EX-99.2

EX-99.2 3 d509155dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

June 30, 2023 and 2022

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)	2023		2022		2023		2022


Operating revenues

Regulated electric	$	1,373	$	1,349	$	2,735	$	2,622

Regulated gas		277		339		843		841

Non-regulated		(232)		(308)		273		(68)

Total operating revenues (note 5)		1,418		1,380		3,851		3,395


Operating expenses
Regulated fuel for generation and purchased power		396		541		871		1,018

Regulated cost of natural gas		58		149		334		405

Operating, maintenance and general expenses (“OM&G”)		471		378		901		765

Provincial, state and municipal taxes		107		91		209		177

Depreciation and amortization		263		230		519		460

Total operating expenses		1,295		1,389		2,834		2,825

Income (loss) from operations		123		(9)		1,017		570


Income from equity investments (note 7)		36		33		71		60

Other income, net		57		21		92		44

Interest expense, net (note 8)		223		163		449		319

Income (loss) before provision for income taxes		(7)		(118)		731		355


Income tax (recovery) expense (note 9)		(51)		(66)		111		29

Net income (loss)		44		(52)		620		326


Preferred stock dividends		16		15		32		31

Net income (loss) attributable to common shareholders	$	28	$	(67)	$	588	$	295


Weighted average shares of common stock outstanding

(in millions) (note 11)
Basic		272.3		264.4		271.5		263.1

Diluted		272.6		264.4		271.8		263.6


Earnings (loss) per common share (note 11)
Basic	$	0.10	$	(0.25)	$	2.17	$	1.12

Diluted	$	0.10	$	(0.25)	$	2.16	$	1.12


Dividends per common share declared	$	0.6900	$	0.6625	$	1.3800	$	1.3250

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

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2023		2022		2023		2022

Net income (loss)	$	44	$	(52)	$	620	$	326

Other comprehensive income (loss), net of tax

Foreign currency translation adjustment (1)		(250)		285		(247)		147

Unrealized gains (losses) on net investment hedges (2) (3)		35		(40)		36		(21)

Cash flow hedges
Net derivative gains		1		-		1		-

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

Net effects of cash flow hedges		1		-		-		(1)

Net change in unrecognized pension and post-retirement benefit obligation		(1)		2		(5)		(8)

Other comprehensive (loss) income (4)	$	(215)	$	247	$	(216)	$	117

Comprehensive income (loss) of Emera Incorporated	$	(171)	$	195	$	404	$	443

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

(1) Net of tax recovery of $3 million (2022 – nil) for the three months ended June 30, 2023 and tax recovery of $7 million (2022 – nil) for the six months ended June 30, 2023.

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

(3) Net of tax expense of nil (2022 – $7 million recovery) for the three months ended June 30, 2023 and tax expense of nil (2022 – $4 million recovery) for the six months ended June 30, 2023.

(4) Net of tax recovery of $3 million (2022 – $7 million recovery) for the three months ended June 30, 2023 and tax recovery of $7 million (2022 – $4 million recovery) for the six months ended June 30, 2023.

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)



As at	June 30		December 31

millions of dollars	2023		2022

Assets

Current assets

Cash and cash equivalents	$	313	$	310

Restricted cash (note 23)		22		22

Inventory		826		769

Derivative instruments (notes 13 and 14)		199		296

Regulatory assets (note 6)		514		602

Receivables and other current assets (note 16)		1,763		2,897

		3,637		4,896
Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $9,681 and $9,574, respectively		23,407		22,996

Other assets
Deferred income taxes (note 9)		187		237

Derivative instruments (notes 13 and 14)		66		100

Regulatory assets (note 6)		2,801		3,018

Net investment in direct finance and sales type leases		592		604

Investments subject to significant influence (note 7)		1,417		1,418

Goodwill		5,877		6,012

Other long-term assets		488		461

		11,428		11,850

Total assets	$	38,472	$	39,742

Liabilities and Equity
Current liabilities
Short-term debt (note 18)	$	2,852	$	2,726

Current portion of long-term debt (note 19)		96		574

Accounts payable		1,283		2,025

Derivative instruments (notes 13 and 14)		399		888

Regulatory liabilities (note 6)		245		495

Other current liabilities		392		579

		5,267		7,287



Long-term liabilities
Long-term debt (note 19)		16,441		15,744

Deferred income taxes (note 9)		2,278		2,196

Derivative instruments (notes 13 and 14)		105		190

Regulatory liabilities (note 6)		1,662		1,778

Pension and post-retirement liabilities (note 17)		253		281

Other long-term liabilities (note 7)		867		825

		21,606		21,014

Equity
Common stock (note 10)		7,922		7,762

Cumulative preferred stock		1,422		1,422

Contributed surplus		81		81

Accumulated other comprehensive income (“AOCI’) (note 12)		362		578

Retained earnings		1,798		1,584

Total Emera Incorporated equity		11,585		11,427

Non-controlling interest in subsidiaries		14		14

Total equity		11,599		11,441

Total liabilities and equity	$	38,472	$	39,742


Commitments and contingencies (note 20)	Approved on behalf of the Board of Directors

The accompanying notes are an integral part of	“M. Jacqueline Sheppard”	“Scott Balfour”
these consolidated financial statements.	Chair of the Board	President and Chief Executive Officer

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)


For the	Six months ended June 30
millions of dollars	2023		2022

Operating activities

Net income	$	620	$	326

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization		522		457

Income from equity investments, net of dividends		(20)		(26)

Allowance for funds used during construction (“AFUDC”) – equity		(17)		(24)

Deferred income taxes, net		93		13

Net change in pension and post-retirement liabilities		(35)		(21)

Fuel adjustment mechanism (“FAM”)		10		(126)

Net change in fair value of derivative instruments		(601)		217

Net change in regulatory assets and liabilities		160		(126)

