Exhibit 99.6

 

2024 Annual Report

Emera at a Glance Data is as of December 31, 2024, unless otherwise indicated.1 Emera is a leading North American provider of energy services headquartered in Halifax, Nova Scotia. Emera delivers safe, reliable and cleaner energy to customers through investments in regulated electric and natural gas utilities, and related businesses and assets. HIGHLIGHTS $43B total assets $7.2B revenue 7,600 employees 2.6M customers 6 electric and natural gas utilities ADJUSTED NET INCOME2 Excluding Corporate costs BY GEOGRAPHY 68% Florida 22% Canada 10% Other OUR COMPANIES Tampa Electric New Mexico Gas3 Emera Energy Nova Scotia Power Emera Caribbean Emera New Brunswick Peoples Gas Emera Newfoundland SeaCoast Gas Transmission & Labrador 1 this report contains forward-looking information and should be read in conjunction with, and is qualified by, the cautionary statement set out on page 12 documents and websites referenced herein are not incorporated by reference into this report unless explicitly stated otherwise. All references in this report to websites are intended to be inactive textual references only. 2 Based on 2024 adjusted net income attributable to common shareholders (“adjusted net income”), excluding corporate costs of $360 million, adjusted net income is a non- GAAP measure, which does not have a standardized meaning under United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). For more information and a reconciliation to the nearest GAAP measure, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2024 MD&A. 3 In August 2024, Emera entered into an agreement to sell New Mexico Gas. This transaction is expected to close later in 2025.

Why Invest in Emera Emera is at the forefront of a transformative era in energy with robust opportunities to invest on behalf of customers across the portfolio. Our proven strategy and operational excellence ensure we can capitalize on these opportunities and deliver earnings, cash flow and dividend growth for investors. PREMIUM PORTFOLIO OF REGULATED VISIBLE GROWTH PLAN UTILITIES FOCUSED IN FLORIDA ~70% $20B capital investment plan through 2029, focused on grid of adjusted net income,1 excluding Corporate costs, reliability, resiliency & modernization, system expansion to comes from our Florida operations meet customer growth, renewable integration, technology and customer facing solutions ~80% 7% to 8% of capital plan through 2029 is being invested in Florida, annualized, forecasted rate-base growth through 2029 supporting strong customer growth at Tampa Electric and Peoples Gas CONSTRUCTIVE REGULATORY ENVIRONMENTS RELIABLE EARNINGS AND DIVIDEND GROWTH Highly rated 18 years regulatory environments of consecutive dividend growth 1-2% 98% annual dividend growth target of adjusted net income,1 excluding Corporate costs, derived from our regulated utilities 5-7% average adjusted EPS2 growth target through 20273 1 Based on 2024 adjusted net income, excluding Corporate costs of $360 million. Adjusted net income is a non-GAAP measure which does not have standardized meaning under USGAAP. For more information and reconciliation to the nearest GAAP measure, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2024 MD&A. 2 Adjusted earnings per share (“EPS”) is a non-GAAP ratio, which does not have standardized meaning under USGAAP. For more information, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2024 MD&A. 3 Adjusted EPS growth forecast uses 2024 as base year.

EMERA 2024 ANNUAL REPORT 1 2024 Financial Highlights Unless otherwise indicated, data is as of December 31, 2024 and currency is in Canadian dollars. $2.94 annual adjusted EPS1 ~70% of adjusted net income,2 excluding Corporate costs, comes from our Florida operations $3.2B capital invested in 2024, leading to an 8% annual increase in rate base 5.4% dividend yield3 2024 Adjusted Net Income2 Excluding Corporate costs 1 Adjusted EPS is a non-GAAP ratio, which does not have standardized meaning under USGAAP. For more information, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2024 MD&A. 2 Based on 2024 adjusted net income, excluding Corporate costs of $360 million. Adjusted net income is a non-GAAP measure, which does not have a standardized meaning under USGAAP. For more information and a reconciliation to the nearest GAAP measure, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2024 MD&A. 3 Based on December 31, 2024, share price of $53.73. 2 EMERA 2024 ANNUAL REPORT

OUR STRATEGY We seek reliable, growing, forward-thinking utility investment opportunities, focused on premium operations in high-growth jurisdictions, a robust capital investment strategy, and a thoughtful approach to risk management, all of which drive value and steady growth for our shareholders. OUR PURPOSE Energizing modern life and delivering a cleaner energy future for all. OUR VISION To be the energy provider of choice for our customers, the employer of choice for our people and a preferred choice for investors. OUR VALUES Our core values shape our culture and guide our work every day. We put safety above all else. We put customers at the centre of everything we do. We value candour, respect and collaboration. We care for each other, the environment and our communities. We set a high bar and take on big things. CLIMATE PROGRESS Building on more than two decades of cost-effective investment, we’re proud of our track record with system enhancements and reductions in CO2 emissions that have addressed government requirements along a path to net zero by 2050.1 1 Achieving our vision on this timeline is subject to external factors beyond our control and dependent upon decisions of, and/or support from, others including government, regulators, independent system operators, independent power producers, interconnected utilities, partners, investors, customers and Indigenous communities. It is also reliant on the development and/or commercialization of new and emerging technologies and/or the use of offsets. Shifts in government and regulatory policies/programs may impact our projects and progress. We will only proceed with forward-looking investments where we can demonstrate to the satisfaction of regulators that such investments are prudent and the most cost-effective solution for customers within the applicable legislative and regulatory regimes. 2 Includes provincial procurement programs and independent power purchase agreements. 3 Our reductions in CO2 emissions, coal used in generation (GWh), and our net-zero vision are compared to 2005 levels and include CO2 Scope 1 generation emissions for Tampa Electric and Nova Scotia Power only. These values are still undergoing review and verification. We have previously shared an internal 2025 target to achieve a 55% reduction in CO2 emissions compared to 2005 levels. 4 90% of our 2025-2029 capital plan is focused on cost-effective investments in grid reliability and modernization, renewable integration and technological innovation. 5. Where required by legislation or otherwise proven to be cost effective for customers. EMERA 2024 ANNUAL REPORT 3

Letter from the Chair and the CEO

 

Karen Sheriff Chair, Emera Inc. Board of Directors   Scott Balfour President and Chief Executive Officer, Emera Inc.
Fellow Shareholders,		It’s a transformative era for the energy sector as economic, social, political, technological and environmental trends are shaping a future where energy is a cornerstone of progress. This is being amplified by advancements made toward the energy transition — where we’re experiencing a fundamental shift in how energy is generated, delivered and consumed.
		Our sector saw numerous challenges, and opportunities throughout the year including evolving customer expectations, customer affordability challenges, unprecedented weather events, supply chain constraints, evolving government and energy policy and ongoing global economic and geopolitical impacts.
		Our operating companies rose to these challenges and seized opportunities, staying focused on reliably and cost effectively delivering for customers today, while working to ensure we can continue to meet their needs in the future. This commitment to customers and operational excellence enables Emera to stay focused on providing sustainable, long- term value to shareholders.
		Our operating teams’ commitment to customers was exemplified in 2024 by the response to two record-breaking storms that impacted our Florida utilities. Hurricane Helene hit in late September, followed less than two weeks later by Hurricane Milton — the strongest storm to hit Tampa Bay in a century. After Milton, more than 6,000 workers, including teams from Nova Scotia Power and across the continent, worked nonstop to restore service to hundreds of thousands of Tampa Electric customers within a week, logging over 900,000 work hours in tough conditions with no serious safety incidents.
		In recognition of this outstanding work, the Tampa Electric team was awarded the Edison Electric Institute Emergency Response Award for 2024. We’re incredibly proud of our team’s dedication to customers despite the challenging circumstances.
		The Peoples Gas system fared very well, with fewer than 1,500 of its more than 500,000 customers experiencing service interruptions during the hurricanes. As electric utilities focused on safely restoring power, Peoples Gas provided critical emergency backup energy for homes, businesses, shelters and healthcare facilities, demonstrating the resilience and

 

4		EMERA 2024 ANNUAL REPORT

reliability of natural gas and its essential role in Florida’s energy system. The team also took steps to protect the system from damage during the restoration, launching a targeted damage prevention campaign to reinforce the importance of safe-digging practices in affected areas. This exceptional level of dedication to customers is shared by every member of the team across Emera — and it’s reinforced by our unwavering commitment to operational excellence and to delivering increasing value to shareholders. As a result, we accomplished a lot together, for customers and shareholders, throughout the year. 2024 Highlights We achieved a number of significant milestones in 2024 as we continued to focus our efforts on driving growth and enhancing shareholder value. We successfully executed our strategic plan to strengthen our balance sheet, create flexibility in our capital funding program and optimize our portfolio for future growth. This included the sale of our interest in the Labrador-Island Link, which closed in June, and the sale of New Mexico Gas, expected to close later this year. Once complete, these will generate combined proceeds that exceed our $1.3 billion target by more than double. We completed a $500 million issuance of hybrid securities, primarily used to repay long-term holding company debt. We moderated our dividend growth rate to provide more flexibility in financing the robust capital profile we have in front of us, while also continuing to deliver growing dividends for investors. EMERA 2024 ANNUAL REPORT 5

