EX-99.1

EX-99.1 2 d71872dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

LOGO

Management’s Discussion & Analysis

As at May 8, 2025

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the “Company”) during the first quarter of 2025 relative to the same quarter in 2024; and its financial position as at March 31, 2025 relative to December 31, 2024. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.

This MD&A should be read in conjunction with the Emera unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2025; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2024. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR+ at www.sedarplus.ca.

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At March 31, 2025, Emera’s rate-regulated subsidiaries and investments include:


Rate-Regulated Subsidiary or Equity Investment		Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric Company (“TEC”)		Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. (“NSPI”)		Nova Scotia Energy Board (“NSEB”), formerly Nova Scotia Utility and Review Board (“UARB”)
Peoples Gas System, Inc. (“PGS”)		FPSC
New Mexico Gas Company, Inc. (“NMGC”)		New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC (“SeaCoast”)		FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)		Canadian Energy Regulator (“CER”)
Barbados Light & Power Company Limited (“BLPC”)		Fair Trading Commission, Barbados (“FTC”)
Grand Bahama Power Company Limited (“GBPC”)		The Grand Bahama Port Authority (“GBPA”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)		NSEB
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”)		CER and FERC
St. Lucia Electricity Services Limited (“Lucelec”)		National Utility Regulatory Commission
Wasoqonatl Transmission Incorporated (“WTI”)		NSEB

All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States dollars (“USD”) unless otherwise stated.

TABLE OF CONTENTS


Forward-looking Information			2
Introduction and Strategic Overview			3
Non-GAAP Financial Measures and Ratios			4
Consolidated Financial Review			5
Significant Items Affecting Earnings			5
Consolidated Financial Highlights			5
Consolidated Income Statement Highlights			7
Business Overview and Outlook			8
Florida Electric Utility			8
Canadian Electric Utilities			9
Gas Utilities and Infrastructure			10
Other Electric Utilities			10
Other			10
Consolidated Balance Sheet Highlights			11
Other Developments			12
Financial Highlights			13
Florida Electric Utility			13
Canadian Electric Utilities			13


Gas Utilities and Infrastructure			14
Other Electric Utilities			15
Other			16
Liquidity and Capital Resources			17
Consolidated Cash Flow Highlights			18
Contractual Obligations			19
Debt Management			20
Guarantees and Letters of Credit			20
Outstanding Stock Data			21
Transactions with Related Parties			21
Risk Management including Financial Instruments			22
Disclosure and Internal Controls			23
Critical Accounting Estimates			23
Changes in Accounting Policies and Practices			23
Future Accounting Pronouncements			23
Summary of Quarterly Results			24

FORWARD-LOOKING INFORMATION

This MD&A contains “forward-looking information” (“FLI”) and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, the expected timing and outcome of the pending sale of NMGC, the scope and impact of the cybersecurity incident and its expected impact on the Company’s financial condition or results of operations, business prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify FLI, although not all FLI contains these identifying words. The FLI reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.

FLI is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the FLI. Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political risk; change in law risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital markets risk; changes in credit ratings; future dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; potential impacts of trade disputes and impositions of tariffs; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; climate change risk; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology (“IT”) infrastructure and cybersecurity risks and incidents; uncertainties associated with infectious diseases, pandemics and similar public health threats; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any FLI as a result of new information, future events or otherwise.

INTRODUCTION AND STRATEGIC OVERVIEW

Emera (TSX: EMA) is a North American provider of energy services, owning and operating a portfolio of cost-of-service, rate-regulated electric and gas utilities. Its largest operations are in Florida, with additional operations in Atlantic Canada, New Mexico, and the Caribbean. Emera is headquartered in Halifax, Nova Scotia.

Emera’s business strategy is centred on continued investment in its regulated utilities, combined with a focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.6 million customers. Effective execution of these priorities supports predictable and growing earnings, cash flow and dividends for shareholders.

Earnings opportunities in regulated utilities are a function of the magnitude of net investment in the utility (known as “rate base”), the amount of equity in the capital structure, and the targeted return on that equity (“ROE”), all as established and approved through regulation. Earnings are also affected by sales volumes and operating expenses. In 2024, Emera’s regulated cost-of-service utilities in Florida accounted for 65 per cent of average consolidated rate base, with Atlantic Canada comprising 27 per cent, and the Caribbean and New Mexico at 4 per cent each.

Emera’s capital investment plan is forecasted to be approximately $20 billion from 2025 through 2029 and is focused on delivering value for customers through prudent investments in reliability and system resiliency, infrastructure modernization, expansion to address customer growth, integration of renewables, and technological innovations to deliver better customer experiences. It is anticipated that approximately 80 per cent of this capital investment will be made in Emera’s Florida utilities, necessitated by customer growth and system requirements at both TEC and PGS.


As at millions of dollars	2025		2026		2027		2028		2029		Total
Capital investment plan	$	3,420	$	3,990	$	4,050	$	4,380	$	4,590	$	20,430
Average consolidated rate base
US operations	$	21,520	$	23,340	$	25,140	$	27,050	$	29,400
Canadian operations		7,630		8,000		8,370		8,590		8,870
Total	$	29,150	$	31,340	$	33,510	$	35,640	$	38,270

*Capital investment plan and average consolidated rate base exclude NMGC. Refer to “Other Developments” for more information on the pending sale of NMGC

Emera’s capital investment plan will be funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity issuances, and proceeds from the anticipated sale of NMGC. Generally, Emera’s equity requirements are expected to be funded through the issuance of preferred equity, and the issuance of common equity through Emera’s dividend reinvestment plan (“DRIP”) and its at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a core strategic priority of the Company.

Emera has increased dividends per common share paid for 18 consecutive years and has provided forward annual dividend growth guidance of one to two per cent. Emera anticipates adjusted EPS average growth of five to seven per cent through 2027 which will support reduction in the ratio of dividend payout to adjusted net income. For further information on the non-GAAP ratios “Adjusted EPS” and “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.

