Emera (ERRAF) 6-K Current report (foreign)

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

June 30, 2022 and 2021

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars (except per share amounts)	2022		2021		2022		2021
Operating revenues
Regulated electric	$	1,349	$	1,099	$	2,622	$	2,201
Regulated gas		339		244		841		637
Non-regulated		(308)		(206)		(68)		(89	)
Total operating revenues (note 5)		1,380		1,137		3,395		2,749
Operating expenses
Regulated fuel for generation and purchased power		541		392		1,018		787
Regulated cost of natural gas		149		69		405		226
Operating, maintenance and general expenses (“OM&G”)		378		344		765		661
Provincial, state and municipal taxes		91		81		177		161
Depreciation and amortization		230		221		460		447
Total operating expenses		1,389		1,107		2,825		2,282
Income (loss) from operations		(9)		30		570		467
Income from equity investments (note 7)		33		37		60		78
Other income, net		21		25		44		45
Interest expense, net		163		153		319		310
Income (loss) before provision for income taxes		(118)		(61)		355		280
Income tax expense (recovery) (note 8)		(66)		(55)		29		1
Net income (loss)		(52)		(6)		326		279
Non-controlling interest in subsidiaries		—		—		—		1
Preferred stock dividends		15		11		31		22
Net income (loss) attributable to common shareholders	$	(67)	$	(17)	$	295	$	256
Weighted average shares of common stock outstanding (in millions) (note 10)
Basic		264.4		255.8		263.1		254.6
Diluted		264.4		255.8		263.6		255.0
Earnings (loss) per common share (note 10)
Basic	$	(0.25)	$	(0.07)	$	1.12	$	1.01
Diluted	$	(0.25)	$	(0.07)	$	1.12	$	1.01
Dividends per common share declared	$	0.6625	$	0.6375	$	1.3250	$	1.2750

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

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Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2022		2021		2022		2021
Net income (loss)	$	(52)	$	(6)	$	326	$	279
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment (1)		285		(133)		147		(244)
Unrealized gains (losses) on net investment hedges (2) (3)		(40)		18		(21)		34
Cash flow hedges
Net derivative gains (losses) (4)		-		(6)		-		18
Less: reclassification adjustment for losses (gains) included in income		-		-		(1)		-
Net effects of cash flow hedges		-		(6)		(1)		18
Net change in unrecognized pension and post-retirement benefit obligation		2		4		(8)		9
Other comprehensive income (loss) (5)		247		(117)		117		(183)
Comprehensive income (loss)		195		(123)		443		96
Comprehensive income attributable to non-controlling interest		-		-		-		1
Comprehensive income (loss) of Emera Incorporated	$	195	$	(123)	$	443	$	95

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

(1) Net of tax expense of nil (2021 - $5 million expense) for the three months ended June 30, 2022 and tax expense of nil (2021 – $5 million expense) for the six months ended June 30, 2022.

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

(3) Net of tax recovery of $7 million (2021 - $3 million expense) for the three months ended June 30, 2022 and tax recovery of $4 million (2021 – $6 million expense) for the six months ended June 30, 2022.

(4) Net of tax expense of nil (2021 - $2 million recovery) for the three months ended June 30, 2022 and tax expense of nil (2021 – $6 million expense) for the six months ended June 30, 2022.

(5) Net of tax recovery of $7 million (2021 - $6 million expense) for the three months ended June 30, 2022 and tax recovery of $4 million (2021 – $17 million expense) for the six months ended June 30, 2022.

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Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

As at	June 30		December 31
millions of dollars	2022		2021
Assets
Current assets
Cash and cash equivalents	$	275	$	394
Restricted cash (note 22)		21		23
Inventory		591		538
Derivative instruments (notes 12 and 13)		539		195
Regulatory assets (note 6)		484		253
Receivables and other current assets (note 15)		2,043		1,733
		3,953		3,136
Property, plant and equipment, net of accumulated depreciation and amortization of $9,044 and $8,739, respectively		21,023		20,353
Other assets
Deferred income taxes (note 8)		344		295
Derivative instruments (notes 12 and 13)		108		106
Regulatory assets (note 6)		2,437		2,313
Net investment in direct finance and sales type leases (note 16)		606		503
Investments subject to significant influence (note 7)		1,396		1,382
Goodwill		5,789		5,696
Other long-term assets		575		460
		11,255		10,755
Total assets	$	36,231	$	34,244
Liabilities and Equity
Current liabilities
Short-term debt (note 18)	$	1,444	$	1,742
Current portion of long-term debt (note 19)		997		462
Accounts payable		1,760		1,485
Derivative instruments (notes 12 and 13)		871		533
Regulatory liabilities (note 6)		487		290
Other current liabilities		370		366
		5,929		4,878
Long-term liabilities
Long-term debt (note 19)		14,485		14,196
Deferred income taxes (note 8)		1,932		1,868
Derivative instruments (notes 12 and 13)		199		149
Regulatory liabilities (note 6)		1,818		1,765
Pension and post-retirement liabilities (note 17)		359		370
Other long-term liabilities (note 7)		1,047		868
		19,840		19,216
Equity
Common stock (note 9)		7,509		7,242
Cumulative preferred stock		1,422		1,422
Contributed surplus		80		79
Accumulated other comprehensive income (“AOCI’) (note 11)		142		25
Retained earnings		1,295		1,348
Total Emera Incorporated equity		10,448		10,116
Non-controlling interest in subsidiaries		14		34
Total equity		10,462		10,150
Total liabilities and equity	$	36,231	$	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