Net change in capitalized transportation capacity		378		(92)

Other operating activities, net		53		148

Changes in non-cash working capital (note 22)		(212)		(73)

Net cash provided by operating activities		951		673

Investing activities
Additions to PP&E		(1,351)		(1,041)

Other investing activities		8		11

Net cash used in investing activities		(1,343)		(1,030)

Financing activities
Change in short-term debt, net		172		285

Proceeds from long-term debt, net of issuance costs		537		2

Retirement of long-term debt		(105)		(21)

Net proceeds under committed credit facilities		55		90

Issuance of common stock, net of issuance costs		19		149



Dividends on common stock		(235)		(233)

Dividends on preferred stock		(32)		(31)

Other financing activities		(11)		(3)

Net cash provided by financing activities		400		238

Effect of exchange rate changes on cash, cash equivalents and restricted cash		(5)		(2)

Net increase (decrease) in cash, cash equivalents, and restricted cash		3		(121)

Cash, cash equivalents and restricted cash, beginning of period		332		417

Cash, cash equivalents and restricted cash, end of period	$	335	$	296

Cash, cash equivalents, and restricted cash consists of:
Cash	$	303	$	201

Short-term investments		10		74

Restricted cash		22		21

Cash, cash equivalents and restricted cash	$	335	$	296

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

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


millions of dollars	Common Stock		Preferred Stock		Contributed Surplus		AOCI		Retained Earnings		Non- Controlling Interest		Total Equity

For the three months ended June 30, 2023

Balance, March 31, 2023	$	7,839	$	1,422	$	81	$	577	$	1,958	$	14	$	11,891

Net income of Emera Incorporated		-		-		-		-		44		-		44

Other comprehensive loss, net of tax recovery of $3 million		-		-		-		(215)		-		-		(215)

Dividends declared on preferred stock (1)		-		-		-		-		(16)		-		(16)

Dividends declared on common stock ($0.6900/share)		-		-		-		-		(188)		-		(188)

Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts		70		-		-		-		-		-		70

Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”)		13		-		-		-		-		-		13

Balance, June 30, 2023	$	7,922	$	1,422	$	81	$	362	$	1,798	$	14	$	11,599



For the six months ended June 30, 2023

Balance, December 31, 2022	$	7,762	$	1,422	$	81	$	578	$	1,584	$	14	$	11,441

Net income of Emera Incorporated		-		-		-		-		620		-		620

Other comprehensive loss, net of tax recovery of $7 million		-		-		-		(216)		-		-		(216)

Dividends declared on preferred stock (2)		-		-		-		-		(32)		-		(32)

Dividends declared on common stock ($1.3800/share)		-		-		-		-		(374)		-		(374)

Issued under the DRIP, net of discounts		139		-		-		-		-		-		139

Senior management stock options exercised and ECSPP		21		-		-		-		-		-		21

Balance, June 30, 2023	$	7,922	$	1,422	$	81	$	362	$	1,798	$	14	$	11,599

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

(1) Series A; $0.1364/share, Series B; $0.3777/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; $0.7347/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

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


											Non-

	Common		Preferred		Contributed				Retained		Controlling		Total

millions of dollars	Stock		Stock		Surplus		AOCI		Earnings		Interest		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)

Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs		72		-		-		-		-		-		72

Issued under the DRIP, net of discounts		56		-		-		-		-		-		56

Senior management stock options exercised and ECSPP		16		-		1		-		-		-		17

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)

Issuance of common stock under ATM program, net of after-tax issuance costs		128		-		-		-		-		-		128

Issued under the DRIP, net of discount		116		-		-		-		-		-		116

Senior management stock options exercised and ECSPP		23		-		1		-		-		-		24

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

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at June 30, 2023 and 2022

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, 2023, Emera’s reportable segments include the following:

Florida Electric Utility, which consists of Tampa Electric (“TEC”), 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 transmission project, including AFUDC; and

a 31 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 Systems, Inc. (“PGS”), a regulated gas distribution utility operating across Florida. Effective January 1, 2023, Peoples Gas System ceased to be a division of Tampa Electric Company and the gas utility was reorganized, resulting in a separate legal entity called Peoples Gas Systems, Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.;

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 from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy North America Canada Partnership, which expires in 2034;

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

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

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

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

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

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

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

Emera Energy, which consists of:

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

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

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

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

Block Energy LLC (previously 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.

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, 2022.

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, 2023.

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

Use of Management Estimates

The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring 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 2022 annual audited consolidated financial statements.

Seasonal Nature of Operations

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

2. FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). 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.

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.


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, 2023
Operating revenues from external customers (1)	$	907	$	340	$	282	$	126	$	(237)	$	-	$	1,418

Inter-segment revenues (1)		2		-		4		-		(37)		31		-

Total operating revenues		909		340		286		126		(274)		31		1,418

Regulated fuel for generation and purchased power		220		115		-		64		-		(3)		396

Regulated cost of natural gas		-		-		58		-		-		-		58

OM&G		217		90		99		32		43		(10)		471

Provincial, state and municipal taxes		72		11		22		1		1		-		107

Depreciation and amortization		141		71		32		17		2		-		263

Income from equity investments		-		28		6		-		2		-		36

Other income (expense), net		19		7		3		3		69		(44)		57

Interest expense, net (2)		70		41		32		6		74		-		223

Income tax expense (recovery)		31		(2)		14		-		(94)		-		(51)

Preferred stock dividends		-		-		-		-		16		-		16

Net income (loss) attributable to common shareholders	$	177	$	49	$	38	$	9	$	(245)	$	-	$	28

For the six months ended June 30, 2023
Operating revenues from external customers (1)	$	1,651	$	844	$	854	$	240	$	262	$	-	$	3,851

