EX-99.2

EX-99.2 3 d891510dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

September 30, 2024 and 2023

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)


	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars (except per share amounts)	2024		2023		2024		2023


Operating revenues
Regulated electric	$	1,534	$	1,598	$	4,431	$	4,333

Regulated gas		291		257		1,134		1,100

Non-regulated		(23)		(115)		(128)		158

Total operating revenues (note 5)		1,802		1,740		5,437		5,591


Operating expenses
Regulated fuel for generation and purchased power		484		530		1,487		1,401

Regulated cost of natural gas		46		58		282		392

Operating, maintenance and general expenses (“OM&G”)		432		497		1,415		1,398

Provincial, state and municipal taxes		110		117		325		326

Depreciation and amortization		293		266		866		785

Impairment charges (note 19)		221		-		221		-

Total operating expenses		1,586		1,468		4,596		4,302

Income from operations		216		272		841		1,289


Income from equity investments (note 7)		25		32		87		103

Other income, net (note 8)		14		15		232		107

Interest expense, net (note 9)		241		235		725		684

Income before provision for income taxes		14		84		435		815


Income tax (recovery) expense (note 10)		(9)		(34)		40		77

Net income		23		118		395		738


Non-controlling interest in subsidiaries (“NCI”)		1		1		1		1

Preferred stock dividends		18		16		54		48

Net income attributable to common shareholders	$	4	$	101	$	340	$	689


Weighted average shares of common stock outstanding (in millions) (note 12)
Basic		290.0		273.6		287.5		272.2

Diluted		290.1		273.8		287.6		272.5


Earnings per common share (note 12)
Basic	$	0.01	$	0.37	$	1.18	$	2.53

Diluted	$	0.01	$	0.37	$	1.18	$	2.53


Dividends per common share declared	$	0.7175	$	0.6900	$	2.1525	$	2.0700

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				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023

Net income	$	23	$	118	$	395	$	738

Other comprehensive income (loss) (“OCI”), net of tax
Foreign currency translation adjustment (1)		(165)		233		240		(14)

Unrealized gains (losses) on net investment hedges (2)		22		(33)		(33)		3

Cash flow hedges
Net derivative gains		-		-		-		1

Less: reclassification adjustment for gains included in income		(1)		(1)		(2)		(2)

Net effects of cash flow hedges		(1)		(1)		(2)		(1)

Unrealized gains on available-for-sale investment		-		-		1		-

Net change in unrecognized pension and post-retirement benefit obligation		-		1		1		(4)

OCI (3)	$	(144)	$	200	$	207	$	(16)

Comprehensive (loss) income		(121)		318		602		722

Comprehensive income attributable to NCI		1		1		1		1

Comprehensive (loss) income of Emera Incorporated	$	(122)	$	317	$	601	$	721

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

(1) Net of tax recovery of $2 million (2023 – $3 million expense) for the three months ended September 30, 2024 and tax expense of $3 million (2023 – $4 million recovery) for the nine months ended September 30, 2024.

(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 recovery of $2 million (2023 – $3 million expense) for the three months ended September 30, 2024 and tax expense of $3 million (2023 – $4 million recovery) for the nine months ended September 30, 2024.

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)



As at	September 30		December 31
millions of dollars	2024		2023

Assets
Current assets
Cash and cash equivalents	$	240	$	567

Restricted cash		20		21

Inventory		746		790

Derivative instruments (notes 14 and 15)		129		174

Regulatory assets (note 6)		202		339

Receivables and other current assets (note 17)		1,528		1,817

Assets held for sale (note 3)		108		-

		2,973		3,708
Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $10,320 and $9,994, respectively		24,459		24,376

Other assets
Deferred income taxes (note 10)		224		208

Derivative instruments (notes 14 and 15)		44		66

Regulatory assets (note 6)		2,696		2,766

Net investment in direct finance and sales type leases		607		621

Investments subject to significant influence (note 7)		652		1,402

Goodwill (note 19)		5,498		5,871

Other long-term assets		482		462

Assets held for sale (note 3)		2,039		-

		12,242		11,396

Total assets	$	39,674	$	39,480

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued


Liabilities and Equity
Current liabilities
Short-term debt (note 20)	$	1,409	$	1,433

Current portion of long-term debt (note 21)		82		676

Accounts payable		1,319		1,454

Derivative instruments (notes 14 and 15)		364		386

Regulatory liabilities (note 6)		302		168

Other current liabilities		535		427

Liabilities associated with assets held for sale (note 3)		132		-

		4,143		4,544

Long-term liabilities
Long-term debt (note 21)		17,180		17,689

Deferred income taxes (note 10)		2,181		2,352

Derivative instruments (notes 14 and 15)		93		118

Regulatory liabilities (note 6)		1,372		1,604

Pension and post-retirement liabilities (note 18)		254		265

Other long-term liabilities (note 7)		879		820

Liabilities associated with assets held for sale (note 3)		1,130		-

		23,089		22,848

Equity
Common stock (note 11)		8,884		8,462

Cumulative preferred stock		1,422		1,422

Contributed surplus		84		82

Accumulated other comprehensive income (“AOCI’) (note 13)		512		305

Retained earnings		1,526		1,803

Total Emera Incorporated equity		12,428		12,074

NCI		14		14

Total equity		12,442		12,088

Total liabilities and equity	$	39,674	$	39,480

Commitments and contingencies (note 22)

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

Approved on behalf of the Board of Directors


“M. Jacqueline Sheppard”		“Scott Balfour”

Chair of the Board		President and Chief Executive Officer

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)


For the	Nine months ended September 30
millions of dollars	2024		2023

Operating activities
Net income	$	395	$	738

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		878		794

Income from equity investments, net of dividends		(10)		(17)

Allowance for funds used during construction (“AFUDC”) – equity		(36)		(27)

Deferred income taxes, net		14		57

Net change in pension and post-retirement liabilities		(40)		(56)

Fuel adjustment mechanism (“FAM”)		18		(35)

Net change in fair value (“FV”) of derivative instruments		50		(633)

Net change in regulatory assets and liabilities		231		387

Net change in capitalized transportation capacity		134		556

Goodwill impairment charge		210		-

Gain on sale of LIL, excluding transaction costs		(191)		-

Other operating activities, net		79		49

Changes in non-cash working capital (note 23)		220		5

Net cash provided by operating activities		1,952		1,818

Investing activities
Additions to PP&E		(2,223)		(2,063)

Proceeds from disposal of investment subject to significant influence		927		-

Other investing activities		7		18

Net cash used in investing activities		(1,289)		(2,045)

Financing activities

Change in short-term debt, net		(83)		47

Proceeds from long-term debt, net of issuance costs		1,359		537

Retirement of long-term debt		(1,082)		(113)

Net (repayments) proceeds under committed credit facilities		(941)		93

Issuance of common stock, net of issuance costs		200		23

Dividends on common stock		(399)		(358)

Dividends on preferred stock		(54)		(48)

Other financing activities		3		(15)

Net cash (used in) provided by financing activities		(997)		166

Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash associated with assets held for sale		10		2

Net decrease in cash, cash equivalents, restricted cash, and cash associated with assets held for sale		(324)		(59)

