Exhibit 99.1
Emera Incorporated
Annual Information Form
For the year ended December 31, 2023
February 26, 2024
ANNUAL INFORMATION FORM
For the year ended December 31, 2023
Dated: February 26, 2024
TABLE OF CONTENTS
PRESENTATION OF INFORMATION |
4 | |||
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION |
4 | |||
CORPORATE STRUCTURE |
5 | |||
Name and Incorporation |
5 | |||
Amended Articles of Association |
6 | |||
Intercorporate Relationships |
6 | |||
INTRODUCTION |
6 | |||
DESCRIPTION OF THE BUSINESS |
8 | |||
Business Segments |
8 | |||
Florida Electric Utility |
8 | |||
Canadian Electric Utilities |
11 | |||
Gas Utilities and Infrastructure |
14 | |||
Other Electric Utilities |
16 | |||
Other |
18 | |||
GENERAL DEVELOPMENT OF THE BUSINESS |
19 | |||
Florida Electric Utility |
19 | |||
Canadian Electric Utilities |
21 | |||
Gas Utilities and Infrastructure |
25 | |||
Other Electric Utilities |
26 | |||
USGAAP Exemptive Relief |
27 | |||
Financing Activity |
27 | |||
RISK FACTORS |
29 | |||
CAPITAL STRUCTURE |
29 | |||
Common Shares |
29 | |||
Emera First Preferred Shares |
30 | |||
Emera Second Preferred Shares |
30 | |||
Share Ownership Restrictions |
30 | |||
CREDIT RATINGS |
31 | |||
DIVIDENDS |
33 | |||
MARKET FOR SECURITIES |
34 | |||
Trading Price and Volume |
34 | |||
At-The-Market Equity Program |
34 | |||
DIRECTORS AND OFFICERS |
35 | |||
Directors |
35 | |||
Officers |
37 |
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AUDIT COMMITTEE |
38 | |||
Audit and Non-Audit Services Pre-Approval Process |
39 | |||
Auditors Fees |
40 | |||
CERTAIN PROCEEDINGS |
40 | |||
CONFLICTS OF INTEREST |
40 | |||
LEGAL PROCEEDINGS AND REGULATORY ACTIONS |
41 | |||
NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS |
41 | |||
MATERIAL CONTRACTS |
41 | |||
TRANSFER AGENT AND REGISTRAR |
41 | |||
EXPERTS |
41 | |||
ADDITIONAL INFORMATION |
41 | |||
APPENDIX A - DEFINITIONS OF CERTAIN TERMS |
42 | |||
APPENDIX B SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SERIES OF FIRST PREFERRED SHARES |
46 | |||
APPENDIX C - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERAS SECURITIES IN 2023 |
49 | |||
APPENDIX D - EMERA INCORPORATED AUDIT COMMITTEE CHARTER |
50 |
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PRESENTATION OF INFORMATION
Unless otherwise noted, the information contained in this Annual Information Form (AIF) is given at or for the year ended December 31, 2023. Amounts are expressed in Canadian dollars unless otherwise indicated. All financial information presented in millions of Canadian dollars is rounded to the nearest million unless otherwise stated. Unless otherwise indicated, all financial information is presented in accordance with United States generally accepted accounting principles (USGAAP). Emera Incorporated (Emera or the Company) uses Adjusted Net Income Attributable to Common Shareholders (adjusted net income) as a financial performance measure, which is not a defined financial measure according to USGAAP and does not have standardized meanings prescribed by USGAAP. For further information on the non-GAAP financial measure, adjusted net income, including a full description of the measure and a reconciliation to the nearest USGAAP measure, please refer to the Companys MD&A section entitled Non-GAAP Financial Measures and Ratios, which is incorporated herein by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Certain capitalized terms used herein, and not otherwise defined herein, are defined under Definitions of Certain Terms, attached to this AIF as Appendix A. References to including, include, or includes means including (or includes) but is not limited to and shall not be construed to limit any general statement preceding it to the specific or similar items or matters immediately following it.
This AIF provides material information about the business and operations of Emera. The Enterprise Risk and Risk Management section of the Companys MD&A is incorporated herein by reference and can be found on SEDAR+ at www.sedarplus.ca.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION
This AIF, including the documents incorporated herein by reference, contains forward-looking information and forward-looking statements within the meaning of applicable securities laws (collectively, forward-looking information). 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 forward-looking information, although not all forward-looking information contains these identifying words. References to Emera in this section include references to the subsidiaries of Emera.
The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements which reflect the current view of Emeras management with respect to Emeras objectives, plans, financial and operating performance, carbon dioxide emissions reduction goals, business prospects and opportunities. The forward-looking information reflects managements current beliefs and is based on information currently available to Emeras 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(s) at which, such events, performance or results will be achieved. All such forward-looking information in this AIF is provided pursuant to safe harbour provisions contained in applicable securities laws.
The forward-looking information in this AIF, including the documents incorporated herein by reference, includes, but is not limited to, statements regarding: Emeras revenue, earnings and cash flow; the growth and diversification of Emeras business and earnings base; future annual net income and dividend growth; expansion of Emeras business; the expected compliance by Emera with the regulation of its operations; the expected timing of regulatory decisions; forecasted capital investments; the nature, timing and costs associated with certain capital projects; the expected impact on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to medium term; expected debt maturities, repayments and renewals; expectations about increases in interest expense and/or fees associated with debt securities and credit facilities; no material adverse credit rating actions expected in the near term; the successful development of relationships with various stakeholders, the impact of currency fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within the United States.
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The forecasts and projections that make up the forward-looking information are based on reasonable assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather or global climate change, other acts of nature or other major events; seasonal weather patterns remaining stable; no significant cyber or physical attacks or disruptions to Emeras systems; the continued ability to maintain transmission and distribution systems to ensure their continued performance; continued investment in solar, wind and hydro generation; continued natural gas activity; no severe and/or prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and commodity prices; no significant variability in interest rates; expectations regarding the nature, timing and costs of capital investments of Emera and its subsidiaries; expectations regarding rate base growth; the continued competitiveness of electricity pricing when compared with other alternative sources of energy; the continued availability of commodity supply; the absence of significant changes in government energy plans and environmental laws and regulations that may materially affect Emeras operations and cash flows; maintenance of adequate insurance coverage; the ability to obtain and maintain licenses and permits; no material decrease in market energy sales prices; favourable labour relations; and sufficient human resources to deliver service and execute Emeras capital investment plan.
The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations include, but are not limited to: 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 infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats; market energy sales prices; labour relations; and availability of labour and management resources.
Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this AIF and in the documents incorporated herein by reference 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 forward-looking information as a result of new information, future events or otherwise.
CORPORATE STRUCTURE
Name and Incorporation
Emera was incorporated on July 23, 1998 pursuant to the Companies Act (Nova Scotia). The Reorganization Act and the Privatization Act require the Companys Articles of Association (the Articles) to contain provisions specifying that the head office and the principal executive offices of the Company are to be situated in the Province of Nova Scotia. The current address of the Companys registered office, head office and principal executive offices is Emera Place, 5151 Terminal Road, Halifax, Nova Scotia, Canada, B3J 1A1.
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Amended Articles of Association
On April 12, 2019, amendments to the Privatization Act and the Reorganization Act were enacted, removing the legislative restriction preventing non-Canadian residents from holding more than 25 per cent of Emera voting shares, in aggregate. These legislative amendments did not alter the existing 15 per cent individual share ownership restriction, as described below in the section entitled Capital Structure Share Ownership Restrictions. The Board approved amendments to the Companys Articles and on July 11, 2019, shareholders passed a special resolution to amend the Articles to remove this non-Canadian resident ownership restriction. For more information on these amendments to the Articles, please refer to Emeras Management Information Circular dated May 31, 2019 distributed in connection with a special meeting of shareholders held on July 11, 2019, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Intercorporate Relationships
The following table sets forth the relationships among the Company and its principal subsidiaries, the percentage of votes attaching to all voting securities of its respective subsidiaries beneficially owned, or controlled or directed, directly or indirectly, by the Company, as well as their respective jurisdictions of incorporation, continuance, formation or organization. This table excludes certain subsidiaries, the assets and revenues of which did not individually exceed 10 per cent, or in the aggregate exceed 20 per cent, of the total consolidated assets or total consolidated revenues of the Company as at December 31, 2023.
Subsidiaries |
Percentage Ownership (%) |
Jurisdiction | ||||
Tampa Electric Company1 |
100 | Florida | ||||
Nova Scotia Power |
100 | Nova Scotia | ||||
Peoples Gas System1 |
100 | Florida | ||||
New Mexico Gas Company |
100 | Delaware |
(1) | Tampa Electric Company has historically included both its regulated electric and gas utilities, namely the Tampa Electric Division and the Peoples Gas System Division. Effective January 1, 2023, PGS ceased to be a division of TEC and the gas utility was reorganized, resulting in a separate legal entity called Peoples Gas System, Inc. (existing under the laws of the State of Florida, and a wholly-owned direct subsidiary of TECO Gas Operations, Inc. |
INTRODUCTION
Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the United States and the Caribbean. Cost-of-service utilities provide essential electric and gas services in designated territories under franchises and are overseen by regulatory authorities. Emeras strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its customers.
The majority of Emeras investments in rate-regulated businesses are located in Florida with other investments in Nova Scotia, New Mexico and the Caribbean. Emeras portfolio of regulated utilities provides 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 ROE as approved through regulation. Earnings are also affected by sales volumes and operating expenses.
Emeras 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
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anticipated that approximately 75 per cent of Emeras $9 billion capital investment plan over the 2024 through 2026 period will be made in Florida.
Emeras 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 Companys capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emeras DRIP and 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 of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emeras 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.
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 place increased pressure on energy costs, and thus customer rates, at a time when affordability is a challenge.
Emeras strategy is to invest in the energy future, including infrastructure renewal, centered on delivering value for customers, and in doing so creating value for shareholders. This includes:
| investing in cleaner and renewable sources of energy, in the related transmission assets, and in energy storage needed to support intermittent renewables; |
| supporting increasing demand from customers and the ongoing electrification of other sectors; |
| improving system reliability and resiliency, including replacing aging infrastructure and expanding systems to service new customers; and |
| 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 by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.
This vision is inspired by Emeras strong track record, the Companys experienced team, and a visible path to Emeras 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. |
| The retirement of Emeras last existing coal unit no later than 2040. |
| An 80 per cent reduction in carbon dioxide emissions by 2040. |
Achieving the above climate goals on these timelines is subject to the Companys regulatory obligations and other external factors beyond Emeras 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.
DESCRIPTION OF THE BUSINESS
Business Segments
Emeras reportable segments are:
| Florida Electric Utility, which consists of TEC; |
| Canadian Electric Utilities, which includes NSPI and ENL, a holding company with equity interests in NSPML (100 per cent) and the LIL (31 per cent); |
| Gas Utilities and Infrastructure, which includes PGS, NMGC, Emera Brunswick Pipeline Company, SeaCoast and an equity interest in M&NP (12.9 per cent); |
| Other Electric Utilities, which includes ECI, a holding company with regulated electric utilities which include BLPC, GBPC and an equity interest in Lucelec (19.5 per cent); and |
| Other, which includes Emera Energy, Block Energy and corporate holding, financing companies and certain other investments. |
General
Emera and its subsidiaries had 7,366 employees as at December 31, 2023, approximately 30 per cent of whom are unionized.
Operations by Segment
The following sections describe the operations included in each of the Companys reportable segments.
Florida Electric Utility
Florida Electric Utility consists of TEC, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. TEC has $12 billion USD of assets, approximately 840,000 customers and 2,546 employees as at December 31, 2023.
TEC is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which occur at the initiative of TEC, the FPSC or other interested parties.
TECs approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity capital structure of 54 per cent. An ROE of 10.20 per cent is used for the calculation of the return on investments for clauses.
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For further details on TECs regulatory environment, base rates and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Market and Sales
TEC Revenue and Sales Volumes by Customer Class | ||||||||
Electric Revenues (%) | GWh Electric Sales Volumes (%) | |||||||
For the year ended December 31 | 2023 | 2022 | 2023 | 2022 | ||||
Residential |
64.9 | 54.7 | 49.0 | 48.4 | ||||
Commercial |
30.4 | 26.4 | 30.7 | 30.2 | ||||
Industrial |
7.7 | 7.0 | 9.9 | 10.1 | ||||
Other |
(3.0)1 | 11.9 | 10.4 | 11.3 | ||||
Total |
100.0 | 100.0 | 100.0 | 100.0 |
(1) | Other includes regulatory deferrals related to clauses, sales to public authorities, off-system sales to other utilities. |
Energy Sources and Generation
As at December 31, 2023, TEC owns 6,433 MW of generating capacity, of which 74 per cent is natural gas fired, 19 per cent is solar and 7 per cent is coal. TEC owns 2,192 kilometres of transmission facilities and 20,299 kilometres of distribution facilities. TEC meets the planning criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.
System Operations
TECs Energy Control Center co-ordinates and controls the electric generation, transmission and distribution facilities. The Energy Control Center is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system operators for remote monitoring and control of the power system assets.
Through interconnection agreements with our neighboring electric utilities within the Florida Region, TECs system has access to other regional power systems and the rest of the interconnected North American electric bulk power system. The interconnection of power systems enhances the cost effectiveness, reserve capacity and reliability of participating power systems. As a member of the Florida Reserve Sharing Group, TEC has immediate access to reserve generating capacity from all other group members.
Contribution to Consolidated Net Income
Florida Electric Utilitys contribution to consolidated net income was $466 million USD in 2023 (2022 $458 million USD).
Seasonal Nature
Electric sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal. In Florida, Q3 is the strongest period for electricity sales, reflecting warmer weather and cooling demand.
Capital Investments
In 2023, capital investments, including AFUDC, in the Florida Electric Utility segment were $1.3 billion USD (2022 $1.1 billion USD). In 2024, capital investment is expected to be approximately $1.3 billion USD, including AFUDC. Capital projects include solar investments, grid modernization, storm hardening investments and other infrastructure investments.
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Environmental Considerations
TEC has significant environmental considerations. TEC operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters.
Hazardous Air Pollutants
All of TECs conventional coal-fired units are already equipped with electrostatic precipitators, scrubbers and selective catalytic reduction systems, and the Polk Unit 1 integrated gasification combined-cycle unit emissions are minimized in the gasification process. Therefore, TEC has minimized the impact of the EPAs current Mercury Air Toxics Standards (MATS) and has demonstrated compliance on all applicable units with the most stringent Low Emitting Electric Generating Unit classification for the EPAs current MATS with nominal additional capital investment.
Carbon Reductions and GHG
In June 2019, the EPA released a final rule, named the Affordable Clean Energy (ACE) rule, to establish emission guidelines for states to address GHG emissions from existing coal-fired electric generating units (EGUs). EPA released a proposed rule establishing CO2 emission standards for new and existing fossil fuel-fired power plants. As proposed under Section 111 of the Clean Air Act, the New Source Performance Standards and Best System of Emission Reduction guidelines would require affected electric generating units to achieve CO2 emission limits thorough the implementation of carbon capture and sequestration, or low-GHG hydrogen co-firing. The proposed rule also repeals the ACE rule promulgated under the Trump Administration. TEC expects one or more units to be subject to the rule, if finalized in its current form.
TEC expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO2 emissions reductions would be reflected in customers bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, TEC could seek to recover those costs through a base-rate proceeding.
Ozone
On December 31, 2020, the EPA published a final rule to retain the national ambient air quality standards (NAAQS) for photochemical oxidants including ozone, originally adopted in 2012. Under the Clean Air Act, the EPA is required to review the NAAQS every five years and, if appropriate, revise it. The EPA has announced that the NAAQS is currently under review, which could result in revisions to the standard affecting compliance in TECs service territory. The impact of this potential new standard on the operations of TEC will depend on the standard that is ultimately adopted and on the outcome of any related litigation or other developments.
Water Supply and Quality
The EPAs final rule under 316(b) of the Clean Water Act (effective October 2014) addresses perceived impacts to aquatic life by cooling water intakes and is applicable to TECs Bayside and Big Bend Power Stations. Polk Power Station is not covered by this rule since it does not operate an intake on waters of the U.S. TEC has two ongoing projects (one for Bayside and one for Big Bend) that require compliance with the rule. The Florida Department of Environmental Protection (FDEP) agreed with TECs proposed plan for Bayside and TEC began a multi-year construction project to install new fish-friendly modified traveling screens and a fish return in 2022. Compliance study elements have been completed and submitted for Bayside. TEC is negotiating an alternative schedule for a portion of the compliance requirements with the Big Bend modernization project, with the remainder of the compliance requirements to be determined and completed at a later date. The full impact of the regulations on TEC will depend on the outcome of subsequent legal proceedings challenging the rule, the results of the study elements performed as part of the rules implementation, and the actual requirements established by FDEP.
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The final EPA rule for existing steam electric effluent limit guidelines (ELGs) became effective January 4, 2016 and establishes limits for certain wastewater discharges. The ELGs are expected to be incorporated into National Pollutant Discharge Elimination System (NPDES) permit renewals for Big Bend Station and Polk Power Station to achieve compliance as soon as possible after November 1, 2018, but no later than December 31, 2023. The EPA proposed a new rule in March 2023 to strengthen discharge limits that is expected to be finalized in 2024.
The preliminary draft of the NPDES Permit for Big Bend stated that effluent limitations for total recoverable arsenic, mercury, and selenium and total nitrate/nitrite for flue gas desulfurization wastewater are applicable no later than December 31, 2023. Big Bend completed construction of a deep injection well system in December 2023 for disposal of various wastewaters. The effluent limitations do not apply to Polk Power Station.
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, PGS is also now a PRP for those sites (in addition to third party PRPs for certain sites). For further details, refer to Note 27, Commitments and Contingencies Legal Proceedings - Superfund and Former Manufactured Gas Plant Sites, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Canadian Electric Utilities
Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia. ENL is a holding company with a 100 per cent equity investment in NSPML and a 31 per cent equity investment in LIL: two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls hydroelectric project (Muskrat Falls) on the Lower Churchill River in Labrador.
NSPI
NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to approximately 549,000 customers with $7.2 billion in assets and 2,179 employees as at December 31, 2023.
NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPIs operations and expenditures. Electricity rates for NSPIs customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPIs or the UARBs request.
NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-related costs from customers through regularly scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in subsequent periods.
NSPIs approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent.
For further details on NSPIs regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
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Market and Sales
NSPI Revenue and Electricity Sales Volumes by Customer Class | ||||||||
Electric Revenues (%) | GWh Electric Sales Volumes (%) | |||||||
For the year ended December 31 | 2023 | 2022 | 2023 | 2022 | ||||
Residential | 55.7 | 50.8 | 47.8 | 46.1 | ||||
Commercial | 28.4 | 26.0 | 29.2 | 28.8 | ||||
Industrial | 13.4 | 21.5 | 20.7 | 23.7 | ||||
Other | 2.5 | 1.7 | 2.3 | 1.4 | ||||
Total | 100.0 | 100.0 | 100.0 | 100.0 |
Energy Sources and Generation
NSPI owns 2,422 MW of generating capacity, of which 44 per cent is coal and/or oil-fired, 28 per cent is natural gas and/or oil, 19 per cent is hydro, wind, or solar, 7 per cent is petroleum coke and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from IPPs, and COMFIT participants, which own 532 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcors NS Block delivery obligations, as discussed below.
Nalcor is obligated to provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, Nalcor is obligated to provide approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from Nalcor for up to 1.8 Terawatt hours (TWh) of energy in any given year and, on average, 1.2 TWh of energy per year through August 31, 2041.
System Operations
NSPIs Control Center Operations co-ordinates and controls the electric generation, transmission and distribution facilities with the goal of providing safe, reliable and efficient electricity supply while adhering to applicable environmental requirements and regulations. The Control Center is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a software applicaction used by system operators for remote monitoring and control of the power system assets via the companys telecommunication networks.
Through interconnection agreements with NB Power and with Newfoundland and Labrador Hydro, NSPIs system has access to other regional power systems and the interconnected North American bulk electric system. The interconnection of power systems enhances the cost effectiveness, reserve capacity and reliability of participating power systems. The interconnection agreements also provide participating utilities with a source of reserve power, subject to availability, transmission line capacity and the requirements of the supplier.
NSPI is a member of the NPCC, a body whose primary role is promoting the reliability of the interconnected power systems throughout the Northeastern United States and Eastern Canada (Nova Scotia, New Brunswick, Quebec, Ontario) under the regulatory authority of NERC. NERC and NPCC reliability standards and criteria are approved for enforcement in Nova Scotia by the UARB. NSPI complies with NPCC criteria and NERC standards for the design, planning and operation of NSPIs portion of the interconnected bulk electric system.
Transmission and Distribution
NSPI transmits and distributes electricity from its generating stations to its customers. NSPIs transmission system consists of approximately 5,000 km of transmission facilities. The distribution system consists of approximately 28,000 km of distribution facilities, which includes distribution supply substations.
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ENL
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPMLs approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.
The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. Nalcors NS Block delivery obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project agreements.
LIL
ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canadas Independent Engineer issuing its Commissioning Certificate on April 13, 2023.
Upon issuance of the Commissioning Certificate, AFUDC equity earnings ceased and cash equity earnings and return of equity to Emera commenced. The first distribution was received from the LIL partnership in Q4 2023.
Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emeras current equity investment is $747 million, comprised of $410 million in equity contribution and $337 million of accumulated equity earnings. Emeras total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million once the final costing has been confirmed by Nalcor to determine the amount of the remaining investment.
Contribution to Consolidated Net Income and Adjusted Net Income
Canadian Electric Utilities contribution to consolidated net income was $247 million in 2023 (2022 - $215 million). Canadian Electric Utilities contribution to Emeras consolidated adjusted net income was $247 million in 2023 (2022 - $222 million). For a reconciliation of Canadian Electric Utilities adjusted net income to consolidated net income, refer to the Non-GAAP Financial Measures and Ratios and Financial Highlights Canadian Electric Utilities sections of Emeras MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Seasonal Nature
Electric sales volumes are primarily driven by weather, number of customers, general economic conditions, and demand side management activities. Residential and commercial electricity sales are seasonal in Nova Scotia, with Q1 historically generating the highest sales, reflecting colder weather and fewer daylight hours in the winter season.
Capital Investment
NSPI
NSPIs capital investments in 2023 were $451 million (2022 $540 million), including AFUDC. In 2024, NSPI expects to invest $435 million, including AFUDC, primarily in capital projects to support power system reliability and reliable service for customers.
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NSPML
NSPML does not anticipate any significant capital investment in 2024.
Environmental Considerations
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these laws and regulations, to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated reductions will be recoverable under NSPIs regulatory framework. NSPI faces risks associated with achieving climate-related and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPIs operations and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the Enterprise Risk and Risk Management section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Other Environmental Legislation and Regulations
There have been several recent environmental developments at both the federal and provincial levels, as described below in the General Development of the Business Canadian Electric Utilities - NSPI section. For additional information on environmental regulations affecting NSPI, see also NSPIs 2023 Annual Information Form, a copy of which is available electronically under NSPIs profile on SEDAR+ at www.sedarplus.ca.
Gas Utilities and Infrastructure
Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emeras equity investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.
PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has firm transportation capacity for delivery by PGS to its customers. NMGCs natural gas is transported on major interstate pipelines on which NMGC has transportation capacity and NMGCs intrastate transmission and distribution system for delivery to customers.
Market and sales
PGS, NMGC and SeaCoast Revenue and Sales Volumes by Customer Class | ||||||||
Gas Revenues (%) | Therms Gas Sales Volumes (%) | |||||||
For the year ended December 31 | 2023 | 2022 | 2023 | 2022 | ||||
Residential | 50.3 | 49.2 | 13.2 | 14.4 | ||||
Commercial | 29.5 | 28.3 | 26.8 | 28.7 | ||||
Industrial | 6.5 | 5.1 | 51.5 | 49.1 | ||||
Other | 13.7 | 17.4 | 8.5 | 7.8 | ||||
Total | 100.0 | 100.0 | 100.0 | 100.0 |
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PGS
As at December 31, 2023, PGS serves approximately 490,000 customers with $2.8 billion USD in assets and 767 employees. The PGS system includes approximately 24,300 kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in 2023.
PGS is regulated by the FPSC. Rates are set at a level that allow the utilities to collect total revenues or revenue requirements equal to their cost to provide service, plus an appropriate return on invested capital.
Beginning in 2024, the approved ROE range for PGS is 9.15 per cent to 11.15 per cent (2023 8.9 per cent to 11.0 per cent), based on an allowed equity capital structure of 54.7 per cent (2023 54.7 per cent). An ROE of 10.15 per cent (2023 9.9 per cent) is used for the calculation of return on investments recovered through cost recovery clauses.
For further details on PGS regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
NMGC
As at December 31, 2023, NMGC serves approximately 540,000 customers with $1.8 billion USD in assets and 725 employees. NMGCs system includes 2,408 km of transmission lines and 17,657 km of distribution lines. Annual natural gas throughput was 1 billion therms in 2023.
NMGC is subject to regulation by the NMPRC. Rates are set at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.
NMGCs approved ROE is 9.375 per cent on an allowed equity capital structure of 52 per cent.
For further details on NMGCs regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
EBPC
EBPC owns Brunswick Pipeline, a regulated 145-km pipeline delivering re-gasified liquefied natural gas from the Saint John LNG import terminal near Saint John, New Brunswick to markets in the Northeastern United States. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/U.S. border near Baileyville, Maine.
Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RENAC under a 25-year firm service agreement, which expires in 2034. Brunswick Pipeline is regulated by the CER, which has classified it as a Group II pipeline. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to a regulatory approval process. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipelines tolls, which are subject to a firm service agreement with RENAC, as noted above. The firm service agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.
Economic Dependence
Brunswick Pipeline has a 25-year firm service agreement with RENAC, which expires in 2034. The risk of non-payment is mitigated as Repsol, the parent company of RENAC, has provided EBPC with a guarantee for all RENACs payment obligations under the firm service agreement.
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M&NP
Emera owns a 12.9 per cent interest in M&NP, which is a 1,400 km pipeline that transports natural gas throughout markets in Atlantic Canada and the Northeastern United States.
Contribution to Consolidated Net Income
Gas Utilities and Infrastructures contribution to consolidated net income was $158 million USD in 2023 (2022 $170 million USD).
Seasonal Nature
Gas sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial gas sales are seasonal. In Florida and New Mexico, Q1 is the strongest period for gas sales due to colder weather and heating demand.
Capital Investment
Capital investments, including AFUDC, in the Gas Utilities and Infrastructure segment in 2023 were $495 million USD (2022 - $436 million USD). In 2024, capital investment is expected to be approximately $465 million USD, including AFUDC. PGS and NMGC will make investments to maintain the reliability of their systems and support customer growth.
Environmental Considerations
PGSs operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment that generally require monitoring, permitting and ongoing expenditures. 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). For further details, refer to Note 27, Commitments and Contingencies Legal Proceedings - Superfund and Former Manufactured Gas Plant Sites, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Brunswick Pipeline is subject to both federal and provincial environmental regulations. Brunswick Pipeline has comprehensive integrity, safety and environmental programs in place, including an integrated management system to ensure compliance and continuous improvement of its integrity, safety and environmental programs. Brunswick Pipeline also conducts regularly scheduled physical inspections of the pipeline and its right-of-way.
Other Electric Utilities
Other Electric Utilities includes ECI, a holding company with regulated electric utilities. ECIs regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island and a 19.5 per cent equity investment in Lucelec on the island of St. Lucia.
Market and Sales
Other Electric Utilities operating revenues for 2023 were $390 million USD (2022 $398 million USD) and electric sales volumes were 1,260 GWh (2022 1,239 GWh).
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BLPC
As at December 31, 2023, BLPC serves approximately 134,000 customers with $517 million USD of assets and a workforce of 414 employees. BLPC owns 243 MW of generating capacity, of which 96 per cent is oil-fired and 4 per cent is solar. BLPCs transmission system consists of 188 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of 3,839 km of distribution lines which includes distribution supply substations.
BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation.The timing of the final enactment is unknown at this time, but BLPC will work towards the implementation of the licenses once enacted.
BLPC is regulated by the FTC. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPCs approved regulated return on rate base is 10 per cent.