Inter-segment revenues (1)		4		-		7		-		-		(11)		-

Total operating revenues		1,655		844		861		240		262		(11)		3,851

Regulated fuel for generation and purchased power		417		339		-		121		-		(6)		871

Regulated cost of natural gas		-		-		334		-		-		-		334

OM&G		384		191		201		62		77		(14)		901

Provincial, state and municipal taxes		135		22		48		2		2		-		209

Depreciation and amortization		282		138		62		33		4		-		519

Income from equity investments		-		52		11		1		7		-		71

Other income (expense), net		36		14		6		4		41		(9)		92

Interest expense, net (2)		137		85		57		12		158		-		449

Income tax expense (recovery)		52		(6)		44		-		21		-		111

Preferred stock dividends		-		-		-		-		32		-		32



Net income attributable to common shareholders	$	284	$	141	$	132	$	15	$	16	$	-	$	588

As at June 30, 2023
Total assets	$	20,878	$	8,345	$	7,418	$	1,295	$	1,781	$	(1,245)	$	38,472

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, 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 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 of $26 million for the three months ended June 30, 2023, and $43 million for the six months ended June 30, 2023 between the Florida Electric Utility, Gas Utilities and Infrastructure and Other segments.


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
OM&G		147		84		86		31		37		(7)		378
Provincial, state and municipal taxes		60		10		20		1		-		-		91
Depreciation and amortization		124		64		26		14		2		-		230
Income from equity investments		-		24		4		1		4		-		33
Other income (expense), net		15		6		5		3		(8)		-		21
Interest expense, net		40		32		19		5		67		-		163
Income tax expense (recovery)		41		-		13		-		(120)		-		(66)
Preferred stock dividends		-		-		-		-		15		-		15
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
OM&G		289		175		176		62		74		(11)		765
Provincial, state and municipal taxes		110		21		43		2		1		-		177
Depreciation and amortization		244		127		53		32		4		-		460
Income from equity investments		-		44		9		2		5		-		60
Other income (expense), net		28		11		7		(1)		(10)		9		44
Interest expense, net		78		65		36		9		131		-		319
Income tax expense (recovery)		66		3		38		-		(78)		-		29
Preferred stock dividends		-		-		-		-		31		-		31
Net income (loss) attributable to common shareholders	$	273	$	130	$	116	$	4	$	(228)	$	-	$	295
As at December 31, 2022
Total assets	$	21,053	$	8,223	$	7,737	$	1,337	$	2,835	$	(1,443)	$	39,742

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $3 million for the three months ended June 30, 2022, and $6 million for the six months ended June 30, 2022 between the Gas Utilities and Infrastructure and Other segments.

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, 2023
Regulated Revenue
Residential	$	577	$	199	$	42	$	115	$	-	$	-	$	933

Commercial		270		107		68		80		-		-		525

Industrial		66		14		8		20		-		(3)		105

Other electric and regulatory deferrals		(9)		10		6		-		-		-		7

Other (1)		5		10		2		50		-		(2)		65

Finance income (2)(3)		-		-		-		15		-		-		15

Regulated revenue		909		340		126		280		-		(5)		1,650

Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		(34)		-		(34)

Other non-regulated operating revenue		-		-		-		6		9		(9)		6

Mark-to-market (3)		-		-		-		-		(249)		45		(204)

Non-regulated revenue		-		-		-		6		(274)		36		(232)

Total operating revenues	$	909	$	340	$	126	$	286	$	(274)	$	31	$	1,418


For the six months ended June 30, 2023

Regulated Revenue
Residential	$	1,016	$	492	$	82	$	429	$	-	$	-	$	2,019

Commercial		500		234		130		235		-		-		1,099

Industrial		129		78		16		45		-		(7)		261

Other electric and regulatory deferrals		-		21		9		-		-		-		30

Other (1)		10		19		3		110		-		(4)		138

Finance income (2)(3)		-		-		-		31		-		-		31

Regulated revenue		1,655		844		240		850		-		(11)		3,578

Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		61		-		61

Other non-regulated operating revenue		-		-		-		11		15		(12)		14

Mark-to-market (3)		-		-		-		-		186		12		198

Non-regulated revenue		-		-		-		11		262		-		273

Total operating revenues	$	1,655	$	844	$	240	$	861	$	262	$	(11)	$	3,851

(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.


	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 electric and 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)

Other non-regulated operating revenue		-		-		-		4		3		(1)		6

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

Other non-regulated operating revenue		-		-		-		8		10		(6)		12

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.

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, 2023, the aggregate amount of the transaction price allocated to remaining performance obligations was $466 million (2022 – $432 million). This amount includes $136 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 2043.

6. REGULATORY ASSETS AND LIABILITIES

A summary of 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 2022 annual audited consolidated financial statements.


As at millions of dollars	June 30 2023		December 31 2022

Regulatory assets
Deferred income tax regulatory assets	$	1,210	$	1,166

TEC capital cost recovery for early retired assets		653		674

Cost recovery clauses		469		707

Pension and post-retirement medical plan		355		369

FAM		299		307

Storm reserve		59		103

Deferrals related to derivative instruments		55		30

NMGC winter event gas cost recovery		32		69

Storm restoration		29		35

Environmental remediations		27		27

Stranded cost recovery		27		27

Other		100		106

	$	3,315	$	3,620

Current	$	514	$	602

Long-term		2,801		3,018

Total regulatory assets	$	3,315	$	3,620


Regulatory liabilities
Accumulated reserve - cost of removal	$	881	$	895

Deferred income tax regulatory liabilities		846		877

Deferrals related to derivative instruments		80		230

Cost recovery clauses		61		70

Self-insurance fund (“SIF”) (note 23)		29		30

NMGC gas hedge settlements		-		162

Other		10		9

	$	1,907	$	2,273

Current	$	245	$	495

Long-term		1,662		1,778

Total regulatory liabilities	$	1,907	$	2,273

Florida Electric Utility

Fuel Recovery:

On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The changes were approved by the Florida Public Service Commission (“FPSC”) on March 7, 2023, and were effective beginning on April 1, 2023.