Letter from the Chair and the CEO

 

                                      

Our ambitious plan positions us well to seize growth opportunities ahead

 

$3.2B capital plan for 2024 completed		In Nova Scotia, we worked with the federal and provincial governments, to securitize more than $600 million of under-recovered fuel costs and deferred fuel costs at Nova Scotia Power, reducing debt and decreasing the impact from the recovery of these costs from customers through rates.
		Executing on our ambitious plan supports our premium portfolio of high-quality assets across North America and positions us well to seize the growth opportunities ahead.
49% reduction in CO2 emissions since 2005		We successfully completed our $3.2 billion capital plan for the year — our largest annual program to date — as we continued to invest in reliability and resiliency, system expansion to meet customer growth, as well as renewables and renewable integration investments largely to meet legislated decarbonization requirements in some of our jurisdictions. As a result, we made significant achievements across the Company in 2024, including:
		•  At the end of 2024, we achieved a 49 per cent reduction in CO2 emissions and reduced our use of coal in generation by 80 per cent, both compared to 2005 levels.1
		•  Tampa Electric continued to expand its solar fleet in 2024. Two new projects totaling 100 MW were brought into service, bringing total solar capacity to 1,350 MW. Another 745 MW is planned to be added by the end of 2028. In addition to supporting reliability, solar generation has saved Tampa Electric customers $321 million USD in fuel costs since 2017.
		•  Peoples Gas constructed pipelines to two renewable natural gas (RNG) producers to connect additional RNG into Florida’s natural gas supply. In addition to the three RNG facilities already connected, the team is building pipelines to connect the Polk County municipal landfill and Southern Cross Dairy facilities to the intrastate transmission pipeline. The dairy connection will be bidirectional, allowing the facility to access natural gas as a reliable backup during a power outage. Both connections are expected to be in service this year.
		•  After receiving regulatory approval in 2024, Nova Scotia Power started construction of its 150 MW grid-scale battery storage project, an equity partnership with Nova Scotia’s 13 Mi’kmaq communities. The project includes three 50 MW battery storage sites that will enable more renewable energy and enhance reliability for customers. Two sites are expected to be operational this year, with the third to be complete in 2026.
		•  The Maritime Link performed well in 2024, once again achieving over 99.9 per cent availability. The Link delivered nearly two million megawatts of clean hydroelectricity to Nova Scotia, serving approximately 19 per cent of Nova Scotia Power’s energy requirements and resulting in $100M in savings for Nova Scotians over the course of the year.

 

1	Reductions are still undergoing verification. CO2 emissions reduction includes Scope 1 generation emissions for Tampa Electric and Nova Scotia Power only.

 

6		EMERA 2024 ANNUAL REPORT

Letter from the Chair and the CEO Safety is our first priority in everything we do across Emera. We continue to reinforce our strong safety culture and have made significant progress in reducing serious injuries and fatalities across our operations. Grand Bahama Power has solar energy in its mix for the first time with agreements to purchase a total of 14.5 MW from three independent solar sites, two of which were commissioned in 2024. The team is also working to launch its own 5 MW solar site later this year. Once complete, solar energy at GBPC will total 19.5 MW, or approximately 14.5 per cent of the island’s energy needs. In addition to reducing CO2 emissions, solar is helping to reduce the impact of volatile fuel prices and stabilize energy costs for customers. New rates came into effect for two of our utilities in 2024 — at Peoples Gas early in January, and at New Mexico Gas in October. In December, the Florida Public Service Commission approved essentially all of Tampa Electric’s capital plan based upon a midpoint return on equity of 10.5%, with an allowed range of 9.5% to 11.5%. New rates went into effect in January 2025. In December, we announced our five-year capital investment plan — the largest in our history at $20 billion through 2029. In addition to delivering exceptional value to customers, our $20B capital plan will drive top-tier rate base growth and support our targeted annual adjusted EPS growth of five to seven per cent through 2027.1, 2 five-year capital investment plan 1 Adjusted EPS is a non-GAAP ratio, which does not have standardized meaning under USGAAP. For more information, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2024 MD&A. 2 Adjusted EPS growth forecast uses 2024 as base year. EMERA 2024 ANNUAL REPORT 7

Letter from the Chair and the CEO

 

                                      

Emera is well-positioned to capitalize on opportunities to deliver for our customers and our shareholders.

 

		Safety
		Safety is a top priority in everything we do across Emera. We continue working to reinforce our strong safety culture and remain relentlessly focused on reducing serious injuries and fatalities across our operations.
		Our commitment to safety is strengthened by visible safety leadership, and we continually work to build on this. Throughout 2024, members of the leadership team conducted safety engagements across the business. This included participating in a wide range of activities such as risk assessments, compliance checks, inspections and safety conversations. We believe these engagements allow leaders to underpin our commitment with frontline employees, further reinforcing our robust safety culture.
		Despite remaining well under the industry average, our key safety metrics for 2024 were disappointing. We saw a 30 per cent increase in our year-over-year total recordable injury rate, placing us 24 per cent higher than our five-year average. Our lost time injury (LTI) frequency rate for the year increased by 40 per cent over 2023, three per cent higher than our five-year average.
		We’re committed to learning from all incidents as we stay focused on safety first and continue working to build an Emera where no one gets hurt.
		Financial Results
$849M annual adjusted net income1		We reported annual adjusted net income1 for 2024 of $849 million and adjusted EPS1 of $2.94. These results were in line with $2.96 in 2023 and the benchmark for our adjusted EPS growth guidance.
		Our regulated utilities, particularly those in Florida, continue to drive our earnings growth with a six per cent increase in adjusted earnings1 contributions in 2024. Adjusted earnings1 growth across our regulated utilities was offset by lower earnings from equity investments as a result of the Labrador Island Link transaction in Q2 2024 and lower contributions from Emera Energy due to less favourable market conditions.
		We remained focused on delivering value to our shareholders. In 2024, our Board of Directors approved an increase in our quarterly dividend of $0.03 per common share, marking our 18th consecutive year of dividend increases. This increase was in line with our adjusted dividend growth targetannounced as partofour strategic update in June. We also announced our three-year average adjusted EPS1 growth target of five to seven per cent through 2027,2 reflecting our confidence in our continued growth and strong performance. Emera shareholders can continue to expect dependable and growing dividends, underpinned by our prudent financial management and disciplined capital allocation.

 

1	Adjusted net income and adjusted EPS are a non-GAAP measure and a non-GAAP ratio, respectively, which do not have standardized meaning under USGAAP. For more information and a reconciliation to the nearest GAAP measure, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2024 MD&A.

2	Adjusted EPS growth forecast uses 2024 as base year.

 

8		EMERA 2024 ANNUAL REPORT

Letter from the Chair and the CEO

 

We saw a positive response to the strategic update we provided to the market mid-year. We saw strong share price performance in the second half of the year, both on an absolute and relative basis. We outperformed our closest peers on both the Canadian and US utility indices, as well as on the broader market.
With key trends converging to drive an unprecedented increase in demand for reliable energy, our growth drivers remain strong, evidenced by our forecasted seven to eight per cent rate-base growth CAGR over the next five years, as we invest to meet customer needs. We’re confident that as we make these customer-focused investments, we will also deliver long-term value for Emera shareholders.
Board Changes
After more than 10 years of service, Jackie Sheppard stepped down as Chair of the Emera Board in February 2025. Jackie’s leadership and her expertise in strategic planning, public markets, legal and corporate governance were critical in guiding Emera through a period of significant growth and expansion, including the 2016 acquisition of TECO and the successful completion of the Maritime Link project. We will continue to benefit from her expertise as she stays on as a Director through 2025. On behalf of the entire Board and management team, thank you Jackie for your invaluable commitment to Emera.
Karen Sheriff has been appointed the new Chair of the Board. Since joining as a Director in 2021, Karen’s leadership experience in public and private companies, as well as in regulated environments, has made her a strong addition to the Board and will be instrumental in guiding Emera’s next phase of growth.
We welcomed Carla Tully to the Board in June 2024. Carla is the former Chief Executive Officer and Co-Founder of Earthrise Energy. Her profound experience in the energy and infrastructure sectors in North America and Europe, combined with her track record in leading and growing businesses, have made her a strong addition to our Board.
It’s been a busy year of progress. With a stronger balance sheet, a disciplined capital investment plan, and a premium portfolio of assets located in high-quality jurisdictions across North America, Emera is well-positioned to capitalize on opportunities to deliver for our customers and our shareholders.		Thank You
This a direct result of the hard work and talent of the teams across our business that drive our success.
To the Board of Directors and the entire Emera team, thank you for your relentless focus on customers and continued commitment to shareholders. Together, we’ve made great progress, and our business is well-placed for future growth.
To our valued shareholders, thank you for your confidence in Emera.

 

Karen Sheriff		Scott Balfour
Chair, Board of Directors,		President and Chief Executive Officer,
Emera Inc.		Emera Inc.

