Form 6-K - Report of foreign issuer [Rules 13a-16 and 15d-16]

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 6-K

 

 

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of May, 2024

Commission File Number: 000-54516

 

 

Emera Incorporated

(Exact name of registrant as specified in its charter)

 

 

5151 Terminal Road

Halifax NS B3J 1A1

Canada

(Address of principal executive offices)

 

 

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ☐     Form 40-F ☑

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

		EMERA INCORPORATED
Date: May 15, 2024		By:				/s/ Brian Curry
						Name: Brian Curry
						Title: Corporate Secretary

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EXHIBIT INDEX

 

Exhibit No.		Description
99.1		Emera Incorporated Management’s Discussion and Analysis of financial position and results of operations as at and for the three month period ended March 31, 2024
99.2		Emera Incorporated Unaudited Condensed Consolidated Interim Financial Statements for the three month period ended March 31, 2024
99.3		Emera Incorporated Earnings Coverage Ratio for the twelve months ended March 31, 2024
99.4		Emera Incorporated Media Release dated May 13, 2024
99.5		Form 52-109F2 Certification of Interim Filings by the Chief Executive Officer
99.6		Form 52-109F2 Certification of Interim Filings by the Chief Financial Officer

Exhibit 99.1

 

Management’s Discussion & Analysis

As at May 13, 2024

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the “Company”) during the first quarter of 2024 relative to the same quarter in 2023; and its financial position as at March 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 unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2024; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2023. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR+ at www.sedarplus.ca.

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At March 31, 2024, Emera’s rate-regulated subsidiaries and investments include:

 

Emera 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
Labrador Island Link Limited Partnership (“LIL”)		Newfoundland and Labrador Board of Commissioners of Public Utilities
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.

 

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TABLE OF CONTENTS

 

Forward-looking Information		2
Introduction and Strategic Overview		3
Non-GAAP Financial Measures and Ratios		4
Consolidated Financial Review		6
Significant Items Affecting Earnings		6
Consolidated Financial Highlights		6
Consolidated Income Statement Highlights		7
Business Overview and Outlook		9
Florida Electric Utility		9
Canadian Electric Utilities		10
Gas Utilities and Infrastructure		11
Other Electric Utilities		12
Other		12
Consolidated Balance Sheet Highlights		13
Other Developments		13
Financial Highlights		14
Florida Electric Utility		14
Canadian Electric Utilities		14

Gas Utilities and Infrastructure			15
Other Electric Utilities			16
Other			17
Liquidity and Capital Resources			18
Consolidated Cash Flow Highlights			19
Contractual Obligations			20
Debt Management			21
Guarantees and Letters of Credit			22
Outstanding Stock Data			22
Transactions with Related Parties			22
Risk Management including Financial Instruments			23
Disclosure and Internal Controls			23
Critical Accounting Estimates			24
Changes in Accounting Policies and Practices			24
Future Accounting Pronouncements			24
Summary of Quarterly Results			25

 

 

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, carbon dioxide emissions reduction goals, 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.

The 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; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; changes in credit ratings; future dividend 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; global climate change; 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.

 

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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

Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the United States (“US”) and the Caribbean. Cost-of-service utilities provide essential electric and gas services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its customers.

The majority of Emera’s investments in rate-regulated businesses are located in Florida with other investments in Nova Scotia, New Mexico and the Caribbean. Emera’s portfolio of regulated utilities intends to provide reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera’s capital investment plan is approximately $9 billion over the 2024 through 2026 period with approximately $2 billion of additional potential capital investments over the same period. The capital investment plan and additional potential capital result in an anticipated compound annual rate base growth in the range of approximately 7 per cent to 8 per cent through 2026. The capital investment plan includes significant investments across the portfolio in renewable and cleaner generation, reliability and system integrity investments, infrastructure modernization, infrastructure expansion to meet the needs of new and existing customers, and technologies to better support the business and customer experiences. It is anticipated that approximately 75 per cent of Emera’s $9 billion capital investment plan over the 2024 through 2026 period will be made in Florida.

Emera’s capital investment plan is being funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity, and select asset sales. Generally, equity requirements in support of the Company’s capital investment plan 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 at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a priority of the Company.

Emera has provided annual dividend growth guidance of four to five per cent through 2026. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.

Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market (“MTM”) adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income and cash flows are impacted by movements in the USD relative to the CAD. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Energy markets worldwide are experiencing significant change and Emera is well-positioned to continue to respond to shifting customer demands and meet the challenges of digitization, decarbonization and decentralized generation, within complex regulatory environments.

 

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Customers depend on energy and are looking for more choice, better control, and greater reliability. The costs of decentralized generation and storage have become more competitive and advancing technologies are transforming how utilities operate and interact with customers. Concurrently, climate change and the increased frequency of extreme weather events are shaping government energy policy. This is also creating a need to replace aging infrastructure and make investments to protect and harden energy systems to deliver energy reliability and system resiliency. These factors combined with inflation, higher interest rates and higher cost of capital increase energy costs, and thus customer rates, at a time when affordability is a challenge.

Emera’s strategy is centred on delivering value for customers, and in doing so creating value for shareholders. This includes:

 

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investing in cleaner and renewable sources of energy, in the related transmission assets, and in energy storage needed to support intermittent renewables;

 

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supporting increasing demand from customers and the ongoing electrification of other sectors;

 

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improving system reliability and resiliency, including replacing aging infrastructure and expanding systems to service new customers; and

 

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investing in new internal and customer-facing technologies for improved cost efficiency and better customer experiences.

Building on its decarbonization progress, Emera is continuing its efforts towards clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a visible path to Emera’s interim carbon goals. With existing technologies and resources, and subject to supportive government and regulatory decisions, Emera is working to achieve the following goals compared to corresponding 2005 levels:

 

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A 55 per cent reduction in carbon dioxide emissions by 2025.

 

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The retirement of Emera’s last existing coal unit no later than 2040.

 

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An 80 per cent reduction in carbon dioxide emissions by 2040.

Achieving the above climate goals on these timelines is subject to the Company’s regulatory obligations and other external factors beyond Emera’s control.

Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships.

NON-GAAP FINANCIAL MEASURES AND RATIOS

Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. The non-GAAP measures and ratios are calculated by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. These measures and ratios are discussed and reconciled below.

 

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Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per Common Share (“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income

Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the effect of MTM adjustments as 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. Management therefore excludes MTM adjustments for evaluation of performance and incentive compensation.

The MTM adjustments are related to the following:

 

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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;

 

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

 

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equity securities held in BLPC and Emera Energy; and

 

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

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

Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in Emera’s 2023 annual MD&A.

The following reconciles net income attributable to common shareholders to adjusted net income:

 

For the		Three months ended March 31
millions of dollars (except per share amounts)		2024				2023
Net income attributable to common shareholders		$	207			$	560
MTM (loss) gain, after-tax (1)			(9)				292
Adjusted net income		$	216			$	268
EPS – basic		$	0.73			$	2.07
Adjusted EPS – basic		$	0.76			$	0.99
(1) Net of income tax recovery of $4 million for the three months ended March 31, 2024 (2023 – $119 million expense).

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.

Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments.

 

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The following is a reconciliation of net income to EBITDA and Adjusted EBITDA:

 

For the		Three months ended March 31
millions of dollars			2024				2023
Net income (1)		$	225			$	576
Interest expense, net			246				226
Income tax expense			28				162
Depreciation and amortization			283				256
EBITDA		$	782			$	1,220
MTM (loss) gain, excluding income tax			(13)				411
Adjusted EBITDA		$	795			$	809

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

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Earnings Impact of MTM Loss, After-Tax

The Q1 2023 MTM gain, after-tax, of $292 million decreased $301 million to a MTM loss, after-tax of $9 million in Q1 2024 due to changes in existing positions at Emera Energy Services (“EES”), partially offset by lower amortization of gas transportation assets at EES.

