EX-99.1

Q1 Average Fuel Costs

US dollars

Dollars per Megawatt hour (“MWh”)

EX-99.1 2 d109447dex991.htm EX-99.1 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.