NON-GAAP FINANCIAL MEASURES AND RATIOS

Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and are calculated by adjusting certain GAAP measures for specific items. They may not be comparable to similar measures presented by other entities. These measures and ratios are discussed and reconciled below.

Adjusted Net Income, Adjusted EPS – Basic and Dividend Payout Ratio of Adjusted Net Income

Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the effect of mark-to-market (“MTM”) adjustments from net income attributable to common shareholders. Management believes excluding from net income the effect of MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows, and therefore excludes MTM adjustments for evaluation of performance and incentive compensation.

The MTM adjustments are related to the following:

●

held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions;

●

the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income;

●

equity securities held in BLPC and Emera Energy; and

●

FX hedges entered into to hedge USD denominated operating unit earnings exposure.

Emera calculates adjusted net income for the Other Electric Utilities and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.

Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in the Company’s 2024 annual MD&A.

Reconciliation of Net Income Attributable to Common Shareholders to Adjusted Net Income:


For the	Three months ended March 31
millions of dollars (except per share amounts)	2025		2024
Net income attributable to common shareholders	$	583	$	207
MTM gain (loss), after-tax (1)		204		(9)
Adjusted net income	$	379	$	216
EPS – basic	$	1.96	$	0.73
Adjusted EPS – basic	$	1.28	$	0.76

(1) Net of income tax expense of $84 million for the three months ended March 31, 2025 (2024 – $4 million recovery).

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA are non-GAAP financial measures used by Emera. These financial measures are used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital, and finance working capital requirements. Adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA:


For the	Three months ended March 31
millions of dollars	2025		2024
Net income (1)	$	601	$	225
Interest expense, net		255		246
Income tax expense		119		28
Depreciation and amortization		319		283
EBITDA	$	1,294	$	782
MTM gain (loss), excluding income tax		288		(13)
Adjusted EBITDA	$	1,006	$	795

(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Earnings Impact of MTM Gain (Loss), After-Tax

The Q1 2024 MTM loss, after-tax, of $9 million decreased $213 million to a MTM gain, after-tax of $204 million in Q1 2025 due to changes in existing positions and lower amortization of gas transportation assets at Emera Energy Services (“EES”).

Consolidated Financial Highlights


For the	Three months ended March 31
millions of dollars	2025		2024
Adjusted Net Income
Florida Electric Utility	$	164	$	85
Canadian Electric Utilities		121		87
Gas Utilities and Infrastructure		120		98
Other Electric Utilities		-		9
Other		(26)		(63)
Adjusted net income	$	379	$	216
MTM gain (loss), after-tax		204		(9)
Net income attributable to common shareholders	$	583	$	207

The following table highlights significant changes in adjusted net income from 2024 to 2025.


For the	Three months ended
millions of dollars	March 31
Adjusted net income – 2024		$ 216
Operating Unit Performance
Increased earnings at TEC primarily due to higher revenue from new base rates and the impact of a weaker CAD		79
Increased earnings at NSPI due to investment tax credits (“ITCs”) related to clean technology investments and increased sales volumes primarily driven by favourable weather		53
Increased earnings at EES due to favourable weather conditions that led to higher natural gas prices and increased volatility		24
Increased earnings at NMGC due to higher revenue from new base rates and the impact of a weaker CAD		19
Decreased income from equity investments due to the sale of Emera’s indirect minority interest in the Labrador Island Link (“sale of LIL”) in Q2 2024		(17)
Corporate
Decreased operating, maintenance and general expenses (“OM&G”) primarily due to the timing difference in the valuation of long-term incentive expense and related hedges in 2024		18
Other Variances		(13)
Adjusted net income – 2025		$ 379

For further details of reportable segment contributions, refer to the “Financial Highlights” section.


For the	Three months ended March 31
millions of dollars	2025		2024
Operating cash flow before changes in working capital	$	733	$	631
Change in working capital		(34)		(62)
Operating cash flow	$	699	$	569
Investing cash flow	$	(708)	$	(604)
Financing cash flow	$	123	$	(288)
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
As at	March 31		December 31
millions of dollars	2025		2024
Total assets	$	43,617	$	42,951
Total long-term debt (including current portion) (1)	$	19,370	$	18,407

(1) Excludes NMGC balances classified as held for sale as at March 31, 2025. For further details refer to the “Other Developments” section and Note 3 in the condensed consolidated interim financial statements.

Consolidated Income Statement Highlights


For the	Three months ended March 31
millions of dollars (except per share amounts)	2025		2024		Variance
Operating revenues	$	2,676	$	2,018	$	658
Operating expenses		1,751		1,581		(170)
Income from operations	$	925	$	437	$	488
Income tax expense	$	119	$	28	$	(91)
Net income attributable to common shareholders	$	583	$	207	$	376
Adjusted net income	$	379	$	216	$	163
Weighted average shares of common stock outstanding (in millions)		297.0		285.1		11.9
EPS – basic	$	1.96	$	0.73	$	1.23
EPS – diluted	$	1.96	$	0.73	$	1.23
Adjusted EPS – basic	$	1.28	$	0.76	$	0.52
Dividends per common share declared	$	0.7250	$	0.7175	$	0.0075
Adjusted EBITDA	$	1,006	$	795	$	211

Operating Revenues

For Q1 2025, operating revenues increased $658 million compared to Q1 2024 and, excluding the change in MTM impacts, increased $368 million. The increase was due to the impact of a weaker CAD; new base rates at TEC and NMGC; increased marketing and trading margin at EES; higher fuel clause recovery at TEC; increased sales volumes primarily driven by favourable weather at NSPI and TEC; and higher storm cost recoveries at TEC and NSPI (offset in OM&G).