GBPC
As at December 31, 2023, GBPC serves approximately 19,000 customers, with $334 million USD of assets and a workforce of 205 employees. GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 994 kilometers of distribution facilities.
GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPCs approved regulatory return on rate base is 8.52 per cent for 2024 (2023 8.32 per cent). For further details on GBPCs regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
System Operation
BLPC and GBPC have system control centres that co-ordinate and control their electric generation and transmission facilities with the goal of providing a reliable and secure electricity supply while maintaining economy of operations. The generation and transmission system control centres are linked to their generating stations and other key parts of their systems by the Supervisory Control and Data Acquisition systems, with fibre optic, voice and data communications networks.
Transmission and Distribution
BLPC and GBPC transmit and distribute electricity from their generating stations to their customers.
Contribution to Consolidated Net Income and Adjusted Net Income
Other Electric Utilities contribution to consolidated net income was $28 million USD in 2023 (2022 a loss of $35 million USD). Other Electric Utilities contribution to consolidated adjusted net income was $26 million USD in 2023 (2022 $23 million USD). For a reconciliation of Other Electric Utilities adjusted net income to consolidated net income, refer to the Non-GAAP Financial Measures and Ratios and Financial Highlights Other Electric Utilities sections of Emeras MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
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Seasonal Nature
Electricity sales and related generation varies significantly over the year in the Caribbean; Q3 is typically the strongest period, reflecting warmer weather. Grand Bahama is also particularly prone to tropical storm and hurricane impacts during Q3.
Capital Investment
Other Electric Utilities capital investments (including AFUDC) for 2023 were $47 million USD (2022 $48 million USD). In 2024, capital investment is expected to be approximately $80 million USD, primarily in more efficient and cleaner sources of generation, including renewables and battery storage.
Environmental Considerations
Emeras Caribbean utilities have implemented formal health & safety and environmental and management systems to assist in safeguarding the health and safety of its employees, contractors and customers while ensuring protection of the environment.
Other
The Other segment includes those business operations that in a normal year are below the required threshold for reporting as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emeras subsidiaries and investments.
Business operations in the Other segment include Emera Energy and Block Energy. Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. Block Energy is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.
Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings and interest expense on corporate debt in both Canada and the U.S. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emeras subsidiaries and investments.
Emera Energy
EES derives revenue and earnings from the wholesale marketing and trading of natural gas and electricity within the companys risk tolerances, including those related to value-at-risk and credit exposure. EES purchases and sells physical natural gas and electricity, the related transportation and transmission capacity rights, and provides related energy asset management services. The primary market area for the natural gas and power marketing and trading business is northeastern North America, including the Marcellus and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast and Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. EES operates in a competitive environment, and the business relies on knowledge of the regions energy markets, understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.
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
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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.
Contribution to Consolidated Net Income and Adjusted Net Income
Others contribution to consolidated net income was a loss of $147 million in 2023 (2022 loss of $39 million). Others contribution to consolidated adjusted net income was a loss of $314 million in 2023 (2022 loss of $218 million). For further information on the non-GAAP measure adjusted net income, refer to the Non-GAAP Financial Measures and Ratios and Financial Highlights Other sections of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Capital Investment
In 2024, capital investment in the Other segment is not expected to be significant.
GENERAL DEVELOPMENT OF THE BUSINESS
Three Year History and Changes Expected in 2024
The following discussion summarizes key developments in Emeras business and operations over the last three completed financial years and changes that are expected to occur during the current financial year.
Florida Electric Utility
Base Rates
On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement by TEC and the intervenors in relation to its rate case filed with the FPSC in April 2021. On October 21, 2021, the FPSC approved a settlement agreement filed by TEC. The settlement agreement allows for an increase of $191 million USD annually, effective January 2022. This increase consisted of $123 million USD in base rate charges and $68 million USD to recover the costs of retiring assets, including Big Bend coal generation assets Units 1 through 3 and meter assets. The settlement agreement further includes two subsequent year adjustments of $90 million USD and $21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The settlement agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint.
On August 16, 2022, the FPSC approved TECs request to increase revenue and ROE due to increases in the 30-year United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point ROE is 10.20 per cent, and the range is 9.25 per cent to 11.25 per cent.
On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TECs ROE adjustment, the increase of $22 million USD was approved by the FPSC on November 17, 2023.
On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January 2025, reflecting a revenue requirement increase of approximately $290 to $320 million USD and additional adjustments of approximately $100 million USD and $70 million USD for 2026 and 2027, respectively. TECs proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024. The FPSC is scheduled to hear the case in Q3 2024 with a decision expected by the end of 2024.
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Fuel Recovery
The mid-course fuel adjustment requested by TEC on July 19, 2021, was approved on August 3, 2021. The rate increase, effective with September 2021 customer bills, covered higher fuel and capacity costs of $83 million USD, and was spread over customer bills from September through December 2021.
The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD, and was spread over customer bills from April 1, 2022 through December 2022.
On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, and were effective beginning on April 1, 2023.
Solar Projects
During 2017 to 2021, TEC invested $850 million USD in 600 MW of utility-scale solar photovoltaic projects, which is recoverable through FPSC-approved SoBRAs. AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW or $104 million USD annually in estimated revenue requirements for in-service projects.
On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates as of January 2020. A $4 million USD true-up was returned to customers during 2021. No true-up for SoBRA tranche 4 was required.
Big Bend Modernization Project
TEC invested $876 million USD, including $91 million USD of AFUDC, during 2018 through 2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this units fuel. As part of the modernization project, TEC retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, of $636 million USD and $267 million USD in accumulated depreciation were reclassified to a regulatory asset on the balance sheet.
TECs 2021 settlement agreement provides recovery for the Big Bend Modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years, effective January 1, 2022. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.
Storm Reserve
In September 2022, TEC was impacted by Hurricane Ian with $119 million USD of restoration costs charged against TECs FPSC approved storm reserve. Total restoration costs charged to the storm reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery.
On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the approved storm reserve level of $56 million USD, for a total of $131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9, 2023, the
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FPSC approved TECs petition, filed on August 16, 2023, to update the total storm cost collection to $134 million USD. It also changed the collection of the expected remaining balance of $29 million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC.
In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were approximately $35 million USD, which were charged to the storm reserve regulatory asset, resulting in minimal impact to earnings. TEC will determine the timing of the request for recovery of Hurricane Idalia costs at a future time.
Storm Protection Cost Recovery Clause and Settlement Agreement
The Storm Protection Plan (SPP) Cost Recovery Clause provides a process for Florida investor-owned utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and TECs cost recovery began in January 2021. The previously approved plan addressed the years 2020 through 2022, and in April 2022 TEC submitted a new plan to determine cost recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved TECs current SPP for those years.
For more information, refer to the Regulatory Environments and Updates Florida Electric Utility section of Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca
Canadian Electric Utilities
NSPI
General Rate Application
On February 2, 2023, the UARB approved the General Rate Application Settlement Agreement between NSPI, key customer representatives and participating interest groups. This resulted in average customer rate increases of 6.9 per cent effective on February 2, 2023, and further average increase of 6.5 per cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARBs established FAM process. It also established a storm rider and a demand-side management rider. On March 27, 2023 the UARB issued a final order approving the electricity rates effective on February 2, 2023.
Fuel Recovery
For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate adjustments related to the under-recovery of fuel and fuel-related costs in the period.
On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the amortization and financing costs of $117 million on behalf of Invest Nova Scotia over a 10-year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. A decision is expected in the first half of 2024. It is anticipated that NSPI will apply to the UARB later in 2024 to collect additional under-recovered fuel amounts in 2025 or future periods, subject to the approval of the UARB.
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Extra Large Industrial Active Demand Tariff
On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, effective January 1, 2022, results in a shifting of fuel costs from this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $51 million increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables and other current assets. This adjustment had minimal impact on earnings.
Hurricane Fiona
On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a post-tropical storm equivalent to a Category 2 hurricane. The storm had sustained winds of over 100 km per hour and peak gusts of approximately 180 km per hour. This historic storm for Nova Scotia caused significant and widespread damage to NSPIs transmission and distribution system and at the height of the storm approximately 415,000 customers lost power. The total cost of the restoration was approximately $120 million, of which $96 million was capitalized to PP&E and $24 million deferred to Other long-term assets for future amortization, subject to UARB approval.
On October 31, 2023, NSPI submitted an application to the UARB to defer $24 million in incremental operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is seeking amortization of the costs over a period to be approved by the UARB during a future rate setting process. At December 31, 2023 the $24 million is deferred to Other long-term assets, pending UARB approval.
Post-Tropical Storm Lee
On September 16, 2023, Nova Scotia was struck by post-tropical storm Lee and as a result, approximately 280,000 customers lost power. The total cost of storm restoration was $19 million, with $9 million charged to OM&G, $5 million capitalized to PP&E and $5 million deferred to the UARB approved storm rider. The storm rider for each of 2023, 2024, and 2025 allows NSPI to apply to the UARB for deferral and recovery of expenses if major storm restoration expenses exceed approximately $10 million in any given year. The application for deferral of the storm rider is made in the year following the year of the incurred costs, with recovery beginning in the year after the application.
Regulatory Matters General
For more information, refer to the Regulatory Environments and Updates Canadian Electric Utilities NSPI section of Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Environmental Legislation and Regulations
Greenhouse Gas Emissions
On June 29, 2021, the federal government enacted Bill C-12 Canadian Net-Zero Emissions Accountability Act with the objective of attaining net-zero emissions by 2050.
On July 9, 2021, the Nova Scotia provincial government amended the Renewable Electricity Regulations, mandating that 80 per cent of electric sales be generated from renewable sources by 2030.
On August 5, 2021, the federal government issued an update to the Pan-Canadian Framework on Clean Growth and Climate Change under the Greenhouse Gas Pollution Pricing Act. This update (the Federal Benchmark) applies to the 2023 through 2030 period and puts in place the legal mechanism for increasing the carbon tax in Canada by $15 per tonne annually and reaching $170 per tonne by 2030. It also outlines
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the minimum compliance criteria for recognizing systems like the Nova Scotia Cap-and-Trade Program to be considered equivalent to the Federal Benchmark.
On November 5, 2021, the Nova Scotia provincial government enacted Bill 57, Environmental Goals and Climate Change Reduction Act, which signals the provincial governments intent to implement several climate change related goals and greenhouse gas reduction targets, many of which overlap with and replace provisions of pre-existing acts. The legislation also introduces a goal to phase out coal-fired electricity generation in Nova Scotia by 2030. Subsequent provincial regulations will be required to detail how these goals and targets will be achieved.
In March 2022 the federal government issued their 2030 Emission Reduction Plan required under the Canadian Net-Zero Emissions Accountability Act. The Emission Reduction Plan acknowledges the federal and provincial emission reduction goals and programs currently legislated and also signals the intention for implementation of further emission reduction goals, including the federal intention of attaining a net-zero electricity grid by 2035. Subsequent regulations will be required to detail how this goal will be achieved.
Clean Electricity Solutions Task Force
The Clean Electricity Solutions Task Force (the Task Force) was created by the Province in April 2023 to advise the provincial government on Nova Scotias transition away from coal to more renewable sources of energy. On February 23, 2024, the Task Force released its report and recommendations, based on engagement with stakeholders, including NSPI. The Task Force report focuses on findings related to system operations, regulatory oversight, reliability, transmission and affordability. The Task Force announced a number of recommendations including a strengthening of the authority and independence of the regulator and the establishment of an independent system operator in order to support the continuing transition to clean energy and the achievement of federal and provincial clean energy goals and legislation. The Province announced they intend to accept these recommendations and will table enabling legislation in its upcoming session which starts February 27, 2024.
Nova Scotia Renewable Electricity Regulations
Under the provincially legislated RER , starting in 2020, 40 per cent of electric sales must be generated from renewable sources. NSPI met this target in 2023, with 43 per cent of NSPIs electric sales coming form renewable sources, subject to a compliance filing.
Due to the delay of NSPI receiving energy form the NS Block, the Province provided NSPI with an alternative compliance plan that required NSPI to achieve 40 per cent of electric sales generated from renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the alternative compliance plan.
On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER compliance period ending in 2022. The penalty was recorded in OM&G on the Consolidated Statements of Income. On May 26, 2023, NSPI initiated an appeal of the penalty through a proceeding with the UARB, as permitted under the RER. On October 12, 2023, the UARB decided that it will hear the appeal by giving due deference to the Provinces decision but permitting the filing of new evidence to support the parties positions. The hearing for the matter is scheduled for June 2024 and a decision is expected before the end of 2024.
Carbon Pricing Regulations
In November 2022, the Province enacted amendments to the Environment Act which provided the framework for Nova Scotia to implement an OBPS to comply with the Government of Canadas 2023 through 2030 carbon pollution pricing regulations effective January 1, 2023. The Government of Canada approved the Provinces proposed system, however the OBPS will be subject to an interim review by the Government of Canada of the standards effective for 2026. The final Output-Based Pricing System
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Reporting and Compliance Regulations were prescribed by Order in Council dated January 30, 2024. The OBPS GHG emissions performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023 and will increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPIs regulatory framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPIs FAM.
Nova Scotia Cap-and-Trade Program Regulations
NSPI was a participant in the Nova Scotia Cap-and-Trade Program and was subject to the 2019 through 2022 compliance period. On March 16, 2023, the Province provided NSPI with emissions allowances sufficient to achieve compliance for the 2019 through 2022 compliance period. As such, compliance costs accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $6 million were not refunded and no further costs were incurred to achieve compliance with the Nova Scotia Cap-and-Trade Program.
Other Legislation
Electricity Act Amendment
On November 9, 2023, the Province enacted amendments in the Electricity Act which permit the Governor in Council to approve energy storage projects proposed by a public utility and owned wholly or in majority by the public utility if the project is in the best interest of ratepayers. Further, the amendments to the Electricity Act expand the ability of the Province to require NSPI to enter into power purchase agreements with renewable generation facilities by further empowering the Province to require NSPI to enter into an agreement for the sale of the electricity to specified customers. This allows specified customers to buy renewable electricity from specified producers, with NSPI managing the transmission and sale of the energy. On December 21, 2023, the Governor in Council enacted regulations which directed NSPI to install three 50 MW four-hour duration grid-scale batteries as part of the regulated assets of NSPI.
Performance Standards Penalty Amendment
On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-compliance with current and future performance standards in a calendar year from $1 million to $25 million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot recover administrative penalties imposed through rates.
ENL
Maritime Link Project
On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and approval of NSPMLs 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARBs decision on the application.
In February 2022, the UARB issued its decision and Board Order approving NSPMLs requested rate base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168 million (2021 $172 million) from NSPI for the recovery of costs associated with the Maritime Link in 2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, release of which was contingent on receiving in that month at least 90 per cent of NS Block deliveries, including supplemental Energy deliveries.
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In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023, subject to a monthly holdback of up to $2 million, which will increase to $4 million beginning December 2023, as discussed below.
On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and future holdback amounts and requirements to end the holdback mechanism. In these decisions, the UARB agreed with the Companys submission that $12 million ($8 million related to 2022 and $4 million relating to 2023) of the previously recorded holdback remain credited to NSPIs FAM, with the remainder released to NSPML and recorded in Emeras Income from equity investments. NSPML did not record any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease once 90 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential relief for planned outages or exceptional circumstances) and the net outstanding balance of previously underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the UARB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023. NSPML expects to file an application to terminate the holdback in 2024.
On December 21, 2023, NSPML received approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up to $4 million a month, as discussed above.
Gas Utilities and Infrastructure
PGS
Base Rates
On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allowed for an increase to base rates by $58 million USD annually effective January 1, 2021, which is a $34 million USD increase in revenue and $24 million USD increase of revenues previously recovered through the cast iron and bare steel replacement rider. It provided PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. PGS reversed $20 million USD of accumulated depreciation in 2023 and $14 million USD in 2022.
On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in September 2023. On November 9, 2023, the FPSC approved a $118 million USD increase to base revenues which includes $11 million USD transferred from the cast iron and bare steel replacement rider, for a net incremental increase to base revenues of $107 million USD. This reflects a 10.15 per cent midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on December 27, 2023, with the new rates effective January 2024.
NMGC
Base Rates
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the settlement agreement on November 30, 2022.
On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective Q4 2024. NMGC requested $49 million USD in annual base revenues primarily as a result of increased operating costs and capital investments in pipeline projects and related infrastructure. The rate case includes a requested ROE of 10.5 per cent. A final order from the NMPRC is expected in Q3 2024.
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NMGC Winter Event Gas Cost Recovery
In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $108 million USD for gas costs above what it would normally have paid during this period. NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause. On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge. On June 15, 2021, the NMPRC approved the recovery of $108 million USD and related borrowing costs over a period of 30 months from July 1, 2021, to December 31, 2023.
For more information, refer to the Regulatory Environments and Updates Gas Utilities and Infrastructure section of Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
Other Electric Utilities
BLPC
General Rate Review
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 related to the self-insurance fund of $50 million USD, prior year benefits recognized on remeasurement of deferred income taxes of $5 million USD, and accumulated depreciation of $16 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the Motion) and applied for a stay of the FTCs 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 FTCs 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. BLPCs 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 BLPCs final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. Management does not expect the final decision and order to have a material impact on adjusted net income.
Clean Energy Transition Program (CETP)
On May 31, 2023, the FTC approved BLPCs application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETP (the Decision). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the CETP.
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GBPC
Base Rates
On January 14, 2022, the GBPA issued its decision on GBPCs application for rate review that was filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The rates include a regulatory ROE of 12.84 per cent.
Fuel Recovery
Effective November 1, 2022, GBPCs fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023 the fuel pass through charge was adjusted monthly, in-line with actual fuel costs.
Storm Restoration Costs Hurricane Matthew
As part of the recovery of costs incurred as a result of Hurricane Matthew in 2016, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPCs application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.
For more information, refer to the Regulatory Environments and Updates Other Electric Utilities section of Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
USGAAP Exemptive Relief
On January 28, 2021, the International Accounting Standards Board (IASB) published an Exposure Draft: Regulatory Assets and Regulatory Liabilities, which proposes the accounting model under which a company subject to rate regulation that meets the scope criteria would recognize regulatory assets and liabilities. The proposed effective date is annual reporting periods beginning on or after a date 18-24 months from the date of publication of the standard. Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report its financial results in accordance with USGAAP (collectively the Exemptive Relief). The Exemptive Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have rate-regulated activities, the first day of the Companys financial year that commences after the Company ceases to have rate-regulated activities; and (iii) the first day of the Companys financial year that commences on or following the later of: (a) the effective date prescribed by the IASB for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities (Mandatory Rate-regulated Standard); and (b) two years after the IASB publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1, 2024.
The Company will continue to monitor the development of the Mandatory Rate-regulated Standard and assess the impact on the existing Exemptive Relief.
Financing Activity
At-The-Market Equity Program
On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Companys discretion, at the
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prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the Companys short form base shelf prospectus dated August 5, 2021.
During 2021, approximately 4.99 million common shares were issued under the ATM Program at an average price of $57.63 per share for gross proceeds of $287 million ($284 million net of after-tax issuance costs). As at December 31, 2021, an aggregate gross sales limit of $457 million remained available for issuance under the ATM Program.
During 2022, approximately 4.07 million common shares were issued under the ATM Program at an average price of $61.31 per share for gross proceeds of $250 million ($248 million net of after-tax issuance costs). As at December 31, 2022, an aggregate gross sales limit of $207 million remained available for issuance under the ATM Program, which expired on September 5, 2023.
On November 14, 2023, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Companys discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement dated November 14, 2023 to the Companys short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025.
During 2023, approximately 8.29 million common shares were issued under the ATM Program at an average price of $48.27 per share for gross proceeds of $400 million ($397 million net of after-tax issuance costs) and an aggregate gross sales limit of $200 million remained available for issuance under the ATM Program.
During 2024, up to and including February 26, 2024, no common shares were issued under the ATM Program and an aggregate gross sales limit of $200 million remains available for issuance under the ATM Program.
Preferred Share Issuances
On April 6, 2021, Emera issued 8 million Series J First Preferred Shares at $25.00 per share at an initial dividend rate of 4.25 per cent. The aggregate gross and net proceeds from the offering were $200 million and $196 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.
On September 24, 2021, Emera issued 9 million Series L First Preferred Shares, at $25.00 per share at an annual yield of 4.60 per cent. The aggregate gross and net proceeds from the offering were $225 million and $222 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.
On July 6, 2023, Emera announced it would not redeem the 10 million outstanding Series C First Preferred Shares. The holders of the Series C First Preferred Shares had the right, at their option, to convert all or any of their Series C First Preferred Shares, on a one-for-one basis, into Series D First Preferred Shares on August 15, 2023 or to continue to hold their Series C First Preferred Shares. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, no Series C First Preferred Shares would be converted into Series D First Preferred Shares.
On July 6, 2023, Emera announced it would not redeem the 12 million outstanding Series H First Preferred Shares. The holders of the Series H First Preferred Shares had the right, at their option, to convert all or any of their Series H First Preferred Shares, on a one-for-one basis, into Series I First Preferred Shares on August 15, 2023 or to continue to hold their Series H First Preferred Shares. On August 4, 2023, Emera
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announced after having taken into account all conversion notices received from holders, no Series H First Preferred Shares would be converted into Series I First Preferred Shares.
Senior Notes
On June 4, 2021, Emera US Finance LP completed an issuance of $750 million USD senior notes. The issuance included $450 million USD senior notes that bear interest at a rate of 2.64 per cent with a maturity date of June 15, 2031 and $300 million USD senior notes that bear interest at a rate of 0.83 per cent with a maturity date of June 15, 2024. The USD senior notes are guaranteed by Emera and Emera US Holdings Inc., a wholly owned Emera subsidiary.
From the $750 million USD senior notes issuance discussed above, on June 15, 2021, Emera US Finance LP repaid its previously outstanding $750 million USD senior notes on maturity.
On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent with a maturity date of May 2, 2030. The proceeds were used to repay Emeras $500 million unsecured fixed rate notes, which matured in June 2023.
For more information on financing activities for Emera and its subsidiaries, please refer to the Liquidity and Capital Resources section of Emeras MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
RISK FACTORS
For Emeras risk factors, refer to the Enterprise Risk and Risk Management section of the MD&A and the Principal Financial Risks and Uncertainties section of Note 27, Commitments and Contingencies, to the Audited Financial Statements, which are each incorporated herein by reference, copies of which are available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
CAPITAL STRUCTURE
The authorized capital of Emera consists of an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. Each class of preferred shares is issuable in series.
As at December 31, 2023, 284,117,511 common shares, 4,866,814 Series A First Preferred Shares, 1,133,186 Series B First Preferred Shares, 10,000,000 Series C First Preferred Shares, 5,000,000 Series E First Preferred Shares, 8,000,000 Series F First Preferred Shares, 12,000,000 Series H First Preferred Shares, 8,000,000 Series J First Preferred Shares, 9,000,000 Series L First Preferred Shares, 2,200,525 Barbados DRs and 1,814,135 Bahamas DRs were issued and outstanding.
Common Shares
The holders of common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Emera, other than separate meetings of holders of any other class or series of shares, and to one vote in respect of each common share held at such meetings.
The holders of common shares are entitled to dividends on a pro rata basis, as and when declared by the Board. Subject to the rights of the holders of the first preferred shares and second preferred shares, if any, who are entitled to receive dividends in priority to the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other class of shares of Emera.
On the liquidation, dissolution or winding-up of Emera, holders of common shares are entitled to participate rateably in any distribution of assets of Emera, subject to the rights of holders of first preferred shares and
Emera Incorporated 2023 Annual Information Form | 29 |
second preferred shares, if any, who are entitled to receive the assets of the Company on such a distribution in priority to the holders of the common shares.
There are no pre-emptive, redemption, purchase or conversion rights attaching to the common shares. The foregoing description is subject to the Share Ownership Restrictions section below.
Emera First Preferred Shares
The first preferred shares of each series rank on parity with the first preferred shares of every other series and are entitled to a preference over the second preferred shares, the common shares, and any other shares ranking junior to the first preferred shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.
In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the first preferred shares, the holders of the first preferred shares will be entitled, for only as long as the dividends remain in arrears, to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.
The first preferred shares of each series are not redeemable at the option of their holders. For a summary of the terms and conditions of the Companys authorized First Preferred Shares as of December 31, 2023, refer to Appendix B of this AIF.
Emera Second Preferred Shares
The second preferred shares have special rights, privileges, restrictions and conditions substantially similar to the first preferred shares, except that the second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Emera in the event of liquidation, dissolution or winding-up of Emera. As at December 31, 2023, Emera had not issued any second preferred shares.
Share Ownership Restrictions
As required by the Reorganization Act and pursuant to the Privatization Act, the Articles of Emera provide that no person, together with associates thereof, may subscribe for, have transferred to that person, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, or vote, in the aggregate, voting shares of Emera to which are attached more than 15 per cent of the votes attached to all outstanding voting shares of Emera.
The common shares, and in certain circumstances the Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are considered to be voting shares for purposes of the constraints on share ownership.
Emeras Articles contain provisions for the enforcement of these constraints on share ownership including provisions for suspension of voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights. The Board may require shareholders to furnish statutory declarations as to matters relevant to enforcement of the restrictions.
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CREDIT RATINGS
Emera has the following credit ratings by the Rating Agencies:
Moodys | S&P | Fitch | ||||
Corporate |
Baa3 | BBB | BBB | |||
Outlook |
Negative | Negative | Negative | |||
Senior unsecured debt program |
Baa3 | BBB- | BBB | |||
Hybrid Notes |
Ba2 | BB+ | BB+ | |||
First Preferred Shares |
N/A | P-3 (high) | BB+ |
Ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities and are indicators of the likelihood of the payment capacity and willingness of an issuer to meet its financial commitment in accordance with the terms of the obligation. The credit ratings assigned by the Rating Agencies are not recommendations to buy, sell, or hold securities in as much as such ratings are not a comment upon the market price of the securities or their stability for a particular investor. The credit ratings assigned to the securities may not reflect the potential impact of all risks on the value of the securities. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a Rating Agency in the future if in its judgment circumstances so warrant.
Moodys
Moodys credit ratings are on a long-term debt rating scale that ranges from Aaa to C, representing the range from highest to lowest quality of such rated securities. The rating of Baa3 obtained from Moodys in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the obligations are subject to moderate credit risk. As such, they are considered medium-grade and may possess speculative characteristics. The rating of Ba2 from Moodys in respect of the Hybrid Notes is characterized as having speculative elements and being subject to substantial credit risk. It is the fifth highest of nine available rating categories. Moodys appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.
S&P
S&Ps credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The issuer rating of BBB obtained from S&P in respect of the corporate rating indicates that the issuer has adequate capacity to meet its financial commitments. The issue rating of BBB- from S&P in respect of the senior unsecured debt indicates that the obligations exhibit adequate protection parameters. The issue rating of BB+ from S&P in respect of the Hybrid Notes indicates that the obligations exhibit adequate projection parameters in the near term however the obligor may not have the capacity to meet its obligations in the long term. The issue and issuer ratings of BBB and BB are the fourth and fifth highest, respectively, of ten available ratings categories and the addition of either a (+) or a (-) designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.
A P-3 (high) rating with respect to Emeras issued and outstanding First Preferred Shares is the third highest of the eight standard categories of ratings utilized by S&P for preferred shares.
Fitch
Fitchs credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB obtained from Fitch in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the issuer has adequate capacity to meet its financial commitments. The rating of BB from Fitch in respect of the
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Hybrid Notes is characterized as having elevated default risk however business or financial flexibility exists that support servicing the financial commitments. The BB rating from Fitch is the fifth highest of nine available ratings categories and the addition of either a (+) or a (-) designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.
Emera has made, or will make, payments in the ordinary course to the Rating Agencies in connection with the assignment of ratings on both Emera and its securities. In addition, Emera has made customary payments in respect of certain subscription services provided to Emera by the Rating Agencies during the last two years.
For further information on the credit ratings of Emera and its subsidiaries, refer to the Credit Ratings section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca.
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DIVIDENDS
Any dividend payments will be at the Boards discretion based upon earnings and capital requirements and any other factors as the Board may consider relevant. On September 20, 2023 Emera extended its annual dividend growth rate target of four to five per cent through 2026. The Company targets a long-term dividend payout ratio 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.
