Emera 6K Current report | ERRAF 14 May 21

Emera (ERRAF) 6-KCurrent report (foreign)

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2021 and 2020

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)


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

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

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

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

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

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

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

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

Dividends per common share declared	$	0.6375	$	0.6125

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

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)


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

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

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

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

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

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

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

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)


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

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued


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

Commitments and contingencies (note 21)

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

Approved on behalf of the Board of Directors


“M. Jacqueline Sheppard”		“Scott Balfour”

Chair of the Board		President and Chief Executive Officer

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)


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

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

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


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

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

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

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

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

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at March 31, 2021 and 2020

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

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

At March 31, 2021, Emera’s reportable segments include the following:

•

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

•

Canadian Electric Utilities, which includes:

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

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

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

a 44.4 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and Nalcor recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work toward final commissioning the LIL. In response to the COVID-19 pandemic, on March 17, 2020 Nalcor announced it had paused construction activities at the Muskrat Falls site and resumed work in May 2020. Nalcor achieved first power on the first of four generators at Muskrat Falls on September 22, 2020 and continues to work toward final project commissioning of Muskrat Falls and LIL in 2021. Refer to note 21 for further details.

•

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

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

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

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

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

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

Gas Utilities and Infrastructure, which includes:

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

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

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

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

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

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

Emera Energy, which consists of:

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

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

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

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

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

Emera Technologies LLC, a wholly owned technology company focused on finding ways to deliver renewables and resilient energy to customers;

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

other investments.

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

Basis of Presentation

These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2020, except as described in note 2.

In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2021.

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

Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, allowance for credit losses, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise.

During the three months ended March 31, 2021, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. The pandemic has generally resulted in lower load and higher operating costs than what otherwise would have been experienced at the Company’s utilities. Some of Emera’s utilities have been impacted more than others. However, on a consolidated basis these unfavourable impacts have not had a material financial impact to net earnings primarily due to a change in the mix of sales across customer classes. Lower commercial and industrial sales have been partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. Emera’s utilities provide essential services and continue to operate and meet customer demand. Governments world-wide have implemented measures intended to address the pandemic. These measures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial spaces and industrial facilities, shutdowns, shelter-in-place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility and governments and central banks are implementing measures designed to stabilize economic conditions. The pace and strength of economic recovery is uncertain and may vary among jurisdictions.

Management has analyzed the impact of the COVID-19 pandemic on its estimates and assumptions and concluded that no material adjustments were required for the three months ended March 31, 2021.

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

Goodwill Impairment Assessments

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

As of March 31, 2021, $5.6 billion of Emera’s goodwill was related to TECO Energy (Tampa Electric, PGS and NMGC reporting units). Given the significant excess of fair value over carrying amounts calculated for these reporting units as of the last quantitative test performed in Q4 2019, and the results of the qualitative assessment performed in Q4 2020, management does not expect the COVID-19 pandemic to have an impact on the goodwill associated with these reporting units.

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

Long-Lived Assets Impairment Assessments

Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at March 31, 2021, there are no indications of impairment of Emera’s long-lived assets. Impacts from COVID-19 could cause the Company to impair long-lived assets in the future; however, there is currently no indication that future cash flows would be impacted to a point where the Company’s long-lived assets would not be recoverable.

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

Receivables and Allowance for Credit Losses

Management estimates credit losses related to accounts receivable after considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. The economic impact of COVID-19, in the service territories where Emera operates, has impacted the aging of customer receivables resulting in higher allowances for credit losses related to customer receivables however it has not had a material impact on earnings.

Pension and Other Post-Retirement Employee Benefits

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

Seasonal Nature of Operations

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

2. CHANGE IN ACCOUNTING POLICY

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

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

The Company adopted Accounting Standard Update (“ASU”) 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) effective January 1, 2021 using the modified retrospective approach. The standard simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in addition to amending disclosure requirements. The standard also updates guidance for the derivative scope exception for contracts in an entity’s own equity and the related earnings per share guidance. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.

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 2020 audited consolidated financial statements, with updates noted below.

Guaranteed Debt Securities Disclosure Requirements

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

4. DISPOSITIONS

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of approximately $2.0 billion including cash proceeds of $1.4 billion, transferred debt and working capital adjustments. In Q1 2020, a gain on disposition of $586 million ($321 million after tax) net of transaction costs, was recognized in the Other segment and included in “Other income” on the Condensed Consolidated Statements of Income.

5. SEGMENT INFORMATION

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


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

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

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

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

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

6. REVENUE

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


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

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

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

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

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


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

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

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

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

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

Remaining Performance Obligations

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of March 31, 2021, the aggregate amount of the transaction price allocated to remaining performance obligations was $447 million (2020 – $368 million). This amount includes $146 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2040.

7. REGULATORY ASSETS AND LIABILITIES

A summary of the Company’s regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 7 in Emera’s 2020 annual audited consolidated financial statements.