Cash, cash equivalents and restricted cash, beginning of period		588		332

Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period	$	264	$	273

Cash, cash equivalents, and restricted cash consists of:
Cash	$	235	$	250

Short-term investments		5		4

Restricted cash		20		19

Cash associated with assets held for sale		4		-

Total	$	264	$	273

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		NCI		Total Equity

For the three months ended September 30, 2024

Balance, June 30, 2024	$	8,657	$	1,422	$	83	$	656	$	1,729	$	14	$	12,561

Net income of Emera Incorporated		-		-		-		-		22		1		23

OCI, net of tax recovery of $2 million		-		-		-		(144)		-		-		(144)

Dividends declared on preferred stock (1)		-		-		-		-		(18)		-		(18)

Dividends declared on common stock ($0.7175/share)		-		-		-		-		(207)		-		(207)

Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts		75		-		-		-		-		-		75

Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs		146		-		-		-		-		-		146

Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”)		6		-		1		-		-		-		7

Other		-		-		-		-		-		(1)		(1)

Balance, September 30, 2024	$	8,884	$	1,422	$	84	$	512	$	1,526	$	14	$	12,442



For the nine months ended September 30, 2024

Balance, December 31, 2023	$	8,462	$	1,422	$	82	$	305	$	1,803	$	14	$	12,088

Net income of Emera Incorporated		-		-		-		-		394		1		395

OCI, net of tax expense of $3 million		-		-		-		207		-		-		207

Dividends declared on preferred stock (2)		-		-		-		-		(54)		-		(54)

Dividends declared on common stock ($2.1525/share)		-		-		-		-		(617)		-		(617)

Issued under the DRIP, net of discounts		217		-		-		-		-		-		217

Issuance of common stock under ATM program, net of after-tax issuance costs		181		-		-		-		-		-		181

Senior management stock options exercised and ECSPP		24		-		2		-		-		-		26

Other		-		-		-		-		-		(1)		(1)

Balance, September 30, 2024	$	8,884	$	1,422	$	84	$	512	$	1,526	$	14	$	12,442

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

(1) Series A; $0.1364/share, Series B; $0.4298/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3953/share; Series J; $0.2656/share and Series L; $0.2875/share

(2) Series A; $0.4092/share, Series B; $1.2948/share, Series C; $1.2064/share, Series E; $0.8438/share, Series F; $0.7879/share; Series H; $1.1858/share; Series J; $0.7969/share and Series L; $0.8625/share

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


millions of dollars	Common Stock		Preferred Stock		Contributed Surplus		AOCI		Retained Earnings		NCI		Total Equity

For the three months ended September 30, 2023

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

Net income of Emera Incorporated		-		-		-		-		117		1		118

OCI, net of tax expense of $3 million		-		-		-		200		-		-		200

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

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

Issued under the DRIP, net of discounts		66		-		-		-		-		-		66

Senior management stock options exercised and ECSPP		5		-		1		-		-		-		6

Other		-		-		-		-		-		(1)		(1)

Balance, September 30, 2023	$	7,993	$	1,422	$	82	$	562	$	1,711	$	14	$	11,784



For the nine months ended September 30, 2023

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

Net income of Emera Incorporated		-		-		-		-		737		1		738

OCI, net of tax recovery of $4 million		-		-		-		(16)		-		-		(16)

Dividends declared on preferred stock (2)		-		-		-		-		(48)		-		(48)

Dividends declared on common stock ($2.0700/share)		-		-		-		-		(562)		-		(562)

Issued under the DRIP, net of discount		205		-		-		-		-		-		205

Senior management stock options exercised and ECSPP		26		-		1		-		-		-		27

Other		-		-		-		-		-		(1)		(1)

Balance, September 30, 2023	$	7,993	$	1,422	$	82	$	562	$	1,711	$	14	$	11,784

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

(1) Series A; $0.1364/share, Series B; $0.3955/share, Series C; $0.2951/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3063/share; Series J; $0.2656/share and Series L; $0.2875/share

(2) Series A; $0.4092/share, Series B; $1.1302/share, Series C; $0.8852/share, Series E; $0.8438/share, Series F; $0.7879/share; Series H; $0.9188/share; Series J; $0.7969/share and Series L; $0.8625/share

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at September 30, 2024 and 2023

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

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

At September 30, 2024, 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

•

a 100 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.8 billion, including AFUDC, transmission project between the island of Newfoundland and Nova Scotia.

On June 4, 2024, Emera completed the sale of its 31.1 per cent indirect minority equity interest in the Labrador Island Link Partnership (“LIL”), which was previously included in the Canadian Electric Utilities segment. For further details, refer to note 3.

•

Gas Utilities and Infrastructure, which includes:

•

Peoples Gas System, Inc. (“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. On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the New Mexico Public Regulation Commission (“NMPRC”). For more information on the pending transaction, refer to note 3;

•

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 (“Repsol Energy”), 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 equity 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 segment includes investments in energy-related non-regulated companies that are below the required threshold for reporting as separate segments and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments. This 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 660 MW pumped storage hydroelectric facility in northwestern Massachusetts.

•

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

•

Block Energy 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, 2023.

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, 2024.

All dollar amounts are presented in Canadian dollars (“CAD”), 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. In Q3 2024, the Company recognized $210 million CAD ($155 million USD), pre-tax, in non-cash goodwill impairment related to the pending sale of NMGC. For more formation on the goodwill impairment, refer to note 19. There were no other material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2023 annual audited consolidated financial statements.

Seasonal Nature of Operations

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

2. FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting–Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard updates are to be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements disclosures.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. The Company does not expect a material impact on its consolidated financial statements disclosures as a result of adoption of the standard.

3. DISPOSITIONS

Pending Sale of NMGC

On August 5, 2024, Emera entered into an agreement to sell its indirect wholly owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024.

As the transaction proceeds will be lower than the carrying amount of the assets and liabilities being sold, Emera assessed the NMGC reporting unit for goodwill impairment by comparing the fair value (“FV”) of expected transaction proceeds to the carrying value of net assets, including goodwill of $366 million USD (“carrying amount”). The goodwill of the reporting unit was determined to be impaired and a non-cash goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million USD ($146 million USD, after-tax) was recorded in “Impairment Charges” on the Condensed Consolidated Statements of Income in Q3 2024.

Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an additional loss for the estimated future transaction costs of $16 million ($13 million after-tax), in addition to incurred transaction costs of $8 million ($6 million after-tax) recorded in “Other Income, net” on the Condensed Consolidated Statements of Income in Q3 2024.

The Company will continue to record depreciation on the NMGC assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $9 million ($7 million USD) has been recorded on these assets from August 5, 2024, the date they were classified as held for sale, to September 30, 2024.