Emera maintains the Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends and to participate in optional cash contributions for the purpose of purchasing common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emeras common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.
The Board approved the payment of the following dividends during the last three completed fiscal years, as summarized in the following table:
Class of Shares | 2023 | 2022 | 2021 | |||||||||
Common Shares(1), (2), (3) |
$2.7875 | $2.6775 | $2.5750 | |||||||||
Series A First Preferred Shares(4) |
$0.5456 | $0.5456 | $0.5456 | |||||||||
Series B First Preferred Shares |
$1.5583 | $0.6869 | $0.4873 | |||||||||
Series C First Preferred Shares(5) |
$1.2873 | $1.1802 | $1.1802 | |||||||||
Series E First Preferred Shares |
$1.1250 | $1.1250 | $1.1250 | |||||||||
Series F First Preferred Shares(6) |
$1.0505 | $1.0505 | $1.0505 | |||||||||
Series H First Preferred Shares(7) |
$1.3140 | $1.2250 | $1.2250 | |||||||||
Series J First Preferred Shares(8) |
$1.0625 | $1.0625 | $0.6470 | |||||||||
Series L First Preferred Shares(9) |
$1.1500 | $1.1500 | $0.1638 |
(1) | On September 24, 2021, Emera approved an increase in the annual common share dividend rate from $2.55 to $2.65. The first payment was effective November 15, 2021. |
(2) | On September 22, 2022, Emera approved an increase in the annual common share dividend rate from $2.65 to $2.76. The first payment was effective November 15, 2022. |
(3) | On September 20, 2023, Emera approved an increase in the annual common share dividend rate from $2.76 to $2.87. The first payment was effective November 15, 2023. |
(4) | The Series A First Preferred Shares annual dividend rate was reset from $0.6388 to $0.5456 for the five year period commencing August 15, 2020 and ending on (and inclusive of) August 14, 2025. |
(5) | The Series C First Preferred Shares annual dividend rate was reset from $1.18024 to $1.60852 for the five year period commencing August 15, 2023 and ending on (and inclusive of) August 14, 2028. |
(6) | The Series F First Preferred Shares annual dividend rate was reset from $1.0625 to $1.0505 for the five year period commencing February 15, 2020 and ending on (and inclusive of) February 14, 2025. |
(7) | The Series H First Preferred Shares annual dividend rate was reset from $1.2250 to $1.5810 for the five year period commencing August 15, 2023 and ending on (and inclusive of) August 14, 2028.. |
(8) | The Series J First Preferred Shares with an annual dividend rate of $1.0625 (per share) were issued April 6, 2021. |
(9) | The Series L First Preferred Shares with an annual dividend rate of $1.150 (per share) were issued September 24, 2021. |
Pursuant to the Income Tax Act (Canada) and corresponding provincial legislation, all dividends paid on Emeras common shares and first preferred shares qualify as eligible dividends.
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MARKET FOR SECURITIES
Trading Price and Volume
Emeras common shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are listed and posted for trading on the TSX under the symbols 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, respectively. The Barbados DRs are listed on the BSE under the symbol EMABDR. The Bahamas DRs are listed on the BISX under the symbol EMAB. The trading volume and high and low price for Emeras securities for each month of 2023 are set out In Appendix C of this AIF.
At-The-Market Equity Program
On November 14, 2023, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Companys discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement dated November 14, 2023 to the Companys short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025, unless terminated prior to such date by the Company or otherwise in accordance with the terms of the equity distribution agreement. As at December 31, 2023, an aggregate gross sales limit of approximately $200 million remains available for issuance under the ATM program. For more information on the ATM Program, refer to General Development of the Business Financing Activity At-The-Market Equity Program above.
Emera Incorporated 2023 Annual Information Form | 34 |
DIRECTORS AND OFFICERS
Directors
The following information is provided for each Director of Emera as at December 31, 2023(1):
Name, Residence, Principal Occupations During the Past Five Years | Director Since(2) |
Committees(3) | ||||
M. Jacqueline Sheppard (Chair), Calgary, Alberta, Canada Chair of the Board since May 2014. Director of Suncor Energy Inc., a Canadian integrated energy company and of ARC Resources Ltd., a publicly traded Canadian energy company. Former Director of Alberta Investment Management Corporation (AIMCo), an institutional investment manager.(1) Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Founder and former Lead Director of Black Swan Energy Inc., an Alberta upstream energy company, which was sold in July 2021. Former Director of Cairn Energy PLC, a publicly traded UK-based international upstream company, as well as former director of the general partner of Pacific Northwest LNG LP and Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown corporation, until June 2014. |
2009 | (4) | ||||
Scott C. Balfour, Halifax, Nova Scotia, Canada A Director and President and Chief Executive Officer of Emera since March 29, 2018. Mr. Balfour is a Director of many Emera subsidiaries, including being Chair of Tampa Electric Company and Nova Scotia Power Inc. He is a former director of Martinrea International Inc. He was Chief Operating Officer from 2016 to 2018 and was Executive Vice President and Chief Financial Officer of Emera from April 2012 to March 2016. From 1994 to 2011 he was Chief Financial Officer and then President of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company. He is also past Chair of the Ontario Energy Association. |
2018 | (5) | ||||
James V, Bertram Calgary, Alberta, Canada Chair of the Board, Keyera Corporation. Formerly President, and Chief Executive Officer of Keyera from its inception in 1998 until 2015, when he became Executive Chair. Previously Vice President Marketing for the worldwide operations of Gulf Canada. Director of Methanex Corporation, the worlds largest producer and supplier of methanol to major international markets. |
2018 |
Chair of HSEC and Member of MRCC |
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Henry E. Demone, Lunenburg, Nova Scotia, Canada Former Chair of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. He was interim Chief Executive Officer of High Liner Foods from August 2017 until April 2018. A Director of Saputo Inc. |
2014 |
Chair of MRCC and Member of NCGC |
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Paula Y. Gold-Williams, San Antonio, Texas, U.S. Former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Currently serves as the Co-Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. Former .Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organizationEnergy Pillar Co-Chair of Dentons Global Smart Cities & Communities Initiatives and Think Tank. Advisory Board Serves on the US Secretary of Energys Advisory Board. A Director of ReNew Energy Global Plc, a renewable energy company based in India. |
2022 |
Member of AC and HSEC |
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Kent M. Harvey, New York, New York, U.S. Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States. |
2017 |
Chair of AC and Member of HSEC |
Emera Incorporated 2023 Annual Information Form | 35 |
B. Lynn Loewen, FCPA, FCA, Westmount, Quebec, Canada Former President of Minogue Medical Inc., a Canadian supplier of innovative medical technologies, supplies and equipment. Former President of Expertech Network Installation Inc., a Canadian network infrastructure service provider, from 2008 to 2011. Member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee and member of its Technology Comittee. Former member of the Board of Directors of Xplore Inc., a Canadian broadband service provider, and a member of its Audit Committee from 2021 to 2023. Former member of the Public Sector Pension Investment Board, serving on the Audit and Conflicts Committee and as Audit Committee Chair. Chancellor of Mount Allison University and a member of the Executive Committee and Chair of its Nominating and Governance Committee since 2018. Member of the Board of Regents from 1998 to 2008, serving as Chair from 2007-2008. |
2013 |
Member of AC, HSEC and RSC |
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Ian E. Robertson, Oakville, Ontario, Canada A principal of the Northern Genesis Capital Group, an investment group focused on identifying and acquiring energy transition businesses which demonstrate strong sustainability and Environmental, Social and Governance (ESG) alignment. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power). Former member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III. Former Director of Embark Technology, Inc., an autonomous vehicle company,Largo Resources Ltd., Algonquin Power and Atlantica Sustainable Infrastructure plc. |
2022 |
Member of AC and RSC |
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Andrea S. Rosen, Toronto, Ontario, Canada Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Manulife Financial Corporation, a Canadian multinational insurance company and financial services provider; Ceridian HCM Holding Inc., a global human capital management software company and Element Fleet Management Corp., a global fleet management company, providing services and financing for commercial vehicle fleets. Former Director of Alberta Investment Management Corporation (AIMCo.). Former Director of Hiscox Ltd., a Bermuda-incorporated specialty insurer listed on the London Stock Exchange. |
2007 |
Chair of NCGC and Member of AC |
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Karen H. Sheriff, Picton, Ontario, Canada Ms. Sheriff is past President and CEO of Q9 Networks Inc., and prior to that, President and CEO of Bell Aliant, Inc., from 2008 to 2014. She held senior leadership positions for more than nine years with BCE Inc. and currently serves on the BCE Inc. Board of Directors. She spent over 10 years at United Airlines in the areas of marketing, strategy, human resources, and finance. She is a former member of the Board of Directors of CPP Investments and WestJet Airlines Ltd. |
2021 |
Member of MRCC, RSC and NCGC |
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Jochen E. Tilk, Toronto, Ontario, Canada Former Executive Chair of Nutrien Ltd., a Canadian global supplier of agricultural products and services based in Saskatoon, Saskatchewan. Former President and Chief Executive Officer of Potash Corporation of Saskatchewan. Previously President and Chief Executive Officer of Inmet Mining Corporation, a Canadian-based, international metals company. Mr. Tilk is a director of AngloGold Ashanti Limited, a publicly listed international gold mining company, headquartered in Johannesburg, South Africa. He is also Vice-Chair of the Princess Margaret Cancer Foundation, a not-for-profit organization. He is the former Chair of the board of directors of Canpotex Limited. Former Director of the Fertilizer Institute and the International Fertilizer Association. |
2018 |
Chair of RSC and Member of MRCC and NCGC |
(1) | Effective January 1, 2023, Ms. Sheppard retired from the AIMCo Board of Directors. |
(2) | Denotes the year the individual became a Director of Emera. Directors are elected for a one year term which expires at the termination of Emeras annual general meeting; |
(3) | Audit Committee (AC), Health, Safety and Environment Committee (HSEC), Management Resources and Compensation Committee (MRCC), Nominating and Corporate Governance Committee (NCGC), and Risk and Sustainability Committee (RSC); |
(4) | Ms. Sheppard is not a member of any committee but attends all committee meetings as Chair of the Board; |
(5) | Mr. Balfour is not a member of any committee as he is the President and Chief Executive Officer of the Company but attends all committee meetings. |
Emera Incorporated 2023 Annual Information Form | 36 |
Officers
The Officers of Emera as at December 31, 2023 were as follows:
Name and Residence | Principal Occupations During the Past Five Years | |
Scott C. Balfour President and Chief Executive Officer Halifax, Nova Scotia, Canada |
A Director and President and Chief Executive Officer of Emera since March 29, 2018.(1) | |
Gregory W. Blunden, FCPA Chief Financial Officer Halifax, Nova Scotia, Canada |
Chief Financial Officer of Emera since March 2016. | |
Karen E. Hutt Executive Vice-President, Business Development and Strategy Halifax, Nova Scotia, Canada |
Executive Vice-President, Business Development and Strategy of Emera since October 21, 2019. Previously, President and Chief Executive Officer of NSPI since August 2016. | |
Bruce A. Marchand Chief Risk and Sustainability Officer Halifax, Nova Scotia, Canada |
Chief Risk and Sustainability Officer of Emera since June 30, 2022. Prior to this Chief Legal and Compliance Officer of Emera and NSPI since December 1, 2014 and Chief Legal Officer of Emera and NSPI since January 2012. | |
R. Michael Roberts Chief Human Resources Officer Halifax, Nova Scotia, Canada |
Chief Human Resources Officer of Emera and NSPI since December 1, 2014. | |
Daniel P. Muldoon Executive Vice-President Project Development and Operations Support Halifax, Nova Scotia, Canada |
Executive Vice-President Project Development and Operations Support of Emera. Chair of the Boards of ENL, EBPC, Emera Technologies LLC and NMGC and Block Energy, LLC. Former Director of Emera Maine from August 2013 until March 2020. Director of TEC and NSPML. Formerly Executive Vice-President, Major Renewables and Alternative Energy since May 2014. | |
Michael R. Barrett Executive Vice-President and General Counsel Halifax, Nova Scotia, Canada |
Executive Vice-President and General Counsel of Emera since July 1, 2022. Prior to this, General Counsel of Emera since November 20, 2017. Prior to joining Emera, Senior Partner and head of the power and climate change practice groups at Bennett Jones LLP in Toronto. | |
Brian C. Curry Corporate Secretary Halifax, Nova Scotia, Canada |
Corporate Secretary of Emera since November 16, 2023 (2) and prior to that Associate Corporate Secretary, Emera. Former Senior Director Regulatory and Corporate Secretary, NSPI from February 2021 to February 2023, Senior Regulaory Counsel and Corporate Secretary, NSPI from January 1, 2020 to February 2021 and Regulatory Counsel from January 2015 to January 2020. |
(1) | Mr. Balfours principal occupations during the past five years are described above in the Directors table. |
(2) | Effective November 16, 2023, Mr. Brian C. Curry succeeded Mr. Stephen D. Aftanas as Corpoate Secretary. Effective January 31, 2024, Mr. Aftanas retired from Emera and various subsidiaries and/or subsidiary boards. |
As at December 31, 2023, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 184,256 common shares or less than 1 per cent of the issued and outstanding common shares of Emera.
Emera Incorporated 2023 Annual Information Form | 37 |
AUDIT COMMITTEE
The Audit Committee of Emera is composed of the following five members, all of whom are independent Directors: Kent M. Harvey (Chair), Paula Gold-Williams, B. Lynn Loewen, Ian E. Robertsonand Andrea S. Rosen. The responsibilities and duties of the Audit Committee are set out in the Audit Committees Charter, a copy of which is attached as Appendix D to this AIF.
The Board believes that the composition of the Audit Committee reflects a high level of financial literacy and experience. Each member of the Audit Committee has been determined by the Board to be financially literate as such term is defined under Canadian securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit Committee. The following is a description of the education and experience of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee:
Kent M. Harvey, Committee Chair
Former Chief Financial Officer for PG&E Corporation, an energy-based holding company headquartered in San Francisco. PG&E Corporation is the parent company of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States. In over 33 years with PG&E Corporation, Mr. Harvey held progressively senior roles before he retired in 2016, including Senior Vice President and Chief Financial Officer 2009 to 2015, Senior Vice President, Chief Risk and Audit Officer 2005 to 2009. He was Senior Vice President, Chief Financial Officer and Treasurer with Pacific Gas and Electric Company, a subsidiary of PG&E Corporation, from 2000 to 2005. He holds a Bachelors degree in Economics and a Masters degree in Engineering, both from Stanford University.
Paula Y. Gold-Williams
She is the former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Ms. Gold-Williams served in positions of increasing responsibility at CPS Energy before becoming CEO in 2015. She held multiple other positions during her 17-year career at CPS Energy, including Group EVP Financial & Administrative Services, CFO and Treasurer. Co-Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. Former Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organization. She also serves on the US Secretary of Energys Advisory Board (SEAB) and is a member of the board of directors of ReNew Energy Global Plc, a renewable energy company based in India. Formerly, First Vice Chair of the Electric Power Resource Institute (EPRI); a member and designated Chair Pro Tem of the Federal Reserve Bank of Dallas San Antonio Branch; and a past-Chair of the San Antonio Chamber of Commerce. She holds an Associate Degree in Fine Arts from San Antonio College and a BBA in accounting from St. Marys University. She earned a Finance and Accounting MBA from Regis University in Denver, Colorado. She is a Certified Public Accountant and a Chartered Global Management Accountant.
B. Lynn Loewen, FCPA, FCA
Former President of Minogue Medical Inc., a Canadian supplier of innovative medical technologies, supplies and equipment. From 2008 to 2011, she was President of Expertech Network Installation Inc., a Canadian network infrastructure service provider and also held key positions with Bell Canada Enterprises, as Vice President of Finance Operations and Vice President of Financial Controls. Earlier in her career, she was with Air Canada Jazz where she held positions of increasing responsibility, including Vice President of Corporate Services and Chief Financial Officer. She is a member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee and member of its Technology Comittee. She was a member of the Board of Directors of Xplore Inc., a Canadian broadband service provider, and a member of its Audit Committee from 2021 to 2023. She is also a former member of the Public Sector Pension Investment Board where she served on the Audit and Conflicts Committee and as Audit Committee Chair. Chancellor of Mount Allison University and a member of the Executive Committee and Chair of its Nominating and Governance Committee since 2018. She was a member of the Board of Regents from 1998 to 2008, serving as Chair from 2007-2008. She holds a Bachelor of Commerce
Emera Incorporated 2023 Annual Information Form | 38 |
from Mount Allison University. Fellow of the Chartered Professional Accountants and has received the Institute of Corporate Directors, Directors Designation.
Ian E. Robertson
A principal of the Northern Genesis Capital Group, an investment group focused on identifying and acquiring energy transition businesses which demonstrate strong sustainability and Environmental, Social and Governance (ESG) alignment. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power), a publicly traded, diversified international generation, transmission, and distribution utility. Founder and principal of Algonquin Power Corporation Inc., a private independent power developer formed in 1988 and predecessor organization to Algonquin Power. Over 30 years of experience in the development of electric power generating projects and the operation of diversified regulated utilities. Former Member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III and a former Director of Embark Technology, Inc., an autonomous vehicle company,Largo Resources Ltd., Algonquin Power and Atlantica Sustainable Infrastructure plc. Mr. Robertson is an electrical engineer and holds a Professional Engineering designation through his Bachelor of Applied Science degree awarded by the University of Waterloo. He earned a Master of Business Administration degree from York Universitys Schulich School of Business. He holds a Chartered Financial Analyst designation, as well as a global professional Master of Laws degree from the University of Toronto. He received a Chartered Director designation from the Directors College of McMaster University. Mr. Robertson is a former member of the board of directors of the American Gas Association.
Andrea S. Rosen
Vice-Chair of TD Bank Financial Group and President, TD Canada Trust from 2002 to 2005. Prior to this, Executive Vice President of TD Commercial Banking and Vice Chair TD Securities. Before joining TD Bank, was Vice President of Varity Corporation from 1991 to 1994 and worked at Wood Gundy Inc. (later CIBC-Wood Gundy) in a variety of roles from 1981 to 1990, eventually becoming Vice President and Director. Holds a Bachelor of Laws from Osgoode Hall Law School and a Masters of Business Administration from the Schulich School of Business at York University. She received a Bachelor of Arts from Yale University. Ms. Rosen is a Director and member of the Audit Committee of Ceridian HCM Holding Inc., a global human capital management software company, and Director and member of the Audit Committee of Manulife Financial Corporation, an issuer listed on The Toronto Stock Exchange, New York Stock Exchange, The Stock Exchange of Hong Kong, and the Philippine Stock Exchange. She is a Director of Element Fleet Management Corp., a global fleet management company. Former Director and member of the Audit Committee of Hiscox Ltd., a Bermuda-incorporated specialty insurer listed on the London Stock Exchange, and former Director of Alberta Investment Management Corporation (AIMCo.). Former member of the Board of Directors of the Institute of Corporate Directors.
Audit and Non-Audit Services Pre-Approval Process
The Audit Committee is responsible for the oversight of the work of the external auditors. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the external auditors in order to assure that they do not impair the external auditors independence from the Company. Accordingly, the Audit Committee has adopted an Audit and Non-Audit Pre-Approval Policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the external auditors may be pre-approved.
Unless a type of service has received the pre-approval of the Audit Committee, it will require specific approval by the Audit Committee if it is to be provided by the external auditors. Any proposed services exceeding the pre-approved cost levels will also require specific approval by the Audit Committee.
Emera Incorporated 2023 Annual Information Form | 39 |
Auditors Fees
The aggregate fees billed by Ernst & Young LLP, the Companys external auditors, during the fiscal years ended December 31, 2023 and 2022 respectively, were as follows:
Service Fee | 2023 ($) | 2022 ($) | ||||||
Audit Fees |
$ | 3,910,266 | $ | 2,018,989 | ||||
Audit-Related Fees (1) |
174,410 | 19,600 | ||||||
Tax Fees (2) |
39,450 | 337,999 | ||||||
All Other Fees |
75,000 | | ||||||
Total |
$ | 4,199,126 | $ | 2,376,588 |
(1) | Audit-related fees for Emera relate to fees associated with agreed upon procedures over rate-case filings and the audit of pension plans. |
(2) | Tax fees for Emera relate to tax compliance services and general tax consulting advice on various matters. |
CERTAIN PROCEEDINGS
To the knowledge of Emera, none of the Directors or Officers of the Company:
(1) | are, as at the date of this AIF, or have been, within ten years before the date of this AIF, a director, chief executive officer or chief financial officer of any company that: |
(a) | was subject to an Order that was issued while the Director or Officer was acting in the capacity as director, chief executive officer or chief financial officer; or |
(b) | was subject to an Order that was issued after the Director or Officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer of chief financial officer; |
(2) | are, as at the date of this AIF, or have been within ten years before the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; |
(3) | have, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the proposed nominee; or |
(4) | have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory body or has entered in a settlement agreement with a securities regulatory body, or is subject to any penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision. |
CONFLICTS OF INTEREST
There are no existing or potential material conflicts of interest between Emera or any of its subsidiaries and any Director or Officer of Emera or any of its subsidiaries.
Emera Incorporated 2023 Annual Information Form | 40 |
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
To the knowledge of Emera, there are no legal proceedings that individually or together could potentially involve claims against Emera or its subsidiaries for damages totaling 10 per cent or more of the current assets of Emera, exclusive of interest and costs.
During Emeras most recently completed financial year, there have been no (a) penalties or sanctions imposed against Emera by a court relating to securities legislation or by a securities regulatory authority, (b) other penalties or sanctions imposed by a court or regulatory body against Emera that would likely be considered important to a reasonable investor in making an investment decision, and (c) settlement agreements entered into by Emera before a court relating to securities legislation or with a securities regulatory authority.
NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
None of the following persons or companies, namely (a) a Director or Officer of Emera, (b) a person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over, more than 10 per cent of any class or series of Emeras outstanding voting securities, or (c) an associate or affiliate of any person or company named in (a) or (b), had a material interest in any transaction involving Emera within Emeras last three completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect Emera.
MATERIAL CONTRACTS
Emera did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2023, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2023 that are still in effect as at the date of this AIF.
TRANSFER AGENT AND REGISTRAR
TSX Trust Company acts as Emeras transfer agent and registrar for Emeras common shares and first preferred shares. Registers for the registration and transfer of these securities of Emera are kept at TSX Trust Companys principal offices in Halifax, Montreal and Toronto.
EXPERTS
Ernst & Young LLP are the external auditors of Emera. Ernst & Young LLP report that they are independent in the context of the CPA Code of Professional Conduct of the Chartered Professional Accountants of Nova Scotia and are in compliance with Rule 3520 of the Public Company Accounting Oversight Board (United States).
ADDITIONAL INFORMATION
Additional information relating to Emera may be found on SEDAR+ at www.sedarplus.ca or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, telephone (902) 428-6096 or fax (902) 428-6171. Additional information, including Directors and Officers remuneration and indebtedness, principal holders of Emeras securities and securities authorized for issuance under equity compensation plans, is contained in Emeras information circular for the most recent annual meeting of Emeras common shareholders. Additional financial information is provided in Emeras Audited Financial Statements and MD&A.
At any time, Emera will provide to any person upon request to the Corporate Secretary, a copy of the Emera Code of Conduct. Alternatively, a copy of the Emera Code of Conduct is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca and on its corporate website at www.emera.com.
Emera Incorporated 2023 Annual Information Form | 41 |
APPENDIX A - Definitions of Certain Terms
For convenience, certain terms used throughout this AIF shall have the following meanings:
adjusted net income has the meaning ascribed to it in the Non-GAAP Financial Measures and Ratios section of the MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca;
AFUDC means allowance for funds used during construction and represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment, where permitted by the regulator;
AIF or Annual Information Form means this 2023 Annual Information Form of Emera;
Atlantic Canada means the region of Canada consisting of the Provinces of New Brunswick, Newfoundland and Labrador, Nova Scotia and Prince Edward Island;
ATM Program means an at-the-market distribution program allowing Emera to issue common shares from treasury at the prevailing market price.
Audited Financial Statements means the audited consolidated financial statements of Emera as at and for the years ended December 31, 2023 and December 31, 2022, together with the auditors report thereon, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca;
Bahamas DRs means the DRs listed on BISX;
Barbados DRs means the DRs listed on the BSE;
BBD means Barbadian dollars;
BISX means The Bahamas International Securities Exchange;
Bear Swamp means Bear Swamp Power Company, LLC, a 633 MW pumped storage hydroelectric company incorporated under the laws of the State of Delaware in which Emera indirectly holds a 50 per cent interest;
Block Energy means Block Energy LLC, formerly Emera Technologies LLC, a wholly-owned subsidiary of Emera existing under the laws of the State of Florida.
BLPC means Barbados Light & Power Company Limited, a vertically integrated electric utility company incorporated under the laws of Barbados and a wholly-owned, direct subsidiary of ECI;
Board means the Board of Directors of Emera;
Brooklyn Energy means Brooklyn Power Corporation, a 30 MW biomass co-generation company incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct subsidiary of Emera;
Brunswick Pipeline means the pipeline delivering re-gasified natural gas from the Saint John LNG gas terminal near Saint John, New Brunswick to markets in the Northeastern United States, which is owned directly by EBPC;
BSD means Bahamian dollars;
BSE means the Barbados Stock Exchange;
CAD means Canadian dollars;
CAIR means the Clean Air Interstate Rule;
CER or Canada Energy Regulator, the independent regulator of EBPC.
