Exhibit 99.1

Management’s Discussion & Analysis

As at May 12, 2020

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the first quarter of 2020 relative to the same quarter in 2019; and its financial position as at March 31, 2020 relative to December 31, 2019. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.

This discussion and analysis should be read in conjunction with the Emera Incorporated unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2020; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2019. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At March 31, 2020, Emera’s rate-regulated subsidiaries and investments include:

Emera Rate-Regulated Subsidiary or Equity Investment	Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric – Electric Division of Tampa Electric Company (“TEC”)	Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Barbados Light & Power Company Limited (“BLPC”)	Fair Trading Commission, Barbados (“FTC”)
Grand Bahama Power Company Limited (“GBPC”)	The Grand Bahama Port Authority (“GBPA”)
Dominica Electricity Services Ltd. (“Domlec”)	Independent Regulatory Commission, Dominica (“IRC”)
Peoples Gas System (“PGS”) – Gas Division of TEC	FPSC
New Mexico Gas Company, Inc. (“NMGC”)	New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC (“SeaCoast”)	FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)	Canadian Energy Regulator (“CER”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)	UARB
Labrador Island Link Limited Partnership (“LIL”)	Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”)
St. Lucia Electricity Services Limited (“Lucelec”)	National Utility Regulatory Commission (“NURC”)
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”)	CER and FERC

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On March 24, 2020, the Company completed the sale of Emera Maine. Refer to the “Significant Items Affecting Q1 Earnings” and “Developments” sections for further details.

All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Other Electric Utilities and Gas Utilities and Infrastructure sections of the MD&A, which are reported in US dollars (“USD”), unless otherwise stated.

Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR at www.sedar.com.

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TABLE OF CONTENTS

Forward-looking Information	4
Introduction and Strategic Overview	4
Non-GAAP Financial Measures	6
Consolidated Financial Review	7
Significant Items Affecting Q1 Earnings	7
Consolidated Financial Highlights by Business Segment	8
Consolidated Income Statement Highlights	9
Business Overview and Outlook	12
COVID-19 Pandemic	12
Florida Electric Utility	13
Canadian Electric Utilities	14
Other Electric Utilities	16
Gas Utilities and Infrastructure	17
Other	18
Consolidated Balance Sheet Highlights	19
Developments	20
Outstanding Common Stock Data	20
Financial Highlights	21
Florida Electric Utility	21
Canadian Electric Utilities	23
Other Electric Utilities	25
Gas Utilities and Infrastructure	27
Other	29
Liquidity and Capital Resources	31
Consolidated Cash Flow Highlights	32
Contractual Obligations	33
Debt Management	34
Credit Ratings	35
Guarantees and Letters of Credit	35
Transactions with Related Parties	36
Risk Management and Financial Instruments	36
Disclosure and Internal Controls	39
Critical Accounting Estimates	39
Changes in Accounting Policies and Practices	40
Future Accounting Pronouncements	41
Summary of Quarterly Results	41

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FORWARD-LOOKING INFORMATION

This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, business prospects and opportunities and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations are discussed in the “Business Overview and Outlook” section of the MD&A and may also include: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; future dividend growth; timing and costs associated with certain capital investment; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

INTRODUCTION AND STRATEGIC OVERVIEW

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

Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have experienced stable regulatory policies and economic conditions.

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Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera has a $7.5 billion capital investment plan over the 2020-to-2022 period and the potential for additional capital opportunities of $200 million to $500 million over the forecast period, resulting in a forecasted rate base growth of 8 per cent through to 2022. Management continues to review the timing of capital expenditures in light of the evolving COVID-19 pandemic. This plan includes significant investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. This planned capital investment is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan will predominantly be funded in the equity capital markets through the dividend reinvestment plan and the issuance of common and preferred equity. Maintaining investment-grade credit ratings is a priority of management.

Emera has provided annual dividend growth guidance of four to five per cent through to 2022. The Company targets a long-term dividend payout ratio of 70 to 75 per cent, and while the payout ratio is likely to exceed that target in the forecast period, it is expected to return to that range over time.

Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income and cash flows are impacted by movements in the US dollar relative to the Canadian dollar and benefit from a weaker Canadian dollar. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investment and other factors mean that results in any one quarter are not necessarily indicative of results in any other quarter or for the year as a whole.

Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, complex regulatory environments and the trend towards de-carbonization. Renewable generation and battery storage are becoming both more affordable and efficient. Climate change and extreme weather are shaping how utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance reliability. Emera sees opportunity in these trends. Emera’s strategy is to fund investments in renewable and technology assets which protect the environment and benefit customers through fuel or operating cost savings.

For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, the ongoing construction of solar generation at Tampa Electric, and the modernization of the Big Bend Power Station at Tampa Electric. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of finding cleaner ways to meet the energy needs of its customers while keeping rates affordable.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships with regulators, stakeholders and the communities where we operate.

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NON-GAAP FINANCIAL MEASURES

Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures by adjusting certain GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period. These measures are discussed and reconciled below.

Adjusted Net Income

Emera calculates an adjusted net income measure by excluding the effect of mark-to-market (“MTM”) adjustments and impacts in Q1 2020 of the gain on sale of Emera Maine and the impairment losses on certain other assets.

The MTM adjustments are a result of the following:

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

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

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

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

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

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

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

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

In Q1 2020, the Company completed the sale of Emera Maine and recognized impairment losses on certain other assets. Management believes excluding these from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. Refer to the “Significant Items Affecting Q1 Earnings” and “Developments” sections for further details related to the sale of Maine. While we have excluded the gain on sale from adjusted earnings, earnings for the Other Electric Utilities segment will not include earnings from Maine for the balance of the year, which were $27 million USD in 2019.

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

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2020		2019
Net income attributable to common shareholders	$	523	$	312
Gain on sale and impairment charges, net of tax	$	298	$	-
After-tax mark-to-market gain	$	32	$	88
Adjusted net income attributable to common shareholders	$	193	$	224
Earnings per common share – basic	$	2.14	$	1.32
Adjusted earnings per common share – basic	$	0.79	$	0.95

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-GAAP financial measure used by Emera. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital and finance working capital requirements.

Adjusted EBITDA is a non-GAAP financial measure used by Emera. Similar to adjusted net income calculations described above, this measure represents EBITDA absent the income effect of Emera’s mark-to-market and amortization adjustments, and the gain on sale and impairment charges, recognized in Q1 2020, as discussed above.

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

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

For the	Three months ended March 31
millions of Canadian dollars	2020		2019
Net income (1)	$	535	$	324
Interest expense, net		184		189
Income tax expense		306		82
Depreciation and amortization		231		224
EBITDA		1,256		819
Gain on sale and impairment charges		564		-
Mark-to-market gain, excluding income tax and interest		45		126
Adjusted EBITDA	$	647	$	693

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

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Q1 Earnings

Gain on Sale and Impairment Charges

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of $2.0 billion ($1.4 billion USD). A gain on sale of $586 million ($321 million after tax or $1.31 per common share), net of transaction costs, was recognized in “Other income” on the Condensed Consolidated Statements of Income. Refer to the “Developments” section for further details. In addition, impairment charges of $22 million ($23 million after tax) were recognized on certain other assets in Q1 2020.

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Earnings Impact of After-Tax Mark-to-Market Gains and Losses

After-tax mark-to-market gains decreased $56 million to $32 million in 2020 compared to $88 million in 2019, mainly due higher amortization of gas transportation assets in 2020 and larger reversal of mark-to-market losses in 2019, partially offset by changes in existing positions on gas contracts in Emera Energy. The decrease is also due to mark-to-market losses related to foreign exchange cash flow hedges entered in Q1 2020 to manage foreign exchange earnings exposure.

Q1 2019 Sale of NEGG and Bayside facilities

In Q1 2020, earnings contribution from Emera Energy Generation was $24 million lower than in 2019 due to the sale of the New England Gas Generating (“NEGG”) and Bayside generation facilities completed in March 2019.