Details of the assets and liabilities classified as held for sale are as follows:


As at millions of dollars	September 30 2024

Cash and cash equivalents	$	4

Inventory		9

Derivative instruments		14

Regulatory assets		19

Receivables and other current assets		62

Current assets held for sale	$	108

PP&E		1,672

Deferred income taxes		54

Regulatory assets		6

Goodwill		284

Other long-term assets		23

Long-term assets held for sale	$	2,039

Total assets held for sale	$	2,147


Short-term debt	$	19

Regulatory liabilities		13

Accounts payable and other current liabilities		100

Current liabilities associated with assets held for sale		132

Long-term debt		653

Deferred income taxes		211

Regulatory liabilities		255

Other long-term liabilities		11

Long-term liabilities associated with assets held for sale	$	1,130

Total liabilities associated with assets held for sale	$	1,262

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its 31.1 per cent indirect minority equity interest in the LIL for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable is held at FV and included in the gain on sale, after transaction costs. As of September 30, 2024, the estimated FV of the escrow proceeds receivable is $25 million. A gain on sale, after transaction costs, of $182 million, ($107 million, after tax and transaction costs), was recognized in “Other Income, net” on the Condensed Consolidated Statements of Income and included in the Other segment.

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 September 30, 2024
Operating revenues from external customers (1)	$	985	$	399		$	297	$	150	$	(29	)	$	-		$	1,802

Inter-segment revenues (1)		3		-			3		-		(8	)		2			-

Total operating revenues		988		399			300		150		(37	)		2			1,802

Regulated fuel for generation and purchased power		224		185			-		78		-			(3	)		484

Regulated cost of natural gas		-		-			46		-		-			-			46

OM&G		196		87			103		39		12			(5	)		432

Provincial, state and municipal taxes		73		12			24		1		-			-			110

Depreciation and amortization		156		71			46		18		2			-			293

Income from equity investments		-		12			4		1		8			-			25

Other income (expenses), net		15		7			5		2		(5	)		(10	)		14

Interest expense, net (2)		66		41			38		5		91			-			241

Impairment charges		-		-			11		-		210			-			221

Income tax expense (recovery)		36		(4	)		11		-		(52	)		-			(9	)

NCI		-		-			-		1		-			-			1

Preferred stock dividends		-		-			-		-		18			-			18

Net income (loss) attributable to common shareholders	$	252	$	26		$	30	$	11	$	(315	)	$	-		$	4

For the nine months ended September 30, 2024
Operating revenues from external customers (1)	$	2,639	$	1,376		$	1,150	$	416	$	(144	)	$	-		$	5,437

Inter-segment revenues (1)		7		-			10		-		10			(27	)		-

Total operating revenues		2,646		1,376			1,160		416		(134	)		(27	)		5,437

Regulated fuel for generation and purchased power		641		639			-		217		-			(10	)		1,487

Regulated cost of natural gas		-		-			282		-		-			-			282

OM&G		587		299			333		106		105			(15	)		1,415

Provincial, state and municipal taxes		207		36			78		3		1			-			325

Depreciation and amortization		462		209			135		54		6			-			866

Income from equity investments		-		67			14		3		3			-			87

Other income, net		44		21			12		7		146			2			232

Interest expense, net (2)		197		126			115		16		271			-			725

Impairment charges		-		-			11		-		210			-			221

Income tax expense (recovery)		72		-			60		-		(92	)		-			40

NCI		-		-			-		1		-			-			1

Preferred stock dividends		-		-			-		-		54			-			54

Net income (loss) attributable to common shareholders	$	524	$	155		$	172	$	29	$	(540	)	$	-		$	340

As at September 30, 2024
Total assets	$	22,552	$	7,697		$	7,929	$	1,337	$	1,393		$	(1,234	)	$	39,674

(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 $8 million for the three months ended September 30, 2024, and $22 million for the nine months ended September 30, 2024 between the 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 September 30, 2023
Operating revenues from external customers (1)	$	1,064	$	388		$	263	$	145	$	(120	)	$	-		$	1,740

Inter-segment revenues (1)		2		-			1		-		26			(29	)		-

Total operating revenues		1,066		388			264		145		(94	)		(29	)		1,740

Regulated fuel for generation and purchased power		282		173			-		76		-			(1	)		530

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

OM&G		237		92			94		31		46			(3	)		497

Provincial, state and municipal taxes		83		12			20		1		1			-			117

Depreciation and amortization		143		68			36		17		2			-			266

Income from equity investments		-		29			5		1		(3	)		-			32

Other income (expenses), net		17		8			1		1		(37	)		25			15

Interest expense, net (2)		67		43			34		5		86			-			235

Income tax expense (recovery)		43		(1	)		5		-		(81	)		-			(34)

NCI		-		-			-		1		-			-			1

Preferred stock dividends		-		-			-		-		16			-			16

Net income (loss) attributable to common shareholders	$	228	$	38		$	23	$	16	$	(204	)	$	-		$	101

For the nine months ended September 30, 2023
Operating revenues from external customers (1)	$	2,715	$	1,232		$	1,117	$	385	$	142		$	-		$	5,591

Inter-segment revenues (1)		6		-			8		-		26			(40	)		-

Total operating revenues		2,721		1,232			1,125		385		168			(40	)		5,591

Regulated fuel for generation and purchased power		699		512			-		197		-			(7	)		1,401

Regulated cost of natural gas		-		-			392		-		-			-			392

OM&G		621		283			295		93		123			(17	)		1,398

Provincial, state and municipal taxes		218		34			68		3		3			-			326

Depreciation and amortization		425		206			98		50		6			-			785

Income from equity investments		-		81			16		2		4			-			103

Other income, net		53		22			7		5		4			16			107

Interest expense, net (2)		204		128			91		17		244			-			684

Income tax expense (recovery)		95		(7	)		49		-		(60	)		-			77

NCI		-		-			-		1		-			-			1

Preferred stock dividends		-		-			-		-		48			-			48

Net income attributable to common shareholders	$	512	$	179		$	155	$	31	$	(188	)	$	-		$	689

As at December 31, 2023
Total assets	$	21,119	$	8,634		$	7,735	$	1,311	$	1,938		$	(1,257)		$	39,480

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $26 million for the three months ended September 30, 2023, and $69 million for the nine months ended September 30, 2023 between the Florida Electric Utility, 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 September 30, 2024
Regulated Revenue
Residential	$	643	$	191	$	56	$	107	$	-	$	-	$	997

Commercial		258		118		78		97		-		-		551

Industrial		56		70		9		24		-		(4)		155

Other electric		101		10		1		-		-		-		112

Regulatory deferrals		(76)		-		5		-		-		-		(71)

Other (1)		6		10		1		51		-		(3)		65

Finance income (2)(3)		-		-		-		16		-		-		16

Regulated revenue		988		399		150		295		-		(7)		1,825

Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		(7)		-		(7)

Other non-regulated operating revenue		-		-		-		5		7		(5)		7

Mark-to-market (3)		-		-		-		-		(37)		14		(23)

Non-regulated revenue		-		-		-		5		(37)		9		(23)

Total operating revenues	$	988	$	399	$	150	$	300	$	(37)	$	2	$	1,802


For the nine months ended September 30, 2024

Regulated Revenue
Residential	$	1,580	$	737	$	149	$	499	$	-	$	-	$	2,965

Commercial		710		371		224		361		-		-		1,666

Industrial		168		207		22		71		-		(11)		457

Other electric		318		31		4		-		-		-		353

Regulatory deferrals		(145)		-		13		-		-		-		(132)

Other (1)		15		30		4		167		-		(7)		209

Finance income (2)(3)		-		-		-		47		-		-		47

Regulated revenue		2,646		1,376		416		1,145		-		(18)		5,565

Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		42		-		42

Other non-regulated operating revenue		-		-		-		15		22		(16)		21

Mark-to-market (3)		-		-		-		-		(198)		7		(191)