COMFIT means the Nova Scotia Community Feed in Tariff program which is offered by the Province of Nova Scotia and enables community organizations to be involved in renewable electricity generation;
Company means Emera;
Consolidated Balance Sheets means the consolidated balance sheets contained within the Audited Financial Statements;
Directors mean the directors of Emera and Director means any one of them;
Dividend Reinvestment Plan or DRIP means the Companys Common Shareholders Dividend Reinvestment and Share Purchase Plan;
DR means a depositary receipt representing common shares of Emera;
EBPC or Emera Brunswick Pipeline Company means Emera Brunswick Pipeline Company Ltd., a company incorporated under the federal laws of Canada and a wholly-owned, indirect subsidiary of Emera;
ECI means Emera (Caribbean) Incorporated, a company incorporated under the laws of Barbados and an indirect subsidiary of Emera and the parent company of BLPC and GBPC;
ECRC means the environmental cost recovery clause;
Emera Incorporated 2023 Annual Information Form | 42 |
Electricity Act means the Electricity Act, 2004, c. 25, s. 1. (Nova Scotia);
Emera means Emera Incorporated, a public company incorporated under the laws of the Province of Nova Scotia and traded on the TSX under the symbol EMA;
Emera Energy means the businesses of Emera Energy Services, Brooklyn Energy and Bear Swamp;
Emera Energy LP means a wholly-owned subsidiary of Emera formed under the laws of the Province of Nova Scotia;
Emera Energy Services or EES means Emera Energy LP and Emera Energy Services, Inc., a natural gas and electricity marketing and trading company and a wholly-owned, indirect subsidiary of Emera incorporated under the laws of the State of Delaware, which together form a natural gas and electricity marketing and trading business;
ENL or Emera Newfoundland and Labrador means Emera Newfoundland and Labrador Holdings Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly-owned, direct subsidiary of Emera, and the parent company of NSP Maritime Link Inc. and ENL Island Link Inc.;
ENL Island Link Inc. means ENL Island Link Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly-owned, direct subsidiary of ENL;
EPA means the U.S. Environmental Protection Agency;
Fair Trading Commission, Barbados or FTC means the regulator of BLPC;
FAM means the fuel adjustment mechanism established by the UARB;
FCM means forward capacity market;
FERC means the United States Federal Energy Regulatory Commission;
Fitch means the credit rating agency Fitch Ratings Inc;
First Preferred Shares means each series of Emeras authorized first preferred shares, namely its Series 2016-A Conversion, First Preferred Shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series D First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series G First Preferred Shares Series H First Preferred Shares, Series I First Preferred Shares
Series J First Preferred Shares and Series L First Preferred Shares;
FPSC means the Florida Public Service Commission, the regulator of Tampa Electric and PGS;
GBPA means The Grand Bahama Port Authority, the regulator of GBPC;
GBPC or Grand Bahama Power Company means Grand Bahama Power Company Limited, a vertically integrated electric utility company incorporated under the laws of the Commonwealth of The Bahamas and an indirect subsidiary of ECI;
Government of Canada Bond Yield on any date means the yield to maturity on such date (assuming semi-annual compounding) of a Canadian dollar denominated non-callable Government of Canada bond with a term to maturity of five years as quoted as of 10:00 a.m. (Toronto time) on such date and which appears on the Bloomberg Screen GCAN5YR Page on such date; provided that, if such rate does not appear on the Bloomberg Screen GCAN5YR Page on such date, the Government of Canada Bond Yield will mean the average of the yields determined by two registered Canadian investment dealers selected by the Company as being the yield to maturity on such date (assuming semi-annual compounding) which a Canadian dollar denominated non-callable Government of Canada bond would carry if issued in Canadian dollars at 100 per cent of its principal amount on such date with a term to maturity of five years;
Government of Canada T-Bill Rate means, for any quarterly floating rate period, the average yield expressed as a percentage per annum on three month Government of Canada treasury bills, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable floating rate calculation date;
GWh means the amount of electricity measured in gigawatt hours;
Hybrid Notes means the $1.2 billion USD unsecured, fixed-to-floating subordinated notes of Emera due 2076;
IFRS means International Financial Reporting Standards;
IMP means integrity management programs;
IPPs means independent power producers;
km means kilometre(s);
Labrador-Island Transmission Link Project or LIL means an electricity transmission project in Newfoundland and Labrador being developed by Nalcor, which will enable the transmission of the
Emera Incorporated 2023 Annual Information Form | 43 |
Muskrat Falls energy between Labrador and the island of Newfoundland;
LNG means liquefied natural gas;
Lucelec means St. Lucia Electricity Services Limited, a company incorporated under the laws of St. Lucia in which Emera holds an indirect 19.5 per cent interest through ECI;
M&NP means the Maritimes & Northeast Pipeline, a pipeline that transports natural gas between the Maritime Provinces and New England, in which Emera holds an indirect 12.9 per cent interest;
Maritime Link means the transmission project which includes two 170-km sub-sea cables between the island of Newfoundland and the Province of Nova Scotia, developed by NSP Maritime Link Inc.;
Maritime Provinces means the region of Canada consisting of the Provinces of Nova Scotia, New Brunswick and Prince Edward Island;
MD&A means Emeras Managements Discussion and Analysis for the fiscal year ended December 31, 2023, a copy of which is available electronically under Emeras profile on SEDAR+ at www.sedarplus.ca;
Moodys means the credit rating agency Moodys Investor Services, Inc. a subsidiary of Moodys Corporation;
MW means the amount of power measured in megawatts;
Nalcor means Nalcor Energy, a company that is incorporated under a special act of the Legislature of the Province of Newfoundland and Labrador as a Crown corporation;
NB Power means New Brunswick Power Corporation, a provincial Crown corporation formed under the laws of the Province of New Brunswick, responsible for the generation, transmission and distribution of electricity in the Province of New Brunswick;
NERC means North American Electric Reliability Corporation;
New England means the region of the United States consisting of the States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont;
NMGC means New Mexico Gas Company, Inc., a regulated gas distribution utility incorporated under the laws of Delaware and serving customers across New Mexico;
NMPRC means the New Mexico Public Regulation Commission, the regulator of NMGC;
NPCC means Northeast Power Coordinating Council, Inc.;
Northeastern United States means the region of the United States consisting of New England and the States of New Jersey, New York and Pennsylvania;
NS Block means the electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project
NSP Maritime Link Inc. or NSPML means NSP Maritime Link Incorporated, a wholly-owned direct subsidiary of ENL, incorporated under the laws of the Province of Newfoundland and Labrador, that developed the Maritime Link;
NSPI or Nova Scotia Power means Nova Scotia Power Incorporated, a vertically integrated electric utility incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct and indirect subsidiary of Emera;
Officers mean the executive officers of Emera and Officer means any one of them;
OM&G means operating, maintenance and general;
OBPS means output-based pricing system;
Order means a cease trade order, an order similar to a cease trade order or an order that denies a company access to any exemption under securities legislation that is in effect for a period of more than 30 consecutive days;
PGAC means purchased gas adjustment clause;
PGS or Peoples Gas System means Peoples Gas System, Inc., formerly the Peoples Gas System Division of TEC, operating as a regulated gas distribution utility serving customers across Florida , and a wholly-owned direct subsidiary of TECO Gas Operations, Inc. existing under the laws of the State of Florida;
PP&E means property, plant and equipment;
Privatization Act means the Nova Scotia Power Privatization Act, S.N.S., 1992, c.8 - and all amendments thereto;
Province means the Province of Nova Scotia, Canada and includes, when the context requires, the provincial government of Nova Scotia, and provincial refers to Nova Scotia;
Public Utilities Act means the Public Utilities Act (Nova Scotia);
Emera Incorporated 2023 Annual Information Form | 44 |
Rating Agencies means collectively Fitch, Moodys and S&P, and Rating Agency means any one of the Rating Agencies;
RENAC means Repsol Energy North America Canada Partnership;
Reorganization Act means the Nova Scotia Power Reorganization (1998) Act, S.N.S., 1998, c.19 - and all amendments thereto;
Repsol means Repsol S.A, the parent company of RENAC;
RER means the Nova Scotia Renewable Electricity Regulations;
ROE means return on equity;
S&P means the credit rating agency S&P Global Ratings, a division of S&P Global Inc.;
SeaCoast means SeaCoast Gas Transmission, LLC, a company incorporated under the laws of the State of Delaware and a wholly-owned subsidiary of TECO Energy;
Securities Act means the United States Securities Act of 1933, as amended;
SEDAR+ means the secure web-based system used by all market participants to file, disclose and search for information in Canadas capital markets, which can be found at www.sedarplus.ca, and replaces SEDAR, the System for Electronic Documents Analysis and Retrieval;
Series 2016-A Conversion, First Preferred Shares means the cumulative preferential first preferred shares, Series 2016-A of Emera;
Series A First Preferred Shares means the cumulative 5-year rate reset first preferred shares, Series A of Emera;
Series B First Preferred Shares means the cumulative floating rate first preferred shares, Series B of Emera;
Series C First Preferred Shares means the cumulative rate reset first preferred shares, Series C of Emera;
Series D First Preferred Shares means the cumulative floating rate first preferred shares, Series D of Emera;
Series E First Preferred Shares means the cumulative redeemable first preferred shares, Series E of Emera;
Series F First Preferred Shares means the cumulative rate reset first preferred shares, Series F of Emera;
Series G First Preferred Shares means the cumulative floating rate first preferred shares, Series G of Emera;
Series H First Preferred Shares means the cumulative minimum rate reset first preferred shares, Series H of Emera;
Series I First Preferred Shares means the cumulative floating rate first preferred shares, Series I of Emera;
Series J First Preferred Shares means the cumulative minimum rate reset first preferred shares, Series J of Emera;
Series K First Preferred Shares means the cumulative floating rate first preferred shares, Series K of Emera;
Series L First Preferred Shares means the cumulative redeemable first preferred shares, Series L of Emera;
SO2 means sulphur dioxide;
SoBRA means solar base rate adjustment;
TEC means Tampa Electric Company, an integrated regulated electric utility, serving customers in West Central Florida, a wholly-owned subsidiary of TECO Energy, incorporated under the laws of the State of Florida ;
TECO Energy means TECO Energy, Inc., an energy-related holding company incorporated under the laws of the State of Florida with regulated electric and gas utilities in Florida and a regulated gas utility in New Mexico;
TECO Gas Operations, Inc. means the wholly-owned subsidiary of TECO Energy, incorporated under the laws of the State of Florida, and the parent company of PGSI, which as of January 1, 2023, currently owns the regulated gas utility known as PGS, formerly a division of TEC;
TSX means The Toronto Stock Exchange;
UARB means the Nova Scotia Utility and Review Board, the independent regulator of NSPI;
USD means U.S. dollars; and
USGAAP means the accounting principles which are recognized as being generally accepted and which are in effect from time to time in the U.S. as codified by the Financial Accounting Standards Board, or any successor institute.
Emera Incorporated 2023 Annual Information Form | 45 |
APPENDIX B Summary of Terms and Conditions of Authorized Series of First Preferred Shares
As of December 31, 2023, the following series of First Preferred Shares have been authorized:
Series A, B, C, D, E, F, G, H, I, J, K and L First Preferred Shares
Holders of the First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of the holders of first preferred shares as a class and holders of First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the First Preferred Shares.
In any instance where the holders of First Preferred Shares are entitled to vote, each holder shall have one vote for each Preferred Share, subject to the restrictions described under Share Ownership Restrictions below.
Holders of Series A, C, F, H and J First Preferred Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board, to be reset periodically on established dates to an annualized rate equal to the sum of the then five-year Government of Canada Bond Yield, calculated at the start of the applicable five-year period, and a spread as set forth in the table below (subject, (i) in the case of the Series H preferred shares, to a fixed minimum reset of 4.90 per cent and (ii) in the case of the Series J preferred shares, to a fixed minimum reset of 4.25 per cent). Holders of the Series A, C, F, H and J First Preferred Shares have the right to convert their shares into an equal number of Series B, D, G, I and K First Preferred Shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below.
Holders of Series B, D, G, I and K First Preferred Shares will be entitled to receive floating rate cumulative preferential cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-Bill Rate , recalculated quarterly, on the applicable reset date plus a spread as set forth in the table below.
The Series A, C, F, H and J First Preferred Shares are redeemable by Emera, in whole or in part under certain circumstances by the payment of cash on the dates set forth in the table below at a price of $25.00 per share plus any accrued and unpaid dividends.
The Series B, D, G, I and K First Preferred Shares are redeemable by Emera, in whole or in part under certain circumstances after their respective initial redemption dates by payment in cash as set forth in the table below at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions as set out in the table below or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date.
Subject to certain conditions including the right of Emera to redeem, holders of the Series A, C, F, H and J First Preferred Shares, have the right to convert any or all of their Series A, C, F, H and J First Preferred Shares into an equal number of Series B, D, G, I and K First Preferred Shares, respectively. In addition, the Series A, C, F, H and J First Preferred Shares may be automatically converted by Emera into Series B, D, G, I and K First Preferred Shares, respectively if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series A, C, F, H and J First Preferred Shares outstanding, respectively.
Subject to automatic conversion conditions including the right of Emera to redeem the Series B, D, G, I and K First Preferred Shares, the holders of Series B, D, G, I and K First Preferred Shares have the right to convert any or all of their Series B, D, G, I and K First Preferred Shares into an equal number of Series A, C, F, H and J First Preferred Shares respectively. In addition, Series B, D, G, I and K First Preferred Shares may be automatically converted by Emera into Series A, C, F, H and J First Preferred Shares, respectively
Emera Incorporated 2023 Annual Information Form | 46 |
if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series B, D, G, I and K First Preferred Shares outstanding.
Holders of Series E First Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.125 per share per annum in perpetuity, subject to certain redemption rights. The Series E First Preferred Shares were not redeemable by the Company prior to August 18, 2018. The Series E First Preferred Shares are redeemable on or after August 18, 2018 by Emera in whole or in part, at the Companys option without the consent of the holder, by the payment of: $26.00 per share if redeemed before August 15, 2019; $25.75 per share if redeemed on or after August 15, 2019 but before August 15, 2020; $25.50 per share if redeemed on or after August 15, 2020 but before August 15, 2021; $25.25 per share if redeemed on or after August 15, 2021 but before August 15, 2022; and $25.00 per share if redeemed on or after August 15, 2022; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.
Holders of Series L First Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.150 per share per annum in perpetuity, subject to certain redemption rights. The Series L First Preferred Shares were not redeemable by the Company prior to November 15, 2026. The Series L First Preferred Shares are redeemable on or after November 15, 2026 by Emera in whole or in part, at the Companys option without the consent of the holder, by the payment of: $26.00 per share if redeemed before November 15, 2027; $25.75 per share if redeemed on or after November 15, 2027 but before November 15, 2028; $25.50 per share if redeemed on or after November 15, 2028 but before November 15, 2029; $25.25 per share if redeemed on or after November 15, 2029 but before November 15, 2030; and $25.00 per share if redeemed on or after November 15, 2030; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.
Applicable redemption, conversion, interest and reset dates and spreads are listed in the following table:
Series of First Preferred Shares |
Initial Redemption / Interest Reset Date |
Subsequent Redemption / Conversion / Interest Reset Dates |
Spreads | |||
Series A |
August 15, 2015 | August 15, 2020 and every fifth year thereafter | 1.84% | |||
Series B |
August 15, 2020 | August 15, 2025 and every fifth year thereafter | 1.84% | |||
Series C |
August 15, 2018 | August 15, 2023 and every fifth year thereafter | 2.65% | |||
Series D |
| August 15, 2023 and every fifth year thereafter | 2.65% | |||
Series E |
August 15, 2018 | | | |||
Series F |
February 15, 2020 | February 15, 2025 and every fifth year thereafter | 2.63% | |||
Series G |
| February 15, 2025 and every fifth year thereafter | 2.63% | |||
Series H |
August 15, 2023 | August 15, 2028 and every fifth year thereafter | 2.54% | |||
Series I |
| August 15, 2028 and every fifth year thereafter | 2.54% | |||
Series J |
May 15, 2026 | May 15, 2031 and every fifth year thereafter | 3.28% | |||
Series K |
| May 15, 2031 and every fifth year thereafter | 3.28% | |||
Series L |
November 15, 2026 | | |
Series 2016-A Conversion, First Preferred Shares
The Series 2016-A Conversion, First Preferred Shares were authorized pursuant to the Hybrid Notes offering in June 2016. As at December 31, 2023, there were no Series 2016-A Conversion, First Preferred Shares issued and outstanding.
Holders of Series 2016-A Conversion, First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of
Emera Incorporated 2023 Annual Information Form | 47 |
the holders of first preferred shares as a class and holders of Series 2016-A Conversion, First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series 2016-A Conversion, First Preferred Shares.
In any instance where the holders of Series 2016-A Conversion, First Preferred Shares are entitled to vote, each holder shall have one vote for each Series 2016-A Conversion, First Preferred Share, subject to the restrictions described under Share Ownership Restrictions below.
Holders of each series of Series 2016-A Conversion, First Preferred Shares will be entitled to receive cumulative preferential cash dividends, if, as and when declared by the Board, at the same rate as would have accrued on the related series of Hybrid Notes (had such Hybrid Notes remained outstanding). The Series 2016-A Conversion, First Preferred Shares do not have a fixed maturity date.
The Series 2016-A Conversion, First Preferred Shares are redeemable by Emera on June 15, 2026. After that date, Emera may redeem at any time all, or from time to time any part, of the outstanding Series 2016-A Conversion, First Preferred Shares, without the consent of the holders, by the payment of an amount in cash for each such share so redeemed of USD$1,000 per share together with an amount equal to all accrued and unpaid dividends thereon.
Emera Incorporated 2023 Annual Information Form | 48 |
APPENDIX C - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERAS SECURITIES IN 2023
Common Shares |
Depositary Receipts
|
Series of First Preferred Shares
| ||||||||||||||||||||
Barbados
|
Bahamas BSD (2)
|
A | B | C | E | F | H | J | L | |||||||||||||
December High ($) Low ($) Volume |
50.55 47.33 19,145,916 |
18.83 17.40 0 |
9.42 8.70 0 |
14.00 13.20 81,163 |
15.70 14.76 24,431 |
20.45 19.32 228,024 |
16.94 16.11 57,698 |
17.47 16.62 214,705 |
21.90 19.75 215,190 |
18.25 17.50 244,386 |
17.05 16.30 267,602 | |||||||||||
November High ($) Low ($) Volume |
49.21 45.45 28,093,789 |
23.00 16.21 82 |
8.97 8.19 0 |
13.91 12.72 148,350 |
15.95 15.06 10,561 |
20.60 18.14 178,388 |
17.10 15.20 37,638 |
17.50 15.60 381,774 |
21.80 18.98 188,378 |
18.49 16.19 218,322 |
17.41 15.23 305,514 | |||||||||||
October High ($) Low ($) Volume |
48.84 43.67 36,544,687 |
23.00 15.94 76 |
8.94 7.97 0 |
13.75 12.75 101,371 |
16.39 15.21 30,259 |
19.32 17.94 125,041 |
16.28 14.99 70,245 |
17.17 15.57 41,159 |
19.93 18.30 144,040 |
17.63 16.00 195,141 |
16.40 15.10 147,818 | |||||||||||
September High ($) Low ($) Volume |
52.31 47.32 18,371,308 |
23.00 17.43 192 |
9.69 8.75 0 |
13.12 13.01 11,087 |
15.75 15.02 11,445 |
19.70 19.00 151,253 |
16.69 15.94 62,159 |
16.83 16.25 51,754 |
20.34 19.51 113,419 |
18.50 17.01 101,830 |
16.78 16.06 129,228 | |||||||||||
August High ($) Low ($) Volume |
53.53 50.04 22,784,822 |
25.00 18.35 35 |
10.10 10.10 1,000 |
13.60 13.03 37,109 |
17.00 15.50 13,238 |
20.74 19.01 280,632 |
16.95 16.39 34,752 |
17.55 16.47 78,393 |
21.49 19.41 219,728 |
20.89 18.04 135,859 |
17.00 16.01 80,944 | |||||||||||
July High ($) Low ($) Volume |
55.74 52.41 20,071,924 |
25.00 19.54 201 |
10.54 9.88 0 |
13.62 13.18 113,886 |
17.96 15.97 52,124 |
20.95 20.10 165,331 |
17.15 16.80 60,766 |
17.64 17.02 81,152 |
22.90 20.48 132,309 |
21.73 20.58 138,081 |
17.35 16.85 108,285 | |||||||||||
June High ($) Low ($) Volume |
56.75 52.96 15,758,704 |
25.00 19.97 30 |
10.56 9.99 0 |
13.30 12.49 91,735 |
15.97 14.21 17,410 |
20.74 18.90 208,315 |
17.65 16.75 29,981 |
17.84 17.10 40,398 |
21.65 20.24 127,602 |
22.08 20.89 58,313 |
18.15 16.91 30,399 | |||||||||||
May High ($) Low ($) Volume |
59.52 55.57 27,608,566 |
25.00 20.30 509 |
11.03 10.21 0 |
13.42 12.54 121,371 |
15.35 14.50 38,700 |
19.42 18.40 79,745 |
18.25 17.27 31,981 |
18.30 16.99 222,314 |
21.02 20.19 77,556 |
22.76 21.04 57,454 |
18.49 17.57 67,226 | |||||||||||
April High ($) Low ($) Volume |
59.16 54.67 27,990,485 |
21.73 20.34 0 |
10.86 10.17 0 |
13.60 13.21 39,553 |
16.05 15.25 25,220 |
19.60 18.67 79,168 |
18.50 17.74 33,017 |
17.84 17.45 431,011 |
20.86 20.00 90,965 |
23.10 22.10 55,156 |
19.03 18.00 100,356 | |||||||||||
March High ($) Low ($) Volume |
56.59 51.94 23,800,570 |
20.91 19.07 0 |
10.45 9.54 0 |
14.20 13.03 136,683 |
16.43 15.56 19,660 |
20.26 18.66 158,448 |
19.08 17.82 58,620 |
18.31 16.82 64,854 |
21.87 20.04 96,223 |
23.25 21.33 109,043 |
18.85 18.05 78,142 | |||||||||||
February High ($) Low ($) Volume |
55.50 52.36 30,781,125 |
20.48 19.65 0 |
9.60 9.60 210 |
14.17 13.76 36,325 |
16.50 16.00 16,498 |
20.05 19.51 134,376 |
19.07 18.06 62,935 |
18.55 17.96 68,619 |
23.45 21.25 78,081 |
24.53 22.85 63,862 |
19.27 18.40 70,049 | |||||||||||
January High ($) Low ($) Volume |
55.31 51.00 28,195,557 |
20.58 18.80 0 |
10.29 9.40 0 |
14.24 13.49 88,141 |
16.50 15.05 20,360 |
20.45 18.60 92,940 |
19.10 16.97 46,564 |
18.81 17.47 43,481 |
22.80 20.95 83,125 |
23.86 21.82 69,677 |
19.28 17.20 108,678 |
(1) | The Barbados DRs trade on the BSE. During those months in 2023 when the Volume Traded was zero (0), the table above indicates the high and low trading prices of the Barbados DRs relative to those of Emeras common shares on the TSX. |
(2) | The Bahamas DRs trade on the BISX. During those months in 2023 when the Volume Traded was zero (0), the table above indicates the high and low trading prices of the Bahamas DRs relative to those of Emeras common shares on the TSX. |
Emera Incorporated 2023 Annual Information Form | 49 |
February 2023 |
APPENDIX D - EMERA INCORPORATED AUDIT COMMITTEE CHARTER
PART I
MANDATE AND RESPONSIBILITIES
Committee Purpose
There shall be a committee of the Board of Directors (the Board) of Emera Inc. (Emera) which shall be known as the Audit Committee (the Committee). The Committee shall assist the Board in discharging its oversight responsibilities concerning:
- | the quality and integrity of Emeras financial statements; |
- | the effectiveness of Emeras internal control systems over financial reporting; |
- | the internal audit and assurance process; |
- | the qualifications, independence and performance of the external auditors; |
- | major financial risk exposures; |
- | Emeras compliance with legal requirements and securities regulations in respect of financial statements and financial reporting; and |
- | any other duties set out in this Charter or delegated to the Committee by the Board. |
1. | Financial Reporting |
(a) | The Committee shall be responsible for reviewing, assessing the completeness and clarity of the disclosures in, and recommending to the Board for approval: |
(i) | the audited annual financial statements of Emera, all related Managements Discussion and Analysis, and earnings press releases; |
(ii) | any documents containing Emeras audited financial statements; and, |
(iii) | the quarterly financial statements, all related Managements Discussion and Analysis, and earnings press releases. |
(b) | The Board may delegate the approval of the quarterly financial statements, all related Managements Discussion and Analysis, and earnings press releases to the Committee. |
(c) | The Committee shall oversee and assess that adequate procedures are in place for the review of public disclosure of financial information. |
2. | External Auditors |
(a) | The Committee shall evaluate and recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing the auditors report or performing other audit, review, or attest services for Emera, and the compensation of such external auditors. |
(b) | Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee the work of the external auditor concerning the preparation or |
Emera Incorporated 2023 Annual Information Form | 50 |
issuance of the auditors report or the performance of other audit, review or attest services for Emera. |
(c) | The Committee shall be responsible for resolving disagreements between management and the external auditor concerning financial reporting. |
(d) | At least annually, the Committee shall obtain and review a report by the external auditors describing: (i) the firms internal quality control procedures; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, with respect to one or more external audits carried out by the firm, and any steps taken to deal with any such issues; and (iii) all relationships between the external auditors and Emera (to assess the auditors independence). |
(e) | The Committee shall annually evaluate the auditors, including the lead audit partners, qualifications, performance, professional skepticism and independence. |
(f) | The Committee shall determine that the external audit firm has a process in place to address the rotation of the lead audit partner and other audit partners serving the account as required under prescribed independence rules. |
(g) | Every five (5) years, the Committee shall perform a comprehensive review of the performance of the external auditors over multiple years to provide further insight on the audit firm, its independence and application of professional standards. |
(h) | The Committee will review differences that were noted or proposed by the external auditors, but that were considered immaterial or insignificant; and any management or internal control letter issued, or proposed to be issued. |
3. | Non-Audit Services |
(a) | The Committee shall be responsible for reviewing and pre-approving all non-audit services to be provided to Emera, or any of its subsidiaries, by the external auditor. |
(b) | The Committee may establish specific policies and procedures concerning the performance of non-audit services by the external auditor so long as the requirements of applicable legislation and regulation are satisfied. |
(c) | In accordance with policies and procedures established by the Committee, and applicable legislation and regulation, the Committee may delegate the pre-approval of non-audit services to a member of the Committee or a sub-committee thereof. |
4. | Oversight and Monitoring of Audits |
(a) | The Committee shall meet with the external auditor prior to the audit to discuss the planning and staffing of the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement. |
Emera Incorporated 2023 Annual Information Form | 51 |
(b) | The Committee shall discuss with the external auditor any issues that arise with Management or the internal auditors during the course of the audit and the adequacy of Managements responses in addressing audit-related deficiencies. |
(c) | The Committee shall regularly review with the external auditors any audit problems or difficulties encountered during the course of the audit work, including any restrictions on the scope of the external auditors activities or access to requested information, and Managements response. |
(d) | The Committee shall review with Management the results of internal and external audits. |
(e) | The Committee shall take such other reasonable steps as it may deem necessary to oversee that the audit was conducted in a manner consistent with applicable legal requirements and auditing standards of applicable professional or regulatory bodies. |
5. | Oversight and Review of Accounting Principles and Practices |
The Committee shall oversee, review and discuss with Management, the external auditor and the internal auditors:
(a) | the quality, appropriateness and acceptability of Emeras accounting principles and practices used in its financial reporting, changes in Emeras accounting principles or practices and the application of particular accounting principles and disclosure practices by Management to new transactions or events; |
(b) | all significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including the effects of alternative methods within generally accepted accounting principles on the financial statements and any other opinions sought by Management from an independent auditor, other than the Companys external auditors, with respect to the accounting treatment of a particular item, and other material written communications between the external auditors and management; |
(c) | disagreements between Management and the external auditor or the internal auditors regarding the application of any accounting principles or practices; |
(d) | any material change to Emeras auditing and accounting principles and practices as recommended by Management, the external auditor or the internal auditors or which may result from proposed changes to applicable generally accepted accounting principles; |
(e) | the effect of regulatory and accounting initiatives on Emeras financial statements and other financial disclosures; |
(f) | any reserves, accruals, provisions, estimates or Management programs and policies, including factors that affect asset and liability carrying values and the timing of revenue and expense recognition, that may have a material effect upon the financial statements of Emera; |
(g) | the use of special purpose entities and the business purpose and economic effect of off-balance sheet transactions, arrangements, obligations, guarantees and other relationships of Emera and their impact on the reported financial results of Emera; |
Emera Incorporated 2023 Annual Information Form | 52 |
(h) | any legal matter, claim or contingency that could have a significant impact on the financial statements, Emeras compliance policies and any material reports, inquiries or other correspondence received from regulators or governmental agencies and the manner in which any such legal matter, claim or contingency has been disclosed in Emeras financial statements; |
(i) | the treatment for financial reporting purposes of any significant transactions which are not a normal part of Emeras operations. |
6. | Hiring Policies |
The Committee shall review and approve Emeras hiring policy concerning partners or employees, as well as former partners and employees, of the present or former external auditors of Emera.
7. | Pension Plans |
The Committee shall exercise oversight of the pension plans in accordance with the Pension Oversight Framework adopted by Emera.
8. | Oversight of Finance Matters |
(a) | The Committee shall review the appointments of key financial executives involved in the financial reporting process of Emera, including the Chief Financial Officer. |
(b) | The Committee may request for review, and shall receive when requested, material tax policies and tax planning initiatives, tax payments and reporting and any pending tax audits or assessments. The Committee shall review Emeras compliance with tax and financial reporting laws and regulations. |
(c) | The Committee shall meet at least annually with Management to review and discuss Emeras major financial risk exposures and the policy steps Management has taken to monitor and control such exposures, including the use of financial derivatives, hedging activities, and credit and trading risks. |
(d) | The Committee may review any investments or transactions that the Committee wishes to review, or which the internal or external auditor, or any officer of Emera, may bring to the attention of the Committee within the context of this charter. |
(e) | The Committee shall review financial information of material subsidiaries of Emera and any auditor recommendations concerning such subsidiaries. |
(f) | The Committee may request for review, and shall receive when requested, all related party transactions required to be disclosed pursuant to generally accepted accounting principles, and discuss with Management the business rationale for the transactions and whether appropriate disclosures have been made. |
Emera Incorporated 2023 Annual Information Form | 53 |
9. | Internal Controls |
The Committee shall oversee:
(a) | the adequacy and effectiveness of the Companys internal accounting and financial controls and the recommendations of Management, the external auditor and the internal auditors for the improvement of accounting practices and internal controls; and |
(b) | managements compliance with the Companys processes, procedures and internal controls. |
In exercising such oversight, the Committee shall review and discuss each of the foregoing with Management, the external auditor and the internal auditor.