Consolidated Financial Highlights

 

For the		Three months ended March 31
millions of dollars			2024				2023
Adjusted Net Income
Florida Electric Utility		$	85			$	107
Canadian Electric Utilities			87				92
Gas Utilities and Infrastructure			98				94
Other Electric Utilities			9				4
Other			(63)				(29	)
Adjusted net income		$	216			$	268
MTM (loss) gain, after-tax			(9)				292
Net income attributable to common shareholders		$	207			$	560

 

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

 

For the millions of dollars			Three months ended March 31
Adjusted net income – 2023			$     268
Operating Unit Performance
Decreased earnings at TEC due to unfavourable weather, increased operating, maintenance and general expenses (“OM&G”) and higher depreciation, partially offset by customer growth and new base rates			(22)
Decreased earnings at NMGC due lower asset optimization revenues and higher OM&G			(14)
Decreased earnings at NSPI due to increased OM&G, partially offset by higher revenues due to new rates and increased residential sales volume			(11)
Decreased earnings at EES due to less favourable market conditions			(10)
Increased earnings at PGS due to new base rates, partially offset by higher interest expense, OM&G and depreciation expense			21
Increased income from equity investments at NSPML primarily due to the Maritime Link holdback recognized in Q1 2023			5
Corporate
Increased OM&G, pre-tax, primarily due to timing of long-term compensation hedges			(19)
Increased interest expense, pre-tax, due to increased total debt			(9)
Increased income tax recovery due to increased losses before provision for income taxes			7
Adjusted net income – 2024			$      216

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

 

For the							Three months ended March 31
millions of dollars							2024				2023
Operating cash flow before changes in working capital						$	631			$	654
Change in working capital							(62)				(201)
Operating cash flow						$	569			$	453
Investing cash flow						$	(604)			$	(640)
Financing cash flow						$	(288)			$	153
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
As at millions of dollars							March 31 2024				December 31 2023
Total assets						$	40,031			$	39,480
Total long-term debt (including current portion)						$	18,491			$	18,365
Consolidated Income Statement Highlights
For the		Three months ended March 31
millions of dollars (except per share amounts)			2024				2023				Variance
Operating revenues		$	2,018			$	2,433			$	(415)
Operating expenses			1,581				1,539				(42)
Income from operations		$	437			$	894			$	(457)
Interest expense, net		$	246			$	226			$	(20)
Income tax expense		$	28			$	162			$	134
Net income attributable to common shareholders		$	207			$	560			$	(353)
Adjusted net income		$	216			$	268			$	(52)
Weighted average shares of common stock outstanding (in millions)			285.1				270.7				14.4
EPS – basic		$	0.73			$	2.07			$	(1.34)
EPS – diluted		$	0.73			$	2.07			$	(1.34)
Adjusted EPS – basic		$	0.76			$	0.99			$	(0.23)
Dividends per common share declared		$	0.7175			$	0.6900			$	0.0275
Adjusted EBITDA		$	795			$	809			$	(14)

 

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Operating Revenues

For Q1 2024, operating revenues decreased $415 million compared to Q1 2023 and, excluding increased MTM loss of $410 million, decreased $5 million. The decrease was due to lower fuel and asset optimization revenues at NMGC; decreased marketing and trading margin at EES; and unfavourable weather at TEC. These decreases were partially offset by new base rates at NSPI, PGS and TEC; and customer growth at TEC and NSPI.

Operating Expenses

For Q1 2024, operating expenses increased $42 million compared to Q1 2023. This increase was due to higher OM&G due to the timing of long-term compensation hedges at Corporate, higher transmission and distribution costs at TEC and NSPI, higher labour costs at PGS and NMGC, storm restoration costs recognized at TEC; higher fuel expense at NSPI and higher depreciation at TEC and PGS. These increases were partially offset by lower cost of natural gas at NMGC; and the Nova Scotia Renewable Electric Regulations (“RER”) penalty recognized at NSPI in Q1 2023.

Interest Expense, Net

For Q1 2024, interest expense, net increased $20 million compared to Q1 2023 due to higher interest rates at PGS and increased borrowings to support ongoing operations at Corporate and PGS.

Income Tax Expense

For Q1 2024, income tax expense decreased $134 million compared to Q1 2023 due to decreased income before provision for income taxes.

Net Income and Adjusted Net Income

For Q1 2024, the increase in net income attributable to common shareholders, compared to Q1 2023, was unfavourably impacted by the $301 million increase in MTM loss, after-tax. Excluding this change, adjusted net income decreased $52 million, primarily due to lower earnings at TEC, NMGC, NSPI, and EES; increased Corporate OM&G due to the timing of long-term compensation hedges; and increased Corporate interest expense due to increased total debt. These were partially offset by higher earnings at PGS and NSPML; and higher income tax recovery at Corporate.

Earnings and Adjusted EPS – Basic

Earnings and Adjusted EPS – basic were lower for Q1 2024 compared to Q1 2023 due to decreased earnings, as discussed above, and an increase in weighted average shares outstanding.

Effect of Foreign Currency Translation

Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2023 annual MD&A.

The relevant CAD/USD exchange rates for 2024 and 2023 are as follows:

 

		Three months ended March 31								Year ended December 31
		2024				2023				2023
Weighted average CAD/USD		$	1.35			$	1.34			$	1.35
Period end CAD/USD exchange rate		$	1.36			$	1.35			$	1.32

 

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

 

For the		Three months ended March 31
millions of USD		2024				2023
Florida Electric Utility		$	63			$	79
Gas Utilities and Infrastructure (1)			69				65
Other Electric Utilities			7				3
Other segment (2)			-				7
Total (3)		$	139			$	154

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

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

(3) Excludes $1 million USD in MTM loss, after-tax, for the three months ended March 31, 2024 (2023 – $232 million USD MTM gain, after-tax).

The translation impact of the change in FX rates on foreign denominated earnings was minimal in Q1 2024 compared to the same period in 2023. The Corporate FX hedges used to mitigate translation risk of USD earnings included in the Other segment decreased net income by $2 million and decreased adjusted net income by $1 million in Q1 2024 compared to the same period in 2023.

BUSINESS OVERVIEW AND OUTLOOK

There have been no material changes in Emera’s business overview and outlook from the Company’s 2023 annual MD&A, except for the updates as disclosed below. Emera’s results have been impacted by macroeconomic conditions, specifically higher interest rates as well as other impacts of inflation. These conditions are likely to continue for the near term. For information on general economic risk, including interest rate and inflation risk, refer to the “Enterprise Risk and Risk Management – General Economic Risk” in Emera’s 2023 annual MD&A. For details on Emera’s reportable segments, refer to note 1 of the Q1 2024 unaudited condensed consolidated interim financial statements.

Florida Electric Utility

TEC anticipates earning towards the lower end of the ROE range in 2024 but expects earnings to be higher than 2023. Normalizing 2023 for weather, TEC sales volumes in 2024 are projected to be higher than 2023 due to customer growth. TEC expects customer growth rates in 2024 to be comparable to 2023, reflective of the expected economic growth in Florida.

On April 24, 2024, the US Environmental Protection Agency issued its final rules for electric generating units. The rules include new greenhouse gas standards, which apply only to existing coal-fired and new natural gas electric generating units and will therefore have limited impact on TEC. They also include new coal combustion residual (“CCR”) rules. TEC is currently evaluating the impact of the new CCR rule at the Big Bend Power Station. TEC expects that prudently incurred costs to comply with new environmental regulations would be eligible for recovery from customers through either the Environmental Cost Recovery Clause or base rates.

On April 2, 2024, TEC requested a base rate increase, reflecting an increased revenue requirement of $297 million USD, effective January 1, 2025, and additional adjustments of $100 million USD and $72 million USD for 2026 and 2027, respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and other resiliency and reliability projects. A decision by the FPSC is expected by the end of 2024.

On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $137 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction is due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected 2024 costs in the fall of 2023. On May 7, 2024, the FPSC voted to approve the mid-course adjustment.

 

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In 2024, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2023 – $1.3 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, grid modernization, storm hardening investments and building resilience.

Canadian Electric Utilities

NSPI

NSPI expects earnings in 2024 to be consistent with 2023 and anticipates earning below its allowed ROE range in 2024. Sales volumes are expected to be higher in 2024 than 2023.

On April 30, 2024, NSPI applied to the UARB for recovery of $22 million of major storm restoration costs deferred to NSPI’s UARB approved storm rider in 2023. If approved, recovery of the 2023 costs deferred in the storm rider would begin January 1, 2025 over the 12 months of 2025. A decision from the UARB is expected by the end of 2024.

On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, which will result in a corresponding decrease of the FAM regulatory asset when recorded in Q2 2024. NSPI will collect the amortization and financing costs related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period beginning in Q2 2024, and remit those amounts to Invest Nova Scotia as collected.

