Emera 6K Current report | ERRAF 17 May 22

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2022 and 2021

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)


For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2022		2021


Operating revenues
Regulated electric	$	1,273	$	1,102

Regulated gas		502		393

Non-regulated		240		117

Total operating revenues (note 5)		2,015		1,612


Operating expenses

Regulated fuel for generation and purchased power		477		395

Regulated cost of natural gas		256		157

Non-regulated fuel for generation and purchased power		-		(1)

Operating, maintenance and general		387		318

Provincial, state and municipal taxes		86		80

Depreciation and amortization		230		226

Total operating expenses		1,436		1,175

Income from operations		579		437


Income from equity investments (note 7)		27		41

Other income, net		23		20

Interest expense, net		156		157

Income before provision for income taxes		473		341


Income tax expense (note 8)		95		56

Net income		378		285


Non-controlling interest in subsidiaries		-		1

Preferred stock dividends		16		11

Net income attributable to common shareholders	$	362	$	273


Weighted average shares of common stock outstanding (in millions) (note 10)
Basic		261.8		253.5

Diluted		262.3		253.8


Earnings per common share (note 10)
Basic	$	1.38	$	1.08

Diluted	$	1.38	$	1.08


Dividends per common share declared	$	0.6625	$	0.6375


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

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)


For the	Three months ended March 31
millions of Canadian dollars	2022		2021

Net income	$	378	$	285

Other comprehensive income (loss), net of tax
Foreign currency translation adjustment		(138)		(111)

Unrealized gains on net investment hedges (1)(2)		19		16

Cash flow hedges
Net derivative gains (3)		-		24

Less: reclassification adjustment for gains included in income		(1)		-

Net effects of cash flow hedges		(1)		24

Net change in unrecognized pension and post-retirement benefit obligation		(10)		5

Other comprehensive loss (4)	$	(130)	$	(66)

Comprehensive income		248		219

Comprehensive income attributable to non-controlling interest		-		1

Comprehensive Income of Emera Incorporated	$	248	$	218


The accompanying notes are an integral part of these condensed consolidated interim financial statements. 1) 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. 2) Net of tax expense of $3 million (2021 - $3 million expense) for the three months ended March 31, 2022. 3) Net of tax expense of nil (2021 - $8 million expense) for the three months ended March 31, 2022. 4) Net of tax expense of $3 million (2021 - $11 million tax expense) for the three months ended March 31, 2022.

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)


As at		March 31		December 31
millions of Canadian dollars	2022		2021

Assets
Current assets
Cash and cash equivalents	$	381		$ 394

Restricted cash (note 22)		23		23

Inventory		438		538

Derivative instruments (notes 12 and 13)		384		195

Regulatory assets (note 6)		337		253

Receivables and other current assets (note 15)		1,825		1,733

		3,388		3,136

Property, plant and equipment, net of accumulated depreciation and amortization of $8,715 and $8,739, respectively		20,211		20,353

Other assets
Deferred income taxes (note 8)		234		295

Derivative instruments (notes 12 and 13)		84		106

Regulatory assets (note 6)		2,321		2,313

Net investment in direct finance and sales type leases (note 16)		606		503

Investments subject to significant influence (note 7)		1,388		1,382

Goodwill		5,614		5,696

Other long-term assets		491		460

		10,738		10,755

Total assets	$	34,337		$ 34,244

Liabilities and Equity
Current liabilities
Short-term debt (note 18)	$	1,861		$ 1,742

Current portion of long-term debt (note 19)		448		462

Accounts payable		1,421		1,485

Derivative instruments (notes 12 and 13)		530		533

Regulatory liabilities (note 6)		402		290

Other current liabilities		456		366

		5,118		4,878

Long-term liabilities
Long-term debt (note 19)		13,853		14,196

Deferred income taxes (note 8)		1,864		1,868

Derivative instruments (notes 12 and 13)		89		149

Regulatory liabilities (note 6)		1,780		1,765

Pension and post-retirement liabilities (note 17)		363		370

Other long-term liabilities (note 7)		958		868

		18,907		19,216

Equity
Common stock (note 9)		7,365		7,242

Cumulative preferred stock		1,422		1,422

Contributed surplus		79		79

Accumulated other comprehensive income (loss) (note 11)		(105)		25

Retained earnings		1,537		1,348

Total Emera Incorporated equity		10,298		10,116

Non-controlling interest in subsidiaries		14		34

Total equity		10,312		10,150

Total liabilities and equity	$	34,337		$ 34,244


Commitments and contingencies (note 20)	Approved on behalf of the Board of Directors
The accompanying notes are an integral part of these condensed consolidated interim financial statements.	“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	2022		2021

Operating activities
Net income	$	378	$	285

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		232		230

Income from equity investments, net of dividends		(9)		(20)

Allowance for equity funds used during construction		(12)		(14)

Deferred income taxes, net		87		46

Net change in pension and post-retirement liabilities		(10)		(5)

