Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2020 and 2019

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Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2020		2019
Operating revenues
Regulated electric	$	1,194	$	1,169
Regulated gas		331		352
Non-regulated		112		297
Total operating revenues (note 6)		1,637		1,818
Operating expenses
Regulated fuel for generation and purchased power		410		401
Regulated cost of natural gas		109		136
Non-regulated fuel for generation and purchased power		4		64
Operating, maintenance and general		378		366
Provincial, state and municipal taxes		84		85
Depreciation and amortization		231		224
Total operating expenses		1,216		1,276
Income from operations		421		542
Income from equity investments (note 7)		41		40
Other income (expenses), net (note 8)		563		13
Interest expense, net		184		189
Income before provision for income taxes		841		406
Income tax expense (note 9)		306		82
Net income		535		324
Non-controlling interest in subsidiaries		1		1
Preferred stock dividends		11		11
Net income attributable to common shareholders	$	523	$	312
Weighted average shares of common stock outstanding (in millions) (note 11)
Basic		244.7		236.4
Diluted		245.2		237.0
Earnings per common share (note 11)
Basic	$	2.14	$	1.32
Diluted	$	2.13	$	1.32
Dividends per common share declared	$	0.6125	$	0.5875

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

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Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

For the	Three months ended March 31
millions of Canadian dollars	2020			2019
Net income	$	535		$	324
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment (1)		761			(163	)
Unrealized gains (losses) on net investment hedges (2)(3)		(141	)		34
Cash flow hedges
Net derivative gains		(3	)		2
Less: reclassification adjustment for gains included in income		1			2
Net effects of cash flow hedges		(2	)		4
Net change in unrecognized pension and post-retirement benefit obligation (4)		(5	)		4
Other comprehensive income (loss) (5)		613			(121	)
Comprehensive income		1,148			203
Comprehensive income attributable to non-controlling interest		2			1
Comprehensive Income of Emera Incorporated	$	1,146		$	202

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

1) Net of tax expense of $13 million (2019 - nil) for the three months ended March 31, 2020.

2) The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations.

3) Net of tax recovery of $1 million (2019 - nil) for the three months ended March 31, 2020.

4) Net of tax expense of nil (2019 - $1 million expense) for the three months ended March 31, 2020.

5) Net of tax expense of $12 million (2019 - $1 million tax expense) for the three months ended March 31, 2020.

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Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

As at millions of Canadian dollars	March 31 2020		December 31 2019
Assets
Current assets
Cash and cash equivalents	$	1,553	$	222
Restricted cash (note 23)		54		51
Inventory		431		467
Derivative instruments (notes 13 and 14)		68		54
Regulatory assets (note 15)		156		121
Receivables and other current assets (note 17)		1,605		1,486
Assets held for sale (note 4)		-		85
		3,867		2,486
Property, plant and equipment, net of accumulated depreciation and amortization of $8,927 and $8,295, respectively		19,846		18,167
Other assets
Deferred income taxes		144		186
Derivative instruments (notes 13 and 14)		47		33
Regulatory assets (note 15)		1,464		1,431
Net investment in direct financing lease		477		473
Investments subject to significant influence (note 7)		1,336		1,312
Goodwill		6,373		5,835
Other long-term assets		302		300
Assets held for sale (note 4)		-		1,619
		10,143		11,189
Total assets	$	33,856	$	31,842

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Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued

As at millions of Canadian dollars	March 31 2020		December 31 2019
Liabilities and Equity
Current liabilities
Short-term debt (note 19)	$	2,211	$	1,537
Current portion of long-term debt (note 20)		379		501
Accounts payable		1,022		1,118
Derivative instruments (notes 13 and 14)		215		268
Regulatory liabilities (note 15)		310		295
Other current liabilities		486		333
Liabilities associated with assets held for sale (note 4)		-		114
		4,623		4,166
Long-term liabilities
Long-term debt (note 20)		14,398		13,679
Deferred income taxes		1,614		1,285
Derivative instruments (notes 13 and 14)		113		102
Regulatory liabilities (note 15)		2,088		1,886
Pension and post-retirement liabilities (note 18)		481		460
Other long-term liabilities		834		764
Long-term liabilities associated with assets held for sale (note 4)		-		899
		19,528		19,075
Equity
Common stock (note 10)		6,340		6,216
Cumulative preferred stock		1,004		1,004
Contributed surplus		78		78
Accumulated other comprehensive income (note 12)		707		95
Retained earnings		1,540		1,173
Total Emera Incorporated equity		9,669		8,566
Non-controlling interest in subsidiaries		36		35
Total equity		9,705		8,601
Total liabilities and equity	$	33,856	$	31,842

Commitments and contingencies (note 21)

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

Approved on behalf of the Board of Directors

“M. Jacqueline Sheppard”	“Scott Balfour”
Chair of the Board	President and Chief Executive Officer

