Form 6-K

EMERA INCORPORATED

Date: May 14, 2021

\s\ Stephen D. Aftanas

Name: Stephen D. Aftanas

Title: Corporate Secretary

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

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

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of May, 2021

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.

EXHIBIT INDEX


Exhibit No.		Description

99.1		Emera Incorporated Management’s Discussion and Analysis for the three month period ended March 31, 2021
99.2		Emera Incorporated Unaudited Condensed Consolidated Interim Financial Statements for the three month period ended March 31, 2021
99.3		Form 52-109F2 Certification of Interim Filings by the Chief Executive Officer
99.4		Form 52-109F2 Certification of Interim Filings by the Chief Financial Officer
99.5		Emera Incorporated Earnings Coverage Ratio for the Twelve Months Ended March 31, 2021
99.6		Emera Incorporated Media Release dated May 12, 2021

EX-99.1

Exhibit 99.1

LOGO

Management’s Discussion & Analysis

As at May 11, 2021

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the first quarter of 2021 relative to the same quarter in 2020; and its financial position as at March 31, 2021 relative to December 31, 2020. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.

This discussion and analysis should be read in conjunction with the Emera Incorporated unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2021; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2020. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At March 31, 2021, 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

On March 24, 2020, the Company completed the sale of Emera Maine. For further detail, refer to the “Significant Items Affecting Earnings” section.

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.

TABLE OF CONTENTS


Forward-looking Information		4
Introduction and Strategic Overview		4
Non-GAAP Financial Measures		6
Consolidated Financial Review		7
Significant Items Affecting Q1 Earnings		7
Consolidated Financial Highlights by Business Segment		8
Consolidated Income Statement Highlights		9
Business Overview and Outlook		12
COVID-19 Pandemic		12
Florida Electric Utility		13
Canadian Electric Utilities		14
Other Electric Utilities		16
Gas Utilities and Infrastructure		16
Other		17
Consolidated Balance Sheet Highlights		18
Developments		18
Outstanding Stock Data		19
Financial Highlights		19
Florida Electric Utility		19
Canadian Electric Utilities		21
Other Electric Utilities		24
Gas Utilities and Infrastructure		25
Other		27
Liquidity and Capital Resources		28
Consolidated Cash Flow Highlights		30
Contractual Obligations		31
Debt Management		32
Guarantees and Letters of Credit		33
Transactions with Related Parties		33
Risk Management including Financial Instruments		34
Disclosure and Internal Controls		36
Critical Accounting Estimates		36
Changes in Accounting Policies and Practices		38
Future Accounting Pronouncements		38
Summary of Quarterly Results		39

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, carbon dioxide emissions reduction goals, 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 include without limitation: 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 continues to be safely delivering 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. 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’s $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, results in a forecasted rate base growth of 7.5 per cent to 8.5 per cent through 2023. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization and customer-focused technologies. Emera’s capital investment plan 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 are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan and at-the-market program. 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 investments 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, digitization, decarbonization, complex regulatory environments and decentralized generation.

Customers are looking for more choice, better control, and enhanced reliability in a time where costs of decentralized generation and storage have become more competitive in some regions. Advancing technologies are transforming the way utilities interact with their customers and generate and transmit energy. In addition, 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 all these trends. Emera’s strategy is to fund investments in renewable energy 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 safely delivering cleaner, reliable, and affordable energy for its customers.

Building on its decarbonization progress over the past 15 years, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a clear path to Emera’s interim carbon goals. With existing technologies and resources and the benefit of supportive regulatory decisions, Emera plans and expects to achieve the following goals compared to corresponding 2005 levels:

•

A 55 per cent reduction in carbon dioxide emissions by 2025.

•

An 80 per cent reduction in coal usage by 2023 and the retirement of Emera’s last existing coal unit no later than 2040.

•

At least an 80 per cent reduction in carbon dioxide emissions by 2040.

Emera seeks to achieve these goals and realize its net-zero vision while remaining focused on maintaining affordability, enhancing reliability, adopting emerging technologies and working constructively with policymakers, regulators, partners, investors, and Emera’s communities.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships.

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, impacts in 2020 of the gain on sale of Emera Maine and impairment charges on certain other assets.

The MTM adjustments are a result of the following:

●

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

●

the MTM 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 MTM 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 MTM adjustments for evaluation of performance and incentive compensation. For further detail on MTM adjustments, refer to the “Consolidated Financial Review” and the “Financial Highlights - Other” sections.

In 2020, the Company recognized a gain on the sale of Emera Maine. Management believes excluding this from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. For further details related to the sale of Emera Maine, refer to the “Significant Items Affecting Earnings” section. While the gain on sale has been excluded from adjusted earnings, earnings for the Other Electric Utilities segment includes earnings from Emera Maine up to the date of its sale on March 24, 2020.

In 2020, the Company recognized certain non-cash impairment charges. Management believes excluding from net income the effect of these charges better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the Company. For further details, refer to the “Significant Items Affecting Earnings” and “Financial Highlights – Other” sections.

The following reconciles reported net income attributable to common shareholders to adjusted net income attributable to common shareholders; and reported earnings per common share – basic, to adjusted earnings per common share – basic:


For the		Three months ended March 31
millions of Canadian dollars (except per share amounts)		2021	2020
Net income attributable to common shareholders	$	273	$ 523
Gain on sale, net of tax and transaction costs		-	321
Impairment charges, net of tax		-	(23)
After-tax MTM gain		30	32
Adjusted net income attributable to common shareholders	$	243	$ 193
Earnings per common share – basic	$	1.08	$ 2.14
Adjusted earnings per common share – basic	$	0.96	$ 0.79

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 MTM adjustments, the gain on sale of Emera Maine and impairment charges, as discussed above.

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies but, in management’s view, appropriately reflect Emera’s specific operating performance. These measures are not intended to replace “Net income attributable to common shareholders” which, as determined in accordance with GAAP, is an indicator of operating performance.

The following is a reconciliation of reported net income to EBITDA and Adjusted EBITDA:


For the		Three months ended March 31
millions of Canadian dollars		2021	2020
Net income (1)	$	285	$ 535
Interest expense, net		157	184
Income tax expense		56	306
Depreciation and amortization		226	231
EBITDA	$	724	$ 1,256
Gain on sale (excluding transaction costs)		-	586
Impairment charges		-	(22)
MTM gain, excluding income tax		43	45
Adjusted EBITDA	$	681	$ 647
(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Q1 Earnings

Earnings Impact of After-Tax MTM Gains

After-tax MTM gains decreased $2 million to $30 million in 2021 compared to $32 million in 2020 due to changes in existing positions, partially offset by lower amortization of gas transportation assets in 2021 compared to 2020 at Emera Energy and decreased foreign exchange losses on cash flow hedges.

Q1 2020 Gain on Sale and Impairment Charges

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of $2.0 billion ($1.4 billion USD). In Q1 2020, a gain on sale of $586 million ($321 million after tax or $1.31 per common share), net of transaction costs, was recognized in “Other income” on the Condensed Consolidated Statements of Income.

In addition, impairment charges of $22 million ($23 million after tax) were recognized on certain other assets in Q1 2020.

Consolidated Financial Highlights by Business Segment


For the	Three months ended March 31
millions of Canadian dollars	2021	2020
Adjusted Net Income
Florida Electric Utility	$ 83	$ 79
Canadian Electric Utilities	88	92
Other Electric Utilities	7	20
Gas Utilities and Infrastructure	80	70
Other	(15)	(68)
Adjusted net income attributable to common shareholders	$ 243	$ 193
Gain on sale, net of tax and transaction costs	-	321
Impairment charges, net of tax	-	(23)
After-tax MTM gain	30	32
Net income attributable to common shareholders	$ 273	$ 523

The following table highlights significant changes in adjusted net income from 2020 to 2021.


For the		Three months ended
millions of Canadian dollars		March 31
Adjusted net income – 2020		$ 193
Operating Unit Performance
Increased earnings at Emera Energy Services (“EES”) due to favourable market conditions driven by colder weather		17
Increased earnings at PGS due to higher base revenues as the result of a base rate increase on January 1, 2021 and customer growth		10
Decreased earnings due to the sale of Emera Maine in Q1 2020		(6)
Tax Related
Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities in Q1 2020 due to the reduction in the Nova Scotia provincial corporate income tax rate		14
Recognition of corporate income tax recovery in Q1 2020 previously deferred as a regulatory liability in 2018 at BLPC		(10)
Corporate
Decreased operating, maintenance and general expense (“OM&G”), pre-tax, due to lower long-term incentive compensation		16
Decreased interest expense, pre-tax, due to repayment of debt, the impact of a stronger CAD and lower interest rates		13
Other Variances		(4)
Adjusted net income – 2021		$ 243

For further details of reportable segment contributions, refer to the “Financial Highlights” section.


For the		Three months ended March 31
millions of Canadian dollars		2021	2020
Operating cash flow before changes in working capital	$	340	$ 502
Change in working capital		(41)	(74)
Operating cash flow	$	299	$ 428
Investing cash flow	$	(478)	$ 746
Financing cash flow	$	196	$ 165

As at		March 31	December 31
millions of Canadian dollars		2021	2020
Total assets	$	31,371	$ 31,234
Total long-term debt (including current portion)	$	14,728	$ 13,721

For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.

Consolidated Income Statement Highlights


For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2021	2020		Variance
Operating revenues	$ 1,612	$ 1,637	$	(25)
Operating expenses	1,175	1,238		63
Income from operations	437	399		38
Income from equity investments	41	41		-
Other income (expenses), net	20	585		(565)
Interest expense, net	157	184		27
Income tax expense	56	306		250
Net income	285	535		(250)
Net income attributable to common shareholders	273	523		(250)
Gain on sale, net of tax and transaction costs	-	321		(321)
Impairment charges, net of tax	-	(23)		23
After-tax MTM gain (loss)	30	32		(2)
Adjusted net income attributable to common shareholders	$ 243	$ 193	$	50
Earnings per common share – basic	$ 1.08	$ 2.14	$	(1.1)
Earnings per common share – diluted	$ 1.08	$ 2.13	$	(1.1)
Adjusted earnings per common share – basic	$ 0.96	$ 0.79	$	0.170
Dividends per common share declared	$ 0.6375	$ 0.6125	$	0.0250

Adjusted EBITDA	$ 681	$ 647	$	34

Operating Revenues

For the first quarter of 2021, operating revenues decreased $25 million compared to the first quarter of 2020. Absent decreased MTM gains of $20 million, operating revenues decreased $5 million due to:

●

$59 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020;

●

$48 million decrease in the Florida Electric Utility segment due to the impact of a stronger CAD and decreased base revenues due to milder weather compared to the prior year;

●

$18 million decrease in the Other Electric Utilities segment due to the impact of a stronger CAD, lower fuel revenue as a result of lower oil prices at BLPC and a reduction in commercial sales as a result of the impact of the COVID-19 pandemic at BLPC and GBPC; and

●

$15 million decrease at NSPI in the Canadian Electric Utilities segment due to lower Maritime Link assessment included in revenue compared to 2020, decreased sales volumes due to warmer weather, and decreased commercial sales volumes due to the impact of the COVID-19 pandemic. This was partially offset by increased fuel-related pricing and increased residential sales volumes due to the impact of COVID-19.

These impacts were partially offset by:

●

$62 million increase in the Gas Utilities and Infrastructure segment due to base rate increases at PGS and NMGC effective January 1, 2021, customer growth at PGS and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices. This increase was partially offset by lower asset optimization revenue at NMGC;

●

$47 million increase in the Florida Electric Utility segment due to higher fuel recovery clause revenues as a result of an increase in fuel costs, the in-service of additional solar generation projects and customer growth; and

●

$26 million increase in the Other segment due to higher marketing and trading margin at EES primarily driven by favourable market conditions. For further details, refer to the “Financial Highlights – Other – Emera Energy” section.

Operating Expenses

For the first quarter of 2021, operating expenses decreased $63 million compared to the first quarter of 2020. Absent the 2020 impairment charges of $22 million, operating expenses decreased $41 million due to:

●

$48 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020;

●

$19 million decrease in the Other Electric Utilities segment due to lower oil prices at BLPC;

●

$16 million decrease in the Other segment due to lower Corporate OM&G reflecting lower long-term incentive compensation; and

●

$9 million decrease at NSPI in the Canadian Electric Utilities segment due to changes in regulatory deferrals, partially offset by increased regulated fuel for generation and purchased power.

These impacts were partially offset by:

●

$49 million increase in the Gas Utilities and Infrastructure segment due to higher gas prices at NMGC and PGS, partially offset by a decrease in system supply volumes.

Other Income, Net

The decrease in other income, net for the first quarter in 2021, compared to the first quarter of 2020, was primarily due to the pre-tax gain on sale of Emera Maine in Q1 2020.

Interest Expense, net

Interest expense, net was lower for the first quarter of 2021 compared to the first quarter of 2020 due to repayment of debt, the impact of a stronger CAD and lower interest rates.

Income Tax Expense

The decrease in income tax expense for the first quarter of 2021 compared to the first quarter of 2020 was primarily due to the gain on sale of Emera Maine in Q1 2020.