The Committee will carry out the following specific duties:
(c) | Review and discuss with the Chief Executive Officer and the Chief Financial Officer the procedures undertaken in connection with the Chief Executive Officer and Chief Financial Officer certifications for the annual and interim filings with applicable securities regulatory authorities. |
(d) | Review disclosures made by Emeras Chief Executive Officer and Chief Financial Officer during their certification process for the annual and interim filing with applicable securities regulatory authorities about any significant deficiencies in the design or operation of internal controls which could adversely affect Emeras ability to record, process, summarize and report financial data or any material weaknesses in the internal controls, and any fraud involving management or other employees who have a significant role in the Emeras internal controls. |
(e) | Discuss with Emeras Chief Legal Officer at least annually any legal matters that may have a material impact on the financial statements, operations, assets or compliance policies and any material reports or inquiries received by Emera or any of its subsidiaries from regulators or governmental agencies. |
10. | Internal Auditor |
(a) | The lead internal auditor shall report directly to the Committee. The Committee shall approve the appointment, removal and replacement of the lead internal auditor. The Committee shall approve the remuneration of the lead internal auditor on appointment. |
(b) | The Committee shall review and approve the internal audit plan, including activities, organizational structure, staffing, qualifications and budget, and shall review all major changes to the plan. The Committee shall review and discuss with the internal auditor the scope, progress, and results of executing the internal audit plan. The Committee shall receive reports on the status of significant findings, recommendations, and managements responses. |
(c) | The Committee shall meet periodically with the internal auditor to discuss the progress of their activities, any significant findings stemming from internal audits, any issues that arise with Management, and the adequacy of Managements responses in addressing audit-related deficiencies. |
Emera Incorporated 2023 Annual Information Form | 54 |
(d) | The Committee shall obtain from the internal auditor and review summaries of the significant reports to Management prepared by the internal auditor, and the actual reports if requested by the Committee, and Managements responses to such reports. |
(e) | The Committee shall annually receive and review a report on the Chief Executive Officers expense accounts. |
(f) | The Committee may communicate with the internal auditor with respect to their reports and recommendations, the extent to which prior recommendations have been implemented and any other matters that the internal auditor brings to the attention of the Committee. |
(g) | The Committee shall, at least biennially or more frequently as it deems necessary, approve the internal audit charter. The internal auditor shall confirm to the Committee annually that the function adheres to applicable professional standards. The Committee may provide feedback on the performance of the lead internal auditor as deemed necessary. |
(h) | The Committee shall, biennially or more frequently as it deems necessary, review the independence of the internal audit function and shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the internal audit function. |
(i) | The Committee shall review the results of an external assessment, performed every five years by a qualified independent assessor or assessment team, of the internal audit function in conformance with International Standards for the Professional Practice of Internal Auditing (IPPF Standards). |
11. | Complaints |
The Committee shall oversee procedures relating to the receipt, retention, and treatment of complaints received concerning accounting, internal accounting controls, or auditing matters. The Committee shall also review procedures concerning the confidential, anonymous submission of concerns by Emeras employees relating to questionable accounting or auditing matters. Without limiting the foregoing, the Committee shall receive periodic ethics updates under Emeras Code of Conduct which relate to matters within the scope of responsibility of the Committee as defined in this Charter, and the Committee shall review the related activities within that scope under Emeras Ethics Program, such as financial reporting, accounting and auditing, business integrity, and corporate assets and infrastructure.
12. | Other Responsibilities |
The Committee shall:
(a) | Periodically review Managements process for identifying non-compliance with legal and regulatory requirements; |
(b) | Annually receive and review a report on executive officers compliance with the Companys Code of Conduct; |
(c) | Annually provide feedback on the performance of the Chief Financial Officer; |
Emera Incorporated 2023 Annual Information Form | 55 |
(d) | Review actions taken by the Company to identify and manage risks related to the Audit Committee mandate, including Primary Enterprise Risks, which may have the potential to adversely impact the Companys operations, strategy or reputation; and |
(e) | Perform such other duties and exercise such powers as may be directed or delegated to the Committee by the Board. |
13. | Limitation on Authority |
Nothing articulated herein is intended to assign to the Committee the Boards responsibility to oversee Emeras compliance with applicable laws or regulations or to expand applicable standards of liability under statutory or regulatory requirements for the Directors or the members of the Committee.
PART II
COMPOSITION
14. | Composition |
(a) | Emeras Articles of Association require that the Committee shall be comprised of no less than three directors none of whom may be officers or employees of Emera nor may they be an officer or employee of any affiliate of Emera. In addition, all members of the Committee shall be independent as required by applicable legislation. |
(b) | The Board shall appoint members to the Committee who are financially literate, as required by applicable legislation, which at a minimum requires that Committee members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Emeras financial statements. |
(c) | Committee members shall be appointed at the Board meeting following the election of Directors at Emeras annual shareholders meeting and membership may be based upon the recommendation of the Nominating and Corporate Governance Committee. |
(d) | Pursuant to Emeras Articles of Association, the Board may appoint, remove, or replace any member of the Committee at any time, and a member of the Committee shall cease to be a member of the Committee upon ceasing to be a Director. Subject to the foregoing, each member of the Committee shall hold office as such until the next annual meeting of shareholders after the members appointment to the Committee. |
(e) | The Secretary of the Committee shall advise Emeras internal and external auditors of the names of the members of the Committee promptly following their election. |
Emera Incorporated 2023 Annual Information Form | 56 |
PART III
COMMITTEE PROCEDURE
15. | Meetings |
(a) | Meetings of the Committee may be called by the Chair or at the request of any member. The Committee shall meet at least quarterly. |
(b) | The timing and location of meetings of the Committee, and the calling of and procedure at any such meeting, shall be determined from time to time by the Committee. |
(c) | Emeras internal and external auditors shall be notified of all meetings of the Committee and shall have the right to appear before and be heard by the Committee. |
(d) | Emeras internal or external auditors may request the Chair of the Committee to consider any matters which the internal or external auditors believe should be brought to the attention of the Committee or the Board. |
16. | Separate Sessions |
(a) | The Committee Chair shall meet periodically with the Chief Financial Officer, the lead internal auditor and the external auditor in separate executive sessions to discuss any matters that the Committee or each of these groups believes should be discussed privately. |
(b) | The Chief Financial Officer, the lead internal auditor and the external auditor shall have access to the Committee to bring forward matters requiring its attention. |
(c) | The Committee shall meet periodically without Management present. |
17. | Quorum |
A majority of the members of the Committee present in person, by teleconferencing, or by videoconferencing, or by a combination thereof, will constitute a quorum.
18. | Chair |
Pursuant to Emeras Articles of Association, the Committee shall choose one of its members to act as Chair of the Committee, which person shall not be the Chair of Nova Scotia Power Inc.s Audit Committee. In selecting a Committee Chair, the Committee may consider any recommendation made by the Nominating and Corporate Governance Committee.
19. | Secretary and Minutes |
Pursuant to Emeras Articles of Association, the Corporate Secretary of Emera shall act as the Secretary of the Committee. Emeras Articles of Association require that the Minutes of the Committee be in writing and duly entered into Emeras records, and the Minutes shall be circulated to all members of the Committee. The Secretary shall maintain all Committee records.
Emera Incorporated 2023 Annual Information Form | 57 |
20. | Board Relationships and Reporting |
The Committee shall:
(a) | Review annually the Committees Charter; |
(b) | Oversee the appropriate disclosure of the Committees Charter as well as other information concerning the Committee which is required to be disclosed by applicable legislation in Emeras Annual Information Form and any other applicable disclosure documents; |
(c) | Report to the Board at the next following board meeting on any meeting held by the Committee, and as required, regularly report to the Board on Committee activities, issues, and related recommendations; and |
(d) | Maintain free and open communication between the Committee, the external auditors, internal auditors, and Management, and determine that all parties are aware of their responsibilities. |
21. | Powers |
The Committee shall:
(a) | examine and consider such other matters, and meet with such persons, in connection with the internal or external audit of Emeras accounts, which the Committee in its discretion determines to be advisable; |
(b) | have the authority to communicate directly with the internal and external auditors; and |
(c) | have the right to inspect all records of Emera or its affiliates and may elect to discuss such records, or any matters relating to the financial affairs of Emera with the officers or auditors of Emera and its affiliates. |
22. | Experts and Advisors |
The Committee may, in consultation with the Chairman of the Board, engage and compensate any outside adviser that it determines necessary in order to carry out its duties.
Emera Incorporated 2023 Annual Information Form | 58 |
Exhibit 99.4
Consent of Independent Registered Public Accounting Firm
We consent to the reference to our Firm under the caption Experts in the Annual Information Form and to the use in this Annual Report on Form 40-F of our report dated February 26, 2024, with respect to the consolidated balance sheets of Emera Incorporated as at December 31, 2023 and 2022, and the consolidated statements of income, consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated statements of cash flows for the years then ended, included in this Annual Report on Form 40-F.
/s/ Ernst & Young LLP | ||
Halifax, Canada | Chartered Professional Accountants | |
February 26, 2024 |
Exhibit 99.5
CERTIFICATION
I, Scott C. Balfour, certify that:
1. | I have reviewed this annual report on Form 40-F of Emera Incorporated; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuers other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting 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 generally accepted accounting principles; |
c) | Evaluated the effectiveness of the issuers disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the issuers internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuers internal control over financial reporting; and |
5. | The issuers other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuers auditors and the audit committee of the issuers board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuers ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuers internal control over financial reporting. |
Date: February 26, 2024
/s/ Scott C. Balfour |
Scott C. Balfour President & Chief Executive Officer |
Exhibit 99.6
CERTIFICATION
I, Gregory W. Blunden, certify that:
1. | I have reviewed this annual report on Form 40-F of Emera Incorporated; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuers other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting 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 generally accepted accounting principles; |
c) | Evaluated the effectiveness of the issuers disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the issuers internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuers internal control over financial reporting; and |
5. | The issuers other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuers auditors and the audit committee of the issuers board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuers ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuers internal control over financial reporting. |
Date: February 26, 2024
/s/ Gregory W. Blunden |
Gregory W. Blunden |
Chief Financial Officer |
Exhibit 99.7
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ENACTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the annual report of Emera Incorporated (the Company) on Form 40-F for the year ended December 31, 2023 (the Report), as filed with the U.S. Securities and Exchange Commission,
I, Scott C. Balfour, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:
(i) | the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934; and |
(ii) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: February 26, 2024
/s/ Scott C. Balfour |
Scott C. Balfour |
President & Chief Executive Officer |
Exhibit 99.8
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ENACTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the annual report of Emera Incorporated (the Company) on Form 40-F for the year ended December 31, 2023 (the Report), as filed with the U.S. Securities and Exchange Commission,
I, Gregory W. Blunden, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:
(i) | the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934; and |
(ii) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: February 26, 2024
/s/ Gregory W. Blunden |
Gregory W. Blunden |
Chief Financial Officer |
Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Consolidated Statements of Comprehensive Income | ||
Net income | $ 1,045 | $ 1,009 |
Other comprehensive (loss) income, net of tax | ||
Foreign currency translation adjustment | (270) | 629 |
Unrealized gains (losses) on net investment hedges | 38 | (97) |
Cash flow hedges - reclassification adjustment for gains included in income | (2) | (2) |
Cash flow hedges | ||
Unrealized losses on available-for-sale investment | 0 | (1) |
Net change in unrecognized pension and post-retirement benefit obligation | (39) | 24 |
Other comprehensive (loss) income | (273) | 553 |
Comprehensive income | 772 | 1,562 |
Comprehensive income attributable to non-controlling interest | 1 | 1 |
Comprehensive Income of Emera Incorporated | $ 771 | $ 1,561 |
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Foreign currency translation, tax expense (recovery) | $ (7) | $ 7 |
Hybrid Notes as a hedge of the foreign currency exposure | 1,200 | 1,100 |
Unrealized gains (losses) on net investment hedges | 0 | (6) |
Net derivative gain, tax | 0 | (1) |
Net change in unrecognized pension and post-retirement benefit obligation | 1 | 1 |
Other comprehensive loss, Tax | (6) | $ 1 |
Net investment in United States dollar denominated operations | ||
Hybrid Notes as a hedge of the foreign currency exposure | $ 1,200 |
Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Consolidated Balance Sheets | ||
Accumulated depreciation and amortization on property, plant and equipment | $ 9,994 | $ 9,574 |
Consolidated Statements of Cash Flows (Parenthetical) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Cash, cash equivalents and restricted cash consists of: | ||
Cash | $ 559 | $ 302 |
Short-term investments | 8 | 8 |
Restricted cash | 21 | 22 |
Cash, cash equivalents, and restricted cash | $ 588 | $ 332 |
Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Consolidated Statements of Changes in Equity | ||
Other comprehensive loss, tax expense/recovery | $ (6) | $ 1 |
Dividends per common share declared | $ 2.7875 | $ 2.6775 |
Summary of Significant Accounting Policies |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 1. Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, and gas transmission and distribution. At December 31, 2023, Emera’s reportable segments include the following: ● electric utility, serving approximately 840,000 ● ● primary electricity supplier in Nova Scotia, serving approximately 549,000 ● investments related to an 824 Falls on the Lower Churchill River in Labrador, developed by Nalcor Energy. investments are: ● 100 the Maritime Link Project, a $ 1.8 ● 31 Partnership (“LIL”), a $ 3.7 Labrador. ● ● 490,000 to be a division of Tampa separate legal entity called Peoples Gas System Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.; ● approximately 540,000 ● 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; ● transmission company offering services in Florida; and ● 12.9 1,400 -kilometre pipeline that transports natural gas throughout markets in Atlantic Canada and the northeastern United States. ● with regulated electric utilities that include: ● electric utility on the island of Barbados, serving approximately 134,000 ● utility on Grand Bahama Island, serving approximately 19,000 ● 19.5 integrated regulated electric utility on the island of St. Lucia. ● which include: ● ● natural gas and electricity and provides related energy asset management services; ● 30 electricity facility in Brooklyn, Nova Scotia; and ● 50.0 Swamp”), a 660 Massachusetts. ● financing subsidiaries of Emera; ● company focused on finding ways to deliver renewable and resilient energy to customers; ● located in the United States; and ● Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated. Principles of Consolidation These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for VIEs in which Emera is not the primary beneficiary. The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the VIE that most significantly impacts its economic performance and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32. Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non- regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for generation and purchased power, or OM&G, depending on the nature of the transaction. Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect 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 (“ARO”), 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. Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated products or services and provide an opportunity for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 6. Foreign Currency Translation Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain USD denominated debt held in CAD functional currency companies as hedges of net investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income (“OCI”). Revenue Recognition Regulated Electric and Gas Revenue: Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates approved by the respective regulators and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes. Non-regulated Revenue: Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms of the contract are satisfied and are presented on a net basis reflecting the nature of contractual relationships with customers and suppliers. Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations under the terms of the contract are satisfied. Other: Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. Franchise Fees and Gross Receipts TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income. PP&E PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction. The cost of additions, including betterments and replacements of units, are included in “PP&E” on the Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are included in income as the dispositions occur. The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance projects and major maintenance projects that do not increase overall life of the related assets are expensed as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. For some of Emera’s rate- regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval. Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of computer software and land rights. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval. Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”). Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance. If the Company performs a qualitative assessment and determines it is more likely than not that its FV is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss is recorded. Management estimates the FV of the reporting unit by using the income approach, or a combination of the income and market approach. The income approach uses a discounted cash flow analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. For the market approach, management estimates FV based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting unit using an income approach include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting units. As of December 31, 2023, $ 5,868 purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. Given the length of time passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a combination of the income and market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying amount, including goodwill, and as a result, no impairment charges were recognized. In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment charge of $ 73 nil details, refer to note 22. Income Taxes and Investment Tax Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward- looking information, and the likelihood that deferred income tax assets will be recovered from future taxable income is assessed and assumptions are made about the expected timing of reversal of deferred income tax assets and liabilities. If management subsequently determines it is likely that some or all of a deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by regulatory practices. TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable, except for the deferred income taxes on certain regulatory balances specifically prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income taxes. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. For further detail, refer to note 10. Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, FX, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as HFT. Collectively, derivatives. The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception 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 creditworthy. contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption if the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where documentation or effectiveness requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. 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 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. TEC has no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31, 2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement agreement. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues, fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an asset in “Receivables and other current assets” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”. Leases The Company determines whether a contract contains a lease at inception by evaluating whether the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to purchase wind and hydro energy over varying contract lengths which are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the difference between the FV and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. Inventory Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates the weighted-average cost will be recovered in future customer rates. Asset Impairment Long-Lived Assets: Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or sale of a business. The assessment involves comparing undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long- lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or other recoverable amounts, are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets. No impairment charges related to long-lived assets were recognized in 2023 or 2022. Equity Method Investments: The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s FV. No Financial Assets: Equity investments, other than those accounted for under the equity method, are measured at FV, with changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No impairment of financial assets was required in either 2023 or 2022. Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study. Some of the Company’s transmission and distribution assets may have conditional AROs that are not recognized in the consolidated financial statements, as the FV of these obligations could not be reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at FV in the period in which an amount can be determined. Cost of Removal (“COR”) TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR represent funds received from customers through depreciation rates to cover estimated future non-legally required COR of PP&E upon retirement. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock- based compensation cost is measured at the grant date, based on the calculated FV of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV and re-measured at FV at each reporting date, with the change in liability recognized in income. Employee Benefits The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes unamortized gains and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets. The components of net periodic benefit cost other than the service cost component are included in “Other income, net” on the Consolidated Statements of Income. For further detail, refer to note 21. |
Future Accounting Pronouncements |
12 Months Ended |
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Dec. 31, 2023 | |
Future Accounting Pronouncements [Abstract] | |
Future Accounting Pronouncements | 2. The Company considers the applicability and impact of all ASUs 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 Tax 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 The guidance will be effective for annual reporting periods beginning after December 15, 2024, and interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements. Improvements to Reportable Segment Disclosures In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 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. |
Dispositions |
12 Months Ended |
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Dec. 31, 2023 | |
Dispositions [Abstract] | |
Dispositions | 3. DISPOSITIONS On March 31, 2022, Emera completed the sale of its 51.9 approximated its carrying value. Domlec was included in the Company’s Other Electric reportable segment up to its date of sale. The sale did not have a material impact on earnings. |
Segment Information |
12 Months Ended |
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Dec. 31, 2023 | |
Segment Information [Abstract] | |
Segment Information | 4. 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. Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2023 Operating revenues from external customers (1) $ 3,548 $ 1,671 $ 1,510 $ 526 $ 308 $ $ 7,563 Inter-segment revenues (1) 8 - 14 - 31 (53) 3,556 1,671 1,524 526 339 (53) 7,563 Regulated fuel for generation and purchased power 920 699 - 275 - (13) 1,881 Regulated cost of natural gas - - 527 - - - 527 OM&G 830 384 405 130 151 (21) 1,879 Provincial, state and municipal taxes 289 45 91 3 5 - 433 Depreciation and amortization 571 276 126 68 8 - 1,049 Income from equity investments - 109 21 4 12 - 146 Other income, net 69 32 11 7 20 19 158 Interest expense, net (2) 271 170 129 23 332 - 925 Income tax expense (recovery) 117 (9) 64 - (44) - 128 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 66 - 66 Net income (loss) attributable to common shareholders $ 627 $ 247 $ 214 $ 37 $ (147) $ - $ 978 Capital expenditures $ 1,736 $ 450 $ 664 $ 63 $ 8 $ - $ 2,921 As at December 31, 2023 Total assets $ 21,119 $ 8,634 $ 7,735 $ 1,311 $ 1,938 $ (1,257) $ 39,480 Investments subject to significant influence $ - $ 1,236 $ 118 $ 48 $ - $ - $ 1,402 Goodwill $ 4,628 $ - $ 1,240 $ - $ 3 $ - $ 5,871 (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 measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 95 December 31, 2023, between the Florida Electric Utility, Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2022 Operating revenues from external customers (1) $ 3,280 $ 1,675 $ 1,697 $ 518 $ 418 $ $ 7,588 Inter-segment revenues (1) 7 - 7 - 22 (36) 3,287 1,675 1,704 518 440 (36) 7,588 Regulated fuel for generation and purchased power 1,086 803 - 290 - (8) 2,171 Regulated cost of natural gas - - 800 - - - 800 OM&G 625 338 365 123 156 (11) 1,596 Provincial, state and municipal taxes 235 43 83 3 3 - 367 Depreciation and amortization 507 259 118 61 7 - 952 Income from equity investments - 87 21 4 17 - 129 Other income (expenses), net 68 24 13 - 23 17 145 Interest expense, net (2) 185 136 81 19 288 - 709 GBPC impairment charge - - - 73 - - 73 Income tax expense (recovery) 121 (8) 70 - 2 - 185 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 63 - 63 Net income (loss) attributable to common shareholders $ 596 $ 215 $ 221 $ (48) $ (39) $ - $ 945 Capital expenditures $ 1,425 $ 507 $ 574 $ 63 $ 6 $ - $ 2,575 As at December 31, 2022 Total assets $ 21,053 $ 8,223 $ 7,737 $ 1,337 $ 2,835 $ (1,443) $ 39,742 Investments subject to significant influence $ - $ 1,241 $ 128 $ 49 $ - $ - $ 1,418 Goodwill $ 4,739 $ - $ 1,270 $ - $ 3 $ - $ 6,012 (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 measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 13 December 31, 2022, between the Gas Utilities and Infrastructure and Other segments. Geographical Information Revenues (based on country of origin of the product or service sold) For the Year ended December 31 millions of dollars 2023 2022 United States 5,310 $ 5,346 Canada 1,727 1,725 Barbados 389 384 The Bahamas 137 122 Dominica - 11 $ 7,563 $ 7,588 Property Plant and Equipment: As at December 31 December 31 millions of dollars 2023 2022 United States $ 18,588 $ 17,382 Canada 4,878 4,689 Barbados 576 583 The Bahamas 334 342 $ 24,376 $ 22,996 |
Revenue |
12 Months Ended |
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Dec. 31, 2023 | |
Revenue [Abstract] | |
Revenue | 5. 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 year ended December 31, 2023 Regulated Revenue Residential $ 2,307 $ 910 $ 183 $ 724 $ - $ - $ 4,124 Commercial 1,083 463 285 425 - - 2,256 Industrial 274 219 33 93 - (13) 606 Other electric 395 41 7 - - - 443 Regulatory deferrals (522) - 12 - - - (510) Other (1) 19 38 6 199 - (8) 254 Finance income (2)(3) - - - 62 - 62 $ 3,556 $ 1,671 $ 526 $ 1,503 $ - $ (21) $ 7,235 Non-Regulated Revenue Marketing and trading margin (4) - - - - 96 - 96 Other non-regulated operating revenue - - - 21 27 (23) 25 Mark-to-market (3) - - - - 216 (9) 207 $ - $ - $ - $ 21 $ 339 $ (32) $ 328 Total operating revenues $ 3,556 $ 1,671 $ 526 $ 1,524 $ 339 $ (53) $ 7,563 For the year ended December 31, 2022 Regulated Revenue Residential $ 1,799 $ 834 $ 184 $ 800 $ - $ - $ 3,617 Commercial 869 427 282 461 - - 2,039 Industrial 230 353 32 83 - (7) 691 Other electric 398 28 6 - - - 432 Regulatory deferrals (27) - 6 - - - (21) Other (1) 18 33 8 283 - (7) 335 Finance income (2)(3) - - - 61 - - 61 $ 3,287 $ 1,675 $ 518 $ 1,688 $ - $ (14) 7,154 Non-Regulated Marketing and trading margin (4) - - - - 143 - 143 Other non-regulated operating revenue - - - 16 16 (10) 22 Mark-to-market (3) - - - - 281 (12) 269 $ - $ - $ - $ 16 $ 440 $ (22) 434 Total operating revenues $ 3,287 $ 1,675 $ 518 $ 1,704 $ 440 $ (36) $ 7,588 (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 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 December 31, 2023, the aggregate amount of the transaction price allocated to remaining performance obligations was $ 488 million (2022 – $ 450 134 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 2043 . |
Regulatory Assets and Liabilities |
12 Months Ended |
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Dec. 31, 2023 | |
Regulatory Assets and Liabilities [Abstract] | |