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Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the	Six months ended June 30
millions of dollars	2022		2021
Operating activities
Net income	$	326	$	279
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		457		454
Income from equity investments, net of dividends		(26)		(40)
Allowance for equity funds used during construction		(24)		(27)
Deferred income taxes, net		13		(10)
Net change in pension and post-retirement liabilities		(21)		(10)
Regulated fuel adjustment mechanism		(126)		(45)
Net change in fair value of derivative instruments		217		147
Net change in regulatory assets and liabilities		(126)		(127)
Net change in capitalized transportation capacity		(92)		31
Other operating activities, net		148		32
Changes in non-cash working capital (note 21)		(73)		(53)
Net cash provided by operating activities		673		631
Investing activities
Additions to property, plant and equipment		(1,041)		(999)
Other investing activities		11		6
Net cash used in investing activities		(1,030)		(993)
Financing activities
Change in short-term debt, net		285		(16)
Repayment of short-term debt with maturities greater than 90 days		-		(377)
Proceeds from long-term debt, net of issuance costs		2		2,330
Retirement of long-term debt		(21)		(1,531)
Net repayments (issuances) under committed credit facilities		90		(182)
Issuance of common stock, net of issuance costs		149		143
Issuance of preferred stock, net of issuance costs		-		195
Dividends on common stock		(233)		(217)
Dividends on preferred stock		(31)		(22)
Other financing activities		(3)		(3)
Net cash provided by financing activities		238		320
Effect of exchange rate changes on cash, cash equivalents and restricted cash		(2)		(5)
Net decrease in cash, cash equivalents, and restricted cash		(121)		(47)
Cash, cash equivalents and restricted cash, beginning of period		417		254
Cash, cash equivalents and restricted cash, end of period	$	296	$	207
Cash, cash equivalents, and restricted cash consists of:
Cash	$	201	$	174
Short-term investments		74		-
Restricted cash		21		33
Cash, cash equivalents and restricted cash	$	296	$	207

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

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Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

millions of dollars	Common Stock		Preferred Stock		Contributed Surplus		AOCI		Retained Earnings		Non- Controlling Interest		Total Equity
For the three months ended June 30, 2022
Balance, March 31, 2022	$	7,365	$	1,422	$	79	$	(105)	$	1,537	$	14	$	10,312
Net loss of Emera Incorporated		-		-		-		-		(52)		-		(52)
Other comprehensive income, net of tax recovery of $7 million		-		-		-		247		-		-		247
Dividends declared on preferred stock (1)		-		-		-		-		(15)		-		(15)
Dividends declared on common stock ($0.6625/share)		-		-		-		-		(175)		-		(175)
Issued under the Dividend Reinvestment Program, net of discounts		63		-		-		-		-		-		63
Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs		72		-		-		-		-		-		72
Senior management stock options exercised and Employee Share Purchase Plan		9		-		1		-		-		-		10
Balance, June 30, 2022	$	7,509	$	1,422	$	80	$	142	$	1,295	$	14	$	10,462
For the six months ended June 30, 2022
Balance, December 31, 2021	$	7,242	$	1,422	$	79	$	25	$	1,348	$	34	$	10,150
Net income of Emera Incorporated		-		-		-		-		326		-		326
Other comprehensive income, net of tax recovery of $4 million		-		-		-		117		-		-		117
Dividends declared on preferred stock (2)		-		-		-		-		(31)		-		(31)
Dividends declared on common stock ($1.3250/share)		-		-		-		-		(348)		-		(348)
Disposal of non-controlling interest of Dominica Electricity Services Ltd (“Domlec”)		-		-		-		-		-		(20)		(20)
Issued under the Dividend Reinvestment Program, net of discounts		128		-		-		-		-		-		128
Issuance of common stock under ATM program, net of after-tax issuance costs		128		-		-		-		-		-		128
Senior management stock options exercised and Employee Share Purchase Plan		11		-		1		-		-		-		12
Balance, June 30, 2022	$	7,509	$	1,422	$	80	$	142	$	1,295	$	14	$	10,462

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

(1)    Series A; $0.1364/share, Series B; $0.1270/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

(2)    Series A; $0.2728/share, Series B; $0.2523/share, Series C; $0.59012/share, Series E; $0.5625/share, Series F; $0.52526/share; Series H; $0.6125/share; Series J; $0.53125/share and Series L; $0.575/share

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Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

millions of dollars	Common Stock		Preferred Stock		Contributed Surplus		AOCI		Retained Earnings		Non- Controlling Interest		Total Equity
For the three months ended June 30, 2021
Balance, March 31, 2021	$	6,816	$	1,004	$	79	$	(145)	$	1,608	$	34	$	9,396
Net loss of Emera Incorporated		-		-		-		-		(6)		-		(6)
Other comprehensive loss, net of tax expense of $6 million		-		-		-		(117)		-		-		(117)
Dividends declared on preferred stock (1)		-		-		-		-		(11)		-		(11)
Dividends declared on common stock ($0.6375/share)		-		-		-		-		(162)		-		(162)
Issuance of preferred stock, net of after-tax issuance costs		-		196		-		-		-		-		196
Issued under the Dividend Reinvestment Program, net of discounts		60		-		-		-		-		-		60
Issuance of common stock under ATM program, net of after-tax issuance costs		78		-		-		-		-		-		78
Senior management stock options exercised and Employee Share Purchas Plan		3		-		-		-		-		-		3
Other		-		-		-		-		2		-		2
Balance, June 30, 2021	$	6,957	$	1,200	$	79	$	(262)	$	1,431	$	34	$	9,439
For the six months ended June 30, 2021
Balance, December 31, 2020	$	6,705	$	1,004	$	79	$	(79)	$	1,495	$	34	$	9,238
Net income of Emera Incorporated		-		-		-		-		278		1		279
Other comprehensive loss, net of tax expense of $17 million		-		-		-		(183)		-		-		(183)
Dividends declared on preferred stock (2)		-		-		-		-		(22)		-		(22)
Dividends declared on common stock ($1.2750/share)		-		-		-		-		(322)		-		(322)
Issuance of preferred stock, net of after-tax issuance costs		-		196		-		-		-		-		196
Issued under the Dividend Reinvestment Program, net of discounts		119		-		-		-		-		-		119
Issuance of common stock under ATM program, net of after-tax issuance costs		128		-		-		-		-		-		128
Senior management stock option exercised and Employee Share Purchase Plan		5		-		-		-		-		-		5
Other		-		-		-		-		2		(1)		1
Balance, June 30, 2021	$	6,957	$	1,200	$	79	$	(262)	$	1,431	$	34	$	9,439

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

(1) Series A; $0.1364/share, Series B; $0.1168/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; $0.2728/share, Series B; $0.2391/share, Series C; $0.59012/share, Series E; $0.5625/share, Series F; $0.52526/share and Series H; $0.6125/share

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Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at June 30, 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 June 30, 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 35 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.