Regulated fuel adjustment mechanism		(64)		(19)

Net change in fair value of derivative instruments		(76)		(42)

Net change in regulatory assets and liabilities		(30)		(128)

Net change in capitalized transportation capacity		(106)		(10)

Other operating activities, net		92		17

Changes in non-cash working capital (note 21)		119		(41)

Net cash provided by operating activities		601		299

Investing activities
Additions to property, plant and equipment		(521)		(477)

Other investing activities		8		(1)

Net cash used in investing activities		(513)		(478)

Financing activities
Change in short-term debt, net		141		(490)

Repayment of short-term debt with maturities greater than 90 days		-		(377)

Proceeds from long-term debt, net of issuance costs		16		1,416

Retirement of long-term debt		(8)		(263)

Net repayments under committed credit facilities		(178)		(27)

Issuance of common stock, net of issuance costs		62		56

Dividends on common stock		(114)		(107)

Dividends on preferred stock		(16)		(11)

Other financing activities		(1)		(1)

Net cash (used in) provided by financing activities		(98)		196

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

Net (decrease) increase in cash, cash equivalents, and restricted cash		(13)		14

Cash, cash equivalents and restricted cash, beginning of period		417		254

Cash, cash equivalents and restricted cash, end of period	$	404	$	268

Cash, cash equivalents, and restricted cash consists of:
Cash	$	206	$	234

Short-term investments		175		-

Restricted cash		23		34

Cash, cash equivalents and restricted cash	$	404	$	268


The accompanying notes are an integral part of these condensed consolidated interim 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) (1)	Retained Earnings	Non- Controlling Interest		Total Equity

For the three months ended March 31, 2022

Balance, December 31, 2021	$ 7,242	$ 1,422	$ 79	$ 25	$ 1,348	$ 34	$	10,150

Net income of Emera Incorporated	-	-	-	-	378	-		378

Other comprehensive loss, net of tax expense of $3 million	-	-	-	(130)	-	-		(130)

Dividends declared on preferred stock (2)	-	-	-	-	(16)	-		(16)

Dividends declared on common stock ($0.6625/share)	-	-	-	-	(173)	-		(173)

Disposal of non-controlling interest of Dominica Electricity Services Ltd (“Domlec”)	-	-	-	-	-	(20)		(20)

Common stock issued under purchase plan	65	-	-	-	-	-		65

Issuance of common stock, net of after-tax issuance costs	56	-	-	-	-	-		56

Senior management stock options exercised	1	-	-	-	-	-		1

Other	1	-	-	-	-	-		1

Balance, March 31, 2022	$ 7,365	$ 1,422	$ 79	$ (105)	$ 1,537	$ 14	$	10,312



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 loss, net of tax expense of $11 million	-	-	-	(66)	-	-		(66)

Dividends declared on preferred stock (3)	-	-	-	-	(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 option exercised	1	-	-	-	-	-		1

Other	1	-	-	-	-	(1)		-

Balance, March 31, 2021	$ 6,816	$ 1,004	$ 79	$ (145)	$ 1,608	$ 34	$	9,396


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

(1) Accumulated Other Comprehensive Income (Loss) (“AOCI”) (“AOCL”)
(2) Series A; $0.1364/share, Series B; $0.1253/share, Series C; $0.29506/share, Series E; $0.28125/share, Series F; $0.26263/share, Series H; $0.30625/share, Series J; $0.265625/share and Series L; $0.2875/share
(3) 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

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at March 31, 2022 and 2021

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, 2022, 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 $1.8 billion (including AFUDC) transmission project; and

●

a 36.9 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.

●

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;

●

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;

●

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

●

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; 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.

●

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;

●

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.

The outbreak of COVID-19 in 2020 resulted in governments worldwide enacting emergency measures to combat the spread of the virus. Management considered the impact of COVID-19 on the Company’s estimates and results and concluded the financial statements as at and for the three months ended March 31, 2022, were not materially impacted.

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, 2021.

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, 2022.

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

Use of Management Estimates

The preparation of condensed consolidated interim financial statements 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. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2021 annual audited consolidated financial statements.

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.

2.	FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The ASUs that have been issued by FASB, but are not yet effective, were assessed and determined to be either not applicable to the Company or have an insignificant impact on the condensed consolidated interim financial statements.

3.	DISPOSITIONS

On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Domlec for proceeds which approximated its carrying value. Domlec was included in the Company’s Other Electric reportable segment up to its date of sale. The sale did not have a material impact on earnings.

4.	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, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.