Consolidated Financial Highlights by Business Segment

For the	Three months ended March 31
millions of Canadian dollars	2020			2019
Adjusted Net Income
Florida Electric Utility	$	79		$	61
Canadian Electric Utilities		92			96
Other Electric Utilities		20			16
Gas Utilities and Infrastructure		70			67
Other		(68	)		(16	)
Adjusted net income attributable to common shareholders	$	193		$	224
Gain on sale and impairment charges, net of tax		298			-
After-tax mark-to-market gain		32			88
Net income attributable to common shareholders	$	523		$	312

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

For the	Three months ended
millions of Canadian dollars	March 31
Adjusted net income – 2019	$	224
Florida Electric Utility - increased earnings due to favourable weather, customer growth and higher contribution from solar projects		18
Recognition of corporate income tax recovery deferred as a regulatory liability in 2018 at BLPC		10
Decreased earnings at Emera Energy Services		(9	)
2019 gain on sale of property in Florida		(10	)
Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities due to the Q1 2020 reduction in the Nova Scotia provincial corporate income tax rate		(14	)
Decreased earnings from Emera Energy Generation due to the sale of NEGG and Bayside generation facilities in Q1 2019		(24	)
Other variances		(2	)
Adjusted net income – 2020	$	193

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

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For the	Three months ended March 31
millions of Canadian dollars	2020			2019
Operating cash flow before changes in working capital	$	502		$	418
Change in working capital		(74	)		(16	)
Operating cash flow	$	428		$	402
Investing cash flow	$	746		$	298
Financing cash flow	$	165		$	(35	)
As at	March 31			December 31
millions of Canadian dollars	2020			2019
Total assets	$	33,856		$	31,842
Total long-term debt (including current portion)	$	14,777		$	14,180

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

Consolidated Income Statement Highlights

For the millions of Canadian dollars (except per share amounts)	Three months ended March 31				Variance
	2020		2019
Operating revenues	$	1,637	$	1,818	$	(181	)
Operating expenses		1,216		1,276		60
Income from operations		421		542		(121	)
Income from equity investments		41		40		1
Other income (expenses), net		563		13		550
Interest expense, net		184		189		5
Income tax expense		306		82		(224	)
Net income		535		324		211
Net income attributable to common shareholders		523		312		211
Gain on sale and impairment charges, net of tax		298		-		298
After-tax mark-to-market gain		32		88		(56	)
Adjusted net income attributable to common shareholders	$	193	$	224	$	(31	)
Earnings per common share – basic	$	2.14	$	1.32	$	0.82
Earnings per common share – diluted	$	2.13	$	1.32	$	0.81
Adjusted earnings per common share – basic	$	0.79	$	0.95	$	(0.16	)
Dividends per common share declared	$	0.6125	$	0.5875	$	0.0250
Adjusted EBITDA	$	647	$	693	$	(46	)

Operating Revenues

For the first quarter of 2020, operating revenues decreased $181 million compared to the first quarter of 2019. Absent decreased mark-to-market gains of $61 million, operating revenues decreased $120 million due to:

• $112 million decrease in the Other segment due to the sale of NEGG and Bayside in Q1 2019;

• $21 million decrease in Gas Utilities and Infrastructure due to lower clause-related revenues at PGS and NMGC, unfavourable weather at NMGC and lower off-system sales at PGS;

• $13 million decrease in marketing and trading margin at Emera Energy due to less favourable market conditions; and

• $12 million decrease in Other Electric Utilities at Emera Maine from lower loads due to weather.

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These impacts were partially offset by increases of:

• $15 million at NSPI due to the reduced Maritime Link assessment included in 2019 rates to be returned to customers in subsequent years, and increased fuel related pricing. This was partially offset by lower sales volumes, primarily due to weather; and

• $19 million in the Florida Electric Utility segment due to increased base revenues related to favourable weather, customer growth, the in-service of solar generation projects and the impact of a weaker CAD.

Operating Expenses

For the first quarter of 2020, operating expenses decreased $60 million compared to the first quarter of 2019 due to:

• $81 million decrease in the Other segment due to the sale of NEGG and Bayside in Q1 2019; and

• $20 million decrease in the Gas Utilities and Infrastructure segment due to lower regulated cost of natural gas reflecting lower commodity costs at PGS and NMGC.

These impacts were partially offset by an increase of:

• $23 million in the Canadian Electric Utility segment due to changes in the fuel adjustment mechanism and increased operating, maintenance and general (“OM&G”) expenses in NSPI.

Other Income (Expenses), Net

The increase in other income (expenses), net for the first quarter in 2020, compared to the first quarter of 2019, was primarily due to the pre-tax gain on sale of Emera Maine, partially offset by impairment charges on certain other assets recognized in Q1 2020.

Income Tax Expense

The increase in income tax expense for the first quarter of 2020 compared to the first quarter of 2019 was primarily due to the gain on sale of Emera Maine and the revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020. This was partially offset by decreased income before provision for income taxes, excluding the gain on sale of Emera Maine, and the recognition of corporate income tax recovery deferred as a regulatory liability in 2018 at BLPC.

Net Income and Adjusted Net Income Attributable to Common Shareholders

For the first quarter of 2020, net income attributable to common shareholders was favourably impacted by the $321 million after-tax gain on sale of Emera Maine, and unfavourably impacted by the $56 million decrease in after-tax mark-to-market gains primarily related to Emera Energy and after-tax impairment charges. Absent the net gain on sale of Emera Maine, the unfavourable mark-to-market changes and impairment charges recognized in Q1 2020, adjusted net income attributable to common shareholders decreased $31 million. The decrease was due to lower contributions from Emera Energy (as a result of the sale of NEGG in Q1 2019 and decreased marketing and trading margin), revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate and the 2019 gain on sale of property in Florida. These were partially offset by an increased contribution from Tampa Electric and recognition of deferred income tax at BLPC.

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Earnings and Adjusted Earnings per Common Share – Basic

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

Effect of Foreign Currency Translation

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

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

Results of foreign operations are translated at the weighted average rate of exchange and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/US exchange rates for 2020 and 2019 are as follows:

	Three months ended March 31				Year ended December 31
	2020		2019		2019
Weighted average CAD/USD	$	1.34	$	1.33	$	1.33
Period end CAD/USD exchange rate	$	1.42	$	1.34	$	1.30

Weakening of the CAD exchange rates increased earnings by $5 million and adjusted earnings by $1 million in Q1 2020 compared to Q1 2019.

Consistent with the Company’s risk management policies, Emera partially manages currency risks through matching US denominated debt to finance its US operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. Emera does not utilize derivative financial instruments for foreign currency trading or speculative purposes.

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

	Three months ended March 31
millions of US dollars	2020			2019
Florida Electric Utility	$	59		$	46
Other Electric Utilities		15			12
Gas Utilities and Infrastructure (1)		45			45
		119			103
Other segment (2)		(23	)		(16	)
Total (3)	$	96		$	87

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

(2) Includes Emera Energy’s US dollar adjusted net income from Emera Energy Services, Bear Swamp, interest expense on Emera Inc.’s US dollar denominated debt and in 2019 net income from NEGG.

(3) Amounts above do not include the impact of mark-to-market.

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BUSINESS OVERVIEW AND OUTLOOK

COVID-19 Pandemic

In Q1 2020, the ongoing COVID-19 pandemic impacted all the service territories in which Emera operates. To date, COVID-19 has not had a material financial impact on the Company, Emera’s utilities provide essential services and continue to operate and meet customer demand. The Company’s top priority continues to be the health and safety of its customers and employees. Management continues to closely monitor developments related to COVID-19.

Governments world-wide have implemented measures intended to address the pandemic. These measures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial spaces and industrial facilities, shutdowns, shelter-in-place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility and weakness. Governments and central banks are implementing measures designed to stabilize economic conditions.

Emera has activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. The Company has updated its principal risks to reflect this uncertainty. Refer to the “Risk Management and Financial Instruments” section and note 21 in the condensed consolidated financial statements for this risk update. The Company has disclosed the impact of this uncertainty on its accounting estimates used in the preparation of the financial statements. Refer to the “Critical Accounting Estimates” section, and the “Use of Management Estimates” section of note 1 in the condensed consolidated financial statements for further details.

Potential future impacts on the business are anticipated to include the following:

• Lower earnings as a result of lower sales volumes due to economic slowdowns. Commercial and industrial sales are generally expected to be lower, with this decrease partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. To date, the Company is generally experiencing reductions to weather-adjusted load in the range of 4-to-6 per cent for most of its utilities;

• Delays of capital projects as a result of construction shutdowns, government restrictions on non-essential capital work, travel restrictions for contractors or supply chain disruptions. Capital project delays have been minimal to date;

• Deferral of and adjustment to regulatory filings, hearings, decisions and recovery periods; and

• Decreased cash flow from operations due to lower earnings and slower collection of accounts receivable. Emera’s utilities are working with customers on relief initiatives in response to the effect on customers’ ability to pay and their need for continued service. These initiatives include the suspension of disconnection for non-payment of bills and the development of payment arrangements if necessary. In certain service territories, collection may be further delayed due to curfew restrictions and temporary short-term closure of locations able to receive in-person payments.