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• 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 renewable 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 unaudited condensed consolidated interim financial statements as at and for the three and six months ended June 30, 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 unaudited 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, 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.

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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”). ASUs issued by FASB, but which are not yet effective, were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the unaudited 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.

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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.

millions of dollars	Florida Electric Utility		Canadian Electric Utilities		Gas Utilities and Infrastructure		Other Electric Utilities		Other		Inter- Segment Eliminations			Total
For the three months ended June 30, 2022
Operating revenues from external customers (1)	$	845	$	375	$	341	$	131	$	(312)	$	-		$	1,380
Inter-segment revenues (1)		1		-		2		-		6		(9)			-
Total operating revenues		846		375		343		131		(306)		(9)			1,380
Regulated fuel for generation and purchased power		288		176		-		79		-		(2)			541
Regulated cost of natural gas		-		-		149		-		-		-			149
Depreciation and amortization		124		64		26		14		2		-			230
Interest expense, net		40		32		16		5		70		-			163
Internally allocated interest (2)		-		-		3		-		(3)		-			-
OM&G		147		84		86		31		34		(4)			378
Income tax expense (recovery)		41		-		13		-		(120)		-		��	(66)
Net income (loss) attributable to common shareholders		161		39		39		5		(311)		-			(67)
For the six months ended June 30, 2022
Operating revenues from external customers (1)		1,489		884		848		250		(76)		-			3,395
Inter-segment revenues (1)		3		-		3		-		16		(22)			-
Total operating revenues		1,492		884		851		250		(60)		(22)			3,395
Regulated fuel for generation and purchased power		460		418		-		142		-		(2)			1,018
Regulated cost of natural gas		-		-		405		-		-		-			405
Depreciation and amortization		244		127		53		32		4		-			460
Interest expense, net		78		65		30		9		137		-			319
Internally allocated interest (2)		-		-		6		-		(6)		-			-
OM&G		289		175		176		62		71		(8)			765
Income tax expense (recovery)		66		3		38		-		(78)		-			29
Net income (loss) attributable to common shareholders		273		130		116		4		(228)		-			295
As at June 30, 2022
Total assets		19,001		7,926		6,866		1,362		2,376		(1,300)	(3)		36,231

(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.

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millions of dollars	Florida Electric Utility		Canadian Electric Utilities		Gas Utilities and Infrastructure		Other Electric Utilities			Other		Inter- Segment Eliminations			Total
For the three months ended June 30, 2021
Operating revenues from external customers (1)	$	651	$	341	$	248	$	107		$	(210)	$	-		$	1,137
Inter-segment revenues (1)		2		-		-		-			14		(16)			-
Total operating revenues		653		341		248		107			(196)		(16)			1,137
Regulated fuel for generation and purchased power		191		147		-		54			-		-			392
Regulated cost of natural gas		-		-		69		-			-		-			69
Depreciation and amortization		113		62		29		15			2		-			221
Interest expense, net		35		33		14		5			66		-			153
Internally allocated interest (2)		-		-		4		-			(4)		-			-
OM&G		131		72		78		36			29		(2)			344
Income tax expense (recovery)		19		2		9		1			(86)		-			(55)
Net income (loss) attributable to common shareholders		125		44		34		(1)			(219)		-			(17)
For the six months ended June 30, 2021
Operating revenues from external customers (1)		1,216		784		645		201			(97)		-			2,749
Inter-segment revenues (1)		3		-		2		-			14		(19)			-
Total operating revenues		1,219		784		647		201			(83)		(19)			2,749
Regulated fuel for generation and purchased power		354		340		-		95			-		(2)			787
Regulated cost of natural gas		-		-		226		-			-		-			226
Depreciation and amortization		231		123		59		30			4		-			447
Interest expense, net		71		68		26		10			135		-			310
Internally allocated interest (2)		-		-		7		-			(7)		-			-
OM&G		248		150		159		61			49		(6)			661
Income tax expense (recovery)		33		8		34		1			(75)		-			1
Net income (loss) attributable to common shareholders		208		132		114		6	��		(204)		-			256
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.

45

5.  REVENUE

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

	Electric						Gas		Other
millions of dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total
For the three months ended June 30, 2022
Regulated Revenue
Residential	$	444	$	182	$	45	$	139	$	-	$	-	$	810
Commercial		218		97		74		95		-		-		484
Industrial		58		80		8		19		-		-		165
Other regulatory deferrals		120		7		2		-		-		-		129
Other (1)		6		9		2		71		-		(3)		85
Finance income (2)(3)		-		-		-		15		-		-		15
Regulated revenue		846		375		131		339		-		(3)		1,688
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		(2)		-		(2)
Energy sales		-		-		-		-		-		(1)		(1)
Other		-		-		-		4		3		-		7
Mark-to-market (3)		-		-		-		-		(307)		(5)		(312)
Non-regulated revenue		-		-		-		4		(306)		(6)		(308)
Total operating revenues	$	846	$	375	$	131	$	343	$	(306)	$	(9)	$	1,380
For the six months ended June 30, 2022
Regulated Revenue
Residential	$	786	$	467	$	88	$	416	$	-	$	-	$	1,757
Commercial		391		219		136		232		-		(1)		977
Industrial		105		168		15		37		-		-		325
Other electric and regulatory deferrals		200		14		7		-		-		-		221
Other (1)		10		16		4		129		-		(5)		154
Finance income (2)(3)		-		-		-		29		-		-		29
Regulated revenue		1,492		884		250		843		-		(6)		3,463
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		47		-		47
Energy sales		-		-		-		-		3		(6)		(3)
Other		-		-		-		8		7		-		15
Mark-to-market (3)		-		-		-		-		(117)		(10)		(127)
Non-regulated revenue		-		-		-		8		(60)		(16)		(68)
Total operating revenues	$	1,492	$	884	$	250	$	851	$	(60)	$	(22)	$	3,395

(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.

