Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2024 and 2023

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

For the	Three months ended March 31
millions of dollars (except per share amounts)	2024		2023
Operating revenues
Regulated electric	$	1,415	$	1,362
Regulated gas		523		566
Non-regulated		80		505
Total operating revenues (note 4)		2,018		2,433
Operating expenses
Regulated fuel for generation and purchased power		512		475
Regulated cost of natural gas		180		276
Operating, maintenance and general expenses (“OM&G”)		500		430
Provincial, state and municipal taxes		106		102
Depreciation and amortization		283		256
Total operating expenses		1,581		1,539
Income from operations		437		894
Income from equity investments (note 6)		34		35
Other income, net		28		35
Interest expense, net (note 7)		246		226
Income before provision for income taxes		253		738
Income tax expense (note 8)		28		162
Net income		225		576
Preferred stock dividends		18		16

Net income attributable to common shareholders	$	207	$	560
Weighted average shares of common stock outstanding (in millions) (note 10)
Basic		285.1		270.7
Diluted		285.2		271.0
Earnings per common share (note 10)
Basic	$	0.73	$	2.07
Diluted	$	0.73	$	2.07
Dividends per common share declared	$	0.7175	$	0.6900

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

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

For the	Three months ended March 31
millions of dollars	2024		2023
Net income	$	225	$	576
Other comprehensive income (loss) (“OCI”), net of tax
Foreign currency translation adjustment (1)		284		3
Unrealized (losses) gains on net investment hedges (2)		(39)		1
Cash flow hedges – reclassification adjustment for gains included in income		(1)		(1)
Unrealized gains on available-for-sale investment		1		-
Net change in unrecognized pension and post-retirement benefit obligation		1		(4)
OCI (3)	$	246	$	(1)
Comprehensive Income of Emera Incorporated	$	471	$	575

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

1) Net of tax expense of $4 million for the three months ended March 31, 2024 (2023 – $4 million recovery).

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

3) Net of tax expense of $4 million for the three months ended March 31, 2024 (2023 – $4 million recovery).

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

As at	March 31		December 31
millions of dollars	2024		2023
Assets
Current assets
Cash and cash equivalents	$	258	$	567
Restricted cash (note 21)		18		21
Inventory		745		790
Derivative instruments (notes 12 and 13)		125		174
Regulatory assets (note 5)		232		339
Receivables and other current assets (note 15)		1,831		1,817
		3,209		3,708
Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $10,304 and $9,994, respectively		25,162		24,376
Other assets
Deferred income taxes (note 8)		205		208
Derivative instruments (notes 12 and 13)		62		66
Regulatory assets (note 5)		2,855		2,766
Net investment in direct finance and sales type leases		618		621
Investments subject to significant influence (note 6)		1,403		1,402
Goodwill		6,015		5,871
Other long-term assets		502		462
		11,660		11,396
Total assets	$	40,031	$	39,480
Liabilities and Equity
Current liabilities
Short-term debt (note 17)	$	1,485	$	1,433
Current portion of long-term debt (note 18)		662		676
Accounts payable		1,196		1,454
Derivative instruments (notes 12 and 13)		370		386
Regulatory liabilities (note 5)		186		168
Other current liabilities		530		427
		4,429		4,544

Long-term liabilities
Long-term debt (note 18)		17,829		17,689
Deferred income taxes (note 8)		2,441		2,352
Derivative instruments (notes 12 and 13)		91		118
Regulatory liabilities (note 5)		1,685		1,604
Pension and post-retirement liabilities (note 16)		263		265
Other long-term liabilities (note 6)		853		820
		23,162		22,848
Equity
Common stock (note 9)		8,565		8,462
Cumulative preferred stock		1,422		1,422
Contributed surplus		82		82
Accumulated other comprehensive income (“AOCI’) (note 11)		551		305
Retained earnings		1,806		1,803
Total Emera Incorporated equity		12,426		12,074
Non-controlling interest in subsidiaries		14		14
Total equity		12,440		12,088
Total liabilities and equity	$	40,031	$	39,480

Commitments and contingencies (note 19)	Approved on behalf of the Board of Directors
The accompanying notes are an integral part of these condensed consolidated interim financial statements.	“M. Jacqueline Sheppard”	“Scott Balfour”
	Chair of the Board	President and Chief Executive Officer