 

EMERA 2024 ANNUAL REPORT		9

Financial Review

 

                                                        

 

 

10		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

Management’s Discussion & Analysis

As at February 21, 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 fourth quarter of, and for the full year of, 2024 relative to the same periods in 2023 and selected financial information for 2022; and its financial position as at December 31, 2024 relative to December 31, 2023. 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 annual 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 December 31, 2024, 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 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”)		UARB
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

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.

 

EMERA 2024 ANNUAL REPORT		11

Management’s Discussion and Analysis

 

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, 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; 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; 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 centered 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.

 

12		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

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 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’s 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 items below from net income attributable to common shareholders. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business.

Emera calculates adjusted net income for the Florida Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. For more information refer to the Financial Highlights section for each of Florida Electric Utility, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.

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, refer to the “Dividend Payout Ratio” section.

ADJUSTING ITEM IMPACTING ALL PERIODS:

Mark-to-market (“MTM”) Adjustments:

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 2024 ANNUAL REPORT		13

Management’s Discussion and Analysis

 

ADJUSTING ITEMS IMPACTING 2024:

Gain on Sale of Emera’s Indirect Minority Interest in the LIL (“Gain on sale of LIL”):

In Q2 2024, Emera recognized a $107 million gain, after tax and transaction costs, on the sale of LIL. In Q4 2024, Emera recognized a $22 million tax benefit related to the reversal of a prior year valuation allowance. A portion of the taxable capital gain on sale of LIL was offset by prior year loss carryforwards, of which the tax benefit was subject to a valuation allowance as at December 31, 2023. For further details refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

Financing Structure Wind-Up:

In Q4 2024, Emera recognized a $58 million tax benefit related to denied interest and financing expenses and the wind- up of a specific financing structure. For further details refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

Charges Related to Wind-Down Costs and Certain Asset Impairments:

In Q4 2024, the Company recognized $26 million, after-tax, in wind-down costs and certain asset impairments, primarily at Block Energy LLC (“Block Energy”). For further details, refer to the “Significant Items Affecting Earnings” section.

Charges Related to the Pending Sale of NMGC:

On August 5, 2024, Emera entered into an agreement to sell NMGC. In Q3 2024, the Company recognized $206 million in non-cash goodwill and other impairment charges, after-tax, and an additional loss of $19 million in estimated transaction costs, after-tax, related to the pending sale. For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

ADJUSTING ITEMS IMPACTING 2022:

GBPC Impairment Charge:

In Q4 2022, the Company recognized a $73 million non-cash goodwill impairment charge related to GBPC due to a decline in the fair value (“FV”) of the reporting unit.

NSPML Unrecoverable Costs:

In Q1 2022, the UARB issued a decision to disallow recovery of $9 million in costs ($7 million after-tax) included in NSPML’s final capital cost application.

RECONCILIATION OF NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS TO ADJUSTED NET INCOME:

 

For the		Three months ended December 31								Year ended December 31
millions of dollars (except per share amounts)		2024				2023				2024				2023				2022
Net income attributable to common shareholders		$	154			$	289			$	494			$	978			$	945
Gain on sale of LIL, after-tax (1)			22				—				129				—				—
Financing structure wind-up			58				—				58				—				—
Charges related to wind-down costs and certain asset impairments, after-tax (2)			(26	)			—				(26	)			—				—
Charges related to the pending sale of NMGC, after-tax (3)(4)			—				—				(225	)			—				—
MTM (loss) gain, after-tax (5)			(146	)			114				(291	)			169				175
GBPC impairment charge			—				—				—				—				(73	)
NSPML unrecoverable costs			—				—				—				—				(7	)
Adjusted net income		$	246			$	175			$	849			$	809			$	850
EPS – basic		$	0.52			$	1.04			$	1.71			$	3.57			$	3.56
Adjusted EPS – basic		$	0.84			$	0.63			$	2.94			$	2.96			$	3.20

 

(1)	Includes an income tax recovery of $22 million for the three months ended December 31, 2024 and net of income tax expense of $53 million for the year ended December 31, 2024 (2023 – nil).

(2)	Net of income tax recovery of $6 million for the three months and year ended December 31, 2024 (2023 – nil).

(3)	Represents (i) $206 million in non-cash goodwill and other impairment charges, after-tax and (ii) $19 million in transaction costs, after-tax for the year ended December 31, 2024 (2023 – nil).

(4)	Net of income tax recovery of $21 million for the year ended December 31, 2024 (2023 – nil).

(5)	Net of income tax recovery of $57 million for the three months ended December 31, 2024 (2023 – $44 million expense) and $117 million recovery for the year ended December 31, 2024 (2023 – $68 million expense) (2022 – $73 million expense).

 

14		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

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 excluding the income effect of the gain on sale of LIL, charges related to wind-down costs and certain asset impairments, charges related to the pending sale of NMGC, MTM adjustments, the 2022 GBPC impairment charge, and the 2022 NSPML unrecoverable costs.

RECONCILIATION OF NET INCOME TO EBITDA AND ADJUSTED EBITDA:

 

For the		Three months ended December 31								Year ended December 31
millions of dollars		2024				2023				2024				2023				2022
Net income (1)		$	173			$	307			$	568			$	1,045			$	1,009
Interest expense, net			248				241				973				925				709
Income tax (recovery) expense			(199	)			51				(159	)			128				185
Depreciation and amortization			296				264				1,162				1,049				952
EBITDA		$	518			$	863			$	2,544			$	3,147			$	2,855
Gain on sale of LIL, excluding income tax			—				—				182				—				—
Charges related to wind-down costs and certain asset impairments, excluding income tax			(32	)			—				(32	)			—				—
Charges related to the pending sale of NMGC, excluding income tax			—				—				(246	)			—				—
MTM (loss) gain, excluding income tax			(203	)			158				(408	)			237				248
GBPC impairment charge			—				—				—				—				(73	)
NSPML unrecoverable costs			—				—				—				—				(7	)
Adjusted EBITDA		$	753			$	705			$	3,048			$	2,910			$	2,687

 

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

Consolidated Financial Review

Significant Items Affecting Earnings

The items detailed below have had a significant impact on Net Income Attributable to Common Shareholders but have been excluded from Adjusted Net Income as described in the section entitled “Non-GAAP Financial Measures and Ratios”.

FINANCING STRUCTURE WIND-UP

During 2024, the Company incurred $185 million of interest and financing expenses in connection with a specific financing structure. The current and future interest and financing expenses are expected to be denied under the recently enacted Excessive Interest and Financing Expenses Limitation (“EIFEL”) legislation and, as a result, the financing structure has been wound up. It was determined that Emera is more likely than not to realize the benefit of the current denied interest and financing expenses in future periods and therefore a $54 million deferred income tax asset and related income tax benefit ($0.19 per common share) was recorded during Q4 2024. In addition, Emera recognized a $4 million income tax benefit ($0.01 per common share) related to the reversal of a deferred income tax liability on the wind-up of the financing structure. The total tax benefit of $58 million was recorded in “Income Tax (Recovery) Expense” on the Consolidated Statements of Income and included in the Other segment. For further details on the EIFEL legislation, refer to the “Other Developments” section.

CHARGES RELATED TO WIND-DOWN COSTS AND CERTAIN ASSET IMPAIRMENTS

In Q4 2024, Emera recognized $32 million ($26 million after-tax, or $0.09 per common share) in wind-down costs and certain asset impairments, primarily at Block Energy. These were recorded in “Other Income, net” and “Impairment Charges” on the Consolidated Statements of Income and included mainly in the Other segment.

 

EMERA 2024 ANNUAL REPORT		15

Management’s Discussion and Analysis

 

GAIN ON SALE OF LIL

On June 4, 2024, Emera completed the sale of its LIL equity interest. A gain on sale of $182 million after transaction costs ($107 million, after tax and transaction costs, or $0.37 per common share), was recognized in “Other Income, net” on the Consolidated Statements of Income in Q2 2024 and included in the Other segment. In Q4 2024, Emera recognized a $22 million ($0.08 per common share) tax benefit related to the reversal of a prior year valuation allowance. A portion of the taxable capital gain on the sale of the LIL equity interest was offset by prior year loss carryforwards, of which the tax benefit had been subject to a valuation allowance as at December 31, 2023. This tax benefit was recorded in “Income Tax (Recovery) Expense” on the Consolidated Statements of Income in Q4 2024 and included in the Other segment. For further details on the transaction, refer to the “Other Developments” section.

CHARGES RELATED TO THE PENDING SALE OF NMGC

In Q3 2024, Emera recognized non-cash goodwill and other impairment charges of $221 million ($206 after-tax, or $0.72 per common share) related to the NMGC reporting unit. These charges were recorded in “Impairment charges” on the Consolidated Statements of Income and included in the Other and Gas Utilities and Infrastructure segments, respectively. For further details on the pending sale of NMGC, refer to the “Other Developments” section. For further details on the non-cash goodwill impairment charge, refer to note 23 in the consolidated financial statements.

Additionally, in Q3 2024, Emera recorded a loss of $25 million ($19 million after-tax, or $0.06 per common share) in estimated transaction costs related to the pending sale of NMGC. These transaction costs were recorded in “Other Income, net” on the Consolidated Statement of Income and included in the Other segment. For further details, refer to the “Other Developments” section.