46

	Electric						Gas		Other
millions of dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total
For the three months ended June 30, 2021
Regulated Revenue
Residential	$	338	$	175	$	42	$	110	$	-	$	-	$	665
Commercial		177		92		55		78		-		-		402
Industrial		51		59		6		16		-		-		132
Other regulatory deferrals		83		7		1		-		-		-		91
Other (1)		4		8		3		26		-		(2)		39
Finance income (2)(3)		-		-		-		14		-		-		14
Regulated revenue		653		341		107		244		-		(2)		1,343
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		-		-		-
Energy sales		-		-		-		-		6		(6)		-
Other		-		-		-		4		3		-		7
Mark-to-market (3)		-		-		-		-		(205)		(8)		(213)
Non-regulated revenue		-		-		-		4		(196)		(14)		(206)
Total operating revenues	$	653	$	341	$	107	$	248	$	(196)	$	(16)	$	1,137
For the six months ended June 30, 2021
Regulated Revenue
Residential	$	632	$	434	$	77	$	328	$	-	$	-	$	1,471
Commercial		336		206		102		192		-		-		836
Industrial		98		115		13		32		-		(1)		257
Other regulatory deferrals		144		14		3		-		-		-		161
Other (1)		9		15		6		59		-		(4)		85
Finance income (2)(3)		-		-		-		28		-		-		28
Regulated revenue		1,219		784		201		639		-		(5)		2,838
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		67		-		67
Energy sales		-		-		-		-		12		(11)		1
Other		-		-		-		8		5		-		13
Mark-to-market (3)		-		-		-		-		(167)		(3)		(170)
Non-regulated revenue		-		-		-		8		(83)		(14)		(89)
Total operating revenues	$	1,219	$	784	$	201	$	647	$	(83)	$	(19)	$	2,749

(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 June 30, 2022, the aggregate amount of the transaction price allocated to remaining performance obligations was $432 million (2021 – $430 million). This amount includes $140 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.

47

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 millions of dollars	June 30 2022		December 31 2021
Regulatory assets
Deferred income tax regulatory assets	$	1,110	$	1,045
Tampa Electric capital cost recovery for early retired assets		654		657
Cost recovery clauses		312		114
Pension and post-retirement medical plan		282		291
Regulated fuel adjustment mechanism (“FAM”)		271		145
NMGC winter event gas cost recovery		87		117
Storm restoration regulatory asset		36		35
Deferrals related to derivative instruments		33		23
Environmental remediations		28		27
Stranded cost recovery		27		26
Other		81		86
	$	2,921	$	2,566
Current	$	484	$	253
Long-term		2,437		2,313
Total regulatory assets	$	2,921	$	2,566
Regulatory liabilities
Deferred income tax regulatory liabilities	$	875	$	863
Accumulated reserve - cost of removal		838		819
Deferrals related to derivative instruments		447		241
Storm reserve		60		58
Cost recovery clauses		42		35
Self-insurance fund (note 22)		28		28
Other		15		11
	$	2,305	$	2,055
Current	$	487	$	290
Long-term		1,818		1,765
Total regulatory liabilities	$	2,305	$	2,055

Tampa Electric

ROE Adjustment

Tampa Electric’s 2021 settlement agreement allows the company to request an increase to revenue and ROE due to increases in the 30-year United States Treasury bond yield rate. On July 1, 2022, Tampa Electric requested the Florida Public Service Commission (“FPSC”) to increase its annual base rates by $10 million United States Dollars (“USD”) and to increase its ROE. If approved, the new mid-point ROE will be 10.20 per cent, and the range will be 9.25 per cent to 11.25 per cent. The FPSC is expected to issue a decision in August 2022.

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 from 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 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.

48

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 effective timing of any approved increases would be determined by the UARB. The hearing for this matter is scheduled for September 2022 and a decision by the UARB is expected later in the year.

Nova Scotia Cap-and-Trade Program

As at June 30, 2022, the FAM includes a recovery of $150 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. Each 1 per cent change in forecasted emissions for the balance of the compliance period would result in a $3 million change in the expense and liability, which NSPI anticipates being recoverable through the FAM.

NSPML

On August 3, 2022, NSPML submitted an application to the UARB requesting recovery of approximately $164 million in Maritime Link costs for 2023. A decision is expected in Q4 2022.

NMGC

On December 13, 2021, NMGC filed a rate case with the New Mexico Public Regulation Commission (“NMPRC”) for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The proposed rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. A hearing was held in June 2022 and a decision from the NMPRC is expected in Q4 2022.

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 expects 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. The approved increase in annual revenues of $3.5 million USD commenced on April 1, 2022.