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Refer to the outlook sections by segment below for discussion of utility-specific impacts. These segment outlooks are based on the information currently available, however, the total impact of COVID-19 is unknown at this time due to uncertainties related to the duration and severity of the pandemic.

Depending on the duration of the COVID-19 pandemic, the forecasted capital expenditures disclosed below may be delayed due to supply chain disruptions, travel restrictions for contractors or the deferral of non-essential capital work, if required. The Company currently expects to continue to have adequate liquidity given its cash position, existing bank facilities, and access to capital, but will continue to monitor the impact of COVID-19 on future cash flows. Refer to the “Liquidity and Capital Resources” section for further details.

Florida Electric Utility

Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida.

Tampa Electric currently anticipates earning within its allowed ROE range in 2020 and expects rate base to be higher than 2019. Favourable weather in Q1 2020 has more than offset the impacts on revenues as a result of COVID-19. Based on Q1 results and current estimates of COVID-19 impacts, and assuming normal weather for the remainder of the year, Tampa Electric expects customer growth rates and volumes to be negatively impacted by expected declines in economic activity in Florida, resulting in overall sales volumes for the year being similar or slightly lower than in 2019. However, current expected outcomes and actual results may differ given the many uncertainties related to the pandemic and its economic impact.

On October 3, 2019, the FPSC issued a rule to implement a storm protection plan cost recovery clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. The FPSC is expected to rule on the plan in late 2020.

On April 28, 2020 the FPSC approved Tampa Electric’s request for a mid-course adjustment to its fuel and capacity charges due to a decline in expected fuel commodity and capacity costs in 2020. The adjustment will be effective beginning with June 2020 customer bills and will result in lower rates for the balance of the year, including an acceleration of the return of these savings in the first three months.

On February 18, 2020, Tampa Electric announced its intention to invest approximately $800 million USD in an additional 600 MW of new utility-scale solar photovoltaic projects by the end of 2023. Refer to the “Developments” section for further details.

Planned capital expenditures in the Florida Electric Utility segment for 2020 remain unchanged at approximately $1.0 billion USD (2019 - $1.1 billion USD), including AFUDC. Capital projects include solar investments, continuation of the modernization of the Big Bend Power Station, storm hardening investments, and advanced metering infrastructure (“AMI”).

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Canadian Electric Utilities

Canadian Electric Utilities includes:

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

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

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

• Construction of the LIL is complete and Nalcor Energy (“Nalcor”) recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL, however, there has been a suspension of on-site commissioning in response to the COVID-19 pandemic.

NSPI

NSPI anticipates earning within its allowed ROE range in 2020. Sales volumes and earnings are expected to be lower than 2019 due to the impact of the COVID-19 pandemic on Nova Scotia’s economy. NSPI expects a decrease in sales volumes primarily in the commercial and industrial classes, partially offset by an increase in residential sales volumes, which have a higher contribution to fixed cost recovery. The anticipated deferral of capital investment, discussed below, will have a corresponding decreasing effect on NSPI’s expected rate base growth in the current year.

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these laws and regulations, to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated reductions will be recoverable under NSPI’s regulatory framework.

In Q1 2020, NSPI received its 2020 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These 2020 allowances will be used in 2020 or allocated within the initial four-year compliance period that ends in 2022. At March 31, 2020, NSPI is on track to meet the requirements of the program. NSPI anticipates that any prudently incurred costs required to comply with the Government of Canada’s laws and regulations, and the Nova Scotia Cap-and-Trade Program Regulations, will be recoverable under NSPI’s regulatory framework.

Over the past several years, the requirement to reduce Nova Scotia’s reliance upon higher carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a significant investment in renewable energy sources and purchasing renewable energy from independent power producers. NSPI will have an increase in energy from renewable sources upon delivery of the Nova Scotia block (“NS Block”) of electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project.

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On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. Due to the unpredictability of the course of the pandemic, Nalcor is currently unable to provide an updated construction schedule. Refer to the “ENL – Impact of COVID-19 on Muskrat Falls and LIL” section below for further details. Should there be a delay in the delivery of the NS Block beyond 2020, NSPI’s ability to achieve the provincially legislated target of 40 per cent electricity generated from renewable sources in 2020 could require the sourcing of alternate qualifying energy. NSPI is working with the provincial government on options to address this potential risk.

As a result of the measures taken to limit the spread of COVID-19, there are restrictions on completing non-essential capital projects. NSPI anticipates this will result in a reduction in its 2020 capital investments from $375 million to approximately $275 million. The $100 million of capital investments will be deferred to 2021 and 2022. Capital investment for 2019, including AFUDC, was $396 million.

ENL

Equity earnings from NSPML and LIL are expected to be higher in 2020, compared to 2019. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

NSPML

Equity earnings contributions from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.

NSPML has UARB approval to collect approximately $145 million (2019—$111 million) from NSPI for the recovery of costs associated with the Maritime Link in 2020, which is included in NSPI rates. NSPML expects to file a final capital cost application for the Maritime Link with the UARB upon commencement of the NS Block of energy from Muskrat Falls. As a result of the potential delay of the NS Block, NSPML’s final capital cost application will be delayed. Consequently, NSPML anticipates making an application with the UARB in 2020 to reset rates for recovery of costs in 2021.

In 2020, NSPML expects to invest approximately $20 million (2019—$28 million) in capital.

LIL

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $591 million, comprised of $410 million in equity contribution and $181 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after all Lower Churchill projects, including Muskrat Falls, are completed.

Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, and until that point Emera will continue to record AFUDC earnings.

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Impact of COVID-19 on Muskrat Falls and LIL

On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor has declared force majeure under various project contracts, including formal notification to NSPML. Due to the unpredictable nature of the COVID-19 pandemic, Nalcor is currently unable to provide an updated completion schedule for Muskrat Falls or LIL until there is greater certainty. Nalcor has expressed its desire to resume work at site as soon as it is safe to do so for its employees, contractors and associated communities.

Other Electric Utilities

Other Electric Utilities includes:

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

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

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

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

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

Earnings from the Caribbean utilities are expected to be lower due to the impact of COVID-19 on local economies. Tourism and associated support businesses have been significantly impacted by the suspension of international travel, with many businesses temporarily closed. As a result, earnings from both BLPC and Domlec are expected to be lower than in 2019. The expected decrease in BLPC’s earnings will be partially offset by the Q1 2020 recognition of a $6.9 million USD corporate income tax recovery which was deferred as a regulatory liability in 2018. GBPC’s earnings are expected to be consistent with 2019 earnings which were lower than normal as a result of Hurricane Dorian. The impact of COVID-19 on GBPC is expected to be partially offset by recovery of load following Hurricane Dorian. The decrease in earnings from the Caribbean utilities is expected to be in the range of approximately $3 million to $8 million USD depending on the extent and duration of the pandemic’s impact on local economies.

On April 16, 2020, S&P Global Ratings (“S&P”) lowered its long-term foreign and local currency ratings on The Bahamas. The downgrade was driven by the uncertainty around the duration of the COVID-19 pandemic and the strength of the recovery. The downgrade is not currently expected to have a material financial impact on GBPC.

On September 1, 2019, Hurricane Dorian struck Grand Bahama Island causing significant damage across the island. In January 2020, the GBPA approved the recovery of approximately $15 million USD of restoration costs related to GBPC’s self-insured assets. As of March 31, 2020, $13 million USD of these costs were incurred, and recorded as a regulatory asset. Recovery of the regulatory asset, due to start on April 1, 2020, has been temporarily suspended as a result of the economic impacts of COVID-19 on Grand Bahama.