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Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the	Three months ended March 31
millions of Canadian dollars	2020		2019
Operating activities
Net income	$	535	$	324
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		235		228
Income from equity investments, net of dividends		(19)		(22)
Allowance for equity funds used during construction		(9)		(4)
Deferred income taxes, net		352		68
Net change in pension and post-retirement liabilities		(6)		(3)
Regulated fuel adjustment mechanism		(3)		(4)
Net change in fair value of derivative instruments		(95)		(114)
Net change in regulatory assets and liabilities		15		(7)
Net change in capitalized transportation capacity		62		(25)
Gain on sale (excluding transaction costs) and impairment charges		(582)		—
Other operating activities, net		17		(23)
Changes in non-cash working capital (note 22)		(74)		(16)
Net cash provided by operating activities		428		402
Investing activities
Proceeds from dispositions (note 4)		1,403		861
Additions to property, plant and equipment		(654)		(557)
Other investing activities		(3)		(6)
Net cash provided by investing activities		746		298
Financing activities
Change in short-term debt, net		156		188
Proceeds from short-term debt with maturities greater than 90 days		399		—
Proceeds from long-term debt, net of issuance costs		57		—
Retirement of long-term debt		(436)		(9)
Net borrowings (repayments) under committed credit facilities		29		(142)
Issuance of common stock, net of issuance costs		77		32
Dividends on common stock		(104)		(90)
Dividends on preferred stock		(11)		(11)
Other financing activities		(2)		(3)
Net cash provided by (used in) financing activities		165		(35)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(6)		(5)
Net increase in cash, cash equivalents and restricted cash		1,333		660
Cash, cash equivalents, restricted cash and assets held for sale, beginning of period		274		372
Cash, cash equivalents and restricted cash, end of period	$	1,607	$	1,032
Cash, cash equivalents, and restricted cash consists of:
Cash	$	1,553	$	332
Short-term investments		—		647
Restricted cash		54		53
Cash, cash equivalents, and restricted cash	$	1,607	$	1,032

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

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Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss) (“AOCI”)		Retained Earnings		Non- Controlling Interest		Total Equity
For the three months ended March 31, 2020
Balance, December 31, 2019	$	6,216	$	1,004	$	78	$	95	$	1,173	$	35	$	8,601
Net income of Emera Incorporated		-		-		-		-		534		1		535
Other comprehensive income (loss), net of tax expense of $12 million		-		-		-		612		-		1		613
Dividends declared on preferred stock (1)		-		-		-		-		(11)		-		(11)
Dividends declared on common stock ($0.6125/share)		-		-		-		-		(149)		-		(149)
Common stock issued under purchase plan		48		-		-		-		-		-		48
Issuance of common stock, net of after-tax issuance costs		58		-		-		-		-		-		58
Senior management stock options exercised		17		-		(1)		-		-		-		16
Adoption of credit losses accounting standard (note 2)										(7)				(7)
Other		1		-		1		-				(1)		1
Balance, March 31, 2020	$	6,340	$	1,004	$	78	$	707	$	1,540	$	36	$	9,705
millions of Canadian dollars
Balance, December 31, 2018	$	5,816	$	1,004	$	84	$	338	$	1,075	$	41	$	8,358
Net income of Emera Incorporated		-		-		-		-		323		1		324
Other comprehensive income (loss), net of tax expense of $1 million		-		-		-		(121)		-		-		(121)
Dividends declared on preferred stock (2)		-		-		-		-		(11)		-		(11)
Dividends declared on common stock ($0.5875/share)		-		-		-		-		(138)		-		(138)
Common stock issued under purchase plan		51		-		-		-		-		-		51
Senior management stock option exercised		32		-		(2)		-		-		-		30
Other		-		-		-		-		-		(2)		(2)
Balance, March 31, 2019	$	5,899	$	1,004	$	82	$	217	$	1,249	$	40	$	8,491

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

(1)    Series A; $0.1597/share, Series B; $0.2190/share, Series C; $.29506/share, Series E; $0.28125/share, Series F; $0.265625/share and Series H; $0.30625/share

(2)    Series A; $0.1597/share, Series B; $0.2206/share, Series C; $.29506/share, Series E; $0.28125/share, Series F; $0.265625/share and Series H; $0.30625/share

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Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at March 31, 2020 and 2019

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

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

At March 31, 2020, Emera’s reportable segments include the following:

• Florida Electric Utility, which consists of Tampa Electric, a vertically integrated regulated electric utility in West Central Florida.

• Canadian Electric Utilities, which includes:

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

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

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

• a 49.5 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and Nalcor recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL, however, there has been a suspension of on-site commissioning in response to the COVID-19 pandemic. On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the novel coronavirus COVID-19 (“COVID-19”) pandemic. Refer to note 21 for further details.

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

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

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

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

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

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

• Gas Utilities and Infrastructure, which includes:

• Peoples Gas System (“PGS”), a regulated gas distribution utility operating across Florida;

• New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico;

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

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

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

At March 31, 2020, Emera’s investments in other energy-related non-regulated companies (included within the Other reportable segment) include the following:

• Emera Energy, which consists of:

• Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;

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

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

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

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

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

• other investments.

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

Basis of Presentation

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

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

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

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Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, 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.