49

7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

	Carrying Value as at				Equity Income for the three months ended				Equity Income for the six months ended				Percentage of
	June 30		December 31		June 30				June 30				Ownership
millions of dollars	2022		2021		2022		2021		2022		2021		2022
LIL (1)	$	710	$	682	$	14	$	13	$	28	$	26		35.0
NSPML		518		533		10		14		16		27		100.0
M&NP (2)		123		123		4		5		9		10		12.9
Lucelec (2)		45		44		1		1		2		2		19.5
Bear Swamp (3)		-		-		4		4		5		13		50.0
	$	1,396	$	1,382	$	33	$	37	$	60	$	78

(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 – $105 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 millions of dollars	June 30 2022		December 31 2021
Current assets	$	19	$	25
Property, plant and equipment		1,548		1,587
Regulatory assets		262		247
Non-current assets		31		31
Total assets	$	1,860	$	1,890
Current liabilities	$	49	$	50
Long-term debt (1)		1,169		1,189
Non-current liabilities		124		118
Equity		518		533
Total liabilities and equity	$	1,860	$	1,890

(1) The project debt has been guaranteed by the Government of Canada.    

50

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:

	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2022		2021		2022		2021
Income (loss) before provision for income taxes	$	(118)	$	(61)	$	355	$	280
Statutory income tax rate		29.0%		29.0%		29.0%		29.0%
Income taxes, at statutory income tax rate		(34)		(18)		103		81
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(10)		(11)		(35)		(31)
Foreign tax rate variance		(9)		(6)		(16)		(16)
Amortization of deferred income tax regulatory liabilities		(8)		(11)		(13)		(16)
Tax effect of equity earnings		(3)		(5)		(5)		(9)
Tax credits		(1)		(4)		(4)		(7)
Other		(1)		-		(1)		(1)
Income tax (recovery) expense	$	(66)	$	(55)	$	29	$	1
Effective income tax rate		56%		90%		8%		0%

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.

51

9. COMMON STOCK

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

Issued and outstanding:	millions of shares		millions of dollars
Balance, December 31, 2021		261.07	$	7,242
Issuance of common stock under ATM program (1)		2.08		128
Issued under the Dividend Reinvestment Program, net of discounts		2.17		128
Senior management stock options exercised and Employee Share Purchase Plan		0.20		11
Balance, June 30, 2022		265.52	$	7,509

(1) In Q2 2022, 1,158,768 common shares were issued under Emera’s ATM program at an average price of $62.64 per share for gross proceeds of $73 million ($72 million net of after-tax issuance costs). For the six months ended June 30, 2022, 2,078,868 common shares were issued under Emera’s ATM program at an average price of $61.83 per share for gross proceeds of $129 million ($128 million net of after-tax issuance costs). As at June 30, 2022, an aggregate gross sales limit of $328 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:

	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars (except per share amounts)	2022		2021		2022		2021
Numerator
Net income (loss) attributable to common shareholders	$	(67.2)	$	(16.9)	$	294.5	$	256.4
Diluted numerator		(67.2)		(16.9)		294.5		256.4
Denominator
Weighted average shares of common stock outstanding		264.4		254.5		263.1		253.3
Weighted average deferred share units outstanding (1)		-		1.3		-		1.3
Weighted average shares of common stock outstanding – basic		264.4		255.8		263.1		254.6
Stock-based compensation (2)		-		-		0.5		0.4
Weighted average shares of common stock outstanding – diluted		264.4		255.8		263.6		255.0
Earnings (loss) per common share
Basic	$	(0.25)	$	(0.07)	$	1.12	$	1.01
Diluted	$	(0.25)	$	(0.07)	$	1.12	$	1.01

(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.

(2) The potential common shares from 0.5 million related to stock-based compensation were excluded from diluted EPS for the three months ended June 30, 2022 and 2021, as the Company had net losses in both quarters.

52

11. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of AOCI, net of tax, are as follows:

millions of 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 six months ended June 30, 2022
Balance, January 1, 2022	$	10	$	35	$	18	$	(1)	$	(37)	$	25
Other comprehensive income (loss) before reclassifications		147		(21)		-		-		-		126
Amounts reclassified from AOCI		-		-		(1)		-		(8)		(9)
Net current period other comprehensive income (loss)		147		(21)		(1)		—		(8)		117
Balance, June 30, 2022	$	157	$	14	$	17	$	(1)	$	(45)	$	142
For the six months ended June 30, 2021
Balance, January 1, 2021	$	52	$	30	$	1	$	(1)	$	(161)	$	(79)
Other comprehensive income (loss) before reclassifications		(244)		34		18		-		-		(192)
Amounts reclassified from AOCI		-		-		-		-		9		9
Net current period other comprehensive income (loss)		(244)		34		18		-		9		(183)
Balance, June 30, 2021	$	(192)	$	64	$	19	$	(1)	$	(152)	$	(262)

The reclassifications out of AOCI are as follows:

For the		Three months ended June 30				Six months ended June 30
millions of dollars		2022		2021		2022		2021
Affected line item in the Consolidated Interim Financial Statements			Amounts reclassified from AOCI
Losses (gain) 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	$	5	$	4	$	9
Amounts reclassified into obligations	Pension and post-retirement liabilities		-		(1)		(12)		-
Total			2		4		(8)		9
Total reclassifications out of AOCI, for the period		$	2	$	4	$	(9)	$	9

53

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:

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

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

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

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

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

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

	Derivative Assets				Derivative Liabilities
As at millions of dollars	June 30 2022		December 31 2021		June 30 2022		December 31 2021
Regulatory deferral
Commodity swaps and forwards
Coal purchases	$	128	$	22	$	15	$	1
Power purchases		156		83		17		8
Natural gas purchases and sales		49		20		20		7
Heavy fuel oil purchases		38		21		4		-
Foreign exchange forwards		9		7		2		8
Physical natural gas purchases		93		88		-		-
		473		241		58		24
HFT derivatives
Power swaps and physical contracts		190		33		186		32
Natural gas swaps, futures, forwards, physical contracts		358		208		1,204		818
		548		241		1,390		850
Other derivatives
Equity derivatives		2		11		-		-
Foreign exchange forwards		7		-		5		-
		9		11		5		-
Total gross current derivatives		1,030		493		1,453		874
Impact of master netting agreements with intent to settle net or simultaneously		(383)		(192)		(383)		(192)
Total derivatives	$	647	$	301	$	1,070	$	682
Current	$	539	$	195	$	871	$	533
Long-term		108		106		199		149
Total derivatives	$	647	$	301	$	1,070	$	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 millions of dollars	June 30 2022		December 31 2021		June 30 2022		December 31 2021
Regulatory deferral	$	37	$	4	$	37	$	4
HFT derivatives		346		188		346		188
Total impact of master netting agreements with intent to settle net or simultaneously	$	383	$	192	$	383	$	192

Cash Flow Hedges

On May 26, 2021 the treasury lock was settled for a gain of $19 million USD that will be amortized through interest expense over 10 years. As of June 30, 2022, there were no outstanding cash flow hedges.