EARNINGS IMPACT OF MTM LOSS, AFTER-TAX

Quarter-to-date the 2023 MTM gain, after-tax, of $114 million decreased $260 million to a $146 million MTM loss, after-tax, for the same period in 2024. For the year ended, the 2023 MTM gain, after-tax, of $169 million decreased $460 million to a $291 million MTM loss, after-tax, for the same period in 2024. These decreases were primarily due to changes in existing positions, partially offset by lower amortization of gas transportation at Emera Energy Services (“EES”).

Consolidated Financial Highlights

 

For the millions of dollars		Three months ended December 31								Year ended December 31
Adjusted net income		2024				2023				2024				2023				2022
Florida Electric Utility		$	120			$	115			$	644			$	627			$	596
Canadian Electric Utilities			77				68				232				247				222
Gas Utilities and Infrastructure			87				59				267				214				221
Other Electric Utilities			21				4				48				35				29
Other			(59	)			(71	)			(342	)			(314	)			(218	)
Adjusted net income		$	246			$	175			$	849			$	809			$	850
Gain on sale of LIL, after-tax			22				—				129				—				—
Financing structure wind-up			58				—				58				—				—
Charges related to wind-down costs and certain asset impairments, after-tax			(26	)			—				(26	)			—				—
Charges related to the pending sale of NMGC, after-tax			—				—				(225	)			—				—
MTM (loss) gain, after-tax			(146	)			114				(291	)			169				175
GBPC impairment charge			—				—				—				—				(73	)
NSPML unrecoverable costs			—				—				—				—				(7	)
Net income attributable to common shareholders		$	154			$	289			$	494			$	978			$	945

 

16		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

The following table highlights significant changes in adjusted net income from 2023 to 2024:

 

For the millions of dollars		Three months ended December 31				Year ended December 31
Adjusted net income – 2023		$	175			$	809
Operating Unit Performance
Increased earnings at NSPI due to increased income tax recovery, partially offset by higher operating, maintenance and general expenses (“OM&G”) due primarily to a lower storm cost deferral			31				19
Increased earnings quarter-over-quarter at Other Electric Utilities primarily due to the timing of recovery of fuel costs and lower OM&G. Year-over-year increased primarily due to higher sales volumes, partially offset by higher OM&G			17				13
Increased earnings quarter-over-quarter at NMGC due to higher revenue from new base rates, partially offset by higher income tax expense. Decreased earnings year-over-year due to lower asset optimization revenue, partially offset by higher revenue from new base rates			14				(4	)
Increased earnings at PGS due to higher revenue from new base rates and customer growth, partially offset by increased interest expense, depreciation, OM&G, and income tax expense			11				58
Increased earnings at TEC due to higher revenues from customer growth and new base rates, and the impact of a weaker CAD, partially offset by higher OM&G, and depreciation. Year-over-year increased earnings also due to lower income tax expense and lower interest expense, partially offset by unfavourable weather			5				17
Decreased earnings year-over-year at EES due to favourable hedging opportunities in Q1 2023 and less favourable market conditions in 2024			(3	)			(16	)
Decreased earnings at Bear Swamp primarily due to the recognition of investment tax credits in 2023			(13	)			(20	)
Decreased income from equity investments due to the sale of LIL equity interest			(16	)			(32	)
Corporate
Decreased deferred income tax asset valuation allowance due to utilization of tax loss carryforwards			36				39
Increased income tax recovery due to increased loss before provision for income taxes			15				20
Increased interest expense due to the impact of a weaker CAD on USD interest expense, increased total Corporate debt and increased interest rates			(9	)			(38	)
Increased OM&G quarter-over-quarter primarily due to the timing difference in the valuation of long-term incentive expense and related hedges			(16	)			(1	)
Other Variances			(1	)			(15	)
Adjusted net income – 2024		$	246			$	849

 

For the		Year ended December 31
millions of dollars		2024				2023				2022
Operating cash flow before changes in working capital		$	2,194			$	2,336			$	1,147
Change in working capital			452				(95	)			(234	)
Operating cash flow		$	2,646			$	2,241			$	913
Investing cash flow		$	(2,218	)		$	(2,917	)		$	(2,569	)
Financing cash flow		$	(818	)		$	939			$	1,555

For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.

 

As at		December 31
millions of dollars		2024				2023				2022
Total assets		$	42,951			$	39,480			$	39,742
Total long-term debt (including current portion) (1)		$	18,407			$	18,365			$	16,318

 

(1)	On August 5, 2024, Emera announced an agreement to sell NMGC. As at December 31, 2024, NMGC’s assets and liabilities were classified as held for sale and are excluded from this table. For further details, refer to the “Other Developments” section and note 4 in the consolidated financial statements.

 

EMERA 2024 ANNUAL REPORT		17

Management’s Discussion and Analysis

 

Consolidated Income Statement Highlights

 

For the millions of dollars		Three months ended December 31												Year ended December 31												Year ended December 31
(except per share amounts)		2024				2023				Variance				2024				2023				Variance				2022
Operating revenues		$	1,763			$	1,972			$	(209	)		$	7,200			$	7,563			$	(363	)		$	7,588
Operating expenses			1,524				1,467				(57	)			6,120				5,769				(351	)			5,959
Income from operations		$	239			$	505			$	(266	)		$	1,080			$	1,794			$	(714	)		$	1,629
Other (expense) income, net		$	(29	)		$	51			$	(80	)		$	203			$	158			$	45			$	145
Interest expense, net		$	248			$	241			$	(7	)		$	973			$	925			$	(48	)		$	709
Income tax (recovery) expense		$	(199	)		$	51			$	250			$	(159	)		$	128			$	287			$	185
Net income attributable to common shareholders		$	154			$	289			$	(135	)		$	494			$	978			$	(484	)		$	945
Adjusted net income		$	246			$	175			$	71			$	849			$	809			$	40			$	850
Weighted average shares of common stock outstanding (in millions)			294.1				277.7				16.4				289.1				273.6				15.5				265.5
EPS – basic		$	0.52			$	1.04			$	(0.52	)		$	1.71			$	3.57			$	(1.86	)		$	3.56
EPS – diluted		$	0.52			$	1.04			$	(0.52	)		$	1.71			$	3.57			$	(1.86	)		$	3.55
Adjusted EPS – basic		$	0.84			$	0.63			$	0.21			$	2.94			$	2.96			$	(0.02	)		$	3.20
Adjusted EBITDA		$	753			$	705			$	48			$	3,048			$	2,910			$	138			$	2,687
Dividends per common share declared		$	0.7250			$	0.7175			$	0.0075			$	2.8775			$	2.7875			$	0.0900			$	2.6775
Dividends per first preferred shares declared:
Series A														$	0.5456			$	0.5456			$	—			$	0.5456
Series B														$	1.6966			$	1.5583			$	0.1383			$	0.6869
Series C														$	1.6085			$	1.2873			$	0.3212			$	1.1802
Series E														$	1.1250			$	1.1250			$	—			$	1.1250
Series F														$	1.0505			$	1.0505			$	—			$	1.0505
Series H														$	1.5810			$	1.3140			$	0.2670			$	1.2250
Series J														$	1.0625			$	1.0625			$	—			$	1.0625
Series L														$	1.1500			$	1.1500			$	—			$	1.1500

OPERATING REVENUES

For Q4 2024, operating revenues decreased $209 million compared to Q4 2023 and, excluding decreased MTM gain of $291 million, increased $82 million. For the year ended December 31, 2024, operating revenues decreased $363 million compared to 2023 and, excluding decreased MTM gain of $559 million, increased $196 million. The increases were due to new rates at PGS, NSPI, TEC and NMGC; the impact of a weaker CAD; and increased customer growth at TEC and PGS. The increases were partially offset by lower fuel recovery clause and storm surcharge revenue (offset in OM&G) at TEC; and lower fuel revenue at NMGC. Year-over-year increase was also due to a change in the fuel cost recovery methodology for an industrial customer in 2023 at NSPI (offset in fuel for generation and purchased power).

OPERATING EXPENSES

For Q4 2024, operating expenses increased $57 million compared to Q4 2023, and, excluding charges related to wind-down costs and certain asset impairments of $4 million, increased $53 million. For the year ended December 31, 2024, operating expenses increased $351 million compared to 2023, and excluding the goodwill and other impairment charges primarily related to the pending sale of NMGC of $225 million, increased $126 million due to higher depreciation at TEC and PGS; the impact of a weaker CAD; higher OM&G due to timing of deferred clause recoveries at PGS and TEC; lower storm cost deferral and higher demand side management program costs at NSPI; and higher labour costs at PGS. This was partially offset by lower natural gas prices at NMGC, PGS and TEC and lower storm cost recognition at TEC (offset in revenue). Year-over-year increase was also due to a change in fuel cost recovery for an industrial customer in 2023 at NSPI (offset in revenue).

 

18		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

OTHER INCOME, NET

For Q4 2024, other income, net decreased $80 million compared to Q4 2024 due to charges related to wind-down costs and certain asset impairments and higher FX losses.