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the	Three months ended March 31
millions of dollars	2024		2023
Operating activities
Net income	$	225	$	576
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		286		258
Income from equity investments, net of dividends		10		(18)
Allowance for funds used during construction (“AFUDC”) – equity		(9)		(8)
Deferred income taxes, net		19		154
Net change in pension and post-retirement liabilities		(14)		(16)
Fuel adjustment mechanism (“FAM”)		(30)		128
Net change in fair value (“FV”) of derivative instruments		45		(633)
Net change in regulatory assets and liabilities		120		(37)
Net change in capitalized transportation capacity		(28)		226
Other operating activities, net		7		24
Changes in non-cash working capital (note 20)		(62)		(201)
Net cash provided by operating activities		569		453
Investing activities
Additions to PP&E		(601)		(637)
Other investing activities		(3)		(3)
Net cash used in investing activities		(604)		(640)
Financing activities
Change in short-term debt, net		(631)		108
Proceeds from long-term debt, net of issuance costs		664		500
Retirement of long-term debt		(39)		(7)
Net repayments under committed credit facilities		(162)		(311)
Issuance of common stock, net of issuance costs		31		7

Dividends on common stock		(133)		(118)
Dividends on preferred stock		(18)		(16)
Other financing activities		-		(10)
Net cash (used in) provided by financing activities		(288)		153
Effect of exchange rate changes on cash, cash equivalents and restricted cash		11		4
Net decrease in cash, cash equivalents, and restricted cash		(312)		(30)
Cash, cash equivalents and restricted cash, beginning of period		588		332
Cash, cash equivalents and restricted cash, end of period	$	276	$	302
Cash, cash equivalents, and restricted cash consists of:
Cash	$	254	$	270
Short-term investments		4		10
Restricted cash		18		22
Cash, cash equivalents and restricted cash	$	276	$	302

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

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

											Non-
	Common		Preferred		Contributed				Retained		Controlling		Total
millions of dollars	Stock		Stock		Surplus		AOCI		Earnings		Interest		Equity
For the three months ended March 31, 2024
Balance, December 31, 2023	$	8,462	$	1,422	$	82	$	305	$	1,803	$	14	$	12,088
Net income of Emera Incorporated		-		-		-		-		225		-		225
OCI, net of tax expense of $4 million		-		-		-		246		-		-		246
Dividends declared on preferred stock (1)		-		-		-		-		(18)		-		(18)
Dividends declared on common stock ($0.7175/share)		-		-		-		-		(204)		-		(204)
Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts		70		-		-		-		-		-		70
Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs		24		-		-		-		-		-		24
Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”)		9		-		-		-		-		-		9
Balance, March 31, 2024	$	8,565	$	1,422	$	82	$	551	$	1,806	$	14	$	12,440
For the three months ended March 31, 2023
Balance, December 31, 2022	$	7,762	$	1,422	$	81	$	578	$	1,584	$	14	$	11,441
Net income of Emera Incorporated		-		-		-		-		576		-		576
OCI, net of tax recovery of $4 million		-		-		-		(1)		-		-		(1)
Dividends declared on preferred stock (2)		-		-		-		-		(16)		-		(16)
Dividends declared on common stock ($0.6900/share)		-		-		-		-		(186)		-		(186)
Issued under the DRIP, net of discount		69		-		-		-		-		-		69
Senior management stock options exercised and ECSPP		8		-		-		-		-		-		8
Balance, March 31, 2023	$	7,839	$	1,422	$	81	$	577	$	1,958	$	14	$	11,891

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

(1) Series A; $0.1364/share, Series B; $0.4408/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; $0.1364/share, Series B; $0.3570/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

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at March 31, 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 March 31, 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;

• 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; and

• a 31.1 per cent equity interest in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion transmission project enabling transmission of energy from Muskrat Falls, an 824 megawatt (“MW”) hydroelectric generating facility developed by Nalcor Energy (“Nalcor”) on the Lower Churchill River in Labrador.

• 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;

• 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”) 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, unless otherwise indicated.

Use of Management Estimates

The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 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.

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 statement 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 is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.