Storm Reserve:

On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the previous approved storm reserve level of $56 million USD, for a total of approximately $131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge on April 2023 bills. The storm recovery is subject to review of the underlying costs for prudency by the FPSC. The review is expected to be completed by the end of 2023.

Canadian Electric Utilities

NSPI

Extra Large Industrial Active Demand Tariff:

On July 5, 2023, NSPI received approval from the Nova Scotia Utility and Review Board (“UARB”) to change the methodology in which fuel cost recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, effective January 1, 2022, results in a shifting of fuel costs from this industrial customer to the FAM. This adjustment has been recorded in Q2 2023 resulting in a $51 million increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables and other current assets. This adjustment had minimal impact on earnings.

General Rate Application:

On March 27, 2023, the UARB issued its final order approving the new electricity rates related to the General Rate Application settlement agreement between NSPI, key customer representatives and participating interest groups. The new electricity rates were effective on February 2, 2023.

Nova Scotia Cap-and-Trade Program:

As of December 31, 2022, the FAM included a cumulative $166 million in fuel costs related to the accrued purchase of emissions credits and $6 million related to credits purchased from provincial auctions. On March 16, 2023, the Province of Nova Scotia amended the Nova Scotia Cap-and-Trade Program Regulations, providing NSPI with additional emissions allowances sufficient to achieve compliance for the 2019 through 2022 period. Accrued compliance costs of $166 million related to the anticipated purchase of emissions credits were reversed in Q1 2023. Credits NSPI purchased from provincial auctions in the amount of $6 million will not be refunded and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-Trade Program.

NSPML

In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023, subject to a holdback of up to $2 million a month. As of June 30, 2023, $18 million ($14 million related to 2022 and $4 million related to Q1 2023) in aggregate has been held back by NSPI, which represents the total holdback for the nine months in which NSPML did not achieve the 90 per cent required delivery of the NS Block. NSPML did not incur any additional holdback in each month of Q2 2023 as a result of achieving the full 90 per cent NS Block deliveries. Determination of allocation of the $18 million between NSPML or to NSPI’s FAM for the benefit of customers is subject to a regulatory process before the UARB, which commenced in March 2023. A decision from the UARB on the holdback is expected later in 2023.

Gas Utilities and Infrastructure

PGS

On April 4, 2023, PGS filed a rate case with the FPSC for new rates to become effective January 2024. PGS requested a $139 million USD increase in annual base rates, including $11 million USD from the cast iron and bare steel replacement rider. This reflects an 11 per cent midpoint ROE. The hearing for the matter is expected to be held in Q3 2023 with a final decision expected by the FPSC in Q4 2023.

Other Electric Utilities

BLPC

Clean Energy Transition Program (“CETP”):

On May 31, 2023, the Fair Trading Commission, Barbados (“FTC”) approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. BLPC has given notice to the FTC of its intention to submit applications in 2023 for costs to be recovered through the CETP.

General Rate Review Application:

On October 4, 2021, BLPC submitted a general rate review application to the FTC. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities related to the SIF of $50 million USD and prior year benefits recognized on remeasurement of deferred income taxes of $5 million USD, and a regulatory asset related to accumulated depreciation of $11 million USD. The FTC also requested a compliance filing before setting final rates which was submitted by BLPC on March 8, 2023. On March 7, 2023, BLPC filed a Motion for Review and Variation of FTC’s decision and applied for a Stay of the Decision. The FTC has determined that it will hear the Motion for Review by way of an oral hearing and parties were invited to submit and exchange written submissions on these matters during Q2 2023. On May 12, 2023, the FTC granted the Stay of the Decision until the determination of the Motion for Review and Variation which is scheduled to be heard in Q3 2023. BLPC expects a decision on final rates from the FTC in 2023.

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		2023		2022		2023		2022		2023		2022		2023

LIL (1)	$	754	$	740	$	15	$	14	$	31	$	28		31.0

NSPML		493		501		13		10		21		16		100.0

M&NP (2)		123		128		6		4		11		9		12.9

Lucelec (2)		47		49		-		1		1		2		19.5

Bear Swamp (3)		-		-		2		4		7		5		50.0

	$	1,417	$	1,418	$	36	$	33	$	71	$	60

(1) Emera indirectly owns 100 per cent of the LIL Class B units, which comprises 24.5 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 $86 million (2022 – $95 million) is recorded in Other long-term liabilities on the Condensed Consolidated Balance Sheets.

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


As at	June 30		December 31

millions of dollars	2023		2022

Current assets	$	16	$	17

PP&E		1,499		1,517

Regulatory assets		264		265

Non-current assets		29		29

Total assets	$	1,808	$	1,828

Current liabilities	$	47	$	48

Long-term debt (1)		1,129		1,149

Non-current liabilities		139		130

Equity		493		501

Total liabilities and equity	$	1,808	$	1,828

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

8. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:


	Three months ended				Six months ended

For the	June 30				June 30

millions of dollars	2023		2022		2023		2022

Interest on debt	$	232	$	165	$	462	$	325

Allowance for borrowed funds used during construction		(4)		(4)		(7)		(9)

Other		(5)		2		(6)		3

	$	223	$	163	$	449	$	319

9. INCOME TAXES

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2023		2022		2023		2022

Income (loss) before provision for income taxes	$	(7)	$	(118)	$	731	$	355

Statutory income tax rate		29.0%		29.0%		29.0%		29.0%

Income taxes, at statutory income tax rate		(2)		(34)		212		103

Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(13)		(10)		(45)		(35)

Foreign tax rate variance		(11)		(9)		(19)		(16)

Tax credits		(10)		(1)		(17)		(4)

Amortization of deferred income tax regulatory liabilities		(11)		(8)		(16)		(13)

Tax effect of equity earnings		(4)		(3)		(7)		(5)

Other		-		(1)		3		(1)

Income tax (recovery) expense	$	(51)	$	(66)	$	111	$	29

Effective income tax rate		729%		56%		15%		8%

On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024 and introduces new technology-neutral clean energy related tax credits beginning in 2025. As of June 30, 2023, the Company has recorded a $20 million regulatory liability in recognition of its obligation to pass the incremental tax benefits realized to customers.

