity swaps and forwards
Power purchases	$	23		$	-		$	-		$	23
Natural gas purchases and sales		-			2			-			2
Heavy fuel oil purchases		-			1			-			1
Foreign exchange forwards		-			2			-			2
		23			5			-			28
HFT derivatives
Power swaps and physical contracts		1			3			1			5
Natural gas swaps, futures, forwards, physical contracts and related transportation		(7	)		46			14			53
		(6	)		49			15			58
Other derivatives
Equity derivatives		1			-			-			1
		1			-			-			1
Total assets		18			54			15			87
Liabilities
Cash flow hedges
Foreign exchange forwards		-			1			-			1
		-			1			-			1
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-			31			-			31
Power purchases		36			-			-			36
Natural gas purchased and sales		3			2			-			5
Foreign exchange forwards		-			6			-			6
		39			39			-			78
HFT derivatives
Power swaps and physical contracts		5			2			-			7
Natural gas swaps, futures, forwards and physical contracts		2			33			249			284
		7			35			249			291
Total liabilities		46			75			249			370
Net assets (liabilities)	$	(28	)	$	(21	)	$	(234	)	$	(283	)

The change in the fair value of the Level 3 financial assets for the three months ended September 30, 2020 was as follows:

	HFT Derivatives
millions of Canadian dollars	Power		Natural                 gas		Total
Balance, beginning of period	$	1	$	11	$	12
Total realized and unrealized gains included in non-regulated operating revenues		-		4		4
Balance, September 30, 2020	$	1	$	15	$	16

The change in the fair value of the Level 3 financial liabilities for the three months ended September 30, 2020 was as follows:

	HFT Derivatives
millions of Canadian dollars	Power		Natural                 gas		Total
Balance, beginning of period	$	-	$	146	$	146
Total realized and unrealized gains included in non-regulated operating revenues		1		181		182
Balance, September 30, 2020	$	1	$	327	$	328

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The change in the fair value of the Level 3 financial assets for the nine months ended September 30, 2020 was as follows:

	HFT Derivatives
millions of Canadian dollars	Power			Natural             gas		Total
Balance, beginning of period	$	1		$	14	$	15
Total realized and unrealized gains included in non-regulated operating revenues		2			1		3
Net transfers out of Level 3		(2	)		-		(2	)
Balance, September 30, 2020	$	1		$	15	$	16

The change in the fair value of the Level 3 financial liabilities for the nine months ended September 30, 2020 was as follows:

	HFT Derivatives
millions of Canadian dollars	Power			Natural             gas		Total
Balance, beginning of period	$	-		$	249	$	249
Total realized and unrealized gains included in non-regulated operating revenues		2			78		80
Net transfers out of Level 3		(1	)		-		(1	)
Balance, September 30, 2020	$	1		$	327	$	328

The Company evaluates observable inputs of market data on a quarterly basis to determine if transfers between levels is appropriate. For the three months ended September 30, 2020, there were no transfers between levels. For the nine months ended September 30, 2020, transfers out of Level 3 in Q2 2020 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.

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:

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As at	September 30, 2020
millions of Canadian dollars	Fair   Value			Valuation Technique		Unobservable Input		Range		Weighted average (1)
Assets
HFT derivatives – Power swaps and physical contracts	$	1			Modelled pricing		Third-party pricing		$17.94-$68.00		$31.62
							Probability of default		0.02%-30.40%		5.72%
							Discount rate		0.01%-0.81%		0.36%
		1			Modelled pricing		Third-party pricing		$26.40-$37.25		$30.11
							Probability of default		0.21%-0.65%		0.46%
							Discount rate		0.17%-0.48%		0.38%
							Correlation factor		100%-100%		100%
HFT derivatives – Natural gas swaps, futures, forwards, physical contracts		12			Modelled pricing		Third-party pricing		$0.91-$8.04		$2.88
							Probability of default		0.02%-10.11%		1.99%
							Discount rate		0.00%-8.11%		0.38%
		2			Modelled pricing		Third-party pricing		$1.33-$8.47		$3.48
							Basis adjustment		$0.00-$1.29		$0.67
							Probability of default		0.07%-17.73%		5.88%
							Discount rate		0.00%-0.55%		0.21%
Total assets	$	16
Liabilities
HFT derivatives – Power swaps and physical contracts	$	1			Modelled pricing		Third-party pricing		$1.13-$68.00		$44.82
							Own credit risk		0.02%-30.40%		2.65%
							Discount rate		0.01%-0.81%		0.30%
		1			Modelled pricing		Third-party pricing		$15.21-$66.95		$60.26
							Own credit risk		0.02%-0.65%		0.42%
							Discount rate		0.01%-0.51%		0.31%
							Correlation factor		100%-100%		100%
HFT derivatives – Natural gas swaps, futures, forwards and physical contracts		311			Modelled pricing		Third-party pricing		$0.66-$8.04		$4.86
							Own credit risk		0.0.2%-10.11%		0.49%
							Discount rate		0.00%-7.15%		0.35%
		15			Modelled pricing		Third-party pricing		$0.71-$9.33		$4.42
							Basis adjustment		$0.00-$1.29		$0.42
							Own credit risk		0.16%-13.09%		0.62%
							Discount rate		0.00%-0.75%		0.22%
Total liabilities	$	328
Net assets (liabilities)	$	(312	)

(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
September 30, 2020	$	14,085	$	16,669	$	-	$	16,160	$	509	$	16,669
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 $34 million was recorded in Other Comprehensive Income for the three months ended September 30, 2020 (2019 – $19 million loss after-tax). An after-tax foreign currency loss of $41 million was recorded in Other Comprehensive Income for the nine months ended September 30, 2020 (2019 – $48 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 millions of Canadian dollars	September 30 2020		December 31 2019
Regulatory assets
Deferred income tax regulatory assets	$	873	$	862
Pension and post-retirement medical plan		377		380
Deferrals related to derivative instruments		68		81
Storm restoration regulatory asset		43		38
Cost recovery clauses		31		13
Environmental remediations		29		26
Stranded cost recovery		28		27
Demand side management (“DSM”) deferral		16		19
Unamortized defeasance costs		14		19
Other		68		87
	$	1,547	$	1,552
Current	$	126	$	121
Long-term		1,421		1,431
Total regulatory assets	$	1,547	$	1,552
Regulatory liabilities
Deferred income tax regulatory liabilities	$	962	$	985
Accumulated reserve - cost of removal		908		891
Regulated fuel adjustment mechanism		82		115
Storm reserve		64		62
Cost recovery clauses		47		53
Self-insurance fund (note 24)		29		29
Deferrals related to derivative instruments		26		42
Other		4		4
	$	2,122	$	2,181
Current	$	187	$	295
Long-term		1,935		1,886
Total regulatory liabilities	$	2,122	$	2,181

Tampa Electric

Base Rates

On July 31, 2020, TEC filed its fourth and final solar base rate adjustments (“SoBRAs”) petition along with supporting tariffs representing 46 MW and $8 million USD annually in estimated revenues. On November 3, 2020, the FPSC approved the tariffs on this SoBRAs filing and TEC will begin receiving these revenues in January 2021.

The true-up filing for SoBRAs tranche 1 and 2 revenue requirement estimates that were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. The $5 million USD true-up was returned to customers in 2020. The true-up for SoBRA tranche 3 will be filed in 2021.

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Storm Protection Cost Recovery Clause and Settlement Agreement

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 SPP program costs previously recovered in base rates 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 removed from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery will begin January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and 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, Tampa Electric recognized $4 million USD of this credit in Q3 2020 and $12 million USD year-to-date, with the remaining $4 million USD to be recognized in Q4 2020.

Big Bend Modernization Project

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.

Mid-Course Adjustment to Fuel Recovery

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.