Net Income and Adjusted Net Income Attributable to Common Shareholders

For the first quarter of 2021, the decrease in net income attributable to common shareholders compared to the same period in 2020, was unfavourably impacted by the $321 million after-tax gain on sale of Emera Maine in 2020, unfavourably impacted by the $2 million decrease in after-tax MTM gains and favourably impacted by the $23 million after-tax impairment charge in 2020. Absent the net gain on sale of Emera Maine, the MTM changes and the 2020 impairment charges, adjusted net income attributable to common shareholders increased $50 million. This increase was due to higher earnings contributions from EES and Gas Utilities and Infrastructure, the 2020 revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate, and lower corporate OM&G and interest expenses. These were partially offset by the 2020 recognition of a corporate income tax recovery previously deferred as a regulatory liability in 2018 at BLPC, the impact of the strengthening CAD and lower earnings from the sale of Emera Maine in Q1 2020.

Earnings and Adjusted Earnings per Common Share – Basic

Earnings per common share – basic were lower for the first quarter due to lower earnings as discussed above and the impact of the increase in the weighted average shares outstanding. Adjusted earnings per common share – basic were higher for the first quarter due to higher adjusted earnings as discussed above, partially offset by the impact of the increase in the weighted average shares outstanding.

Effect of Foreign Currency Translation

Emera operates internationally including in Canada, the US and various Caribbean countries. As such, the Company generates revenues and incurs expenses denominated in local currencies which are translated into CAD for financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can positively or adversely affect results.

In general, Emera’s earnings benefit from a weakening CAD and are adversely impacted by a strengthening CAD. The impact of foreign exchange in any period is driven by rate changes, the timing of earnings from foreign operations during the period, the percentage of earnings from foreign operations in the period and the impact of foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure.

Results of foreign operations are translated at the weighted average rate of exchange and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/USD exchange rates for 2021 and 2020 are as follows:


	Three months ended		Year ended
	March 31		December 31
	2021	2020	2020
Weighted average CAD/USD	$ 1.27	$ 1.34	$ 1.34
Period end CAD/USD exchange rate	$ 1.26	$ 1.42	$ 1.27

Strengthening of the CAD decreased earnings by $11 million and decreased adjusted earnings by $9 million in Q1 2021 compared to Q1 2020.

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 USD currency.


For the	Three months ended March 31
millions of US dollars	2021	2020
Florida Electric Utility	$ 65	$ 59
Other Electric Utilities	6	15
Gas Utilities and Infrastructure (1)	56	45
	127	119
Other segment (2)	(2)	(23)
Total	$ 125	$ 96

(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.

(2) Includes Emera Energy’s USD adjusted net income from Emera Energy Services, Bear Swamp, and interest expense on Emera Inc.’s USD denominated debt.

BUSINESS OVERVIEW AND OUTLOOK

COVID-19 Pandemic

The ongoing COVID-19 pandemic continues to affect all service territories in which Emera operates. Emera’s utilities provide essential services and continue to operate to meet customer demand. The Company’s priorities continue to be the reliable delivery of essential energy services while maintaining the health and safety of its customers and employees and supporting the communities in which Emera operates.

Governments world-wide have implemented measures intended to address the pandemic. These measures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial 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 continue to work with customers on relief initiatives in response to the effect of the pandemic on customers’ ability to pay and their need for continued service. Initiatives taken by Emera included the temporary suspension of disconnection for non-payment of bills and the development of payment arrangements where necessary. For further information on the impact to the aging of customer receivables and allowance for credit losses, refer to the “Liquidity and Capital Resources” section.

Potential future impacts of COVID-19 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. 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, timing and effectiveness of vaccinations, 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. For further detail, refer to the “Liquidity and Capital Resources” section.

Refer to the outlook sections below, by segment, for affiliate specific impacts. These segment outlooks are based on the information currently available, however, the total impact of COVID-19 is unknown at this time.

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.

Due to continued growth in rate base, Tampa Electric anticipates earning near or below the bottom of the allowed ROE range in 2021. Tampa Electric sales volumes are expected to be lower than in 2020, which benefited from weather that was warmer than in recent years. As a result, Tampa Electric anticipates earnings to be slightly lower than in 2020. Tampa Electric expects customer growth rates in 2021 to be consistent with 2020, reflective of current expected economic growth in Florida.

On April 9, 2021, Tampa Electric requested a base rate increase, reflecting increased revenue requirements of $295 million USD, effective January 1, 2022. Tampa Electric’s proposed 2022 rates include recovery for the costs of the first phase of the Big Bend modernization project, 225 MW of utility-scale solar projects, the advanced metering infrastructure (“AMI”) investment, and accelerated recovery of the remaining net book value of retiring coal and other assets. Tampa Electric also requested approval for Generation Base Rate Adjustments for 2023 and 2024 that total approximately $130 million USD to recover the remaining investments in the Big Bend modernization project and additional utility-scale solar projects in subsequent years. A decision by the FPSC is expected by the end of 2021.

In 2021, capital investment in the Florida Electric Utility segment is expected to be approximately $1.2 billion USD (2020 - $1.0 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, continuation of the modernization of the Big Bend Power Station, storm hardening investments, and AMI.

Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and Emera Newfoundland & Labrador Holdings Inc. (“ENL”). NSPI is 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. ENL is 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.

NSPI

NSPI anticipates earning near the low end of its allowed ROE range in 2021 and expects rate base and earnings to be higher than 2020. Assuming normal weather and a modest economic recovery from impacts of the COVID-19 pandemic in 2021, NSPI expects sales volumes to be higher than 2020.

In Q1 2021, NSPI received its 2021 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These 2021 allowances will be used in 2021 or allocated within the initial four-year compliance period that ends in 2022. NSPI is on track to meet the requirements of the program, where compliance is forecasted to be achieved through the granted emissions allowances, reduced emissions and credit purchases under the Cap-and-Trade 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.

Energy from renewable sources will increase upon delivery of the Nova Scotia block (“NS Block”) of electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project (“Muskrat Falls”). The NS Block will provide NSPI with approximately 900 GWh of energy annually for 35 years. In addition, for the first five years of the NS Block, NSPI is also entitled to receive approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. NSPI has the option of purchasing additional market-priced energy from Nalcor Energy (“Nalcor”) through the Energy Access Agreement. Nalcor is obligated to offer NSPI a minimum average of 1.2 TWh of energy annually pursuant to this agreement. Nalcor continues to work toward construction completion and final commissioning in 2021 for the Lower Churchill projects (including Muskrat Falls and LIL), with delivery of the NS Block anticipated to commence in the second half of 2021.

Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be generated from renewable sources. Due to the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan in 2020, as permitted by the legislation. The alternative compliance plan requires NSPI to supply customers with at least 40 per cent of energy generated from renewable sources over the 2020 to 2022 period. NSPI expects to achieve this alternative compliance standard.

In 2021, capital investment for NSPI is expected to be approximately $395 million (2020 – $316 million), including AFUDC, primarily in capital projects required to support system reliability and hydroelectric infrastructure renewal projects.

ENL

Equity earnings from NSPML and LIL are expected to be higher in 2021, compared to 2020. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

NSPML

Equity earnings 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.

The Maritime Link assets entered service on January 15, 2018 and provide for the transmission of energy between Newfoundland and Nova Scotia, 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 Lower Churchill project is complete.

NSPML has UARB approval to collect $172 million (2020 - $145 million) from NSPI for the recovery of costs associated with the Maritime Link in 2021. This is subject to a holdback of $10 million and potential long-term deferral of approximately $23 million in depreciation expense dependent upon the timing of commencement of the NS Block. Approximately $162 million is included in NSPI rates. NSPML anticipates making an application with the UARB in 2021 to set rates for recovery of Maritime Link costs in 2022. NSPML expects to file a final capital cost application with the UARB upon commencement of the NS Block of energy from Muskrat Falls which is expected to take place in the second half of 2021.

In 2021, NSPML expects to invest approximately $10 million (2020 - $7 million) in capital.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor continues to work toward final project commissioning in 2021.

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 $641 million, comprised of $410 million in equity contribution and $231 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 the Lower Churchill projects 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 final project commissioning of Muskrat Falls and LIL in 2021.

Other Electric Utilities

Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island, a 51.9 per cent interest in Domlec on the island of Dominica and a 19.5 per cent interest in Lucelec on the island of St. Lucia which is accounted for on the equity basis.

On March 24, 2020, Emera completed the sale of Emera Maine which was included in the Other Electric Utilities segment in Q1 2020.

Removing the Q1 2020 earnings contribution from Emera Maine (refer to “Significant Items Affecting Q1 Earnings”), Other Electric Utilities’ earnings in 2021 are expected to increase over the prior year due to higher earnings in 2021 as local economies begin to recover from the impacts of COVID-19 and continued recovery from Hurricane Dorian at GBPC. As of Q1 2021, GBPC has recognized the remaining proceeds from insurers with respect to the Hurricane Dorian claim.

In Q1 2021, GBPC notified the GBPA of its intention to submit a Rate Plan proposal in 2021.

On November 6, 2020, BLPC notified the FTC that it plans to file a general rate review application with the FTC. This application is expected to be filed in Q2 2021.

In 2021, capital investment in the Other Electric Utilities segment is expected to be approximately $120 million USD (2020 – $111 million USD including $14 million USD invested in Emera Maine projects), primarily in more efficient and cleaner sources of generation, including renewables and battery storage. BLPC expects to complete installation of a 33 MW diesel engine plant in Q2 2021. This 33 MW plant is expected to increase efficiency and bridge BLPC’s transition to increased renewable sources of generation.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s non-consolidated investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is a regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.

Gas Utilities and Infrastructure earnings are anticipated to be higher in 2021 than 2020 primarily due to approved base rate increases for PGS and NMGC.

PGS anticipates earning within its allowed ROE range in 2021 and expects rate base and earnings to be higher than in 2020. PGS expects customer growth in 2021 to be higher than Florida’s population growth rates, reflecting expectations of continued strong housing demand in Florida and commercial activity trending back towards normal levels. Assuming normal weather, PGS sales volumes are expected to increase above customer growth, as the COVID-19 pandemic impact on 2021 commercial energy sales is expected to be less than 2020. In January 2021, a base rate increase went into effect in accordance with the FPSC approved rate case settlement and is expected to result in a $34 million USD revenue increase.

NMGC’s application for new rates was approved in December 2020 and took effect in January 2021. The new rates result in an increase in revenue of approximately $5 million USD annually. NMGC anticipates earning at or near its authorized ROE in 2021 and expects rate base to be higher than 2020. NMGC expects customer growth rates to be consistent with historical trends.

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $110 million USD for gas costs above what it would normally have paid during this period. NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause. On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge. The filing proposes to recover the $110 million USD over a period of 30 months beginning July 1, 2021. A decision is expected by the end of Q2 2021.

In 2021, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $430 million USD (2020 - $553 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC completed the Santa Fe Mainline Looping project in 2021 and will continue to invest in system improvements.

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 the Other segment include Emera Technologies LLC (“ETL”) and Emera Energy. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers. Emera Energy consists of EES, a wholly owned physical energy marketing and trading business 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.

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, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. 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 natural gas and electricity 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 usually providing the greatest opportunity for earnings. EES 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. The COVID-19 pandemic remains a challenge to the overall economy but is expected to continue to have limited impact on EES operations unless circumstances deteriorate significantly.

Absent the gain on the TECO Guatemala Holdings award in Q4 2020, the adjusted net loss from the Other segment is expected to be lower in 2021, primarily due to decreased interest expense, lower OM&G and higher earnings from EES. The decrease is expected to be partially offset by increased taxes due to a lower net loss and increased project spend in ETL.

In 2021, capital investment in the Other segment is expected to be approximately $5 million (2020 - $3 million).

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2020 and March 31, 2021 include:


millions of Canadian dollars	Increase (Decrease)		Explanation
Assets
Regulatory assets (current and long-term)	$	128	Increased due to NMGC winter event gas cost recovery and increased income tax regulatory asset at NSPI. This increase was partially offset by deferrals related to derivative instruments at NSPI.
Goodwill		(71)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign affiliates.
Liabilities and Equity
Short-term debt and long-term debt (including current portion)	$	124	Increased due to issuance of long-term debt at TEC and NMGC. This increase was partially offset by net repayments on committed credit facilities and short-term debt at TEC, and the effect of a stronger CAD on the translation of Emera’s foreign affiliates.
Accounts payable		(130)	Decreased due to timing of payments at Tampa Electric, PGS, NSPI, and NMGC, and the effect of a stronger CAD on the translation of Emera’s foreign affiliates.
Deferred income tax liabilities, net of deferred income tax assets		54	Increased due to tax deductions in excess of accounting depreciation related to property, plant and equipment.
Derivative instruments (current and long-term)		(58)	Decreased due to the reversal of 2020 contracts, partially offset by new contracts in 2021 at Emera Energy.
Other liabilities (current and long-term)		75	Increase due to higher accrued interest on long-term debt at Tampa Electric and Corporate and investment tax credits related to solar projects at Tampa Electric.
Common stock		111	Increased due to shares issued under the dividend reinvestment plan and Emera’s at-the-market equity program.
Accumulated other comprehensive income		(66)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign affiliates.
Retained earnings		113	Increased due to net income in excess of dividends paid.