10. COMMON STOCK

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


Issued and outstanding:	millions of shares		millions of dollars

Balance, December 31, 2022		269.95	$	7,762

Issued under the DRIP, net of discounts		2.53		139

Senior management stock options exercised and ECSPP		0.43		21

Balance, June 30, 2023		272.91	$	7,922

As at June 30, 2023, an aggregate gross sales limit of $207 million remained available for issuance under the ATM program.

11. EARNINGS PER SHARE

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


For the	Three months ended June 30				Six months ended June 30
millions of dollars (except per share amounts)	2023		2022		2023		2022

Numerator
Net income (loss) attributable to common shareholders	$	27.5	$	(67.2)	$	587.9	$	294.5

Diluted numerator		27.5		(67.2)		587.9		294.5

Denominator
Weighted average shares of common stock outstanding – basic		272.3		264.4		271.5		263.1

Stock-based compensation (1)		0.3		-		0.3		0.5

Weighted average shares of common stock outstanding – diluted		272.6		264.4		271.8		263.6

Earnings (loss) per common share
Basic	$	0.10	$	(0.25)	$	2.17	$	1.12

Diluted	$	0.10	$	(0.25)	$	2.16	$	1.12

(1) 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, as the Company had net loss in this quarter.

12. 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		Gains (losses) 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, 2023

Balance, January 1, 2023	$	639	$	(62)	$	16	$	(2)	$	(13)	$	578

Other comprehensive (loss) income before reclassifications		(247)		36		1		-		-		(210)

Amounts reclassified from AOCI		-		-		(1)		-		(5)		(6)

Net current period other comprehensive (loss) income		(247)		36		-		-		(5)		(216)

Balance, June 30, 2023	$	392	$	(26)	$	16	$	(2)	$	(18)	$	362


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

The reclassifications out of AOCI are as follows:


For the		Three months ended June 30				Six months ended June 30

millions of dollars		2023		2022		2023	2022

	Affected line item in the Condensed		Amounts reclassified from AOCI

	Consolidated Interim Financial Statements

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

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

Amounts reclassified into obligations	Pension and post-retirement benefits		(1)		-	(5)		(12)

Total			(1)		2	(5)		(8)

Total reclassifications out of AOCI, for the period		$	(1)	$	2	$ (6)	$	(9)

13. DERIVATIVE INSTRUMENTS

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

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

foreign exchange (“FX”) fluctuations on foreign currency denominated purchases and sales;

interest rate fluctuations on debt securities; and

share price fluctuations on stock-based compensation.

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

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

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

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

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. TEC 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, 2024.

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

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


	Derivative Assets				Derivative Liabilities


As at millions of dollars	June 30 2023		December 31 2022		June 30 2023		December 31 2022

Cash flow hedges:
FX forwards	$	1	$	-	$	-	$	-

Regulatory deferral:
Commodity swaps and forwards		81		186		51		42

FX forwards		5		18		4		1

Physical natural gas purchases		7		52		-		-

		93		256		55		43

HFT derivatives:
Power swaps and physical contracts		46		89		42		77

Natural gas swaps, futures, forwards, physical		254		340		545		1,224

contracts

		300		429		587		1,301

Other derivatives:
Equity derivatives		3		-		-		5

FX forwards		17		5		11		23

		20		5		11		28

Total gross current derivatives		414		690		653		1,372

Impact of master netting agreements:
Regulatory deferral		(12)		(18)		(12)		(18)

HFT derivatives		(137)		(276)		(137)		(276)

Total impact of master netting agreements		(149)		(294)		(149)		(294)

Total derivatives	$	265	$	396	$	504	$	1,078

Current (1)		199		296		399		888

Long-term (1)		66		100		105		190

Total derivatives	$	265	$	396	$	504	$	1,078

(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts. Cash Flow Hedges On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. The Company has FX forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline. The amounts related to cash flow hedges recorded in AOCI consisted of the following:

As at	June 30, 2023				December 31, 2022

	Interest rate		FX		Interest rate		FX

millions of dollars	hedge		forwards		hedge		forwards

Total unrealized gain in AOCI, net of tax	$	15	$	1	$	16	$	-

For the three and six months ended June 30, 2023, unrealized gains of nil (2022 – nil) and $1 million (2022 – $1 million) respectively have been reclassified from AOCI into interest expense. The Company expects $3 million of unrealized gains currently in AOCI to be reclassified into net income within the next 12 months.

As at June 30, 2023, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:



millions	2023

FX forwards (USD) sales	$	27

Regulatory Deferral

The Company has recorded the following changes with respect to derivatives receiving regulatory deferral:


millions of dollars	Physical natural gas purchases		Commodity swaps and forwards		FX forwards		Physical natural gas purchases		Commodity swaps and forwards		FX forwards

For the three months ended June 30						2023						2022

Unrealized gain (loss) in regulatory assets	$	-	$	(9)	$	(3)	$	-	$	(30)	$	3

Unrealized gain (loss) in regulatory liabilities		1		8		(4)		18		108		6

Realized (gain) loss in regulatory assets		-		(4)		-		-		14		-

Realized (gain) loss in regulatory liabilities		-		3		-		-		(13)		-

Realized (gain) loss in inventory (1)		-		4		(4)		-		(32)		2

Realized (gain) loss in regulated fuel for generation and purchased power (2)		(3)		7		(2)		(5)		(22)		-