Operating Expenses

For Q1 2025, operating expenses increased $170 million compared to Q1 2024. This increase was due to the impact of a weaker CAD; higher natural gas prices at TEC, PGS and NMGC; higher fuel expense at NSPI; higher depreciation at TEC; and higher OM&G at TEC and NSPI due to higher storm cost recognition (offset in revenues). This was partially offset by lower OM&G at Corporate due to the timing difference in the valuation of long-term incentive expense and related hedges in 2024.

Income Tax Expense

For Q1 2025, income tax expense increased $91 million compared to Q1 2024 due to increased income before provision for income taxes, partially offset by increased ITCs related to clean technology investments at NSPI and increased production tax credits related to solar facilities at TEC.

Net Income and Adjusted Net Income

For Q1 2025, the increase in net income attributable to common shareholders, compared to Q1 2024, was favourably impacted by the $213 million decrease in MTM losses, after-tax. Excluding this change, adjusted net income increased $163 million, primarily due to increased earnings at TEC, NSPI, EES and NMGC; the impact of a weaker CAD; and decreased Corporate OM&G. This was partially offset by decreased income from equity investments due to the sale of LIL.

Earnings and Adjusted EPS – Basic

Earnings and Adjusted EPS – basic were higher for Q1 2025 compared to Q1 2024 due to increased earnings, as discussed above, partially offset by an increase in weighted average shares outstanding.

Effect of Foreign Currency Translation

Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2024 annual MD&A.

The relevant CAD/USD exchange rates for 2025 and 2024 are as follows:


	Three months ended March 31				Year ended December 31
	2025		2024		2024
Weighted average CAD/USD	$	1.44	$	1.35	$	1.36
Period end CAD/USD exchange rate	$	1.44	$	1.36	$	1.44
The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:
For the			Three months ended March 31
millions of USD			2025		2024
Florida Electric Utility			$	114	$	63
Gas Utilities and Infrastructure (1)				79		69
Other Electric Utilities				-		7
Other segment (2)				5		-
Total (3)			$	198	$	139

(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.

(2) Includes Emera Energy’s USD adjusted net income from EES and Bear Swamp, and interest expense on Emera Inc.’s USD denominated debt.

(3) Excludes a $143 million USD MTM gain, after-tax, for the three months ended March 31, 2025 (2024 – $1 million USD MTM loss, after-tax).

Weakening of the CAD increased adjusted net income by $14 million and increased net income attributable to common shareholders by $30 million in Q1 2025 compared to the same period in 2024. Impacts of the changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of USD earnings in the Other segment.

BUSINESS OVERVIEW AND OUTLOOK

There have been no material changes in Emera’s business overview and outlook from the Company’s 2024 annual MD&A, except for the updates disclosed below. The extent of the future impact of trade disputes and the imposition of tariffs on the Company’s financial results and business operations continues to evolve, cannot be predicted at this time and will depend on future developments. To date, there has been no material financial impact on the Company. For information on risks associated with trade disputes and the imposition of tariffs, refer to the “Enterprise Risk and Risk Management” section in Emera’s 2024 annual MD&A.

Florida Electric Utility

TEC anticipates earning within the upper half of its ROE range in 2025. As a result of new base rates effective January 1, 2025, TEC’s 2025 USD earnings are expected to be higher than in 2024. TEC expects customer growth rates in 2025 to be comparable to 2024, reflective of the expected economic growth in Florida.

On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. For additional details on the rate case decision, refer to note 7 in Emera’s 2024 annual audited consolidated financial statements. In February 2025, a motion for reconsideration on certain aspects of the final order was filed by an intervening party with the FPSC. On May 6, 2025, the FPSC denied the motion for reconsideration, except with respect to immaterial calculation corrections. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. As of May 8, 2025, the intervening parties have not filed their briefs related to the appeal.

On February 4, 2025, the FPSC approved TEC’s petition for the recovery of $466 million USD of costs associated with Hurricane Idalia, Hurricane Debby, Hurricane Helene and Hurricane Milton, and the associated interest to replenish the storm reserve over an 18-month recovery period beginning in March 2025. The amount of cost-recovery is subject to a true-up mechanism with the FPSC. For additional details on the storm reserve, refer to note 7 in Emera’s annual audited consolidated financial statements.

In 2025, capital investment in the Florida Electric Utility segment is expected to be $1.7 billion USD (2024 – $1.4 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, grid modernization, storm hardening investments and building resilience.

Canadian Electric Utilities

NSPI

NSPI anticipates earning below its allowed ROE range in 2025. NSPI expects earnings in 2025 to be higher than 2024. Sales volumes are expected to be higher in 2025 than 2024.

On March 5, 2025, NSPI, the Canada Infrastructure Bank (“CIB”) and the Wskijinu’k Mtmo’taqnuow Agency (“WMA”) announced the Wasoqonatl transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. The project will be owned by a new regulated utility, WTI, which is wholly-owned by a newly formed limited partnership between NSPI, CIB and WMA. NSPI will be responsible for providing construction, operation, maintenance and administrative services to WTI. NSPI has a 50 per cent indirect voting interest in WTI and will be recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets. As of March 31, 2025, NSPI’s investment is nominal.

In 2025, capital investment, including AFUDC, is expected to be $680 million (2024 – $487 million). NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.

NSPML

Equity earnings from NSPML in 2025 are expected to be consistent with 2024. The NSPML investment is recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.

On November 29, 2024, NSPML received approval from the NSEB to collect up to $197 million in 2025 from NSPI. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no holdback recorded in Q1 2025. NSPML expects to file an application to terminate the holdback mechanism in 2025.

NSPML does not anticipate any significant capital investment in 2025.

Gas Utilities and Infrastructure

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in Q4 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 as of Q3 2024. For more information on the pending transaction, refer to the “Other Developments” section.