3. 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 March 31, 2024
Operating revenues from external customers (1)	$	736	$	554	$	529	$	124	$	75	$	-	$	2,018
Inter-segment revenues (1)		2		-		3		-		15		(20)		-
Total operating revenues		738		554		532		124		90		(20)		2,018
Regulated fuel for generation and purchased power		189		260		-		65		-		(2)		512
Regulated cost of natural gas		-		-		180		-		-		-		180
OM&G		187		117		116		30		53		(3)		500
Provincial, state and municipal taxes		63		12		29		1		1		-		106
Depreciation and amortization		151		69		44		17		2		-		283
Income from equity investments		-		30		5		1		(2)		-		34
Other income (expense), net		15		7		2		4		(15)		15		28
Interest expense, net (2)		67		43		39		6		91		-		246
Income tax expense (recovery)		11		3		33		-		(19)		-		28
Preferred stock dividends		-		-		-		-		18		-		18
Net income (loss) attributable to common shareholders	$	85	$	87	$	98	$	10	$	(73)	$	-	$	207
As at March 31, 2024
Total assets	$	21,774	$	8,672	$	8,012	$	1,335	$	1,617	$	(1,379)	$	40,031
For the three months ended March 31, 2023
Operating revenues from external customers (1)	$	744	$	504	$	572	$	114	$	499	$	-	$	2,433
Inter-segment revenues (1)		2		-		3		-		37		(42)		-
Total operating revenues		746		504		575		114		536		(42)		2,433
Regulated fuel for generation and purchased power		197		224		-		57		-		(3)		475
Regulated cost of natural gas		-		-		276		-		-		-		276
OM&G		167		101		102		30		34		(4)		430
Provincial, state and municipal taxes		63		11		26		1		1		-		102
Depreciation and amortization		141		67		30		16		2		-		256

Income from equity investments		-		24		5		1		5		-		35
Other income (expenses), net		17		7		3		1		(28)		35		35
Interest expense, net (2)		67		44		25		6		84		-		226
Income tax expense (recovery)		21		(4)		30		-		115		-		162
Preferred stock dividends		-		-		-		-		16		-		16
Net income attributable to common shareholders	$	107	$	92	$	94	$	6	$	261	$	-	$	560
As at December 31, 2023
Total assets	$	21,119	$	8,634	$	7,735	$	1,311	$	1,938	$	(1,257)	$	39,480

(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 and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $7 million for the three months ended March 31, 2024, between the Gas Utilities and Infrastructure and Other segments (2023 – $17 million between Florida Electric Utility, Gas Utilities and Infrastructure and Other segments).

4. REVENUE

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

	Electric						Gas		Other
	Florida		Canadian		Other		Gas Utilities				Inter-
	Electric		Electric		Electric		and				Segment
millions of dollars	Utility		Utilities		Utilities		Infrastructure		Other		Eliminations		Total
For the three months ended March 31, 2024
Regulated Revenue:
Residential	$	409	$	329	$	44	$	268	$	-	$	-	$	1,050
Commercial		209		138		68		160		-		-		575
Industrial		54		67		7		24		-		(3)		149
Other electric		92		12		1		-		-		-		105
Regulatory deferrals		(31)		-		3		-		-		-		(28)
Other (1)		5		8		1		60		-		(2)		72
Finance income (2)(3)		-		-		-		15		-		-		15
Regulated revenue		738		554		124		527		-		(5)		1,938
Non-Regulated Revenue:
Marketing and trading margin (4)		-		-		-		-		80		-		80
Other non-regulated operating revenues		-		-		-		5		9		(6)		8
Mark-to-market (3)		-		-		-		-		1		(9)		(8)
Non-regulated revenue		-		-		-		5		90		(15)		80
Total operating revenues	$	738	$	554	$	124	$	532	$	90	$	(20)	$	2,018
For the three months ended March 31, 2023
Regulated Revenue:
Residential	$	439	$	293	$	40	$	314	$	-	$	-	$	1,086
Commercial		230		127		62		155		-		-		574
Industrial		63		64		8		25		-		(4)		156
Other electric		94		11		1		-		-		-		106
Regulatory deferrals		(85)		-		2		-		-		-		(83)
Other (1)		5		9		1		60		-		(2)		73
Finance income (2)(3)		-		-		-		16		-		-		16
Regulated revenue		746		504		114		570		-		(6)		1,928
Non-Regulated:
Marketing and trading margin (4)		-		-		-		-		95		-		95
Other non-regulated operating revenues		-		-		-		5		6		(3)		8
Mark-to-market (3)		-		-		-		-		435		(33)		402
Non-regulated revenue		-		-		-		5		536		(36)		505
Total operating revenues	$	746	$	504	$	114	$	575	$	536	$	(42)	$	2,433

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

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

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

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

Remaining Performance Obligations:

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts, and long-term steam supply arrangements with fixed contract terms. As of March 31, 2024, the aggregate

amount of the transaction price allocated to remaining performance obligations was $477 million (2023 – $471 million). This amount includes $133 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.