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In 2020, capital expenditures in the Other Electric Utilities segment are forecasted to be approximately $130 million USD (including $14 million USD invested in Emera Maine projects supporting normal system reliability prior to completion of the sale) (2019 – $150 million USD). Completion of BLPC’s 33MW diesel engine installation, expected by mid-2020, will be delayed until travel restrictions, implemented by the government in response to COVID-19, are lifted for construction work.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes:

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

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

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

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

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

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

PGS anticipates earning below its allowed ROE range in 2020. PGS sales volumes are expected to be lower than in 2019 as a result of the economic impact of COVID-19 in Florida. Beginning mid-March, PGS sales volumes have shown a decreasing trend as a result of the impact of government quarantine measures on commercial activity and tourism. Prior to the impact of COVID-19, PGS anticipated it would earn below its allowed ROE range in 2020 primarily due to significant capital investments and related growth in rate base. Therefore, as a result of forecasted revenue requirements being higher than what is in current rates, on February 7, 2020, PGS notified the FPSC that it was planning to file a base rate proceeding in April 2020 for new rates effective January 2021. Due to the COVID-19 pandemic, in early April 2020, PGS requested and received an extension from the FPSC to file this proceeding by June 8, 2020.

NMGC anticipates earning at or slightly below its allowed ROE in 2020 and expects rate base to be higher than 2019. Assuming normal weather, NMGC sales volumes are expected to decrease, as 2019 energy sales benefited from favourable weather in the first half of the year. NMGC sales volumes to date have not been significantly impacted by COVID-19. Depending on the duration of COVID-19 related restrictions, industrial and commercial sales volumes are expected to decrease. Earnings from NMGC are also expected to be lower as a result of the 2019 recognition of tax reform benefits, and the approved change in treatment of net operating loss (“NOL”) carryforwards in 2019, which contributed a total of $14 million USD to earnings last year.

In 2020, capital expenditures in the Gas Utilities and Infrastructure segment are expected to be approximately $600 million USD (2019 - $331 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will complete the Santa Fe Mainline Looping project in 2020 and will continue to invest in system improvements. SeaCoast will continue to invest in the Seminole Pipeline and the Callahan Pipeline with approximately $100 million USD expected to be invested in 2020. The Seminole and Callahan Pipelines remain on schedule with total costs of approximately $110 million USD and $32 million USD, respectively.

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Other

The Other segment includes those business operations that, in a normal year, are below the required threshold for reporting as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Business operations in Other include Emera Energy, which consists of:

• Emera Energy Services (“EES”), a wholly owned physical energy marketing and trading business;

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

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

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

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

Earnings from EES are generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 generally providing the greatest opportunity for earnings. The business is generally expected to deliver annual adjusted net earnings of $15 to $30 million USD ($45 to $70 million USD of margin), with the opportunity for upside when market conditions present. EES expects that the COVID-19 related economic slowdown could impact gas supply/demand and result in lower absolute pricing and volatility in its core geography for some months. This would reduce opportunity for the business, which the Company expects would result in earnings at the lower end of the normal range in 2020.

The Other segment is expected to contribute positively to earnings in 2020 due to the gain on sale of Emera Maine recognized in earnings in Q1 2020. Absent this gain, the adjusted net loss from the Other segment is expected to increase over the prior year. This increase is primarily due to decreased tax recoveries and increased interest due to increased borrowings. The decrease in tax recoveries is due to the revaluation of deferred income tax assets at the lower Nova Scotia corporate income tax rate enacted in March 2020. These impacts are anticipated to be partially offset by increased EES contribution.

In 2020, capital expenditures in the Other segment are expected to be approximately $40 million (2019 - $63 million), including investment in contracted energy infrastructure.

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CONSOLIDATED BALANCE SHEET HIGHLIGHTS

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

millions of Canadian dollars	Increase (Decrease)			Explanation
Assets
Cash and cash equivalents	$	1,331		Increased due to proceeds on the sale of Emera Maine and cash from operations, partially offset by additions of property, plant and equipment and dividends on common stock.
Regulatory assets (current and long-term)		68		Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Receivables and other assets (current and long-term)		121		Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, reclassification of corporate alternative minimum tax credit carryforwards from deferred income tax liabilities, increased cash collateral position on derivative instruments at NSPI and the seasonality of business at NSPI. This is partially offset by lower commodity prices at Emera Energy.
Assets held for sale (current and long-term), net of liabilities		(691	)	Decreased due to the completion of the sale of Emera Maine.
Property, plant and equipment, net of accumulated depreciation and amortization		1,679		Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates and additions at Tampa Electric, PGS and NSPI.
Goodwill		538		Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		1,271		Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, and increased borrowings under Tampa Electric’s committed credit facilities. These were partially offset by payment of long-term debt at TECO Finance.
Accounts payable		(96	)	Decreased due to lower commodity prices at Emera Energy, payments for solar projects and the Big Bend modernization at Tampa Electric, and timing of payments at NSPI. These were partially offset by the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Deferred income tax liabilities, net of deferred income tax assets		371		Increased due to net utilization of tax loss carryforwards primarily related to the sale of Emera Maine, tax deductions in excess of accounting depreciation related to property, plant and equipment and the effect of a weaker CAD on the translation of Emera’s foreign subsidiaries. The increase is partially offset by the revaluation of net deferred income tax liabilities resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020.
Regulatory liabilities (current and long-term)		217		Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, increased cost recovery clauses at Tampa Electric and increased deferrals related to derivative instruments at NSPI.
Other liabilities (current and long-term)		223		Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, higher accrued interest on long-term debt at Tampa Electric and Corporate and investment tax credits related to solar projects at Tampa Electric.

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Common stock	124	Increased due to shares issued under Emera’s at-the-market equity plan, stock options exercised and the dividend reinvestment plan.
Accumulated other comprehensive income	612	Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates.
Retained earnings	367	Increased due to the gain on sale of Emera Maine and net income in excess of dividends paid.

DEVELOPMENTS

Sale of Emera Maine

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of $2.0 billion ($1.4 billion USD), including cash proceeds of $1.4 billion, transferred debt and a working capital adjustment. A gain on sale of $586 million ($321 million after tax), net of transaction costs, was recognized in the Other segment and included in “Other income” on the Condensed Consolidated Statements of Income. Proceeds from the sale are being used to support capital investment opportunities within Emera’s regulated utilities and to reduce corporate debt.

Tampa Electric Solar Investment

On February 18, 2020, Tampa Electric announced its intention to invest approximately $800 million USD in an additional 600 MW of new utility-scale solar photovoltaic projects by the end of 2023. On completion of these projects, approximately 22 per cent or 1,250 MW of Tampa Electric’s total generating capacity will be solar.

OUTSTANDING COMMON STOCK DATA

Common stock Issued and outstanding:	millions of shares		millions of Canadian dollars
Balance, December 31, 2018		234.12	$	5,816
Conversion of Convertible Debentures		0.03		1
Issuance of common stock		1.77		99
Issued for cash under Purchase Plans at market rate		3.99		202
Discount on shares purchased under Dividend Reinvestment Plan		-		(7	)
Options exercised under senior management stock option plan		2.57		104
Employee Share Purchase Plan		-		1
Balance, December 31, 2019		242.48	$	6,216
Issuance of common stock (1)		0.98		58
Issued for cash under Purchase Plans at market rate		0.83		49
Discount on shares purchased under Dividend Reinvestment Plan		-		(1	)
Options exercised under senior management stock option plan		0.36		17
Employee Share Purchase Plan		-		1
Balance, March 31, 2020		244.65	$	6,340

(1) In Q1 2020, 982,982 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $59.79 per share for gross proceeds of $58.8 million ($58 million net of issuance costs). As at March 31, 2020, an aggregate gross sales limit of $441.2 million remains available for issuance under the ATM program.

As at May 8, 2020 the amount of issued and outstanding common shares was 244.7 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended March 31, 2020 was 244.7 million (2019 – 236.4 million).

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FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.

For the millions of US dollars (except per share amounts)	Three months ended March 31
	2020		2019
Operating revenues – regulated electric	$	421	$	412
Regulated fuel for generation and purchased power		106		115
Contribution to consolidated net income	$	59	$	46
Contribution to consolidated net income – CAD	$	79	$	61
Contribution to consolidated earnings per common share – basic – CAD	$	0.32	$	0.26
Net income weighted average foreign exchange rate – CAD/USD	$	1.34	$	1.33
EBITDA	$	184	$	166
EBITDA – CAD	$	248	$	221

Net Income

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

For the millions of US dollars	Three months ended March 31
Contribution to consolidated net income – 2019		$            46
Increased operating revenues—see Operating Revenues—Regulated Electric below		9
Decreased fuel for generation and purchased power—see Regulated Fuel for Generation and Purchased Power below		9
Increased depreciation and amortization due to increased property, plant and equipment		(4	)
Increased other income as a result of higher AFUDC earnings due to the construction of solar projects and Big Bend modernization project		3
Increased interest expense to support ongoing capital investment activity		(3	)
Other		(1	)
Contribution to consolidated net income – 2020		$            59

Florida Electric Utility’s CAD contribution to consolidated net income increased $18 million to $79 million in Q1 2020, compared to $61 million in Q1 2019. Earnings increased due to higher base revenues as a result of favourable weather, customer growth and the in-service of solar generation projects. This increase was partially offset by higher depreciation expense and higher interest expense as a result of higher capital investments.