Non-regulated revenue		-		-		-		15		(134)		(9)		(128)

Total operating revenues	$	2,646	$	1,376	$	416	$	1,160	$	(134)	$	(27)	$	5,437

(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 September 30, 2023
Regulated Revenue
Residential	$	761	$	179	$	54	$	100	$	-	$	-	$	1,094

Commercial		313		111		74		76		-		-		574

Industrial		76		81		9		23		-		(1)		188

Other electric		96		8		2		-		-		-		106

Regulatory deferrals		(184)		-		3		-		-		-		(181)

Other (1)		4		9		3		44		-		(2)		58

Finance income (2)(3)		-		-		-		16		-		-		16

Regulated revenue		1,066		388		145		259		-		(3)		1,855

Non-Regulated Revenue

Other non-regulated operating revenue		-		-		-		5		7		(6)		6

Mark-to-market (3)		-		-		-		-		(101)		(20)		(121)

Non-regulated revenue		-		-		-		5		(94)		(26)		(115)

Total operating revenues	$	1,066	$	388	$	145	$	264	$	(94)	$	(29)	$	1,740


For the nine months ended September 30, 2023

Regulated Revenue
Residential	$	1,777	$	671	$	136	$	529	$	-	$	-	$	3,113

Commercial		813		345		204		311		-		-		1,673

Industrial		205		159		25		68		-		(8)		449

Other electric		311		29		5		-		-		-		345

Regulatory deferrals		(399)		-		9		-		-		-		(390)

Other (1)		14		28		6		154		-		(6)		196

Finance income (2)(3)		-		-		-		47		-		-		47

Regulated revenue		2,721		1,232		385		1,109		-		(14)		5,433

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

Other non-regulated operating revenue		-		-		-		16		22		(18)		20

Mark-to-market (3)		-		-		-		-		85		(8)		77

Non-regulated revenue		-		-		-		16		168		(26)		158

Total operating revenues	$	2,721	$	1,232	$	385	$	1,125	$	168	$	(40)	$	5,591

(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 September 30, 2024, the aggregate amount of the transaction price allocated to remaining performance obligations was $453 million (2023 – $461 million), including $5 million related to NMGC. This amount includes $128 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 2044.

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 6 in Emera’s 2023 annual audited consolidated financial statements. Updates to regulatory environments are included below.


As at millions of dollars	September 30 2024 (1)		December 31 2023

Regulatory assets
Deferred income tax regulatory assets	$	1,117	$	1,233

TEC capital cost recovery for early retired assets		693		671

NSPI FAM		377		395

Pension and post-retirement medical plan		360		364

Storm cost recovery clauses		117		52

Deferrals related to derivative instruments		46		88

Cost recovery clauses		30		151

Environmental remediations		26		26

Stranded cost recovery		26		25

Other (2)		106		100

	$	2,898	$	3,105

Current	$	202	$	339

Long-term		2,696		2,766

Total regulatory assets	$	2,898	$	3,105


Regulatory liabilities
Deferred income tax regulatory liabilities	$	806	$	830

Accumulated reserve – cost of removal		686		849

Cost recovery clauses		117		32

Deferrals related to derivative instruments		24		17

BLPC Self-insurance fund (“SIF”) (note 24)		30		29

Other (2)		11		15

	$	1,674	$	1,772

Current	$	302	$	168

Long-term		1,372		1,604

Total regulatory liabilities	$	1,674	$	1,772

(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at September 30, 2024, NMGC’s assets and liabilities were classified as held for sale and excluded from the table above. For further details on the pending transaction, refer to note 3.

(2) Comprised of regulatory assets and liabilities that are not individually significant.

Florida Electric Utility

Storm Reserve:

On September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall approximately 200 miles north of Tampa, in Taylor County, as a Category 4 hurricane. TEC’s service territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number of customers out of 100,000. As of September 30, 2024, TEC deferred $45 million USD to the storm reserve for future recovery, with a minimal impact to earnings. As at September 30, 2024, total restoration costs charged to the storm reserve account, including Q3 2024 costs related to Hurricane Helene, have exceeded the storm reserve balance and therefore $35 million USD has been deferred as a regulatory asset for future recovery.

Base Rates:

On April 2, 2024, TEC requested a base rate increase, reflecting an increased revenue requirement of $297 million USD, effective January 1, 2025, and additional adjustments of $100 million USD and $72 million USD for 2026 and 2027, respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and other resiliency and reliability projects. The rate case hearing occurred in August 2024.

Fuel Recovery:

On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction is due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected 2024 costs in the fall of 2023. On May 7, 2024, the Florida Public Service Commission approved the mid-course adjustment.

Canadian Electric Utilities

NSPI

Federal Loan Guarantee (“FLG”):

On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML, and the Province of Nova Scotia (the “Province”) on terms and conditions for a FLG of $500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of the replacement energy that was required during the several years of delay in the Muskrat Falls hydroelectricity project. Subject to certain conditions, including regulatory approval by the Nova Scotia Utility and Review Board (“UARB”), the net proceeds of the NSPML debt issuance will be transferred to NSPI as a refund of a portion of previous NSPML assessment payments and be applied against the FAM regulatory asset balance. NSPML will then increase its annual assessment charge to NSPI to recover the refund and related financing costs over a 28-year period. On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. A decision on the NSPML application would trigger the debt issuance and refund to NSPI and a decision on the NSPI application would reflect the necessary 2025 fuel rates to service the incremental NSPML debt.

Hurricane Fiona:

On June 27, 2024, the UARB approved the deferred recognition of $25 million in incremental operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. Following UARB approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The UARB also directed NSPI to reclassify $10 million of undepreciated costs related to assets retired because of Hurricane Fiona to “Regulatory assets” from “PP&E” on the Condensed Consolidated Balance Sheets. NSPI began amortizing both regulatory assets over a 10-year period beginning July 1, 2024.

Storm Rider:

On April 30, 2024, NSPI applied to the UARB for recovery of $22 million of major storm restoration costs deferred to NSPI’s UARB approved storm rider in 2023. If approved, the 2023 costs deferred to the storm rider would be recovered over a 12-month period beginning January 1, 2025.

Fuel Recovery:

On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, which resulted in a corresponding decrease of the FAM regulatory asset. NSPI is collecting the amortization and financing costs related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period, which began in Q2 2024, and is remitting those amounts to Invest Nova Scotia quarterly.

NSPML

On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the Province on terms and conditions for a FLG of $500 million in debt to be issued by NSPML. For further information, refer to the NSPI section above.

On July 4, 2024, NSPML submitted an application to the UARB requesting recovery of approximately $158 million in Maritime Link costs for 2025.

On December 21, 2023, NSPML received approval from the UARB to collect up to $164 million in 2024 from NSPI for the recovery of costs associated with the Maritime Link subject to a holdback of $4 million per month. There was no holdback recorded year-to-date in 2024.