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

	Three months ended June 30				Six months ended June 30
For the	2022		2021		2022		2021
millions of dollars	Interest rate hedge		Foreign exchange forwards		Interest rate hedge		Foreign exchange forwards
Realized gain in interest expense, net	$	-	$	-	$	1	$	-
Total gains in net income	$	-	$	-	$	1	$	-
As at	June 30, 2022				December 31, 2021
millions of dollars			Interest rate hedge				Interest rate hedge
Total unrealized gain in AOCI – 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:

millions of dollars	Physical natural gas purchases		Commodity swaps and forwards		Foreign exchange forwards		Physical natural gas purchases		Commodity swaps and forwards		Foreign exchange forwards
For the three months ended June 30					2022						2021
Unrealized gain (loss) in regulatory assets	$	-	$	(30)	$	3	$	-	$	6	$	(1)
Unrealized gain (loss) in regulatory liabilities		18		108		6		-		70		(2)
Realized (gain) loss in regulatory assets		-		14		-		-		(2)		-
Realized gain in regulatory liabilities		-		(13)		-		-		-		-
Realized (gain) loss in inventory (1)		-		(32)		2		-		-		1
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(5)		(22)		-		-		4		3
Total change in derivative instruments	$	13	$	25	$	11	$	-	$	78	$	1
millions of dollars	Physical natural gas purchases		Commodity swaps and forwards		Foreign exchange forwards		Physical natural gas purchases		Commodity swaps and forwards		Foreign exchange forwards
For the six months ended June 30					2022						2021
Unrealized gain (loss) in regulatory assets	$	-	$	(38)	$	1	$	-	$	11	$	(3)
Unrealized gain (loss) in regulatory liabilities		39		329		2		-		87		(4)
Realized (gain) loss in regulatory assets		-		16		-		-		(2)		-
Realized gain in regulatory liabilities		-		(22)		-		-		(2)		-
Realized (gain) loss in inventory (1)		-		(42)		4		-		6		3
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(34)		(58)		1		-		-		4
Total change in derivative instruments	$	5	$	185	$	8	$	-	$	100	$	-

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

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

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Physical Natural Gas Purchases

As at June 30, 2022, the Company had the following notional volumes of physical natural gas purchases for regulatory deferral that are expected to settle as outlined below:

millions	2022 Purchases		2023-2024 Purchases
Natural Gas (Mmbtu)		4		6

Commodity Swaps and Forwards

As at June 30, 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:

millions	2022 Purchases		2023-2024 Purchases
Natural Gas (Mmbtu)		13		25
Power (MWh)		-		3

Foreign Exchange Swaps and Forwards

As at June 30, 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 USD)	$	104	$	150
Weighted average rate		1.2782		1.2413
% of USD requirements		72%		17%

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

HFT 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 June 30				Six months ended June 30
millions of dollars	2022		2021		2022		2021
Power swaps and physical contracts in non-regulated operating revenues	$	8	$	1	$	4		$                 2
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		(266)		(121)		(72)		7
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		-		-		-		1
	$	(258)	$	(120)	$	(68)		$               10

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As at June 30, 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)		240		176		70		27		26
Natural gas sales (Mmbtu)		304		186		51		13		3
Power purchases (MWh)		3		2		-		-		-
Power sales (MWh)		3		2		-		-		-

Other Derivatives

As at June 30, 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 $317 million USD and expire throughout 2022, 2023, and 2024.

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

millions of dollars	Foreign exchange forwards		Equity derivatives		Foreign exchange forwards		Equity derivatives
For the three months ended June 30				2022				2021
Unrealized gain (loss) in OM&G	$	-	$	(5)	$	-	$	1
Unrealized loss in other income, net		-		-		(3)		-
Realized gain in other income, net		-		-		5		-
Total gains (losses) in net income	$	-	$	(5)	$	2	$	1
	Foreign exchange forwards		Equity derivatives		Foreign exchange forwards		Equity derivatives
For the six months ended June 30				2022				2021
Unrealized gain (loss) in OM&G	$	-	$	(9)	$	-	$	6
Unrealized gain (loss) in other income, net		1		-		(6)		-
Realized gain in other income, net		-		-		9		-
Total gains (losses) in net income	$	1	$	(9)	$	3	$	6

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.

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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 June 30, 2022, the Company had $145 million (December 31, 2021 - $114 million) in financial assets considered to be past due, which had been outstanding for an average 60 days. The fair value of these financial assets was $127 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 millions of dollars	June 30 2022		December 31 2021
Cash collateral provided to others	$	275	$	212
Cash collateral received from others	$	251	$	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 June 30, 2022, the total fair value of derivatives in a liability position was $1,070 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.