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PGS

On October 22, 2020, PGS filed a settlement agreement for approval with the FPSC. The settlement agreement allows for an increase in base rates of $58 million USD annually effective January 2021. The $58 million USD increase includes $24 million USD previously recovered through the cast iron and bare steel replacement rider. The settlement agreement includes an allowed regulatory ROE range of 8.90 per cent to 11.00 per cent with a 9.90 per cent midpoint (2020 - 9.25 per cent to 11.75 per cent with a 10.75 per cent midpoint). The settlement agreement provides PGS with the ability to reverse a total of $34 million USD of accumulated depreciation through 2023 and sets new depreciation rates going into effect January 1, 2021. These depreciation rates are comparatively consistent with PGS’ current overall average depreciation rate. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE falls below 8.90 per cent before that time, with an allowed equity capital structure of 54.7 per cent. The settlement agreement further addresses tax rate changes. PGS will quantify the future impact of decreases in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in PGS’ next base rate proceeding. A decision from the FPSC is expected in 2020.

NMGC

On December 23, 2019, NMGC filed a future year rate case for new rates effective January 2021. On August 25, 2020, NMGC filed a settlement agreement with the NMPRC and, on October 20, 2020, a hearing in front of the Hearing Examiner was held. The proposed new rates reflect the recovery of capital investment in pipelines and related infrastructure and would be expected to result in an increase in revenue of approximately $5 million USD annually. A decision from the NMPRC is expected in 2020.

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 September 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 January 1, 2021.

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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 Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $27 million for the three months ended September 30, 2020 (2019 - $26 million) and $82 million for the nine months ended September 30, 2020 (2019 - $80 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.

● Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $2 million for the three months ended September 30, 2020 (2019 - $16 million) and $13 million for the nine months ended September 30, 2020 (2019-$50 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at September 30, 2020 and at December 31, 2019.

17.  RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:    

As at millions of Canadian dollars	September 30 2020		December 31 2019
Customer accounts receivable – billed	$	550	$	603
Customer accounts receivable – unbilled		228		265
Allowance for credit losses		(26)		(9)
Capitalized transportation capacity (1)		181		272
Income tax receivable (2)		153		118
Prepaid expenses		79		48
Other		148		189
	$	1,313	$	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.

(2) At September 30, 2020, includes $145 million related to refundable AMT credit carryforwards. The Company received this refund on October 22, 2020.

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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	Three months ended				Nine months ended
millions of Canadian dollars	September 30				September 30
		2020		2019		2020		2019
Defined benefit pension plans
Service cost	$	11	$	12	$	35	$	36
Non-service cost
Interest cost		21		26		64		78
Expected return on plan assets		(34)		(37)		(107)		(112)
Current year amortization of:
Actuarial losses		4		4		11		12
Past service gains		(1)		(1)		(1)		(1)
Regulatory asset		6		5		20		15
Settlements and curtailments		-		-		-		1
Total non-service costs		(4)		(3)		(13)		(7)
Total defined benefit pension plans		7		9		22		29
Non-pension benefit plans
Service cost		1		1		3		3
Non-service cost
Interest cost		2		4		8		11
Expected return on plan assets		-		-		(1)		(1)
Current year amortization of:
Regulatory asset		-		(2)		-		(5)
Total non-service costs		2		2		7		5
Total non-pension benefit plans		3		3		10		8
Total defined benefit plans	$	10	$	12	$	32	$	37

Emera’s pension and non-pension contributions related to these defined-benefit plans for the three months ended September 30, 2020 were $20 million (2019 – $29 million), and for the nine months ended September 30, 2020 were $50 million (2019 – $63 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 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.

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.

At September 30, 2020, BLPC had drawn $67 million BBD ($33 million USD) against a $110 million BBD ($55 million USD) non-revolving term loan. The loan bears interest at a rate of 2.05 per cent and has a 5-year term.

Other

On March 13, 2020, TECO Finance repaid a $300 million USD note upon maturity. The note was repaid using existing credit facilities.

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21.  COMMITMENTS AND CONTINGENCIES

A. Commitments

As at September 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)	$	74	$	218	$	218	$	216	$	219	$	2,024	$	2,969
Transportation (2)		157		467		396		337		307		3,028		4,692
Capital projects (3)		222		195		104		91		-		-		612
Fuel, gas supply and storage		177		240		44		6		1		-		468
Long-term service agreements (4)		13		30		30		27		25		96		221
Equity investment commitments (5)		-		-		240		-		-		-		240
Leases and other (6)		4		19		18		18		16		128		203
Demand side management		8		42		43		-		-		-		93
	$	655	$	1,211	$	1,093	$	695	$	568	$	5,276	$	9,498

(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 $422 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. Nalcor achieved first power on the first of four generators at Muskrat Falls on September 22, 2020 and continues to work toward project commissioning in 2021.