Regulatory Assets and Liabilities | 6. REGULATORY Regulatory assets represent prudently incurred costs that have been deferred because it is probable they will be recovered through future rates or tolls collected from customers. Management believes existing regulatory assets are probable for recovery either because the Company received specific approval from the applicable regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, deferred costs are charged to income. Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income. For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator. As at December 31 December 31 millions of dollars 2023 2022 Regulatory assets Deferred income tax regulatory assets $ 1,233 $ 1,166 TEC capital cost recovery for early retired assets 671 674 NSPI FAM 395 307 Pension and post-retirement medical plan 364 369 Cost recovery clauses 151 707 Deferrals related to derivative instruments 88 30 Storm cost recovery clauses 52 138 Environmental remediations 26 27 Stranded cost recovery 25 27 NMGC winter event gas cost recovery - 69 Other 100 106 $ 3,105 $ 3,620 Current $ 339 $ 602 Long-term 2,766 3,018 Total regulatory assets $ 3,105 $ 3,620 Regulatory liabilities Accumulated reserve – COR 849 895 Deferred income tax regulatory liabilities 830 877 Cost recovery clauses 32 70 BLPC Self-insurance fund ("SIF") (note 32) 29 30 Deferrals related to derivative instruments 17 230 NMGC gas hedge settlements (note 18) - 162 Other 15 9 $ 1,772 $ 2,273 Current $ 168 $ 495 Long-term 1,604 1,778 Total regulatory liabilities $ 1,772 $ 2,273 Deferred Income Tax Regulatory Assets and Liabilities To years, a regulatory asset or liability is recognized as appropriate. TEC Capital Cost Recovery for Early Retired Assets This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and is recovered as a separate line item on customer bills for a period of 15 years . This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the TEC section below. NSPI FAM NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel- related costs from customers through regularly scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in subsequent periods. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and post-retirement benefits at TEC, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC, as applicable. It is amortized over the remaining service life of plan participants. Cost Recovery Clauses These assets and liabilities are related to TEC, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period. Deferrals Related to Derivative Instruments This asset is primarily related to NSPI deferring changes in FV of derivatives that are documented as economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved by the UARB. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, other income, inventory, being economically hedged. Storm Cost Recovery Clauses TEC and PGS Storm Reserve: The storm reserve is for hurricanes and other named storms that cause significant damage to TEC and PGS systems. As allowed by the FPSC, if charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. TEC and PGS can petition the FPSC to seek recovery of restoration costs over a 12-month period or longer, as determined by the FPSC, as well as replenish the reserve. In 2022, TEC and PGS were impacted by Hurricane Ian. For further information, refer to “TEC Storm Reserve” in the Florida Electric Utility section below. NSPI Storm Rider: NSPI has a UARB approved storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration expenses exceed approximately $ 10 million in a given year. GBPC Storm Restoration: This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are not covered by commercial insurance. In January 2020, the Grand Bahama Port Authority (“GBPA”) approved recovery of $ 15 2019 costs related to Hurricane Dorian, over a five-year period from 2021 through 2025. Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC section below. Environmental Remediations This asset is primarily related to PGS costs associated with environmental remediation at Manufactured Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. Stranded Cost Recovery Due to decommissioning of a GBPC steam turbine in 2012, the GBPA approved recovery of a $ 21 USD stranded cost through electricity rates; it is included in rate base and expected to be included in rates in future years. NMGC Winter Event Gas Cost Recovery In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $ 108 NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause (“PGAC”). On June 15, 2021, the NMPRC approved recovery of $ 108 costs in customer rates over a period of 30 months Accumulated Reserve – COR This regulatory liability represents the non-ARO COR reserve in TEC, PGS, NMGC and NSPI. AROs represent the FV of estimated cash flows associated with the Company’s legal obligation to retire its PP&E. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future COR of PP&E value upon retirement that are not legally required. This reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as new assets are put into service. NMGC Gas Hedge Settlements This regulatory liability represents regulatory deferral of gas options exercised above strike price but settled subsequent to the period end. The value from cash settlement of these options flows to customers via the PGAC. Other Regulatory Assets and Liabilities Comprised of regulatory assets and liabilities that are not individually significant. Regulatory Environments and Updates Florida Electric Utility TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties. TEC’s approved regulated return on equity (“ROE”) range for 2023 and 2022 was 9.25 11.25 per cent based on an allowed equity capital structure of 54 10.20 10.20 Base Rates: On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January 2025, reflecting a revenue requirement increase of approximately $ 290 320 additional adjustments of approximately $ 100 70 respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024. The FPSC is scheduled to hear the case in Q3 2024. On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the increase of $ 22 Fuel Recovery and Other Cost Recovery Clauses: TEC has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost- recovery rates for purchased power, capacity, on capital invested. Differences between prudently incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in subsequent periods. On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under- recovery of $ 518 21 months . The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $ 170 FPSC on March 7, 2023, and were effective beginning on April 1, 2023. The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $ 169 2022. Big Bend Modernization Project: TEC invested $ 876 91 modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the modernization project, TEC in 2020 retired the Unit 1 components that would not be used in the modernized plant and did the same for Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it was in the best interests of the customers from an economic, environmental risk and operational perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, of $ 636 267 reclassified to a regulatory asset on the balance sheet. TEC’s 2021 settlement agreement provides for cost recovery of the Big Bend Modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years , effective January 1, 2022. This recovery mechanism was authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. Storm Reserve: In September 2022, TEC was impacted by Hurricane Ian, with $ 119 charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the approved storm reserve level of $ 56 USD, for a total of $ 131 March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9, 2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost collection to $ 134 29 million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC. In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were approximately $ 35 minimal impact to earnings. Storm Protection Cost Recovery Clause and Settlement Agreement: The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and TEC’s cost recovery began in January 2021. The current approved plan addressed the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022. Canadian Electric Utilities NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request. NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved regulated ROE range for 2023 and 2022 was 8.75 9.25 quarter average regulated common equity component of up to 40 General Rate Application (“GRA”): On February 2, 2023, the UARB approved the GRA settlement agreement between NSPI, key customer representatives and participating interest groups. This resulted in average customer rate increases of 6.9 per cent effective on February 2, 2023, and further average increases of 6.5 with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It also established a storm rider and a demand-side management rider. On March 27, 2023, the UARB issued a final order approving the electricity rates effective on February 2, 2023. Fuel Recovery: For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate adjustments related to the under-recovery of fuel and fuel-related costs in the period. On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $ 117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the amortization and financing costs of $ 117 10 -year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. Storm Rider: The storm rider was effective as of the GRA decision date. The application for deferral and recovery of the storm rider is made in the year following the year of the incurred cost, with recovery beginning in the year after the application. Total major storm restoration expense for 2023 was $ 31 21 million was deferred to the storm rider. Hurricane Fiona: On October 31, 2023, NSPI submitted an application to the UARB to defer $ 24 operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is seeking amortization of the costs over a period to be approved by the UARB during a future rate setting process. At December 31, 2023, the $ 24 approval. Maritime Link: The Maritime Link is a $ 1.8 two 170 -kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. Any difference between the amounts recovered from customers through rates and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. Nova Scotia Cap-and-Trade (“Cap-and-Trade”) As of December 31, 2022, the FAM included a cumulative $ 166 purchase of emissions credits and $ 6 March 16, 2023, the Province of Nova Scotia provided NSPI with emissions allowances sufficient to achieve compliance for the 2019 through 2022 period. As such, compliance costs accrued of $ 166 were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $ 6 million were not refunded and no further costs were incurred to achieve compliance with the Cap-and- Trade Program. Extra Large Industrial Active Demand Tariff: On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $ 51 increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables and other current assets. This adjustment had minimal impact on earnings. NSPML Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 9.25 based on an actual five-quarter average regulated common equity component of up to 30 Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and delivery will continue over the next 35 years In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $ 1.8 9 7 otherwise been recoverable if incurred by NSPI. On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and future holdback amounts and requirements to end the holdback mechanism. In these decisions, the UARB agreed with the Company’s submission that $ 12 8 4 relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease once 90 relief for planned outages or exceptional circumstances) and the net outstanding balance of previously underdelivered NS Block energy is less than 10 UARB increased the monthly holdback amount from $ 2 4 On December 21, 2023, NSPML received approval to collect up to $ 164 164 from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up to $ 4 Gas Utilities and Infrastructure PGS PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. PGS’s approved ROE range for 2023 and 2022 was 8.9 11.0 9.9 midpoint, based on an allowed equity capital structure of 54.7 Base Rates: On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in September 2023. On November 9, 2023, the FPSC approved a $ 118 revenues which includes $ 11 for a net incremental increase to base revenues of $ 107 10.15 midpoint ROE with an allowed equity capital structure of 54.7 December 27, 2023, with the new rates effective January 2024. The 2020 PGS rate case settlement provided the ability to reverse a total of $ 34 accumulated depreciation through 2023. PGS reversed $ 20 2023 and $ 14 Fuel Recovery: PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually by the FPSC. Recovery of Energy Conservation and Pipeline Replacement Programs: The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are required by Florida law and approved and monitored by the FPSC. PGS also has a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete plastic pipe continuing until 2028 under the rider. NMGC NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital. NMGC’s approved ROE for 2023 and 2022 was 9.375 52 Base Rates: On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective Q4 2024. NMGC requested $ 49 operating costs and capital investments in pipeline projects and related infrastructure. The rate case includes a requested ROE of 10.5 Fuel Recovery: NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust charges based on the next month’s expected cost of gas and any prior month under-recovery or over- recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. NMGC received approval of its PGAC Continuation in December 2020, for the four-year period ending December 2024. Integrity Management Programs (“IMP”) Regulatory Asset: A portion of NMGC’s annual spending on infrastructure is for IMP, legacy systems. These programs are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13, 2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the IMP regulatory asset. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Saint John LNG import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25 -year firm service agreement commencing in July 2009 with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada Energy Regulator (“CER”). The CER Gas Transportation Tariff compliance with the requirements of the CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline. Other Electric Utilities BLPC BLPC is regulated by the Fair Trading Commission (“FTC”), under the Utilities Regulation (Procedural) Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s approved regulated return on rate base was 10 Licenses: BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the implementation of the licenses once enacted. 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 month. On February 15, 2023, the FTC issued a decision on the significant items: an allowed regulatory ROE of 11.75 55 a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities related to the self-insurance fund of $ 50 recognized on remeasurement of deferred income taxes of $ 5 of $ 16 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. 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. Fuel Recovery: BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all prudently incurred fuel costs from customers in a timely manner. The calculation of the fuel charge is adjusted on a monthly basis and reported to the FTC for approval. Clean Energy Transition Program (“CETP”): On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the CETP. Fuel Hedging: On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC requested the FTC review the required 50 /50 cost sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses associated with the hedging program. GBPC GBPC is regulated by the GBPA. The GBPA franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPC’s approved regulated return on rate base was 8.32 8.23 Base Rates: There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows for an increase in revenues of $ 3.5 12.84 Fuel Recovery: GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs from customers in a timely manner. Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge was adjusted monthly, in-line with actual fuel costs. Storm Restoration Costs – Hurricane Matthew: As part of the recovery of costs incurred as a result of Hurricane Matthew, in 2016, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA amortization of the remaining regulatory asset over the three year period ending December 31, 2024. |
Investments Subject to Significant Influence and Equity Income |
12 Months Ended |
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Dec. 31, 2023 | |
Investments Subject to Significant Influence and Equity Income [Abstract] | |
Investments Subject to Significant Influence and Equity Income | 7. Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of dollars 2023 2022 2023 2022 2023 LIL (1) $ 747 $ 740 $ 63 $ 58 31.0 NSPML 489 501 46 29 100.0 M&NP 118 128 21 21 12.9 Lucelec (2) 48 49 4 4 19.5 Bear Swamp - - 12 17 50.0 $ 1,402 $ 1,418 $ 146 $ 129 (1) Emera indirectly owns 100 24.5 ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 transmission developments. (2) Emera has significant influence over the operating and financial decisions of these companies through Board representation 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 Bear Swamp's credit investment balance of $ 81 95 Consolidated Balance Sheets. Equity investments include a $ 10 investees' assets as at the date of acquisition. The excess is attributable to goodwill. Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of dollars 2023 2022 Balance Sheets Current assets $ 21 $ 17 PP&E 1,473 1,517 Regulatory assets 272 265 Non-current assets 29 29 Total assets $ 1,795 $ 1,828 Current liabilities $ 48 $ 48 Long-term debt (1) 1,109 1,149 Non-current liabilities 149 130 Equity 489 501 Total liabilities and equity $ 1,795 $ 1,828 (1) The project debt has been guaranteed by the Government of Canada. |
Other Income, Net |
12 Months Ended |
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Dec. 31, 2023 | |
Other Income, Net [Abstract] | |
Other Income, Net | 8. For the Year ended December 31 millions of dollars 2023 2022 Interest income $ 43 $ 25 AFUDC 38 52 Pension non-current service cost recovery 35 24 FX gains (losses) 20 (26) TECO Guatemala Holdings award (1) - 63 Other 22 7 $ 158 $ 145 (1) On December 15, 2022, a payment of $ 63 second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute an investment in TGH, a wholly-owned subsidiary of TECO Energy. |
Interest Expense, Net |
12 Months Ended |
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Dec. 31, 2023 | |
Interest Expense, Net [Abstract] | |
Interest Expense, Net | 9. Interest expense, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2023 2022 Interest on debt $ 954 $ 727 Allowance for borrowed funds used during construction (16) (21) Other (13) 3 $ 925 $ 709 |
Income Taxes |
12 Months Ended |
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Dec. 31, 2023 | |
Income Taxes [Abstract] | |
Income Taxes | 10. The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons: millions of dollars 2023 2022 Income before provision for income taxes $ 1,173 $ 1,194 Statutory income tax rate 29.0% 29.0% Income taxes, at statutory income tax rate 340 346 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (72) (70) Tax credits (53) (18) Foreign tax rate variance (36) (44) Amortization of deferred income tax regulatory liabilities (33) (33) Tax effect (15) (10) GBPC impairment charge - 21 Other (3) (7) Income tax expense $ 128 $ 185 Effective income tax rate 11% 15% 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 December 31, 2023, the Company has recorded a $ 30 9 Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers. The following table reflects the composition of taxes on income from continuing operations presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2023 2022 Current income taxes $ 26 $ 25 5 8 Deferred income taxes 93 122 128 252 Investment tax credits (29) (7) Operating loss carryforwards (93) (94) (2) (121) Income tax expense $ 128 $ 185 The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2023 2022 Canada $ 171 $ 173 United States 964 1,063 Other 38 (42) Income before provision for income taxes $ 1,173 $ 1,194 The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of dollars 2023 2022 Deferred income tax assets: Tax loss carryforwards $ 1,195 $ 1,207 Tax credit carryforwards 454 415 Derivative instruments 205 45 Regulatory liabilities 175 264 Other 372 341 Total deferred income tax assets before valuation allowance 2,401 2,272 Valuation allowance (363) (312) Total deferred income tax assets after valuation allowance $ 2,038 $ 1,960 Deferred income tax (liabilities): PP&E $ (3,223) $ (2,981) Derivative instruments (235) (125) Investments subject to significant influence (216) (181) Regulatory assets (196) (310) Other (312) (322) Total deferred income tax liabilities $ (4,182) $ (3,919) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 208 $ 237 Long-term deferred income tax liabilities (2,352) (2,196) Net deferred income tax liabilities $ (2,144) $ (1,959) Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for certain loss carryforwards and unrealized capital losses on long-term debt and investments. A valuation allowance of $ 363 312 related to the loss carryforwards, long-term debt and investments. The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at December 31, 2023, $ 4.7 3.8 deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred. Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2023 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of dollars Carryforwards Allowance Carryforwards Period Canada $ 2,914 $ (1,164) $ 1,750 2026 - 2043 73 (73) - Indefinite United States $ 1,360 $ (1) $ 1,359 2036 - Indefinite 1,003 (1) 1,002 2026 - Indefinite 454 (3) 451 2025 - 2043 Other $ 81 $ (28) $ 53 2024 - 2030 The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows: millions of dollars 2023 2022 Balance, January 1 $ 33 $ 28 Increases due to tax positions related to current year 5 5 Increases due to tax positions related to a prior year 1 2 Decreases due to tax positions related to a prior year (2) (2) Balance, December 31 $ 37 $ 33 Unrecognized tax benefits relate to the timing of certain tax deductions at NSPI and research and development tax credits primarily at TEC. The total amount of unrecognized tax benefits as at December 31, 2023 was $ 37 33 total amount of accrued interest with respect to unrecognized tax benefits was $ 9 7 million) with $ 2 1 million). No next 12 months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service audits. A reasonable estimate of any change cannot be made at this time. During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years. NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $ 126 126 55 the amount in dispute, as required by CRA. On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be available in subsequent years. Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute. NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not determinable at this time. Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31, 2023, the Company’s tax years still open to examination by taxing authorities include 2005 and subsequent years. |
Common Stock |
12 Months Ended |
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Dec. 31, 2023 | |
Common Stock [Abstract] | |
Common Stock | 11. Authorized : 2023 2022 Issued and outstanding: millions of shares dollars millions of shares dollars Balance, January 1 269.95 $ 7,762 261.07 $ 7,242 Issuance of common stock under ATM program (1)(2) 8.29 397 4.07 248 Issued under the DRIP, 5.26 272 4.21 238 Senior management stock options exercised and Employee Share Purchase Plan 0.62 31 0.60 34 Balance, December 31 284.12 $ 8,462 269.95 $ 7,762 (1) For the year ended December 31, 2022, a total of 4,072,469 average price of $ 61.31 250 248 (2) For the year ended December 31, 2023, a total of 8,287,037 average price of $ 48.27 400 397 As at December 31, 2023, the following common shares were reserved for issuance: 6 6 million) under the senior management stock option plan, 2 2.7 common share purchase plan and 18 10 The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed 10 Emera was in compliance with this requirement. ATM Equity Program On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of its ATM Program in Q4 2023 that will allow the Company to issue up to $ 600 from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. This ATM Program is expected to remain in effect until November 4, 2025. |
Earnings Per Share |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | 12. Basic earnings per share is determined by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior management stock option plan, convertible debentures and shares issued under the DRIP. The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of dollars (except per share amounts) 2023 2022 Numerator Net income attributable to common shareholders $ 977.7 $ 945.1 Diluted numerator 977.7 945.1 Denominator Weighted average shares of common stock outstanding – basic 273.6 265.5 Stock-based compensation 0.2 0.4 Weighted average shares of common stock outstanding – diluted 273.8 265.9 Earnings per common share Basic $ 3.57 $ 3.56 Diluted $ 3.57 $ 3.55 |
Accumulated Other Comprehensive Income |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Accumulated Other Comprehensive Income [Abstract] | |
Accumulated Other Comprehensive Income | 13. The components of AOCI are as follows: millions of dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges Losses on derivatives recognized as cash flow hedges Net change on available- for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2023 Balance, January 1, 2023 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 Other comprehensive (loss) income before reclassifications (270) 38 - - (232) Amounts reclassified from AOCI - - (2) - (39) (41) Net current period other comprehensive (loss) income (270) 38 (2) - (39) (273) Balance, December 31, 2023 $ 369 $ (24) $ 14 $ (2) $ (52) $ 305 For the year ended December 31, 2022 Balance, January 1, 2022 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 Other comprehensive income (loss) before reclassifications 629 (97) - (1) - 531 Amounts reclassified from AOCI - - (2) - 24 22 Net current period other comprehensive income (loss) 629 (97) (2) (1) 24 553 Balance, December 31, 2022 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 The reclassifications out of AOCI are as follows: For the Year ended December 31 millions of dollars 2023 2022 Affected line item in the Consolidated Financial Statements Gains on derivatives recognized as cash flow hedges Interest expense, net $ (2) $ (2) Net change in unrecognized pension and post-retirement benefit costs Other income, net $ - $ 10 Other income, net 2 - Pension and post-retirement benefits (40) 15 Total before tax (38) 25 Income tax expense (1) (1) Total net of tax $ (39) $ 24 Total reclassifications out of AOCI, net of tax, for the period $ (41) $ 22 |
Inventory |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Inventory [Abstract] | |
Inventory | 14. As at December 31 December 31 millions of dollars 2023 2022 Fuel $ 382 $ 404 Materials 408 365 Total $ 790 $ 769 |
Derivative Instruments |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Derivative Instruments | |
Derivative Instruments | 15. Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of dollars 2023 2022 2023 2022 Regulatory deferral: $ 16 $ 186 $ 76 $ 42 3 18 3 1 - 52 - - 19 256 79 43 HFT derivatives: 29 89 36 77 319 340 531 1,224 348 429 567 1,301 Other derivatives: 4 - - 5 18 5 7 23 22 5 7 28 Total gross current derivatives 389 690 653 1,372 Impact of master netting agreements: (3) (18) (3) (18) (146) (276) (146) (276) Total impact of master netting agreements (149) (294) (149) (294) Total derivatives $ 240 $ 396 $ 504 $ 1,078 Current (1) 174 296 386 888 Long-term (1) 66 100 118 190 Total derivatives $ 240 $ 396 $ 504 $ 1,078 (1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying Cash Flow Hedges On May 26, 2021, a treasury lock was settled for a gain of $ 19 interest expense over 10 years The amounts related to cash flow hedges recorded in AOCI consisted of the following: For the Year ended December 31 millions of dollars 2023 2022 Interest Interest rate hedge rate hedge Realized gain in interest expense, net $ 2 $ 2 Total gains in net income $ 2 $ 2 As at December 31 December 31 millions of dollars 2023 2022 Interest Interest rate hedge rate hedge Total unrealized gain in AOCI – effective portion, net of tax $ 14 $ 16 The Company expects $ 2 within the next 12 months. Regulatory Deferral The Company has recorded the following changes with respect to derivatives receiving regulatory deferral: Physical Commodity Physical Commodity natural gas swaps and FX natural gas swaps and FX millions of dollars purchases forwards forwards purchases forwards forwards For the year ended December 31 2023 2022 Unrealized gain (loss) in regulatory assets $ - $ (109) $ (3) $ - $ (69) $ 1 Unrealized gain (loss) in regulatory liabilities (3) (73) - 28 343 16 Realized (gain) loss in regulatory assets - (5) - - 48 - Realized (gain) loss in regulatory liabilities - 2 - - (41) - Realized (gain) loss in inventory (1) - 4 (10) - (121) 1 Realized (gain) in regulated fuel for generation and purchased power (2) (49) (9) (4) (64) (146) - Other - (14) - - - - Total change in derivative instruments $ (52) $ (204) $ (17) $ (36) $ 14 $ 18 (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 December 31, 2023, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below: millions 2024 2025-2026 Physical natural gas purchases: Natural gas (MMBtu) 7 6 Commodity swaps and forwards purchases: Natural gas (MMBtu) 16 10 Power (MWh) 1 1 Coal (metric tonnes) 1 - FX swaps and forwards: FX contracts (millions of USD) $ 241 $ 70 Weighted average rate 1.3155 1.3197 % of USD requirements 63% 17% HFT Derivatives The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives: For the Year ended December 31 millions of dollars 2023 2022 Power swaps and physical contracts in non-regulated operating revenues $ (6) $ 17 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 1,043 47 Total gains in net income $ 1,037 $ 64 As at December 31, 2023, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below: 2028 and millions 2024 2025 2026 2027 thereafter Natural gas purchases (Mmbtu) 296 80 50 38 30 Natural gas sales (Mmbtu) 338 86 16 6 4 Power purchases (MWh) 1 - - - - Power sales (MWh) 1 - - - - Other Derivatives As at December 31, 2023, the Company had equity derivatives in place to manage the 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 combined notional amount of $508 million USD and expire in 2023, 2024 and 2025. For the Year ended December 31 millions of dollars 2023 2022 FX Equity FX Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in OM&G $ - $ 4 $ - $ (5) Unrealized gain (loss) in other income, net 28 - (18) - Realized loss in OM&G - (13) - (17) Realized loss in other income, net (11) - (6) - Total gains (losses) in net income $ 17 $ (9) $ (24) $ (22) 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 assesses credit risk internally for counterparties that are not rated. As at December 31, 2023, the maximum exposure the Company had to credit risk was $ 1.2 – $ 1.9 derivatives. 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 total cash deposits/collateral on hand as at December 31, 2023 was $ 310 386 mitigated the Company’s maximum credit risk exposure. 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 December 31, 2023, the Company had $ 142 131 considered to be past due, which have been outstanding for an average 64 financial assets was $ 127 114 allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue. Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2023 December 31, 2022 millions of dollars % of total exposure millions of dollars % of total exposure Receivables, net Regulated utilities: Residential $ 476 31% $ 455 19% Commercial 194 13% 192 8% Industrial 84 5% 121 5% Other 103 7% 122 5% Cash collateral 94 6% - 0% 951 62% 890 37% Trading group: Credit rating of A- or above 47 3% 125 5% Credit rating of BBB- to BBB+ 33 2% 75 3% Not rated 108 7% 307 13% 188 12% 507 21% Other accounts receivable 151 10% 585 25% 1,290 84% 1,982 83% Derivative Instruments (current and long-term) Credit rating of A- or above 138 9% 202 9% Credit rating of BBB- to BBB+ 7 1% 8 0% Not rated 95 6% 186 8% 240 16% 396 17% $ 1,530 100% $ 2,378 100% Cash Collateral The Company’s cash collateral positions consisted of the following: As at December 31 December 31 millions of dollars 2023 2022 Cash collateral provided to others $ 101 $ 224 Cash collateral received from others $ 22 $ 112 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 December 31, 2023, the total FV of derivatives in a liability position was $ 504 2022 – 1,078 value of the net liability position could be required to be posted as collateral for these derivatives. |
FV Measurements |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
FV Measurements [Abstract] | |
Fair Value Measurements | 16. The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 1) 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: ● seasonal or monthly shaping and locational basis differentials. ● accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. ● utilized in the valuations. Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the FV measurement. The following tables set out the classification of the methodology used by the Company to FV its derivatives: As at December 31, 2023 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 7 $ 6 $ - $ 13 - 3 - 3 7 9 - 16 HFT derivatives: (5) 23 - 18 42 108 34 184 37 131 34 202 Other derivatives: - 18 - 18 4 - - 4 4 18 - 22 Total assets 48 158 34 240 Liabilities Regulatory deferral: 43 30 - 73 - 3 - 3 43 33 - 76 HFT derivatives: - 24 - 24 13 19 365 397 13 43 365 421 Other derivatives: - 7 - 7 - 7 - 7 Total liabilities 56 83 365 504 Net assets (liabilities) $ (8) $ 75 $ (331) $ (264) As at December 31, 2022 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 120 $ 48 $ - $ 168 - 18 - 18 - - 52 52 120 66 52 238 HFT derivatives: 9 31 4 44 3 72 34 109 12 103 38 153 Other derivatives: - 5 - 5 Total assets 132 174 90 396 Liabilities Regulatory deferral: 15 9 - 24 - 1 - 1 15 10 - 25 HFT derivatives: 2 28 1 31 51 118 825 994 53 146 826 1,025 Other derivatives: - 23 - 23 5 - - 5 Total liabilities 73 179 826 1,078 Net assets (liabilities) $ 59 $ (5) $ (736) $ (682) The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as follows: Regulatory Deferral HFT Derivatives Physical natural Natural millions of dollars gas purchases Power gas Total Balance, January 1, 2023 $ 52 $ 4 $ 34 $ 90 Realized gains (losses) included in fuel for generation and purchased power (49) - - (49) Unrealized gains (losses) included in regulatory assets and liabilities (3) - - (3) Total realized and unrealized gains (losses) included in non-regulated operating revenues - (4) - (4) Balance, December 31, 2023 $ - $ - $ 34 $ 34 The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as follows: Natural millions of dollars Power gas Total Balance, January 1, 2023 $ 1 $ 825 $ 826 Total realized and unrealized gains included in non- regulated operating revenues (1) (460) (461) Balance, December 31, 2023 $ - $ 365 $ 365 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: Significant Weighted millions of dollars FV Unobservable Input Low High average (1) Assets Liabilities As at December 31, 2023 HFT derivatives – Natural 34 365 Third-party pricing $1.27 $16.25 $4.85 gas swaps, futures, forwards and physical contracts Total $ 34 $ 365 Net liability $ 331 As at December 31, 2022 Regulatory deferral – Physical $ 52 $ - Third-party pricing $5.79 $31.85 $12.27 natural gas purchases HFT derivatives – Power 4 1 Third-party pricing $43.24 $269.10 $138.79 swaps and physical contracts HFT derivatives – Natural 34 825 Third-party pricing $2.45 $33.88 $12.01 gas swaps, futures, forwards and physical contracts Total $ 90 $ 826 Net liability $ 736 (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 Consolidated Balance Sheets. The balance consisted of the following: As at Carrying millions of dollars Amount FV Level 1 Level 2 Level 3 Total December 31, 2023 $ 18,365 $ 16,621 $ - $ 16,363 $ 258 $ 16,621 December 31, 2022 $ 16,318 $ 14,670 $ - $ 14,284 $ 386 $ 14,670 The Company has designated $ 1.2 currency exposure of its ne t investment are contingently convertible into preferred shares in the event of bankruptcy or other related events. A redemption option on or after June 15, 2026 is available and at the control of the Company. The Hybrid Notes are classified as Level 2 financial assets. As at December 31, 2023, the FV of the Hybrid Notes was $ 1.2 1.1 38 AOCI for the year ended December 31, 2023 (2022 – $ 97 |
Related Party Transactions |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 17. 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: ● Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $ 163 157 NSPML is accounted for as an equity investment, and therefore 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 Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $ 14 – $ 9 There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated Balance Sheets as at December 31, 2023 and at December 31, 2022. |
Receivables and Other Current Assets |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Receivables and Other Current Assets [Abstract] | |
Receivables and Other Current Assets | 18. As at December 31 December 31 millions of dollars 2023 2022 Customer accounts receivable – billed $ 805 $ 1,096 Capitalized transportation capacity (1) 358 781 Customer accounts receivable – unbilled 363 424 Prepaid expenses 105 82 Income tax receivable 10 9 Allowance for credit losses (15) (17) NMGC gas hedge settlement receivable 162 Other 191 360 Total receivables and other current assets $ 1,817 $ 2,897 (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. (2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information, to note 6. |