DEVELOPMENTS

Preferred Shares

On April 6, 2021, Emera issued 8 million Cumulative Minimum Rate Reset First Preferred Shares, Series J at $25.00 per share at an initial dividend rate of 4.25 per cent. The aggregate gross and net proceeds from the offering were $200 million and $196 million, respectively. The net proceeds of the preferred share offering will be used for general corporate purposes.

OUTSTANDING STOCK DATA

Common stock


	millions of		millions of
Issued and outstanding:	shares		Canadian dollars
Balance, December 31, 2019		242.48		$ 6,216
Issuance of common stock (1)		4.54		251
Issued for cash under Purchase Plans at market rate		3.99		219
Discount on shares purchased under Dividend Reinvestment Plan		-		(4	)
Options exercised under senior management stock option plan		0.42		20
Employee Share Purchase Plan		-		3
Balance, December 31, 2020		251.43		$ 6,705
Issuance of common stock (2)		0.94		50
Issued for cash under Purchase Plans at market rate		1.18		60
Discount on shares purchased under Dividend Reinvestment Plan		-		(1	)
Options exercised under senior management stock option plan		0.01		1
Employee Share Purchase Plan		-		1
Balance, March 31, 2021		253.56		$ 6,816

(1) In 2020, 4,544,025 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $56.04 per share for gross proceeds of $255 million ($251 million net of issuance costs).

(2) In Q1 2021, 940,100 common shares were issued under Emera’s ATM program at an average price of $53.57 per share for gross proceeds of $50 million ($50 million net of issuance costs). As at March 31, 2021 an aggregate gross sales limit of $195 million remains available for issuance under the ATM program.

As at May 7, 2021 the amount of issued and outstanding common shares was 253.7 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended March 31, 2021 was 253.5 million (2020 – 244.7 million).

FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.


For the		Three months ended March 31
millions of US dollars (except per share amounts)		2021	2020
Operating revenues – regulated electric	$	447	$ 421
Regulated fuel for generation and purchased power	$	128	$ 106
Contribution to consolidated net income	$	65	$ 59
Contribution to consolidated net income – CAD	$	83	$ 79
Contribution to consolidated earnings per common share – basic – CAD	$	0.33	$ 0.32
Net income weighted average foreign exchange rate – CAD/USD	$	1.28	$ 1.34

EBITDA	$	197	$ 184
EBITDA – CAD	$	251	$ 248

Net Income

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


For the		Three months ended
millions of US dollars		March 31
Contribution to consolidated net income – 2020		$ 59
Increased operating revenues - see Operating Revenues - Regulated Electric below		26
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		(22)
Decreased OM&G expenses due to lower benefit costs, timing of planned maintenance outages quarter-over-quarter and lower labour costs as the result of lower coal generation		10
Increased depreciation and amortization due to increased property, plant and equipment		(7)
Increased AFUDC earnings due to the Big Bend Power Station modernization and solar projects		4
Other		(5)
Contribution to consolidated net income – 2021		$ 65

Florida Electric Utility’s CAD contribution to consolidated net income increased $4 million to $83 million in Q1 2021, compared to $79 million in Q1 2020. Earnings increased due to lower OM&G expense and higher AFUDC, partially offset by lower base revenues from unfavourable weather and higher depreciation expense.

The impact of the change in the foreign exchange rate decreased Q1 2021 CAD earnings by $5 million.

Operating Revenues – Regulated Electric

Electric revenues increased $26 million to $447 million in Q1 2021 compared to $421 million in Q1 2020 primarily due to higher fuel recovery clause revenue as a result of higher fuel costs, partially offset by lower base revenue. Base revenue decreased due to mild weather compared to the same period in 2020, partially offset by higher base rates from the in-service of additional solar generation projects and customer growth.

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

Q1 Electric Revenues

millions of US dollars


		2021	2020
Residential	$	232	$ 205
Commercial		126	125
Industrial		37	37
Other (1)		52	54
Total	$	447	$ 421

(1) Other includes sales to public authorities, off-system sales to other utilities, unbilled revenues and regulatory deferrals related to clauses.

Q1 Electric Sales Volumes (1)

Gigawatt hours (“GWh”)


	2021	2020
Residential	2,053	1,880
Commercial	1,325	1,373
Industrial	474	497
Other	445	466
Total	4,297	4,216

(1) Electric sales volumes are calculated based on billed hours only. GWh related to unbilled revenues are excluded.

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $22 million to $128 million in Q1 2021, compared to $106 million in Q1 2020, due to increased natural gas prices.

Q1 Production Volumes


GWh
	2021	2020
Natural gas	3,407	4,105
Solar	286	234
Coal	406	181
Purchased power	340	36
Total	4,439	4,556

Average fuel cost per MWh increased in Q1 2021, compared to Q1 2020, primarily due to increased natural gas prices.

Canadian Electric Utilities


For the		Three months ended March 31
millions of Canadian dollars (except per share amounts)		2021	2020
Operating revenues – regulated electric	$	443	$ 458
Regulated fuel for generation and purchased power (1)	$	212	$ 194
Income from equity investments	$	26	$ 27
Contribution to consolidated net income	$	88	$ 92
Contribution to consolidated earnings per common share - basic	$	0.35	$ 0.38

EBITDA	$	190	$ 193

(1) Regulated fuel for generation and purchased power includes NSPI’s Fuel Adjustment Mechanism (“FAM”) and fixed cost deferrals on the Condensed Consolidated Income Statement, however it is excluded in the segment overview.

Canadian Electric Utilities’ contribution is summarized in the following table:


For the	Three months ended March 31
millions of Canadian dollars	2021		2020
NSPI	$	62	$ 65
Equity investment in NSPML		13	15
Equity investment in LIL		13	12
Contribution to consolidated net income	$	88	$ 92

Net Income

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


For the		Three months ended
millions of Canadian dollars		March 31
Contribution to consolidated net income – 2020		$ 92
Decreased operating revenues - see Operating Revenues - Regulated Electric below		(15)
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		(18)
Decreased FAM and fixed cost deferrals due to under-recovery of current period fuel costs compared to prior year’s over-recovery of fuel costs. This was partially offset by the refund to customers in 2020		29
Increased depreciation and amortization due to increased property, plant and equipment		(3)
Decreased income tax expense primarily due to the impact of the change in the Nova Scotia provincial income tax rate in the prior year		2
Other		1
Contribution to consolidated net income – 2021		$ 88

Canadian Electric Utilities’ contribution to consolidated net income decreased in Q1 2021 primarily due to lower contribution from NSPI. This decrease was due to lower Maritime Link assessment included in revenue compared to 2020, decreased sales volumes due to warmer weather and increased fuel costs. The decrease was partially offset by lower FAM expense and fixed cost deferrals due to under-recovery of current period fuel costs in the current year compared to prior year’s over-recovery, partially offset by a refund to customers in prior year. Q1 2021 income from equity earnings was consistent with Q1 2020.

NSPI

Operating Revenues – Regulated Electric

Operating revenues decreased $15 million to $443 million in Q1 2021 compared to $458 million in Q1 2020. The decrease was primarily due to lower Maritime Link assessment included in revenue compared to 2020, decreased sales volumes due to warmer weather and decreased commercial sales volumes due to the impact of the COVID-19 pandemic. This was partially offset by increased fuel related pricing and increased residential sales volumes due to the impact of COVID-19.

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

Q1 Electric Revenues


millions of Canadian dollars
		2021	2020
Residential	$	259	$ 264
Commercial		114	120
Industrial		56	56
Other		7	11
Total	$	436	$ 451

Q1 Electric Sales Volumes


GWh
	2021	2020
Residential	1,549	1,560
Commercial	822	860
Industrial	572	588
Other	43	76
Total	2,986	3,084

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $18 million to $212 million in Q1 2021 compared to $194 million in Q1 2020, due to changes in generation mix and increased commodity prices, partially offset by decreased sales volumes.

Q1 Production Volumes


GWh
		2021	2020
Coal		1,654	1,595
Natural Gas		313	474
Petcoke		206	272
Purchased power – other		139	119
Oil		51	10
Total non-renewables		2,363	2,470
Purchased power – Independent Power Producers (“IPP”)		361	335
Wind and hydro		305	341
Purchased power – Community Feed-in Tariff program		151	147
Biomass		37	11
Total renewables		854	834
Total production volumes		3,217	3,304

Q1 Average Fuel Costs
		2021	2020
Dollars per MWh	$	66	$ 59

Average fuel cost per MWh increased in Q1 2021, compared to Q1 2020, primarily due to changes in generation mix as a result of increased purchased power, increased oil and biomass generation, partially offset by lower natural gas generation. Additionally, decreased generation from NSPI-owned wind and hydro, with no associated fuel costs, had an unfavourable impact on generation mix. Increased commodity prices also contributed to a higher average fuel cost quarter-over-quarter.

NSPI’s FAM regulatory liability balance decreased $19 million from $21 million at December 31, 2020 to $2 million at March 31, 2021 due to under-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. For further detail, refer to the “Significant Items Affecting Earnings” section.


For the		Three months ended March 31
millions of US dollars (except per share amounts)		2021	2020
Operating revenues – regulated electric	$	74	$ 127
Regulated fuel for generation and purchased power (1)	$	33	$ 50
Adjusted contribution to consolidated net income	$	6	$ 15
Adjusted contribution to consolidated net income - CAD	$	7	$ 20
After-tax equity securities MTM gain (loss)	$	-	$ (2)
Contribution to consolidated net income	$	6	$ 13
Contribution to consolidated net income – CAD	$	7	$ 17
Adjusted contribution to consolidated earnings per common share – basic – CAD	$	0.03	$ 0.08
Contribution to consolidated earnings per common share – basic – CAD	$	0.03	$ 0.07
Net income weighted average foreign exchange rate – CAD/USD	$	1.26	$ 1.37

Adjusted EBITDA	$	22	$ 40
Adjusted EBITDA - CAD	$	28	$ 54

(1) Regulated fuel for generation and purchased power includes transmission pool expense in 2020 related to Emera Maine.

Other Electric Utilities’ adjusted contribution is summarized in the following table:


For the		Three months ended March 31
millions of US dollars		2021	2020
GBPC	$	5	$ 1
BLPC		2	11
Emera Maine		-	4
Other		(1)	(1)
Adjusted contribution to consolidated net income	$	6	$ 15

Excluding the change in MTM, Other Electric Utilities’ CAD contribution to consolidated net income decreased by $13 million to $7 million in Q1 2021, compared to $20 million in Q1 2020. The sale of Emera Maine decreased earnings by $6 million. BLPC’s contribution decreased due to the recognition of a $10 million previously deferred corporate income tax recovery in Q1 2020 related to the enactment of a lower corporate income tax rate in December 2018. These decreases were partially offset by the recognition of Hurricane Dorian insurance proceeds at GBPC. The foreign exchange rate decreased earnings and adjusted earnings $1 million for the three months ended March 31, 2021.

Operating Revenues – Regulated Electric

Operating revenues decreased $53 million to $74 million in Q1 2021 compared to $127 million in Q1 2020. Decreases were the result of the sale of Emera Maine, lower fuel revenue at BLPC due to lower oil prices and a reduction in commercial sales as a result of the impact of the COVID-19 pandemic.

Electric sales volumes were 289 GWh in Q1 2021 compared to 818 GWh in Q1 2020.

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $17 million to $33 million in Q1 2021, compared to $50 million in Q1 2020 primarily due to lower oil prices at BLPC.

Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.


For the		Three months ended March 31
millions of US dollars (except per share amounts)		2021	2020
Operating revenues – regulated gas (1)	$	312	$ 250
Operating revenues – non-regulated		3	3
Total operating revenue	$	315	$ 253
Regulated cost of natural gas	$	124	$ 81
Income from equity investments	$	4	$ 3
Contribution to consolidated net income	$	63	$ 53
Contribution to consolidated net income – CAD	$	80	$ 70
Contribution to consolidated earnings per common share – basic - CAD	$	0.32	$ 0.29
Net income weighted average foreign exchange rate – CAD/USD	$	1.27	$ 1.33

EBITDA	$	118	$ 103
EBITDA – CAD	$	150	$ 137

(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2020 – $11 million), however, it is excluded from the gas revenues analysis below.

Gas Utilities and Infrastructure’s contribution is summarized in the following table:


For the		Three months ended March 31
millions of US dollars		2021	2020
PGS	$	27	$ 18
NMGC		24	23
Other		12	12
Contribution to consolidated net income	$	63	$ 53

Net Income

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


For the		Three months ended
millions of US dollars		March 31
Contribution to consolidated net income – 2020		$ 53
Increased gas operating revenues - see Operating Revenues - Regulated Gas below		62
Increased cost of natural gas sold - see Regulated Cost of Natural Gas below		(43)
Increased depreciation and amortization expenses due to increased property, plant and equipment		(3)
Other		(6)
Contribution to consolidated net income – 2021		$ 63

Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $10 million to $80 million in Q1 2021 compared to $70 million in Q1 2020 due to PGS’ higher base revenues as the result of a base rate increase and customer growth.

The impact of the change in the foreign exchange rate decreased CAD earnings by $4 million for the three months ended March 31, 2021.