For the year ended December 31, 2024, other income, net increased $45 million compared to the same period in 2023 due to the gain on sale of LIL, after transaction costs, partially offset by higher FX losses, charges related wind-down costs and certain asset impairments, transaction costs related to the pending sale of NMGC, and lower interest income.

INTEREST EXPENSE, NET

For Q4 2024, interest expense, net increased $7 million and for the year ended December 31,2024, increased $48 million compared to the same periods in 2023 due to the impact of a weaker CAD on USD interest expense, increased borrowings to support ongoing operations and higher interest rates.

INCOME TAX (RECOVERY) EXPENSE

For Q4 2024, income tax recovery increased $250 million compared to Q4 2023 due to decreased income before provision for income taxes, decreased deferred income tax asset valuation allowance and recognition of tax benefits associated with denied interest and financing expenses.

For the year ended December 31, 2024, income tax recovery increased $287 million compared to 2023 due to decreased income before provision for income taxes (excluding the gain on sale of LIL and charges related to the pending sale of NMGC), decreased deferred income tax asset valuation allowance and recognition of tax benefits associated with denied interest and financing expenses. This increased recovery was partially offset by the net tax impact of the gain on sale of LIL and charges related to the pending sale of NMGC.

NET INCOME AND ADJUSTED NET INCOME

For Q4 2024, net income attributable to common shareholders compared to Q4 2023, was favourably impacted by the $58 million tax benefit related to a specific financing structure and its wind-up and the $22 million valuation allowance reversal related to the gain on sale of LIL, and unfavourably impacted by the $26 million charges related to wind-down costs and certain asset impairments, and the $260 million decrease in MTM gains. Excluding these impacts, adjusted net income increased $71 million, primarily due to increased earnings at NSPI, Other Electric Utilities, NMGC, PGS, and TEC, and increased Corporate income tax recovery. This was partially offset by lower equity earnings from LIL; increased Corporate OM&G due to timing of long-term incentive expenses and related hedges; increased Corporate interest expense; and decreased earnings at Emera Energy.

For the year ended December 31, 2024, net income attributable to common shareholders, compared to the same period in 2023, was favourably impacted by the $129 million gain on sale of LIL, and the $58 million tax benefit related to a specific financing structure and its wind-up and unfavourably impacted by the $26 million in charges related to wind-down costs and certain asset impairments, $225 million in charges related to the pending sale of NMGC, and the $460 million decrease in MTM gains. Excluding these changes, adjusted net income increased $40 million. The increase was primarily due to increased earnings at PGS, NSPI, TEC, and Other Electric Utilities, and increased Corporate income tax recovery. This was partially offset by increased Corporate interest expense; lower equity earnings from LIL; and decreased earnings at Emera Energy.

EPS – BASIC AND ADJUSTED EPS – BASIC

For Q4 2024, EPS – basic was lower than in Q4 2023 due to the impact of decreased earnings, as discussed above, and an increase in weighted average shares outstanding. Adjusted EPS – basic was higher in Q4 2024, compared to Q4 2023, due to increased adjusted earnings as discussed above, partially offset by an increase in weighted average shares outstanding.

For the year ended December 31, 2024, EPS – basic was lower than in 2023 due to the impact of an increase in weighted average shares outstanding and decreased earnings, as discussed above. Adjusted EPS – basic was lower in 2024, compared to 2023, due to the impact of an increase in weighted average shares outstanding, partially offset by increased adjusted earnings, as discussed above.

EFFECT OF FOREIGN CURRENCY TRANSLATION

Emera operates in the United States (“US”), Canada and various Caribbean countries and, as such, generates revenues and incurs expenses denominated in local currencies which are translated into CAD for financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can positively or adversely affect results.

 

EMERA 2024 ANNUAL REPORT		19

Management’s Discussion and Analysis

 

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. The relevant CAD/USD exchange rates on net income attributable to common shareholders for 2024 and 2023 are as follows:

 

		Three months ended December 31								Year ended December 31
		2024				2023				2024				2023
Weighted average CAD/USD		$	1.37			$	1.36			$	1.36			$	1.35
Period end CAD/USD exchange rate		$	1.44			$	1.32			$	1.44			$	1.32

The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:

 

For the		Three months ended December 31								Year ended December 31
millions of USD		2024				2023				2024				2023
Florida Electric Utility (1)		$	85			$	85			$	470			$	466
Gas Utilities and Infrastructure (2)(3)			56				41				178				142
Other Electric Utilities			15				3				35				26
Other segment (4)(5)			(33	)			(18	)			(131	)			(95	)
Total (1)(3)(5)		$	123			$	111			$	552			$	539

 

(1)	Excludes $2 million USD, after-tax, in other impairment charges for the three months and year ended December 31, 2024.

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

(3)	Excludes $6 million USD, after-tax, in other impairment charges associated with the pending sale of NMGC for the year ended December 31, 2024.

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

(5)	Excludes $84 million USD in MTM losses, after-tax, for the three months ended December 31, 2024 (2023 – $73 million USD MTM gain, after-tax) and $189 million in USD MTM losses, after-tax, for the year ended December 31, 2024 (2023 – $116 million USD MTM gain, after-tax).

Weakening of the CAD increased adjusted net income by $2 million in Q4 2024 and $5 million for the year ended December 31, 2024, compared to the same periods in 2023. 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.

The translation impact of a weaker CAD on USD earnings was more than offset by the realized and unrealized losses on FX hedges used to mitigate translation risk of USD earnings, resulting in a $29 million decrease to net income in Q4 2024 and $35 million decrease to net income for the year ended December 31, 2024, compared to the same periods in 2023.

Business Overview and Outlook

Florida Electric Utility

The Florida Electric Utility segment consists of TEC, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. TEC has $13 billion USD of assets and approximately 855,000 customers at December 31, 2024. TEC owns 6,620 megawatts (“MW”) of generating capacity, of which 73 per cent is natural gas fired, 20 per cent is solar and 7 per cent is coal. TEC also owns 2,192 kilometres of transmission facilities and 20,693 kilometres of distribution facilities. TEC meets the planning criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.

Beginning in 2025, TEC’s approved regulated ROE range is 9.50 per cent to 11.50 per cent (2024 – 9.25 per cent to 11.25 per cent) based on an allowed equity capital structure of 54 per cent (2024 – 54 per cent). An ROE of 10.50 per cent (2024 – 10.20 per cent) is used for the calculation of the return on investments for clauses.

TEC anticipates earning within 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. Normalizing 2024 for weather, TEC’s sales volumes in 2025 are projected to be higher than in 2024 due to customer growth. TEC expects customer growth rates in 2025 to be comparable to 2024, reflective of the expected economic growth in Florida.

 

20		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

On April 2, 2024, TEC filed a rate case with the FPSC for new base rates. On December 3, 2024, the FPSC rendered a decision which includes annual base rate increases of $185 million USD in 2025 and adjustments of $87 million USD and $9 million USD in 2026 and 2027, respectively. The rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and other resiliency and reliability projects. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital and the allowed regulatory ROE range is 9.50 per cent to 11.50 per cent with a 10.50 per cent midpoint. On February 3, 2025, the FPSC issued the final order approving the decision, effective January 1, 2025. On February 18, 2025, a motion for reconsideration on certain aspects of the rate case order was filed with the FPSC. TEC will respond to this motion in February 2025. TEC expects the FPSC to reach a final decision on the motion in Q2 2025.

On September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall approximately 200 miles north of Tampa, in Taylor County, as a Category 4 hurricane. TEC’s service territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number of customers out of 100,000. As of December 31, 2024, TEC deferred $49 million USD to the storm reserve for future recovery.

On October 9, 2024, Hurricane Milton made landfall approximately 50 miles south of Tampa, near Sarasota, and was the worst weather event to impact the area in over 100 years. The Category 3 hurricane had a significant impact on TEC’s service territory which resulted in a peak number of customers out of 600,000. As of December 31, 2024, TEC deferred $340 million USD to the storm reserve for future recovery.

As at December 31, 2024, total restoration costs charged to the storm reserve account have exceeded the storm reserve balance (for additional details on the storm reserve, refer to note 7 in Emera’s consolidated financial statements) and therefore $377 million USD has been deferred as a regulatory asset for future recovery. On February 4, 2025, the FPSC approved TEC’s petition filed on December 27, 2024 for the recovery of $466 million USD for 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.

On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction was 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 FPSC approved the mid-course adjustment.

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, building resilience and energy storage.

Canadian Electric Utilities

The Canadian Electric Utilities segment includes NSPI and NSPML. NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia. NSPML is a 100 per cent equity interest in the Maritime Link Project (“Maritime Link”), a transmission project between the island of Newfoundland and Nova Scotia.

On June 4, 2024, Emera completed the sale of its LIL equity interest. For further information, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

NSPI

With $7.1 billion of assets and approximately 557,000 customers at December 31, 2024, NSPI owns 2,422 MW of generating capacity, of which 44 per cent is coal and/or oil-fired; 28 per cent is natural gas and/or oil; 19 per cent is hydro, wind, or solar; 7 per cent is petroleum coke (“petcoke”) and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPPs”) and community feed-in tariff (“COMFIT”) participants, which own 533 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing Newfoundland and Labrador Hydro’s (“NLH”) Nova Scotia Block (“NS Block”) delivery obligations, as discussed below. NSPI owns approximately 5,000 kilometres of transmission facilities and 28,000 kilometres of distribution facilities.