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, resulting in an additional $27 million to be collected from NSPI. A decision from the UARB is 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 September 30, 2020, $79 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 amounts of $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts included in the NSPI fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. 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.

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.

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. TGH subsequently requested a reconsideration of the interest quantum awarded. On October 16, 2020, the tribunal granted TGH’s request for additional interest. The additional amount is approximately $2 million USD. Guatemala now has until February 13, 2021 to seek annulment of this second award. The total of the two awards, with interest, is approximately $96 million USD. Results to date do not reflect any benefit.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at September 30, 2020, TEC has estimated its financial liability to be $28 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 Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

C. Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are discussed in note 13 and note 14.

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management.

Public Health Risk

An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19 pandemic, or a fear of any of the foregoing, could adversely impact the Company, including by causing operating, supply chain and project development delays and disruptions, labour shortages and shutdowns (including as a result of government regulation and prevention measures), which could have a negative impact on the Company’s operations.

Any adverse changes in general economic and market conditions arising as a result of a public health threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which could result in a material adverse effect on the Company’s business.

The extent of the evolving COVID-19 pandemic and its future impact on the Company is uncertain. The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat. The Company’s top priority continues to be the health and safety of its customers and employees. In Q1 2020, Emera activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

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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 or future 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 or future 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 $54 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 September 30, 2020 was $63 million (December 31, 2019 - $52 million).

Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The guarantee for the notes will expire in May 2023.

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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:

As the Q3 2020 dividends were declared by the Board of Directors and recognized in Q2 2020, there were no preferred share dividends recognized in Q3 2020.

On July 9, 2020, Emera announced it would not redeem the 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 17, 2020, Emera announced 128,610 of its 3,864,636 issued and outstanding Series A Shares were tendered for conversion into Series B Shares and 1,130,788 of its 2,135,364 issued and outstanding Series B Shares were tendered for conversion into Series A Shares, all on a one-for-one basis. As a result of the conversion, Emera has 4,866,814 Series A Shares and 1,133,186 Series B Shares issued and 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 which commenced on August 15, 2020 and ends 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 which commenced on August 15, 2020 and ends on (and inclusive of) November 14, 2020 ($0.1274 per Series B Share for the quarter).

23.  SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the	Nine months ended September 30
millions of Canadian dollars	2020		2019
Changes in non-cash working capital:
Inventory	$	(3)	$	(28)
Receivables and other current assets		115		317
Accounts payable		(42)		(211)
Other current liabilities		69		50
Total non-cash working capital	$	139	$	128
Supplemental disclosure of non-cash activities:
Dividends payable (1)	$	-	$	159
Common share dividends reinvested	$	140	$	140
Decrease in accrued capital expenditures	$	23	$	14

(1) The Board of Directors declaration of the Q4 2020 dividends occurred in October, compared to September in 2019. As a result, there are no common or preferred dividends payable at September 30, 2020.

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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 VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method.

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of Maritime Link. Thus, Emera records 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	September 30, 2020				December 31, 2019
millions of Canadian dollars	Total assets		Maximum exposure to loss		Total assets		Maximum exposure to loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)	$	560	$	17	$	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 November 12, 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:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended September 30, 2020.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

A. designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

i. material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

ii. information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

B. designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.

5.2 ICFR – material weakness relating to design: N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

a. the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of:

i. a proportionately consolidated entity in which the issuer has an interest;

ii. a special purpose entity in which the issuer has an interest; or

iii. a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and

b. summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.

6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2020 and ended on September 30, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 12, 2020

“Scott Balfour”

Scott Balfour

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:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended September 30, 2020.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

A. designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

i. material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

ii. information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

B. designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.

5.2 ICFR – material weakness relating to design: N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

a. the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of:

i. a proportionately consolidated entity in which the issuer has an interest;

ii. a special purpose entity in which the issuer has an interest; or

iii. a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and

b. summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.