5. 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	March 31		December 31
millions of dollars	2024		2023
Regulatory assets
Deferred income tax regulatory assets	$	1,266	$	1,233
TEC capital cost recovery for early retired assets		697		671
NSPI FAM		429		395
Pension and post-retirement medical plan		372		364
Cost recovery clauses		71		151
Deferrals related to derivative instruments		58		88
Storm cost recovery clauses		43		52
Environmental remediations		26		26
Stranded cost recovery		26		25
Other (1)		99		100
	$	3,087	$	3,105
Current	$	232	$	339
Long-term		2,855		2,766
Total regulatory assets	$	3,087	$	3,105
Regulatory liabilities
Accumulated reserve – cost of removal	$	897	$	849
Deferred income tax regulatory liabilities		855		830
Cost recovery clauses		37		32
Deferrals related to derivative instruments		33		17
BLPC Self-insurance fund (“SIF”) (note 21)		30		29
Other (1)		19		15
	$	1,871	$	1,772
Current	$	186	$	168
Long-term		1,685		1,604
Total regulatory liabilities	$	1,871	$	1,772
(1) Comprised of regulatory assets and liabilities that are not individually significant.

Florida Electric Utility

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.

Fuel Recovery:

On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $137 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 voted to approve the mid-course adjustment.

Canadian Electric Utilities

NSPI

Storm Rider:

On April 30, 2024, NSPI applied to the Nova Scotia Utility and Review Board (“UARB”) for recovery of $22 million of major storm restoration expense deferred to NSPI’s UARB approved storm rider in 2023. If approved, recovery of the 2023 costs deferred in the storm rider would begin January 1, 2025 over the 12 months of 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 will result in a corresponding decrease of the FAM regulatory asset when recorded in Q2 2024. NSPI will collect the amortization and financing costs in related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period beginning in Q2 2024, and remit those amounts to Invest Nova Scotia as collected.

NSPML

On December 21, 2023, NSPML received approval 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 in Q1 2024.

Gas Utilities and Infrastructure

NMGC

Base Rates:

On September 14, 2023, NMGC filed a rate case with the New Mexico Public Regulation Commission (“NMPRC”) for new base rates to become effective in October 2024. 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 proposed 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 application for a certificate of public convenience and necessary for a liquified natural gas facility in New Mexico. The settlement is subject to NMPRC approval.

Other Electric Utilities

BLPC

Clean Energy Transition Rider (“CETR”):

On May 31, 2023, the Fair Trading Commission, Barbados (“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.

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 process is currently ongoing.

6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

	Carrying Value as at				Equity Income for the three months ended					Percentage of
	March 31		December 31		March 31					Ownership
millions of dollars	2024		2023		2024			2023		2024
LIL (1)	$	750	$	747	$	17		$	16		31.1
NSPML		483		489		13			8		100.0
M&NP (2)		119		118		5			5		12.9
Lucelec (2)		51		48		1			1		19.5
Bear Swamp (3)		-		-		(2	)		5		50.0
	$	1,403	$	1,402	$	34		$	35

(1) Emera indirectly owns 100 per cent of the LIL Class B units, which comprises 24.5 per cent of the total units issued. Percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments.

(2) 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.

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $86 million (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 21). NSPML’s consolidated summarized balance sheet is as follows:

As at	March 31		December 31
millions of dollars	2024		2023
Current assets	$	40	$	21
PP&E		1,460		1,473
Regulatory assets		277		272
Non-current assets		28		29
Total assets	$	1,805	$	1,795
Current liabilities	$	58	$	48
Long-term debt (1)		1,109		1,109
Non-current liabilities		155		149
Equity		483		489
Total liabilities and equity	$	1,805	$	1,795

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

7. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the	Three months ended March 31
millions of dollars	2024		2023
Interest on debt	$	253	$	230
Allowance for borrowed funds used during construction		(4)		(3)
Other		(3)		(1)
	$	246	$	226

8. INCOME TAXES

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

For the	Three months ended March 31
millions of dollars	2024		2023
Income before provision for income taxes		$  253		$  738
Statutory income tax rate		29.0%		29.0%
Income taxes, at statutory income tax rate		73		214
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(21)		(32)
Tax credits		(8)		(6)
Foreign tax rate variance		(7)		(8)
Amortization of deferred income tax regulatory liabilities		(6)		(6)
Tax effect of equity earnings		(4)		(3)
Other		1		3
Income tax expense		$  28		$  162
Effective income tax rate		11%		22%

On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024, and introduces new technology-neutral clean energy related tax credits beginning in 2025. As of March 31, 2024, the Company has recorded a $40 million (December 31, 2023 – $30 million) regulatory liability on the Consolidated Balance Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers.