In Q1 2020, the ongoing COVID-19 pandemic impacted all the service territories in which Emera operates. Currently, 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. 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.

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.

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.

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Pension and Other Post-Retirement Employee Benefits

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

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

Seasonal Nature of Operations

Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity and gas sales, and related transmission and distribution, vary over the year. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Certain quarters may also be impacted by weather and the number and severity of storms. In 2020, quarterly results may also be affected by the impact of the COVID-19 pandemic.

Receivables and Allowance for Doubtful Accounts

Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit assessments may be conducted on new customers. Deposits are requested on accounts as required. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis.

Management estimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.

The potential future economic impact of COVID-19, in the service territories in which Emera operates, may impact the collectability of customer receivables.

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2. CHANGE IN ACCOUNTING POLICY

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

Measurement of Credit Losses on Financial Instruments

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

3.   FUTURE ACCOUNTING PRONOUNCEMENTS

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

Facilitation of the Effects of Reference Rate Reform on Financial Reporting

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

4.   DISPOSITIONS

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of approximately $2.0 billion including cash proceeds of $1.4 billion, transferred debt and a working capital adjustment. A gain on disposition of $586 million ($321 million after tax) net of transaction costs, was recognized in the Other segment and included in “Other income” on the Condensed Consolidated Statements of Income.

Emera Maine’s assets and liabilities were classified as held for sale at March 25, 2019. The Company continued recording depreciation on these assets through the transaction closing date, as the depreciation continued to be reflected in customer rates and was reflected in the carryover basis of the assets on completion of the sale. A total of $53 million of depreciation and amortization was recorded on these assets from March 25, 2019, the date they were classified as held for sale, until the date of the sale. $39 million of the $53 million was recorded in 2019. Emera Maine’s assets and liabilities were included in the Company’s Other Electric Utilities segment.

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5.  SEGMENT INFORMATION

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

millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations			Total
For the three months ended March 31, 2020
Operating revenues from external customers (1)	$	565	$	458	$	171	$	334	$	109	$	-		$	1,637
Inter-segment revenues (1)		2		-		-		3		4		(9)			-
Total operating revenues		567		458		171		337		113		(9)			1,637
Regulated fuel for generation and purchased  power		142		204		67		-		-		(3)			410
Regulated cost of natural gas		-		-		-		109		-		-			109
Depreciation and amortization		116		58		28		27		2		-			231
Interest expense, net		40		35		13		15		82		(1)			184
Internally allocated interest (2)		-		-		-		3		(3)		-			-
Operating, maintenance and general (“OM&G”)		138		79		47		84		35		(5)			378
Gain on sale and impairment charges		-		-		-		-		564		-			564
Income tax expense (recovery)		14		8		(8)		22		270		-			306
Net income attributable to common shareholders		79		92		17		70		265		-			523
As at March 31, 2020
Total assets		18,008		6,879		1,534		6,026		2,598		(1,189)	(3)		33,856
For the three months ended March 31, 2019
Operating revenues from external customers (1)		545		442		182		356		294		-			1,819
Inter-segment revenues (1)		3		1		-		6		10		(21)			(1)
Total operating revenues		548		443		182		362		304		(21)			1,818
Regulated fuel for generation and purchased  power		152		188		66		-		-		(5)			401
Regulated cost of natural gas		-		-		-		136		-		-			136
Depreciation and amortization		109		56		29		27		3		-			224
Interest expense, net		38		35		13		16		87		-			189
Internally allocated interest (2)		-		-		-		3		(3)		-			-
OM&G		133		74		49		78		45		(13)			366
Income tax expense (recovery)		13		8		3		21		37		-			82
Net income attributable to common shareholders		61		96		18		67		70		-			312
As at December 31, 2019
Total assets		16,214		6,717		3,069		5,489		1,459		(1,106)	(3)		31,842

(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs.

(3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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6.   REVENUE

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

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

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

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

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

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

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millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations			Total
For the three months ended March 31, 2019
Regulated
Electric Revenue
Residential	$	274	$	252	$	68	$	-	$	-	$	-		$	594
Commercial		160		113		80		-		-		-			353
Industrial		46		55		12		-		-		-			113
Other electric and regulatory deferrals		62		16		3		-		-		-			81
Other (1)		6		7		19		-		-		(4)			28
Regulated electric revenue		548		443		182		-		-		(4)			1,169
Gas Revenue
Residential		-		-		-		189		-		-			189
Commercial		-		-		-		98		-		-			98
Industrial		-		-		-		12		-		-			12
Finance income (2)(3)		-		-		-		14		-		-			14
Other		-		-		-		45		-		(6)			39
Regulated gas revenue		-		-		-		358		-		(6)			352
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		54		-			54
Energy sales (4)		-		-		-		-		78		(4)			74
Capacity		-		-		-		-		38		-			38
Other		-		-		-		4		10		(7)			7
Mark-to-market (3)		-		-		-		-		124		-			124
Non-regulated revenue		-		-		-		4		304		(11)			297
Total operating revenues	$	548	$	443	$	182	$	362	$	304		$          (21	)	$	1,818

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

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

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

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

Remaining Performance Obligations

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of March 31, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was $368 million (December 31, 2019 – $347 million). As allowed by the practical expedient in ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2033.