6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2020 and ended on September 30, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 12, 2020

“Greg Blunden”

Greg Blunden

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 nine months ended September 30, 2020.

The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended September 30, 2020.

	Twelve months ended September 30, 2020
Earnings Coverage (1)	2.49

⁽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 29.0 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 29.0 per cent, amounted to $48 million for the twelve months ended September 30, 2020. Emera’s interest requirements for the twelve months ended September 30, 2020 amounted to $723 million. Emera’s consolidated income before interest and income tax for the twelve months ended September 30, 2020 was $1,923 million, which is 2.49 times Emera’s aggregate preferred dividends and interest requirements for this period.

EX-99.6

Exhibit 99.6

Emera Reports 2020 Third Quarter Financial Results

HALIFAX, Nova Scotia — Today Emera (TSX: EMA) announced financial results for the third quarter of 2020.

Q3 2020 and Year-to-Date Highlights:

Reported Net Income

• Q3 2020 reported net income was $84 million, or $0.34 per common share, compared with net income of $55 million, or $0.23 per common share, in Q3 2019.

• Year-to-date reported net income was $665 million, or $2.70 per common share, compared with net income of $470 million, or $1.97 per common share, in the 2019 period.

Adjusted Net Income ⁽¹⁾

• Q3 2020 adjusted net income was $166 million, or $0.67 per common share, compared with $122 million, or $0.51 per common share, in Q3 2019.

• Year-to-date adjusted net income was $477 million, or $1.93 per common share, compared with $476 million, or $1.99 per common share, in the 2019 period.

Significant Items Affecting Reported and Adjusted Net Income

• Reported earnings included $309 million year-to-date, net of tax and transaction costs of earnings related to the gain on sale of the Emera Maine business. In addition, $26 million year-to date after-tax impairment were recognized on certain assets.

• 2020 adjusted earnings contribution from Emera Maine was $16 million lower in Q3 2020 than in Q3 2019 and $32 million lower year-to-date reflecting the sale.

• 2020 adjusted earnings contribution from Emera Energy Generation was $22 million lower year-to-date than in 2019 due to the sale of the New England Gas Generating and Bayside generation facilities in March 2019.

• 2020 adjusted earnings were reduced by $14 million year-to-date from the revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities due to the reduction in the Nova Scotia provincial corporate income tax rate.

• Timing of preferred share dividend declaration increased earnings by $22 million for Q3 2020 as compared to Q3 2019, and $11 million higher for the year-to-date.

Cash Flow

• Year-to-date operating cash flow, before changes in working capital, decreased by $81 million to $1,101 million, compared with $1,182 million in the 2019 period.

⁽¹⁾ See “Non-GAAP Measures” noted below.

“Our businesses have continued to focus on safely delivering for our customers during the challenges of the COVID-19 pandemic”, said Scott Balfour, President & CEO of Emera Inc. “Over 60% of our updated capital program is focused on improving reliability and delivering cleaner energy. Our continuing investments are driving a forecasted 50% reduction in GHG emissions and an 80% reduction in coal generation in 2023 as compared to 2005 levels.”

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Financial Highlights:

For the	Three months ended				Nine months ended
millions of Canadian dollars (except per share amounts)	September 30				September 30
	2020		2019		2020		2019
Net income attributable to common shareholders	$	84	$	55	$	665	$	470
Gain on sale and impairment charges, net of tax	$	-		-		283		-
After-tax mark-to-market gain (loss)		(82)		(67)		(95)		(6)
Adjusted net income attributable to common shareholders(1)(2)	$	166	$	122	$	477	$	476
Earnings per common share – basic	$	0.34	$	0.23	$	2.70	$	1.97
Adjusted earnings per common share – basic (1)(2)	$	0.67	$	0.51	$	1.93	$	1.99
Weighted average shares of common stock outstanding - basic (millions of shares)		248		241		247		239

⁽¹⁾ See “Non-GAAP Measures” noted below

⁽⁽²⁾ Adjusted net income and adjusted earnings per common share exclude the effect of mark-to-market adjustments, gain on sale and impairment charges, net of tax

After-tax mark-to-market losses increased $15 million to $82 million in Q3 2020 compared to $67 million in Q3 2019. This increase was due to changes in existing positions on gas contracts and higher amortization of gas transportation assets in 2020. Year-to-date, after-tax mark-to-market losses increased $89 million to $95 million in 2020, compared to a $6 million loss in 2019. This increase was due to higher amortization of gas transportation assets in 2020 and larger reversal of mark-to-market losses in 2019.