In 2024, capital investment, including AFUDC, is expected to be $480 million (2023 – $451 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 of Nova Scotia (the “Province”). For further discussion on environmental legislation and regulations and associated risks, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Enterprise Risk and Risk Management” sections respectively of Emera’s 2023 annual MD&A. Recent developments related to provincial and federal environmental laws and regulations are outlined below.

Nova Scotia Energy Reform Act:

On April 5, 2024, the Province enacted Bill 404 - Energy Reform (2024) Act. This legislation implements certain recommendations made by the Clean Electricity Solutions Task Force, which was established by the Province to advise the provincial government on Nova Scotia’s transition away from coal to more renewable sources of energy. 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 working with 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 2024, however additional process steps related to the disclosure of evidence are expected to impact the timeline of the proceeding. NSPI is awaiting further communication from the UARB on the updated timeline and the delays could impact the UARB’s ability to issue a decision on the matter in 2024.

 

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NSPML

Equity earnings from NSPML in 2024 are expected to be consistent with 2023.

On December 21, 2023, NSPML received approval to collect up to $164 million in 2024 from NSPI for the recovery of costs associated with the Maritime Link subject to a holdback of $4 million per month. There was no holdback recorded in Q1 2024. NSPML expects to file an application to terminate the holdback mechanism in 2024.

NSPML does not anticipate any significant capital investment in 2024.

LIL

Equity earnings from the LIL are expected to be higher in 2024, compared to 2023, resulting from an increased investment in LIL planned for 2024.

Equity earnings from the LIL investment are based on the book value of the equity investment and the approved ROE of 8.5 per cent. Emera’s current equity investment is $750 million, comprised of $410 million in equity contribution and $340 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be $650 million once the final costing has been confirmed by Nalcor Energy (“Nalcor”) to determine the amount of the remaining investment.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2024 than 2023, primarily due to a base rate increase effective January 2024 at PGS and an expected base rate increase effective October 2024 at NMGC, partially offset by increased operating expenses and lower asset optimization revenues expected at NMGC.

PGS expects rate base to be higher than in 2023 and anticipates earning within its allowed ROE range in 2024. USD earnings for 2024 are expected to be significantly higher than in 2023 primarily due to higher revenue from new base rates in support of significant ongoing system investment and continued customer growth in 2024, which is expected to be consistent with Florida’s population growth rates.

NMGC expects 2024 rate base growth to be higher than 2023, with slightly lower USD earnings as a result of increased operating expenses and lower asset optimization revenues, partially offset by higher revenue from expected new base rates, effective October 2024. NMGC anticipates earning near its authorized ROE in 2024. Customer growth is expected to be consistent with historical trends.

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective in October 2024. On March 1, 2024, NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30 million USD in annual base revenues and maintaining NMGC’s ROE at 9.375 per cent. The proposed rates reflect the recovery of increased operating costs and capital investments in pipeline projects and related infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw, and to not reassert in a future rate case application, its request for a regulatory asset for costs associated with its application for a certificate of public convenience and necessary for a liquified natural gas facility in New Mexico. The settlement is subject to NMPRC approval. The NMPRC is expected to rule on the settlement in Q3 2024.

In 2024, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $445 million USD (2023 – $495 million USD), including AFUDC. PGS and NMGC will make investments to maintain the reliability of their systems and support customer growth.

 

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Other Electric Utilities

Other Electric Utilities’ USD earnings in 2024 are expected to increase over the prior year due to higher sales volumes at BLPC.

On May 9, 2024, the Government of Bahamas passed the ‘Electricity Bill 2024’, subject to Royal Assent, to take effect June 1, 2024. The bill purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian regulator, regulate GBPC. Management is assessing the implications of the legislation, but do not foresee it having a material impact to Emera.

In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.

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

In 2024, capital investment in the Other Electric Utilities segment is expected to be approximately $80 million USD (2023 – $47 million USD), primarily in projects to support system reliability.

Other

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 within its guidance range of $15 to $30 million USD.

The adjusted net loss from the Other segment is expected to be higher in 2024 due to increased interest expense, higher Corporate OM&G, and a lower contribution to net income from Emera Energy primarily as a result of one-time investment tax credits at Bear Swamp in 2023.

The Other segment does not anticipate any significant capital investment in 2024.

 

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CONSOLIDATED BALANCE SHEET HIGHLIGHTS

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

 

millions of dollars		Increase (Decrease)				Explanation
Assets
Cash and cash equivalents		$	(309)			Decreased due to investment in property, plant and equipment (“PP&E”), net repayments under committed credit facilities at Corporate, and dividends paid on Emera common stock. These were partially offset by cash from operations
Derivative instruments (current and long-term)			(53)			Decreased due to reversal of 2023 contracts and changes in existing positions at EES as a result of lower natural gas prices, and settlements on derivative instruments in NSPI, partially offset by higher commodity prices and new derivative instruments at NSPI
Receivables and other assets (current and long-term)			54			Increased due to seasonal trends of the business at NSPI, new base rates that went into effect in 2024 at PGS, and higher gas transportation assets at EES. These were partially offset by lower accounts receivable as a result of lower natural gas prices at TEC, NMGC and EES
PP&E, net of accumulated depreciation and amortization			786			Increased due to capital additions in excess of depreciation and the effect of FX translation of Emera’s non-Canadian affiliates
Goodwill			144			Increased due to the effect of FX translation of Emera’s non-Canadian affiliates
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		$	178			Increased due to issuance of long-term debt at TEC; the effect of FX translation of Emera’s non-Canadian affiliates and proceeds from committed credit facilities at Emera and TECO Finance, Inc. (“TECO Finance”). These were partially offset by repayment of committed credit facilities at TEC and NSPI and repayment of debt at NMGC
Accounts payable			(258)			Decreased due to lower commodity prices at TEC, EES and NMGC
Deferred income tax liabilities, net of deferred income tax assets			92			Increased due to tax deductions in excess of accounting depreciation related to PP&E and the effect of FX translation of Emera’s non-Canadian affiliates
Regulatory liabilities (current and long-term)			99			Increased due to the effect of FX translation of Emera’s non-Canadian affiliates, higher cost of removal at TEC, and higher deferrals related to derivative instruments at NSPI
Other liabilities (current and long-term)			136			Increased due to timing of interest payments at Corporate, TEC and PGS
Common stock			103			Increased due to shares issued
Accumulated other comprehensive income			246			Increased due to the effect of FX translation of Emera’s non-Canadian affiliates

OTHER DEVELOPMENTS

Appointments

Board of Directors

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.

 

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FINANCIAL HIGHLIGHTS

Florida Electric Utility

 

For the		Three months ended March 31
millions of USD (except as indicated)		2024				2023
Operating revenues – regulated electric		$	548			$	552
Regulated fuel for generation and purchased power		$	141			$	146
Contribution to consolidated net income		$	63			$	79
Contribution to consolidated net income – CAD		$	85			$	107
Electric sales volumes (Gigawatt hours (“GWh”))			4,350				4,474
Electric production volumes (GWh)			4,471				4,590
Average fuel cost in dollars per megawatt hour (“MWh”)		$	32			$	32

The impact on Q1 2024 earnings related to the change in the FX rate was minimal.

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

 

For the millions of USD		Three months ended March 31
Contribution to consolidated net income – 2023		$	79
Decreased operating revenues primarily due to the impact of unfavourable weather of $13 million, pre-tax, partially offset by new base rates and customer growth			(4)
Decreased fuel for generation and purchased power due to lower natural gas prices			5
Increased OM&G, pre-tax, due to storm restoration cost recognition related to storm surcharge revenue ($6 million expense, offset in revenue), higher generation maintenance, and higher transmission and distribution expenses			(16)
Increased depreciation and amortization due to additions to facilities and generation projects placed in service			(8)
Decreased income tax expense due to decreased income before provision for income taxes and increased production tax credits related to solar facilities			7
Contribution to consolidated net income – 2024		$	63

Canadian Electric Utilities

 

For the		Three months ended March 31
millions of dollars (except as indicated)		2024				2023
Operating revenues – regulated electric		$	554			$	504
Regulated fuel for generation and purchased power (1)		$	290			$	103
Contribution to consolidated net income		$	87			$	92
Electric sales volumes (GWh)			3,183				3,131
Electric production volumes (GWh)			3,433				3,354
Average fuel costs in dollars per MWh (2)		$	84			$	31

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

(2) Average fuel costs for the three months ended March 31, 2023, include a reversal of $166 million related to the Nova Scotia Cap-and-Trade Program.