Total change in derivative instruments	$	(2)	$	9	$	(13)	$	13	$	25	$	11


millions of dollars	Physical natural gas purchases		Commodity swaps and forwards		FX forwards		Physical natural gas purchases		Commodity swaps and forwards		FX forwards

For the six months ended June 30						2023						2022

Unrealized gain (loss) in regulatory assets	$	-	$	(29)	$	(3)	$	-	$	(38)	$	1

Unrealized gain (loss) in regulatory liabilities		(3)		(59)		(2)		39		329		2

Realized loss in regulatory assets		-		-		-		-		16		-

Realized (gain) loss in regulatory liabilities		-		4		-		-		(22)		-

Realized (gain) loss in inventory (1)		-		5		(9)		-		(42)		4

Realized (gain) loss in regulated fuel for generation and purchased power (2)		(42)		(20)		(2)		(34)		(58)		1

Other		-		(15)		-		-		-		-

Total change in derivative instruments	$	(45)	$	(114)	$	(16)	$	5	$	185	$	8

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

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

As at June 30, 2023, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:


millions	2023		2024-2026

Physical natural gas purchases:

Natural gas (MMBtu)		2		-

Commodity swaps and forwards purchases:

Natural gas (MMBtu)		12		15

Power (MWh)		1		1

FX swaps and forwards:

FX contracts (millions of USD)	$	147	$	248

Weighted average rate		1.3247		1.3118

% of USD requirements		123%		35%

HFT Derivatives

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	2023		2022		2023		2022

Power swaps and physical contracts in non-regulated operating revenues	$	-	$	8	$	-	$	4

Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		(22)		(266)		817		(72)

Total gains (losses) in net income	$	(22)	$	(258)	$	817	$	(68)

As at June 30, 2023, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:


millions	2023		2024		2025		2026		2027 and thereafter

Natural gas purchases (MMBtu)		234		141		52		39		137

Natural gas sales (MMBtu)		337		276		123		11		23

Power purchases (MWh)		1		-		-		-		-

Power sales (MWh)		1		-		-		-		-

Other Derivatives

As at June 30, 2023, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.8 million shares and extends until December 2023. The FX forwards have a combined notional amount of $574 million USD and expire in 2023 through 2025.

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


	FX		Equity		FX		Equity

millions of dollars	forwards		derivatives		forwards		derivatives

For the three months ended June 30				2023				2022

Unrealized loss in OM&G	$	-	$	(3)	$	-	$	(5)

Unrealized gain in other income, net		17		-		-		-

Realized loss in other income, net		(2)		-		-		-

Total gains (losses) in net income	$	15	$	(3)	$	-	$	(5)


	FX		Equity		FX		Equity

millions of dollars	forwards		derivatives		forwards		derivatives

For the six months ended June 30				2023				2022

Unrealized gain (loss) in OM&G	$	-	$	8	$	-	$	(9)

Unrealized gain in other income, net		23		-		1		-

Realized loss in other income, net		(5)		-				-

Total gains (losses) in net income	$	18	$	8	$	1	$	(9)

Credit Risk

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

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

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX 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, 2023, the Company had $144 million (December 31, 2022 – $131 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 $126 million (December 31, 2022 – $114 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	June 30		December 31

millions of dollars	2023		2022

Cash collateral provided to others	$	104	$	224

Cash collateral received from others	$	11	$	112

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, 2023, the total fair value of derivatives in a liability position was $504 million (December 31, 2022 – $1,078 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.

14. FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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


As at	June 30, 2023

millions of dollars	Level 1		Level 2		Level 3		Total

Assets

Cash flow hedges:

FX forwards	$	-	$	1	$	-	$	1

Regulatory deferral:

Commodity swaps and forwards		37		32		-		69

FX forwards		-		5		-		5

Physical natural gas purchases		-		-		7		7

	37		37		7		81

HFT derivatives:

Power swaps and physical contracts		6		26		-		32

Natural gas swaps, futures, forwards, physical contracts and related transportation		22		84		25		131

	28		110		25		163

Other derivatives:

FX forwards		-		17		-		17

Equity derivatives		3		-		-		3

	3		17		-		20

Total assets		68		165		32		265

Liabilities

Regulatory deferral:

Commodity swaps and forwards		28		11		-		39

FX forwards		-		4		-		4

	28		15		-		43

HFT derivatives:

Power swaps and physical contracts		1		25		1		27

Natural gas swaps, futures, forwards and physical contracts		27		40		356		423


		28		65		357		450

Other derivatives:

FX forwards		-		11		-		11

Total liabilities		56		91		357		504

Net assets (liabilities)	$	12	$	74	$	(325)	$	(239)


As at	December 31, 2022
millions of dollars	Level 1		Level 2		Level 3		Total

Assets

Regulatory deferral:
Commodity swaps and forwards	$	120	$	48	$	-	$	168

FX forwards		-		18		-		18

Physical natural gas purchases and sales		-		-		52		52

		120		66		52		238

HFT derivatives:
Power swaps and physical contracts		9		31		4		44

Natural gas swaps, futures, forwards, physical contracts and related transportation		3		72		34		109

		12		103		38		153

Other derivatives:
FX forwards		-		5		-		5

Total assets		132		174		90		396

Liabilities

Regulatory deferral:
Commodity swaps and forwards		15		9		-		24

FX forwards		-		1		-		1

	15		10		-		25

HFT derivatives:
Power swaps and physical contracts		2		28		1		31

Natural gas swaps, futures, forwards and physical contracts		51		118		825		994

	53		146		826		1,025

Other derivatives:
FX forwards		-		23		-		23
Equity derivatives		5		-		-		5



		5		23		-		28

Total liabilities		73		179		826		1,078

Net assets (liabilities)	$	59	$	(5)	$	(736)	$	(682)