Leases |
12 Months Ended |
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Dec. 31, 2023 | |
Leases [Abstract] | |
Leases, Lessee | 19. Lessee The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain they will be exercised. As at December 31 December 31 millions of dollars Classification 2023 2022 Right-of-use asset Other long-term assets $ 54 $ 58 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 55 59 Total lease liabilities $ 58 $ 62 The Company recorded lease expense of $ 127 $ 138 119 131 facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income. Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Minimum lease payments $ 6 $ 5 $ 3 $ 3 $ 3 $ 111 $ 131 Less imputed interest (73) Total $ 58 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2023 2022 Cash paid for amounts included in the measurement of lease liabilities: $ 8 $ 8 Right-of-use assets obtained in exchange for lease obligations: $ 1 $ 1 Weighted average remaining lease term (years) 44 44 Weighted average discount rate- operating leases 3.93% 3.98% Lessor The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, Seacoast, compressed natural gas (“CNG”) stations, a renewable natural gas (“RNG”) facility and heat pumps. The Company manages its risk associated with the residual value of the Brunswick Pipeline lease through proper routine maintenance of the asset. Customers have the option to purchase CNG station assets by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee. Commencing in October 2023, the Company leased a RNG facility to a biogas producer that is classified as a sales-type lease. The term of the facility lease is 15 years , with a nominal value purchase at the end of the term and a net investment of approximately $ 35 Commencing in January 2022, the Company leased Seacoast pipeline, a 21-mile, 30-inch lateral that is classified as a sales-type lease. The term of the pipeline lateral lease is 34 $ 100 16 renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably certain that they will be exercised. Direct finance and sales-type lease unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” and “Other income, net” on the Consolidated Statements of Income. The total net investment in direct finance and sales-type leases consist of the following: As at December 31 December 31 millions of dollars 2023 2022 Total minimum lease payment to be received $ 1,360 $ 1,393 Less: amounts representing estimated executory costs (190) (205) Minimum lease payments receivable $ 1,170 $ 1,188 Estimated residual value of leased property (unguaranteed) 183 183 Less: Credit loss reserve (2) - Less: unearned finance lease income (693) (733) Net investment in direct finance and sales-type leases $ 658 $ 638 Principal due within one year (included in "Receivables and other current assets") 37 34 Net Investment in direct finance and sales type leases - long-term $ 621 $ 604 As at December 31, 2023, future minimum lease payments to be received for each of the next five years and in aggregate thereafter were as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Minimum lease payments to be received $ 97 $ 99 $ 98 $ 97 $ 96 $ 873 $ 1,360 Less: executory costs (190) Total $ 1,170 |
Property, Plant and Equipment |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | 20. PP&E consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of dollars Estimated useful life 2023 2022 Generation 3 131 $ 13,500 $ 13,083 Transmission 10 80 2,835 2,731 Distribution 4 80 7,417 6,978 Gas transmission and distribution 6 92 5,536 5,061 General plant and other 2 71 2,985 2,723 Total cost 32,273 30,576 Less: Accumulated depreciation (1) (9,994) (9,574) 22,279 21,002 Construction work in progress (1) 2,097 1,994 Net book value $ 24,376 $ 22,996 (1) SeaCoast owns a 50 % undivided ownership interest in a jointly owned 26 -mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $ 27 27 accumulated depreciation of $ 2 1 funds and all operations are accounted for as if such participating interest were a wholly owned facility. expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income. |
Employee Benefit Plans |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Employee Benefit Plans [Abstract] | |
Employee Benefit Plans | 21. 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: Benefit Obligation and Plan Assets: The changes in benefit obligation and plan assets, and the funded status for all plans were as follows: For the Year ended December 31 millions of dollars 2023 2022 Change in Projected Benefit Obligation ("PBO") and Accumulated Post- retirement Benefit Obligation ("APBO") Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Balance, January 1 $ 2,158 $ 243 $ 2,624 $ 318 Service cost 30 3 41 4 Plan participant contributions 6 6 6 6 Interest cost 111 13 80 9 Plan amendments - (14) - - Benefits paid (147) (29) (174) (31) Actuarial losses (gains) 146 10 (480) (79) Settlements and curtailments (8) - (6) - FX translation adjustment (23) (5) 67 16 Balance, December 31 $ 2,273 $ 227 $ 2,158 $ 243 Change in plan assets Balance, January 1 $ 2,163 $ 46 $ 2,702 $ 51 Employer contributions 42 23 45 24 Plan participant contributions 6 6 6 6 Benefits paid (147) (29) (174) (31) Actual return on assets, net of expenses 262 3 (489) (7) Settlements and curtailments (8) - (6) - FX translation adjustment (20) (1) 79 3 Balance, December 31 $ 2,298 $ 48 $ 2,163 $ 46 Funded status, end of year $ 25 $ (179) $ 5 $ (197) The actuarial losses recognized in the period are primarily due to changes in the discount rate, higher than expected indexation, and compensation-related assumption changes. Plans with PBO/APBO in Excess of Plan Assets: The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit plans) exceeded the plan assets for the years ended December 31 was as follows: millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 120 $ 205 $ 1,006 $ 221 FV of plan assets 37 - 914 - Funded status $ (83) $ (205) $ (92) $ (221) Plans with Accumulated Benefit Obligation (“ABO”) in Excess of Plan Assets: The ABO for the DB pension plans was $ 2,172 2,080 The aggregate financial position for those plans with an ABO in excess of the plan assets for the years ended December 31 was as follows: millions of dollars 2023 2022 Defined benefit pension plans Defined benefit pension plans ABO $ 114 $ 111 FV of plan assets 37 33 Funded status $ (77) $ (78) Balance Sheet: The amounts recognized in the Consolidated Balance Sheets consisted of the following: As at December 31 December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (5) $ (18) $ (13) $ (20) Long-term liabilities (78) (187) (80) (201) Other long-term assets 108 26 98 24 AOCI, net of tax and regulatory assets 385 20 358 22 Less: Deferred income tax (expense) recovery in AOCI (8) (1) (7) (1) Net amount recognized $ 402 $ (160) $ 356 $ (176) Amounts Recognized in AOCI and Regulatory Assets: Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets. The following table summarizes the change in AOCI and regulatory assets: Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of dollars Defined Benefit Pension Plans Balance, January 1, 2023 $ 336 $ 15 $ - Amortized in current period (6) (3) - Current year additions 1 41 - Change in FX rate (7) - - Balance, December 31, 2023 $ 324 $ 53 $ - Non-pension benefits plans Balance, January 1, 2023 $ 31 $ (10) $ - Amortized in current period 2 3 - Current year reductions (3) (1) (3) Change in FX rate (1) - 1 Balance, December 31, 2023 $ 29 $ (8) $ (2) As at December 31 December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 53 (8) $ 15 $ (10) Past service gains - (2) - - Deferred income tax expense 8 1 7 1 AOCI, net of tax 61 (9) 22 (9) Regulatory assets 324 29 336 31 AOCI, net of tax and regulatory assets $ 385 $ 20 $ 358 $ 22 Benefit Cost Components: Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 30 $ 3 $ 41 $ 4 Interest cost 111 13 80 9 Expected return on plan assets (161) (2) (144) - Current year amortization of: 1 (3) 8 - 6 (2) 21 2 Settlement, curtailments 2 - 2 - Total $ (11) $ 9 $ 8 $ 15 The expected return on plan assets is determined based on the market-related value of plan assets of $ 2,577 2,482 during the year. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period. Pension Plan Asset Allocations: Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad range of investment and non-investment grade securities. Emera’s target asset allocation is as follows: Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 10% Fixed income 34% to 49% Equities: 7% to 17% 35% to 59% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Cash and cash equivalents 0% to 10% Fixed income 29% to 49% Equities 48% to 68% Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies. All pension investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company. The following tables set out the classification of the methodology used by the Company to FV its investments: millions of dollars NAV Level 1 Level 2 Total Percentage As at December 31, 2023 Cash and cash equivalents $ - $ 40 $ - $ 40 2 % Net in-transits - (9) - (9) - % Equity securities: - 96 - 96 4 % - 141 - 141 6 % - 112 - 112 5 % Fixed income securities: - - 172 172 8 % - - 90 90 4 % - 4 5 9 - % Mutual funds - 50 - 50 2 % Other - 6 (1) 5 - % Open-ended investments measured at NAV 1,006 - - 1,006 44 % Common collective trusts measured at NAV (2) 586 - - 586 25 % Total $ 1,592 $ 440 $ 266 $ 2,298 100 % As at December 31, 2022 Cash and cash equivalents $ - $ 70 $ - $ 70 3 % Net in-transits - (70) - (70) (3) % Equity securities: - 87 - 87 4 % - 233 - 233 11 % - 186 - 186 8 % Fixed income securities: - - 104 104 5 % - - 83 83 4 % - 3 11 14 1 % Mutual funds - 68 - 68 3 % Other - - (3) (3) - % Open-ended investments measured at NAV 790 - - 790 36 % Common collective trusts measured at NAV (2) 601 - - 601 28 % Total $ 1,391 $ 577 $ 195 $ 2,163 100 % (1) Net asset value ("NAV") investments are open-ended or pooled funds. NAV’s are calculated (2) The common collective trusts are private funds valued at NAV. securities. Since the prices are not published to external sources, NAV primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour subscription and redemption activity regularly. Refer to note 16 for more information on the FV hierarchy and inputs used to measure FV. Post-Retirement Benefit Plans: There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is common practice, post-retirement health benefits are paid from general accounts as required. The primary exception to this is the NMGC Retiree Medical Plan, which is fully funded. Investments in Emera: As at December 31, 2023 and 2022, assets related to the pension funds and post-retirement benefit plans did not hold any material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities. Cash Flows: The following table shows expected cash flows for DB pension and other post-retirement benefit plans: millions of dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2024 $ 34 $ 19 Expected benefit payments 2024 172 21 2025 163 21 2026 166 21 2027 171 21 2028 173 20 2029 – 2033 890 95 Assumptions: The following table shows the assumptions that have been used in accounting for DB pension and other post-retirement benefit plans: 2023 2022 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 4.89 % 4.89 % 5.33 % 5.31 % Discount rate - future service 4.88 % 4.89 % 5.34 % 5.32 % Rate of compensation increase 3.87 % 3.85 % 3.62 % 3.61 % Health care trend - 6.04 % - 5.40 % - 3.76 % - 3.77 % 2043 2043 Benefit cost for year ended December 31: Discount rate - past service 5.33 % 5.31 % 3.05 % 2.81 % Discount rate - future service 5.34 % 5.32 % 3.18 % 2.92 % Expected long-term return on plan assets 6.56 % 2.16 % 6.07 % 1.32 % Rate of compensation increase 3.62 % 3.61 % 3.31 % 3.29 % Health care trend - 5.40 % - 5.09 % - 3.77 % - 3.77 % 2043 2042 Actual assumptions used differ by plan. The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from the pension plan. Defined Contribution Plan: Emera also provides a DC pension plan for certain employees. The Company’s contribution for the year ended December 31, 2023 was $ 45 41 |
Goodwill |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Goodwill [Abstract] | |
Goodwill | 22. The change in goodwill for the year ended December 31 was due to the following: millions of dollars 2023 2022 Balance, January 1 $ 6,012 $ 5,696 Change in FX rate (141) 389 GBPC impairment charge - (73) Balance, December 31 $ 5,871 $ 6,012 Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera’s Consolidated Balance Sheets at December 31, 2023, primarily related to TECO Energy (reporting units with goodwill are TEC, PGS, and NMGC). In 2023, Emera performed qualitative impairment assessments for NMGC and PGS, concluding that the FV of the reporting units exceeded their respective carrying amounts, and as such, no quantitative assessments were performed and no passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a combination of the income approach and market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying amount, including goodwill, and as a result no charges were recognized. In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC, using the income approach. It was determined that the FV did not exceed its carrying amount, including goodwill. As a result of this assessment, a goodwill impairment charge of $ 73 31, 2022. This non-cash charge is included in “GBPC impairment charge” on the Consolidated Statements of Income. |
Short-Term Debt |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Short-Term Debt [Abstract] | |
Short-Term Debt | 23. Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non- revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following: millions of dollars 2023 Weighted average interest rate 2022 Weighted average interest rate TEC Advances on revolving credit facilities $ 277 5.68 % $ 1,380 5.00 % Emera Non-revolving term facilities 796 6.07 % 796 5.19 % Bank indebtedness 9 - % - - % TECO Finance Advances on revolving credit and term facilities 245 6.54 % 481 5.47 % PGS Advances on revolving credit facilities 73 6.36 % - - % NMGC Advances on revolving credit facilities 25 6.46 % 59 5.15 % GBPC Advances on revolving credit facilities 8 5.54 % 10 5.25 % Short-term debt $ 1,433 $ 2,726 The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of dollars Maturity 2023 2022 TEC - Unsecured committed revolving credit facility 2026 $ 401 $ 1,084 TECO Energy/TECO Finance - revolving credit facility 2026 - 542 TECO Finance - Unsecured committed revolving credit facility 2026 529 - Emera - Unsecured non-revolving term facility 2024 400 400 Emera - Unsecured non-revolving term facility 2024 400 400 PGS - Unsecured revolving credit facility 2028 331 - TEC - Unsecured revolving facility 2024 265 542 TEC - Unsecured revolving facility 2024 265 - NMGC - Unsecured revolving credit facility 2026 165 169 Other - Unsecured committed revolving credit facilities Various 17 18 Total $ 2,773 $ 3,155 Less: Advances under revolving credit and term facilities 1,433 2,731 Letters of credit issued within the credit facilities 3 4 Total advances under available facilities 1,436 2,735 Available capacity under existing agreements $ 1,337 $ 420 The weighted average interest rate on outstanding short-term debt at December 31, 2023 was 5.95 cent (2022 – 5.01 Recent Significant Financing Activity by Segment Florida Electric Utilities On November 24, 2023, TEC repaid its $ 400 on December 13, 2023 . On April 3, 2023, TEC entered into a 364 -day, $ 200 which matures on April 1, 2024 . The credit agreement contains customary representations and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the federal funds rate or the one-month SOFR, plus a margin. On March 1, 2023, TEC entered into a 364 -day, $ 200 facility which matures on February 28, 2024 . The credit facility contains customary representations and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the one-month SOFR, plus a margin. Gas Utilities and Infrastructure On December 1, 2023, PGS entered into a $ 250 with a group of banks, maturing on December 1, 2028 . PGS has the ability to request the lenders to increase their commitments under the credit facility by up to $ 100 agreement from participating lenders. The credit agreement contains customary representations and warranties, events of default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin. Other On December 16, 2023, Emera amended its $ 400 maturity date from December 16, 2023 December 16, 2024 . There were no other changes in commercial terms from the prior agreement. On June 30, 2023, Emera amended its $ 400 maturity date from August 2, 2023 August 2, 2024 . There were no other changes in commercial terms from the prior agreement. |
Other Current Liabilities |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Other Current Liabilities | |
Other Current Liabilities | 24. As at December 31 December 31 millions of dollars 2023 2022 Accrued charges $ 172 $ 174 Nova Scotia Cap-and-Trade Program provision (note 6) - 172 Accrued interest on long-term debt 107 97 Pension and post-retirement liabilities (note 21) 23 33 Sales and other taxes payable 11 14 Income tax payable 2 9 Other 112 80 $ 427 $ 579 |
Long-Term Debt |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Long-term Debt [Abstract] | |
Long-term Debt | 25. Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year. Long-term debt as at December 31 consisted of the following: Weighted average interest rate (1) millions of dollars 2023 2022 Maturity 2023 2022 Emera Bankers acceptances, SOFR loans Variable Variable 2027 $ 465 $ 403 Unsecured fixed rate notes 4.84% 2.90% 2030 500 500 Fixed to floating subordinated notes (2) 6.75% 6.75% 2076 1,587 1,625 $ 2,552 $ 2,528 Emera Finance Unsecured senior notes 3.65% 3.65% 2024 - 2046 $ 3,637 $ 3,725 TEC (3) Fixed rate notes and bonds 4.61% 4.15% 2024 - 2051 $ 5,654 $ 4,341 PGS Fixed rate notes and bonds 5.63% 3.78% 2028 - 2053 $ 1,223 $ 772 NMGC Fixed rate notes and bonds 3.78% 3.11% 2026 - 2051 $ 642 $ 521 Non-revolving term facility, floating rate Variable Variable 2024 30 108 $ 672 $ 629 NMGI Fixed rate notes and bonds 3.64% 3.64% 2024 $ 198 $ 203 NSPI Discount Notes (4) Variable Variable 2024 - 2027 $ 721 $ 881 Medium term fixed rate notes 5.13% 5.14% 2025 - 2097 3,165 2,665 $ 3,886 $ 3,546 EBP Senior secured credit facility Variable Variable 2026 $ 246 $ 249 ECI Secured senior notes Variable Variable 2027 $ 75 $ 86 Amortizing fixed rate notes 4.00% 3.97% 2026 79 100 Non-revolving term facility, floating rate Variable Variable 2025 29 30 Non-revolving term facility, fixed rate 2.15% 2.05% 2025 - 2027 155 91 Secured fixed rate senior notes (5) 3.09% 3.06% 2024 - 2029 84 142 $ 422 $ 449 Adjustments Fair market value adjustment - TECO Energy acquisition $ - $ 2 Debt issuance costs (125) (126) Amount due within one year (676) (574) $ (801) $ (698) Long-Term Debt $ 17,689 $ 15,744 (1) Weighted average interest rate of fixed rate long-term debt. (2) In 2023, the Company recognized $ 109 110 subordinated notes. (3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently bonds outstanding under TEC’s first mortgage bond indenture. (4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’ acceptances for a period of greater than one year. (5) Notes are issued and payable in either USD or BBD. The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of dollars Maturity 2023 2022 Emera – revolving credit facility (1) June 2027 $ 900 $ 900 TEC - Unsecured committed revolving credit facility December 2026 657 - NSPI - revolving credit facility (1) December 2027 800 800 NSPI - non-revolving credit facility July 2024 400 400 Emera - Unsecured non-revolving credit facility February 2024 400 - NMGC - Unsecured non-revolving credit facility March 2024 30 108 ECI – revolving credit facilities October 2024 10 11 Total $ 3,197 $ 2,219 Less: Borrowings under credit facilities 1,884 1,396 Letters of credit issued inside credit facilities 6 12 Use of available facilities $ 1,890 $ 1,408 Available capacity under existing agreements $ 1,307 $ 811 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $ 50 Debt Covenants Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significant covenants are listed below: As at Financial Covenant Requirement December 31, 2023 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.57 Recent Significant Financing Activity by Segment Florida Electric Utility On January 30, 2024, TEC issued $ 500 4.90 per cent with a maturity date of March 1, 2029 . Proceeds from the issuance were primarily used for repayment of short-term borrowings outstanding under the 5 -year credit facility. Therefore, $ 497 USD of short-term borrowings that were repaid was classified as long-term debt at December 31, 2023. Canadian Electric Utilities On March 24, 2023, NSPI issued $ 500 300 unsecured notes that bear interest at 4.95 November 15, 2032 , and $ 200 million unsecured notes that bear interest at 5.36 March 24, 2053 . Gas Utilities and Infrastructure On December 19, 2023, PGS completed an issuance of $ 925 included $ 350 5.42 December 19, 2028 , $ 350 5.63 of December 19, 2033 225 5.94 maturity date of December 19, 2053 . On October 19, 2023, NMGC issued $ 100 6.36 October 19, 2033 . Other Electric Utilities On May 24, 2023, GBPC issued a $ 28 4.00 cent with a maturity date of May 24, 2028 . Other On August 18, 2023, Emera entered into a $ 400 February 19, 2024 . The credit agreement contains customary representations and warranties, events of default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin. On February 16, 2024, Emera extended the term of this agreement to a maturity date of February 19, 2025 . On May 2, 2023, Emera issued $ 500 4.84 with a maturity date of May 2, 2030 . Long-Term Debt Maturities As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Emera $ 199 $ - $ 1,587 $ 266 $ - $ 500 $ 2,552 Emera US Finance LP 397 - 992 - - 2,248 3,637 TEC 397 - - - - 5,257 5,654 PGS - - - - 463 760 1,223 NMGC 30 - 93 - - 549 672 NMGI 198 - - - - - 198 NSPI 398 125 40 323 - 3,000 3,886 EBP - - 246 - - - 246 ECI 51 139 89 77 62 4 422 Total $ 1,670 $ 264 $ 3,047 $ 666 $ 525 $ 12,318 $ 18,490 |
Asset Retirement Obligations |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | 26. AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the FV of any related ARO cannot be made. The change in ARO for the years ended December 31 is as follows: millions of dollars 2023 2022 Balance, January 1 $ 174 $ 174 Accretion included in depreciation expense 9 9 Change in FX rate (1) 3 Additions - 1 Accretion deferred to regulatory asset (included in PP&E) 18 1 Liabilities settled (8) (1) Revisions in estimated cash flows - (13) Balance, December 31 $ 192 $ 174 |
Commitments and Contingencies |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 27. Commitments As at December 31, 2023, 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) $ 696 $ 495 $ 405 $ 388 $ 338 $ 2,597 $ 4,919 Purchased power (2) 274 249 263 312 312 3,435 4,845 Fuel, gas supply and storage 556 215 62 - 5 - 838 Capital projects 778 111 70 1 - - 960 Equity investment commitments (3) 240 - - - - - 240 Other 154 147 56 46 35 221 659 $ 2,698 $ 1,217 $ 856 $ 747 $ 690 $ 6,253 $ 12,461 (1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. $ 134 (2) Annual requirement to purchase electricity production from IPPs 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 contributions over the life of the partnership. respective investment obligations of the parties in relation 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 February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $ 1.8 UARB approved the collection of up to $ 164 2024. The timing and amounts payable to NSPML for the remainder of the 38 -year commitment period are subject to UARB approval. Construction of the LIL is complete, and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700 MW, which was validated by the Government of Canada’s Independent Engineer issuing its Commissioning Certificate on April 13, 2023. 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. 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 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). result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at December 31, 2023, the aggregate financial liability of the Florida utilities is estimated to be $ 15 11 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. Principal Financial Risks and Uncertainties Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and FV measurements are discussed in note 15 and note 16. Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management Committee (“ERMC”) and monitored by the Board of Directors, to ensure an effective, consistent and coherent approach to risk management. The Board of Directors has a Risk and Sustainability Committee (‘RSC”) with a mandate that includes oversight of the Company’s Enterprise Risk Management framework, including the identification, assessment, monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to sustainability and its performance relative to its sustainability objectives. Regulatory and Political Risk The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions. As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera also holds investments in entities in which it has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, and M&NP. Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034, with Repsol Energy North America Canada Partnership. Regulators administer the regulatory frameworks covering material aspects of the utilities’ businesses, including applying market-based tests to determine the appropriate customer rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the provision of service, performance standards, and affiliate transactions. Regulators also review the prudency of costs and other decisions that impact customer rates and reliability of service and work to ensure the financial health of the utility for the benefit of customers. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally require a public hearing process or may be mandated by other governmental bodies. public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in decreased rate affordability for customers and could materially affect Emera and its utilities. Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital plans. The subsidiaries work to establish collaborative relationships with regulatory stakeholders, including customer representatives, both through its approach to filings and additional efforts with technical conferences and, where appropriate, negotiated settlements. Changes in government and shifts in government policy and legislation can impact the commercial and regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that could adversely affect the Company’s operations, net income and cash flows. State and local policies in some United States jurisdictions have sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and regulations, including electrification legislation, could adversely impact PGS and NMGC. Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic, political or other factors, or its ability to respond in an effective and timely manner or the resulting compliance costs. Government interference in the regulatory process can undermine regulatory stability, predictability, and independence, and could have a material adverse effect on the Company. Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the CAD and, particularly, the USD, which could positively or adversely affect results. Consistent with the Company’s risk management policies, Emera manages currency risks through matching United States denominated debt to finance its United States operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including FX. The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI. Liquidity and Capital Market Risk Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets. Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market disruptions and ratings assigned by various market analysts, including credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in PP&E and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of borrowing may be impacted by various market disruptions. The inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan. Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its regulatory framework and legislative environment, political interference in the regulatory process, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increased borrowing costs under certain existing credit facilities, limit access to the commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation. General Economic Risk The Company has exposure to the macro-economic conditions in North America and in other geographic regions in which Emera operates. Like most utilities, economic factors such as consumer income, employment and housing affect demand for electricity and natural gas, and in turn the Company’s financial results. Adverse changes in general economic conditions and inflation may impact the ability of customers to afford rate increases arising from increases to fuel, operating, capital, environmental compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or increased risk to full and timely recovery of costs and regulatory assets. Interest Rate Risk: Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives. Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity and Capital Market Risk”. As with most other utilities and other similar yield-returning investments, Emera’s share price may be affected by changes in interest rates and could underperform the market in an environment of rising interest rates. Inflation Risk: The Company may be exposed to changes in inflation that may result in increased operating and maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and measure operating performance, as well as collective bargaining agreements that mitigate the short-term impact of inflation on labour costs of unionized employees. Commodity Price Risk The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts and arrangements. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. These include the Company’s commercial arrangements, such as the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this risk. Regulated Utilities: The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can be affected by a wide range of factors which are difficult to predict and may change rapidly, including but not limited to currency fluctuations, changes in global economic conditions, natural disasters, transportation or production disruptions, and geo-political risks such as political instability, conflicts, changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or regulatory assets, and/or negative impacts on customer consumption patterns and sales. Emera Energy Marketing and Trading: Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets in the event of an operational issue or counterparty default. Changes in commodity prices can also result in increased collateral requirements associated with physical contracts and financial hedges, resulting in higher liquidity requirements and increased costs to the business. To including an estimated VaR analysis of its exposures. The VaR potential change in FV that could occur from changes in Emera Energy’s portfolio or changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodities, primarily natural gas and power positions. Income Tax Risk The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred income tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results. Guarantees and Letters of Credit Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2023 : TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $ 45 USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $ 27 TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm service agreement, which expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential amount of $ 13 In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $ 13 USD. Emera Inc. has issued a guarantee of $ 66 guarantee will automatically terminate on the date upon which the obligations have been repaid in full. NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the amount of $ 104 119 The Company has standby letters of credit and surety bonds in the amount of $ 103 (December 31, 2022 – $ 145 subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required. Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2024. The amount committed as at December 31, 2023 was $ 56 63 Collaborative Arrangements For the years ended December 31, 2023 and 2022, the Company has identified the following material collaborative arrangements: Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in “OM&G” on the Consolidated Statements of Income. In 2023, NSPI recognized $ 8 12 million) in “Regulated fuel for generation and purchased power” and $ 3 3 “OM&G” on the Consolidated Statements of Income. |
Cumulative Preferred Stock |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Cumulative Preferred Stock [Abstract] | |
Cumulative Preferred Stock | 28. Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2023 December 31, 2022 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.5456 $ 25.00 4,866,814 $ 119 4,866,814 $ 119 Series B Floating $ 25.00 1,133,186 $ 28 1,133,186 $ 28 Series C $ 1.6085 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.00 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0505 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.5810 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Series J $ 1.0625 $ 25.00 8,000,000 $ 196 8,000,000 $ 196 Series L $ 1.1500 $ 26.00 9,000,000 $ 222 9,000,000 $ 222 Total 58,000,000 $ 1,422 58,000,000 $ 1,422 Characteristics of the First Preferred Shares: First Preferred Shares (1)(2) Initial Yield (%) Current Annual Dividend ($) Minimum Reset Dividend Yield (%) Earliest Redemption and/or Conversion Option Date Redemption Value ($) Right to Convert on a one for one basis Fixed rate reset (3)(4) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B 4.100 1.6085 2.65 August 15, 2028 25.00 Series D 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) 2.393 Floating 1.84 August 15, 2025 25.00 Series A (5)(7) 4.900 1.5810 4.90 August 15, 2028 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate 4.500 1.1250 25.00 (9) 4.600 1.1500 November 15, 2026 26.00 (1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation. (2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but dates fixed for redemption. (3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying 25.00 share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government Bond Yield on the applicable reset date, plus the applicable reset dividend yield 4.90 (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years for cash, in whole or in part at a price of $ 25.00 redemption and $ 25.50 of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively. yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 (5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series 2023. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, C Shares were converted into Series D Shares and no Series H Shares were converted into Series I shares. (6) The annual fixed dividend per share for Series C Shares was reset from $ 1.1802 1.6085 including August 15, 2028. (7) The annual fixed dividend per share for Series H Shares was reset from $ 1.2250 1.5810 including August 15, 2028. (8) First Preferred Shares, Series E are redeemable at $25.00 per share. (9) First Preferred Shares, Series L are redeemable at $ 26.00 $ 0.25 25.00 First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting. |