Gas Utilities and Infrastructure

NMGC

Base Rates:

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates. On March 1, 2024, NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30 million USD in annual base revenues and maintaining NMGC’s return on equity (“ROE”) at 9.375 per cent. The rates reflect the recovery of increased operating costs and capital investments in pipeline projects and related infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw, and to not reassert in a future rate case application, its request for a regulatory asset for costs associated with its 2022 application for a certificate of public convenience and necessity for a liquefied natural gas storage facility in New Mexico. The NMPRC approved the rate case settlement on July 25, 2024. New rates became effective October 1, 2024.

Other Electric Utilities

BLPC

Barbados Domestic Tax Rate Change:

On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation) Act into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs over a period to be approved by the Fair Trading Commission, Barbados (“FTC”) during a future rate setting process.

Clean Energy Transition Rider (“CETR”):

On May 31, 2023, the FTC approved BLPC’s application to establish a CETR to recover prudently incurred costs associated with its clean energy transition project. The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the mechanism. On May 6, 2024, the FTC approved certain aspects of BLPC’s application, including the recovery for capital investment in a 15 MW battery storage system. BLPC is currently evaluating the impact of operationalizing the decision.

Base Rates:

In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued a decision on the 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 totalling approximately $71 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023 decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. The appeal is currently scheduled to be heard in December 2024.

GBPC

Base Rates:

On August 1, 2024, as required by the Grand Bahamas Port Authority (“GBPA”) Operating Protocol and Regulatory Framework Agreement, GBPC filed a rate plan proposal. During Q2 2024, GBPC customers experienced power interruptions due to unscheduled generation outages. Subsequently, on October 1, 2024, the GBPA suspended its review of GBPC’s rate plan proposal until a period of reliability is re-established by GBPC.

Electricity Act, 2024:

On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian regulator, regulate GBPC.

7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME


	September 30		Carrying Value as at December 31		Equity Income (loss) for the three months ended September 30				Equity Income for the nine months ended September 30				Percentage of Ownership
millions of dollars		2024		2023		2024		2023		2024		2023		2024
NSPML	$	483	$	489	$	12	$	13	$	38	$	34		100.0
M&NP (1)		117		118		4		5		14		16		12.9
Lucelec (1)		52		48		1		1		3		2		19.5
LIL (2)		-		747		-		16		29		47		-
Bear Swamp (3)		-		-		8		(3)		3		4		50.0
	$	652	$	1,402	$	25	$	32	$	87	$	103

(1) Emera has significant influence over the operating and financial decisions of these companies through Board representation and therefore, records its investment in these entities using the equity method.

(2) On June 4, 2024, Emera completed the sale of its equity interest in the LIL. For further details, refer to note 3.

(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 $84 million (2023 – $81 million) is recorded in Other long-term liabilities on the Condensed Consolidated Balance Sheets.

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


As at millions of dollars	September 30 2024		December 31 2023
Current assets	$	49	$	21
PP&E		1,438		1,473
Regulatory assets		285		272
Non-current assets		27		29
Total assets	$	1,799	$	1,795
Current liabilities	$	62	$	48
Long-term debt (1)		1,090		1,109
Non-current liabilities		164		149
Equity		483		489
Total liabilities and equity	$	1,799	$	1,795

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

8. OTHER INCOME, NET


	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
Gain on sale of LIL, net of transaction costs (1)	$	-	$	-	$	182	$	-
AFUDC - equity		15		10		36		27
Pension non-service cost recovery		8		9		26		25
Interest income		4		11		13		36
FX gains (losses)		6		(18)		(16)		3
Transaction costs related to the pending sale of NMGC (1)		(24)		-		(24)		-
Other		5		3		15		16
	$	14	$	15	$	232	$	107

(1) For more information related to the gain on sale, after transaction costs, of Emera’s indirect minority equity interest in the LIL and the pending sale of NMGC, refer to note 3.

9. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:


	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
Interest on debt	$	252	$	244	$	753	$	706
Allowance for borrowed funds used during construction		(6)		(4)		(15)		(11)
Other		(5)		(5)		(13)		(11)
	$	241	$	235	$	725	$	684

10. INCOME TAXES

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


	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
Income before provision for income taxes	$	14	$	84	$	435	$	815
Statutory income tax rate		29%		29%		29%		29%
Income taxes, at statutory income tax rate		4		24		126		236
Goodwill impairment charge		48		-		48		-
Tax credits		(22)		(15)		(47)		(32)
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(8)		(8)		(38)		(53)
Amortization of deferred income tax regulatory liabilities		(14)		(16)		(30)		(32)
Foreign tax rate variance		(11)		(14)		(26)		(33)
Additional impact from the sale of LIL equity interest		-		-		22		-
Tax effect of equity earnings		(4)		(4)		(12)		(11)
Other		(2)		(1)		(3)		2
Income tax (recovery) expense	$	(9)	$	(34)	$	40	$	77
Effective income tax rate		(64%)		(40%)		9%		9%

Excessive Interest and Financing Expenses Limitation (“EIFEL”) Regime:

On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March 28, 2023, was enacted. Bill C-59 includes the EIFEL regime, which is effective January 1, 2024. EIFEL applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of earnings before interest, income taxes, depreciation, and amortization for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be carried forward indefinitely. The EIFEL regime did not have a material impact on the Company in Q3 2024.

Canadian Global Minimum Tax Act (“GMTA”):

On June 20, 2024, Bill C-69, an Act to implement certain provisions of the budget tabled in Parliament on April 16, 2024, was enacted. Bill C-69 includes the GMTA, a regime based on the rules of the Organisation for Economic Co-operation and Development (“OECD”). The GMTA ensures that large multinational corporations are subject to a minimum effective tax rate of 15 per cent on their profits wherever they do business. The GMTA did not have a material impact on the Company in Q3 2024.

Barbados Domestic Tax Rate Change:

United States Inflation Reduction Act (“IRA”):

On August 16, 2022, the 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 September 30, 2024, the Company has recorded a $70 million (December 31, 2023 – $30 million) regulatory liability on the Condensed Consolidated Balance Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers.

11. COMMON STOCK

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


Issued and outstanding:	millions of shares		millions of dollars
Balance, December 31, 2023		284.12	$	8,462
Issuance of common stock under ATM program (1)		3.61		181
Issued under the DRIP, net of discounts		4.61		217
Senior management stock options exercised and ECSPP		0.50		24
Balance, September 30, 2024		292.84	$	8,884

(1) For the three months ended September 30, 2024, 2,882,000 common shares were issued under Emera’s ATM program at an average price of $51.18 per share for gross proceeds of $148 million ($146 million, net of after-tax issuance costs). For the nine months ended September 30, 2024, 3,606,996 common shares were issued under Emera’s ATM program at an average price of $50.58 per share for gross proceeds of $182 million ($181 million net of after-tax issuance costs). As at September 30, 2024, an aggregate gross sales limit of $18 million remained available for issuance under the ATM program.