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7.  INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

	Carrying Value as at				Equity Income For the three months ended March 31				Percentage of Ownership
	March 31		December 31
millions of Canadian dollars	2020		2019		2020		2019		2020
LIL (1)	$	591	$	579	$	12	$	11		49.5
NSPML		557		554		15		14		100.0
M&NP (2)		143		138		5		6		12.9
Lucelec (2)		45		41		1		1		19.5
Bear Swamp (3)		-		-		8		8		50.0
	$	1,336	$	1,312	$	41	$	40

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

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

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $145 million (2019 - $137 million) is recorded in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 23). NSPML’s consolidated summarized balance sheet is as follows:

As at	March 31		December 31
millions of Canadian dollars	2020		2019
Balance Sheet
Current assets	$	80	$	69
Property, plant and equipment		1,660		1,671
Regulatory assets		188		177
Non-current assets		32		32
Total assets	$	1,960	$	1,949
Current liabilities	$	32	$	23
Long-term debt		1,288		1,288
Non-current liabilities		83		84
Equity		557		554
Total liabilities and equity	$	1,960	$	1,949

8.  OTHER INCOME (EXPENSES), NET

For the	Three months ended March 31
millions of Canadian dollars	2020			2019
Gain on sale and impairment charges (1)	$	564		$	-
Allowance for equity funds used during construction		9			4
Other		(10	)		9
	$	563		$	13

(1) Refer to note 4 for further details related to the gain on sale    

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9.  INCOME TAXES

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

For the	Three months ended March 31
millions of Canadian dollars	2020		2019
Income before provision for income taxes	$	841	$	406
Statutory income tax rate		29.5%		31%
Income taxes, at statutory income tax rate		248		126
Additional impact from the sale of Emera Maine		92		-
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(21)		(21)
Amortization of deferred income tax regulatory liabilities		(16)		(9)
Revaluation of deferred income taxes due to change in Nova Scotia tax rate		12		-
Foreign tax rate variance		(9)		(12)
Other		-		(2)
Income tax expense	$	306	$	82
Effective income tax rate		36%		20%

The increase in the effective income tax rate was primarily due to the sale of Emera Maine and the revaluation of deferred income taxes as a result of the decrease in the Nova Scotia provincial corporate income tax rate, as discussed below.

On March 10, 2020, Bill 243 of the Nova Scotia Financial Measures (2020) Act (“the Financial Measures Act”) was enacted, which included a reduction in the Nova Scotia provincial corporate income tax rate from 16% to 14%. As a result, the Company’s combined Canadian federal and provincial statutory income tax rate was reduced from 31% to 29.5% for 2020 and further reduced to 29% for subsequent years.

As a result of the enactment of the Financial Measures Act, the Company was required to revalue certain of its Canadian deferred income tax assets and liabilities based on the new tax rates. The Company recorded a reduction of $52 million to its net deferred income tax liabilities and an offsetting reduction to its net deferred income tax regulatory asset, as the benefit of lower net deferred income tax liabilities is expected to be returned to customers in future years. The Company also recognized a $12 million income tax expense in Q1 2020 as a result of the revaluation of certain net deferred income tax assets.

On March 25, 2020, Bill C-13, the Canadian COVID-19 Emergency Response Act (“the COVID-19 Act”) was enacted, guaranteeing rapid implementation and administration of measures to protect Canadians’ health and safety, and stabilize the economy. In addition, the Government of Canada announced the opportunity for businesses to defer certain tax payments. The Company does not anticipate any material impacts from the COVID-19 Act or the Government of Canada’s additional announcements.

On March 27, 2020, the United States Coronavirus Aid, Relief, and Economic Security (CARES) Act (“the CARES Act”) was signed into legislation. The CARES Act includes several business provisions including deferral of employer payroll taxes, an employee retention payroll tax credit, temporary changes to business interest expense disallowance rules, changes to net operating loss carryback and limitation rules and corporate alternative minimum tax (“AMT”) relief. Under the new AMT provisions, companies can accelerate the refund of AMT credit carryforwards. In Q1 2020, the Company reclassified $77 million of AMT credit carryforwards from deferred income tax assets to receivables and other current assets as it expects to receive the refund in 2020. The Company does not anticipate any other material impacts from the CARES Act.

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10.  COMMON STOCK

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

Issued and outstanding:	millions of shares		millions of Canadian dollars
Balance, December 31, 2019		242.48		$                6,216
Issuance of common stock (1)		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 share 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.