 

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

 

For the		Three months ended March 31
millions of dollars		2024				2023
NSPI		$	57			$	68
Equity investment in LIL			17				16
Equity investment in NSPML			13				8
Contribution to consolidated net income		$	87			$	92

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

 

For the millions of dollars		Three months ended March 31
Contribution to consolidated net income – 2023		$	92
Increased operating revenues due to new rates and increased residential sales volumes			50
Increased regulated fuel for generation and purchased power primarily due to reversal of the Nova Scotia Cap-and-Trade Program provision (1) in Q1 2023, higher commodity prices and increased sales volumes			(187)
Decreased FAM deferral primarily due to reversal of the Nova Scotia Cap-and-Trade Program provision (1) in Q1 2023, partially offset by under-recovery of fuel costs in 2024			151
Increased OM&G, pre-tax, due to higher transmission and distribution costs, a disallowance (2) under the FAM audit, and higher storm restoration and vegetation management costs. These were partially offset by the RER penalty recognized in Q1 2023			(16)
Increased income from equity investments at NSPML primarily due to the Maritime Link holdback recognized in Q1 2023			5
Increased income tax expense at NSPI due to decreased tax deductions in excess of accounting depreciation related to PP&E, partially offset by a decrease in the benefit of tax loss carryforwards recognized as a deferred income tax regulatory liability, and decreased income before provision for income taxes			(7)
Other			(1)
Contribution to consolidated net income – 2024		$	87

(1) In Q1 2023, the Province provided NSPI with additional emissions allowances sufficient to achieve compliance with the 2019 through 2022 Nova Scotia Cap-and-Trade Program compliance period and accrued compliance costs related to the expected purchase of emissions credits were reversed, resulting in a fuel cost recovery of $166 million.

(2) On February 21, 2024, the UARB’s decision on the FAM audit findings relating to fiscal 2020 and 2021 were released and included a disallowance of costs, net of tax and interest, of $3 million recorded in OM&G (the associated interest expense of $1 million is recorded in ‘Interest expense, net’).

Gas Utilities and Infrastructure

 

For the		Three months ended March 31
millions of USD (except as indicated)		2024				2023
Operating revenues – regulated gas (1)		$	391			$	422
Operating revenues – non-regulated			4				4
Total operating revenue		$	395			$	426
Regulated cost of natural gas		$	134			$	205
Contribution to consolidated net income		$	73			$	70
Contribution to consolidated net income – CAD		$	98			$	94
Gas sales volumes (millions of Therms)			910				930

(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline for the three months ended March 31, 2024 (2023 – $11 million).

 

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

 

For the		Three months ended March 31
millions of USD		2024				2023
PGS		$	42			$	26
NMGC			22				33
Other			9				11
Contribution to consolidated net income		$	73			$	70

The impact on Q1 2024 earnings related to the change in the FX rate was minimal.

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

 

For the millions of USD		Three months ended March 31
Contribution to consolidated net income – 2023			$     70
Decreased gas revenues due to lower fuel revenues at NMGC, partially offset by new base rates at PGS			(23)
Decreased asset optimization revenues at NMGC			(8)
Decreased cost of natural gas due to lower natural gas prices at NMGC			71
Increased OM&G, pre-tax, primarily due to the timing of deferred clause recoveries at PGS and higher labour costs at PGS and NMGC			(12)
Increased depreciation primarily due to asset growth at PGS			(10)
Increased interest expense, net, pre-tax, primarily due to higher interest rates and increased borrowings to support ongoing operations and capital investments primarily at PGS			(10)
Other			(5)
Contribution to consolidated net income – 2024			$     73

Other Electric Utilities.

 

For the		Three months ended March 31
millions of USD (except as indicated)		2024				2023
Operating revenues – regulated electric		$	92			$	85
Regulated fuel for generation and purchased power		$	48			$	42
Contribution to consolidated adjusted net income		$	7			$	3
Contribution to consolidated adjusted net income – CAD		$	9			$	4
Equity securities MTM gain		$	1			$	1
Contribution to consolidated net income		$	7			$	4
Contribution to consolidated net income – CAD		$	10			$	6
Electric sales volumes (GWh)			305				283
Electric production volumes (GWh)			327				300
Average fuel costs in dollars per MWh			147				140
Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
For the		Three months ended March 31
millions of USD		2024				2023
BLPC		$	5			$	2
GBPC			2				2
Other			-				(1)
Contribution to consolidated adjusted net income		$	7			$	3

The impact on Q1 2024 earnings related to the change in the FX rate was minimal.

 

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

 

For the millions of USD		Three months ended March 31
Contribution to consolidated net income – 2023			$      4
Increased operating revenues – regulated electric primarily due to higher fuel revenue and higher sales volumes at BLPC			7
Increased regulated fuel for generation and purchased power as a result of higher fuel prices at BLPC			(6)
Other			2
Contribution to consolidated net income – 2024			$      7

Other

 

For the		Three months ended March 31
millions of dollars		2024				2023
Marketing and trading margin (1) (2)		$	80			$	95
Other non-regulated operating revenue			9				6
Total operating revenues – non-regulated		$	89			$	101
Contribution to consolidated adjusted net (loss) income		$	(63)			$	(29)
MTM (loss) gain, after-tax (3)			(10)				290
Contribution to consolidated net (loss) income		$	(73)			$	261
(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs, and energy asset management services’ revenues. (2) Marketing and trading margin excludes a pre-tax MTM gain of $1 million for the three months ended March 31, 2024 (2023 – $435 million gain). (3) Net of income tax recovery of $4 million for the three months ended March 31, 2024 (2023 – $119 million expense).   Other’s contribution to consolidated adjusted net (loss) income is summarized in the following table:
For the		Three months ended March 31
millions of dollars		2024				2023
Emera Energy
EES		$	45			$	55
Other			1				1
Corporate – see breakdown of adjusted contribution below			(103)				(80)
Block Energy LLC			(6)				(4)
Other			-				(1)
Contribution to consolidated adjusted net (loss) income		$	(63)			$	(29)

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

 

For the millions of dollars		Three months ended March 31
Contribution to consolidated net income – 2023			$     261
Decreased marketing and trading margin due to lower natural gas prices, low volatility, and less favourable hedging opportunities			(15)
Increased OM&G, pre-tax, primarily due to the timing of long-term compensation hedges			(20)
Increased interest expense, pre-tax, primarily due to increased total debt			(8)
Increased income tax recovery, primarily due to increased losses before provision for income taxes			11
Decreased MTM gain, after-tax, primarily due to changes in existing positions partially offset by lower amortization of gas transportation assets at EES			(300)
Other			(2)
Contribution to consolidated net (loss) income – 2024			$     (73)

 

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Corporate

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

 

For the		Three months ended March 31
millions of dollars		2024				2023
Operating expenses (1)		$	(25)			$	(6)
Interest expense			(91)				(82)
Income tax recovery			33				26
Preferred dividends			(18)				(16)
Other (2)(3)			(2)				(2)
Corporate adjusted net (loss) income (4)		$	(103)			$	(80)

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

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

(3) Includes a realized, pre-tax, net loss of $1 million on FX hedges for the three months ended March 31, 2024 ($1 million after-tax), as discussed above (2023 – $3 million net loss, pre-tax and $2 million loss, after-tax).

(4) Excludes a MTM loss, after-tax, of $2 million for the three months ended March 31, 2024 (2023 – $5 million gain, after-tax).

LIQUIDITY AND CAPITAL RESOURCES

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

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has an approximate $9 billion capital investment plan over the 2024 through 2026 period with approximately $2 billion of additional potential capital investments over the same period. Capital investments at Emera’s regulated utilities are subject to regulatory approval.

Emera plans to use cash from operations, debt raised at the utilities, equity, and select asset sales to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Generally, equity requirements in support of the Company’s capital investment plan are expected to be funded through issuance of preferred equity and issuance of common equity through Emera’s DRIP and ATM programs.

Emera has credit facilities with varying maturities that cumulatively provide $5.1 billion of credit, with approximately $2.7 billion undrawn and available at March 31, 2024. The Company was holding a cash balance of $276 million at March 31, 2024. For further discussion, refer to the “Debt Management” section below.