		Florida		Canadian	Gas Utilities		Other			Inter-

		Electric		Electric	and		Electric			Segment

millions of Canadian dollars		Utility		Utilities	Infrastructure		Utilities		Other	Eliminations			Total
For the three months ended March 31, 2022
Operating revenues from external customers (1)	$	644	$	509	$ 507	$	119	$	236	$ -		$	2,015
Inter-segment revenues (1)		2		-	1		-		10	(13)			-
Total operating revenues		646		509	508		119		246	(13)			2,015
Regulated fuel for generation and purchased power		172		242			63		-	-			477
Regulated cost of natural gas		-		-	256		-		-	-			256
Depreciation and amortization		120		63	27		18		2	-			230
Interest expense, net		38		33	14		4		67	-			156
Internally allocated interest (2)		-		-	3		-		(3)	-			-
Operating, maintenance and general expenses (“OM&G”)		142		91	90		31		37	(4)			387
Income tax expense		25		3	25		-		42	-			95
Net income attributable to common shareholders		112		91	77		(1)		83	-			362
As at March 31, 2022
Total assets		17,941		7,776	6,604		1,295		1,933	(1,212)	⁽³⁾		34,337
For the three months ended March 31, 2021
Operating revenues from external customers (1)		565		443	397		94		113	-			1,612
Inter-segment revenues (1)		1		-	2		-		-	(3)			-
Total operating revenues		566		443	399		94		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	30		15		2	-			226
Interest expense, net		36		35	12		5		69	-			157
Internally allocated interest (2)		-		-	3		-		(3)	-			-
OM&G		117		78	81		25		21	(4)			318
Income tax expense		14		6	25		-		11	-			56
Net income attributable to common shareholders		83		88	80		7		15	-			273
As at December 31, 2021
Total assets		17,903		7,418	6,666		1,402		2,034	(1,179)	⁽³⁾		34,244
(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, 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.

5.	REVENUE

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


		Electric						Gas		Other
		Florida		Canadian		Other		Gas Utilities				Inter-
		Electric		Electric		Electric		and				Segment
millions of Canadian dollars		Utility		Utilities		Utilities		Infrastructure		Other		Eliminations		Total
For the three months ended March 31, 2022
Regulated Revenue:
Residential	$	342	$	285	$	43		$ 277	$	-		$ -	$	947
Commercial		173		122		62		137		-		(1)		493
Industrial		47		88		7		18		-		-		160
Other regulatory deferrals		80		7		5		-		-		-		92
Other (1)		4		7		2		58		-		(2)		69
Finance income (2)(3)		-		-		-		14		-		-		14
Regulated revenue		646		509		119		504		-		(3)		1,775
Non-Regulated Revenue:
Marketing and trading margin (4)		-		-		-		-		49		-		49
Energy sales		-		-		-		-		3		(5)		(2)
Other		-		-		-		4		4		-		8
Mark-to-market (3)		-		-		-		-		190		(5)		185
Non-regulated revenue		-		-		-		4		246		(10)		240
Total operating revenues	$	646	$	509	$	119	$	508	$	246	$	(13)	$	2,015
For the three months ended March 31, 2021
Regulated Revenue:
Residential	$	294	$	259	$	35	$	218	$	-	$	-	$	806
Commercial		159		114		47		114		-		-		434
Industrial		47		56		7		16		-		(1)		125
Other regulatory deferrals		61		7		2		-		-		-		70
Other (1)		5		7		3		33		-		(2)		46
Finance income (2)(3)		-		-		-		14		-		-		14
Regulated revenue		566		443		94		395		-		(3)		1,495
Non-Regulated:
Marketing and trading margin (4)		-		-		-		-		67		-		67
Energy sales		-		-		-		-		6		(5)		1
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.

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, 2022, the aggregate amount of the transaction price allocated to remaining performance obligations was $421 million (2021 – $447 million). This amount includes $137 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 2041.

6.	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 2021 annual audited consolidated financial statements.


As at		March 31	December 31
millions of Canadian dollars		2022	2021
Regulatory assets
Deferred income tax regulatory assets	$	1,078	$ 1,045
Tampa Electric capital cost recovery for early retired assets		639	657
Pension and post-retirement medical plan		282	291
Regulated fuel adjustment mechanism (“FAM”)		209	145
Cost recovery clauses		175	114
NMGC winter event gas cost recovery		95	117
Storm restoration regulatory asset		36	35
Environmental remediations		27	27
Stranded cost recovery		26	26
Deferrals related to derivative instruments		11	23
Other		80	86
	$	2,658	$ 2,566
Current	$	337	$ 253
Long-term		2,321	2,313
Total regulatory assets	$	2,658	$ 2,566

Regulatory liabilities
Deferred income tax regulatory liabilities	$	854	$ 863
Accumulated reserve - cost of removal		811	819
Deferrals related to derivative instruments		389	241
Storm reserve		58	58
Cost recovery clauses		31	35
Self-insurance fund (note 22)		27	28
Other		12	11
	$	2,182	$ 2,055
Current	$	402	$ 290
Long-term		1,780	1,765
Total regulatory liabilities	$	2,182	$ 2,055

Tampa Electric

Mid-Course Fuel Adjustment

The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD and will be spread over customer bills beginning April 1, 2022 through December 2022.