Weakening of the CAD exchange rates increased earnings by $4 million and adjusted earnings by $2 million in Q3 2020 compared to Q3 2019. The weakening of the CAD exchange rates increased earnings by $18 million and adjusted earnings by $6 million year-to-date in 2020, compared to the same period in 2019.

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Consolidated Financial Review:

The following table highlights significant changes in adjusted net income from 2019 to 2020 in the third quarter and year-to-date periods.

For the millions of Canadian dollars	Three months ended September 30			Nine months ended September 30
Adjusted net income – 2019	$	122		$	476
Increased earnings at Tampa Electric in both periods due to the in- service of solar generation, higher allowance for funds used during construction (“AFUDC”) earnings from the Big Bend modernization and solar projects, increased sales to residential customers, favourable weather, customer growth, and a credit to depreciation and amortization expense as a result of a regulatory settlement		22			61
Timing of preferred share dividend declaration		22			11
Recognition of corporate income tax recovery deferred as a regulatory liability in 2018 at BLPC		-			10
2019 recognition of corporate loss for the share of the unrecoverable loss on GBPC’s facilities related to Hurricane Dorian		9			9
Increased earnings at Emera Energy Services in Q3 2020 due to lower fixed commitments for gas transportation and storage assets and periods of increased volatility which improved market opportunity. Year- to-date the increase was due to more favourable hedges, partially offset by less favourable winter market conditions in Q1 2020		9			9
Decreased earnings at NSPI due to higher income tax expense and lower commercial sales related to COVID-19 in both periods, the quarter-over-quarter impact of the reversal of fixed cost deferrals in Q3 2019 and unfavourable weather year-to-date. The decrease in both periods was partially offset by increased residential sales related to COVID-19 and decreased operating, maintenance and general (“OM&G”) expense		(2	)		(13	)
Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities due to the Q1 2020 reduction in the Nova Scotia provincial corporate income tax rate		-			(14	)
Lower earnings contribution from the Caribbean utilities due to lower sales related to the impact of the COVID-19 pandemic and continued recovery from Hurricane Dorian at GBPC		(1	)		(15	)
Q3 2019 recognition of tax benefits related to change in treatment of net operating loss (“NOL”) carryforwards and tax reform benefits recognized in Q2 2019 in NMGC		(7	)		(19	)
Decreased earnings due to the sale of Emera Maine in Q1 2020 and the sale of Emera Energy’s New England Gas Generating Facilities (“NEGG”) and Bayside generation facilities in Q1 2019		(17	)		(54	)
Other variances		9			16
Adjusted net income – 2020	$	166		$	477

⁽¹⁾ See “Non-GAAP Measures” noted below

⁽²⁾ Excludes the effect of mark-to-market adjustments, gain on sale and impairment charges, net of tax

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Segmented Results:

For the millions of Canadian dollars (except per share amounts)	Three months ended September 30						Nine months ended September 30
	2020			2019			2020			2019
Adjusted net income (1)
Florida Electric Utility	$	175		$	153		$	400		$	339
Canadian Electric Utilities		35			33			164			171
Other Electric Utilities		6			23			25			62
Gas Utilities and Infrastructure		20			25			117			132
Other (2)		(70	)		(112	)		(229	)		(228	)
Adjusted net income (1)	$	166		$	122		$	477		$	476
Gain on sale and impairment charges, net of tax		-						283			-
After-tax mark-to-market gain (loss)		(82	)		(67	)		(95	)		(6	)
Net income attributable to common shareholders	$	84		$	55		$	665		$	470
EPS (basic)	$	0.34		$	0.23		$	2.70		$	1.97
Adjusted EPS (basic) (1)(2)	$	0.67		$	0.51		$	1.93		$	1.99

⁽¹⁾ See “Non-GAAP Measures” noted below.