PGS

PGS anticipates earning at the bottom of its allowed ROE range in 2025. USD earnings for 2025 are expected to be consistent with 2024 primarily due to higher operating costs and depreciation driven by ongoing capital investments to support customer demand and system needs.

On March 31, 2025, PGS filed a rate case with the FPSC for new rates to become effective January 2026. PGS requested a $104 million USD increase in annual base rates and an additional adjustment of $27 million USD for 2027. The request for 2026 includes $7 million USD from the cast iron and bare steel replacement rider. The proposed rates include recovery of investments in the gas system to meet the needs of a growing customer base and to improve reliability, resiliency, and efficiency. The hearing with the FPSC is scheduled for Q3 2025 with a decision expected by the end of 2025.

In 2025, capital investment, including AFUDC, is expected to be approximately $360 million USD (2024 – $323 million USD). PGS will make investments to maintain the reliability of their systems and support customer growth.

NMGC

NMGC’s USD earnings contributions to Emera in 2025 are expected to be lower than in 2024 as a result of the pending sale of NMGC that is currently expected to close in Q4 2025.

Other Electric Utilities

Other Electric Utilities’ USD earnings in 2025 are expected to be consistent with the prior year.

In 2025, capital investment in the Other Electric Utilities segment is expected to be approximately $140 million USD, including AFUDC (2024 – $59 million USD), primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

GBPC

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 (URCA), another Bahamian regulator, regulate GBPC. URCA filed a claim in the Supreme Court of the Bahamas, seeking an order that the GBPA be prohibited and restrained from considering and/or approving any adjustment to rates sought by GBPC. URCA contends that it has regulatory authority over electricity provision on Grand Bahama pursuant to the Electricity Act. Management does not foresee that the outcome of the proceedings will have a material impact to Emera.

Other

The adjusted net loss from the Other segment is expected to be lower in 2025 than 2024, due to higher contributions from EES and the wind down of Block Energy LLC in Q4 2024.

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income of $15 to $30 million USD. In light of very strong performance in Q1, EES expects adjusted net income between $35 and $45 million USD in 2025.

The Other segment does not anticipate any significant capital investment in 2025.

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2024 and March 31, 2025 include:


millions of dollars	Increase (Decrease)		Explanation
Assets
Cash and cash equivalents		$ 112	Increased due to cash from operations, partially offset by investment in property, plant and equipment (“PP&E”), net repayments under committed credit facilities at Corporate and PGS, and dividends paid on Emera common stock
Derivative instruments (current and long-term)		84	Increase due to new contracts at EES
Receivables and other assets (current and long-term)		118	Increased due to seasonal trends of the business and higher income tax receivable due to clean technology ITCs at NSPI, increased gas transportation assets at EES, and increased accounts receivable at PGS, partially offset by decreased cash collateral positions on derivative instruments at EES
Assets held for sale (current and long-term), net of liabilities (1)		52	Increased primarily due to lower accounts payable reflecting seasonal trends of the business and repayments under committed credit facilities at NMGC
PP&E, net of accumulated depreciation and amortization		452	Increased due to capital additions in excess of depreciation
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		$ 276	Increased due to issuance of long-term debt at TEC, higher proceeds from committed credit facilities at NSPI and TECO Finance, Inc., partially offset by repayment of committed credit facilities at TEC, Emera and PGS
Deferred income tax liabilities, net of deferred income tax assets		168	Increased due to tax deductions in excess of accounting depreciation related to PP&E
Derivative instruments (current and long-term)		(193)	Decreased due to changes in existing positions, partially offset by new contracts at EES
Regulatory liabilities (current and long-term)		(79)	Decreased primarily due to lower fuel adjustment mechanism (“FAM”) liability balance at NSPI
Other liabilities (current and long-term)		192	Increased due to timing of interest payments at Corporate, TEC and PGS
Common stock		98	Increased due to shares issued
Retained earnings		368	Increased due to net income in excess of dividends paid

(1) On August 5, 2024, Emera announced the sale of NMGC. As at March 31, 2025, NMGC’s assets and liabilities were classified as held for sale. For further details, refer to the ‘Other Developments’ section and note 3 in the condensed consolidated interim financial statements.

OTHER DEVELOPMENTS

Cybersecurity Incident

On April 25, 2025, Emera and NSPI discovered a cybersecurity incident (the “Cybersecurity Incident”) involving unauthorized access into certain parts of its Canadian network and servers supporting portions of its business applications. Immediately following detection of the external threat, incident response and business continuity protocols were activated, including the engagement of leading third-party cybersecurity experts. Actions have been taken to contain and isolate the affected servers and prevent further intrusion and to notify law enforcement in Canada and the United States (“US”). There remains no disruption to any of our Canadian physical operations, including at NSPI’s generation, transmission and distribution facilities, the Maritime Link, or the Brunswick Pipeline. There has been no impact to Emera’s US or Caribbean utilities’ operations. The investigation and assessment of the financial and other impacts of the Cybersecurity Incident is ongoing. At this time, the Cybersecurity Incident is not expected to have a material impact on the Company’s financial condition or results of operations.

New York Stock Exchange (“NYSE”) Listing

On May 1, 2025, Emera filed a registration statement on Form 40-FR with the Securities Exchange Commission to register its common shares under the Securities and Exchange Act of 1934, in connection with Emera’s planned listing of its common shares on the NYSE.

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 Q4 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, in Q3 2024 NMGC’s assets and liabilities were classified as held for sale and the carrying value of the assets and liabilities were adjusted to fair value (“FV”) less cost to sell. There were no impairment or FV less costs to sell adjustments recorded in Q1 2025. The Company will continue to assess FV less costs to sell during the close period, and does not anticipate any significant adjustments through to the close of the transaction.

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 $44 million ($31 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through March 31, 2025. Of the $44 million ($31 million USD) recorded to date, $26 million ($19 million USD) was recorded in 2024.