The impact of the change in the foreign exchange rate increased Q1 2020 CAD earnings by $1 million.

Operating Revenues – Regulated Electric

Electric revenues increased $9 million to $421 million in Q1 2020 compared to $412 million in Q1 2019. Revenues increased due to higher base revenues related to favourable weather, customer growth and the in-service of solar generation projects, partially offset by lower clause revenues. A significant portion of the weather impact occurred during the last half of March 2020 resulting in an increase in unbilled revenues in Q1 2020, compared to Q1 2019. While operating revenues include both billed and unbilled

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revenues, Q1 2020 electric sales volumes, in the table below, do not reflect this increase as they are calculated based on billed hours only.

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

Q1 Electric Revenues millions of US dollars
	2020		2019
Residential	$	205	$	206
Commercial		125		120
Industrial		37		34
Other (1)		54		52
Total	$	421	$	412

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

Q1 Electric Sales Volumes (1) Gigawatt hours (“GWh”)
	2020		2019
Residential		1,880		1,939
Commercial		1,373		1,370
Industrial		497		462
Other		466		461
Total		4,216		4,232

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

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $9 million to $106 million in Q1 2020, compared to $115 million in Q1 2019, due to increased use of lower-cost natural gas and increased solar generation.

Q1 Production Volumes GWh
	2020		2019
Natural gas		4,105		3,768
Solar		234		152
Coal		181		308
Purchased power		36		95
Total		4,556		4,323

Q1 Average Fuel Costs
US dollars		2020		2019
Dollars per Megawatt hour (“MWh”)	$	23	$	27

Average fuel cost per MWh decreased in Q1 2020, compared to Q1 2019, primarily due to increased use of lower-cost natural gas and zero fuel cost solar generation.

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Canadian Electric Utilities

For the		Three months ended March 31
millions of Canadian dollars (except per share amounts)	2020		2019
Operating revenues – regulated electric	$	458	$	443
Regulated fuel for generation and purchased power (1)		194		192
Income from equity investments		27		25
Contribution to consolidated net income	$	92	$	96
Contribution to consolidated earnings per common share - basic	$	0.38	$	0.41
EBITDA	$	193	$	196

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

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

For the millions of Canadian dollars	Three months ended March 31
	2020		2019
NSPI	$	65	$	71
Equity investment in NSPML		15		14
Equity investment in LIL		12		11
Contribution to consolidated net income	$	92	$	96

Net Income

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

For the millions of Canadian dollars	Three months ended March 31
Contribution to consolidated net income – 2019	$	96
Increased operating revenues - see Operating Revenues - Regulated Electric below		15
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		(2	)
Increased FAM and fixed cost deferrals primarily due to the refund to customers of prior years’ over-recovery of fuel costs and reduced Maritime Link Assessment, partially offset by the over-recovery of current period fuel costs		(14	)
Increased OM&G expenses primarily due to higher storm recovery costs, higher costs for information technology, an increased allowance for doubtful accounts and contributions for community support related to the COVID-19 pandemic response		(7	)
Income from equity investments - see Electric Utilities contribution below		2
Other		2
Contribution to consolidated net income – 2020	$	92

Canadian Electric Utilities’ contribution to consolidated net income decreased in Q1 2020 due to lower contribution from NSPI. This decrease was mainly due to higher OM&G costs and lower sales volumes, primarily due to weather, partially offset by regulatory deferral timing. The timing of regulatory deferrals causes quarterly earnings volatility, while full year results are more predictable. Q1 2020 income from equity earnings was consistent with Q1 2019.

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NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $15 million to $458 million in Q1 2020 compared to $443 million in Q1 2019. Revenues increased due to the reduced Maritime Link assessment included in 2019 rates to be returned to customers in subsequent years, and increased fuel-related pricing. This was partially offset by decreased sales volumes due to weather, decreased export sales and decreased other, industrial and commercial class sales volumes.

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

Q1 Electric Revenues
millions of Canadian dollars
	2020		2019
Residential	$	264	$	252
Commercial		120		113
Industrial		56		55
Other		11		16
Total	$	451	$	436

Q1 Electric Sales Volumes
GWh
	2020		2019
Residential		1,560		1,621
Commercial		860		884
Industrial		588		597
Other		76		143
Total		3,084		3,245

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $2 million to $194 million in Q1 2020 compared to $192 million in Q1 2019, primarily due to a change in generation mix, partially offset by decreased commodity prices and decreased sales volumes.

Q1 Production Volumes
GWh
	2020		2019
Coal		1,595		1,846
Natural Gas		474		244
Oil and petcoke		282		315
Purchased power – other		119		141
Total non-renewables		2,470		2,546
Wind and hydro		341		371
Purchased power – IPP		335		370
Purchased power – Community Feed-in Tariff program		147		163
Biomass		11		15
Total renewables		834		919
Total production volumes		3,304		3,465
Q1 Average Fuel Costs
	2020		2019
Dollars per MWh	$	59	$	55

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Average fuel cost per MWh increased in Q1 2020, compared to Q1 2019, primarily due to a change in generation mix resulting from higher natural gas consumption partially offset by lower generation from solid fuel and a decrease in purchased power.

NSPI’s FAM regulatory liability balance decreased $3 million from $115 million at December 31, 2019 to $112 million at March 31, 2020 primarily due to the refund of prior years’ over-recovery of fuel costs and reduced Maritime Link assessment to customers. This was partially offset by over-recovery of current period fuel costs.

Other Electric Utilities

All amounts are reported in USD, unless otherwise stated.

On March 24, 2020, Emera completed the sale of Emera Maine. The Company continued to record depreciation on these assets through the transaction closing date, as the depreciation continued to be reflected in customer rates and was reflected in the carryover basis of the assets on close. Refer to the “Significant Items Affecting Q1 Earnings” and “Developments” sections for further details.

For the	Three months ended March 31
millions of US dollars (except per share amounts)	2020			2019
Operating revenues – regulated electric	$	127		$	136
Regulated fuel for generation and purchased power (1)		50			49
Adjusted contribution to consolidated net income	$	15		$	12
Adjusted contribution to consolidated net income - CAD	$	20		$	16
After-tax equity securities mark-to-market gain (loss)		(2	)		1
Contribution to consolidated net income	$	13		$	13
Contribution to consolidated net income – CAD	$	17		$	18
Adjusted contribution to consolidated earnings per common share – basic – CAD	$	0.08		$	0.07
Contribution to consolidated earnings per common share – basic – CAD		0.07		$	0.08
Net income weighted average foreign exchange rate – CAD/USD	$	1.37		$	1.33
Adjusted EBITDA	$	40		$	47
Adjusted EBITDA - CAD	$	54		$	62

(1) Regulated fuel for generation and purchased power includes transmission pool expense.

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

For the	Three months ended
millions of US dollars	March 31
	2020		2019
Emera Maine	$	4	$	8
ECI		11		4
Adjusted contribution to consolidated net income	$	15	$	12

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Net Income

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

For the	Three months ended
millions of US dollars	March 31
Contribution to consolidated net income – 2019	$	13
Operating revenues - see Operating Revenues - Regulated Electric below		(9	)
Regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below		(1	)
Increased income tax recovery primarily due to the recognition of a previously deferred corporate income tax recovery related to the enactment of a lower corporate income tax rate in December 2018 at BLPC		7
Other		3
Contribution to consolidated net income – 2020	$	13

Excluding the change in mark-to-market, Other Electric Utilities’ CAD contribution to consolidated net income increased by $4 million to $20 million in Q1 2020, compared to $16 million in Q1 2019. ECI’s contribution increased due to recognition of a previously deferred corporate income tax recovery related to the enactment of a lower corporate income tax rate in December 2018 at BLPC. Emera Maine contribution decreased due to unseasonably warm weather and lower regional transmission revenues. The foreign exchange rate had minimal impact on Other Electric Utilities for the three months ended March 31, 2020.