Storm Protection Plan (“SPP”) Cost Recovery Clause

On April 11, 2022, Tampa Electric filed a new SPP with the Florida Public Service Commission (“FPSC”) to determine the storm hardening activities and related costs in 2023, 2024 and 2025. The FPSC is expected to rule on the SPP in the second half of 2022.

NSPI

General Rate Application

On January 27, 2022, NSPI filed a General Rate Application (“GRA”) with the Nova Scotia Utility and Review Board (“UARB”), which was then amended on February 18, 2022. The GRA proposes a rate stability plan for 2022 through 2024 which includes average base rate increases of 2.8 per cent per year and average fuel rate increases pursuant to the FAM of 0.8 per cent per year on August 1, 2022, January 1, 2023 and January 1, 2024. The proposed rates would result in annualized incremental revenue (base and fuel rates) increases of $52 million in 2022 ($21 million related to August 1, 2022 through December 31, 2022), $54 million in 2023 and $56 million in 2024. The hearing for this matter is scheduled to begin September 6, 2022 and a decision by the UARB is expected later in the year.

Nova Scotia Cap-and-Trade Program

As at March 31, 2022, the FAM includes a $111 million (December 31, 2021 – $38 million) non-cash accrual representing the estimated future cost of acquiring emissions credits for the 2019 through 2022 Nova Scotia Cap-and-Trade compliance period. These costs are estimated based on forecast emissions for the compliance period and are sensitive to changes to forecasts of energy received from Muskrat Falls for the remainder of 2022 and the actual emissions profile.

BLPC

On October 4, 2021 BLPC submitted a general rate review application to the Fair Trading Commission (“FTC”). The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country’s transition towards 100 per cent renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent. BLPC is expecting a decision from the FTC and new rates in 2022.

GBPC

On January 14, 2022, The Grand Bahama Port Authority issued its decision on GBPC’s rate application allowing for an increase in revenues of $3.5 million USD starting on April 1, 2022.

7.	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		2022	2021		2022	2021	2022
LIL (1)	$	696	$ 682	$	14	$ 13	36.9
NSPML		527	533		6	13	100.0
M&NP (2)		121	123		5	5	12.9
Lucelec (2)		44	44		1	1	19.5
Bear Swamp (3)		-	-		1	9	50.0
	$	1,388	$ 1,382	$	27	$ 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 $101 million (2021 – $104 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 22). NSPML’s consolidated summarized balance sheet is as follows:
As at		March 31	December 31
millions of Canadian dollars		2022	2021
Current assets	$	43	$ 25
Property, plant and equipment		1,565	1,587
Regulatory assets		260	247
Non-current assets		30	31
Total assets	$	1,898	$ 1,890
Current liabilities	$	62	$ 50
Long-term debt (1)		1,189	1,189
Non-current liabilities		120	118
Equity		527	533
Total liabilities and equity	$	1,898	$ 1,890
(1) The project debt has been guaranteed by the Government of Canada.

8.	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	2022	2021
Income before provision for income taxes	$ 473	$ 341
Statutory income tax rate	29.0%	29.0%
Income taxes, at statutory income tax rate	137	99
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities	(25)	(20)
Foreign tax rate variance	(7)	(10)
Amortization of deferred income tax regulatory liabilities	(5)	(5)
Tax effect of equity earnings	(2)	(4)
Other	(3)	(4)
Income tax expense	$ 95	$ 56
Effective income tax rate	20%	16%

During 2022, the Canada Revenue Agency (“CRA”) issued notices of reassessment to NSPI for the 2013 through 2016 taxation years. NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $126 million (2021 - $62 million), including interest. NSPI has prepaid $55 million (2021 - $23 million) of the amount in dispute, as required by the CRA.

On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be available in subsequent years.

Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.

NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not determinable at this time.

9.	COMMON STOCK


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

Issued and outstanding:	millions of shares	millions of Canadian dollars
Balance, December 31, 2021	261.07	$ 7,242
Issuance of common stock (1)	0.92	56
Issued for cash under Purchase Plans at market rate	1.13	66
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, 2022	263.13	$ 7,365
(1) In Q1 2022, 920,100 common shares were issued under Emera’s ATM program at an average price of $60.81 per share for gross proceeds of $56 million ($56 million net of after-tax issuance costs). As at March 31, 2022, an aggregate gross sales limit of $401 million remained available for issuance under the ATM program.

10.

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)		2022		2021

Numerator
Net income attributable to common shareholders	$	361.7	$	273.3

Diluted numerator		361.7		273.3

Denominator
Weighted average shares of common stock outstanding		261.8		252.2

Weighted average deferred share units outstanding (1)		-		1.3

Weighted average shares of common stock outstanding – basic	$	261.8	$	253.5

Stock-based compensation		0.5		0.3

Weighted average shares of common stock outstanding – diluted	$	262.3	$	253.8

Earnings per common share
Basic	$	1.38	$	1.08

Diluted	$	1.38	$	1.08

(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore no longer included in the calculation of earnings per common share.