12. EARNINGS PER SHARE

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


	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars (except per share amounts)	2024		2023		2024		2023
Numerator
Net income attributable to common shareholders	$	3.7	$	100.6	$	339.9	$	688.5
Diluted numerator		3.7		100.6		339.9		688.5
Denominator
Weighted average shares of common stock outstanding – basic		290.0		273.6		287.5		272.2
Stock-based compensation		0.1		0.2		0.1		0.3
Weighted average shares of common stock outstanding – diluted		290.1		273.8		287.6		272.5
Earnings per common share
Basic	$	0.01	$	0.37	$	1.18	$	2.53
Diluted	$	0.01	$	0.37	$	1.18	$	2.53

13. ACCUMULATED OTHER COMPREHENSIVE INCOME

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


millions of dollars	Unrealized 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 nine months ended September 30, 2024
Balance, January 1, 2024	$	369	$	(24)	$	14	$	(2)	$	(52)	$	305
OCI before reclassifications		240		(33)		-		1		-		208
Amounts reclassified from AOCI		-		-		(2)		-		1		(1)
Net current period OCI		240		(33)		(2)		1		1		207
Balance, September 30, 2024	$	609	$	(57)	$	12	$	(1)	$	(51)	$	512

For the nine months ended September 30, 2023
Balance, January 1, 2023	$	639	$	(62)	$	16	$	(2)	$	(13)	$	578
OCI before reclassifications		(14)		3		1		-		-		(10)
Amounts reclassified from AOCI		-		-		(2)		-		(4)		(6)
Net current period OCI		(14)		3		(1)		-		(4)		(16)
Balance, September 30, 2023	$	625	$	(59)	$	15	$	(2)	$	(17)	$	562

The reclassifications out of AOCI are as follows:


		Three months ended				Nine months ended
For the		September 30				September 30
millions of dollars		2024		2023		2024		2023
Affected line item in the Condensed Consolidated Interim Financial Statements			Amounts reclassified from AOCI
Gain on derivatives recognized as cash flow hedges
Interest rate hedge	Interest expense, net	$	(1)	$	(1)	$	(2)	$	(2)
Net change in unrecognized pension and post-retirement benefit costs
Amounts reclassified into obligations	Pension and post-retirement benefits		-		1		1		(4)
Total reclassifications out of AOCI, for the period		$	(1)	$	-	$	(1)	$	(6)

14. DERIVATIVE INSTRUMENTS

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

•

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

•

foreign exchange (“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 FV 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 FV 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 FV with any changes in FV 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 FV on the balance sheet as derivative assets or liabilities. The change in FV 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. Based on current direction from the FPSC, TEC and PGS have no derivatives related to hedging.

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 FV, 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	September 30		December 31		September 30		December 31
millions of dollars	2024		2023		2024		2023
Regulatory deferral:
Commodity swaps and forwards	$	36	$	16	$	46	$	76
FX forwards		7		3		4		3
		43		19		50		79
HFT derivatives:
Power swaps and physical contracts		14		29		13		36
Natural gas swaps, futures, forwards, physical contracts		249		319		528		531
		263		348		541		567
Other derivatives:
Equity derivatives		13		4		-		-
FX forwards		4		18		2		7
		17		22		2		7
Total gross derivatives		323		389		593		653
Impact of master netting agreements:
Regulatory deferral		(4)		(3)		(4)		(3)
HFT derivatives		(132)		(146)		(132)		(146)
Total impact of master netting agreements		(136)		(149)		(136)		(149)
Less: Derivatives classified as held for sale (1)		(14)		-		-		-
Total derivatives	$	173	$	240	$	457	$	504
Current (2)		129		174		364		386
Long-term (2)		44		66		93		118
Total derivatives	$	173	$	240	$	457	$	504

(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at September 30, 2024, NMGC’s assets and liabilities were classified as held for sale. For further details on the pending transaction, refer to note 3.

(2) 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. As of September 30, 2024, the unrealized gain in AOCI was $12 million, after-tax (December 31, 2023 – $14 million, after-tax). For the three and nine months ended September 30, 2024, unrealized gains of $1 million (2023 – $1 million) and $2 million (2023 – $2 million) respectively have been reclassified from AOCI into interest expense, net. The Company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months.

Regulatory Deferral

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


millions of dollars	Commodity swaps and forwards		FX forwards		Physical natural gas purchases		Commodity swaps and forwards		FX forwards
For the three months ended September 30				2024						2023
Unrealized gain (loss) in regulatory assets	$	(14)	$	(1)	$	-	$	11	$	4
Unrealized gain (loss) in regulatory liabilities		(6)		(1)		-		12		6
Realized gain in regulatory assets		(3)		-		-		(5)		-
Realized (gain) loss in regulatory liabilities		1		-		-		(1)		-
Realized (gain) loss in inventory (1)		3		(1)		-		2		(1)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		16		(1)		(6)		-		-
Total change in derivative instruments	$	(3)	$	(4)	$	(6)	$	19	$	9

For the nine months ended September 30				2024						2023
Unrealized gain (loss) in regulatory assets	$	(1)	$	-	$	-	$	(18)	$	1
Unrealized gain (loss) in regulatory liabilities		6		13		(3)		(47)		4
Realized gain in regulatory assets		(7)		-		-		(5)		-
Realized loss in regulatory liabilities		1		-		-		3		-
Realized (gain) loss in inventory (1)		10		(5)		-		7		(10)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		41		(5)		(48)		(20)		(2)
Other		-		-		-		(15)		-
Total change in derivative instruments	$	50	$	3	$	(51)	$	(95)	$	(7)

(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 September 30, 2024, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:


millions	2024		2025-2026
Physical natural gas purchases:
Natural gas (MMBtu)		2		6
Commodity swaps and forwards purchases:
Natural gas (MMBtu)		9		28
Heavy fuel oil (bbls)		-		1
Power (MWh)		-		1
Coal (metric tonnes)		-		1
FX swaps and forwards:
FX contracts (millions of USD)	$	86	$	272
Weighted average rate		1.3436		1.3330
% of USD requirements		90%		33%

HFT Derivatives

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


	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
Power swaps and physical contracts in non-regulated operating revenues	$	-	$	(2)	$	11	$	(2)
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		59		92		198		909
Total gains in net income	$	59	$	90	$	209	$	907

As at September 30, 2024, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:


millions	2024		2025		2026		2027		2028 and thereafter
Natural gas purchases (MMBtu)		87		191		86		41		103
Natural gas sales (MMBtu)		111		201		46		13		10
Power purchases (MWh)		-		1		-		-		-
Power sales (MWh)		-		1		-		-		-

Other Derivatives

As at September 30, 2024, the Company had equity derivatives in place to manage 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 2.9 million shares and extends until December 2024. The FX forwards have a combined notional amount of $458 million USD and expire in 2024 through 2026.

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


millions of dollars	FX forwards		Equity derivatives		FX forwards		Equity derivatives
For the three months ended September 30			2024				2023
Unrealized gain (loss) in OM&G	$	-	$	22	$	-	$	(20)
Unrealized gain (loss) in other income, net		8		-		(16)		-
Realized loss in other income, net		(3)		-		(2)		-
Total gains (losses) in net income	$	5	$	22	$	(18)	$	(20)

For the nine months ended September 30				2024				2023
Unrealized gain (loss) in OM&G	$	-	$	8	$	-	$	(12)
Unrealized gain (loss) in other income, net		(8)		-		7		-
Realized loss in other income, net		(7)		-		(7)		-
Total gains (losses) in net income	$	(15)	$	8	$	-	$	(12)

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 September 30, 2024, the Company had $124 million (December 31, 2023 – $142 million) in financial assets considered to be past due, which had been outstanding for an average 64 days. The FV of these financial assets was $112 million (December 31, 2023 – $127 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.