⁽²⁾ Excludes the effect of mark-to-market adjustments, gain on sale and impairment charges, net of tax

Florida Electric Utility’s CAD net income increased by $22 million to $175 million in Q3 2020, compared to $153 million in Q3 2019. Year-to-date, Florida Electric Utility’s CAD net income increased by $61 million to $400 million, compared to $339 million in 2019. The increase in both periods was due to increased base revenues and higher AFUDC earnings as a result of the Big Bend modernization and solar projects. Operating revenues decreased due to lower clause revenues; however, base revenues increased as a result of the in-service of solar generation projects, a greater mix of residential sales, favourable weather and customer growth.

Canadian Electric Utilities’ net income increased by $2 million to $35 million, compared to $33 million in Q3 2019 due to decreased OM&G, higher residential electric sales at NSPI and higher equity earnings at ENL, partially offset by reversal of fixed cost deferral in 2019 and increased income taxes resulting from lower tax deductions in excess of accounting depreciation related to property, plant and equipment. Year-to-date, Canadian Electric Utilities’ net income decreased by $7 million to $164 million, compared to $171 million in Q3 2019. The decrease was due to the unfavourable impacts of increased income tax expense, as discussed above, unfavourable weather and decreased commercial, other and industrial sales volumes related to the impact of the COVID-19 pandemic, partially offset by decreased OM&G expense and increased residential sales volumes related to the impact of the COVID-19 pandemic at NSPI and higher equity earnings in ENL.

Other Electric Utilities’ CAD net income, adjusted to exclude mark-to-market, decreased by $17 million to $6 million in Q3 2020, compared to $23 million in Q3 2019. Year-to-date, Other Electric Utilities’ CAD net income, adjusted to exclude mark-to-market, decreased by $37 million to $25 million, compared to $62 million in 2019. ECI’s year-to-date contribution decreased due to lower commercial and industrial sales, partially offset by increased sales to residential customers due to the impact of the COVID-19 pandemic and due to the continued recovery from Hurricane Dorian at GBPC. Year-to-date, the decrease was partially offset by recognition of a previously deferred corporate income tax recovery related to enactment of a lower

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corporate income tax rate in December 2018 at BLPC. Lower contribution from Emera Maine as a result of the sale in Q1 2020 decreased earnings in both periods.

Gas Utilities and Infrastructure’s CAD net income decreased by $5 million to $20 million in Q3 2020, compared to $25 million in Q3 2019. Year-to-date, Gas Utilities and Infrastructure’s CAD net income decreased by $15 million to $117 million, compared to $132 million in 2019. The decrease in both periods were due to NMGC’s recognition of a tax benefit related to the change in treatment of NOL carryforwards in Q3 2019 and lower PGS base revenues due to the impacts of COVID-19 on commercial sales. These decreases were partially offset by higher customer growth, increased AFUDC earnings and higher return on investment in Cast Iron/Bare Steel replacement rider at PGS and lower OM&G expenses at NMGC. Year-to-date, the decrease was also due to NMGC’s recognition of tax reform benefits in Q2 2019.

Other’s net loss, adjusted to exclude mark-to-market, decreased by $42 million to $70 million in Q3 2020, compared to $112 million in Q3 2019. Year-to-date, Other’s net loss, adjusted to exclude mark-to-market and the gain on sale and impairment charges, net of tax, increased by $1 million to $229 million, compared to $228 million in 2019. Year-to-date and quarter-over-quarter, the decreases were due to the timing of preferred stock dividends, higher marketing and trading margin, lower interest and the recognition of the corporate share of the unrecoverable loss on GBPC’s facilities in 2019, partially offset by lower income tax recovery. Year-to-date, the decrease was also due to the impact of the sale of NEGG and Bayside Power, revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020 and the 2019 sale of property in Florida.

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.

Teleconference Call

The company will be hosting a teleconference today, Friday, November 13, 2020, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q3 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.

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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 by dialing 1-800-585-8367 and entering pass code 6936268

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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