FINANCIAL HIGHLIGHTS

Florida Electric Utility


For the	Three months ended March 31
millions of USD (except as indicated)	2025		2024
Operating revenues – regulated electric	$	649	$	548
Regulated fuel for generation and purchased power	$	161	$	141
Contribution to consolidated net income	$	114	$	63
Contribution to consolidated net income – CAD	$	164	$	85
Electric sales volumes (Gigawatt hours (“GWh”))		4,636		4,350
Electric production volumes (GWh)		4,636		4,471
Average fuel cost in dollars per megawatt hour (“MWh”)	$	35	$	32

The impact of the change in the FX rate increased CAD earnings for the three months ended March 31, 2025 by $10 million.

Highlights of the net income changes are summarized in the following table:


For the millions of USD	Three months ended March 31
Contribution to consolidated net income – 2024	$	63
Increased operating revenues primarily due to new base rates, the impact of favourable weather of $5 million, customer growth and higher regulatory deferral revenue and storm cost recovery revenue (offset in OM&G)		101
Increased fuel for generation and purchased power due to higher natural gas prices		(20)
Increased OM&G due to higher storm cost recognition (offset in revenue), partially offset by timing of deferred clause recoveries		(9)
Increased depreciation and amortization due to facilities and generation projects placed in service		(10)
Increased income tax expense primarily due to higher income before provision for income taxes, partially offset by higher benefit from production tax credits related to solar facilities		(10)
Other		(1)
Contribution to consolidated net income – 2025	$	114

Canadian Electric Utilities


For the	Three months ended March 31
millions of dollars (except as indicated)	2025		2024
Operating revenues – regulated electric	$	599	$	554
Regulated fuel for generation and purchased power (1)	$	359	$	290
Contribution to consolidated net income	$	121	$	87
Electric sales volumes (GWh)		3,333		3,183
Electric production volumes (GWh)		3,589		3,433
Average fuel costs in dollars per MWh	$	100	$	84

(1) Regulated fuel for generation and purchased power includes NSPI’s FAM deferral on the Condensed Consolidated Statements of Income; however, it is excluded in the segment overview.

Canadian Electric Utilities’ contribution to consolidated net income is summarized in the following table:


For the	Three months ended March 31
millions of dollars	2025		2024
NSPI	$	110	$	57
Equity investment in NSPML		11		13
Equity investment in LIL (1)		-		17
Contribution to consolidated net income	$	121	$	87

(1) On June 4, 2024, Emera completed the sale of LIL. For further details, refer to “Other Developments” in Emera’s 2024 annual MD&A

Highlights of the net income changes are summarized in the following table:


For the millions of dollars	Three months ended March 31
Contribution to consolidated net income – 2024		$ 87
Increased operating revenues due to higher sales volumes primarily driven by favourable weather, higher storm cost recoveries, and higher fuel cost recoveries		45
Increased regulated fuel for generation and purchased power primarily due to changes in generation mix, and increased sales volumes		(69)
Decreased FAM deferral primarily due to under-recovery of fuel costs		49
Decreased income from equity investments due to the sale of LIL		(17)
Decreased income tax expense at NSPI due to ITCs related to clean technology investments in the current year		33
Other		(7)
Contribution to consolidated net income – 2025		$ 121

Gas Utilities and Infrastructure

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in Q4 2025, subject to certain approvals, including regulatory approval by the NMPRC. For more information on the pending transaction, refer to the “Other Developments” section.


For the millions of USD (except as indicated)	Three months ended March 31
For the millions of USD (except as indicated)	2025		2024
Operating revenues – regulated gas (1)		$ 425		$ 391
Operating revenues – non-regulated		4		4
Total operating revenue		$ 429		$ 395
Regulated cost of natural gas		$ 153		$ 134
Contribution to consolidated net income		$ 83		$ 73
Contribution to consolidated net income – CAD		$ 120		$ 98
Gas sales volumes (millions of Therms)		857		910

(1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline for the three months ended March 31, 2025 (2024 – $11 million).

Gas Utilities and Infrastructure’s contribution to consolidated net income is summarized in the following table:


For the	Three months ended March 31
millions of USD	2025		2024
PGS		$ 40		$ 42
NMGC		34		22
Other		9		9
Contribution to consolidated net income		$ 83		$ 73

The impact of the change in the FX rate increased CAD earnings for the three months ended March 31, 2025, by $7 million.

Highlights of the net income changes are summarized in the following table:


For the millions of USD	Three months ended March 31
Contribution to consolidated net income – 2024		$ 73
Increased gas revenues due to higher fuel revenue and off-system sales at PGS and new base rates at NMGC		34
Increased cost of natural gas due to higher natural gas prices at PGS		(19)
Increased income tax expense primarily due to higher taxable income at NMGC		(4)
Other		(1)
Contribution to consolidated net income – 2025		$ 83

Other Electric Utilities.


For the	Three months ended March 31
millions of USD (except as indicated)	2025		2024
Operating revenues – regulated electric		$ 92		$ 92
Regulated fuel for generation and purchased power		$ 47		$ 48
Contribution to consolidated adjusted net income		$ -		$ 7
Contribution to consolidated adjusted net income – CAD		$ -		$ 9
Equity securities MTM gain		$ -		$ 1
Contribution to consolidated net income		$ -		$ 7
Contribution to consolidated net income – CAD		$ -		$ 10
Electric sales volumes (GWh)		303		305
Electric production volumes (GWh)		322		327
Average fuel costs in dollars per MWh		146		147

Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:


For the	Three months ended March 31
millions of USD	2025		2024
BLPC		$ 2		$ 5
GBPC		(2)		2
Contribution to consolidated adjusted net income		$ -		$ 7

The impact on Q1 2025 earnings related to the change in the FX rate was minimal.