Operating Revenues – Regulated Gas

Operating revenues increased $62 million to $312 million in Q1 2021 compared to $250 million in Q1 2020 due to a base rate increase at PGS and NMGC effective January 1, 2021, customer growth at PGS, and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices. This increase was partially offset by lower asset optimization revenues at NMGC.

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

Q1 Gas Revenues


millions of US dollars
		2021	2020
Residential	$	172	$ 126
Commercial		90	67
Industrial (1)		12	10
Other (2)		27	36
Total (3)	$	301	$ 239

(1) Industrial includes sales to power generation customers.

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

(3) Excludes $11 million of finance income from Brunswick Pipeline (2020 – $11 million).

Q1 Gas Volumes


Therms (millions)
	2021	2020
Residential	188	172
Commercial	242	251
Industrial	367	387
Other	47	97
Total	844	907

Regulated Cost of Natural Gas

Regulated cost of natural gas increased $43 million to $124 million in Q1 2021, compared to $81 million in Q1 2020, due to higher gas prices, partially offset by a decrease in system supply sales volumes.

Gas sales by type are summarized in the following table:

Q1 Gas Volumes by Type

Other


For the		Three months ended March 31
millions of Canadian dollars (except per share amounts)		2021	2020
Marketing and trading margin (1) (2)	$	67	$ 41
Other non-regulated operating revenue		8	9
Total operating revenues – non-regulated	$	75	$ 50
Income from equity investments	$	7	$9
Adjusted contribution to consolidated net income (loss)	$	(15)	$ (68)
Gain on sale, net of tax and transaction costs		-	321
Impairment charges, net of tax		-	(23)
After-tax derivative MTM gain		30	35
Contribution to consolidated net income	$	15	$ 265
Adjusted contribution to consolidated earnings per common share – basic	$	(0.06)	$ (0.28)
Contribution to consolidated earnings per common share – basic	$	0.06	$ 1.08

Adjusted EBITDA	$	65	$ 17

(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 MTM gain of $38 million for the quarter ended March 31, 2021 (2020 - $63 million gain).

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


For the		Three months ended March 31
millions of Canadian dollars		2021	2020
Emera Energy	$	43	$ 21
Corporate – see breakdown of adjusted contribution below		(54)	(87)
Emera Technologies		(3)	(2)
Other		(1)	-
Adjusted contribution to consolidated net income (loss)	$	(15)	$ (68)

Net Income

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


For the		Three months ended
millions of Canadian dollars		March 31
Contribution to consolidated net income – 2020		$ 265
Increased marketing and trading margin - see Emera Energy		26
Decreased OM&G primarily due to lower long-term incentive compensation		16
Decreased interest expense due to repayment of debt, the impact of a stronger CAD and lower interest rates		13
Revaluation of net deferred income tax assets and liabilities resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, including $2 million recovery related to MTM		11
Realized foreign exchange gain on cash flow hedges to hedge foreign exchange earnings exposure		5
Decreased MTM gain, net of tax, primarily due to changes in existing positions, partially offset by lower amortization of gas transportation assets and decreased foreign exchange losses on cash flow hedges		(4)
Decreased income tax recovery primarily due to decreased losses before provision for income taxes		(21)
2020 gain on sale and impairment charges, net of tax		(298)
Other		2
Contribution to consolidated net income – 2021		$ 15

Emera Energy

Marketing and trading margin increased $26 million to $67 million in Q1 2021 compared to $41 million in Q1 2020. The mid-February extreme weather event across the South-Central US sharply increased pricing and volatility in adjacent markets where Emera Energy has a presence, and the business was able to capitalize. The Northeast, though seasonally cold, was largely insulated from the weather event, but still provided steady opportunity throughout Q1.

Corporate

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


For the	Three months ended March 31
millions of Canadian dollars	2021	2020

Operating expenses (1)	$ -	$ 16

Interest expense	68	81

Income tax expense (recovery)	(18)	(33)

Preferred dividends	11	11

Income tax expense associated with the revaluation of Corporate deferred income tax assets and liabilities due to the 2020 reduction in the Nova Scotia provincial corporate income tax rate	-	9

Other	(7)	3

Adjusted contribution to consolidated net income (loss)	$ (54)	$ (87)

(1) Operating expenses include OM&G and depreciation. In the three months ended March 31, 2021, OM&G and depreciation were offset by a decrease in long-term incentive compensation. The value of long-term incentive compensation and related hedges are impacted by changes in Emera’s period end share price.

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.

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 financial impact to consolidated net earnings to date in 2021. For further discussion, refer to the “Business Overview and Outlook – COVID-19 Pandemic” section. In 2020, as a result of the temporary suspension of disconnections and the challenging economic environment, the Company’s utilities experienced an increase in the aging of customer receivables. In Q1 2021, most of Emera’s utilities have resumed normal disconnection and collection processes and as a result this trend has continued to reverse and aging of customers receivables has improved. There have been no significant customer defaults as a result of bankruptcies with many customer accounts secured by deposits. As of March 31, 2021, adjustments to the allowance for credit losses have increased but 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 working 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, timing and effectiveness of vaccinations, 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 investments 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 investment plan cannot be predicted at this time. 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 and debt raised at the utilities 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 are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan and at-the-market program. The Company’s future access to capital may be impacted by possible COVID-19 related market disruptions.

Emera has credit facilities with varying maturities that cumulatively provide $3.4 billion of credit, with approximately $2.0 billion undrawn and available at March 31, 2021. The Company was holding a cash balance of $268 million at March 31, 2021. For further discussion, refer to the “Debt Management” section below. Refer to notes 19 and 20 in the condensed consolidated financial statements for additional information regarding the credit facilities.

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 2021 and 2020 include:


millions of Canadian dollars	2021	2020	Change

Cash, cash equivalents, and restricted cash, beginning of period	$ 254	$ 274	$ (20)

Provided by (used in):

Operating cash flow before change in working capital	340	502	(162)

Change in working capital	(41)	(74)	33

Operating activities	$ 299	$ 428	$ (129)

Investing activities	(478)	746	(1,224)

Financing activities	196	165	31

Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(3)	(6)	3

Cash, cash equivalents, and restricted cash, end of period	$ 268	$ 1,607	$ (1,339)

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $129 million to $299 million for the three months ended March 31, 2021, compared to $428 million for the same period in 2020.

Cash from operations before changes in working capital decreased $162 million. The decrease was primarily due to the deferral of gas costs at NMGC resulting from the February 2021 extreme cold weather event, higher under-recovery of clause related costs at Tampa Electric and the sale of Emera Maine in Q1 2020. This was partially offset by increased marketing and trading margin at Emera Energy.

Changes in working capital increased operating cash flows by $33 million due to favourable changes in cash collateral positions on derivative instruments at NSPI and Emera Energy. These were partially offset by the timing of accounts payable payments at Tampa Electric and NSPI and unfavourable changes in accounts receivable at NMGC.

Cash Flow from Investing Activities

Net cash used in investing activities increased $1,224 million to $478 million for the three months ended March 31, 2021, compared to cash provided by investing activities of $746 million for the same period in 2020. The increase was due to the proceeds of $1.4 billion received on the sale of Emera Maine in 2020, partially offset by lower capital expenditures in 2021.

Capital expenditures for the three months ended March 31, 2021, including AFUDC, were $491 million compared to $663 million for the same period in 2020. Details of the 2021 capital spend by segment are shown below:

●

$244 million - Florida Electric Utility (2020 – $356 million);

●

$73 million - Canadian Electric Utilities (2020 – $93 million);

●

$26 million - Other Electric Utilities (2020 – $46 million);

●

$146 million - Gas Utilities and Infrastructure (2020 – $167 million); and

●

$2 million - Other (2020 – $1 million).

Cash Flow from Financing Activities

Net cash provided by financing activities increased $31 million to $196 million for the three months ended March 31, 2021, compared to $165 million for the same period in 2020. The increase was due to net proceeds from the issuance of long-term debt at Tampa Electric and NMGC in 2021 and repayment of long-term debt at TECO Finance in 2020. This was partially offset by higher net repayments of committed credit facilities at Tampa Electric and TECO Finance.

Contractual Obligations

As at March 31, 2021, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:


millions of Canadian dollars	2021	2022	2023	2024	2025	Thereafter	Total

Long-term debt principal	$ 1,440	$ 520	$ 801	$ 784	$ 227	$ 11,069	$ 14,841

Interest payment obligations (1)	579	581	560	546	527	6,937	9,730

Transportation (2)	417	406	341	303	276	2,672	4,415

Purchased power (3)	222	215	218	229	235	2,136	3,255

Capital projects	442	113	72	-	-	-	627

Fuel, gas supply and storage	394	98	5	1	-	-	498

Asset retirement obligations	15	2	7	2	2	390	418

Pension and post-retirement obligations (4)	23	37	32	33	32	186	343

Long-term service agreements (5)	34	40	35	33	33	102	277

Equity investment commitments (6)	-	240	-	-	-	-	240

Leases and other (7)	12	17	16	15	8	118	186

Demand side management	30	45	-	-	-	-	75

Long-term payable	4	5	5	-	-	-	14

Convertible debentures	-	-	-	-	-	1	1

	$ 3,612	$ 2,319	$ 2,092	$ 1,946	$ 1,340	$ 23,611	$ 34,920

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2021, including any expected required payment under associated swap agreements.

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $146 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(3) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(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) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(6) Emera has a commitment to make equity contributions to the LIL.

(7) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.

NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls, which is anticipated to take place in the second half of 2021. The UARB approved assessment for 2021 is approximately $172 million subject to a holdback of $10 million and potential long-term deferral of up to $23 million in depreciation expense dependent upon the timing of commencement of the NS Block. NSPML anticipates making an application with the UARB in 2021 to set rates for recovery of Maritime Link costs in 2022.

NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include $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 38-year commitment period are dependent on regulatory filings with the UARB.

Once Muskrat Falls and LIL have achieved full power, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties relating to the Maritime Link and LIL.

Emera has committed to obtain certain transmission rights for Nalcor Energy, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador 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, the obligations are included 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 $3.4 billion committed syndicated bank lines of credit in either CAD or USD, per the table below.


millions of dollars	Maturity		Credit Facilities		Utilized		Undrawn and Available

Emera – Unsecured committed revolving credit facility	June 2024	$	900	$	267	$	633

TEC (in USD) – Unsecured committed revolving credit facility (1)	March 2023		800		11		789

NSPI – Unsecured committed revolving credit facility	October 2024		600		317		283

Emera – Unsecured non-revolving facility	December 2021		400		400		-

TECO Finance (in USD) – Unsecured committed revolving credit facility	March 2023		400		223		177

NMGC (in USD) – Unsecured committed revolving credit facility	March 2023		125		25		100

NMGC (in USD) - Unsecured non-revolving facility	September 2022		100		100		-

Other (in USD) – Unsecured committed revolving credit facilities	Various		35		24		11

(1) This facility is available for use by Tampa Electric and PGS. At March 31, 2021, this facility was used by Tampa Electric and PGS with $1 million USD and $10 million USD utilized, respectively.

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements as at March 31, 2021.

Recent significant financing activities for Emera and its subsidiaries are discussed below by segment:

Florida Electric Utility

On March 18, 2021, TEC completed an issuance of $800 million USD senior notes. The issuance included $400 million USD senior notes that bear interest at a rate of 2.40 per cent with a maturity date of March 15, 2031 and $400 million USD senior notes that bear interest at a rate of 3.45 per cent with a maturity date of March 15, 2051.

As a result of the $800 million USD senior notes issuance discussed above, on March 23, 2021, TEC repaid its $300 million USD non-revolving term loan. TEC also repaid its $150 million USD accounts receivable collateralized borrowing facility and the agreement subsequently matured and terminated on March 22, 2021.

Gas Utilities and Infrastructure

On March 25, 2021, NMGC entered into a $100 million USD unsecured, non-revolving credit facility with a maturity date of September 23, 2022. The credit facility contains customary representations and warranties, events of default, financial and other covenants and bears interest based on either the LIBOR, prime rate, or the federal funds rate, plus a margin. Proceeds from this issuance were used to pay for higher than normal gas costs as a result of the severe cold weather event in February 2021 (for more detail, refer to “Business Overview and Outlook – Gas Utilities and Infrastructure” section).

On February 5, 2021, NMGC completed an issuance of $220 million USD senior notes. The issuance included $70 million USD senior notes that bear interest at a rate of 2.26 per cent with a maturity date of February 5, 2031, $65 million USD senior notes that bear interest at a rate of 2.51 per cent and with a maturity date of February 5, 2036, and $85 million USD senior notes that bear interest at a rate of 3.34 per cent with a maturity date of February 5, 2051. Proceeds from this issuance were used to repay a $200 million USD note due in 2021, which was classified as long-term debt at December 31, 2020.

Preferred Share issuance

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2020 annual MD&A, with updates as noted below:

The Company has standby letters of credit and surety bonds in the amount of $69 million USD (December 31, 2020 - $55 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.

NSPI has issued guarantees in the amount of $23 million USD (December 31, 2020 - $18 million USD) on behalf of its subsidiary, NS Power Energy Marketing Incorporated (“NSPEMI”), to secure obligations under purchase agreements with third- party suppliers. The guarantees have terms of varying lengths and will be renewed as required.