 

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Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 2024 and 2023 include:

 

millions of dollars		2024				2023				Change
Cash, cash equivalents, and restricted cash, beginning of period		$    588				$    332				$    256
Provided by (used in):
Operating cash flow before changes in working capital			631				654				(23)
Change in working capital			(62)				(201)				139
Operating activities		$	569			$	453			$	116
Investing activities			(604)				(640)				36
Financing activities			(288)				153				(441)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash			11				4				7
Cash, cash equivalents, and restricted cash, end of period		$	276			$	302			$	(26)

Cash Flow from Operating Activities

Net cash provided by operating activities increased $116 million to $569 million for the three months ended March 31, 2024, compared to $453 million for the same period in 2023.

Cash from operations before changes in working capital decreased $23 million year-over-year. This decrease was due to increased fuel for generation and purchase power expense at NSPI, driven by the reversal of the Nova Scotia Cap-and-Trade Program provision in Q1 2023, and decreased earnings and lower fuel clause recoveries at TEC. This was partially offset by the favourable change in regulatory liabilities due to the 2023 gas hedge settlements at NMGC, and increased earnings at PGS.

Changes in working capital increased operating cash flows by $139 million year-over-year. This increase was due to the 2023 reversal of the Nova Scotia Cap-and-Trade accrual at NSPI in Q1 2023, favourable changes in cash collateral positions at NSPI, and timing of accounts payable payments at NSPI, TEC, and NMGC. These were partially offset by unfavourable changes in accounts receivable at NMGC due to the receipt of its 2023 gas hedge settlement, and unfavourable changes in cash collateral positions at EES.

Cash Flow from Investing Activities

Net cash used in investing activities decreased $36 million to $604 million for the three months ended March 31, 2024, compared to $640 million for the same period in 2023. The decrease was due to lower capital investment primarily at PGS, partially offset by higher capital investment primarily at TEC.

Capital investments, including AFUDC, for the three months ended March 31, 2024, were $610 million compared to $646 million for the same period in 2023. Details of the 2024 capital investment by segment are shown below:

 

·

$368 million – Florida Electric Utility (2023 – $347 million);

 

·

$112 million – Canadian Electric Utilities (2023 – $115 million);

 

·

$116 million – Gas Utilities and Infrastructure (2023 – $170 million);

 

·

$14 million – Other Electric Utilities (2023 – $11 million); and

 

·

$nil – Other (2023 – $3 million).

 

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Cash Flow from Financing Activities

Net cash used in financing activities increased $441 million to $288 million for the three months ended March 31, 2024, compared to cash provided by financing activities of $153 million for the same period in 2023. This increase was due to repayment of short-term debt at TEC, the 2023 proceeds of long-term debt at NSPI, and higher repayments of Emera’s committed credit facilities. These were partially offset by issuance of long-term debt at TEC, lower repayments of committed credit facilities at NSPI, and higher proceeds from short-term debt at TECO Finance.

Contractual Obligations

As at March 31, 2024, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

 

millions of dollars		2024				2025				2026				2027				2028				Thereafter				Total
Long-term debt principal		$	1,459			$	267			$	3,114			$	706			$	538			$	12,534			$	18,618
Interest payment obligations (1)			746				821				732				637				598				7,572				11,106
Transportation (2)			592				561				435				413				364				2,728				5,093
Purchased power (3)			209				254				272				321				322				3,514				4,892
Capital projects			866				151				78				9				-				-				1,104
Fuel, gas supply and storage			394				239				61				10				5				-				709
Asset retirement obligations			9				2				1				1				2				409				424
Pension and post-retirement obligations (4)			22				30				40				48				32				151				323
Equity investment commitments (5)			240				-				-				-				-				-				240
Other			99				150				58				50				36				223				616
		$	4,636			$	2,475			$	4,791			$	2,195			$	1,897			$	27,131			$	43,125

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2024, including any expected required payment under associated swap agreements.

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

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

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

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

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In December 2023, the UARB approved the collection of up to $164 million from NSPI for the recovery of Maritime Link costs in 2024. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

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

 

20

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Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD, per the table below as at March 31, 2024.

 

millions of Canadian dollars (unless otherwise indicated)		Maturity				Credit Facilities				Utilized				Undrawn and Available
Emera – Unsecured committed revolving credit facility			June 2027			$	900			$	327			$	573
TEC (in USD) – Unsecured committed revolving credit facility			December 2028				800				57				743
NSPI – Unsecured committed revolving credit facility			December 2027				800				310				490
Emera – Unsecured non-revolving facility			December 2024				400				400				-
Emera – Unsecured non-revolving facility			February 2025				400				200				200
Emera – Unsecured non-revolving facility			August 2024				400				400				-
TECO Finance (in USD) – Unsecured committed revolving credit facility			December 2028				400				265				135
NSPI – Unsecured non-revolving facility			July 2024				400				400				-
PGS (in USD) – Unsecured revolving facility			December 2028				250				27				223
TEC (in USD) – Unsecured revolving facility			April 2024				200				-				200
NMGC (in USD) – Unsecured revolving credit facility			December 2026				125				2				123
Other (in USD) – Unsecured committed revolving credit facilities			Various				21				10				11

Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at March 31, 2024.

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

Florida Electric Utilities

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

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

Other Electric Utilities

On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend the maturity date from February 19, 2025 to July 19, 2028. There were no material changes in commercial terms from the prior agreement. This facility was classified as long-term debt at March 31, 2024.

Other

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

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

 

21

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Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2023

annual MD&A.

Outstanding Stock Data

Common Stock

 

Issued and outstanding:		millions of shares				millions of dollars
Balance, December 31, 2023			284.12			$	8,462
Issuance of common stock under ATM program (1)			0.50				24
Issued under the DRIP, net of discounts			1.54				70
Senior management stock options exercised and Employee Share Purchase Plan			0.19				9
Balance, March 31, 2024			286.35			$	8,565

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

As at May 8, 2024 the amount of issued and outstanding common shares was 286.6 million.

If all outstanding stock options were converted as at May 8, 2024, an additional 3.8 million common shares would be issued and outstanding.

Preferred Stock

As at May 8, 2024, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

TRANSACTIONS WITH RELATED PARTIES

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

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

 

·

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

For further details, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPML” and “Contractual Obligations” sections.

 

·

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

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

 

22

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2023 annual MD&A.

Derivative Assets and Liabilities Recognized on the Balance Sheet

 

As at millions of dollars		March 31 2024				December 31 2023
Regulatory Deferral:
Derivative instrument assets (1)		$	34			$	16
Derivative instrument liabilities (2)			(55)				(76)
Regulatory assets (1)			58				88
Regulatory liabilities (2)			(33)				(17)
Net asset		$	4			$	11
HFT Derivatives:
Derivative instrument assets (1)		$	132			$	202
Derivative instrument liabilities (2)			(390)				(421)
Net liability		$	(258)			$	(219)
Other Derivatives:
Derivative instrument assets (1)		$	21			$	22
Derivative instrument liabilities (2)			(16)				(7)
Net asset		$	5			$	15
(1) Current and other assets.
(2) Current and long-term liabilities.

Realized and Unrealized Gains (Losses) Recognized in Net Income

 

For the		Three months ended March 31
millions of dollars		2024				2023
Regulatory Deferral:
Regulated fuel for generation and purchased power (1)		$	(5)			$	66
HFT Derivatives:
Non-regulated operating revenues		$	160			$	839
Other Derivatives:
OM&G		$	(8)			$	11
Other income, net			(3)				3
Net gains (losses)		$	(11)			$	14
Total net gains		$	144			$	919

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

As of March 31, 2024, the unrealized gain in accumulated other comprehensive income was $13 million, net of tax (December 31, 2023 – $14 million, net of tax). For the three months ended March 31, 2024, unrealized gains of $1 million (2023 – $1 million), have been reclassified into interest expense, net.

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. The Company’s internal control framework is based on criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at March 31, 2024, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

 

23

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

There were no changes in the Company’s ICFR during the quarter ended March 31, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES

The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2023 annual MD&A.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Future Accounting Pronouncements

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

Improvements to Income Tax Disclosures

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

 

24

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Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.

SUMMARY OF QUARTERLY RESULTS

 

For the quarter ended millions of dollars		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
(except per share amounts)		2024				2023				2023				2023				2023				2022				2022				2022
Operating revenues		$	2,018			$	1,972			$	1,740			$	1,418			$	2,433			$	2,358			$	1,835			$	1,380
Net income (loss) attributable to common shareholders		$	207			$	289			$	101			$	28			$	560			$	483			$	167			$	(67)
Adjusted net income		$	216			$	175			$	204			$	162			$	268			$	249			$	203			$	156
EPS – basic		$	0.73			$	1.04			$	0.37			$	0.10			$	2.07			$	1.80			$	0.63			$	(0.25)
EPS – diluted		$	0.73			$	1.04			$	0.37			$	0.10			$	2.07			$	1.80			$	0.63			$	(0.25)
Adjusted EPS – basic		$	0.76			$	0.63			$	0.75			$	0.60			$	0.99			$	0.93			$	0.76			$	0.59

Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the “Significant Items Affecting Earnings” section.