11.

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, 2022
Balance, January 1, 2022	$	10	$	35	$	18	$	(1)	$	(37)	$	25
Other comprehensive income (loss) before reclassifications		(138)		19		-		-		-		(119)
Amounts reclassified from AOCI		-		-		(1)		-		(10)		(11)
Net current period other comprehensive income (loss)		(138)		19		(1)		-		(10)		(130)
Balance, March 31, 2022	$	(128)	$	54	$	17	$	(1)	$	(47)	$	(105)

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 AOCI		-		-		-		-		5		5
Net current period other comprehensive income (loss)		(111)		16		24		-		5		(66)
Balance, March 31, 2021	$	(59)	$	46	$	25	$	(1)	$	(156)	$	(145)


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

For the		Three months ended March 31

millions of Canadian dollars		2022	2021

	Affected line item in the Condensed Consolidated Financial Statements	Amounts reclassified from AOCI

Gains on derivatives recognized as cash flow hedges
Interest rate hedge	Interest expense, net	$ (1)	$ -

Total		$ (1)	$ -

Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses	Other income, net	$ 2	$ 4

Amounts reclassified into obligations	Pension and post-retirement benefits	(12)	1

Total		$ (10)	$ 5

Total reclassifications out of AOCI for the period		$ (11)	$ 5

12.

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 2022		December 31 2021		March 31 2022	December 31 2021
Regulatory deferral
Commodity swaps and forwards
Coal purchases	$	112	$	22	$	14	$ 1
Power purchases		107		83		5	8
Natural gas purchases and sales		55		20		5	7
Heavy fuel oil purchases		40		21		-	-
Foreign exchange forwards		3		7		7	8
Physical natural gas purchases and sales		80		88		-	-
		397		241		31	24
HFT derivatives
Power swaps and physical contracts		46		33		49	32
Natural gas swaps, futures, forwards, physical contracts		262		208		784	818
		308		241		833	850
Other derivatives
Equity derivatives		7		11		-	-
Foreign exchange forwards		1		-		-	-
		8		11		-	-
Total gross current derivatives		713		493		864	874
Impact of master netting agreements with intent to settle net or simultaneously		(245)		(192)		(245)	(192)
Total derivatives	$	468	$	301	$	619	$ 682
Current	$	384	$	195	$	530	$ 533
Long-term		84		106		89	149
Total derivatives	$	468	$	301	$	619	$ 682

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		2022		2021		2022	2021
Regulatory deferral	$	17	$	4	$	17	$ 4
HFT derivatives		228		188		228	188
Total impact of master netting agreements with intent to settle net or simultaneously	$	245	$	192	$	245	$ 192

Cash Flow Hedges

On May 26, 2021 the treasury lock was settled for a gain of $18 million USD that will be amortized through interest expense over 10 years. As of March 31, 2022, there were no outstanding cash flow hedges.

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	2022	2021
	Interest rate hedge	Interest rate hedge
Realized gain in interest expense, net	$ 1	$ -
Total gains in net income	$ 1	$ -

As at	March 31	December 31
millions of Canadian dollars	2022	2021
	Interest rate hedge	Interest rate hedge
Total unrealized gain in AOCI – effective portion, net of tax	$ 17	$ 18

The Company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

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					2022
		Natural gas and biofuel energy		Commodity swaps and forwards	Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	-	$	(8)	$ (2)
Unrealized gain (loss) in regulatory liabilities		21		221	(4)
Realized (gain) loss in regulatory assets		-		2	-
Realized (gain) loss in regulatory liabilities		-		(9)	-
Realized (gain) loss in inventory (1)		-		(10)	2
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(29)		(36)	1
Total change derivative instruments	$	(8)	$	160	$ (3)
(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 and hedging relationships that have been terminated or the hedged transaction is no longer probable.

For the				Three months ended March 31
millions of Canadian dollars					2021
		Natural gas and biofuel energy		Commodity swaps and forwards	Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	-	$	5	$ (2)
Unrealized gain (loss) in regulatory liabilities		-		17	(2)
Realized (gain) loss in regulatory liabilities		-		(2)	-
Realized (gain) loss in inventory (1)		-		6	2
Realized (gain) loss in regulated fuel for generation and purchased power (2)		-		(4)	1
Total change derivative instruments	$	-	$	22	$ (1)
(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 and hedging relationships that have been terminated or the hedged transaction is no longer probable.