Operating Revenues – Regulated Electric

Operating revenues decreased $9 million to $127 million in Q1 2020 compared to $136 million in Q1 2019, primarily due to unseasonably warm weather at Emera Maine and lower sales at GBPC due to the impact of Hurricane Dorian. These were partially offset by increased sales volumes at Domlec and BLPC and higher fuel revenue at BLPC.

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

Q1 Electric Revenues
millions of US dollars
	2020		2019
Residential	$	46	$	51
Commercial		59		60
Industrial		9		9
Other (1)		13		16
Total	$	127	$	136

(1) Other revenue includes amounts recognized relating to Emera Maine’s FERC transmission rate refunds and other transmission revenue adjustments.

Q1 Electric Sales Volumes
GWh	2020		2019
Residential		331		339
Commercial		358		369
Industrial		122		112
Other		7		7
Total		818		827

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Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $1 million to $50 million in Q1 2020, compared to $49 million in Q1 2019 due to higher hedged commodity prices at GBPC.

Q1 Production Volumes
GWh
	2020		2019
Oil		311		319
Hydro		4		4
Solar		5		5
Purchased power		11		8
Total		331		336
(1) Production volumes relate to ECI only.
Q1 Average Fuel Costs
US dollars		2020		2019
Dollars per MWh	$	122	$	116

(2) Average fuel costs relate to ECI only.

Average fuel cost per MWh increased in Q1 2020, compared to Q1 2019, as a result of usage of higher cost fuel and volatility in fuel market negatively impacting hedged fuel at GBPC.

Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.

For the	Three months ended
millions of US dollars (except per share amounts)			March 31
	2020		2019
Operating revenues – regulated gas (1)	$	250	$	269
Operating revenues – non-regulated		3		3
Total operating revenue		253		272
Regulated cost of natural gas		81		103
Income from equity investments		3		5
Contribution to consolidated net income	$	53	$	51
Contribution to consolidated net income – CAD	$	70	$	67
Contribution to consolidated earnings per common share – basic - CAD	$	0.29	$	0.28
Net income weighted average foreign exchange rate – CAD/USD	$	1.33	$	1.33
EBITDA	$	103	$	102
EBITDA – CAD	$	137	$	135

(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2019 – $11 million), however, it is excluded from the gas revenues analysis below.

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

For the	Three months ended
millions of US dollars			March 31
	2020		2019
PGS	$	18	$	18
NMGC		23		23
Other		12		10
Contribution to consolidated net income	$	53	$	51

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Net Income

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

For the	Three months ended
millions of US dollars	March 31
Contribution to consolidated net income – 2019	$	51
Decreased gas operating revenues—see Operating Revenues—Regulated Gas below		(19	)
Decreased cost of natural gas sold—see Regulated Cost of Natural Gas below		22
Increased OM&G expenses due to lower capitalized construction overheads at NMGC related to capital project timing, and increased labour and contractor costs at PGS as a result of its growing distribution system		(3	)
Other		2
Contribution to consolidated net income – 2020	$	53

Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $3 million to $70 million in Q1 2020 compared to $67 million in Q1 2019. Earnings from PGS and NMGC were consistent quarter-over-quarter as customer growth, higher return on investment in Cast Iron/Bare Steel replacement rider at PGS and lower NMGC depreciation rates were offset by unfavourable weather at NMGC, higher OM&G expenses, and higher depreciation at PGS.

The foreign exchange rate had minimal impact for the three months ended March 31, 2020.

Operating Revenues – Regulated Gas

Operating revenues decreased $19 million to $250 million in Q1 2020 compared to $269 million in Q1 2019. This decrease resulted from lower clause-related revenues at PGS and NMGC, unfavourable weather in New Mexico and lower off-system sales at PGS, partially offset by customer growth at PGS.

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

Q1 Gas Revenues
millions of US dollars
	2020		2019
Residential	$	126	$	142
Commercial		67		73
Industrial (1)		10		9
Other (2)		36		34
Total (3)	$	239	$	258

(1) Industrial includes sales to power generation customers.

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

(3) Excludes $11 million of finance income from Brunswick Pipeline (2019 – $11 million).

Q1 Gas Volumes
Therms (millions)
	2020		2019
Residential		172		175
Commercial		251		263
Industrial		387		337
Other		97		61
Total		907		836

Regulated Cost of Natural Gas

Regulated cost of natural gas decreased $22 million to $81 million in Q1 2020, compared to $103 million in Q1 2019, due to lower commodity costs at PGS and NMGC.

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Gas sales by type are summarized in the following table:

Q1 Gas Volumes by Type
Therms (millions)
	2020		2019
System supply		275		268
Transportation		632		568
Total		907		836

Other

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2020			2019
Marketing and trading margin (1) (2)	$	41		$	54
Electricity and capacity sales (3)		4			116
Other non-regulated operating revenue		5			10
Total operating revenues – non-regulated		50			180
Intercompany revenue (4)		3			9
Non-regulated fuel for generation and purchased power (5)		4			64
Income from equity investments		9			8
Interest expense, net		82			93
Adjusted contribution to consolidated net income (loss)	$	(68	)	$	(16	)
Gain on sale and impairment charges, net of tax		298			-
After-tax derivative mark-to-market gain	$	35		$	86
Contribution to consolidated net income	$	265		$	70
Adjusted contribution to consolidated earnings per common share – basic	$	(0.28	)	$	(0.07	)
Contribution to consolidated earnings per common share – basic	$	1.08		$	0.30
Adjusted EBITDA	$	17		$	90

(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management services’ revenues.

(2) Marketing and trading margin excludes a pre-tax mark-to-market gain of $63 million for the quarter ended March 31, 2020 (2019 - $122 million gain).

(3) Electricity and capacity sales exclude a pre-tax mark-to-market loss of nil for the quarter ended March 31, 2020 (2019 - $2 million gain).

(4) Intercompany revenue consists of interest from Brunswick Pipeline and M&NP.

(5) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market loss of $2 million for the quarter ended March 31, 2020 (2019 - $2 million loss).

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

For the	Three months ended
millions of Canadian dollars				March 31
	2020			2019
Emera Energy	$	21		$	52
Corporate		(89	)		(67	)
Other		-			(1	)
Adjusted contribution to consolidated net income (loss)	$	(68	)	$	(16	)

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Net Income

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

For the	Three months ended
millions of Canadian dollars	March 31
Contribution to consolidated net income – 2019	$	70
Gain on sale and impairment charges, net of tax		298
Decreased mark-to-market gain, net of tax, primarily due to higher amortization of gas transportation assets in 2020, larger reversal of mark-to-market losses in 2019 and losses related to foreign exchange cash flow hedges entered in Q1 2020 to manage foreign exchange earnings exposure, partially offset by changes in existing positions on gas contracts		(53	)
Impact of 2019 sale of NEGG and Bayside Power, net of tax		(24	)
Decreased marketing and trading margin - see Emera Energy		(13	)
Revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, including $2 million recovery related to mark-to-market		(11	)
Decrease in other income due to 2019 gain on sale of property in Florida, net of tax		(10	)
Increased OM&G primarily due to performance based compensation, partially offset by lower expenses due to the sale of Emera Utility Services assets in 2019		(5	)
Increased income tax recovery primarily due to increased losses before provision for income taxes and the impact of effective state tax rates		13
Contribution to consolidated net income – 2020	$	265

Excluding the decrease in mark-to-market gain, the gain on sale and impairment charges recognized on certain other assets, Other’s contribution to consolidated net income decreased $52 million to a loss of $68 million for Q1 2020, compared to Q1 2019. This was primarily due to the impact of the sale of NEGG and Bayside Power in 2019, decreased marketing and trading margin, revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, the 2019 sale of property in Florida and increased OM&G in Corporate. These were partially offset by lower income taxes due to lower earnings and the impact of effective state tax rates.

Emera Energy

Marketing and trading margin decreased $13 million to $41 million in Q1 2020 compared to $54 million in Q1 2019 as a result of less favourable market conditions, specifically warmer than normal weather, lower natural gas prices and low volatility when compared to 2019.

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LIQUIDITY AND CAPITAL RESOURCES

The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in markets served by Emera, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets and changes in environmental legislation. Emera’s subsidiaries are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and maintain their credit metrics.