Highlights of the net income changes are summarized in the following table:


For the millions of USD	Three months ended March 31
Contribution to consolidated net income – 2024		$ 7
Increased OM&G due to higher generation maintenance costs at BLPC and GBPC		(3)
Increased income tax expense due to the remeasurement of deferred income tax liabilities as a result of a corporate income tax rate change at BLPC		(2)
Other		(2)
Contribution to consolidated net income – 2025		$ -

Other


For the		Three months ended March 31
millions of dollars	2025		2024
Marketing and trading margin (1) (2)		$ 120		$ 80
Other non-regulated operating revenue		9		9
Total operating revenues – non-regulated		$ 129		$ 89
Contribution to consolidated adjusted net (loss) income		$ (26)		$ (63)
MTM gain (loss), after-tax (3)		204		(10)
Contribution to consolidated net income (loss)		$ 178		$ (73)

(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs, and energy asset management services’ revenues.

(2) Marketing and trading margin excludes a pre-tax MTM gain of $288 million for the three months ended March 31, 2025 (2024 – $1 million gain).

(3) Net of income tax expense of $84 million for the three months ended March 31, 2025 (2024 – $4 million recovery).

Other’s contribution to consolidated adjusted net (loss) income is summarized in the following table:


For the		Three months ended March 31
millions of dollars	2025		2024
Emera Energy
EES		$ 69		$ 45
Other		(1)		1
Corporate – see breakdown of adjusted contribution below		(94)		(103)
Block Energy LLC		-		(6)
Contribution to consolidated adjusted net (loss) income		$ (26)		$ (63)

Highlights of the net income changes are summarized in the following table:


For the millions of dollars	Three months ended March 31
Contribution to consolidated net income – 2024		$ (73)
Increased marketing and trading margin due to favourable weather conditions that led to higher natural gas prices and increased volatility that created profitable opportunities		40
Decreased OM&G primarily due to the timing difference in the valuation of long-term incentive expense and related hedges in 2024		18
Increased interest expense primarily due to increased total debt and the impact of a weaker CAD on USD denominated debt		(5)
Decreased income tax recovery due to decreased loss before provision for income taxes, partially offset by decreased deferred income tax asset valuation allowance due to the utilization of tax loss carryforwards		(9)
Decreased MTM loss, after-tax, primarily due to changes in existing positions and lower amortization of gas transportation assets at EES		214
Other		(7)
Contribution to consolidated net income – 2025		$ 178

Corporate

Corporate’s adjusted loss is summarized in the following table:


For the	Three months ended March 31
millions of dollars	2025		2024
Operating expenses (1)		$ (7)		$ (25)
Interest expense		(96)		(91)
Income tax recovery		34		33
Preferred dividends		(18)		(18)
Other (2)(3)		(7)		(2)
Corporate adjusted net (loss) income (4)		$ (94)		$ (103)

(1) Operating expenses include OM&G and depreciation.

(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings exposure.

(3) Includes a realized, pre-tax, net loss of $8 million on FX hedges for the three months ended March 31, 2025 ($5 million after-tax), as discussed above (2024 – $1 million net loss, pre-tax and $1 million loss, after-tax).

(4) Excludes a MTM gain, after-tax, of $3 million for the three months ended March 31, 2025 (2024 – $2 million loss, after-tax).

LIQUIDITY AND CAPITAL RESOURCES

The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include changes to global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity price changes on collateral requirements and timely recoveries of fuel and storm costs from customers, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and that they maintain their credit metrics.

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has an approximate $20 billion capital investment plan over the 2025 through 2029 period and supports ongoing growth. Capital investments at Emera’s regulated utilities are subject to regulatory approval.

Emera has sufficient liquidity to service debt obligations as they come due to meet any near-term capital investment requirements as currently planned. Emera plans to use cash from operations, debt raised at the utilities, Corporate equity, and proceeds from the pending sale of NMGC to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Generally, Corporate equity requirements in support of the Company’s capital investment plan are expected to be funded through issuance of preferred equity and issuance of common equity through Emera’s DRIP and ATM programs.

Emera has total committed credit facilities with varying maturities that cumulatively provide $2.3 billion CAD and $1.6 billion USD of credit, with approximately $1.0 billion CAD and $1.1 billion USD undrawn and available at March 31, 2025. The Company was holding a cash balance of $317 million, which includes $9 million classified as assets held for sale, related to the pending sale of NMGC, at March 31, 2025. For further discussion, refer to the “Debt Management” section below.

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 2025 and 2024 include:


millions of dollars	2025		2024		Change
Cash, cash equivalents, restricted cash, and cash associated with assets held for sale, beginning of period	$	221	$	588	$	(367)
Provided by (used in):
Operating cash flow before changes in working capital		733		631		102
Change in working capital		(34)		(62)		28
Operating activities	$	699	$	569	$	130
Investing activities		(708)		(604)		(104)
Financing activities		123		(288)		411
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale		-		11		(11)
Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period	$	335	$	276	$	59

Cash Flow from Operating Activities

Net cash provided by operating activities increased $130 million to $699 million for the three months ended March 31, 2025, compared to $569 million for the same period in 2024.

Cash from operations before changes in working capital increased $102 million year-over-year. This increase was due to new base rates at TEC and NMGC, higher marketing and trading margin at EES, increased sales volumes at NSPI primarily as a result of favourable weather, and higher fuel over-recoveries at PGS. These were partially offset higher fuel under-recoveries at TEC, increased fuel costs at NSPI and higher interest on long-term debt at Corporate.

Changes in working capital increased operating cash flows by $28 million year-over-year. This increase was due to favourable changes in cash collateral positions and timing of settlements at EES, and timing of accounts receivable at NSPI. These were partially offset by unfavourable changes in accounts receivable at TEC due to increased base rates and storm cost recoveries, and unfavourable changes in fuel inventory at NSPI.