TRANSACTIONS WITH RELATED PARTIES

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies are as follows:

●

Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the

Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $28 million for the three months ended March 31, 2021 (2020 - $28 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. For further details, refer to the “Business Overview and Outlook - Canadian Electric Utilities - ENL” and “Contractual Obligations” sections.

●

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 $7 million for the three months ended March 31, 2021 (2020 - $8 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2021 and at December 31, 2020.

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 2020 annual MD&A.

Hedging Items Recognized on the Balance Sheets

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


As at	March 31	December 31
millions of Canadian dollars	2021	2020
Derivative instrument assets (current and other assets)	$ 33	$ 1
Net derivative instrument assets (liabilities)	$ 33	$ 1

Hedging Impact Recognized in Net Income

The Company recognized losses related to the effective portion of hedging relationships under the following categories:


For the	Three months ended March 31
millions of Canadian dollars	2021	2020
Operating revenues – regulated	$ -	$ (1)
Effective net losses	$ -	$ (1)

The effectiveness losses reflected in the above table would be offset in net income by the hedged item realized in the period.

Regulatory Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:


As at	March 31	December 31
millions of Canadian dollars	2021	2020
Derivative instrument assets (current and other assets)	$ 25	$ 14
Regulatory assets (current and other assets)	52	65
Derivative instrument liabilities (current and long-term liabilities)	(52)	(62)
Regulatory liabilities (current and long-term liabilities)	(26)	(15)
Net (liability) asset	$ (1)	$ 2

Regulatory Impact Recognized in Net Income

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


For the	Three months ended March 31
millions of Canadian dollars	2021	2020
Regulated fuel for generation and purchased power (1)	$ 3	$ (5)
Net gains (losses)	$ 3	$ (5)

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

HFT Items Recognized on the Balance Sheets

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


As at		March 31	December 31
millions of Canadian dollars		2021	2020
Derivative instrument assets (current and other assets)	$	57	$ 68
Derivative instrument liabilities (current and long-term liabilities)		(228)	(275)
Net derivative instrument liability	$	(171)	$ (207)

HFT Items Recognized in Net Income

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


For the	Three months ended March 31
millions of Canadian dollars	2021	2020
Operating revenues – non-regulated	$ 133	$ 212
Non-regulated fuel for generation and purchased power	1	(4)
Net gains	$ 134	$ 208

Other Derivatives Recognized on the Balance Sheets

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


As at	March 31	December 31
millions of Canadian dollars	2021	2020
Derivative instrument assets (current and other assets)	$ 18	$ 15
Derivative instrument liabilities (current and long-term liabilities)	-	(1)
Net derivative instrument assets	$ 18	$ 14

Other Derivatives Recognized in Net Income

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


For the	Three months ended March 31
millions of Canadian dollars	2021	2020
OM&G	$ 5	$ (1)
Other income (expense)	1	(10)
Total gains (losses)	$ 6	$ (11)

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The Company’s internal control framework is based on the criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at March 31, 2021, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company’s ICFR during the quarter ended March 31, 2021 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, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected 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 assumptions and concluded that no material adjustments were required for the three months ended March 31, 2021.

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, timing and effectiveness of vaccinations, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these estimates.

Goodwill Impairment Assessments

Management considered whether the potential impacts of the COVID-19 pandemic on future earnings required testing for goodwill impairment in Q1 2021 and determined that it is more likely than not that the fair value of reporting units that include goodwill exceeded their respective carrying amounts as of March 31, 2021.

As of March 31, 2021, $5.6 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, and the results of the qualitative assessment performed in Q4 2020, management does not expect the COVID-19 pandemic to have an impact on the goodwill associated with these reporting units.

As of March 31, 2021, $67 million of Emera’s goodwill was related to GBPC. In Q4 2020, the Company performed a quantitative impairment assessment for GBPC as this reporting unit is more sensitive to changes in forecasted future earnings due to limited excess of fair value over the carrying value. As part of the assessment management considered potential impacts of the COVID-19 pandemic on the future earnings of the reporting unit. Adverse changes in significant assumptions could result in a future impairment. No adverse changes in significant assumptions were identified in Q1 2021 and no impairment has been recorded for the three months ended March 31, 2021 associated with this goodwill.

Long-Lived Assets Impairment Assessments

Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at March 31, 2021, there are no indications of impairment of Emera’s long-lived assets. Impacts from 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 $22 million ($23 million after tax) were recognized on certain assets for the three months ended March 31, 2021 and three months ended March 31, 2020, respectively.

Receivables and Allowance for Credit Losses

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. The economic impact of COVID-19, in the service territories where Emera operates, has impacted the aging of customer receivables resulting in higher allowances for credit losses related to customer receivables however it has not had a material impact on earnings.

Pension and Other Post-Retirement Employee Benefits

The COVID-19 pandemic could impact key actuarial assumptions used to account for employee post-retirement benefits as a result of changes in the market. These changes could impact assumptions 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.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2021, are described as follows:

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity

The Company adopted Accounting Standard Update (“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) effective January 1, 2021 using the modified retrospective approach. The standard simplifies the accounting 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. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.

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 2020 audited consolidated financial statements, with updates noted below.

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.

SUMMARY OF QUARTERLY RESULTS

For the quarter ended


millions of dollars		Q1		Q4		Q3		Q2		Q1		Q4		Q3	Q2
(except per share amounts)		2021		2020		2020		2020		2020		2019		2019	2019
Operating revenues	$	1,612	$	1,537	$	1,163	$	1,169	$	1,637	$	1,616	$	1,299	$ 1,378
Net income attributable to common shareholders		273		273		84		58		523		193		55	103
Adjusted net income attributable to common shareholders		243		188		166		118		193		145		122	130
Earnings per common share - basic		1.08		1.09		0.34		0.24		2.14		0.79		0.23	0.43
Earnings per common share - diluted		1.08		1.08		0.34		0.23		2.13		0.80		0.23	0.43
Adjusted earnings per common share - basic		0.96		0.75		0.67		0.48		0.79		0.60		0.51	0.54

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 and 2021, quarterly results include the impact of the COVID-19 pandemic commencing in March 2020. For further detail, refer to the “Business Overview and Outlook” section.

EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2021 and 2020

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)


For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2021		2020

Operating revenues
Regulated electric	$	1,102	$	1,194
Regulated gas		393		331
Non-regulated		117		112
Total operating revenues (note 6)		1,612		1,637

Operating expenses
Regulated fuel for generation and purchased power		395		410
Regulated cost of natural gas		157		109
Non-regulated fuel for generation and purchased power		(1)		4
Operating, maintenance and general		318		378
Provincial, state and municipal taxes		80		84
Depreciation and amortization		226		231
Impairment charges		-		22
Total operating expenses		1,175		1,238
Income from operations		437		399

Income from equity investments (note 8)		41		41
Other income, net (note 9)		20		585
Interest expense, net		157		184
Income before provision for income taxes		341		841

Income tax expense (note 10)		56		306
Net income		285		535

Non-controlling interest in subsidiaries		1		1
Preferred stock dividends		11		11
Net income attributable to common shareholders	$	273	$	523

Weighted average shares of common stock outstanding (in millions) (note 12)
Basic		253.5		244.7
Diluted		253.8		245.2

Earnings per common share (note 12)
Basic	$	1.08	$	2.14
Diluted	$	1.08	$	2.13

Dividends per common share declared	$	0.6375	$	0.6125

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

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)


For the	Three months ended March 31
millions of Canadian dollars	2021		2020
Net income	$	285	$	535
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment (1)		(111)		761
Unrealized gains (losses) on net investment hedges (2)(3)		16		(141)
Cash flow hedges
Net derivative gains (losses) (4)		24		(3)
Less: reclassification adjustment for gains included in income		-		1
Net effects of cash flow hedges		24		(2)
Net change in unrecognized pension and post-retirement benefit obligation		5		(5)
Other comprehensive income (loss) (5)		(66)		613
Comprehensive income		219		1,148
Comprehensive income attributable to non-controlling interest		1		2
Comprehensive Income of Emera Incorporated	$	218	$	1,146

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

1) Net of tax expense of nil (2020 - $13 million expense) for the three months ended March 31, 2021.

2) The Company has designated $1.2 billion US dollar (“USD”) denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations.

3) Net of tax expense of $3 million (2020 - $1 million recovery) for the three months ended March 31, 2021.

4) Net of tax expense of $8 million (2020 - nil) for the three months ended March 31, 2021.

5) Net of tax expense of $11 million (2020 - $12 million tax expense) for the three months ended March 31, 2021.

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)


As at millions of Canadian dollars	March 31 2021		December 31 2020
Assets
Current assets
Cash and cash equivalents	$	234	$	220
Restricted cash (note 24)		34		34
Inventory		417		453
Derivative instruments (notes 14 and 15)		111		73
Regulatory assets (note 7)		126		165
Receivables and other current assets (note 17)		1,269		1,233
		2,191		2,178
Property, plant and equipment, net of accumulated depreciation and amortization of $8,798 and $8,714, respectively		19,579		19,535
Other assets
Deferred income taxes (note 10)		182		209
Derivative instruments (notes 14 and 15)		22		25
Regulatory assets (note 7)		1,586		1,419
Net investment in direct financing lease		469		475
Investments subject to significant influence (note 8)		1,356		1,346
Goodwill		5,649		5,720
Other long-term assets		337		327
		9,601		9,521
Total assets	$	31,371	$	31,234

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued


As at millions of Canadian dollars	March 31 2021		December 31 2020
Liabilities and Equity
Current liabilities
Short-term debt (note 19)	$	742	$	1,625
Current portion of long-term debt (note 20)		1,394		1,382
Accounts payable		1,018		1,148
Derivative instruments (notes 14 and 15)		189		251
Regulatory liabilities (note 7)		128		129
Other current liabilities		418		340
		3,889		4,875
Long-term liabilities
Long-term debt (note 20)		13,334		12,339
Deferred income taxes (note 10)		1,656		1,629
Derivative instruments (notes 14 and 15)		91		87
Regulatory liabilities (note 7)		1,792		1,832
Pension and post-retirement liabilities (note 18)		435		453
Other long-term liabilities		778		781
		18,086		17,121
Equity
Common stock (note 11)		6,816		6,705
Cumulative preferred stock (note 22)		1,004		1,004
Contributed surplus		79		79
Accumulated other comprehensive loss (note 13)		(145)		(79)
Retained earnings		1,608		1,495
Total Emera Incorporated equity		9,362		9,204
Non-controlling interest in subsidiaries		34		34
Total equity		9,396		9,238
Total liabilities and equity	$	31,371	$	31,234

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

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)


For the	Three months ended March 31
millions of Canadian dollars	2021		2020
Operating activities
Net income	$	285	$	535
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		230		235
Income from equity investments, net of dividends		(20)		(19)
Allowance for equity funds used during construction		(14)		(9)
Deferred income taxes, net		46		352
Net change in pension and post-retirement liabilities		(5)		(6)
Regulated fuel adjustment mechanism		(19)		(3)
Net change in fair value of derivative instruments		(42)		(95)
Net change in regulatory assets and liabilities		(128)		15
Net change in capitalized transportation capacity		(10)		62
Impairment charges		-		22
Gain on sale, excluding transaction costs		-		(604)
Other operating activities, net		17		17
Changes in non-cash working capital (note 23)		(41)		(74)
Net cash provided by operating activities		299		428
Investing activities
Proceeds from dispositions		-		1,403
Additions to property, plant and equipment		(477)		(654)
Other investing activities		(1)		(3)
Net cash (used in) provided by investing activities		(478)		746
Financing activities
Change in short-term debt, net		(490)		156
Proceeds from short-term debt with maturities greater than 90 days		-		399
Repayment of short-term debt with maturities greater than 90 days		(377)		-
Proceeds from long-term debt, net of issuance costs		1,416		57
Retirement of long-term debt		(263)		(436)
Net (repayments) borrowings under committed credit facilities		(27)		29
Issuance of common stock, net of issuance costs		56		77
Dividends on common stock		(107)		(104)
Dividends on preferred stock		(11)		(11)
Other financing activities		(1)		(2)
Net cash provided by financing activities		196		165
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(3)		(6)
Net increase in cash, cash equivalents, and restricted cash		14		1,333
Cash, cash equivalents, and restricted cash, beginning of period		254		274
Cash, cash equivalents, and restricted cash, end of period	$	268	$	1,607
Cash, cash equivalents, and restricted cash consists of:
Cash	$	234	$	1,553
Restricted cash		34		54
Cash, cash equivalents, and restricted cash	$	268	$	1,607

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

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss) (“AOCI”)		Retained Earnings		Non- Controlling Interest		Total Equity
For the three months ended March 31, 2021
Balance, December 31, 2020	$	6,705	$	1,004	$	79	$	(79)	$	1,495	$	34	$	9,238
Net income of Emera Incorporated		-		-		-		-		284		1		285
Other comprehensive income (loss), net of tax expense of $11 million		-		-		-		(66)		-		-		(66)
Dividends declared on preferred stock (1)		-		-		-		-		(11)		-		(11)
Dividends declared on common stock ($0.6375/share)		-		-		-		-		(160)		-		(160)
Common stock issued under purchase plan		59		-		-		-		-		-		59
Issuance of common stock, net of after-tax issuance costs		50		-		-		-		-		-		50
Senior management stock options exercised		1		-		-		-		-		-		1
Other		1		-		-		-		-		(1)		-
Balance, March 31, 2021	$	6,816	$	1,004	$	79	$	(145)	$	1,608	$	34	$	9,396

For the three months ended March 31, 2020
Balance, December 31, 2019	$	6,216	$	1,004	$	78	$	95	$	1,173	$	35	$	8,601
Net income of Emera Incorporated		-		-		-		-		534		1		535
Other comprehensive income (loss), net of tax expense of $12 million		-		-		-		612		-		1		613
Dividends declared on preferred stock (2)		-		-		-		-		(11)		-		(11)
Dividends declared on common stock ($0.6125/share)		-		-		-		-		(149)		-		(149)
Common stock issued under purchase plan		48		-		-		-		-		-		48
Issuance of common stock, net of after-tax issuance costs		58		-		-		-		-		-		58
Senior management stock option exercised		17		-		(1)		-		-		-		16
Adoption of credit losses accounting standard		-		-		-		-		(7)		-		(7)
Other		1		-		1		-		-		(1)		1
Balance, March 31, 2020	$	6,340	$	1,004	$	78	$	707	$	1,540	$	36	$	9,705

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

(1) Series A; $0.1364/share, Series B; $0.1223/share, Series C; $0.29506/share, Series E; $0.28125/share, Series F; $0.26263/share and Series H; $0.30625/share

(2) Series A; $0.1597/share, Series B; $0.2190/share, Series C; $0.29506/share, Series E; $0.28125/share, Series F; $0.265625/share and Series H; $.30625/share

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at March 31, 2021 and 2020

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

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

At March 31, 2021, 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 44.4 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 toward final commissioning the LIL. In response to the COVID-19 pandemic, on March 17, 2020 Nalcor announced it had paused construction activities at the Muskrat Falls site and 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 final project commissioning of Muskrat Falls and LIL 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.