In Q1 2020, the impact of the COVID-19 pandemic and resulting government measures to address this pandemic have resulted in economic slowdowns in all markets served by Emera. Currently, COVID-19 has not had a material financial impact on the Company. Refer to the “Outlook” section for discussion by utility. The impact of COVID-19 may result in decreased cash flow from operations due to the potential of lower sales and slower collection of accounts receivable. The extent of the future impact of COVID-19 on the Company’s operating cash flow cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. The Company currently expects to continue to have adequate liquidity given its cash position, existing bank facilities, and access to capital, but will continue to monitor the impact of COVID-19 on future cash flows.

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has a $7.5 billion capital investment plan over the 2020-to-2022 period and the potential for additional capital opportunities of $200 million to $500 million over the forecast period. This plan includes significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. Capital expenditures at the regulated utilities are subject to regulatory approval. The extent of the future impact of COVID-19 on the profile of the Company’s capital plan cannot be predicted at this time due to reasons discussed earlier. The Company possesses flexibility with respect to its capital investment plan and will continue to monitor current events and related impacts of COVID-19.

Emera plans to use cash from operations, debt raised at the utilities and proceeds from the Emera Maine sale, to support normal operations, repayment of existing debt and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital investment plan will predominantly be funded in the equity capital markets through the dividend reinvestment plan and the issuance of common and preferred equity. The Company’s future access to capital may be impacted by possible continued COVID-19 related market disruptions. Refer to the “Risk Management and Financial Instruments” section for updated risk disclosure.

As at March 31, 2020, the Company was holding a cash balance of $1.6 billion. Emera also has credit facilities with varying maturities that cumulatively provide $3.8 billion of credit, with approximately $1.3 billion undrawn and available at March 31, 2020. Refer to the “Debt Management” section below for further details. Refer to notes 19 and 20 in the condensed consolidated financial statements for additional information regarding the credit facilities.

As at March 31, 2020, Emera had $155 million CAD ($109 million USD) in receivables related to the expected refund of alternative minimum tax credit carryforwards. Under the provisions of the United States Coronavirus Aid, Relief, and Economic Security (CARES) Act, Emera’s US businesses are allowed to secure their remaining AMT credits in their 2019 filings. The Company has filed for this refund and expects to receive it in 2020.

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Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 2020 and 2019 include:

millions of Canadian dollars	2020			2019			Change
Cash, cash equivalents, restricted cash and assets held for sale, beginning of period	$	274		$	372		$	(98	)
Provided by (used in):
Operating cash flow before change in working capital		502			418			84
Change in working capital		(74	)		(16	)		(58	)
Operating activities		428			402			26
Investing activities		746			298			448
Financing activities		165			(35	)		200
Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash included in assets held for sale		(6	)		(5	)		(1	)
Cash, cash equivalents, and restricted cash, end of period	$	1,607		$	1,032		$	575

Cash Flow from Operating Activities

Net cash provided by operating activities increased $26 million to $428 million for the three months ended March 31, 2020, compared to $402 million for the same period in 2019.

Cash from operations before changes in working capital increased $84 million. The increase was primarily due to higher over-recovery from customers on clause related costs at Tampa Electric.

Changes in working capital decreased operating cash flows by $58 million. The decrease was due to unfavourable changes in cash collateral at Emera Energy and NSPI. This was partially offset by timing of accounts payable at NSPI and Tampa Electric, and decreased fuel inventory at NSPI.

Cash Flow used in Investing Activities

Net cash provided by investing activities increased $448 million to $746 million for the three months ended March 31, 2020, compared to $298 million for the same period in 2019. In 2020, Emera received proceeds of $1.4 billion on the sale of Emera Maine compared to proceeds of $861 million on dispositions in 2019, primarily from the sale of the NEGG and Bayside facilities. This increase in proceeds was partially offset by higher capital expenditures in Q1 2020.

Capital expenditures for the three months ended March 31, 2020, including AFUDC, were $663 million compared to $561 million for the same period in 2019. Details of the 2020 capital spend by segment are shown below:

• $356 million - Florida Electric Utility (2019 – $306 million);

• $93 million - Canadian Electric Utilities (2019 – $71 million);

• $46 million - Other Electric Utilities (2019 – $38 million);

• $167 million - Gas Utilities and Infrastructure (2019 – $94 million); and

• $1 million - Other (2019 – $52 million).

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Cash Flow from Financing Activities

Net cash provided by financing activities increased $200 million to $165 million for the three months ended March 31, 2020, compared to net cash used in financing activities of $35 million for the same period in 2019. The increase was due to proceeds from committed credit facilities at Tampa Electric, the 2019 net repayment of Emera’s committed credit facilities and issuance of common shares under Emera’s ATM program. These were partially offset by repayment of debt at TECO Finance.

Contractual Obligations

As at March 31, 2020, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2020		2021		2022		2023		2024		Thereafter		Total
Long-term debt principal	$	83	$	1,821	$	449	$	833	$	1,065	$	10,644	$	14,895
Interest payment obligations (1)		617		638		602		576		556		7,141		10,130
Purchased power (2)		197		218		247		268		282		1,993		3,205
Transportation (3)		423		429		374		312		288		2,999		4,825
Pension and post-retirement obligations (4)		20		33		29		29		98		261		470
Capital projects (5)		414		135		111		94		-		-		754
Fuel, gas supply and storage		363		133		28		5		1		-		530
Asset retirement obligations		2		35		1		1		1		366		406
Long-term service agreements (6)		62		23		22		19		19		71		216
Equity investment commitments (7)		-		240		-		-		-		-		240
Leases and other (8)		13		20		20		18		19		114		204
Demand side management		24		41		43		-		-		-		108
Long-term payable		4		5		5		5		-		-		19
	$	2,222	$	3,771	$	1,931	$	2,160	$	2,329	$	23,589	$	36,002

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2020, including any expected required payment under associated swap agreements.

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

(3) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.

(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.

(5) Includes $485 million of commitments related to Tampa Electric’s solar, Big Bend Power Station modernization and AMI projects.

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

(7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership.

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

On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor has declared force majeure under various project contracts, including formal notification to NSPML. Due to the unpredictable nature of the COVID-19 pandemic, Nalcor is currently unable to provide an updated completion schedule for Muskrat Falls or LIL until there is greater certainty. Nalcor has expressed its desire to resume work at site as soon as it is safe to do so for its employees, contractors and associated communities.

NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls. NSPML anticipates making an application with the UARB in 2020 with respect to recovery of 2021 costs.

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NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years from its January 15, 2018 in-service date. The UARB approved payment for 2020 is $145 million subject to a $10 million holdback and as at March 31, 2020, $26 million has been paid. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include the $145 million approved for 2020 and estimated amounts of $164 million and $162 million for 2021 and 2022, respectively. These estimated amounts are subject to review and approval by the UARB. The timing and amounts payable to NSPML for the remainder of the 37-year commitment period are dependent on regulatory filings with the UARB.

Emera has committed to obtain certain transmission rights for Nalcor Energy, if requested, to enable them to transmit energy which is not otherwise used in Newfoundland or Nova Scotia. This energy could be transmitted from Nova Scotia to New England energy markets beginning at first commercial power of the Muskrat Falls hydroelectric generating facility and related transmission assets when Nalcor commences delivery of the NS Block, and continuing for 50 years. As transmission rights are contracted, Emera includes the obligations within “Leases and other” in the above table.

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $3.8 billion committed syndicated revolving bank lines of credit in either CAD or USD per the table below.

millions of dollars	Maturity		Revolving Credit Facilities		Utilized		Undrawn and Available
Emera Inc. – Unsecured committed revolving credit facility		June 2024	$	900	$	453	$	447
Emera Inc. – Unsecured non-revolving facility		December 2020		400		400		-
TECO Finance, Inc. – in USD – Unsecured committed revolving credit facility		March 2022		400		360		40
TECO Finance, Inc. – in USD – Unsecured non-revolving facility		July 2020		500		500		-
NSPI – Unsecured committed revolving credit facility		October 2024		600		398		202
TEC – in USD – Unsecured committed revolving credit facility (1)		March 2022		400		31		369
TEC – in USD – Accounts receivable collateralized borrowing facility (1)		March 2021		150		74		76
TEC – in USD – Unsecured non-revolving facility (1)		February 2021		300		300		-
NMGC – in USD – Unsecured committed revolving credit facility		March 2022		125		1		124
Other – in USD – Unsecured committed revolving credit facilities		Various		32		22		10

(1) These facilities are available for use by Tampa Electric and PGS. At March 31, 2020, Tampa Electric had utilized $313 million USD and PGS had utilized $92 million USD of the facilities.