Commodity Swaps and Forwards

As at March 31, 2022, 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:


	2022	2023-2024
millions	Purchases	Purchases
Natural Gas (Mmbtu)	13	14
Power (MWh)	1	2

Foreign Exchange Swaps and Forwards

As at March 31, 2022, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated for regulated deferral that are expected to settle as outlined below:


		2022	2023-2024
Foreign exchange contracts (millions of US dollars)	$	159	$ 150
Weighted average rate		1.2856	1.2413
% of USD requirements		75%	29%

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		2022	2021
Power swaps and physical contracts in non-regulated operating revenues	$	(4)	$ 1
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		194	132
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		-	1
	$	190	$ 134

As at March 31, 2022, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:


millions	2022	2023	2024	2025	2026
Natural gas purchases (Mmbtu)	297	114	58	26	26
Natural gas sales (Mmbtu)	400	142	39	9	9
Power purchases (MWh)	1	-	-	-	-
Power sales (MWh)	2	-	-	-	-

Other Derivatives

As at March 31, 2022, 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 USD cash inflows. The equity derivative hedges the return on 2.8 million shares and extends until December 2022. The foreign exchange forwards have a combined notional amount of $52 million USD and expire throughout 2022 and 2023.

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

2022

2021

Foreign

Foreign

Exchange

Equity

Exchange

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

$ -

$ (4)

$ -

$ 5

Unrealized gain (loss) in other income (expense)

(3)

Realized gain (loss) in other income (expense)

Total gains (losses) in net income

$ 1

$ (4)

$ 1

$ 5

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, 2022, the Company had $118 million (December 31, 2021 - $114 million) in financial assets considered to be past due, which had been outstanding for an average 61 days. The fair value of these financial assets was $98 million (December 31, 2021 - $93 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:


As at		March 31	December 31
millions of Canadian dollars		2022	2021
Cash collateral provided to others	$	125	$ 212
Cash collateral received from others	$	198	$ 100

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, 2022, the total fair value of derivatives in a liability position was $619 million (December 31, 2021 – $682 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.

13.

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 12), 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, 2022
millions of Canadian dollars		Level 1		Level 2		Level 3	Total
Assets
Regulatory deferral
Commodity swaps and forwards
Coal purchases	$	-	$	99	$	-	$ 99
Power purchases		103		-		-	103
Natural gas purchases and sales		51		3		-	54
Heavy fuel oil purchases		9		32		-	41
Foreign exchange forwards		-		3		-	3
Physical natural gas purchases and sales		-		-		80	80
		163		137		80	380
HFT derivatives
Power swaps and physical contracts		5		13		2	20
Natural gas swaps, futures, forwards, physical contracts and related transportation		(3)		34		29	60
		2		47		31	80
Other derivatives
Foreign exchange forwards		-		1		-	1
Equity derivatives		7		-		-	7
		7		1		-	8
Total assets		172		185		111	468
Liabilities
Regulatory deferral
Commodity swaps and forwards
Power purchases		3		-		-	3
Natural gas purchases and sales		-		4		-	4
Foreign exchange forwards		-		7		-	7
		3		11		-	14
HFT derivatives
Power swaps and physical contracts		8		13		3	24
Natural gas swaps, futures, forwards and physical contracts		52		91		438	581
		60		104		441	605
Total liabilities		63		115		441	619
Net assets (liabilities)	$	109	$	70	$	(330)	$ (151)


As at		December 31, 2021
millions of Canadian dollars		Level 1		Level 2		Level 3	Total
Assets
Regulatory deferral
Commodity swaps and forwards
Coal purchases	$	-	$	22	$	-	$ 22
Power purchases		83		-		-	83
Natural gas purchases and sales		15		1		-	16
Heavy fuel oil purchases		3		18		-	21
Foreign exchange forwards		-		7		-	7
Physical natural gas purchases and sales		-		-		88	88
		101		48		88	237
HFT derivatives
Power swaps and physical contracts		4		5		4	13
Natural gas swaps, futures, forwards, physical contracts and related transportation		(1)		29		12	40
		3		34		16	53
Other derivatives
Equity derivatives		11		-		-	11
Total assets		115		82		104	301
Liabilities
Regulatory deferral
Commodity swaps and forwards
Power purchases		7		-		-	7
Natural gas purchases and sales		-		5		-	5
Foreign exchange forwards		-		8		-	8
		7		13		-	20
HFT derivatives
Power swaps and physical contracts		4		5		3	12
Natural gas swaps, futures, forwards and physical contracts		13		122		515	650
		17		127		518	662
Total liabilities		24		140		518	682
Net assets (liabilities)	$	91	$	(58)	$	(414)	$ (381)

The change in the fair value of the Level 3 financial assets for the three months ended March 31, 2022 was as follows:

Regulatory Deferral

HFT Derivatives

millions of Canadian dollars

Physical natural gas

purchases and sales

Power

Natural gas

Total

Balance, beginning of period

$ 88

$ 4

$ 12

$ 104

Realized gain (losses) included in fuel for generation and purchased power

(29)

Unrealized gains (losses) included in regulatory assets or liabilities

Total realized and unrealized gains (losses) included in non-regulated operating revenues

(2)

Balance, March 31, 2022

$ 80

$ 2

$ 29

$ 111

The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 2022 was as follows:

HFT Derivatives

millions of Canadian dollars

Power

Natural gas

Total

Balance, beginning of period

$ 515

$ 518

Total realized and unrealized gains included in non-regulated operating revenues

(77)