NLH is obligated to provide NSPI with approximately 900 Gigawatt hours (“GWh”) of energy annually over 35 years. In addition, for the first five years of the NS Block, NLH is obligated to provide approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. NSPI has the option of purchasing additional market-priced energy from NLH through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from NLH for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of energy per year through August 31, 2041.

 

EMERA 2024 ANNUAL REPORT		21

Management’s Discussion and Analysis

 

NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent of approved rate base.

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

On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the Province of Nova Scotia (the “Province”) on terms and conditions for a federal loan guarantee (“FLG”) of $500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of the replacement energy that was required during the several years of delay in the Muskrat Falls hydroelectricity project. On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. On November 29, 2024, the UARB approved NSPML’s application to issue the debt, transfer the proceeds to NSPI as a refund of a portion of previous NSPML assessment payments (“NSPML Refund”), and to increase its annual assessment charge to NSPI to recover the refund and related financing costs over a 28-year period. On December 16, 2024, the net proceeds of the NSPML debt issuance were transferred to NSPI and applied against the FAM regulatory asset balance. On February 18, 2025, the UARB approved NSPI’s application to increase 2025 fuel rates to service the incremental NSPML debt.

On December 2, 2024, the UARB approved the recovery of $24 million of major storm restoration and incremental financing costs deferred to NSPI’s storm rider in 2023 to be recovered over a 12-month period beginning on January 1, 2025.

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

On June 13, 2024, the UARB approved $238 million of capital investment, including AFUDC, for the Battery Energy Storage System Project. The project is comprised of three 50 MW, four-hour battery facilities. Two facilities are anticipated to be in- service in late 2025 and the third facility in 2026.

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

In 2025, capital investment, including AFUDC, is expected to be $480 million (2024 – $487 million). NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.

ENVIRONMENTAL LEGISLATION AND REGULATIONS

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province. NSPI continues to work with both levels of government to comply with these laws and regulations to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated compliance will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPI’s operations and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management” section. Recent developments related to provincial and federal environmental laws and regulations are outlined below.

Clean Electricity Regulations (“CER”):

On December 17, 2024, Environment and Climate Change Canada released a finalized version of the CER. The CER establish performance standards to further limit greenhouse gas (“GHG”) emissions from fossil fuel-generated electricity starting in 2035 and help facilitate the Government of Canada’s intention of achieving a net-zero electricity grid by 2050. Compliance with the finalized version of the CER is not anticipated to require significant capital investment incremental to achieve the 2030 targets as NSPI’s planned capital investment during this period is driven by the Province’s goals to transition off coal and reach 80 per cent renewable electricity sales by 2030.

 

22		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

Nova Scotia Energy Reform Act:

On April 5, 2024, the Province enacted Bill 404 – Energy Reform (2024) Act. The legislation enacted the Energy and Regulatory Board Act, which established the Nova Scotia Energy Board (“NSEB”). The NSEB is a new board which will regulate energy and utility entities in Nova Scotia, with a mandate of increased focus on meeting energy transition demands. The legislation also enacts the More Access to Energy Act, which provides for the establishment of and phased transition to the Nova Scotia Independent Energy System Operator. NSPI is fully engaged in supporting the Province on these initiatives.

RER:

On May 26, 2023, NSPI initiated an appeal, through a proceeding with the UARB, of the $10 million penalty levied on NSPI by the Province for non-compliance with the RER compliance period ending in 2022. The hearing for the matter is currently scheduled for June 2025.

NSPML

Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.

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

The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. NLH’s NS Block delivery obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project agreements.

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

On November 29, 2024, NSPML received approval from the UARB to collect up to $197 million in 2025 from NSPI; which includes $158 million for the recovery of costs associated with the Maritime Link, and $39 million associated with the additional FLG debt and financing costs discussed in the NSPI section above. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no holdback recorded for the year ended December 31, 2024. NSPML expects to file an application to terminate the holdback mechanism in early 2025.

NSPML does not anticipate any significant capital investment in 2025.

Gas Utilities and Infrastructure

The Gas Utilities and Infrastructure segment includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s equity investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern US.

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the 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

With $3.1 billion USD of assets and approximately 508,000 customers, the PGS system includes 25,240 kilometres of natural gas mains and 14,530 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in 2024.

The approved ROE range for PGS is 9.15 per cent to 11.15 per cent based on an allowed equity capital structure of 54.7 per cent. An ROE of 10.15 per cent is used for the calculation of return on investments for clauses.

PGS anticipates earning near the bottom of its allowed ROE range in 2025 as a result of the continued investments across Florida to maintain reliability and service new customers. Capital investments are expected to outpace revenue growth. USD arnings 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.

 

EMERA 2024 ANNUAL REPORT		23

Management’s Discussion and Analysis

 

On January 30, 2025, PGS notified the FPSC of its intent to seek a base rate increase effective January 2026, reflecting a revenue requirement of approximately $90 to $110 million USD and subsequent year adjustment for 2027 of approximately

$25 to $40 million USD. PGS’ proposed rates support on-going growth in Florida and a continued commitment to delivering safe and reliable service to PGS customers. The filing range amounts are estimates until PGS files its detailed case in March 2025. The FPSC is scheduled to hear the case in 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

With $1.5 billion USD of assets and approximately 550,000 customers, NMGC’s system includes approximately 2,405 kilometres of transmission pipelines and 17,810 kilometres of distribution pipelines. Annual natural gas throughput was approximately 1 billion therms in 2024.

The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per cent.

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 October 2025.

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

Other Electric Utilities

Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island, and an equity investment in Lucelec on the island of St. Lucia.

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.

BLPC

With $538 million USD of assets and approximately 135,000 customers, BLPC owns 243 MW of generating capacity, of which 96 per cent is oil-fired and 4 per cent is solar. BLPC owns approximately 188 kilometres of transmission facilities and 3,989 kilometres of distribution facilities. BLPC’s approved regulated return on rate base is 10 per cent.

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

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.

 

24		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023 decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. The appeal is currently scheduled to be heard in 2025.

BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the implementation of the licenses once enacted.

GBPC

With $340 million USD of assets and approximately 19,500 customers, GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 994 kilometres of distribution facilities. GBPC’s approved regulatory return on rate base is 8.52 per cent.

On August 1, 2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement, GBPC filed a rate plan proposal. Review of the rate application is expected to be completed in 2025.

On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian regulator, regulate GBPC. The GBPA has opposed the legislated removal of its regulatory authority over GBPC, citing conflict with the Hawksbill Creek Agreement, the 1955 agreement with the Bahamian government that provided for the development and administration of the Freeport area. Management expects the matter of regulatory jurisdiction over GBPC to be the subject of legal proceedings, however, does not foresee that the legislation or the outcome of such proceedings will have a material impact to Emera.

Other

The Other segment includes business operations that in a normal year 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.

Business operations in the Other segment include Corporate; Emera Energy Services (EES), a physical energy marketing and trading business; a 50 per cent joint venture interest in Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts; and Block Energy. In Q4 2024, Block Energy initiated the process to wind-up operations.

Corporate items included are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings and interest expense on corporate debt in both Canada and the US. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

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.

The adjusted net loss from the Other segment is expected to be lower in 2025 than 2024, due primarily to the wind-up of Block Energy in 2024.

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

 

EMERA 2024 ANNUAL REPORT		25

Management’s Discussion and Analysis

 

Consolidated Balance Sheet Highlights

Significant changes in the Consolidated Balance Sheets between December 31, 2023 and December 31, 2024 include:

 

millions of dollars		Total Increase (Decrease)				Increase (Decrease) due to held for sale classification (1)				Other Increase (Decrease)				Explanation of Other Increase (Decrease)
Assets
Cash and cash equivalents		$	(371	)		$	(8	)		$	(363	)		Decreased due to investment in PP&E, net repayments on committed credit facilities at Corporate and NSPI, repayment of short-term debt at TEC, retirement of long-term debt at Emera, TEC and New Mexico Gas Intermediate, Inc (“NMGI”), and dividends paid on Emera common stock. These were partially offset by cash from operations, proceeds from debt issuances at TEC and EUSHI Finance, Inc. (“EUSHI Finance”), proceeds received on the sale of the LIL equity interest and proceeds from common shares issued
Derivative instruments (current and long-term)			(74	)			(1	)			(73	)		Decreased due to reversal of 2023 contracts at EES, partially offset by higher commodity prices at NSPI
Regulatory assets (current and long-term)			322				(34	)			356			Increased due to higher storm costs recovery clause assets at TEC and NSPI, the effect of FX translation of Emera’s non- Canadian affiliates, and reclassification of early retired plant from PP&E to a regulatory asset at TEC. These were partially offset by decreased FAM balance at NSPI due to the NSPML refund, and decreased fuel clause recovery balance at TEC due to higher over-recoveries
Receivables and other assets (current and long-term)			70				(150	)			220			Increased due to higher cash collateral positions on derivative instruments and increased trade receivables as a result of higher commodity prices at EES, and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by lower gas transportation assets at EES and lower trade receivables at TEC
Assets held for sale (current and long- term), net of liabilities			973				973				—
PP&E, net of accumulated depreciation and amortization			1,792				(1,828	)			3,620			Increased due to capital additions in excess of depreciation and the effect of FX translation of Emera’s non-Canadian affiliates, partially offset by a reclassification of early retired plant to TEC capital cost recovery regulatory asset
Investments subject to significant influence			(748	)			—				(748	)		Decreased primarily due to sale of LIL equity interest
Goodwill			(13	)			(303	)			290			Increased due to the effect of FX translation of Emera’s non-Canadian affiliates, partially offset by the non-cash impairment charge recognized primarily related to NMGC

 

(1)	On August 5, 2024, Emera announced the sale of NMGC. As at December 31, 2024 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 consolidated financial statements.