11.  EARNINGS PER SHARE

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

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2020		2019
Numerator
Net income attributable to common shareholders	$	523.1	$	311.8
Diluted numerator		523.1		311.8
Denominator
Weighted average shares of common stock outstanding		243.4		234.9
Weighted average deferred share units outstanding		1.3		1.5
Weighted average shares of common stock outstanding – basic		244.7		236.4
Stock-based compensation		0.5		0.5
Convertible Debentures		-		0.1
Weighted average shares of common stock outstanding – diluted		245.2		237.0
Earnings per common share
Basic	$	2.14	$	1.32
Diluted	$	2.13	$	1.32

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12.   ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

millions of Canadian dollars	Unrealized (loss) gain on translation of self-sustaining foreign operations		Net change in net investment hedges		(Losses) gains on derivatives recognized as cash flow hedges		Net change in available-for- sale investments		Net change in unrecognized pension and post- retirement benefit costs		Total AOCI
For the three months ended March 31, 2020
Balance, January 1, 2020	$	253	$	4	$	(1)	$	(1)	$	(160)	$	95
Other comprehensive income (loss) before reclassifications		760		(141)		(3)		-		-		616
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		1		-		(5)		(4)
Net current period other comprehensive income (loss)		760		(141)		(2)		-		(5)		612
Balance, March 31, 2020	$	1,013	$	(137)	$	(3)	$	(1)	$	(165)	$	707
For the three months ended March 31, 2019
Balance, January 1, 2019	$	654	$	(74)	$	(7)	$	(1)	$	(234)	$	338
Other comprehensive income (loss) before reclassifications		(163)		34		2		-		-		(127)
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		2		-		4		6
Net current period other comprehensive income (loss)		(163)		34		4		-		4		(121)
Balance, March 31, 2019	$	491	$	(40)	$	(3)	$	(1)	$	(230)	$	217

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

For the		Three months ended March 31
millions of Canadian dollars		2020		2019
	Affected line item in the Consolidated Financial Statements	Amounts reclassified from AOCI
Losses (gain) on derivatives recognized as cash flow hedges
Foreign exchange forwards	Operating revenue - regulated	$	1	$	2
Total		$	1		2
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses (gains)	OM&G	$	3	$	5
Amounts reclassified into obligations	Pension and post-retirement benefits		(8)		-
Total before tax			(5)		5
	Income tax recovery (expense)		-		(1)
Total net of tax		$	(5)	$	4
Total reclassifications out of AOCI, net of tax, for the period		$	(4)	$	6

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13.  DERIVATIVE INSTRUMENTS

The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:

• commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations;

• foreign exchange fluctuations on foreign currency denominated purchases and sales

• interest rate fluctuations on debt securities; and

• share price fluctuations on stock-based compensation.

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

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

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

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

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

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

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

	Derivative Assets				Derivative Liabilities
As at	March 31		December 31		March 31		December 31
millions of Canadian dollars	2020		2019		2020		2019
Cash flow hedges
Foreign exchange forwards	$	-	$	-	$	3	$	1
		-		-		3		1
Regulatory deferral
Commodity swaps and forwards
Coal purchases		14		8		49		39
Power purchases		12		23		57		36
Natural gas purchases and sales		2		2		8		5
Heavy fuel oil purchases		-		1		31		-
Foreign exchange forwards		35		2		-		6
		63		36		145		86
HFT derivatives
Power swaps and physical contracts		21		19		27		22
Natural gas swaps, futures, forwards, physical contracts		138		151		251		381
		159		170		278		403
Other derivatives
Equity derivatives and interest rate swaps		1		1		-		-
Foreign exchange forwards		1		-		11		-
		2		1		11		-
Total gross current derivatives		224		207		437		490
Impact of master netting agreements with intent to settle net or simultaneously		(109)		(120)		(109)		(120)
		115		87		328		370
Current		68		54		215		268
Long-term		47		33		113		102
Total derivatives	$	115	$	87	$	328	$	370

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

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

	Derivative Assets				Derivative Liabilities
As at	March 31		December 31		March 31		December 31
millions of Canadian dollars	2020		2019		2020		2019
Regulatory deferral	$	14	$	8	$	14	$	8
HFT derivatives		95		112		95		112
Total impact of master netting agreements with intent to settle net or simultaneously	$	109	$	120	$	109	$	120

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Cash Flow Hedges

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

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

For the millions of Canadian dollars	Three months ended March 31
	2020		2019
		Foreign exchange forwards
Realized gain (loss) in operating revenue – regulated	$	(1)	$	(2)
Total gains (losses) in net income	$	(1)	$	(2)
As at millions of Canadian dollars	March 31 2020		December 31 2019
		Foreign exchange forwards
Total unrealized gain (loss) in AOCI – effective portion, net of tax	$	(3)	$	(1)

The Company expects $3 million of unrealized loss currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

As at March 31, 2020, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:

millions		2020
Foreign exchange forwards (USD) sales	$	21

Regulatory Deferral

The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:

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

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

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

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For the millions of Canadian dollars	Three months ended March 31, 2019
		Commodity swaps and forwards		Foreign exchange forwards
Unrealized gain (loss) in regulatory assets		$                          6	$	(1)
Unrealized gain (loss) in regulatory liabilities		(19)		(5)
Realized (gain) loss in regulatory assets		5		-
Realized (gain) loss in inventory (1)		(18)		(5)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(2)		(2)
Total change in derivative instruments		$                     (28)	$	(13)

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

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

Commodity Swaps and Forwards

As at March 31, 2020, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:

	2020	2021-2022
millions	Purchases	Purchases
Natural Gas (Mmbtu)	3	10
Power (MWh)	1	3
Heavy fuel oil (bbls)	-	1
Coal (metric tonnes)	-	1

Foreign Exchange Swaps and Forwards

As at March 31, 2020, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated as regulated deferral that are expected to settle as outlined below:

		2020		2021-2022
Foreign exchange contracts (millions of US dollars)	$	120	$	208
Weighted average rate		1.2925		1.3272
% of USD requirements		67%		55%

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

Held-for-Trading Derivatives

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

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

For the	Three months ended March 31
millions of Canadian dollars	2020			2019
Power swaps and physical contracts in non-regulated operating revenues	$	1		$	(3	)
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		211			152
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		(4	)		(2	)
	$	208		$	147

As at March 31, 2020, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions	2020	2021	2022	2023	2024
Natural gas purchases (Mmbtu)	421	119	56	41	26
Natural gas sales (Mmbtu)	386	75	11	3	2
Power purchases (MWh)	2	-	-	-	-
Power sales (MWh)	2	-	-	-	-

Other Derivatives

As at March 31, 2020, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and foreign exchange forwards in place to manage cash flow risk associated with forecasted US dollar cash inflows. The equity derivative hedges the return on 2.8 million shares and extends until December of 2020. The foreign exchange forwards have a combined notional amount of $247 million and expire in 2020 through 2021.

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

For the				Three months ended March 31
millions of Canadian dollars				2020					2019
		Foreign Exchange Forwards			Equity Derivatives			Foreign Exchange Forwards		Equity Derivatives
Unrealized gain (loss) in operating, maintenance and general	$	-		$	(1	)	$	-	$	14
Unrealized gain (loss) in other income (expense)		(9	)		-			-		-
Realized gain (loss) in other income (expense)		(1	)		-			-		-
Total gains (losses) in net income	$	(10	)	$	(1	)	$	-	$	14

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts.

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The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable, or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

As at March 31, 2020, the Company had $121 million (December 31, 2019 - $115 million) in financial assets considered to be past due, which have been outstanding for an average 57 days. The fair value of these financial assets is $110 million (December 31, 2019 - $106 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue.

Cash Collateral

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

As at millions of Canadian dollars	March 31 2020		December 31 2019
Cash collateral provided to others	$	166	$	101
Cash collateral received from others		2		2

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

As at March 31, 2020, the total fair value of these derivatives, in a liability position, was $328 million (December 31, 2019 – $370 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.

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14. FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 13), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:

● While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

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

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

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

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

As at	March 31, 2020
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral
Commodity swaps and forwards
Power purchases	$	12	$	-	$	-	$	12
Natural gas purchases and sales		-		2		-		2
Foreign exchange forwards		-		35		-		35
		12		37		-		49
HFT derivatives
Power swaps and physical contracts		3		-		4		7
Natural gas swaps, futures, forwards, physical contracts and related transportation		(4)		46		15		57
		(1)		46		19		64
Other derivatives
Foreign exchange forwards		-		1		-		1
Equity derivatives		1		-		-		1
		1		1		-		2
Total assets		12		84		19		115
Liabilities
Cash flow hedges
Foreign exchange forwards		-		3		-		3
		-		3		-		3
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		35		-		35
Power purchases		57		-		-		57
Heavy fuel oil purchases		8		23		-		31
Natural gas purchases and sales		6		2		-		8
		71		60		-		131
HFT derivatives
Power swaps and physical contracts		9		1		3		13
Natural gas swaps, futures, forwards and physical contracts		2		16		152		170
		11		17		155		183
Other derivatives
Foreign exchange forwards		-		11		-		11
		-		11		-		11
Total liabilities		82		91		155		328
Net assets (liabilities)	$	(70)	$	(7)	$	(136)	$	(213)

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

The change in the fair value of the Level 3 financial assets for the three months ended March 31, 2020 was as follows:

	HFT Derivatives
millions of Canadian dollars	Power		Natural                 gas		Total
Balance, beginning of period	$	1	$	14	$	15
Total realized and unrealized gains (losses) included in non-regulated operating revenues		3		1		4
Balance, March 31, 2020	$	4	$	15	$	19

The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 2020 was as follows:

	HFT Derivatives
millions of Canadian dollars	Power		Natural                 gas		Total
Balance, beginning of period	$	-	$	249	$	249
Total realized and unrealized gains (losses) included in non-regulated operating revenues		3		(97)		(94)
Balance, March 31, 2020	$	3	$	152	$	155