9. 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)		0.50		24
Issued under the DRIP, net of discounts		1.54		70
Senior management stock options exercised and ECSPP		0.19		9
Balance, March 31, 2024		286.35	$	8,565

(1) In Q1 2024, a total of 498,553 common shares were issued under Emera’s ATM program at an average price of $48.43 per share for gross proceeds of $24 million ($24 million net of after-tax issuance costs). As at March 31, 2024, an aggregate gross sales limit of $176 million remained available for issuance under the ATM program.

10. EARNINGS PER SHARE

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

For the	Three months ended March 31
millions of dollars (except per share amounts)	2024		2023
Numerator
Net income attributable to common shareholders	$	207.2	$	560.4
Diluted numerator		207.2		560.4
Denominator
Weighted average shares of common stock outstanding – basic	$	285.1	$	270.7
Stock-based compensation		0.1		0.3
Weighted average shares of common stock outstanding – diluted	$	285.2	$	271.0
Earnings per common share
Basic	$	0.73	$	2.07
Diluted	$	0.73	$	2.07

11. 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 three months ended March 31, 2024
Balance, January 1, 2024		$  369		$  (24)		$  14		$  (2)		$  (52)		$  305
OCI before reclassifications		284		(39)		-		1		-		246
Amounts reclassified from AOCI		-		-		(1)		-		1		-
Net current period OCI		284		(39)		(1)		1		1		246
Balance, March 31, 2024		$  653		$  (63)		$  13		$  (1)		$  (51)		$  551
For the three months ended March 31, 2023
Balance, January 1, 2023		$  639		$  (62)		$  16		$  (2)		$  (13)		$  578
OCI before reclassifications		3		1		-		-		-		4
Amounts reclassified from AOCI		-		-		(1)		-		(4)		(5)
Net current period OCI		3		1		(1)		-		(4)		(1)
Balance, March 31, 2023		$  642		$  (61)		$  15		$  (2)		$  (17)		$  577

The reclassifications out of AOCI are as follows:

For the		Three months ended March 31
millions of dollars		2024		2023
	Affected line item in the Condensed Consolidated Financial Statements	Amounts reclassified from AOCI
Gains on derivatives recognized as cash flow hedges
Interest rate hedge	Interest expense, net		$  (1)		$  (1)
Net change in unrecognized pension and post-retirement benefit costs
Amounts reclassified into obligations	Pension and post-retirement benefits		1		(4)
Total reclassifications out of AOCI for the period			$    -		$  (5)

12. DERIVATIVE INSTRUMENTS

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

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

● foreign exchange (“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:

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

2. 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.

3. Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at 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.

4. Derivatives that do not meet any of the above criteria are designated as held-for-trading (“HFT”) derivatives and are recorded on the balance sheet at 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	March 31		December 31		March 31		December 31
millions of dollars	2024		2023		2024		2023
Regulatory deferral:
Commodity swaps and forwards	$	31	$	16	$	59	$	76
FX forwards		10		3		3		3
		41		19		62		79
HFT derivatives:
Power swaps and physical contracts		8		29		6		36
Natural gas swaps, futures, forwards, physical contracts		230		319		490		531
		238		348		496		567
Other derivatives:
Equity derivatives		-		4		3		-
FX forwards		21		18		13		7
		21		22		16		7
Total gross derivatives		300		389		574		653
Impact of master netting agreements:
Regulatory deferral		(7)		(3)		(7)		(3)
HFT derivatives		(106)		(146)		(106)		(146)
Total impact of master netting agreements		(113)		(149)		(113)		(149)
Total derivatives	$	187	$	240	$	461	$	504
Current (1)		125		174		370		386
Long-term (1)		62		66		91		118
Total derivatives	$	187	$	240	$	461	$	504