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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	June 30, 2022
millions of dollars		Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral
Commodity swaps and forwards
Coal purchases	$	-	$	113	$	-	$	113
Power purchases		148		-		-		148
Natural gas purchases and sales		28		7		-		35
Heavy fuel oil purchases		11		27		-		38
Foreign exchange forwards		-		9		-		9
Physical natural gas purchases		-		-		93		93
		187		156		93		436
HFT derivatives
Power swaps and physical contracts		6		62		8		76
Natural gas swaps, futures, forwards, physical contracts and related transportation		-		67		59		126
		6		129		67		202
Other derivatives
Foreign exchange forwards		-		7		-		7
Equity derivatives		2		-		-		2
		2		7		-		9
Total assets		195		292		160		647
Liabilities
Regulatory deferral
Commodity swaps and forwards
Power purchases		9		-		-		9
Heavy fuel oil purchases		4		-		-		4
Natural gas purchases and sales		-		6		-		6
Foreign exchange forwards		-		2		-		2
	13		8		-		21
HFT derivatives
Power swaps and physical contracts		10		56		5		71
Natural gas swaps, futures, forwards and physical contracts		91		191		691		973
	101		247		696		1,044
Other derivatives
Foreign exchange forwards		-		5		-		5
Total liabilities		114		260		696		1,070
Net assets (liabilities)	$	81	$	32	$	(536)	$	(423)

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As at	December 31, 2021
millions of 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 June 30, 2022 was as follows:

	Regulatory Deferral				HFT Derivatives
millions of dollars	Physical natural gas purchases				Power		Natural gas		Total
Balance, beginning of period		$            80		��	$	2	$	29	$	111
Realized losses included in fuel for generation and purchased power		(5	)			-		-		(5	)
Unrealized gains included in regulatory assets or liabilities		18				-		-		18
Total realized and unrealized gains included in non-regulated operating revenues		-				6		30		36
Balance, June 30, 2022		$            93			$	8	$	59	$	160

The change in the fair value of the Level 3 financial liabilities for the three months ended June 30, 2022 was as follows:

	HFT Derivatives
millions of dollars	Power		Natural gas		Total
Balance, beginning of period	$	3		$            438	$	441
Total realized and unrealized gains included in non-regulated operating revenues		2		253		255
Balance, June 30, 2022	$	5		$            691	$	696

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The change in the fair value of the Level 3 financial assets for the six months ended June 30, 2022 was as follows:

	Regulatory Deferral		HFT Derivatives
millions of dollars	Physical natural gas purchases		Power		Natural gas		Total
Balance, beginning of period		$            88		$            4		$            12		$            104
Realized losses included in fuel for generation and purchased power		(34)		-		-		(34)
Unrealized gains included in regulatory assets or liabilities		39		-		-		39
Total realized and unrealized gains included in non-regulated operating revenues		-		4		47		51
Balance, June 30, 2022		$            93		$            8		$            59		$            160

The change in the fair value of the Level 3 financial liabilities for the six months ended June 30, 2022 was as follows:

	HFT Derivatives
millions of dollars	Power		Natural gas		Total
Balance, beginning of period		$          3		$        515		$        518
Total realized and unrealized gains included in non-regulated operating revenues		2		176		178
Balance, June 30, 2022		$          5		$        691		$        696

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.

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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	June 30, 2022
millions of dollars	Fair Value		Valuation Technique		Unobservable Input		Range		Weighted average (1)
Assets
Regulatory deferral – Physical	$	93		Modelled pricing		Third-party pricing		$5.50 - $43.05		$14.38
natural gas purchases and sales						Probability of default		1.14% - 2.31%		1.90%
						Discount rate		0.40% - 3.59%		1.96%
HFT derivatives – Power swaps		8		Modelled pricing		Third-party pricing		$46.70 - $269.10		$178.79
and physical contracts						Probability of default		0.06% - 0.86%		0.35%
						Discount rate		0.02% - 5.17%		1.60%
HFT derivatives –		59		Modelled pricing		Third-party pricing		$2.45 - $33.44		$6.05
Natural gas swaps, futures,						Probability of default		0.02% - 4.56%		0.18%
forwards and physical contracts						Discount rate		0.00% - 22.75%		1.57%
Total assets	$	160
Liabilities
HFT derivatives – Power swaps	$	3		Modelled pricing		Third-party pricing		$38.20 - $269.10		$157.44
and physical contracts						Own credit risk		0.06% - 0.86%		0.20%
						Discount rate		0.15% - 5.17%		2.30%
		2		Modelled pricing		Third-party pricing		$43.24 - $225.90		$153.18
						Correlation factor		99% - 106%		99%
						Own credit risk		0.06% - 4.48%		0.06%
						Discount rate		0.15% - 5.17%		1.08%
HFT derivatives –		661		Modelled pricing		Third-party pricing		$2.40 - $33.45		$14.41
Natural gas swaps, futures,						Own credit risk		0.06% - 7.44%		0.14%
forwards and physical contracts						Discount rate		0.00% - 25.84%		3.43%
		30		Modelled pricing		Third-party pricing		$4.05 - $33.88		$22.30
						Basis adjustment		$0.00 - $0.87		$0.35
						Own credit risk		0.06% - 3.36%		0.41%
						Discount rate		0.06% - 4.91%		1.85%
Total liabilities	$	696
Net liabilities	$	536

(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 dollars	Carrying Amount		Fair Value		Level 1		Level 2		Level 3		Total
June 30, 2022	$	15,482	$	14,736	$	-	$	14,309	$	427	$	14,736
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 loss of $40 million was recorded in Other Comprehensive Income for the three months ended June 30, 2022 (2021 – $18 million after-tax gain) and an after-tax foreign currency loss of $21 million for the six months ended June 30, 2022 (2021 – $34 million after tax gain).

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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 $43 million for the three months ended June 30, 2022 (2021 - $36 million) and $77 million for the six months ended June 30, 2022 (2021 - $64 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 $2 million for the three months ended June 30, 2022 (2021 - $3 million) and $6 million for the six months ended June 30, 2022 (2021 - $10 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at June 30, 2022 and at December 31, 2021.