As at millions of dollars	September 30 2024		December 31 2023
Cash collateral provided to others	$	67	$	101
Cash collateral received from others	$	7	$	22

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 September 30, 2024, the total FV of derivatives in a liability position was $457 million (December 31, 2023 – $504 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.

15. FV MEASUREMENTS

The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 14), and uses a market approach to do so. The three levels of the FV 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 FV measurement.

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


As at	September 30, 2024
millions of dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral:
Commodity swaps and forwards	$	9	$	23	$	-	$	32
FX forwards		-		7		-		7
		9		30		-		39
HFT derivatives:
Power swaps and physical contracts		-		8		3		11
Natural gas swaps, futures, forwards, physical contracts and related transportation		33		69		18		120
		33		77		21		131
Other derivatives:
FX forwards		-		4		-		4
Equity derivatives		13		-		-		13
		13		4		-		17
Less: Derivatives classified as held for sale (1)		-		(14)		-		(14)
Total assets		55		97		21		173
Liabilities
Regulatory deferral:
Commodity swaps and forwards		29		13		-		42
FX forwards		-		4		-		4
		29		17		-		46
HFT derivatives:
Power swaps and physical contracts		1		6		3		10
Natural gas swaps, futures, forwards and physical contracts		8		26		365		399
		9		32		368		409
Other derivatives:
FX forwards		-		2		-		2
Total liabilities		38		51		368		457
Net assets (liabilities)	$	17	$	46	$	(347)	$	(284)


As at	December 31, 2023
millions of dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral:
Commodity swaps and forwards	$	7	$	6	$	-	$	13
FX forwards		-		3		-		3
		7		9		-		16
HFT derivatives:
Power swaps and physical contracts		(5)		23		-		18
Natural gas swaps, futures, forwards, physical contracts and related transportation		42		108		34		184
		37		131		34		202
Other derivatives:
Equity derivatives		4		-		-		4
FX forwards		-		18		-		18
		4		18		-		22
Total assets		48		158		34		240
Liabilities
Regulatory deferral:
Commodity swaps and forwards		43		30		-		73
FX forwards		-		3		-		3
		43		33		-		76
HFT derivatives:
Power swaps and physical contracts		-		24		-		24
Natural gas swaps, futures, forwards and physical contracts		13		19		365		397
		13		43		365		421
Other derivatives:
FX forwards		-		7		-		7
Total liabilities		56		83		365		504
Net assets (liabilities)	$	(8)	$	75	$	(331)	$	(264)

The change in the FV of the Level 3 financial assets and liabilities was as follows:


	Three months ended						Nine months ended
	September 30, 2024						September 30, 2024
	HFT Derivatives						HFT Derivatives
millions of dollars	Power		Natural gas		Total		Power		Natural gas		Total
Assets
Balance, beginning of period	$	3	$	13	$	16	$	-	$	34	$	34
Total realized and unrealized gains (losses) included in non-regulated operating revenues		-		5		5		3		(16)		(13)
Balance, September 30, 2024	$	3	$	18	$	21	$	3	$	18	$	21
Liabilities
Balance, beginning of period	$	2	$	374	$	376	$	-	$	365	$	365
Total realized and unrealized gains (losses) included in non-regulated operating revenues		1		(9)		(8)		3		-		3
Balance, September 30, 2024	$	3	$	365	$	368	$	3	$	365	$	368

Significant unobservable inputs used in the FV 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) FV 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 FV of Level 3 derivative instruments. The following table outlines quantitative information about the significant unobservable inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:


	September 30, 2024
As at millions of dollars	FV				Significant Unobservable Input	Low		High		Weighted Average (1)
	Assets		Liabilities
HFT derivatives – Power swaps and physical contracts		3		3	Third-party pricing	$	23.75	$	125.70		$74.84
HFT derivatives – Natural gas swaps, futures, forwards and physical contracts		18		365	Third-party pricing		$1.50		$14.86		$6.29
Total	$	21	$	368
Net liability			$	347

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

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


As at millions of dollars	Carrying Amount		FV		Level 1		Level 2		Level 3		Total
September 30, 2024	$	17,262	$	16,757	$	-	$	16,516	$	241	$	16,757
December 31, 2023	$	18,365	$	16,621	$	-	$	16,363	$	258	$	16,621

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 $22 million was recorded in AOCI for the three months ended September 30, 2024 (2023 – $33 million after-tax loss) and an after-tax foreign currency loss of $33 million was recorded for the nine months ended September 30, 2024 (2023 – $3 million after-tax gain).

16. 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 September 30, 2024 (2023 – $44 million) and $123 million for the nine months ended September 30, 2024 (2023 – $122 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 September 30, 2024 (2023 – $2 million) and $8 million for the nine months ended September 30, 2024 (2023 – $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 September 30, 2024 and at December 31, 2023.

17. RECEIVABLES AND OTHER CURRENT ASSETS


As at	September 30		December 31
millions of dollars	2024		2023
Customer accounts receivable – billed	$	715	$	805
Customer accounts receivable – unbilled		304		363
Capitalized transportation capacity (1)		227		358
Prepaid expenses		136		105
Income tax receivable		3		10
Allowance for credit losses		(12)		(15)
Other		155		191
Total receivables and other current assets	$	1,528	$	1,817

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

18. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) 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				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
DB pension plans
Service cost	$	9	$	8	$	26	$	23
Non-service cost:
Interest cost		27		27		82		83
Expected return on plan assets		(40)		(40)		(120)		(121)
Current year amortization of:
Actuarial losses		-		-		1		-
Regulatory asset		3		2		7		5
Settlements and curtailments		-		2		-		2
Total non-service costs		(10)		(9)		(30)		(31)
Total DB pension plans		(1)		(1)		(4)		(8)
Non-pension benefit plans
Service cost		1		1		2		2
Non-service cost:
Interest cost		3		3		9		10
Expected return on plan assets		(1)		-		(2)		(1)
Current year amortization of:
Actuarial gains		-		(1)		-		(1)
Regulatory asset		(1)		(1)		(3)		(3)
Total non-service costs		1		1		4		5
Total non-pension benefit plans		2		2		6		7
Total DB plans	$	1	$	1	$	2	$	(1)

Emera’s pension and non-pension contributions related to these DB plans for the three months ended September 30, 2024 were $13 million (2023 – $20 million), and for the nine months ended September 30, 2024 were $41 million (2023 – $55 million). Annual employer contributions to the DB pension plans are estimated to be $34 million for 2024. Emera’s contributions related to the DC plans for the three months ended September 30, 2024 were $12 million (2023 – $11 million) and $37 million (2023 – $33 million) for the nine months ended September 30, 2024.

19. GOODWILL

The change in goodwill was due to the following:


As at	September 30		December 31
millions of dollars	2024		2023
Balance, January 1	$	5,871	$	6,012
Impairment charge		(210)		-
Classified as assets held for sale (1)		(284)		-
Change in FX rate		121		(141)
Total goodwill	$	5,498	$	5,871

(1) As at September 30, 2024, NMGC’s assets and liabilities were classified as held for sale. For further details on the pending transaction, refer to note 3.