Cash Flow from Investing Activities

Net cash used in investing activities increased $104 million to $708 million for the three months ended March 31, 2025, compared to $604 million for the same period in 2024. The increase was due to higher capital investment.

Capital investments, including AFUDC, for the three months ended March 31, 2025, were $742 million, compared to $610 million for the same period in 2024. Details of the 2025 capital investment by segment are shown below:

•

$459 million – Florida Electric Utility (2024 – $368 million);

•

$122 million – Canadian Electric Utilities (2024 – $112 million);

•

$143 million – Gas Utilities and Infrastructure (2024 – $116 million); and

•

$18 million – Other Electric Utilities (2024 – $14 million).

Cash Flow from Financing Activities

Net cash provided by financing activities increased $411 million to $123 million for the three months ended March 31, 2025, compared to cash used in financing activities of $288 million for the same period in 2024. This increase was due to higher net borrowings on committed credit facilities at NSPI, lower net repayments under committed credit facilities at TEC, and higher long-term debt issuances at TEC. These were partially offset by higher short-term debt repayments at Emera and higher net repayments under committed credit facilities at Emera and PGS.

Contractual Obligations

As at March 31, 2025, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:


millions of dollars	2025		2026		2027		2028		2029		Thereafter		Total
Long-term debt principal (1)	$	197	$	3,279	$	123	$	653	$	1,848	$	14,108	$	20,208
Interest payment obligations (2)(3)		845		882		791		784		711		8,975		12,988
Transportation (4)(5)		652		622		568		475		425		3,589		6,331
Purchased power (6)		320		287		379		378		379		4,544		6,287
Fuel, gas supply and storage (7)		697		180		82		37		35		88		1,119
Capital projects		528		278		22		4		1		-		833
Pension and post-retirement obligations (8)		24		32		69		73		73		224		495
Asset retirement obligations		10		2		2		4		3		429		450
Other		118		87		71		47		45		260		628
	$	3,391	$	5,649	$	2,107	$	2,455	$	3,520	$	32,217	$	49,339

As detailed below, contractual obligations at March 31, 2025 includes those related to NMGC. On completion of the sale of NMGC, all of the remaining future contractual obligations will be transferred to the buyer. For further details on the pending transaction, refer to the “Other Developments” section.

(1) Includes $696 million related to NMGC (2026: $100 million and $596 million thereafter) and $1.2 billion USD of hybrid debt in Emera Inc. that matures in June 2026.

(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2025, including any expected required payment under associated swap agreements.

(3) Includes $346 million related to NMGC (2025: $20 million, 2026: $26 million, 2027: $23 million, 2028: $23 million, 2029: $23 million and $231 million thereafter).

(4) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $132 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(5) Includes $71 million related to NMGC (2025: $16 million, 2026: $24 million, 2027: $16 million, and 2028: $12 million and 2029: $3 million).

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

(7) Includes $108 million related to NMGC (2025: $38 million, 2026: $54 million, 2027: $13 million, and 2028: $3 million).

(8) Includes the estimated contractual obligation, which is calculated as the current legislatively required contributions to the registered funded pension plans, plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.

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 November 2024, the NSEB approved the collection of up to $197 million from NSPI for the recovery of Maritime Link costs in 2025. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to NSEB approval.

Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Newfoundland and Labrador Hydro’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.

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to unsecured committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD, per the table below as at March 31, 2025.


millions of dollars in currency as noted below	Maturity		Credit Facilities		Utilized		Undrawn and Available
In CAD:
Emera – committed revolving credit facility		June 2029	$	1,300	$	502	$	798
NSPI – committed revolving credit facility		June 2029		800		562		238
Emera – non-revolving facility		February 2026		200		200		-
In USD:
TEC – committed revolving credit facility		December 2028		800		159		641
TECO Finance, Inc. – committed revolving credit facility		December 2028		400		256		144
PGS – revolving facility		December 2028		250		72		178
NMGC – revolving credit facility		December 2026		125		16		109
Other – committed revolving credit facilities		Various		21		10		11

Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at March 31, 2025.

Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:

Florida Electric Utility

On March 6, 2025, TEC issued $600 million USD of senior unsecured notes that bear interest at 5.15 per cent with a maturity date of March 1, 2035. Proceeds from this issuance were used for the repayment of a portion of TEC’s outstanding commercial paper.

Other

On February 20, 2025, Emera amended its $200 million unsecured non-revolving facility to extend the maturity date from February 19, 2025 to February 19, 2026. There were no other material changes to the terms from the prior agreement.

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2024 annual MD&A, with material updates as noted below:

Emera, on behalf of Brunswick Pipeline, issued a standby letter of credit for $22 million to secure obligations under a non-revolving loan agreement. This standby letter of credit has a one-year term, expiring on March 31, 2026, and will be renewed annually, as required.

Outstanding Stock Data

Common Stock


Issued and outstanding:	millions of shares		millions of dollars
Balance, December 31, 2024		295.94	$	9,042
Issuance of common stock under ATM program (1)		0.19		10
Issued under the DRIP, net of discounts		1.39		76
Senior management stock options exercised and Employee Share Purchase Plan		0.22		12
Balance, March 31, 2025		297.74	$	9,140

(1) For the three months ended March 31, 2025, a total of 187,600 common shares were issued under Emera’s ATM program at an average price of $53.58 per share for gross proceeds of $10 million ($10 million, net of after-tax issuance costs). As at March 31, 2025, an aggregate gross sales limit of $326 million remained available for issuance under the ATM program.

As at May 6, 2025, the amount of issued and outstanding common shares was 297.9 million.

If all outstanding stock options were converted as at May 6, 2025, an additional 4.3 million common shares would be issued and outstanding.