15.  RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:

As at millions of dollars	June 30 2022		December 31 2021
Customer accounts receivable – billed	$	946	$	767
Customer accounts receivable – unbilled		285		318
Allowance for credit losses		(18)		(21)
Capitalized transportation capacity (1)		349		316
Income tax receivable		11		8
Prepaid expenses		102		65
Other		368		280
	$	2,043	$	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.

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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 millions of dollars	June 30 2022		December 31 2021
Total minimum lease payment to be received	$	1,429	$	947
Less: amounts representing estimated executory costs		(218)		(165)
Minimum lease payments receivable	$	1,211	$	782
Estimated residual value of leased property (unguaranteed)		182		183
Less: unearned finance lease income		(753)		(443)
Net investment in direct finance and sales-type leases	$	640	$	522
Principal due within one year (included in “Receivables and other current assets”)		34		19
Net Investment in direct finance and sales type leases - long-term	$	606	$	503

As at June 30, 2022, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows:

millions of dollars	2022		2023		2024		2025		2026		Thereafter		Total
Minimum lease payments to be received	$	46	$	93	$	94	$	96	$	94	$	1,006	$	1,429
Less: executory costs														(218)
Total													$	1,211

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.

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Emera’s net periodic benefit cost included the following:

For the	Three months ended June 30				Six months ended June 30
millions of dollars	2022		2021		2022		2021
Defined benefit pension plans
Service cost	$	11	$	11	$	21	$	22
Non-service cost
Interest cost		20		17		40		34
Expected return on plan assets		(37)		(33)		(72)		(66)
Current year amortization of:
Actuarial losses		2		5		4		9
Regulatory asset		6		6		10		13
Total non-service costs		(9)		(5)		(18)		(10)
Total defined benefit pension plans		2		6		3		12
Non-pension benefit plans
Service cost		1		2		2		3
Non-service cost
Interest cost		2		2		4		4
Expected return on plan assets		-		(1)		-		(1)
Current year amortization of regulatory asset		-		1		1		2
Total non-service costs		2		2		5		5
Total non-pension benefit plans		3		4		7		8
Total defined benefit plans	$	5	$	10	$	10	$	20

Emera’s pension and non-pension contributions related to these defined-benefit plans for the three months ended June 30, 2022 were $17 million (2021 – $15 million), and for the six months ended June 30, 2022 were $31 million (2021 – $29 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 contribution plans for the three months ended June 30, 2022 were $10 million (2021 – $9 million) and $19 million (2021 – $19 million) for the six months ended June 30, 2022.

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, and below for 2022 short-term debt financing activity.

Recent Significant Financing Activity by Segment:

Other

On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on August 2, 2023. The credit agreement contains customary representation and warranties, events of default and financial and other covenants and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin.

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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:

Florida Electric Utilities

On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included $300 million USD senior notes that bear an interest rate of 3.875 per cent with a maturity date of July 12, 2024, and $300 million USD senior notes that bear an interest rate of 5 per cent with a maturity date of July 15, 2052. Proceeds from the issuance were used to repay TEC’s $470 million USD commercial paper, due in 2022, and for general corporate purposes. This commercial paper was classified as long-term debt at June 30, 2022.

Canadian Electric Utilities

On July 15, 2022, NSPI entered into a $400 million non-revolving term facility which matures on July 15, 2024. The credit agreement contains customary representation and warranties, events of default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin.

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.

Gas Utilities and Infrastructure

On June 30, 2022, Brunswick Pipeline amended its credit agreement to extend the maturity from June 30, 2025 to June 30, 2026. There were no other changes in commercial terms.

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20.  COMMITMENTS AND CONTINGENCIES

A.  Commitments

As at June 30, 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 dollars	2022		2023		2024		2025		2026		Thereafter		Total
Transportation (1)	$	310	$	512	$	426	$	357	$	326	$	2,680	$	4,611
Purchased power (2)		180		232		245		239		230		2,366		3,492
Fuel, gas supply and storage		651		396		204		139		34		-		1,424
Capital projects		388		220		83		1		-		-		692
Long-term service agreements (3)		47		60		58		42		36		94		337
Equity investment commitments (4)		240		-		-		-		-		-		240
Leases and other (5)		6		15		14		12		5		117		169
Demand side management		24		1		1		1		-		-		27
	$	1,846	$	1,436	$	1,031	$	791	$	631	$	5,257	$	10,992

(1)    Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $140 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(2)    Annual requirement to purchase electricity production from Independent Power Producers 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.

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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 was filed on June 8, 2022. To date, the total of the Second Award, with interest, is approximately $63 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 June 30, 2022, TEC has estimated its financial liability to be $18 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

For information on principal financial risks which could materially affect the Company in the normal course of business, refer to note 27 in Emera’s 2021 annual audited consolidated financial statements. There have been no material changes to the principal financial risks as of June 30, 2022. Risks associated with derivative instruments and fair value measurements are discussed in note 12 and note 13.

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D.  Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2021 annual audited consolidated financial statements, with material updates as noted below:

The Company has standby letters of credit and surety bonds in the amount of $111 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	Six months ended June 30
millions of dollars	2022		2021
Changes in non-cash working capital:
Inventory	$	(59)	$	(28)
Receivables and other current assets		(290)		(6)
Accounts payable		289		(38)
Other current liabilities		(13)		19
Total non-cash working capital	$	(73)	$	(53)
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	115	$	106
Reclassification of long-term debt to short-term debt		500		-
Reclassification of short-term debt from current to long-term		602		-
Increase in accrued capital expenditures		18		32

22.  VARIABLE INTEREST ENTITIES

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

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

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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 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 “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	June 30, 2022				December 31, 2021
millions of dollars	Total assets		Maximum exposure to loss		Total assets		Maximum exposure to loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)	$	518	$	6	$	533	$	11

23.  COMPARATIVE INFORMATION

These unaudited condensed consolidated interim 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 unaudited condensed consolidated interim financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through August 9, 2022, the date the unaudited condensed consolidated interim financial statements were issued.

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