Balance, March 31, 2022

$ 438

$ 441

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, 2022
millions of Canadian dollars		Fair Value	Valuation Technique	Unobservable Input	Range	Weighted average (1)
Assets
Regulatory deferral – Physical	$	80	Modelled pricing	Third-party pricing	$5.25 - $36.12	$11.64
natural gas purchases and sales				Probability of default	1.05% - 2.10%	1.71%
				Discount rate	0.04% - 3.84%	1.68%
HFT derivatives – Power swaps		2	Modelled pricing	Third-party pricing	$46.60 - $221.40	$117.40
and physical contracts				Probability of default	0.05% - 0.35%	0.29%
				Discount rate	0.00% - 4.27%	0.86%
HFT derivatives –		39	Modelled pricing	Third-party pricing	$2.32 - $12.03	$5.03
Natural gas swaps, futures,				Probability of default	0.02% - 7.44%	0.09%
forwards and physical contracts				Discount rate	0.00% - 18.10%	0.87%
		(10)	Modelled pricing	Third-party pricing	$3.73 - $29.33	$6.04
				Basis adjustment	$0.00 - $0.44	$0.44
				Probability of default	0.05% - 0.49%	0.07%
				Discount rate	0.01% - 4.00%	0.17%
Total assets	$	111
Liabilities
HFT derivatives –	$	1	Modelled pricing	Third-party pricing	$45.85 - $221.40	$163.16
Power swaps and				Own credit risk	0.05% - 0.35%	0.07%
physical contracts				Discount rate	0.04% - 4.27%	1.82%
		2	Modelled pricing	Third-party pricing	$48.01 - $185.00	$116.02
				Correlation factor	99% - 109%	99%
				Own credit risk	0.05% - 0.15%	0.05%
				Discount rate	0.04% - 4.27%	0.93%
HFT derivatives –		414	Modelled pricing	Third-party pricing	$2.32 - $28.89	$12.78
Natural gas swaps, futures,				Own credit risk	0.02% - 7.44%	0.13%
forwards and physical contracts				Discount rate	0.00% - 21.03%	2.85%
		24	Modelled pricing	Third-party pricing	$3.69 - $29.33	$15.04
				Basis adjustment	$0.00 - $0.88	$0.33
				Own credit risk	0.05% - 4.17%	0.07%
				Discount rate	0.00% - 4.00%	1.27%
Total liabilities	$	441
Net liabilities	$	330
(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		Carrying
millions of Canadian dollars		Amount		Fair Value		Level 1		Level 2		Level 3	Total
March 31, 2022	$	14,301	$	14,909	$	-	$	14,489	$	420	$ 14,909
December 31, 2021	$	14,658	$	16,775	$	-	$	16,308	$	467	$ 16,775

The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency gain of $19 million was recorded in OCI for the three months ended March 31, 2022 (2021 – $16 million gain after-tax).

14.

RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy 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 $34 million for the three months ended March 31, 2022 (2021 - $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 $4 million for the three months ended March 31, 2022 (2021 - $7 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, 2022 and at December 31, 2021.


15. RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:

As at		March 31	December 31
millions of Canadian dollars		2022	2021
Customer accounts receivable – billed	$	761	$ 767
Customer accounts receivable – unbilled		341	318
Allowance for credit losses		(20)	(21)
Capitalized transportation capacity (1)		413	316
Income tax receivable		7	8
Prepaid expenses		76	65
Other		247	280
	$	1,825	$ 1,733
(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.

16.

LEASES

Lessor

The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, Seacoast, compressed natural gas (“CNG”) stations and heat pumps.

Commencing in January 2022, the Company leased a Seacoast pipeline, a 21-mile, 30-inch lateral that is classified as a sales-type lease. The term of the pipeline lateral lease is 34 years with a net investment of $100 million USD. The lessee of the new pipeline lateral has renewal options for an additional 16 years. These renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably certain that they will be exercised.

For further information on the Brunswick Pipeline lease, CNG stations and heat pumps, refer to note 19 in Emera’s 2021 annual audited consolidated financial statements.

The total net investment in direct finance and sales-type leases consist of the following:


As at		March 31		December 31
millions of Canadian dollars		2022		2021
Total minimum lease payment to be received	$	1,432	$	947
Less: amounts representing estimated executory costs		(219)		(165)
Minimum lease payments receivable	$	1,213	$	782
Estimated residual value of leased property (unguaranteed)		182		183
Less: unearned finance lease income		(756)		(443)
Net investment in direct finance and sales-type leases	$	639	$	522
Principal due within one year (included in “Receivables and other current assets”)		33		19
Net Investment in direct finance and sales type leases - long-term	$	606	$	503


As at March 31, 2022, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows:

millions of Canadian dollars		2022		2023		2024		2025		2026		Thereafter	Total
Minimum lease payments to be received	$	70	$	92	$	93	$	95	$	93	$	989	$ 1,432
Less: executory costs													(219)
Total													$ 1,213

17.