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, that transports natural gas throughout markets in Atlantic Canada and the northeastern United States.

Emera’s other reportable segment includes investments in energy-related non-regulated companies which includes:

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 30 MW biomass co-generation electricity facility 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 Technologies LLC, a wholly owned technology company focused on finding ways to deliver renewables and resilient energy to customers;

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

other investments.

In 2020, the outbreak of the novel strain of coronavirus, specifically identified as COVID-19, resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of COVID-19 in the Company’s estimates and results, the financial statements for three months ended March 31, 2021 and 2020 were not materially impacted by COVID-19. However, it is not possible to reliably estimate the length and severity of the COVID-19 pandemic and the impact on the financial results and condition of the Company in future periods.

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, 2020, 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, 2021.

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

Use of Management Estimates

During the three months ended March 31, 2021, 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 primarily due to a change in the mix of sales across 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. Emera’s utilities provide essential services and continue to operate and meet customer demand. Governments world-wide have implemented measures intended to address the pandemic. These measures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial spaces and industrial facilities, shutdowns, shelter-in-place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility and 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 assumptions and concluded that no material adjustments were required for the three months ended March 31, 2021.

Goodwill Impairment Assessments

Long-Lived Assets Impairment Assessments

Impairment charges of nil and $22 million ($23 million after tax) were recognized on certain assets for the three months ended March 31, 2021 and three months ended March 31, 2020, respectively.

Receivables and Allowance for Credit Losses

Pension and Other Post-Retirement Employee Benefits

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 during 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. Quarterly results include the impact of the COVID-19 pandemic which began in March 2020.

2. CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2021, are described as follows:

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity

3. FUTURE ACCOUNTING PRONOUNCEMENTS

Guaranteed Debt Securities Disclosure Requirements

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. In Q1 2020, a gain on disposition of $586 million ($321 million after tax) net of transaction costs, was recognized in the Other segment and included in “Other income” on the Condensed Consolidated Statements of Income.

5. SEGMENT INFORMATION

Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. Emera’s five reportable segments are Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.


millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations			Total
For the three months ended March 31, 2021
Operating revenues from external customers (1)	$	565	$	443	$	94	$	397	$	113	$	-		$	1,612
Inter-segment revenues (1)		1		-		-		2		-		(3)			-
Total operating revenues		566		443		94		399		113		(3)			1,612
Regulated fuel for generation and purchased power		163		193		41		-		-		(2)			395

Regulated cost of natural gas		-		-		-		157		-		-			157
Depreciation and amortization		118		61		15		30		2		-			226
Interest expense, net		36		35		5		12		69		-			157
Internally allocated interest (2)		-		-		-		3		(3)		-			-
Operating, maintenance and general (“OM&G”)		117		78		25		81		21		(4)			318
Income tax expense (recovery)		14		6		-		25		11		-			56
Net income attributable to common shareholders		83		88		7		80		15		-			273
As at March 31, 2021
Total assets		16,832		6,837		1,360		6,261		1,178		(1,097)	⁽³⁾		31,371
For the three months ended March 31, 2020
Operating revenues from external customers (1)		565		458		171		334		109		-			1,637
Inter-segment revenues (1)		2		-		-		3		4		(9)			-
Total operating revenues		567		458		171		337		113		(9)			1,637
Regulated fuel for generation and purchased power		142		204		67		-		-		(3)			410
Regulated cost of natural gas		-		-		-		109		-		-			109
Depreciation and amortization		116		58		28		27		2		-			231
Interest expense, net		40		35		13		15		82		(1)			184
Internally allocated interest (2)		-		-		-		3		(3)		-			-
OM&G		138		79		47		84		35		(5)			378
Gain on sale, net of transaction costs		-		-		-		-		586		-			586
Impairment charges		-		-		-		-		22		-			22
Income tax expense (recovery)		14		8		(8)		22		270		-			306
Net income attributable to common shareholders		79		92		17		70		265		-			523
As at December 31, 2020
Total assets		16,889		6,752		1,365		6,067		1,234		(1,073)	⁽³⁾		31,234

(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.

6. REVENUE

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


millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total
For the three months ended March 31, 2021
Regulated
Electric Revenue:
Residential	$	294	$	259	$	35	$	-	$	-	$	-	$	588
Commercial		159		114		47		-		-		-		320
Industrial		47		56		7		-		-		-		110
Other electric and regulatory deferrals		61		7		2		-		-		-		70
Other (1)		5		7		3		-		-		(1)		14
Regulated electric revenue		566		443		94		-		-		(1)		1,102
Gas Revenue:
Residential		-		-		-		218		-		-		218
Commercial		-		-		-		114		-		-		114
Industrial		-		-		-		16		-		(1)		15
Finance income (2)(3)		-		-		-		14		-		-		14
Other		-		-		-		33		-		(1)		32
Regulated gas revenue		-		-		-		395		-		(2)		393
Non-Regulated:
Marketing and trading margin (4)		-		-		-		-		67		-		67
Energy sales		-		-		-		-		6		(5)		1
Capacity		-		-		-		-		-		-		-
Other		-		-		-		4		2		-		6
Mark-to-market (3)		-		-		-		-		38		5		43
Non-regulated revenue		-		-		-		4		113		-		117
Total operating revenues	$	566	$	443	$	94	$	399	$	113	$	(3)	$	1,612

(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.


millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total
For the three months ended March 31, 2020
Regulated:
Electric Revenue:
Residential	$	275	$	264	$	61	$	-	$	-	$	-	$	600
Commercial		168		120		80		-		-		-		368
Industrial		50		56		12		-		-		-		118
Other electric and regulatory deferrals		68		11		3		-		-		-		82
Other (1)		6		7		15		-		-		(2)		26
Regulated electric revenue		567		458		171		-		-		(2)		1,194
Gas Revenue:
Residential		-		-		-		168		-		-		168
Commercial		-		-		-		91		-		-		91
Industrial		-		-		-		13		-		-		13
Finance income (2)(3)		-		-		-		15		-		-		15
Other		-		-		-		47		-		(3)		44
Regulated gas revenue		-		-		-		334		-		(3)		331
Non-Regulated:
Marketing and trading margin (4)		-		-		-		-		41		-		41
Energy sales		-		-		-		-		4		(4)		-
Capacity		-		-		-		-		-		-		-
Other		-		-		-		3		5		-		8
Mark-to-market (3)		-		-		-		-		63		-		63
Non-regulated revenue		-		-		-		3		113		(4)		112
Total operating revenues	$	567	$	458	$	171	$	337	$	113	$	(9)	$	1,637

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.

Remaining Performance Obligations

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of March 31, 2021, the aggregate amount of the transaction price allocated to remaining performance obligations was $447 million (2020 – $368 million). This amount includes $146 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040. 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 2040.

7. 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 7 in Emera’s 2020 annual audited consolidated financial statements.


As at mil lions of Canadian dollars	March 31 2021		December 31 2020
Regulatory assets
Deferred income tax regulatory assets	$	921	$	887
Pension and post-retirement medical plan		381		394
NMGC winter event gas cost recovery		139		-
Deferrals related to derivative instruments		52		65
Cost recovery clauses		40		49
Storm restoration regulatory asset		38		41
Environmental remediations		29		28
Stranded cost recovery		26		26
Demand side management (“DSM”) deferral		14		15
Unamortized defeasance costs		11		13
Other		61		66
	$	1,712	$	1,584
Current	$	126	$	165
Long-term		1,586		1,419
Total regulatory assets	$	1,712	$	1,584

Regulatory liabilities
Deferred income tax regulatory liabilities	$	922	$	933
Accumulated reserve - cost of removal		849		865
Storm reserve		61		62
Self-insurance fund (note 24)		28		28
Cost recovery clauses		26		31
Deferrals related to derivative instruments		26		15
Regulated fuel adjustment mechanism		2		21
Other		6		6
	$	1,920	$	1,961
Current	$	128	$	129
Long-term		1,792		1,832
Total regulatory liabilities	$	1,920	$	1,961

Tampa Electric

NMGC

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $110 million USD for gas costs above what normally would have been paid during this period. NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause. On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge. The filing proposes to recover the $110 million USD over a period of 30 months beginning July 1, 2021. A decision is expected by the end of Q2 2021.

GBPC

In Q1 2021, GBPC notified the GBPA of its intention to submit a Rate Plan proposal in 2021.

8. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME


					Equity Income				Percentage
	Carrying Value as at				For the three months ended				of
	March 31		December 31		March 31				Ownership
millions of Canadian dollars	2021		2020		2021		2020		2021
LIL (1)	$	642	$	629	$	13	$	12		44.4
NSPML		548		547		13		15		100.0
M&NP (2)		124		129		5		5		12.9
Lucelec (2)		42		41		1		1		19.5
Bear Swamp (3)		-		-		9		8		50.0
	$	1,356	$	1,346	$	41	$	41

(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 $108 million (2020 – $118 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 millions of Canadian dollars	March 31 2021		December 31 2020
Balance Sheet
Current assets	$	69	$	57
Property, plant and equipment		1,621		1,629
Regulatory assets		228		210
Non-current assets		31		32
Total assets	$	1,949	$	1,928
Current liabilities	$	70	$	56
Long-term debt		1,228		1,228
Non-current liabilities		103		97
Equity		548		547
Total liabilities and equity	$	1,949	$	1,928

9. OTHER INCOME, NET


For the	Three months ended March 31
millions of Canadian dollars	2021		2020
Allowance for equity funds used during construction	$	14	$	9
Gain on sale, net of transaction costs (1)		-		586
Other		6		(10)
	$	20	$	585

(1) For further details related to the gain on sale of Emera Maine, refer to note 4.

10. INCOME TAXES

The income tax provision differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:


For the	Three months ended March 31
millions of Canadian dollars	2021		2020
Income before provision for income taxes	$	341	$	841
Statutory income tax rate		29.0%		29.5%
Income taxes, at statutory income tax rate		99		248
Additional impact from the sale of Emera Maine		-		92
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(20)		(21)
Foreign tax rate variance		(10)		(9)
Amortization of deferred income tax regulatory liabilities		(5)		(16)
Tax effect of equity earnings		(4)		(5)
Revaluation of deferred income taxes due to change in Nova Scotia tax rate		-		12
Other		(4)		5
Income tax expense	$	56	$	306
Effective income tax rate		16%		36%

The decrease in the effective income tax rate was primarily due to the sale of Emera Maine in Q1 2020 and decreased income before provision for income taxes.

11. COMMON STOCK

Authorized: Unlimited number of non-par value common shares.


Issued and outstanding:	millions of shares		millions of Canadian dollars
Balance, December 31, 2020		251.43	$	6,705
Issuance of common stock (1)		0.94		50
Issued for cash under Purchase Plans at market rate		1.18		60
Discount on shares purchased under Dividend Reinvestment Plan		-		(1	)
Options exercised under senior management share option plan		0.01		1
Employee Share Purchase Plan		-		1
Balance, March 31, 2021		253.56	$	6,816

(1) In Q1 2021, 940,100 common shares were issued under Emera’s ATM program at an average price of $53.57 per share for gross proceeds of $50 million ($50 million net of issuance costs). As at March 31, 2021, an aggregate gross sales limit of $195 million remains available for issuance under the ATM program.