On August 5, 2024, Emera announced an agreement to sell NMGC. As the expected transaction proceeds on the pending sale will be less than the carrying value of net assets, including goodwill (“carrying amount”), in Q3 2024, the Company performed a quantitative goodwill impairment assessment for the NMGC reporting unit. It was determined that the carrying amount exceeded the FV of the expected transaction proceeds, and as a result, a non-cash goodwill impairment charge of $210 million, pre-tax, was recorded in Q3 2024, reducing the NMGC reporting unit goodwill balance to $284 million as at September 30, 2024. This non-cash charge is included in “Impairment charges” on the Condensed Consolidated Statements of Income.

20. 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 2023 annual audited consolidated financial statements, and below for 2024 short-term debt financing activity.

Florida Electric Utilities

On April 1, 2024, TEC amended its $800 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in commercial terms from the prior agreement.

Other

On June 17, 2024, Emera repaid $200 million from the December 2024 unsecured non-revolving facility, decreasing the facility from $400 million to $200 million. There were no other material changes in commercial terms from the prior agreement.

On April 1, 2024, TECO Finance amended its $400 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in commercial terms from the prior agreement.

On February 16, 2024, Emera amended its $400 million unsecured non-revolving facility to extend the maturity date from February 19, 2024 to February 19, 2025. There were no other changes in commercial terms from the prior agreement. On July 19, 2024, Emera reduced the amount of the facility from $400 million to $200 million.

21. LONG-TERM DEBT

For details regarding long-term debt, refer to note 25 in Emera’s 2023 annual audited consolidated financial statements, and below for 2024 long-term debt financing activity.

Florida Electric Utilities

On July 12, 2024, TEC repaid a $300 million USD note upon maturity. This note was repaid with proceeds from commercial paper.

On January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 4.90 per cent with a maturity date of March 1, 2029. Proceeds from the issuance were primarily used for the repayment of short-term borrowings outstanding under the 5-year credit facility.

Canadian Electric Utilities

On June 24, 2024, NSPI amended its unsecured committed revolving credit facility to extend the maturity date from December 16, 2027 to June 24, 2029. There were no other material changes in commercial terms from the prior agreement.

On June 24, 2024, NSPI amended its unsecured non-revolving credit facility to extend the maturity date from July 15, 2024 to June 24, 2025 and reduce the facility from $400 million to $300 million. There were no other material changes in commercial terms from the prior agreement.

On June 13, 2024, NSPI entered a non-revolving credit facility to finance the Battery Energy Storage Project. NSPI can request funds under the facility quarterly for amounts related to incurred project costs up to the total commitment of the lessor of $120 million and 45.06 per cent of the total eligible project costs over the term of the agreement. The facility will be available until 6 months after completion of the project, not to exceed May 21, 2027 and matures 20 years following the end of the period. As at September 30, 2024, NSPI had utilized $16 million from the facility, which bears interest at 2.51 per cent.

Gas Utilities and Infrastructure

On July 30, 2024, New Mexico Gas Intermediate, Inc. repaid its $150 million USD fixed rate notes upon maturity.

Other Electric Utilities

On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend the maturity date from February 19, 2025 to July 19, 2028. There were no other material changes in commercial terms from the prior agreement.

Other

On June 24, 2024, Emera amended its unsecured committed revolving credit facility increasing the facility from $900 million to $1,300 million. Emera also extended the maturity date from June 24, 2027 to June 24, 2029. There were no other material changes in commercial terms from the prior agreement.

On June 24, 2024, Emera repaid its $400 million unsecured non-revolving credit facility set to mature in August 2024.

On June 15, 2024, Emera Finance repaid its $300 million USD senior notes upon maturity.

On June 18, 2024, EUSHI Finance, Inc., completed an issuance of $500 million USD fixed-to-fixed reset rate junior subordinated notes. The notes initially bear interest at a rate of 7.625 per cent, and will reset on December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S. treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, Inc., at its option, may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-annual interest payment date thereafter, at a redemption price equal to the principal amount.

22. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at September 30, 2024, 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		2024		2025		2026		2027		2028		Thereafter		Total
Transportation (1)(2)	$	216	$	654	$	483	$	488	$	420	$	3,401	$	5,662
Purchased power (3)		82		289		275		324		325		3,562		4,857
Capital projects		712		245		62		10		1		1		1,031
Fuel, gas supply and storage (4)		217		445		86		11		4		-		763
Other		34		148		62		50		37		233		564
	$	1,261	$	1,781	$	968	$	883	$	787	$	7,197	$	12,877

As detailed below, commitments at September 30, 2024 include those related to NMGC. On completion of the sale of NMGC, all the remaining future commitments will be transferred to the buyer. For further details on the pending transaction, refer to note 3.

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $128 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(2) Includes $77 million related to NMGC (2024: $10 million, 2025: $27 million, 2026: $19 million, 2027: $12 million, 2028: $9 million).

(3) Annual requirement to purchase electricity from Independent Power Producers or other utilities over varying contract lengths.

(4) Includes $203 million related to NMGC (2024: $52 million, 2025: $107 million, 2026: $36 million, 2027: $5 million, 2028: $3 million).

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 December 2023, the UARB approved the collection of up to $164 million from NSPI for the recovery of Maritime Link costs in 2024. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Nalcor Energy’s use, if requested, 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 September 30, 2024, the aggregate financial liability of the Florida utilities is estimated to be $15 million ($11 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 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 2023 annual audited consolidated financial statements. Risks associated with derivative instruments and FV measurements are discussed in note 14 and note 15. There have been no material changes to the principal financial risks as of September 30, 2024.

D. Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2023 audited annual consolidated financial statements, with material updates as noted below:

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2025. The amount committed as at September 30, 2024 was $58 million (December 31, 2023 – $56 million).

Emera has provided an indemnity to a counterparty in relation to certain future tax amounts that could arise from specific future changes in Canadian federal law, subject to certain conditions and limitations. No such changes in law have been proposed at this time. A reasonable estimate of the potential amount of future payments that could result from future claims under this indemnity cannot be calculated, but the risk of having to make any significant payments under this indemnity is considered to be remote.

23. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


For the	Nine months ended September 30
millions of dollars			2024		2023
Changes in non-cash working capital:
Inventory		$	44	$	(71)
Receivables and other current assets (1)			155		731
Accounts payable			(64)		(541)
Other current liabilities (2)			85		(114)
Total non-cash working capital		$	220	$	5

1) The nine months ended September 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 nine months ended September 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.


For the	Nine months ended September 30
millions of dollars			2024		2023
Supplemental disclosure of non-cash activities:
Common share dividends reinvested		$	217	$	205
Increase in accrued capital expenditures		$	12	$	45
Accrued proceeds from disposal of investment subject to significant influence		$	25	$	-
Reclassification of short-term debt and current portion of long-term debt to long-term debt		$	-	$	135

Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities		$	216	$	54

24. VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have 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 it has authority over the majority of the direct activities expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link 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 as an “Other long-term asset”, “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

September 30, 2024

December 31, 2023

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)

483

489

25. 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 November 8, 2024, the date the unaudited condensed consolidated interim financial statements were issued.