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, and Grand Bahama Island.

Emera’s net periodic benefit cost included the following:


For the		Three months ended March 31
millions of Canadian dollars		2022	2021
Defined benefit pension plans
Service cost	$	10	$ 11
Non-service cost
Interest cost		20	17
Expected return on plan assets		(35)	(33)
Current year amortization of:
Actuarial losses		2	4
Regulatory asset		4	7
Total non-service costs		(9)	(5)
Total defined benefit pension plans		1	6
Non-pension benefits plan
Service cost		1	1
Non-service cost
Interest cost		2	2
Current year amortization of regulatory asset		1	1
Total non-service costs		3	3
Total non-pension benefits plans		4	4
Total defined benefit plans	$	5	$ 10

Emera’s contributions related to these defined-benefit plans for the three months ended March 31, 2022 were $14 million (2021 - $14 million). Annual employer contributions to the defined-benefit pension plans are estimated to be $41 million for 2022. Emera’s contributions related to these defined-contributions plans for the three months ended March 31, 2022 were $9 million (2021 - $10 million).

18.

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 2021 annual audited consolidated financial statements.

19.

LONG-TERM DEBT

For details regarding long-term debt, refer to note 25 in Emera’s 2021 annual audited consolidated financial statements, and below for 2022 long-term debt financing activity.

Recent Significant Financing Activity by Segment:

Other Electric Utilities

On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25, 2022 to March 25, 2027.

20.

COMMITMENTS AND CONTINGENCIES

A.	Commitments

As at March 31, 2022, 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		2022		2023		2024		2025		2026		Thereafter	Total
Transportation (1)	$	438	$	464	$	377	$	321	$	295	$	2,588	$ 4,483
Purchased power (2)		194		228		242		236		228		2,309	3,437
Fuel, gas supply and storage		758		136		54		48		31		-	1,027
Capital Projects		369		98		4		1		-		-	472
Long-term service agreements (3)		52		57		56		40		33		92	330
Equity investment commitments (4)		240		-		-		-		-		-	240
Leases and other (5)		11		15		14		12		5		115	172
Demand side management		36		1		1		1		-		-	39
	$	2,098	$	999	$	748	$	659	$	592	$	5,104	$ 10,200
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $137 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 upon its commissioning.
(5) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.

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. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $1.8 billion and the approval to collect $168 million from NSPI for the recovery of Maritime Link costs in 2022. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

Once LIL has been commissioned, 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, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the date the NS Block delivery obligation commenced, 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.

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. On May 17, 2021, the ad hoc Committee issued (i) a decision continuing the stay of enforcement of the Second Award until the committee renders its decision on Guatemala’s application for annulment and (ii) an order with dates for briefings on the annulment and a hearing commencing July 27, 2022. Guatemala filed its Memorial on Annulment on August 25, 2021. TGH’s Counter-Memorial on Annulment was filed on December 8, 2021. Guatemala’s reply was filed on Monday, March 7, 2022. TGH’s rejoinder is due on June 6, 2022. To date, the total of the Second Award, with interest, is approximately $62 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, 2022, TEC has estimated its financial liability to be $17 million ($14 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 12 and note 13.

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. The Board of Directors established a Risk and Sustainability Committee (‘RSC”) in September 2021. The mandate of the RSC is to assist the Board in carrying out its risk and sustainability oversight responsibilities and includes oversight of the Company’s Enterprise Risk Management framework, including the identification, assessment, monitoring and management of enterprise risks.

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 foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenue 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 Company’s future access to capital and cost of borrowing may be impacted by various market disruptions. The inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan.

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, increased 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.

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 electric and gas utilities have adopted and implemented fuel adjustment mechanisms and purchased gas adjusted mechanisms respectively, 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 and gas costs.

Emera Energy Marketing and Trading

Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy’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 Energy 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 Emera Energy’s portfolio or 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 2021 audited annual consolidated financial statements, with material updates as noted below:

The Company has standby letters of credit and surety bonds in the amount of $119 million USD (December 31, 2021 - $148 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.

Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will automatically terminate on the date upon which the obligations have been repaid in full.

TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm service agreement, which expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.

21.

SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


For the		Three months ended March 31
millions of Canadian dollars		2022	2021
Changes in non-cash working capital:

Inventory	$	86	$ 32
Receivables and other current assets		(47)	(49)
Accounts payable		(4)	(98)
Other current liabilities		84	74
Total non-cash working capital	$	119	$ (41)

Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	59	$ 53
Increase in accrued capital expenditures	$	30	$ 26

22.

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 NSPML. Thus, Emera records NSPML 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, 2022

December 31, 2021

Maximum

Maximum

millions of Canadian dollars

Total
assets

exposure to
loss

Total
assets

exposure to
loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

527

533

23.

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.

24.

SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 12, 2022, the date the financial statements were issued.

Emera (ERRAF) 6-KCurrent report (foreign)