 

25

Exhibit 99.2

 

 

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2024 and 2023

---

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

 

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

---

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

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

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Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

 

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

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

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

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

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

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Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

 

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

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

 

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

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Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)

 

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

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

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

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Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

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

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

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(1) Series A; $0.1364/share, Series B; $0.4408/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3953/share; Series J; $0.2656/share and Series L; $0.2875/share

(2) Series A; $0.1364/share, Series B; $0.3570/share, Series C; $0.2951/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3063/share; Series J; $0.2656/share and Series L; $0.2875/share

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Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at March 31, 2024 and 2023

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

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

At March 31, 2024, Emera’s reportable segments include the following:

•

Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated electric utility in West Central Florida.

 

•

Canadian Electric Utilities, which includes:

•

Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia;

•

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

•

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

 

•

Gas Utilities and Infrastructure, which includes:

•

Peoples Gas System, Inc. (“PGS”), a regulated gas distribution utility operating across Florida;

•

New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico;

•

Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy North America Canada Partnership (“Repsol Energy”), which expires in 2034;

•

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

•

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

 

•

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

•

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

•

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

•

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

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•

Emera’s other segment includes investments in energy-related non-regulated companies that are below the required threshold for reporting as separate segments and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments. This includes:

•

Emera Energy, which consists of:

•

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

•

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

•

a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts.

•

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

•

Block Energy LLC, a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers;

•

Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and

•

Other investments.

Basis of Presentation

These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2023.

In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2024.

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

Use of Management Estimates

The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2023 annual audited consolidated financial statements.

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Seasonal Nature of Operations

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

2. FUTURE ACCOUNTING PRONOUNCEMENTS

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

Improvements to Income Tax Disclosures

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

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.

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3.	SEGMENT INFORMATION

Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker.

 

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

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

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

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

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4.

REVENUE

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

 

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

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

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

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

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

Remaining Performance Obligations:

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

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amount of the transaction price allocated to remaining performance obligations was $477 million (2023 – $471 million). This amount includes $133 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2044.

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5. REGULATORY ASSETS AND LIABILITIES

A summary of regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 6 in Emera’s 2023 annual audited consolidated financial statements. Updates to regulatory environments are included below.

 

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

Florida Electric Utility

Base Rates:

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

Fuel Recovery:

On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $137 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction is due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected 2024 costs in the fall of 2023. On May 7, 2024, the Florida Public Service Commission voted to approve the mid-course adjustment.

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Canadian Electric Utilities

NSPI

Storm Rider:

On April 30, 2024, NSPI applied to the Nova Scotia Utility and Review Board (“UARB”) for recovery of $22 million of major storm restoration expense deferred to NSPI’s UARB approved storm rider in 2023. If approved, recovery of the 2023 costs deferred in the storm rider would begin January 1, 2025 over the 12 months of 2025.

Fuel Recovery:

On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, which will result in a corresponding decrease of the FAM regulatory asset when recorded in Q2 2024. NSPI will collect the amortization and financing costs in related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period beginning in Q2 2024, and remit those amounts to Invest Nova Scotia as collected.

NSPML

On December 21, 2023, NSPML received approval to collect up to $164 million in 2024 from NSPI for the recovery of costs associated with the Maritime Link subject to a holdback of $4 million per month. There was no holdback recorded in Q1 2024.

Gas Utilities and Infrastructure

NMGC

Base Rates:

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

Other Electric Utilities

BLPC

Clean Energy Transition Rider (“CETR”):

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

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Base Rates:

In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.

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

 

6.	INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

 

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

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

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

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $86 million (2023 – $81 million) is recorded in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets.

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Emera accounts for its variable interest investment in NSPML as an equity investment (note 21). NSPML’s consolidated summarized balance sheet is as follows:

 

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

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

 

7.	INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

 

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

 

8.	INCOME TAXES

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

 

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

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

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9.	COMMON STOCK

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

 

Issued and outstanding:		millions of shares				millions of dollars
Balance, December 31, 2023			284.12			$	8,462
Issuance of common stock under ATM program (1)			0.50				24
Issued under the DRIP, net of discounts			1.54				70
Senior management stock options exercised and ECSPP			0.19				9
Balance, March 31, 2024			286.35			$	8,565

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

 

10.	EARNINGS PER SHARE

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

 

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

 

11.	ACCUMULATED OTHER COMPREHENSIVE INCOME

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

 

millions of dollars		Unrealized gain on translation of self-sustaining foreign operations				Net change in net investment hedges				Gains (losses) on derivatives recognized as cash flow hedges				Net change in  available- for-sale investments				Net change in unrecognized pension and post- retirement benefit costs				Total   AOCI
For the three months ended March 31, 2024
Balance, January 1, 2024			$  369				$  (24)				$  14				$  (2)				$  (52)				$  305
OCI before reclassifications			284				(39)				-				1				-				246
Amounts reclassified from AOCI			-				-				(1)				-				1				-
Net current period OCI			284				(39)				(1)				1				1				246
Balance, March 31, 2024			$  653				$  (63)				$  13				$  (1)				$  (51)				$  551
For the three months ended March 31, 2023
Balance, January 1, 2023			$  639				$  (62)				$  16				$  (2)				$  (13)				$  578
OCI before reclassifications			3				1				-				-				-				4
Amounts reclassified from AOCI			-				-				(1)				-				(4)				(5)
Net current period OCI			3				1				(1)				-				(4)				(1)
Balance, March 31, 2023			$  642				$  (61)				$  15				$  (2)				$  (17)				$  577

The reclassifications out of AOCI are as follows:

 

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

 

12.	DERIVATIVE INSTRUMENTS

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

 

●

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

●

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

●

interest rate fluctuations on debt securities; and

●

share price fluctuations on stock-based compensation.

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

 

1.

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

 

2.

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

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

 

3.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at FV on the balance sheet as derivative assets or liabilities. The change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Based on current direction from the FPSC, TEC and PGS have no derivatives related to hedging.

 

4.

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

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

 

		Derivative Assets								Derivative Liabilities
As at		March 31				December 31				March 31				December 31
millions of dollars		2024				2023				2024				2023
Regulatory deferral:
Commodity swaps and forwards		$	31			$	16			$	59			$	76
FX forwards			10				3				3				3
			41				19				62				79
HFT derivatives:
Power swaps and physical contracts			8				29				6				36
Natural gas swaps, futures, forwards, physical contracts			230				319				490				531
			238				348				496				567
Other derivatives:
Equity derivatives			-				4				3				-
FX forwards			21				18				13				7
			21				22				16				7
Total gross derivatives			300				389				574				653
Impact of master netting agreements:
Regulatory deferral			(7)				(3)				(7)				(3)
HFT derivatives			(106)				(146)				(106)				(146)
Total impact of master netting agreements			(113)				(149)				(113)				(149)
Total derivatives		$	187			$	240			$	461			$	504
Current (1)			125				174				370				386
Long-term (1)			62				66				91				118
Total derivatives		$	187			$	240			$	461			$	504

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

Cash Flow Hedges

On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. As of March 31, 2024, the unrealized gain in AOCI was $13 million, net of tax (December 31, 2023 – $14 million, net of tax). For the three months ended March 31, 2024, unrealized gains of $1 million (2023 – $1 million) have been reclassified from AOCI into interest expense, net. The company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months.