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

Cash Flow Hedges

On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. As of March 31, 2024, the unrealized gain in AOCI was $13 million, net of tax (December 31, 2023 – $14 million, net of tax). For the three months ended March 31, 2024, unrealized gains of $1 million (2023 – $1 million) 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 March 31				2024						2023
Unrealized gain (loss) in regulatory assets	$	8	$	-	$	-	$	(20)	$	-
Unrealized gain (loss) in regulatory liabilities		15		11		(4)		(67)		2
Realized (gain) loss in regulatory assets		(1)		-		-		4		-
Realized (gain) loss in regulatory liabilities		(1)		-		-		1		-
Realized (gain) loss in inventory (1)		4		(2)		-		1		(5)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		7		(2)		(39)		(27)		-
Other		-		-		-		(15)		-
Total change in derivative instruments	$	32	$	7	$	(43)	$	(123)	$	(3)

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

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

As at March 31, 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)		5		6
Commodity swaps and forwards purchases:
Natural gas (MMBtu)		12		16
Power (MWh)		1		1
Coal (metric tonnes)		1		-
FX swaps and forwards:
FX contracts (millions of USD)	$	210	$	117
Weighted average rate		1.3326		1.3302
% of USD requirements		74%		29%

HFT Derivatives

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

For the	Three months ended March 31
millions of dollars	2024		2023
Power swaps and physical contracts in non-regulated operating revenues	$	10	$	-
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		150		839
Total gains in net income	$	160	$	839

As at March 31, 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)		276		124		64		38		103
Natural gas sales (MMBtu)		347		146		32		9		10

Other Derivatives

As at March 31, 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 $527 million USD and expire in 2024 through 2025.

For the			Three months ended March 31
millions of dollars			2024				2023
	FX		Equity		FX		Equity
	forwards		derivatives		forwards		derivatives
Unrealized gain (loss) in OM&G	$	-	$	(8)	$	-	$	11
Unrealized gain (loss) in other income, net		(2)		-		6		-
Realized loss in other income, net		(1)		-		(3)		-
Total gains (losses) in net income	$	(3)	$	(8)	$	3	$	11

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 March 31, 2024, the Company had $149 million (December 31, 2023 – $142 million) in financial assets considered to be past due, which had been outstanding for an average 65 days. The FV of these financial assets was $134 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.

Cash Collateral

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

As at	March 31		December 31
millions of dollars	2024		2023
Cash collateral provided to others	$	100	$	101
Cash collateral received from others	$	10	$	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 March 31, 2024, the total FV of derivatives in a liability position was $461 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.

13. FV MEASUREMENTS

The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 12), and uses a market approach to do so. The three levels of the 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	March 31, 2024
millions of dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral:
Commodity swaps and forwards		$    9		$    15		$    -		$    24
FX forwards		-		10		-		10
		9		25		-		34
HFT derivatives:
Power swaps and physical contracts		1		5		1		7
Natural gas swaps, futures, forwards, physical contracts and related transportation		26		86		13		125
		27		91		14		132
Other derivatives:
FX forwards		-		21		-		21
Total assets		36		137		14		187
Liabilities
Regulatory deferral:
Commodity swaps and forwards		46		6		-		52
FX forwards		-		3		-		3
		46		9		-		55
HFT derivatives:
Power swaps and physical contracts		-		4		1		5
Natural gas swaps, futures, forwards and physical contracts		16		18		351		385
		16		22		352		390
Other derivatives:
FX forwards		-		13		-		13
Equity derivatives		3		-		-		3
		3		13		-		16

Total liabilities	65	44	352	461
Net assets (liabilities)	$  (29)	$  93	$  (338)	$  (274)

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 for the three months ended March 31, 2024 was as follows:

	HFT Derivatives
millions of dollars	Power		Natural gas		Total
Balance, beginning of period		$  -		$  34		$  34
Total realized and unrealized gains (losses) included in non-regulated operating revenues		1		(21)		(20)
Balance, March 31, 2024		$  1		$  13		$  14

The change in the FV of the Level 3 financial liabilities for the three months ended March 31, 2024 was as follows:

	HFT Derivatives
millions of dollars	Power		Natural gas		Total
Balance, beginning of period		$  -		$  365		$  365
Total realized and unrealized gains (losses) included in non-regulated operating revenues		1		(14)		(13)
Balance, March 31, 2024		$  1		$  351		$  352

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:

	March 31, 2024
As at millions of dollars	FV				Significant Unobservable Input		Low		High		Weighted Average (1)
	Assets		Liabilities
HFT derivatives – Power swaps and physical contracts		1		1		Third-party pricing	$	18.60	$	115.65	$	65.62
HFT derivatives – Natural gas swaps, futures, forwards and physical contracts		13		351		Third-party pricing	$	1.15	$	13.81	$	5.64
Total	$	14	$	352
Net liability			$	338

(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	Carrying
millions of dollars	Amount		FV		Level 1		Level 2		Level 3		Total
March 31, 2024	$	18,491	$	17,201	$	-	$	16,946	$	255	$	17,201
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 loss of $39 million was recorded in AOCI for the three months ended March 31, 2024 (2023 – $1 million gain after-tax).

14. RELATED PARTY TRANSACTIONS

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

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

● Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $42 million for the three months ended March 31, 2024 (2023 – $37 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.

● Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, non-regulated, totalled $4 million for the three months ended March 31, 2024 (2023 – $1 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2024 and at December 31, 2023.

15. RECEIVABLES AND OTHER CURRENT ASSETS

As at	March 31		December 31
millions of dollars	2024		2023
Customer accounts receivable – billed		$  770		$  805
Customer accounts receivable – unbilled		362		363
Capitalized transportation capacity (1)		402		358
Prepaid expenses		103		105
Income tax receivable		10		10
Allowance for credit losses		(15)		(15)
Other		199		191
Total receivables and other current assets		$  1,831		$  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.

16. 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:

For the	Three months ended March 31
millions of dollars	2024		2023
DB pension plans
Service cost	$	8	$	8
Non-service cost:
Interest cost		27		28
Expected return on plan assets		(39)		(40)
Current year amortization of regulatory asset		2		1
Total non-service costs		(10)		(11)
Total DB pension plans		(2)		(3)
Non-pension benefits plan
Service cost		1		-
Non-service cost:
Interest cost		3		3
Expected return on plan assets		(1)		-
Current year amortization of regulatory asset		(1)		(1)
Total non-service costs		1		2
Total non-pension benefits plans		2		2
Total DB pension plans	$	-	$	(1)

Emera’s contributions related to these DB pension plans for the three months ended March 31, 2024 were $12 million (2023 – $14 million). Annual employer cash contributions to the DB pension plans are estimated to be $34 million for 2024. Emera’s cash contributions related to these DC pension plans for the three months ended March 31, 2024 were $12 million (2023 – $11 million).

17. 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 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.

18. 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 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.

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 material changes in commercial terms from the prior agreement. This facility was classified as long-term debt at March 31, 2024.

19. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at March 31, 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)	$	592	$	561	$	435	$	413	$	364	$	2,728	$	5,093
Purchased power (2)		209		254		272		321		322		3,514		4,892
Capital projects		866		151		78		9		-		-		1,104
Fuel, gas supply and storage		394		239		61		10		5		-		709
Equity investment commitments (3)		240		-		-		-		-		-		240
Other		99		150		58		50		36		223		616
	$	2,400	$	1,355	$	904	$	803	$	727	$	6,465	$	12,654

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $133 million related to a gas transportation contract between PGS and SeaCoast through 2040.

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

(3) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining capital contributions over the life of the partnership. The commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation to the Maritime Link and LIL which is expected to be approximately $240 million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major maintenance.

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 for Nalcor, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.

B. Legal Proceedings

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). While the aggregate joint and several liability associated with these sites has not changed as a result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at March 31, 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 12 and note 13. There have been no material changes to the principal financial risks as of March 31, 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.

20. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the	Three months ended March 31
millions of dollars	2024		2023
Changes in non-cash working capital:
Inventory	$	55	$	33
Receivables and other current assets (1)		50		589
Accounts payable		(250)		(691)
Other current liabilities (2)		83		(132)
Total non-cash working capital	$	(62)	$	(201)

1) The three months ended March 31, 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 three months ended March 31, 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	Three months ended March 31
millions of dollars	2024		2023
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	70	$	69
Increase in accrued capital expenditures	$	30	$	29
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities	$	108	$	(170)

21. 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 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 assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.

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

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

As at	March 31, 2024				December 31, 2023
			Maximum				Maximum
millions of dollars	Total assets		exposure to loss		Total assets		exposure to loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)	$	483	$	6	$	489	$	6

22. 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 May 13, 2024, the date the unaudited condensed consolidated interim financial statements we re issued.