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

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

As at	March 31, 2020
millions of Canadian dollars	Fair Value			Valuation Technique		Unobservable Input		Range		Weighted average (1)
Assets
HFT derivatives – Power swaps and physical contracts	$	4			Modelled pricing		Third-party pricing		$0.06-$64.15		$9.38
							Probability of default		0.01%-1.05%		0.11%
							Discount rate		0.08%-1.78%		0.64%
HFT derivatives – Natural gas swaps, futures, forwards, physical contracts		8			Modelled pricing		Third-party pricing		$1.11-$3.17		$1.81
							Probability of default		0.01%-2.56%		0.10%
							Discount rate		0.00%-8.51%		0.67%
		7			Modelled pricing		Third-party pricing		$1.22-$8.25		$3.25
							Basis adjustment		$0.00-$1.17		$0.75
							Probability of default		0.01%-3.46%		1.15%
							Discount rate		0.00%-1.37%		0.62%
Total assets	$	19
Liabilities
HFT derivatives –	$	3			Modelled pricing		Third-party pricing		$1.13-$64.15		$9.73
Power swaps and							Own credit risk		0.01%-1.05%		0.09%
physical contracts							Discount rate		0.08%-1.78%		0.63%
HFT derivatives – Natural gas swaps, futures, forwards and physical contracts		139			Modelled pricing		Third-party pricing		$1.11-$7.45		$2.89
							Own credit risk		0.01%-2.56%		0.17%
							Discount rate		0.00%-7.3%		0.63%
		13			Modelled pricing		Third-party pricing		$0.85-$8.25		$3.87
							Basis adjustment		$0.00-$1.17		$0.54
							Own credit risk		0.01%-1.72%		0.08%
							Discount rate		0.00%-1.28%		0.69%
Total liabilities	$	155
Net assets (liabilities)	$	(136	)

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

The financial liabilities included on the Condensed Consolidated Balance Sheets that are not measured at fair value consisted of long-term debt, as follows:

As at
millions of Canadian dollars	Carrying Amount		Fair Value		Level 1		Level 2		Level 3		Total
March 31, 2020	$	14,777	$	15,602	$	-	$	15,075	$	527	$	15,602
December 31, 2019	$	14,180	$	16,049	$	-	$	15,598	$	451	$	16,049

The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. An after-tax foreign currency loss of $141 million was recorded in Other Comprehensive Income for the three months ended March 31, 2020 (2019 – $34 million gain after-tax).

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15. REGULATORY ASSETS AND LIABILITIES

A summary of the Company’s regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 15 in Emera’s 2019 annual audited consolidated financial statements.

As at millions of Canadian dollars	March 31 2020		December 31 2019
Regulatory assets
Deferred income tax regulatory assets	$	852	$	862
Pension and post-retirement medical plan		409		380
Deferrals related to derivative instruments		132		81
Storm restoration regulatory asset		43		38
Stranded cost recovery		29		27
Environmental remediations		29		26
Demand side management (“DSM”) deferral		18		19
Unamortized defeasance costs		17		19
Cost recovery clauses		4		13
Other		87		87
	$	1,620	$	1,552
Current	$	156	$	121
Long-term		1,464		1,431
Total regulatory assets	$	1,620	$	1,552
Regulatory liabilities
Deferred income tax regulatory liabilities	$	1,051	$	985
Accumulated reserve - cost of removal		970		891
Regulated fuel adjustment mechanism		112		115
Cost recovery clauses		108		53
Storm reserve		68		62
Deferrals related to derivative instruments		56		42
Self-insurance fund (note 23)		31		29
Other		2		4
	$	2,398	$	2,181
Current	$	310	$	295
Long-term		2,088		1,886
Total regulatory liabilities	$	2,398	$	2,181

Tampa Electric

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.

BLPC

In December 2018, as a result of the enactment of the Income Tax Amendment Act in Barbados, BLPC was required to remeasure its deferred income tax liability at a new lower corporate income tax rate. At that time, BLPC deferred $6.9 million USD of the recovery, all of which was recognized in earnings in Q1 2020.

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Grand Bahama Power Company

On September 1, 2019, Hurricane Dorian struck Grand Bahama Island causing significant damage across the island. In January 2020, the GBPA approved the recovery of approximately $15 million USD of restoration costs related to GBPC’s self-insured assets. As of 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 potential economic impacts of COVID-19 on Grand Bahama.

16.  RELATED PARTY TRANSACTIONS

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

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

● Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $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.

● 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.

17.  RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:    

As at millions of Canadian dollars	March 31 2020		December 31 2019
Customer accounts receivable – billed	$	590	$	603
Customer accounts receivable – unbilled		269		265
Allowance for doubtful accounts		(13)		(9)
Capitalized transportation capacity (1)		234		272
Income tax receivable		189		118
Prepaid expenses		82		48
Other		254		189
	$	1,605	$	1,486

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

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18.  EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, Dominica and Grand Bahama Island. For details of the Company’s employee benefit plan, refer to note 19 in Emera’s 2019 annual audited consolidated financial statements. Refer to note 1 “Use of Management Estimates – Pension and Other Post-Retirement Employee Benefits”.