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

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

Tampa Electric

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

NMGC

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

GBPC

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

8. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME


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

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

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

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $108 million (2020 – $118 million) is recorded in Other long-term liabilities on the Condensed Consolidated Balance Sheets.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 24). NSPML’s consolidated summarized balance sheet is as follows:


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

9. OTHER INCOME, NET


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

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

10. INCOME TAXES

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


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

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

11. COMMON STOCK

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


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

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

12. EARNINGS PER SHARE

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


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

13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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


millions of Canadian dollars	Unrealized (loss) gain on translation of self-sustaining foreign operations		Net change in net investment hedges			(Losses) gains on derivatives recognized as cash flow hedges		Net change in available- for-sale investments			Net change in unrecognized pension and post- retirement benefit costs			Total AOCI
For the three months ended March 31, 2021
Balance, January 1, 2021	$	52	$	30		$	1	$	(1)		$	(161)		$	(79)
Other comprehensive income (loss) before reclassifications		(111)		16			24		-			-			(71)
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-			-		-			5			5
Net current period other comprehensive income (loss)		(111)		16			24		-			5			(66)
Balance, March 31, 2021	$	(59)	$	46		$	25	$	(1)		$	(156)		$	(145)

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

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


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

14. DERIVATIVE INSTRUMENTS

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

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

foreign exchange fluctuations on foreign currency denominated purchases and sales;

interest rate fluctuations on debt securities; and

share price fluctuations on stock-based compensation.

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

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

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

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

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

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

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


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

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

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


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

Cash Flow Hedges

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

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


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

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

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

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


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

Regulatory Deferral

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


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

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

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

Commodity Swaps and Forwards

As at March 31, 2021, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:


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

Foreign Exchange Swaps and Forwards

As at March 31, 2021, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated as regulated deferral that are expected to settle as outlined below:


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

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

Held-for-Trading Derivatives

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

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


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

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


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

Other Derivatives

As at March 31, 2021, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and foreign exchange forwards in place to manage cash flow risk associated with forecasted US dollar cash inflows. The equity derivative hedges the return on 2.8 million shares and extends until December of 2021. The foreign exchange forwards have a combined notional amount of $75 million USD and expire in 2021.

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


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

Credit Risk

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

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

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

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

As at March 31, 2021, the Company had $126 million (December 31, 2020 - $123 million) in financial assets considered to be past due, which had been outstanding for an average 68 days. The fair value of these financial assets was $104 million (December 31, 2020 - $101 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.

Cash Collateral

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

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

As at March 31, 2021, the total fair value of derivatives in a liability position, was $280 million (December 31, 2020 – $338 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.

15. FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 14), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

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

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

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

•

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

•

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

•

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

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

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


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


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

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


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

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


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

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

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


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

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

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


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

The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. An after-tax foreign currency gain of $16 million was recorded in Other Comprehensive Income for the three months ended March 31, 2021 (2020 – $141 million loss after-tax).

16. RELATED PARTY TRANSACTIONS

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

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

●

Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $28 million for the three months ended March 31, 2021 (2020 - $28 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.

●

Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $7 million for the three months ended March 31, 2021 (2020 - $8 million).

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

17. RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:


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

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

18. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, Dominica and Grand Bahama Island. For details of the Company’s employee benefit plan, refer to note 21 in Emera’s 2020 annual audited consolidated financial statements. Refer to note 1 “Use of Management Estimates – Pension and Other Post-Retirement Employee Benefits”.

Emera’s net periodic benefit cost included the following:


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

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

19. SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt, refer to note 23 in Emera’s 2020 annual audited consolidated financial statements, and below for 2021 short-term debt financing activity.

Recent Significant Financing Activity by Segment

Florida Electric Utility

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

20. LONG-TERM DEBT

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

Recent Significant Financing Activity by Segment

Florida Electric Utility

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

Gas Utilities and Infrastructure

On March 25, 2021, NMGC entered into a $100 million USD unsecured, non-revolving credit facility with a maturity date of September 23, 2022. The credit facility contains customary representations and warranties, events of default, financial and other covenants and bears interest based on either the LIBOR, prime rate, or the federal funds rate, plus a margin.

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

21. COMMITMENTS AND CONTINGENCIES

A.	Commitments

As at March 31, 2021, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:


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

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

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

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

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

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

On March 17, 2020, Nalcor announced that it had paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor declared force majeure under various project contracts, including formal notification to NSPML. Nalcor resumed work in May 2020. Nalcor achieved first power on the first of four generators at Muskrat Falls on September 22, 2020 and continues to work toward final project commissioning of Muskrat Falls and LIL in 2021.

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

NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts included in the NSPI fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are dependent on regulatory filings with the UARB.

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

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

B.	Legal Proceedings

TECO Guatemala Holdings (“TGH”)

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

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at March 31, 2021, TEC has estimated its financial liability to be $21 million ($17 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Condensed Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

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

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

Other Legal Proceedings

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

C.	Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are discussed in note 14 and note 15.

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

Public Health Risk

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

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

The extent of the evolving COVID-19 pandemic and its future impact on the Company is uncertain. The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat. The Company’s top priority continues to be the health and safety of its customers and employees.

Foreign Exchange Risk

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

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

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

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed capital needs.

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

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

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

Interest Rate Risk

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

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

Commodity Price Risk

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

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

Regulated Utilities

A large portion of the Company’s utility fuel supply comes from international suppliers and therefore may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable.

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

Emera Energy Marketing and Trading

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

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

Income Tax Risk

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

D.	Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2020 audited annual consolidated financial statements.

The Company has standby letters of credit and surety bonds in the amount of $69 million USD (December 31, 2020 - $55 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.

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

22. CUMULATIVE PREFERRED STOCK

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

23. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


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

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

24. VARIABLE INTEREST ENTITIES

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

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

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

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

As at

March 31, 2021

December 31, 2020

millions of Canadian dollars

Total
assets

Maximum
exposure to

loss

Total
assets

Maximum
exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

548

547

25. COMPARATIVE INFORMATION

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

26. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 11, 2021, the date the financial statements were issued.

March 31

December 31

millions of Canadian dollars

Cash collateral provided to others

Cash collateral received from others