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Regulatory Deferral

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

 

millions of dollars		Commodity swaps and forwards				FX forwards				Physical natural gas purchases				Commodity swaps and forwards				FX forwards
For the three months ended March 31							2024												2023
Unrealized gain (loss) in regulatory assets		$	8			$	-			$	-			$	(20)			$	-
Unrealized gain (loss) in regulatory liabilities			15				11				(4)				(67)				2
Realized (gain) loss in regulatory assets			(1)				-				-				4				-
Realized (gain) loss in regulatory liabilities			(1)				-				-				1				-
Realized (gain) loss in inventory (1)			4				(2)				-				1				(5)
Realized (gain) loss in regulated fuel for generation and purchased power (2)			7				(2)				(39)				(27)				-
Other			-				-				-				(15)				-
Total change in derivative instruments		$	32			$	7			$	(43)			$	(123)			$	(3)

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

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

As at March 31, 2024, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:

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millions		2024				2025-2026
Physical natural gas purchases:
Natural gas (MMBtu)			5				6
Commodity swaps and forwards purchases:
Natural gas (MMBtu)			12				16
Power (MWh)			1				1
Coal (metric tonnes)			1				-
FX swaps and forwards:
FX contracts (millions of USD)		$	210			$	117
Weighted average rate			1.3326				1.3302
% of USD requirements			74%				29%

HFT Derivatives

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

 

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

As at March 31, 2024, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

 

millions		2024				2025				2026				2027				2028 and thereafter
Natural gas purchases (MMBtu)			276				124				64				38				103
Natural gas sales (MMBtu)			347				146				32				9				10

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Other Derivatives

As at March 31, 2024, the Company had equity derivatives in place to manage cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.9 million shares and extends until December 2024. The FX forwards have a combined notional amount of $527 million USD and expire in 2024 through 2025.

 

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

Credit Risk

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

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

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps

---

and Derivatives Association agreements, North American Energy Standards Board agreements and/or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

---

As at March 31, 2024, the Company had $149 million (December 31, 2023 – $142 million) in financial assets considered to be past due, which had been outstanding for an average 65 days. The FV of these financial assets was $134 million (December 31, 2023 – $127 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.

Cash Collateral

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

 

As at		March 31				December 31
millions of dollars		2024				2023
Cash collateral provided to others		$	100			$	101
Cash collateral received from others		$	10			$	22

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at March 31, 2024, the total FV of derivatives in a liability position was $461 million (December 31, 2023 – $504 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.

13. FV MEASUREMENTS

The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 12), and uses a market approach to do so. The three levels of the FV hierarchy are defined as follows:

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

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

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

●

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

●

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

●

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

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

---

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

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As at		March 31, 2024
millions of dollars		Level 1				Level 2				Level 3				Total
Assets
Regulatory deferral:
Commodity swaps and forwards			$    9				$    15				$    -				$    24
FX forwards			-				10				-				10
			9				25				-				34
HFT derivatives:
Power swaps and physical contracts			1				5				1				7
Natural gas swaps, futures, forwards, physical contracts and related transportation			26				86				13				125
			27				91				14				132
Other derivatives:
FX forwards			-				21				-				21
Total assets			36				137				14				187
Liabilities
Regulatory deferral:
Commodity swaps and forwards			46				6				-				52
FX forwards			-				3				-				3
			46				9				-				55
HFT derivatives:
Power swaps and physical contracts			-				4				1				5
Natural gas swaps, futures, forwards and physical contracts			16				18				351				385
			16				22				352				390
Other derivatives:
FX forwards			-				13				-				13
Equity derivatives			3				-				-				3
			3				13				-				16

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

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

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Total liabilities			56				83				365				504
Net assets (liabilities)			$   (8)				$    75				$  (331)				$  (264)

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

 

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

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

 

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

Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV measurement. Other unobservable inputs used include internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers.

The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative instruments. The following table outlines quantitative information about the significant unobservable inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:

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

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

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

 

As at		Carrying
millions of dollars		Amount				FV				Level 1				Level 2				Level 3				Total
March 31, 2024		$	18,491			$	17,201			$	-			$	16,946			$	255			$	17,201
December 31, 2023		$	18,365			$	16,621			$	-			$	16,363			$	258			$	16,621

The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency loss of $39 million was recorded in AOCI for the three months ended March 31, 2024 (2023 – $1 million gain after-tax).

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14.	RELATED PARTY TRANSACTIONS

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

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

 

●

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

 

●

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

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

 

15.	RECEIVABLES AND OTHER CURRENT ASSETS

 

As at		March 31				December 31
millions of dollars		2024				2023
Customer accounts receivable – billed			$  770				$  805
Customer accounts receivable – unbilled			362				363
Capitalized transportation capacity (1)			402				358
Prepaid expenses			103				105
Income tax receivable			10				10
Allowance for credit losses			(15)				(15)
Other			199				191
Total receivables and other current assets			$  1,831				$  1,817

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

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16. EMPLOYEE BENEFIT PLANS

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

Emera’s net periodic benefit cost included the following:

 

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

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

 

17.	SHORT-TERM DEBT

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Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt, refer to note 23 in Emera’s 2023 annual audited consolidated financial statements, and below for 2024 short-term debt financing activity.

Florida Electric Utilities

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

Other

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

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

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18. LONG-TERM DEBT

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

Florida Electric Utilities

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

Other Electric Utilities

On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend the maturity date from February 19, 2025 to July 19, 2028. There were no material changes in commercial terms from the prior agreement. This facility was classified as long-term debt at March 31, 2024.

19. COMMITMENTS AND CONTINGENCIES

 

A.	Commitments

As at March 31, 2024, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:

 

millions of dollars		2024				2025				2026				2027				2028				Thereafter				Total
Transportation (1)		$	592			$	561			$	435			$	413			$	364			$	2,728			$	5,093
Purchased power (2)			209				254				272				321				322				3,514				4,892
Capital projects			866				151				78				9				-				-				1,104
Fuel, gas supply and storage			394				239				61				10				5				-				709
Equity investment commitments (3)			240				-				-				-				-				-				240
Other			99				150				58				50				36				223				616
		$	2,400			$	1,355			$	904			$	803			$	727			$	6,465			$	12,654

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

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

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

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In December 2023, the UARB approved the collection of up to $164 million from NSPI for the recovery of Maritime Link costs in 2024. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

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

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B.	Legal Proceedings

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). While the aggregate joint and several liability associated with these sites has not changed as a result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at March 31, 2024, the aggregate financial liability of the Florida utilities is estimated to be $15 million ($11 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities. The estimates to perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, the Florida utilities could be liable for more than their actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

 

C.	Principal Financial Risks and Uncertainties

For information on principal financial risks which could materially affect the Company in the normal course of business, refer to note 27 in Emera’s 2023 annual audited consolidated financial statements. Risks associated with derivative instruments and FV measurements are discussed in note 12 and note 13. There have been no material changes to the principal financial risks as of March 31, 2024.

 

D.	Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2023 audited annual consolidated financial statements.

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20. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

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

1) The three months ended March 31, 2023, includes $162 million related to the January 2023 settlement of NMGC gas hedges. Offsetting change in regulatory liabilities is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

2) The three months ended March 31, 2023, includes $(166) million related to the decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges. Offsetting regulatory asset (FAM) balance is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

 

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

21. VARIABLE INTEREST ENTITIES

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

BLPC established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as an “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.

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

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

 

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

 

22.	SUBSEQUENT EVENTS

These unaudited condensed consolidated interim financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 13, 2024, the date the unaudited condensed consolidated interim financial statements we re issued.

Exhibit 99.3

Emera Incorporated

Earnings Coverage Ratio

Pursuant to Section 8.4 of National Instrument 44-102, this updated calculation of the earnings coverage ratio is filed as an exhibit to the audited consolidated financial statements of Emera Incorporated (“Emera”) for the three months ended March 31, 2024.

The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended March 31, 2024.

 

		Twelve months ended March 31, 2024
Earnings Coverage (1)		1.54

⁽¹⁾ Earnings coverage is equal to consolidated net income attributable to common shareholders plus: income taxes, interest on debt, amortization of debt financing costs, allowance for funds used during construction and preferred share dividends declared during the period together with undeclared preferred share dividends, if any, divided by the sum of interest on debt, amortization of debt financing costs, allowance for funds used during construction, capitalized interest and preferred dividends grossed up to a before-tax equivalent using an effective tax rate of 29.0 per cent.

Emera’s dividend requirements on all of its preferred shares, grossed up to a before-tax equivalent using an effective income tax rate of 29.0 per cent, amounted to $96 million for the twelve months ended March 31, 2024. Emera’s interest requirements for the twelve months ended March 31, 2024 amounted to $962 million. Emera’s consolidated income before interest and income tax for the twelve months ended March 31, 2024 was $1,633 million, which is 1.54 times Emera’s aggregate preferred dividends and interest requirements for this period.

Exhibit 99.4

 

Emera Reports 2024 First Quarter Financial Results

HALIFAX, Nova Scotia -- Today Emera (TSX: EMA) reported 2024 first quarter financial results.