The change in the fair value of the Level 3 financial assets for the three months ended June 30, 2023 was as follows:


	Regulatory Deferral		HFT Derivatives
millions of dollars	Physical natural gas purchases		Power		Natural gas		Total

Balance, beginning of period		$ 9	$	(1)	$	39	$	47

Realized gains included in fuel for generation and purchased power		(3)		-		-		(3)

Unrealized gains included in regulatory liabilities		1		-		-		1

Total realized and unrealized gains (losses) included in non-regulated operating revenues		-		1		(14)		(13)

Balance, June 30, 2023		$ 7	$	-	$	25	$	32

The change in the fair value of the Level 3 financial liabilities for the three months ended June 30, 2023 was as follows:


	HFT Derivatives
millions of dollars	Power		Natural gas		Total

Balance, beginning of period	$	2	$	326	$	328

Total realized and unrealized (gains) losses included in non-regulated operating revenues		(1)		30		29

Balance, June 30, 2023	$	1	$	356	$	357

The change in the fair value of the Level 3 financial assets for the six months ended June 30, 2023 was as follows:


	Regulatory Deferral		HFT Derivatives
millions of dollars	Physical natural gas purchases		Power		Natural gas		Total

Balance, beginning of period		$ 52	$	4	$	34	$	90

Realized gains included in fuel for generation and purchased power		(42)		-		-		(42)

Unrealized gains included in regulatory liabilities		(3)		-		-		(3)

Total realized and unrealized losses included in non-regulated operating revenues		-		(4)		(9)		(13)

Balance, June 30, 2023		$ 7	$	-	$	25	$	32

The change in the fair value of the Level 3 financial liabilities for the six months ended June 30, 2023 was as follows:


	HFT Derivatives
millions of dollars	Power		Natural gas		Total

Balance, beginning of period	$	1	$	825	$	826

Total realized and unrealized gains included in non-regulated operating revenues		-		(469)		(469)

Balance, June 30, 2023	$	1	$	356	$	357

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. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. Other unobservable inputs used include 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.

The Company uses a modelled pricing valuation technique for determining the fair value of Level 3 derivative instruments. 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:


	June 30, 2023
As at											Weighted
millions of dollars	Fair Value				Significant Unobservable Input		Low		High		average(1)

	Assets		Liabilities

Regulatory deferral – Physical	$	7	$	-		Third-party pricing		$3.99		$6.96		$4.91
natural gas purchases

HFT derivatives – Power		-		1		Third-party pricing		$28.07		$148.65		$62.39
swaps and physical contracts

HFT derivatives – Natural		25		356		Third-party pricing		$1.07		$18.64		$7.06
gas swaps, futures, forwards and physical contracts

Total	$	32	$	357

Net liability			$	325

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

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


As at	Carrying

millions of dollars	Amount		Fair Value		Level 1		Level 2		Level 3		Total

June 30, 2023	$	16,537	$	15,144	$	166	$	14,727	$	251	$	15,144

December 31, 2022	$	16,318	$	14,670	$	-	$	14,284	$	386	$	14,670

The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency gain of $35 million was recorded in AOCI for the three months ended June 30, 2023 (2022 – $40 million after-tax loss) and an after-tax foreign currency gain of $36 million was recorded for the six months ended June 30, 2023 (2022 – $21 million after-tax loss).

15. 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 $41 million for the three months ended June 30, 2023 (2022 – $43 million) and $78 million for the six months ended June 30, 2023 (2022 – $77 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 $3 million for the three months ended June 30, 2023 (2022 – $2 million) and $8 million for the six months ended June 30, 2023 (2022 – $6 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, 2023 and at December 31, 2022.

16. RECEIVABLES AND OTHER CURRENT ASSETS


As at	June 30		December 31

millions of dollars	2023		2022

Customer accounts receivable – billed	$	734	$	1,096

Capitalized transportation capacity (1)		395		781

Customer accounts receivable – unbilled		316		424

Prepaid expenses		123		82

Income tax receivable		11		9

Allowance for credit losses		(18)		(17)

NMGC gas hedge settlement receivable (2)		-		162

Other		202		360

Total receivables and other current assets	$	1,763	$	2,897

(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.

(2) Related amount is included in regulatory liabilities for NMGC as gas hedges are part of the purchased gas adjustment clause. Refer to note 7 in Emera’s 2022 annual audited consolidated financial statements.

17. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.

Emera’s net periodic benefit cost included the following:


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2023		2022		2023		2022

Defined benefit pension plans
Service cost	$	7	$	11	$	15	$	21

Non-service cost:
Interest cost		28		20		56		40

Expected return on plan assets		(41)		(37)		(81)		(72)

Current year amortization of:
Actuarial losses		-		2		-		4

Regulatory asset		2		6		3		10

Total non-service costs		(11)		(9)		(22)		(18)

Total defined benefit pension plans		(4)		2		(7)		3

Non-pension benefit plans
Service cost		1		1		1		2

Non-service cost:
Interest cost		4		2		7		4

Expected return on plan assets		(1)		-		(1)		-

Current year amortization of regulatory asset		(1)		-		(2)		1

Total non-service costs		2		2		4		5

Total non-pension benefit plans		3		3		5		7

Total defined benefit plans	$	(1)	$	5	$	(2)	$	10

Emera’s pension and non-pension contributions related to these defined-benefit plans for the three months ended June 30, 2023 were $21 million (2022 – $17 million), and for the six months ended June 30, 2023 were $35 million (2022 – $31 million). Annual employer contributions to the defined benefit pension plans are estimated to be $44 million for 2023. Emera’s contributions related to these defined contribution plans for the three months ended June 30, 2023 were $11 million (2022 – $10 million) and $22 million (2022 – $19 million) for the six months ended June 30, 2023.

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 2022 annual audited consolidated financial statements, and below for 2023 short-term debt financing activity.