12. EARNINGS PER SHARE

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


For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2021		2020
Numerator
Net income attributable to common shareholders	$	273.3	$	523.1
Diluted numerator		273.3		523.1
Denominator
Weighted average shares of common stock outstanding		252.2		243.4
Weighted average deferred share units outstanding		1.3		1.3
Weighted average shares of common stock outstanding – basic		253.5		244.7
Stock-based compensation		0.3		0.5
Weighted average shares of common stock outstanding – diluted		253.8		245.2
Earnings per common share
Basic	$	1.08	$	2.14
Diluted	$	1.08	$	2.13

13. 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 three months ended March 31, 2021
Balance, January 1, 2021	$	52	$	30		$	1	$	(1)		$	(161)		$	(79)
Other comprehensive income (loss) before reclassifications		(111)		16			24		-			-			(71)
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-			-		-			5			5
Net current period other comprehensive income (loss)		(111)		16			24		-			5			(66)
Balance, March 31, 2021	$	(59)	$	46		$	25	$	(1)		$	(156)		$	(145)

For the three months ended March 31, 2020
Balance, January 1, 2020	$	253	$	4		$	(1)	$	(1)		$	(160)		$	95
Other comprehensive income (loss) before reclassifications		760		(141)			(3)		-			-			616
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-			1		-			(5)			(4)
Net current period other comprehensive income (loss)		760		(141)			(2)		-			(5)			612
Balance, March 31, 2020	$	1,013	$	(137	)	$	(3)	$	(1	)	$	(165	)	$	707

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


For the		Three months ended March 31
millions of Canadian dollars		2021		2020
	Affected line item in the Condensed Consolidated Financial Statements	Amounts reclassified from AOCI
Losses on derivatives recognized as cash flow hedges
Foreign exchange forwards	Operating revenue - regulated	$	-	$	1
Total		$	-	$	1
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses	Other income, net	$	4	$	3
Amounts reclassified into obligations	Pension and post-retirement benefits		1		(8)
Total			5		(5)
Total reclassifications out of AOCI for the period		$	5	$	(4)

14. 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:

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.

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.

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.

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.

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


	Derivative Assets				Derivative Liabilities
As at millions of Canadian dollars	March 31 2021		December 31 2020		March 31 2021		December 31 2020
Cash flow hedges
Interest rate hedge	$	33	$	1	$	-	$	-
		33		1		-		-
Regulatory deferral
Commodity swaps and forwards
Coal purchases		2		1		3		6
Power purchases		13		10		30		34
Natural gas purchases and sales		5		4		3		2
Heavy fuel oil purchases		7		1		-		5
Foreign exchange forwards		1		-		19		17
		28		16		55		64
HFT derivatives
Power swaps and physical contracts		9		13		9		13
Natural gas swaps, futures, forwards, physical contracts		140		139		311		346
		149		152		320		359
Other derivatives
Equity derivatives		5		-		-		1
Foreign exchange forwards		13		15		-		-
		18		15		-		1
Total gross current derivatives		228		184		375		424
Impact of master netting agreements with intent to settle net or simultaneously		(95)		(86)		(95)		(86)
		133		98		280		338
Current		111		73		189		251
Long-term		22		25		91		87
Total derivatives	$	133	$	98	$	280	$	338

Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Details of master netting agreements, shown net on the Condensed Consolidated Balance Sheets, are summarized in the following table:


	Derivative Assets		Derivative Liabilities
As at	March 31	December 31	March 31	December 31
millions of Canadian dollars	2021	2020	2021	2020
Regulatory deferral	$ 3	$ 2	$ 3	$ 2
HFT derivatives	92	84	92	84
Total impact of master netting agreements with intent to settle net or simultaneously	$ 95	$ 86	$ 95	$ 86

Cash Flow Hedges

As at March 31, 2021 the Company had a treasury lock in place to hedge the interest rate risk associated with the refinancing of long-term debt due in June 2021.

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


For the	Three months ended March 31
millions of Canadian dollars	2021		2020
	Foreign exchange forwards
Realized gain (loss) in operating revenue – regulated	$	-	$ (1)
Total gains (losses) in net income	$	-	$ (1)

As at	March 31		December 31
millions of Canadian dollars	2021		2020
	Interest		Interest
	rate hedge		rate hedge
Total unrealized gain (loss) in AOCI – effective portion, net of tax	$	25	$ 1

The Company expects $25 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

As at March 31, 2021, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:


millions		2021
U.S. Treasury lock (USD)		$ 350

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 March 31
millions of Canadian dollars	2021			2020
	Commodity swaps and forwards	Foreign exchange forwards	Commodity swaps and forwards	Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$ 5	$ (2)	$ (74)	$ 6
Unrealized gain (loss) in regulatory liabilities	17	(2)	(10)	35
Realized (gain) loss in regulatory liabilities	(2)	-	7	-
Realized (gain) loss in inventory (1)	6	2	-	(1)
Realized (gain) loss in regulated fuel for generation and purchased power (2)	(4)	1	6	(1)
Total change in derivative instruments	$ 22	$ (1)	$ (71)	$ 39

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable.

Commodity Swaps and Forwards

As at March 31, 2021, 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:


millions	2021 Purchases	2022-2023 Purchases
Natural Gas (Mmbtu)	9	7
Power (MWh)	2	1
Heavy fuel oil (bbls)	-	1
Coal (metric tonnes)	-	1

Foreign Exchange Swaps and Forwards

As at March 31, 2021, 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:


	2021	2022-2023
Foreign exchange contracts (millions of US dollars)	$ 152	$ 172
Weighted average rate	1.3133	1.3129
% of USD requirements	77%	48%

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.

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


For the	Three months ended March 31
millions of Canadian dollars	2021		2020
Power swaps and physical contracts in non-regulated operating revenues	$	1	$ 1
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		132	211
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		1	(4)
	$	134	$ 208

As at March 31, 2021, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:


millions	2021		2022		2023		2024		2025
Natural gas purchases (Mmbtu)		349		85		51		27	26
Natural gas sales (Mmbtu)		341		78		26		6	2
Power purchases (MWh)		1		-		-		-	-
Power sales (MWh)		1		-		-		-	-

Other Derivatives

As at March 31, 2021, 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 2021. The foreign exchange forwards have a combined notional amount of $75 million USD and expire in 2021.

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


For the	Three months ended March 31
millions of Canadian dollars			2021				2020
	Foreign Exchange Forwards		Equity Derivatives		Foreign Exchange Forwards		Equity Derivatives
Unrealized gain (loss) in OM&G	$	-	$	5	$	-	$	(1)
Unrealized gain (loss) in other income (expense)		(3)		-		(9)		-
Realized gain (loss) in other income (expense)		4		-		(1)		-
Total gains (losses) in net income	$	1	$	5	$	(10)	$	(1)

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 internally assesses credit risk 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, North American Energy Standards Board agreements and, or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

As at March 31, 2021, the Company had $126 million (December 31, 2020 - $123 million) in financial assets considered to be past due, which had been outstanding for an average 68 days. The fair value of these financial assets was $104 million (December 31, 2020 - $101 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:

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at March 31, 2021, the total fair value of derivatives in a liability position, was $280 million (December 31, 2020 – $338 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.

15. 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 14), 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.

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


As at	March 31, 2021
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Assets
Interest rate swap	$	-	$	33	$	-	$ 33
		-		33		-	33
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		1		-	1
Power purchases		12		-		-	12
Natural gas purchases and sales		2		2		-	4
Heavy fuel oil purchases		-		7		-	7
Foreign exchange forwards		-		1		-	1
		14		11		-	25
HFT derivatives
Power swaps and physical contracts		3		3		1	7
Natural gas swaps, futures, forwards, physical contracts and related transportation		-		38		12	50
		3		41		13	57
Other derivatives
Foreign exchange forwards		-		13		-	13
Equity derivatives		5		-		-	5
		5		13		-	18
Total assets		22		98		13	133
Liabilities
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		3		-	3
Power purchases		29		-		-	29
Natural gas purchases and sales		-		1		-	1
Foreign exchange forwards		-		19		-	19
		29		23		-	52
HFT derivatives
Power swaps and physical contracts		3		3		1	7
Natural gas swaps, futures, forwards and physical contracts		-		(4)		225	221
		3		(1)		226	228
Total liabilities		32		22		226	280
Net assets (liabilities)	$	(10)	$	76	$	(213)	$ (147)


As at	December 31, 2020
millions of Canadian dollars	Level 1	Level 2		Level 3		Total
Assets
Cash flow hedges
Interest rate hedge	$ 1	$	-	$	-	$ 1
	1		-		-	1
Regulatory deferral
Commodity swaps and forwards
Power purchases	9		-		-	9
Natural gas purchases and sales	2		1		-	3
Heavy fuel oil purchases	-		2		-	2
	11		3		-	14
HFT derivatives
Power swaps and physical contracts	3		2		2	7
Natural gas swaps, futures, forwards, physical contracts and related transportation	1		48		12	61
	4		50		14	68
Other derivatives
Foreign exchange forwards	-		15		-	15
	-		15		-	15
Total assets	16		68		14	98
Liabilities
Regulatory deferral
Commodity swaps and forwards
Coal purchases	-		4		-	4
Power purchases	33		-		-	33
Heavy fuel oil purchases	3		3		-	6
Natural gas purchases and sales	-		2		-	2
Foreign exchange forwards	-		17		-	17
	36		26		-	62
HFT derivatives
Power swaps and physical contracts	4		2		1	7
Natural gas swaps, futures, forwards and physical contracts	1		10		257	268
	5		12		258	275
Other derivatives
Equity derivatives	1		-		-	1
	1		-		-	1
Total liabilities	42		38		258	338
Net assets (liabilities)	$ (26)	$	30	$	(244)	$ (240)

The change in the fair value of the Level 3 financial assets for the three months ended March 31, 2021 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power			Natural gas		Total
Balance, beginning of period	$	2		$	12	$ 14
Total realized and unrealized gains included in non-regulated operating revenues		(1	)		-	(1)
Balance, March 31, 2021	$	1		$	12	$ 13

The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 2021 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power		Natural gas		Total
Balance, beginning of period	$	1	$	257	$ 258
Total realized and unrealized gains included in non-regulated operating revenues		-		(32)	(32)
Balance, March 31, 2021	$	1	$	225	$ 226

Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.

The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:


As at	March 31, 2021
millions of Canadian dollars	Fair Value			Valuation Technique		Unobservable Input	Range	Weighted average (1)
Assets
HFT derivatives – Power swaps	$	1			Modelled pricing	Third-party pricing	$20.40 - $73.10	$31.29
and physical contracts						Probability of default	0.02% - 11.29%	1.22%
						Discount rate	0.01% - 1.21%	0.25%
HFT derivatives –		17			Modelled pricing	Third-party pricing	$1.67 - $4.82	$2.51
Natural gas swaps, futures,						Probability of default	0.03% - 3.90%	0.39%
forwards and physical contracts						Discount rate	0.00% - 17.76%	1.19%
		(5	)		Modelled pricing	Third-party pricing	$1.75 - $8.67	$3.17
						Basis adjustment	$0.00 - $0.65	$0.36
						Probability of default	0.03% - 7.24%	1.52%
						Discount rate	0.00% - 1.04%	0.27%
Total assets	$	13
Liabilities
		1			Modelled pricing	Third-party pricing	$40.40 - $72.20	$63.16
						Own credit risk	100% - 100%	100%
						Discount rate	0.03% - 0.10%	0.04%
						Correlation factor	0.15% - 0.50%	0.27%
HFT derivatives –		202			Modelled pricing	Third-party pricing	$1.33 - $8.44	$3.88
Natural gas swaps, futures,						Own credit risk	0.03% - 4.03%	0.12%
forwards and physical contracts						Discount rate	0.00% - 15.54%	0.98%
		23			Modelled pricing	Third-party pricing	$1.20 - $9.09	$4.46
						Basis adjustment	$0.00 - $1.42	$0.88
						Own credit risk	0.02% - 7.24%	0.15%
						Discount rate	0.00% - 1.04%	0.17%
Total liabilities	$	226
Net liabilities	$	(213	)

(1) Unobservable inputs were weighted by the relative fair value of the instruments

Long-term debt is a financial liability not measured at fair value on the Condensed Consolidated Balance Sheets. The balance consisted of the following:


As at millions of Canadian dollars	Carrying Amount		Fair Value		Level 1		Level 2		Level 3		Total
March 31, 2021	$	14,728	$	16,428	$	—	$	15,960	$	468	$	16,428
December 31, 2020	$	13,721	$	16,487	$	—	$	16,020	$	467	$	16,487

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 $16 million was recorded in Other Comprehensive Income for the three months ended March 31, 2021 (2020 – $141 million loss after-tax).

16. RELATED PARTY TRANSACTIONS

Significant transactions between Emera and its associated companies are as follows:

●

Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $28 million for the three months ended March 31, 2021 (2020 - $28 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.

●

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2021 and at December 31, 2020.

17. RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:


As at millions of Canadian dollars	March 31 2021		December 31 2020
Customer accounts receivable – billed	$	592	$	570
Customer accounts receivable – unbilled		294		286
Allowance for credit losses		(22)		(22)
Capitalized transportation capacity (1)		196		200
Income tax receivable		10		11
Prepaid expenses		80		50
Other		119		138
	$	1,269	$	1,233

(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.