Emera’s net periodic benefit cost included the following:

For the	Three months ended March 31
millions of Canadian dollars	2020		2019
Defined benefit pension plans
Service cost	$	12	$	12
Non-service cost
Interest cost		22		26
Expected return on plan assets		(37)		(37)
Current year amortization of:
Actuarial losses		4		5
Regulatory asset		7		4
Total non-service costs		(4)		(2)
Total defined benefit pension plans		8		10
Non-pension benefits plan
Service cost		1		1
Non-service cost
Interest cost		3		4
Expected return on plan assets		-		(1)
Current year amortization of:
Regulatory asset		-		(2)
Total non-service costs		3		1
Total non-pension benefits plans		4		2
Total defined benefit plans	$	12	$	12

Emera’s contributions related to these defined-benefit plans for the three months ended March 31, 2020 were $16 million (2019 - $16 million). Annual employer contributions to the defined benefit pension plans are estimated to be $39 million for 2020.

19.  SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt refer to note 22 in Emera’s 2019 annual audited consolidated financial statements, and below for 2020 short-term debt financing activity.

Recent Significant Financing Activity by Segment

Florida Electric Utilities

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

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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 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.

20.  LONG-TERM DEBT

For details regarding long-term debt, refer to note 24 in Emera’s 2019 annual audited consolidated financial statements, and below for 2020 long-term debt financing activity.

Recent Significant Financing Activity by Segment

Canadian Electric Utilities

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

Other Electric Utilities

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

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21.   COMMITMENTS AND CONTINGENCIES

A. Commitments

As at March 31, 2020, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2020		2021		2022		2023		2024		Thereafter		Total
Purchased power (1)	$	197	$	218	$	247	$	268	$	282	$	1,993	$	3,205
Transportation (2)		423		429		374		312		288		2,999		4,825
Capital projects (3)		414		135		111		94		-		-		754
Fuel, gas supply and storage		363		133		28		5		1		-		530
Long-term service agreements (4)		62		23		22		19		19		71		216
Equity investment commitments (5)		-		240		-		-		-		-		240
Leases and other (6)		13		20		20		18		19		114		204
Demand side management		24		41		43		-		-		-		108
	$	1,496	$	1,239	$	845	$	716	$	609	$	5,177	$	10,082

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

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

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

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

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

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

On March 17, 2020, Nalcor announced that it had 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.

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.

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B. Legal Proceedings

TECO Guatemala Holdings (“TGH”)

In 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (“Guatemala”) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus two per cent. This award was upheld in subsequent annulment proceedings in 2016 and, in addition, TGH’s application for partial annulment of the award was granted, and Guatemala was ordered to pay certain costs relating to the annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding.

On September 23, 2016, TGH filed a request for resubmission to arbitration. A new tribunal was constituted, and the matter was fully briefed. A hearing was held in March 2019 and a decision is expected from the tribunal in 2020. In addition, TGH sued Guatemala in Washington, D.C. court to enforce the $21 million USD owing. Guatemala’s motion to dismiss the enforcement action was denied. On October 1, 2019, the court granted TGH’s motion for summary judgment which will allow TGH to seek collection of the award plus interest when the order is final. Guatemala has appealed that decision. Results to date do not reflect any benefit.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at March 31, 2020, TEC has estimated its financial liability to be $30 million ($21 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Condensed Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.

Emera Maine

On March 24, 2020, the Company completed the sale of Emera Maine. Emera has no remaining obligations with respect to the legal proceedings previously disclosed in note 26 of Emera’s 2019 annual audited consolidated financial statements. No new or additional reserves were made in Q1 2020 with respect to any of the four complaints filed with the Federal Energy Regulatory Commission.

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Other Legal Proceedings

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

C. Principal Financial Risks and Uncertainties

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

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

Public Health Risk

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

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

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

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.

Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange.

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The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, select asset sales, short-term credit facilities, and ongoing access to capital markets. Cash flows generated from the sale of select assets are dependent on the market for the assets, acceptable pricing and the timing of the close of any sales. The Company reasonably expects liquidity sources to exceed capital needs.

Emera’s access to capital and cost of borrowing is subject to a number of risk factors including financial market conditions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in property, plant and equipment. Emera is subject to risk with changes in interest rates that could have an adverse effect on the cost of financing. Inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan. The Company’s future access to capital and cost of borrowing may be impacted by possible continued COVID-19 related market disruptions.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. Emera manages this risk by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings.

The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation, preferred share units and deferred share units.

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. Future interest rates may be impacted by possible continued COVID-19 related market disruptions.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives.

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Commodity Price Risk

A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results.

D. Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2019 audited annual consolidated financial statements, with 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.

22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the	Three months ended March 31
millions of Canadian dollars	2020		2019
Changes in non-cash working capital:
Inventory	$	60	$	57
Receivables and other current assets		(84)		151
Accounts payable		(168)		(265)
Other current liabilities		118		41
Total non-cash working capital	$	(74)	$	(16)
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	45	$	48
Decrease (increase) in accrued capital expenditures	$	23	$	(18)

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23.  VARIABLE INTEREST ENTITIES

The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”) or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities.

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

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

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

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

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

As at	March 31, 2020				December 31, 2019
millions of Canadian dollars	Total assets		Maximum exposure to loss		Total assets		Maximum exposure to loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)	$	557	$	22	$	554	$	23

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24.  COMPARATIVE INFORMATION

These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

25.  SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 12, 2020, the date the financial statements were issued.

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