Florida Electric Utilities

On March 1, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit facility which matures on February 28, 2024. The credit facility contains customary representations and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term secured overnight financing rate (“SOFR”), the Bank of Nova Scotia’s prime rate, the federal funds rate or the one-month SOFR, plus a margin.

On April 3, 2023, TEC entered into an additional 364-day, $200 million USD senior unsecured revolving credit facility which matures on April 1, 2024. The credit agreement contains customary representation and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term SOFR, Wells Fargo’s prime rate, the federal funds rate or the one-month SOFR, plus a margin.

Other

On June 30, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the maturity date from August 2, 2023 to August 2, 2024. There were no other changes in commercial terms from the prior agreement.

19. LONG-TERM DEBT

For details regarding long-term debt, refer to note 25 in Emera’s 2022 annual audited consolidated financial statements, and below for 2023 long-term debt financing activity.

Canadian Electric Utilities

On March 24, 2023, NSPI issued $500 million in unsecured notes. The issuance included $300 million unsecured notes that bear interest at 4.95 per cent with a maturity date of November 15, 2032, and $200 million unsecured notes that bear interest at 5.36 per cent with a maturity date of March 24, 2053.

Other Electric Utilities

On May 24, 2023, GBPC issued a $28 million USD non-revolving term loan that bears interest at 4.00 per cent with a maturity date of May 24, 2028.

Other

On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent with a maturity date of May 2, 2030.

20. COMMITMENTS AND CONTINGENCIES

A.	Commitments

As at June 30, 2023, 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	2023		2024		2025		2026		2027		Thereafter		Total

Transportation (1)	$	366		566		440		397		380		2,780	$	4,929

Purchased power (2)		149		242		241		256		305		3,583		4,776

Fuel, gas supply and storage		462		327		122		47		5		1		964

Capital projects		623		184		5		6		1		-		819

Equity investment commitments (3)		-		240		-		-		-		-		240

Other		80		155		139		52		45		211		682

	$	1,680	$	1,714	$	947	$	758	$	736	$	6,575	$	12,410

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $136 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) Emera has a commitment to make equity contributions to the LIL. The commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be made in 2024.

NSPI has a contractual obligation to pay NSPML for 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. In December 2022, the UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

Construction of the LIL is complete, and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canada’s Independent Engineer issuance of its Commissioning Certificate on April 13, 2023.

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 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.

B.	Legal Proceedings

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). While the aggregate joint and several liability associated with these sites has not changed as a result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at June 30, 2023, the aggregate financial liability of the Florida utilities is estimated to be $17 million ($13 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 the Florida utilities. The estimates to perform the work are based on the Florida utilities’ 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, the Florida utilities could be liable for more than their 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 2022 annual audited consolidated financial statements. Risks associated with derivative instruments and fair value measurements are discussed in note 13 and note 14. There have been no material changes to the principal financial risks as of June 30, 2023.

D.	Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2022 audited annual consolidated financial statements, with material updates as noted below:

NSPI renewed guarantees of $15 million USD with terms of varying lengths. As at June 30, 2023, NSPI had $109 million USD (2022 – $119 million USD) of guarantees outstanding with terms of varying lengths, all of which are issued on behalf of its subsidiary, NS Power Energy Marking Incorporated.

21. CUMULATIVE PREFERRED STOCK

For details regarding cumulative preferred stock, refer to note 28 in Emera’s 2022 annual audited consolidated financial statements, and below for 2023 preferred stock activity.

On July 6, 2023, Emera announced that it would not redeem the 10,000,000 outstanding Cumulative Rate Reset Preferred Shares, Series C (“Series C Shares”) or the 12,000,000 outstanding Cumulative Minimum Rate Reset First Preferred Shares, Series H (“Series H Shares”) on August 15, 2023. Additionally, during the conversion period between July 17, 2023 and July 31, 2023, subject to certain conditions, the holders of the Series C Shares had the right, at their option, to convert all or any of their Series C Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series D of the Company (the “Series D Shares”) and the holders of the Series H Shares had the right, at their option, to convert all or any of their Series H Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series I of the Company (the “Series I Shares”), in each case on August 15, 2023.

On August 4, 2023, Emera announced that after having taken into account all conversion notices received from holders, no Series C Shares would be converted into Series D Shares and no Series H Shares would be converted into Series I Shares. The holders of the Series C Shares will be entitled to receive a dividend of 6.434 per cent per annum on the Series C Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of) August 14, 2028 ($0.40213 per Series C Share per quarter). The holders of the Series H Shares will be entitled to receive a dividend of 6.324 per cent per annum on the Series H Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of) August 14, 2028 ($0.39525 per Series H Share per quarter).

22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


For the	Six months ended June 30
millions of dollars	2023		2022

Changes in non-cash working capital:
Inventory	$	(67)	$	(59)

Receivables and other current assets (1)		728		(290)

Accounts payable		(678)		289

Other current liabilities (2)		(195)		(13)

Total non-cash working capital	$	(212)	$	(73)

1) The six months ended June 30, 2023, includes $162 million related to the January 2023 settlement of NMGC gas hedges. Offsetting change in regulatory liabilities is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities. 2) The six months ended June 30, 2023, includes $(166) million related to the decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges. Offsetting regulatory asset (FAM) balance is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	139	$	115

Increase in accrued capital expenditures	$	30	$	18

Reclassification of long-term debt to short-term debt	$	-	$	500

Reclassification of short-term debt from current to long-term	$	-	$	602


Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities	$	(71)	$	(190)

23. VARIABLE INTEREST ENTITIES

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

BLPC established a 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, 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 in “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, 2023

December 31, 2022

Maximum

Maximum

millions of dollars

Total
assets

exposure to

loss

Total
assets

exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

493

501

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 11, 2023, the date the unaudited condensed consolidated interim financial statements were issued.