 

26		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

millions of dollars		Total Increase (Decrease)				Increase (Decrease) due to held for sale classification (1)				Other Increase (Decrease)				Explanation of Other Increase (Decrease)
Liabilities and Equity
Short-term debt and long- term debt (including current portion)		$	9			$	(742	)		$	751			Increased due the effect of FX translation of Emera’s non-Canadian affiliates, proceeds from long-term debt issuance at TEC, and issuance of junior subordinated notes at EUSHI Finance. These were partially offset by repayment of Emera’s committed credit facilities using the LIL transaction proceeds, repayment of short-term debt at TEC and NSPI, and retirement of long-term debt at Corporate, TEC, and NMGI
Accounts payable			538				(131	)			669			Increased due to storm cost payable at TEC, the effect of FX translation of Emera’s non-Canadian affiliates, and increased commodity prices at EES
Deferred income tax liabilities, net of deferred income tax assets			(205	)			(167	)			(38	)		No significant change after removing impact of held for sale classification
Derivative instruments (current and long-term)			113				(1	)			114			Increased due to new contracts in 2024 and changes in existing positions at EES, higher FX forward liability at Corporate due to changes in the FX hedges, partially offset by higher commodity prices and settlements of derivative instruments at NSPI
Regulatory liabilities (current and long-term)			108				(284	)			392			Increased due to effect of FX translation of Emera’s non- Canadian affiliates and recognition of fuel cost recovery liabilities at TEC and NSPI due to over-recovery of fuel costs
Other liabilities (current and long-term)			152				(34	)			186			Increased due the effect of FX translation of Emera’s non-Canadian affiliates and higher accrued interest on long-term debt at NSPI
Common stock			580				—				580			Increased due to shares issued
Accumulated other comprehensive income			956				—				956			Increased due to the effect of FX translation of Emera’s non-Canadian affiliates
Retained earnings			(335	)			—				(335	)		Decreased due to dividends paid in excess of net income

 

(1)	On August 5, 2024, Emera announced the sale of NMGC. As at December 31, 2024 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 consolidated financial statements.

Other Developments

CANADIAN TAX LEGISLATION CHANGES

On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March 28, 2023, was enacted. Bill C-59 includes the EIFEL regime, which is effective January 1, 2024. EIFEL applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of EBITDA for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be carried forward indefinitely. During 2024, the Company incurred $185 million of interest and financing expenses in connection with a specific financing structure. The interest and financing expenses related to the financing structure as well as $88 million of other interest and financing expenses are expected to be denied under the EIFEL regime. It was determined that the Company is more likely than not to realize the tax benefit of the denied interest and financing expenses in future periods and therefore a $79 million deferred income tax asset has been recorded as at December 31, 2024.

PENDING SALE OF NMGC

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

 

EMERA 2024 ANNUAL REPORT		27

Management’s Discussion and Analysis

 

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

Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an additional loss for the estimated future transaction costs of $16 million ($12 million after-tax), in addition to incurred transaction costs of $9 million ($7 million after- tax) recorded in “Other Income, net” on the Consolidated Statements of Income in Q3 2024.

The Company will continue to record depreciation on the NMGC assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $26 million ($19 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through December 31, 2024.

INCREASE IN COMMON DIVIDEND

On September 18, 2024, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.90 from $2.87 per common share. The first payment was effective November 15, 2024.

SALE OF LIL EQUITY INTEREST

On June 4, 2024, Emera completed the sale of its 31.1 per cent LIL equity interest for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable is held at FV and included in the gain on sale, after transaction costs. As of December 31, 2024, the estimated FV of the escrow proceeds receivable is $25 million. In Q2 2024, a gain on sale, after tax and transaction costs, of $107 million, was included in the Other segment (the gain on sale, net of transaction costs of $182 million was recognized in “Other Income, net” on the Consolidated Statements of Income). In Q4 2024, Emera recognized a $22 million tax benefit due to the reversal of a prior year valuation allowance related to loss carryforwards applied against a portion of the taxable capital gain on the sale of LIL. This tax benefit was recorded in “Income Tax (Recovery) Expense” on the Consolidated Statements of Income in Q4 2024 and included in the Other segment. Proceeds from the sale were used to reduce corporate debt and fund investment in the Company’s regulated utility businesses.

APPOINTMENTS

BOARD OF DIRECTORS

Effective February 21, 2025, Karen Sheriff was appointed Chair of the Emera Board of Directors, succeeding Jackie Sheppard. Ms. Sheriff joined the Emera Board of Directors in February 2021 and since that time has served as a member of the Management Resources and Compensation Committee, the Risk and Sustainability Committee as well as Chair of the Nominating and Corporate Governance Committee.

Effective June 26, 2024, Carla Tully joined the Emera Board of Directors. Ms. Tully is the former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company. She also previously served as Executive Vice President and Managing Director of Renewable Energy at MAP Energy and held various senior leadership roles with AES Corporation.

Effective March 6, 2024, Brian J. Porter joined the Emera Board of Directors. Mr. Porter is the former President and Chief Executive Officer of The Bank of Nova Scotia (Scotiabank), a global bank operating in Canada and the Americas.

 

28		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

Financial Highlights

Florida Electric Utility

 

For the		Three months ended December 31								Year ended December 31
millions of USD (except as indicated)		2024				2023				2024				2023
Operating revenues – regulated electric		$	582			$	613			$	2,526			$	2,637
Regulated fuel for generation and purchased power		$	151			$	162			$	622			$	682
Contribution to consolidated adjusted net income		$	85			$	85			$	470			$	466
Contribution to consolidated adjusted net income – CAD		$	120			$	115			$	644			$	627
Charges related to wind-down costs and certain asset impairments, after-tax (1)		$	(2	)		$	—			$	(2	)		$	—
Contribution to consolidated net income		$	83			$	85			$	468			$	466
Contribution to consolidated net income – CAD		$	117			$	115			$	641			$	627
Average fuel costs in dollars per MWh		$	31			$	34			$	28			$	31

 

(1)	Net of income tax recovery of $1 million for the three months and year ended December 31, 2024.

The impact of the change in the FX rate increased CAD earnings and adjusted earnings for the three months and year ended December 31, 2024, by $3 million and $10 million, respectively.

NET INCOME

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

 

For the millions of USD		Three months ended December 31				Year ended December 31
Contribution to consolidated net income – 2023		$	85			$	466
Decreased operating revenues primarily due to decreased fuel recovery clause revenue, lower storm surcharge revenue (offset in OM&G), and the unfavourable load impact of Hurricane Milton, partially offset by customer growth and new base rates. Revenues were also impacted by favourable weather of $10 million quarter-over-quarter, and unfavourable weather of $10 million year-over-year			(31	)			(111	)
Decreased fuel for generation and purchased power due to lower natural gas prices			11				60
Decreased OM&G due to lower storm cost recognition (offset in revenue), partially offset by the timing of deferred clause recoveries and higher solar operations, labour, and software maintenance costs			16				47
Increased depreciation and amortization due to additions to facilities and generation projects placed in service			(9	)			(32	)
Decreased interest expense year-over-year due to lower borrowings			—				7
Decreased state and municipal taxes due to lower retail sales tax, partially offset by higher property taxes			4				14
Decreased income tax expense year-over-year due to increased production tax credits related to solar facilities			—				18
Other			7				(1	)
Contribution to consolidated net income – 2024		$	83			$	468

 

EMERA 2024 ANNUAL REPORT		29

Management’s Discussion and Analysis

 

OPERATING REVENUES – REGULATED ELECTRIC

Annual electric revenues and sales volumes are summarized in the following table by customer class:

 

		Electric Revenues (millions of USD)								Electric Sales Volumes (Gigawatt hours (“GWh”))
		2024				2023				2024				2023
Residential		$	1,507			$	1,711				10,269				10,307
Commercial			686				803				6,481				6,462
Industrial			162				203				2,019				2,082
Other (1)			171				(80	)			2,276				2,194
Total		$	2,526			$	2,637				21,045				21,045

 

(1)	Other includes regulatory deferrals related to clauses, sales to public authorities, off-system sales to other utilities.