Preferred Stock

As at May 6, 2025, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

On January 16, 2025, Emera announced that the annual fixed dividend per share for Series F shares would be reset from $1.0505 to $1.4372 for the five-year period from and including February 15, 2025.

TRANSACTIONS WITH RELATED PARTIES

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 $49 million for the three months ended March 31, 2025 (2024 – $42 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. For further details, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPML” and “Contractual Obligations” sections.

•

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 $8 million for the three months ended March 31, 2025 (2024 – $4 million).

•

On March 4, 2025, NSPI sold development assets associated with the Wasoqonatl transmission line project to WTI for consideration of $15 million. The development assets were sold at cost with no gain or loss recognized in the Condensed Consolidated Statement of Income.

As at March 31, 2025, Emera and its associated companies had $37 million due to related parties (December 31, 2024 – $24 million) recorded in “Other Current Liabilities” on the Condensed Consolidated Balance Sheets.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2024 annual MD&A.

Derivative Assets and Liabilities Recognized on the Balance Sheet


As at millions of dollars	March 31 2025		December 31 2024
Regulatory Deferral:
Derivative instrument assets (1)	$	50	$	45
Derivative instrument liabilities (2)		(35)		(40)
Regulatory assets (1)		36		53
Regulatory liabilities (2)		(50)		(44)
Net asset	$	1	$	14
HFT Derivatives:
Derivative instrument assets (1)	$	181	$	122
Derivative instrument liabilities (2)		(360)		(542)
Net liability	$	(179)	$	(420)
Other Derivatives:
Derivative instrument assets (1)	$	19	$	-
Derivative instrument liabilities (2)		(29)		(36)
Net liability	$	(10)	$	(36)

(1) Current, other and held for sale assets.

(2) Current, long-term and held for sale liabilities.

Realized and Unrealized Gains (Losses) Recognized in Net Income


For the	Three months ended March 31
millions of dollars	2025		2024
Regulatory Deferral:
Regulated fuel for generation and purchased power (1)	$	(1)	$	(5)
HFT Derivatives:
Non-regulated operating revenues	$	466	$	160
Other Derivatives:
OM&G	$	20	$	(8)
Other income, net		(4)		(3)
Net gains (losses)	$	16	$	(11)
Total net gains	$	481	$	144

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

As of March 31, 2025, the unrealized gain in accumulated other comprehensive income was $12 million, net of tax (December 31, 2024 – $12 million, net of tax). For the three months ended March 31, 2025, unrealized gains of nil (2024 – $1 million), were reclassified into interest expense, net.

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. The Company’s internal control framework is based on criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at March 31, 2025, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company’s ICFR during the quarter ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CRITICAL ACCOUNTING 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 2024 annual MD&A.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

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.

SUMMARY OF QUARTERLY RESULTS


For the quarter ended millions of dollars	Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2
(except per share amounts)	2025		2024		2024		2024		2024		2023		2023		2023
Operating revenues	$	2,676	$	1,763	$	1,802	$	1,617	$	2,018	$	1,972	$	1,740	$	1,418
Net income attributable to common shareholders	$	583	$	154	$	4	$	129	$	207	$	289	$	101	$	28
EPS – basic	$	1.96	$	0.52	$	0.01	$	0.45	$	0.73	$	1.04	$	0.37	$	0.10
EPS – diluted	$	1.96	$	0.52	$	0.01	$	0.45	$	0.73	$	1.04	$	0.37	$	0.10

Quarterly operating revenues and adjusted net income are affected by seasonality. 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. Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the “Significant Items Affecting Earnings” section. Quarter-over-quarter variances are discussed further below.

Q1 2025 compared to Q1 2024

For explanation of variances, refer to the “Consolidated Income Statement Highlights” section.

Q4 2024 compared to Q4 2023

Q4 2024 net income attributable to common shareholders decreased by $135 million and EPS – basic and diluted decreased by $0.52 compared to Q4 2023. The decreases were primarily due to decreased MTM gains; charges related to wind-down costs and certain asset impairments; lower equity earnings from LIL; increased Corporate OM&G due to the timing difference in the valuation of long-term incentive expenses and related hedges; decreased earnings at Emera Energy; and increased Corporate interest expense. These changes were partially offset by the tax benefit related to a specific financing structure and its wind-up; increased earnings at NSPI, Other Electric Utilities, NMGC, PGS, and TEC; valuation allowance reversal related to the gain on sale of LIL; and increased Corporate income tax recovery. The change in EPS was also impacted by an increase in weighted average shares outstanding.

Q3 2024 compared to Q3 2023

Q3 2024 net income attributable to common shareholders decreased by $97 million and EPS – basic and diluted decreased by $0.36 compared to Q3 2023. The decreases were primarily due to charges related to the pending sale of NMGC; decreased earnings at Emera Energy; lower equity earnings from LIL; lower Corporate income tax recovery due to decreased losses before provision for income taxes; increased Corporate interest expense due to increased interest rates and increased total debt; and increased Corporate preferred share dividends. These changes were partially offset by decreased MTM losses; increased earnings at TEC, PGS, NSPI and NMGC; and lower Corporate OM&G due to the timing difference in the valuation of long-term incentive expense and related hedges. The change in EPS was also impacted by an increase in weighted average shares outstanding.

Q2 2024 compared to Q2 2023

Q2 2024 net income attributable to common shareholders increased by $101 million and EPS – basic and diluted increased by $0.35 compared to Q2 2023. The increases were primarily due to the gain on sale of LIL, after transaction costs; increased earnings at PGS and TEC; increased Corporate income tax recovery due to increased losses before provision for income taxes; and decreased MTM losses. These changes were partially offset by decreased earnings at NMGC and NSPI; higher Corporate interest expense due to increased interest rates and increased total average debt; and FX losses on the translation of USD short-term debt balances in Corporate. The change in EPS was also impacted by an increase in weighted average shares outstanding.