Summary

 

·

Quarterly adjusted earnings per share (“EPS”) (1) of $0.76 decreased $0.23 or 23% compared to $0.99 in Q1 2023. The primary drivers of this change are:

 

o

the impact of milder weather at Tampa Electric during the quarter;

 

o

lower contributions from New Mexico Gas Company’s (“NMGC”) asset management agreements, which were very strong in Q1 last year;

 

o

lower earnings at Nova Scotia Power (“NSPI”) due to an increase in OM&G costs focused on reliability and customer experience, as well as a one-time regulatory disallowance;

o

lower contributions from marketing and trading at Emera Energy Services (“EES”), which had a very strong Q1 last year;

o

higher corporate costs due to mark-to-market losses related to long-term compensation-related hedges;

o

partially offset by higher contributions from Peoples Gas (“PGS”), which benefited from new rates and strong customer growth – delivering its highest quarterly earnings ever.

 

·

Quarterly reported net income decreased by $353 million to $207 million compared to $560 million in Q1 2023 and quarterly reported EPS decreased by $1.34 to $0.73 from $2.07 in Q1 2023. Both decreases were primarily due to mark-to-market (“MTM”) gains at EES in 2023.

“While weather and an unusually strong prior-year quarter contributed to lower comparative adjusted earnings for the quarter, our core utilities remain on track to deliver solid earnings results for the full year” said Scott Balfour, President and CEO of Emera Inc. “We remain confident in the underlying forward-looking growth profile of our business, driven in large part by our two operations in Florida. Peoples Gas is on track to become our second largest earnings contributor in 2024, behind Tampa Electric. Together, our Florida businesses have delivered significant growth in earnings over the last five years, and we expect the drivers of this growth to continue.”

Q1 2024 Financial Results

Q1 2024 reported net income was $207 million, or $0.73 per common share, compared with net income $560 million, or $2.07 per common share, in Q1 2023.

Q1 2024 adjusted net income⁽¹⁾ was $216 million, or $0.76 per common share, compared with $268 million, or $0.99 per common share, in Q1 2023. The decrease was primarily due to lower earnings from our operating businesses; increased corporate OM&G due to the timing of long-term compensation hedges; and higher corporate interest expense.

(1) See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-US GAAP Reconciliation” below for reconciliation to nearest USGAAP measure.

 

1

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Consolidated Financial Review

The following table highlights significant changes in adjusted net income attributable to common shareholders from 2023 to 2024.

 

For the millions of Canadian dollars		Three months ended March 31
Adjusted net income – 20231,2			$   268
Operating Unit Performance
Decreased earnings at TEC due to unfavourable weather, increased OM&G and higher depreciation, partially offset by customer growth and new base rates			(22)
Decreased earnings at NMGC due lower asset optimization revenues and higher operating, maintenance and general expenses (“OM&G”)			(14)
Decreased earnings at NSPI due to increased OM&G, partially offset by higher revenues due to new rates and increased residential sales volumes			(11)
Decreased earnings at EES due to less favourable market conditions			(10)
Increased earnings at PGS due to new base rates, partially offset by higher interest expense, OM&G and depreciation expense			21
Increased income from equity investments at NSPML primarily due to the Maritime Link holdback recognized in Q1 2023			5
Corporate
Increased OM&G, pre-tax, primarily due to timing of long-term compensation hedges			(19)
Increased interest expense, pre-tax, due to increased total debt			(9)
Increased income tax recovery due to increased losses before provision for income taxes			7
Adjusted net income – 20241,2			$   216

¹ See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” for reconciliation to nearest USGAAP measure.

² Excludes the effect of MTM adjustments, net of tax.

Segment Results and Non-GAAP Reconciliation

 

For the		Three months ended March 31
millions of Canadian dollars (except per share amounts)		2024				2023
Adjusted net income1,2
Florida Electric Utility		$	85			$	107
Canadian Electric Utilities			87				92
Gas Utilities and Infrastructure			98				94
Other Electric Utilities			9				4
Other3			(63)				(29)
Adjusted net income1,2		$	216			$	268
MTM (loss) gain, after-tax4,			(9)				292
Net income attributable to common shareholders		$	207			$	560
EPS (basic)		$	0.73			$	2.07
Adjusted EPS (basic)1,2		$	0.76			$	0.99

¹ See “Non-GAAP Financial Measures and Ratios” noted below.

² Excludes the effect of MTM adjustments.

³ Primarily due to timing of long-term incentive compensation at corporate, higher corporate interest expense and lower contributions from EES, partially offset by increased income tax recovery at corporate.

⁴ Net of income tax recovery of $4 million for the three months ended March 31, 2024 (2023 - $119 million tax expense).

 

2

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¹ Non-GAAP Financial Measures and Ratios

Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures and ratios by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes the ongoing operations of the business. For further information on the non-GAAP financial measure, adjusted net income, and the non-GAAP ratio, adjusted EPS – basic, refer to the “Non-GAAP Financial Measures and Ratios” section of the Emera’s Q1 2024 MD&A which is incorporated herein by reference and can be found on SEDAR+ at www.sedarplus.ca. Reconciliation to the nearest GAAP measure is included in “Segment Results and Non-GAAP Reconciliation” above.

Forward Looking Information

This news release contains forward-looking information within the meaning of applicable securities laws. By its nature, forward-looking information requires Emera to make assumptions and is subject to inherent risks and uncertainties. These statements reflect Emera management’s current beliefs and are based on information currently available to Emera management. There is a risk that predictions, forecasts, conclusions and projections that constitute forward-looking information will not prove to be accurate, that Emera’s assumptions may not be correct and that actual results may differ materially from such forward-looking information. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Business Risks and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR+ at www.sedarplus.ca.

Teleconference Call

The company will be hosting a teleconference today, Monday, May 13, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q1 2024 financial results.

Analysts and other interested parties in North America are invited to participate by dialing 1-800-717-1738. International parties are invited to participate by dialing 1-289-514-5100. Participants should dial in at least 10 minutes prior to the start of the call. No pass code is required.

A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available on the Company’s website two hours after the conclusion of the call.

About Emera

Emera Inc. is a geographically diverse energy and services company headquartered in Halifax, Nova Scotia, with approximately $39 billion in assets and 2023 revenues of $7.6 billion. The company primarily invests in regulated electricity generation and electricity and gas transmission and distribution with a strategic focus on transformation from high carbon to low carbon energy sources. Emera has investments in Canada, the United States and in three Caribbean countries. Emera’s common and preferred shares are listed on the Toronto Stock Exchange and trade respectively under the symbol EMA, EMA.PR.A, EMA.PR.B, EMA.PR.C, EMA.PR.E, EMA.PR.F, EMA.PR.H, EMA.PR.J and EMA.PR.L. Depositary receipts representing common shares of Emera are listed on the Barbados Stock Exchange under the symbol EMABDR and on The Bahamas International Securities Exchange under the symbol EMAB. Additional information can be accessed at www.emera.com or at www.sedarplus.ca.

 

3

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Emera Inc.

Investor Relations

Dave Bezanson, VP, Investor Relations & Pensions

902-474-2126

[e-mail]

Media

902-222-2683

[e-mail]

 

4

Exhibit 99.5

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Scott Balfour, President and Chief Executive Officer of Emera Incorporated, certify the following:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended March 31, 2024.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

 

A.

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

 

i.

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

 

ii.

information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

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B.

designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.

5.2 ICFR – material weakness relating to design: N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

 

a.

the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of:

 

i.

a proportionately consolidated entity in which the issuer has an interest;

 

ii.

a special purpose entity in which the issuer has an interest; or

 

iii.

a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and

 

b.

summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.

6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2024 and ended on March 31, 2024 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date:  May 13, 2024

 

“Scott Balfour”

Scott Balfour President and Chief Executive Officer

Exhibit 99.6

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Greg Blunden, Chief Financial Officer of Emera Incorporated, certify the following:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended March 31, 2024.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

 

A.

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

 

i.

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

 

ii.

information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

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B.

designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.

5.2 ICFR – material weakness relating to design: N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

 

a.

the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of:

 

i.

a proportionately consolidated entity in which the issuer has an interest;

 

ii.

a special purpose entity in which the issuer has an interest; or

 

iii.

a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and

 

b.

summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.

6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2024 and ended on March 31, 2024 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date:  May 13, 2024

 

“Greg Blunden”

Greg Blunden Chief Financial Officer

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