REGULATED FUEL FOR GENERATION AND PURCHASED POWER

Annual production volumes are summarized in the following table:

 

		Production Volumes (GWh)
		2024				2023
Natural gas			18,027				17,843
Solar			2,250				1,748
Purchased power			1,569				1,443
Coal			32				744
Total			21,878				21,778

TEC’s fuel costs are affected by commodity prices and generation mix that is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on first (renewable energy from solar or battery storage), such that the incremental cost of production increases as sales volumes increase. Generation mix may also be affected by plant outages, plant performance, availability of lower priced short-term purchased power, availability of renewable solar generation, and compliance with environmental standards and regulations.

REGULATORY ENVIRONMENT

TEC is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC, the FPSC, or other interested parties. For further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to note 7 in the consolidated financial statements.

Canadian Electric Utilities

On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to the “Other Developments” section.

 

For the		Three months ended December 31								Year ended December 31
millions of dollars (except as indicated)		2024				2023				2024				2023
Operating revenues – regulated electric		$	479			$	439			$	1,855			$	1,671
Regulated fuel for generation and purchased power (1)		$	(216	)		$	234			$	509			$	777
Contribution to consolidated net income		$	77			$	68			$	232			$	247
Average fuel costs in dollars per MWh (2)		$	(73	)		$	81			$	45			$	70

 

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

(2)

2024 Average fuel costs include the $486 million NSPML Refund which decreased average fuel costs by $164 per MWh and $43 per MWh for the three months and year ended December 31, 2024, respectively. Average fuel costs for the year ended December 31, 2023 include reversal of the $166 million of the Nova Scotia Cap-and-Trade Program provision which decreased average fuel costs by $15 per MWh. For more information the NSPML Refund and the Nova Scotia Cap-and-Trade Program provision reversal, refer to note 7 in the consolidated financial statements.

 

30		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

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

 

For the		Three months ended December 31								Year ended December 31
millions of dollars		2024				2023				2024				2023
NSPI		$	71			$	40			$	160			$	141
Equity investment in NSPML			6				12				44				46
Equity investment in LIL			—				16				28				60
Contribution to consolidated net income		$	77			$	68			$	232			$	247

NET INCOME

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

 

For the millions of dollars		Three months ended December 31				Year ended December 31
Contribution to consolidated net income – 2023		$	68			$	247
Increased operating revenues at NSPI due to new rates. Year-over-year also due to changes in fuel cost recovery methodology for an industrial customer in 2023 (1)			40				184
Decreased regulated fuel for generation and purchased power at NSPI due to the NSPML Refund (1) and decreased commodity prices, partially offset by change in generation mix and increased sales volumes. Year-over-year decrease was partially offset by the reversal of the Nova Scotia Cap-and-Trade Program provision (1) in 2023			450				268
Increased FAM deferral at NSPI primarily due to the NSPML Refund.(1) Year-over-year increase also due to changes in the fuel cost recovery methodology for an industrial customer in 2023 and under-recovery of fuel costs in 2023, partially offset by the reversal of the Nova Scotia Cap-and- Trade Program provision (1) in 2023			(484	)			(428	)
Increased OM&G due to a lower storm cost deferral, and higher demand side management program costs at NSPI			(8	)			(24	)
Decreased income from equity investments due to the sale of LIL			(16	)			(34	)
Increased income tax recovery at NSPI due to the utilization of tax loss carryforwards offset to a regulatory deferred income tax liability, partially offset by decreased tax deductions in excess of accounting depreciation related to property, plant and equipment			40				32
Other			(13	)			(13	)
Contribution to consolidated net income – 2024		$	77			$	232

 

(1)	For more information on the changes in fuel cost recovery methodology for an industrial customer in 2023, the $486 million NSPML Refund, and the $166 million reversal of the Nova Scotia Cap-and-Trade Program provision, refer to note 7 in the consolidated financial statements.

NSPI

OPERATING REVENUES – REGULATED ELECTRIC

Annual electric revenues and sales volumes are summarized in the following tables by customer class:

 

		Electric Revenues (millions of dollars)								Electric Sales Volumes (GWh)
		2024				2023				2024				2023
Residential		$	997			$	910				5,096				4,986
Commercial			499				463				3,046				3,053
Industrial			276				219				2,217				2,164
Other			41				41				222				239
Total		$	1,813			$	1,633				10,581				10,442

 

EMERA 2024 ANNUAL REPORT		31

Management’s Discussion and Analysis

 

REGULATED FUEL FOR GENERATION AND PURCHASED POWER

Annual production volumes are summarized in the following table:

 

		Production Volumes (GWh)
		2024				2023
Coal			3,347				3,086
Natural gas			2,317				1,946
Purchased power			620				881
Petcoke			374				553
Oil			132				145
Total non-renewables			6,790				6,611
Purchased power – IPP, COMFIT and imports			3,464				3,251
Wind, hydro and solar			932				1,149
Biomass			140				128
Total renewables			4,536				4,528
Total production volumes			11,326				11,139

NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after renewable energy from IPPs including COMFIT participants, for which NSPI has power purchase agreements in place, and the NS Block of energy, including the Supplemental Energy Block, which carries no additional fuel cost outside of the UARB approved annual assessments paid to NSPML for the use of the Maritime Link.

Generation mix may also be affected by plant outages, carbon pricing programs, including the Nova Scotia Output-Based Pricing System, availability of renewable generation, availability of energy from the NS Block, plant performance, and compliance with environmental regulations.

REGULATORY ENVIRONMENT – NSPI

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request. For further details on NSPI’s regulatory environment and recovery mechanisms, refer to note 7 in the consolidated financial statements.

Gas Utilities and Infrastructure

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

 

For the		Three months ended December 31								Year ended December 31
millions of USD (except as indicated)		2024				2023				2024				2023
Operating revenues – regulated gas (1)		$	317			$	290			$	1,160			$	1,114
Operating revenues – non-regulated			3				3				15				15
Total operating revenue		$	320			$	293			$	1,175			$	1,129
Regulated cost of natural gas		$	81			$	99			$	289			$	391
Contribution to consolidated adjusted net income		$	61			$	43			$	194			$	158
Contribution to consolidated adjusted net income – CAD		$	87			$	59			$	267			$	214
Charges related to the pending sale of NMGC, after-tax (2)		$	—			$	—			$	(6	)		$	—
Contribution to consolidated net income		$	61			$	43			$	188			$	158
Contribution to consolidated net income – CAD		$	87			$	59			$	259			$	214

 

(1)

Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2023 – $11 million) for the three months ended December 31, 2024 and $46 million (2023 – $46 million) for the year ended December 31 2024; however, it is excluded from the gas revenues and cost of natural gas analysis below.

(2)	Includes an other impairment charge, net of income tax recovery of nil and $2 million for the three months and the year ended December 31, 2024, respectively.

 

32		EMERA 2024 ANNUAL REPORT

Management’s Discussion and Analysis

 

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

 

For the		Three months ended December 31								Year ended December 31
millions of USD		2024				2023				2024				2023
PGS		$	28			$	21			$	120			$	79
NMGC			23				14				39				43
Other			10				8				35				36
Contribution to consolidated adjusted net income		$	61			$	43			$	194			$	158

Impact of the change in the FX rate increased CAD earnings and adjusted earnings for the three months and year ended December 31, 2024, by $3 million and $4 million respectively.

NET INCOME

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

 

For the millions of USD		Three months ended December 31				Year ended December 31
Contribution to consolidated net income – 2023		$	43			$	158
Increased gas revenues due to new base rates at PGS and NMGC, and customer growth at PGS, partially offset by lower fuel revenues at NMGC			27				54
Decreased asset optimization revenues at NMGC			—				(8	)
Decreased cost of natural gas due to lower natural gas prices primarily at NMGC			18				102
Increased OM&G primarily due to the timing of deferred clause recoveries and higher labour cost at PGS			(5	)			(31	)
Increased depreciation primarily due to asset growth at PGS and the effect of reversal of accumulated depreciation in 2023 as a result of the 2021 rate case settlement at PGS			(13	)			(39	)
Increased interest expense, net year-over-year, primarily due to higher interest rates and increased borrowings to support ongoing operations and capital investments primarily at PGS			1				(15	)
Increased income tax expense primarily due to increased income before provision for income taxes at PGS. Quarter-over-quarter increase also due to increased income before provision for income taxes at NMGC			(13	)			(21	)
Charges related to the pending sale of NMGC, after-tax			—				(6	)
Other			3				(6	)
Contribution to consolidated net income – 2024		$	61			$	188

OPERATING REVENUES – REGULATED GAS

Annual gas revenues and sales volumes are summarized in the following tables by customer class:

 

		Gas Revenues (millions of USD)								Gas Volumes (millions of Therms)
		2024				2023				2024				2023
Residential		$	520			$	537				410				414
Commercial			362				315				824				839
Industrial (1)			69				69				1,620				1,615
Other (2)			163				147				278				266
Total (3)		$	1,114			$	1,068				3,132				3,134

 

(1)	Industrial gas revenue includes sales to power generation customers.

(2)	Other gas revenue includes off-system sales to other utilities and various other items.

(3)	Total gas revenue excludes $46 million of finance income from Brunswick Pipeline (2023 – $46 million).

 

EMERA 2024 ANNUAL REPORT		33