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly, and the Company is in compliance with its covenant requirements as at March 31, 2020.

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

Florida Electric Utilities

On February 6, 2020, TEC entered into a $300 million USD non-revolving credit agreement with a maturity date of February 4, 2021. The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at LIBOR, prime rate or the federal funds rate, plus a margin.

Canadian Electric Utilities

On April 24, 2020, NSPI completed a $300 million 30-year unsecured notes issuance. The notes bear interest at a rate of 3.31 per cent and have a maturity date of April 25, 2050.

Other Electric Utilities

On February 19, 2020, BLPC received its first advance of $40 million BBD ($20 million USD) on a $110 million BBD ($55 million USD) non-revolving term loan. The loan bears interest at a rate of 2.05 per cent and has a 5-year term.

Other

On April 3, 2020, TECO Energy/Finance repaid $200 million USD of its $500 million Non-Revolving Term Loan that is due to mature on July 3, 2020. This partial repayment was made from proceeds of the Emera Maine sale.

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

On February 28, 2020, TECO Energy/Finance extended the maturity date of its $500 million USD credit facility from March 5, 2020 to July 3, 2020. There were no other significant changes in commercial terms from the prior agreement.

Credit Ratings

On March 24, 2020, S&P changed its issuer rating for Emera and TECO to BBB from BBB+ and at the same time changed the outlook on both to stable from negative. S&P also affirmed its BBB+ issuer ratings for TEC and NSPI and changed the outlook on both to stable from negative.

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2019 audited annual consolidated financial statements, with an update as noted below:

The Company has standby letters of credit and surety bonds in the amount of $74 million USD (December 31, 2019—$82 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.

The Company is in the process of issuing a guarantee of up to $60 million USD relating to outstanding notes of GBPC. The guarantee will reduce to no more than $35 million USD upon repayment of certain notes that are due May 22, 2020.

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TRANSACTIONS WITH RELATED PARTIES

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

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

• Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $28 million for the three months ended March 31, 2020 (2019—$27 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.

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

• Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $8 million for the three months ended March 31, 2020 (2019 - $18 million).

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

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2019 annual MD&A, except for the following:

Public Health Risk

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

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

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

Hedging Items Recognized on the Balance Sheets

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

As at millions of Canadian dollars	March 31 2020			December 31 2019
Derivative instrument liabilities (current and long-term liabilities)	$	(3	)	$	(1	)
Net derivative instrument liabilities	$	(3	)	$	(1	)

Hedging Impact Recognized in Net Income

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

For the	Three months ended March 31
millions of Canadian dollars	2020			2019
Operating revenues – regulated	$	(1	)	$	(2	)
Effective net losses	$	(1	)	$	(2	)

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

Regulatory Items Recognized on the Balance Sheets

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

As at	March 31			December 31
millions of Canadian dollars	2020			2019
Derivative instrument assets (current and other assets)	$	49		$	28
Regulatory assets (current and other assets)		131			80
Derivative instrument liabilities (current and long-term liabilities)		(131	)		(78	)
Regulatory liabilities (current and long-term liabilities)		(56	)		(42	)
Net liability	$	(7	)	$	(12	)

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Regulatory Impact Recognized in Net Income

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

For the	Three months ended March 31
millions of Canadian dollars	2020			2019
Regulated fuel for generation and purchased power (1)	$	(5	)	$	4
Net gains (losses)	$	(5	)	$	4

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

HFT Items Recognized on the Balance Sheets

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

As at	March 31			December 31
millions of Canadian dollars	2020			2019
Derivative instrument assets (current and other assets)	$	64		$	58
Derivative instrument liabilities (current and long-term liabilities)		(183	)		(291	)
Net derivative instrument liability	$	(119	)	$	(233	)

HFT Items Recognized in Net Income

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

For the	Three months ended March 31
millions of Canadian dollars	2020			2019
Operating revenues – non-regulated	$	212		$	149
Non-regulated fuel for generation and purchased power		(4	)		(2	)
Net gains	$	208		$	147

Other Derivatives Recognized on the Balance Sheets

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

As at	March 31			December 31
millions of Canadian dollars	2020			2019
Derivative instrument assets (current and other assets)	$	2		$	1
Derivative instrument liabilities (current and long-term liabilities)		(11	)		-
Net derivative instrument assets (liabilities)	$	(9	)	$	1

Other Derivatives Recognized in Net Income

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

For the millions of Canadian dollars	Three months ended March 31
	2020			2019
Operating, maintenance and general	$	(1	)	$	14
Other income (expense)		(10	)		-
Total gains (losses)	$	(11	)	$	14

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DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The Company’s internal control framework is based on the criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at March 31, 2020, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

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

There were no changes in the Company’s ICFR during the quarter ended March 31, 2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, capitalized overhead and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Management has analyzed the impact of the COVID-19 pandemic on its estimates and judgements and concluded that no material adjustments are required at March 31, 2020.

Goodwill Impairment Assessments

Management considered whether the potential impacts of the COVID-19 pandemic on future earnings required testing for goodwill impairment in Q1 2020 and determined that it is more likely than not that the fair value of reporting units that include goodwill exceeded their respective carrying amounts as of March 31, 2020.

As of March 31, 2020, $6.3 billion of Emera’s goodwill was related to TECO Energy (Tampa Electric, PGS and NMGC reporting units). Given the significant excess of fair value over carrying amounts calculated for these reporting units as of the last quantitative test performed in Q4 2019, management does not expect the COVID-19 pandemic to have an impact on the goodwill associated with these reporting units.

As of March 31, 2020, $76 million of Emera’s goodwill was related to GBPC. The calculated goodwill for this reporting unit is more sensitive to changes in forecasted future earnings. Adverse impacts to earnings in the future as a result of COVID-19 could cause impairment, however, the impact of COVID-19 on future earnings cannot be reasonably determined or estimated at this time. No impairment has been recorded in Q1 2020.

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Long-Lived Assets Impairment Assessments

Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at March 31, 2020, there are no indications of impairment of Emera’s long-lived assets. The impact of COVID-19 could cause the Company to impair long-lived assets in the future, however, there is currently no indication that future cash flows would be impacted to a point where the Company’s long-lived assets would not be recoverable.

Impairment charges of $22 million ($23 million after tax) were recognized on certain assets in Q1 2020.

Pension and Other Post-Retirement Employee Benefits

The COVID-19 pandemic could impact key actuarial assumptions used to account for employee post-retirement benefits including the anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation, benefit costs and annual pension funding requirements. Fluctuations in actual equity market returns and changes in interest rates as a result of the COVID-19 pandemic may also result in changes to pension costs and funding in future periods.

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these estimates.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2020, are described as follows:

Measurement of Credit Losses on Financial Instruments

The Company adopted Accounting Standard Update (“ASU”) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. The adoption of the standard resulted in a $7 million decrease to retained earnings in the condensed consolidated financial statements as of January 1, 2020.

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Future Accounting Pronouncements

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

Facilitation of the Effects of Reference Rate Reform on Financial Reporting

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The standard provides optional expedients and exceptions for applying USGAAP to contract modifications and hedging relationships that reference LIBOR or another rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The Company is currently evaluating the impact of adoption of the standard, if elected, on its consolidated financial statements.

SUMMARY OF QUARTERLY RESULTS

For the quarter ended millions of dollars	Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2
(except per share amounts)	2020		2019		2019		2019		2019		2018		2018		2018
Operating revenues	$	1,637	$	1,616	$	1,299	$	1,378	$	1,818	$	1,799	$	1,495	$	1,423
Net income attributable to common shareholders		523		193		55		103		312		231		118		90
Adjusted net income attributable to common shareholders		193		145		122		130		224		167		191		111
Earnings per common share - basic		2.14		0.79		0.23		0.43		1.32		0.98		0.51		0.38
Earnings per common share - diluted		2.13		0.80		0.23		0.43		1.32		0.98		0.50		0.38
Adjusted earnings per common share - basic		0.79		0.60		0.51		0.54		0.95		0.71		0.82		0.48

Quarterly operating revenues and adjusted net income attributable to common shareholders are affected by seasonality. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the “Significant Items Affecting Earnings” section. In 2020, quarterly results may also be affected by the impact of the COVID-19 pandemic. Refer to the “Business Overview and Outlook” section for further details.

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