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 21 in Emera’s 2020 annual audited consolidated financial statements. Refer to note 1 “Use of Management Estimates – Pension and Other Post-Retirement Employee Benefits”.

Emera’s net periodic benefit cost included the following:


For the	Three months ended March 31
millions of Canadian dollars	2021			2020
Defined benefit pension plans
Service cost	$	11		$	12
Non-service cost
Interest cost		17			22
Expected return on plan assets		(33	)		(37	)
Current year amortization of:
Actuarial losses		4			4
Regulatory asset		7			7
Total non-service costs		(5	)		(4	)
Total defined benefit pension plans		6			8
Non-pension benefits plan
Service cost		1			1
Non-service cost
Interest cost		2			3
Current year amortization of regulatory asset		1			—
Total non-service costs		3			3
Total non-pension benefits plans		4			4
Total defined benefit plans	$	10		$	12

Emera’s contributions related to these defined-benefit plans for the three months ended March 31, 2021 were $14 million (2020 - $16 million). Annual employer contributions to the defined benefit pension plans are estimated to be $41 million for 2021. Emera’s contributions related to these defined-contributions plans for the three months ended March 31, 2021 were $10 million (2020 - $11 million).

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 23 in Emera’s 2020 annual audited consolidated financial statements, and below for 2021 short-term debt financing activity.

Recent Significant Financing Activity by Segment

Florida Electric Utility

Using proceeds from the $800 million USD senior notes issuance (refer to note 20), on March 23, 2021, TEC repaid its $300 million USD non-revolving term loan. TEC also repaid its $150 million USD accounts receivable collateralized borrowing facility and the agreement subsequently matured and terminated on March 22, 2021.

20. LONG-TERM DEBT

For details regarding long-term debt, refer to note 25 in Emera’s 2020 annual audited consolidated financial statements, and below for 2021 long-term debt financing activity.

Recent Significant Financing Activity by Segment

Florida Electric Utility

Gas Utilities and Infrastructure

21. COMMITMENTS AND CONTINGENCIES

A.	Commitments

As at March 31, 2021, contractual commitments (excluding pensions and other post-retirement obligations, 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	2021		2022		2023		2024		2025		Thereafter		Total
Transportation (1)	$	417	$	406	$	341	$	303	$	276	$	2,672		4,415
Purchased power (2)		222		215		218		229		235		2,136	$	3,255
Capital projects		442		113		72		-		-		-		627
Fuel, gas supply and storage		394		98		5		1		-		-		498
Long-term service agreements (3)		34		40		35		33		33		102		277
Equity investment commitments (4)		-		240		-		-		-		-		240
Leases and other (5)		12		17		16		15		8		118		186
Demand side management		30		45		-		-		-		-		75
	$	1,551	$	1,174	$	687	$	581	$	552	$	5,028	$	9,573

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $146 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(3) 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.

(4) Emera has a commitment to make equity contributions to the LIL.

(5) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.

B.	Legal Proceedings

TECO Guatemala Holdings (“TGH”)

Prior to Emera’s acquisition of TECO Energy in 2016, TGH, a wholly owned subsidiary of TECO Energy, divested of its indirect investment in the Guatemala electricity sector, but retained certain claims against the Republic of Guatemala (“Guatemala”). In 2013, TGH asserted an arbitration claim against Guatemala with the International Centre for the Settlement of Investment Disputes (“ICSID”) under the Dominican Republic Central America – United States Free Trade Agreement. The arbitration concerned TGH’s allegation that Guatemala unfairly set the distribution tariff for a local distribution company which harmed TGH’s investment in that company. A tribunal established by the ICSID ruled in favour of TGH (the “First Award”) and in November 2020, Guatemala made a payment of approximately $38 million USD in full and final satisfaction of the First Award. For more information, refer to note 27 of Emera’s 2020 annual audited consolidated financial statements.

On September 23, 2016, TGH had filed a request for resubmission to arbitration seeking damages in addition to those awarded in the First Award. On May 13, 2020, an ICSID tribunal awarded TGH additional damages and costs against Guatemala of more than $35 million USD plus interest (the “Second Award”). TGH subsequently requested a reconsideration of the interest quantum awarded in connection with this Second Award. On October 16, 2020, the tribunal granted TGH’s request for additional interest. The additional amount is approximately $2 million USD. On February 12, 2021, Guatemala filed an application for annulment of the Second Award with ICSID. On March 31, 2021, ICSID constituted an ad hoc Committee to oversee the annulment proceeding. To date, the total of the Second Award, with interest, is approximately $59 million USD. Results to date do not reflect any benefit of the Second Award.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at March 31, 2021, TEC has estimated its financial liability to be $21 million ($17 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.

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 14 and note 15.

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 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 investments, 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.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s 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 investments, 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 could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed capital needs.

Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market disruptions 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 and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The 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 various market disruptions including those related to public health threats, such as the COVID-19 pandemic.

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. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these risks 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.

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital investments, 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 interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. Interest rates may be impacted by market disruptions related to public health threats, including the COVID-19 pandemic.

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

The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts and arrangements.

The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. The Company’s commercial arrangements, including the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments are all used to manage and mitigate this risk. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this risk.

Regulated Utilities

A large portion of the Company’s utility fuel supply comes from international suppliers and therefore 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 using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable.

The majority of Emera’s regulated utilities have adopted and implemented fuel adjustment mechanisms which has further helped manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs.

Emera Energy Marketing and Trading

Emera Energy has employed further measures to manage commodity risk. The majority of Emera’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets, in the event of an operational issue or counterparty default.

To measure commodity price risk exposure, Emera employs a number of controls and processes, including an estimated value-at-risk (“VaR”) analysis of its exposures. The VaR amount represents an estimate of the potential change in fair value that could occur from changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodities, primarily natural gas and power positions.

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 2020 audited annual consolidated financial statements.

22. CUMULATIVE PREFERRED STOCK

23. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


For the	Three months ended March 31
millions of Canadian dollars	2021		2020
Changes in non-cash working capital:
Inventory	$	32	$	60
Receivables and other current assets		(49)		(84)
Accounts payable		(98)		(168)
Other current liabilities		74		118
Total non-cash working capital	$	(41)	$	(74)

Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	53	$	45
Increase in accrued capital expenditures	$	26	$	23

24. VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of Maritime Link. Thus, Emera began recording Maritime Link as an equity investment.

BLPC has established a Self-Insurance Fund (“SIF”), primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as an “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.

The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

The following table provides information about Emera’s portion of material unconsolidated VIEs:

As at

March 31, 2021

December 31, 2020

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)

548

547

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 May 11, 2021, the date the financial statements were issued.

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

March 31, 2021.

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

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

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

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

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:

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

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

6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2021 and ended on March 31, 2021 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.


Date: May 11, 2021

“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

March 31, 2021.

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

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.

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

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:

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


Date: May 11, 2021

“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 three months ended March 31, 2021.

The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended March 31, 2021.

Twelve months ended

March 31, 2021

Earnings Coverage ⁽¹⁾

2.00

⁽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 $63 million for the twelve months ended March 31, 2021. Emera’s interest requirements for the twelve months ended March 31, 2021 amounted to $676 million. Emera’s consolidated income before interest and income tax for the twelve months ended March 31, 2021 was $1,476 million, which is 2.00 times Emera’s aggregate preferred dividends and interest requirements for this period.

EX-99.6

Exhibit 99.6

LOGO

Emera Reports 2021 First Quarter Financial Results

HALIFAX, Nova Scotia — Today Emera (TSX: EMA) reported 2021 first quarter financial results.

Highlights

Quarterly adjusted EPS increased by $0.17 to $0.96 driven by continued strength in the regulated portfolio, increased marketing and trading earnings and lower financing and other corporate costs, partially offset by a stronger Canadian dollar (“CAD”).

On track to deploy more than $2 billion of capital investment in 2021 to drive rate base growth and advance Emera’s strategy.

Filed a petition to increase 2022 base rates at Tampa Electric by $295 million USD.

“We’re off to a solid start this year,” said Scott Balfour, President and CEO of Emera Inc. “Emera’s proven strategy of safely delivering cleaner, affordable and reliable energy has been a driver of growth and innovation for over 15 years. As customers and policymakers look to accelerate the pace of decarbonization, Emera is aligned and well positioned to help lead the energy transition in a way that never loses sight of affordability and reliability for customers while continuing to deliver long-term value to shareholders.”

Q1 2021 Financial Results

Q1 2021 reported net income was $273 million, or $1.08 per common share, compared with net income of $523 million, or $2.14 per common share, in Q1 2020.

Reported net income for Q1 2020 included $321 million of earnings related to the gain on sale of the Emera Maine business, net of tax and transaction costs. In addition, $23 million of after-tax impairment charges were recognized on certain assets in Q1 2020.

Q1 2021 adjusted net income was $243 million, or $0.96 per common share, compared with $193 million, or $0.79 per common share, in Q1 2020.

Growth in quarterly adjusted net income was largely due to increased earnings at Emera Energy Services (“EES”), increased earnings at Peoples Gas (“PGS”) and Tampa Electric, and lower corporate interest and operating, maintenance and general expenses (“OM&G”), partially offset by a stronger CAD.

Strengthening of the CAD exchange rates decreased reported net income by $11 million and decreased adjusted net income by $9 million in Q1 2021 compared to Q1 2020.

Outlook

Emera’s capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of our capital investment plan are expected to be funded through the dividend reinvestment plan, the issuance of preferred equity and the issuance of common equity through our at-the-market program. Maintaining investment-grade credit ratings is a priority of management.

LOGO

Emera has provided annual dividend growth guidance of four to five per cent through to 2022.

Consolidated Financial Review

The following table highlights significant changes in adjusted net income from 2020 to 2021.


For the		Three months ended
millions of Canadian dollars		March 31
Adjusted net income – 2020^1,2		$ 193
Operating Unit Performance
Increased earnings at EES due to favourable market conditions driven by colder weather		17
Increased earnings at PGS due to higher base revenues as the result of a base rate increase on January 1, 2021 and customer growth		10
Increased earnings at Tampa Electric due to lower OM&G and higher AFUDC, partially offset by unfavourable weather, higher depreciation expense and a stronger CAD		4
Decreased earnings due to the sale of Emera Maine in Q1 2020		(6)
Tax Related
Revaluation of Nova Scotia net deferred income tax assets and liabilities and recognition of corporate income tax recovery at Barbados Light and Power in Q1 2020		4
Corporate
Decreased OM&G (pre-tax) primarily due to lower long-term incentive compensation expense		16
Decreased interest expense (pre-tax) due to repayment of debt, the impact of a stronger CAD and lower interest rates		13
Other Variances		(8)
Adjusted net income – 2021^1,2		$ 243

¹ See “Non-GAAP Measures” noted below.

² Excludes the effect of mark-to-market adjustments, gain on sale of Emera Maine and impairment charges, net of tax.

Segment Results and Non-US GAAP Reconciliation


For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2021		2020
Adjusted net income^1,2
Florida Electric Utility³	$	83	$	79
Canadian Electric Utilities⁴		88		92
Other Electric Utilities^2,5		7		20
Gas Utilities and Infrastructure⁶		80		70
Other^2,7		(15)		(68)
Adjusted net income^1,2	$	243	$	193
Gain on sale, net of tax and transaction costs		-		321
Impairment charges, net of tax		-		(23)
After-tax mark-to-market gain (loss)		30		32
Net income attributable to common shareholders	$	273	$	523
EPS (basic)	$	1.08	$	2.14
Adjusted EPS (basic)^1,2	$	0.96	$	0.79

¹ See “Non-GAAP Measures” noted below.

² Excludes the effect of mark-to-market adjustments, gain on sale of Emera Maine and impairment charges, net of tax.

³Increase due to stronger operating earnings, partially offset by a stronger CAD.

⁴ Decrease due to lower operating earnings at NSPI, primarily due to weather.

⁵Decrease due to the sale of Emera Maine in Q1 2020, the recognition of a corporate income tax recovery at Barbados Light and Power in Q1 2020, partially offset by stronger earnings at GBPC.

⁶Increase due to stronger operating earnings at PGS due to new base rates and customer growth, partially offset by a stronger CAD.

⁷ Decreased loss due to stronger marketing and trading earnings, lower corporate financing costs and OM&G and revaluation of Nova Scotia deferred income tax assets and liabilities in Q1 2020.

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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 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, Wednesday, May 12, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q1 2021 financial results.

Analysts and other interested parties in North America are invited to participate by dialing 1-866-521-4909. International parties are invited to participate by dialing 1-647-427-2311. Participants should dial in at least 10 minutes prior to the start of the call. No pass code is required.

A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available two hours after the conclusion of the call by dialing 1-800-585-8367 and entering pass code 7046138.

About Emera

Emera Inc. is a geographically diverse energy and services company headquartered in Halifax, Nova Scotia, with approximately $31 billion in assets and 2020 revenues of more than $5.5 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 in Canada, the United States 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, EMA.PR.H and EMA.PR.J. 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.

LOGO

Emera Inc.

Investor Relations

Dave Bezanson, VP, Investor Relations & Pensions

902-474-2126

dave.bezanson@emera.com

Erin Power, Director, Investor Relations

902-428-6760

erin.power@emera.com

Media

902-222-2683

media@emera.com