Non-Controlling Interest in Subsidiaries |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Non-Controlling Interest in Subsidiaries [Abstract] | |
Non-Controlling Interest in Subsidiaries | 29. As at December 31 December 31 millions of dollars 2023 2022 Preferred shares of GBPC $ 14 $ 14 $ 14 $ 14 Preferred shares of GBPC: Authorized: 10,000 2023 2022 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14 GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock: The preferred shares are redeemable by GBPC after June 17, 2021 , at $ 1,000 accrued and unpaid dividends and are entitled to a 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually . The Preferred Shares rank behind GBPC’s current and future secured and unsecured debt and ahead of all of GBPC’s current and future common stock. |
Supplementary Information to Consolidated Statements of Cash Flows |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Supplementary Information to Consolidated Statements of Cash Flows [Abstract] | |
Supplementary Information to Consolidated Statements of Cash Flows | 30. SUPPLEMENTARY CASH FLOWS For the Year ended December 31 millions of dollars 2023 2022 Changes in non-cash working capital: $ (31) $ (214) (1) 653 (636) (538) 423 (2) (179) 193 Total non-cash working capital $ (95) $ (234) (1) Includes $ 162 162 ) million). Offsetting regulatory liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities. (2) Includes ($ 166 ) million related to the Nova Scotia Cap-and-Trade program (2022 – $ 172 6. Offsetting regulatory asset (FAM) balance is cash provided by operating activities. For the Year ended December 31 millions of dollars 2023 2022 Supplemental disclosure of cash paid: Interest $ 930 $ 699 Income taxes $ 43 $ 67 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 271 $ 237 Decrease in accrued capital expenditures $ (19) $ (13) Reclassification of short-term debt to long-term debt $ 657 $ - Reclassification of long-term debt to short-term debt $ - $ 500 Supplemental disclosure of operating activities: Net change in short-term regulatory assets and liabilities $ 123 $ (157) |
Stock Based Compensation |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Stock-Based Compensation [Abstract] | |
Stock-based Compensation | 31. Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows reinvestment of dividends for all participants except where prohibited by law. maximum aggregate number of Emera common shares reserved for issuance under this plan is 7 common shares. As at December 31, 2023, Emera was in compliance with this requirement. Compensation cost for shares issued under the ECSPP for the year ended December 31, 2023 was $ 3 million (2022 – $ 3 The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023. Stock-Based Compensation Plans Stock Option Plan The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock Exchange on the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with this requirement. Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be exercised within the 27 months six months termination without just cause or death, and within sixty days cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised during the full term of the option following the option holders date of retirement, six months termination without just cause or death, and within sixty days cause or resignation. If stock options are not exercised within such time, they expire. The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The following table shows the weighted average FV per stock option along with the assumptions incorporated into the valuation models for options granted, for the year-ended December 31: 2023 2022 Weighted average FV per option $ 6.32 $ 5.35 Expected term (1) 5 5 Risk-free interest rate (2) 3.53 % 1.79 % Expected dividend yield (3) 5.05 % 4.55 % Expected volatility (4) 20.07 % 18.87 % (1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government bond yields. (3) Incorporates current dividend rates and historical dividend increase patterns. (4) Estimated using the five-year historical volatility. The following table summarizes stock option information for 2023: Total Options Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2022 2,853,879 $ 50.41 1,348,400 $ 4.08 Granted 483,100 54.64 483,100 6.32 Exercised (146,475) 43.94 N/A N/A Forfeited (94,900) 56.32 (51,625) 3.61 Vested N/A N/A (526,620) 3.58 Options outstanding December 31, 2023 3,095,604 $ 51.20 1,253,255 $ 5.17 Options exercisable December 31, 2023 (2)(3) 1,842,349 $ 48.39 (1) As at December 31, 2023, there was $ 5 expected to be recognized over a weighted average period of approximately 3 4 3 (2) As at December 31, 2023, the weighted average remaining term of vested options was 5 $ 8 5 10 (3) As at December 31, 2023, the FV of options that vested in the year was $ 2 2 Compensation cost recognized for stock options for the year ended December 31, 2023 was $ 2 (2022 – $ 2 As at December 31, 2023, cash received from option exercises was $ 6 9 total intrinsic value of options exercised for the year ended December 31, 2023 was $ 2 4 million). The range of exercise prices for the options outstanding as at December 31, 2023 was $ 32.35 $ 60.03 32.35 60.03 ). Share Unit Plans The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. Deferred Share Unit Plans Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are redeemed. Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met. When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash. In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee (“MRCC”), to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives. A summary of the activity related to employee and director DSUs for the year ended December 31, 2023 is presented in the following table: Employee DSU Weighted Average Grant Date FV Director DSU Weighted Average Grant Date FV Outstanding as at December 31, 2022 627,223 $ 41.55 664,258 $ 45.83 Granted including DRIP 85,740 47.66 117,893 49.99 Exercised N/A N/A (53,093) 49.39 Outstanding and exercisable as at December 31, 2023 712,963 $ 42.29 729,058 $ 46.24 Compensation cost recovery recognized for employee and director DSU’s for the year ended December 31, 2023 was $ 2 6 share units realized for the year ended December 31, 2023 was $ 1 2 aggregate intrinsic value of the outstanding shares for the year ended December 31, 2023 for employees was $ 36 33 ended December 31, 2023 for directors was $ 37 34 during the year ended December 31, 2023 associated with the DSU plan were $ 3 8 million). Performance Share Unit Plan Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement. A summary of the activity related to employee PSUs for the year ended December 31, 2023 is presented in the following table: Employee PSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2022 690,446 $ 56.24 $ 40 Granted including DRIP 386,261 52.71 Exercised (323,155) 54.62 Forfeited (10,187) 55.15 Outstanding as at December 31, 2023 743,365 $ 55.13 $ 41 Compensation cost recognized for the PSU plan for the year ended December 31, 2023 was $ 11 (2022 – $ 18 ended December 31, 2023 were $ 3 5 ended December 31, 2023 associated with the PSU plan were $ 19 24 Restricted Share Unit Plan Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement. A summary of the activity related to employee RSUs for the year ended December 31, 2023 is presented in the following table: Employee RSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2022 508,468 $ 56.25 $ 30 Granted including DRIP 236,537 52.07 Exercised (171,537) 54.62 Forfeited (10,827) 54.76 Outstanding as at December 31, 2023 562,641 $ 55.01 $ 32 Compensation cost recognized for the RSU plan for the year ended December 31, 2023 was $ 10 (2022 – $ 9 ended December 31, 2023 were $ 3 2 ended December 31, 2023 associated with the RSU plan were $ 10 nil ). |
Variable Interest Entities |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Variable Interest Entities [Abstract] | |
Variable Interest Entities | 32. 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 the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as it has authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment. BLPC has 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, the 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 “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF. The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The following table provides information about Emera’s portion of material unconsolidated VIEs: As at December 31, 2023 December 31, 2022 Maximum Maximum millions of dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 489 $ 6 $ 501 $ 6 |
Subsequent Events |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Subsequent Events [Abstract] | |
Subsequent Events | 33. These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 26, 2024, the date the financial statements were issued. |
Summary of Significant Accounting Policies (Policies) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Summary of Significant Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated. |
Principles of Consolidation | Principles of Consolidation These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for VIEs in which Emera is not the primary beneficiary. The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the VIE that most significantly impacts its economic performance and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32. Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non- regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for generation and purchased power, or OM&G, depending on the nature of the transaction. |
Use of Management Estimates | Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect 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 (“ARO”), 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. |
Regulatory Matters | Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated products or services and provide an opportunity for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 6. |
Foreign Currency Translation | Foreign Currency Translation Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain USD denominated debt held in CAD functional currency companies as hedges of net investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income (“OCI”). |
Revenue Recognition | Revenue Recognition Regulated Electric and Gas Revenue: Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates approved by the respective regulators and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes. Non-regulated Revenue: Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms of the contract are satisfied and are presented on a net basis reflecting the nature of contractual relationships with customers and suppliers. Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations under the terms of the contract are satisfied. Other: Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. |
Franchise Fees and Gross Receipts | Franchise Fees and Gross Receipts TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income. |
PP&E | PP&E PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction. The cost of additions, including betterments and replacements of units, are included in “PP&E” on the Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are included in income as the dispositions occur. The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance projects and major maintenance projects that do not increase overall life of the related assets are expensed as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. For some of Emera’s rate- regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval. Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of computer software and land rights. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval. |
Goodwill | Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”). Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance. If the Company performs a qualitative assessment and determines it is more likely than not that its FV is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss is recorded. Management estimates the FV of the reporting unit by using the income approach, or a combination of the income and market approach. The income approach uses a discounted cash flow analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. For the market approach, management estimates FV based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting unit using an income approach include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting units. As of December 31, 2023, $ 5,868 purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. Given the length of time passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a combination of the income and market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying amount, including goodwill, and as a result, no impairment charges were recognized. In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment charge of $ 73 nil details, refer to note 22. |
Income Taxes and Investment Tax Credits | Income Taxes and Investment Tax Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward- looking information, and the likelihood that deferred income tax assets will be recovered from future taxable income is assessed and assumptions are made about the expected timing of reversal of deferred income tax assets and liabilities. If management subsequently determines it is likely that some or all of a deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by regulatory practices. TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable, except for the deferred income taxes on certain regulatory balances specifically prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income taxes. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. For further detail, refer to note 10. |
Derivatives and Hedging Activities | Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, FX, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as HFT. Collectively, derivatives. The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception 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 creditworthy. contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption if the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where documentation or effectiveness requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. 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 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. TEC has no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31, 2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement agreement. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues, fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an asset in “Receivables and other current assets” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”. |
Lessee, Leases | Leases The Company determines whether a contract contains a lease at inception by evaluating whether the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to purchase wind and hydro energy over varying contract lengths which are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. |
Lessor, Leases | Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the difference between the FV and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. |
Cash, Cash Equivalents and Restricted Cash | Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. |
Receivables | Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. |
Allowance for Credit Losses | Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. |
Inventory | Inventory Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates the weighted-average cost will be recovered in future customer rates. |
Asset Impairment | Asset Impairment Long-Lived Assets: Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or sale of a business. The assessment involves comparing undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long- lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or other recoverable amounts, are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets. No impairment charges related to long-lived assets were recognized in 2023 or 2022. Equity Method Investments: The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s FV. No Financial Assets: Equity investments, other than those accounted for under the equity method, are measured at FV, with changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No impairment of financial assets was required in either 2023 or 2022. |
Asset Retirement Obligations and Cost of Removal | Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study. Some of the Company’s transmission and distribution assets may have conditional AROs that are not recognized in the consolidated financial statements, as the FV of these obligations could not be reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at FV in the period in which an amount can be determined. Cost of Removal (“COR”) TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR represent funds received from customers through depreciation rates to cover estimated future non-legally required COR of PP&E upon retirement. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. |
Stock-Based Compensation | Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock- based compensation cost is measured at the grant date, based on the calculated FV of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV and re-measured at FV at each reporting date, with the change in liability recognized in income. |
Employee Benefits | Employee Benefits The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes unamortized gains and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets. The components of net periodic benefit cost other than the service cost component are included in “Other income, net” on the Consolidated Statements of Income. For further detail, refer to note 21. |
Segment Information (Tables) |
12 Months Ended |
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Dec. 31, 2023 | |
Segment Information [Abstract] | |
Segment Information | Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2023 Operating revenues from external customers (1) $ 3,548 $ 1,671 $ 1,510 $ 526 $ 308 $ $ 7,563 Inter-segment revenues (1) 8 - 14 - 31 (53) 3,556 1,671 1,524 526 339 (53) 7,563 Regulated fuel for generation and purchased power 920 699 - 275 - (13) 1,881 Regulated cost of natural gas - - 527 - - - 527 OM&G 830 384 405 130 151 (21) 1,879 Provincial, state and municipal taxes 289 45 91 3 5 - 433 Depreciation and amortization 571 276 126 68 8 - 1,049 Income from equity investments - 109 21 4 12 - 146 Other income, net 69 32 11 7 20 19 158 Interest expense, net (2) 271 170 129 23 332 - 925 Income tax expense (recovery) 117 (9) 64 - (44) - 128 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 66 - 66 Net income (loss) attributable to common shareholders $ 627 $ 247 $ 214 $ 37 $ (147) $ - $ 978 Capital expenditures $ 1,736 $ 450 $ 664 $ 63 $ 8 $ - $ 2,921 As at December 31, 2023 Total assets $ 21,119 $ 8,634 $ 7,735 $ 1,311 $ 1,938 $ (1,257) $ 39,480 Investments subject to significant influence $ - $ 1,236 $ 118 $ 48 $ - $ - $ 1,402 Goodwill $ 4,628 $ - $ 1,240 $ - $ 3 $ - $ 5,871 (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 measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 95 December 31, 2023, between the Florida Electric Utility, Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2022 Operating revenues from external customers (1) $ 3,280 $ 1,675 $ 1,697 $ 518 $ 418 $ $ 7,588 Inter-segment revenues (1) 7 - 7 - 22 (36) 3,287 1,675 1,704 518 440 (36) 7,588 Regulated fuel for generation and purchased power 1,086 803 - 290 - (8) 2,171 Regulated cost of natural gas - - 800 - - - 800 OM&G 625 338 365 123 156 (11) 1,596 Provincial, state and municipal taxes 235 43 83 3 3 - 367 Depreciation and amortization 507 259 118 61 7 - 952 Income from equity investments - 87 21 4 17 - 129 Other income (expenses), net 68 24 13 - 23 17 145 Interest expense, net (2) 185 136 81 19 288 - 709 GBPC impairment charge - - - 73 - - 73 Income tax expense (recovery) 121 (8) 70 - 2 - 185 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 63 - 63 Net income (loss) attributable to common shareholders $ 596 $ 215 $ 221 $ (48) $ (39) $ - $ 945 Capital expenditures $ 1,425 $ 507 $ 574 $ 63 $ 6 $ - $ 2,575 As at December 31, 2022 Total assets $ 21,053 $ 8,223 $ 7,737 $ 1,337 $ 2,835 $ (1,443) $ 39,742 Investments subject to significant influence $ - $ 1,241 $ 128 $ 49 $ - $ - $ 1,418 Goodwill $ 4,739 $ - $ 1,270 $ - $ 3 $ - $ 6,012 (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 measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 13 December 31, 2022, between the Gas Utilities and Infrastructure and Other segments. Geographical Information Revenues (based on country of origin of the product or service sold) For the Year ended December 31 millions of dollars 2023 2022 United States 5,310 $ 5,346 Canada 1,727 1,725 Barbados 389 384 The Bahamas 137 122 Dominica - 11 $ 7,563 $ 7,588 Property Plant and Equipment: As at December 31 December 31 millions of dollars 2023 2022 United States $ 18,588 $ 17,382 Canada 4,878 4,689 Barbados 576 583 The Bahamas 334 342 $ 24,376 $ 22,996 |
Revenue (Tables) |
12 Months Ended |
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Dec. 31, 2023 | |
Revenue [Abstract] | |
Disaggregation of 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 year ended December 31, 2023 Regulated Revenue Residential $ 2,307 $ 910 $ 183 $ 724 $ - $ - $ 4,124 Commercial 1,083 463 285 425 - - 2,256 Industrial 274 219 33 93 - (13) 606 Other electric 395 41 7 - - - 443 Regulatory deferrals (522) - 12 - - - (510) Other (1) 19 38 6 199 - (8) 254 Finance income (2)(3) - - - 62 - 62 $ 3,556 $ 1,671 $ 526 $ 1,503 $ - $ (21) $ 7,235 Non-Regulated Revenue Marketing and trading margin (4) - - - - 96 - 96 Other non-regulated operating revenue - - - 21 27 (23) 25 Mark-to-market (3) - - - - 216 (9) 207 $ - $ - $ - $ 21 $ 339 $ (32) $ 328 Total operating revenues $ 3,556 $ 1,671 $ 526 $ 1,524 $ 339 $ (53) $ 7,563 For the year ended December 31, 2022 Regulated Revenue Residential $ 1,799 $ 834 $ 184 $ 800 $ - $ - $ 3,617 Commercial 869 427 282 461 - - 2,039 Industrial 230 353 32 83 - (7) 691 Other electric 398 28 6 - - - 432 Regulatory deferrals (27) - 6 - - - (21) Other (1) 18 33 8 283 - (7) 335 Finance income (2)(3) - - - 61 - - 61 $ 3,287 $ 1,675 $ 518 $ 1,688 $ - $ (14) 7,154 Non-Regulated Marketing and trading margin (4) - - - - 143 - 143 Other non-regulated operating revenue - - - 16 16 (10) 22 Mark-to-market (3) - - - - 281 (12) 269 $ - $ - $ - $ 16 $ 440 $ (22) 434 Total operating revenues $ 3,287 $ 1,675 $ 518 $ 1,704 $ 440 $ (36) $ 7,588 (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 customers. |
Regulatory Assets and Liabilities (Tables) |
12 Months Ended |
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Dec. 31, 2023 | |
Regulatory Assets and Liabilities [Abstract] | |
Regulatory Assets | As at December 31 December 31 millions of dollars 2023 2022 Regulatory assets Deferred income tax regulatory assets $ 1,233 $ 1,166 TEC capital cost recovery for early retired assets 671 674 NSPI FAM 395 307 Pension and post-retirement medical plan 364 369 Cost recovery clauses 151 707 Deferrals related to derivative instruments 88 30 Storm cost recovery clauses 52 138 Environmental remediations 26 27 Stranded cost recovery 25 27 NMGC winter event gas cost recovery - 69 Other 100 106 $ 3,105 $ 3,620 Current $ 339 $ 602 Long-term 2,766 3,018 Total regulatory assets $ 3,105 $ 3,620 Regulatory liabilities Accumulated reserve – COR 849 895 Deferred income tax regulatory liabilities 830 877 Cost recovery clauses 32 70 BLPC Self-insurance fund ("SIF") (note 32) 29 30 Deferrals related to derivative instruments 17 230 NMGC gas hedge settlements (note 18) - 162 Other 15 9 $ 1,772 $ 2,273 Current $ 168 $ 495 Long-term 1,604 1,778 Total regulatory liabilities $ 1,772 $ 2,273 |
Regulatory Liabilities | As at December 31 December 31 millions of dollars 2023 2022 Regulatory assets Deferred income tax regulatory assets $ 1,233 $ 1,166 TEC capital cost recovery for early retired assets 671 674 NSPI FAM 395 307 Pension and post-retirement medical plan 364 369 Cost recovery clauses 151 707 Deferrals related to derivative instruments 88 30 Storm cost recovery clauses 52 138 Environmental remediations 26 27 Stranded cost recovery 25 27 NMGC winter event gas cost recovery - 69 Other 100 106 $ 3,105 $ 3,620 Current $ 339 $ 602 Long-term 2,766 3,018 Total regulatory assets $ 3,105 $ 3,620 Regulatory liabilities Accumulated reserve – COR 849 895 Deferred income tax regulatory liabilities 830 877 Cost recovery clauses 32 70 BLPC Self-insurance fund ("SIF") (note 32) 29 30 Deferrals related to derivative instruments 17 230 NMGC gas hedge settlements (note 18) - 162 Other 15 9 $ 1,772 $ 2,273 Current $ 168 $ 495 Long-term 1,604 1,778 Total regulatory liabilities $ 1,772 $ 2,273 |
Investments Subject to Significant Influence and Equity Income (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Variable Interest Entity [Line Items] | |
Summary of Investments Subject to Significant Influence | Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of dollars 2023 2022 2023 2022 2023 LIL (1) $ 747 $ 740 $ 63 $ 58 31.0 NSPML 489 501 46 29 100.0 M&NP 118 128 21 21 12.9 Lucelec (2) 48 49 4 4 19.5 Bear Swamp - - 12 17 50.0 $ 1,402 $ 1,418 $ 146 $ 129 (1) Emera indirectly owns 100 24.5 ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 transmission developments. (2) Emera has significant influence over the operating and financial decisions of these companies through Board representation 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 Bear Swamp's credit investment balance of $ 81 95 Consolidated Balance Sheets. |
NSP Maritime Link Inc. [Member] | |
Variable Interest Entity [Line Items] | |
Summary of Investments Subject to Significant Influence | Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of dollars 2023 2022 Balance Sheets Current assets $ 21 $ 17 PP&E 1,473 1,517 Regulatory assets 272 265 Non-current assets 29 29 Total assets $ 1,795 $ 1,828 Current liabilities $ 48 $ 48 Long-term debt (1) 1,109 1,149 Non-current liabilities 149 130 Equity 489 501 Total liabilities and equity $ 1,795 $ 1,828 (1) The project debt has been guaranteed by the Government of Canada. |
Other Income, Net (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Other Income, Net [Abstract] | |
Components of Other Expense, Net | For the Year ended December 31 millions of dollars 2023 2022 Interest income $ 43 $ 25 AFUDC 38 52 Pension non-current service cost recovery 35 24 FX gains (losses) 20 (26) TECO Guatemala Holdings award (1) - 63 Other 22 7 $ 158 $ 145 (1) On December 15, 2022, a payment of $ 63 second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute an investment in TGH, a wholly-owned subsidiary of TECO Energy. |
Interest Expense, Net (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Interest Expense, Net [Abstract] | |
Components of Interest Expense, Net | Interest expense, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2023 2022 Interest on debt $ 954 $ 727 Allowance for borrowed funds used during construction (16) (21) Other (13) 3 $ 925 $ 709 |
Income Taxes (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Income Taxes [Abstract] | |
Reconciliation of Effective Income Tax Rate | The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons: millions of dollars 2023 2022 Income before provision for income taxes $ 1,173 $ 1,194 Statutory income tax rate 29.0% 29.0% Income taxes, at statutory income tax rate 340 346 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (72) (70) Tax credits (53) (18) Foreign tax rate variance (36) (44) Amortization of deferred income tax regulatory liabilities (33) (33) Tax effect (15) (10) GBPC impairment charge - 21 Other (3) (7) Income tax expense $ 128 $ 185 Effective income tax rate 11% 15% |
Composition of Taxes on Income from Continuing Operations | millions of dollars 2023 2022 Current income taxes $ 26 $ 25 5 8 Deferred income taxes 93 122 128 252 Investment tax credits (29) (7) Operating loss carryforwards (93) (94) (2) (121) Income tax expense $ 128 $ 185 The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2023 2022 Canada $ 171 $ 173 United States 964 1,063 Other 38 (42) Income before provision for income taxes $ 1,173 $ 1,194 |
Schedule of Deferred Income Tax Assets and Liabilities | The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of dollars 2023 2022 Deferred income tax assets: Tax loss carryforwards $ 1,195 $ 1,207 Tax credit carryforwards 454 415 Derivative instruments 205 45 Regulatory liabilities 175 264 Other 372 341 Total deferred income tax assets before valuation allowance 2,401 2,272 Valuation allowance (363) (312) Total deferred income tax assets after valuation allowance $ 2,038 $ 1,960 Deferred income tax (liabilities): PP&E $ (3,223) $ (2,981) Derivative instruments (235) (125) Investments subject to significant influence (216) (181) Regulatory assets (196) (310) Other (312) (322) Total deferred income tax liabilities $ (4,182) $ (3,919) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 208 $ 237 Long-term deferred income tax liabilities (2,352) (2,196) Net deferred income tax liabilities $ (2,144) $ (1,959) |
Net Operating Loss ("NOL"), Capital Loss and Tax Credit Carryforwards and Their Expiration Periods | Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2023 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of dollars Carryforwards Allowance Carryforwards Period Canada $ 2,914 $ (1,164) $ 1,750 2026 - 2043 73 (73) - Indefinite United States $ 1,360 $ (1) $ 1,359 2036 - Indefinite 1,003 (1) 1,002 2026 - Indefinite 454 (3) 451 2025 - 2043 Other $ 81 $ (28) $ 53 2024 - 2030 |
Details of Change in Unrecognized Tax Benefits | millions of dollars 2023 2022 Balance, January 1 $ 33 $ 28 Increases due to tax positions related to current year 5 5 Increases due to tax positions related to a prior year 1 2 Decreases due to tax positions related to a prior year (2) (2) Balance, December 31 $ 37 $ 33 |
Common Stock (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Common Stock [Abstract] | |
Summary of Issued and Outstanding Common Stock | Authorized : 2023 2022 Issued and outstanding: millions of shares dollars millions of shares dollars Balance, January 1 269.95 $ 7,762 261.07 $ 7,242 Issuance of common stock under ATM program (1)(2) 8.29 397 4.07 248 Issued under the DRIP, 5.26 272 4.21 238 Senior management stock options exercised and Employee Share Purchase Plan 0.62 31 0.60 34 Balance, December 31 284.12 $ 8,462 269.95 $ 7,762 (1) For the year ended December 31, 2022, a total of 4,072,469 average price of $ 61.31 250 248 (2) For the year ended December 31, 2023, a total of 8,287,037 average price of $ 48.27 400 397 |
Earnings Per Share (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Earnings per Share | The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of dollars (except per share amounts) 2023 2022 Numerator Net income attributable to common shareholders $ 977.7 $ 945.1 Diluted numerator 977.7 945.1 Denominator Weighted average shares of common stock outstanding – basic 273.6 265.5 Stock-based compensation 0.2 0.4 Weighted average shares of common stock outstanding – diluted 273.8 265.9 Earnings per common share Basic $ 3.57 $ 3.56 Diluted $ 3.57 $ 3.55 |
Accumulated Other Comprehensive Income (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Accumulated Other Comprehensive Income [Abstract] | |
Components of Accumulated Other Comprehensive Income | The components of AOCI are as follows: millions of dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges Losses on derivatives recognized as cash flow hedges Net change on available- for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2023 Balance, January 1, 2023 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 Other comprehensive (loss) income before reclassifications (270) 38 - - (232) Amounts reclassified from AOCI - - (2) - (39) (41) Net current period other comprehensive (loss) income (270) 38 (2) - (39) (273) Balance, December 31, 2023 $ 369 $ (24) $ 14 $ (2) $ (52) $ 305 For the year ended December 31, 2022 Balance, January 1, 2022 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 Other comprehensive income (loss) before reclassifications 629 (97) - (1) - 531 Amounts reclassified from AOCI - - (2) - 24 22 Net current period other comprehensive income (loss) 629 (97) (2) (1) 24 553 Balance, December 31, 2022 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 |
Reclassifications out of Accumulated Other Comprehensive Income (Loss) | The reclassifications out of AOCI are as follows: For the Year ended December 31 millions of dollars 2023 2022 Affected line item in the Consolidated Financial Statements Gains on derivatives recognized as cash flow hedges Interest expense, net $ (2) $ (2) Net change in unrecognized pension and post-retirement benefit costs Other income, net $ - $ 10 Other income, net 2 - Pension and post-retirement benefits (40) 15 Total before tax (38) 25 Income tax expense (1) (1) Total net of tax $ (39) $ 24 Total reclassifications out of AOCI, net of tax, for the period $ (41) $ 22 |
Inventory (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Inventory [Abstract] | |
Components of Inventory | As at December 31 December 31 millions of dollars 2023 2022 Fuel $ 382 $ 404 Materials 408 365 Total $ 790 $ 769 |
Derivative Instruments (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Derivative Instruments | |
Derivative Assets and Liabilities | Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of dollars 2023 2022 2023 2022 Regulatory deferral: $ 16 $ 186 $ 76 $ 42 3 18 3 1 - 52 - - 19 256 79 43 HFT derivatives: 29 89 36 77 319 340 531 1,224 348 429 567 1,301 Other derivatives: 4 - - 5 18 5 7 23 22 5 7 28 Total gross current derivatives 389 690 653 1,372 Impact of master netting agreements: (3) (18) (3) (18) (146) (276) (146) (276) Total impact of master netting agreements (149) (294) (149) (294) Total derivatives $ 240 $ 396 $ 504 $ 1,078 Current (1) 174 296 386 888 Long-term (1) 66 100 118 190 Total derivatives $ 240 $ 396 $ 504 $ 1,078 (1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying |
Cash Flow Hedges Recorded in AOCI | For the Year ended December 31 millions of dollars 2023 2022 Interest Interest rate hedge rate hedge Realized gain in interest expense, net $ 2 $ 2 Total gains in net income $ 2 $ 2 As at December 31 December 31 millions of dollars 2023 2022 Interest Interest rate hedge rate hedge Total unrealized gain in AOCI – effective portion, net of tax $ 14 $ 16 |
Changes in Realized and Unrealized Gains (Losses) on Derivatives | Physical Commodity Physical Commodity natural gas swaps and FX natural gas swaps and FX millions of dollars purchases forwards forwards purchases forwards forwards For the year ended December 31 2023 2022 Unrealized gain (loss) in regulatory assets $ - $ (109) $ (3) $ - $ (69) $ 1 Unrealized gain (loss) in regulatory liabilities (3) (73) - 28 343 16 Realized (gain) loss in regulatory assets - (5) - - 48 - Realized (gain) loss in regulatory liabilities - 2 - - (41) - Realized (gain) loss in inventory (1) - 4 (10) - (121) 1 Realized (gain) in regulated fuel for generation and purchased power (2) (49) (9) (4) (64) (146) - Other - (14) - - - - Total change in derivative instruments $ (52) $ (204) $ (17) $ (36) $ 14 $ 18 (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. For the Year ended December 31 millions of dollars 2023 2022 Power swaps and physical contracts in non-regulated operating revenues $ (6) $ 17 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 1,043 47 Total gains in net income $ 1,037 $ 64 For the Year ended December 31 millions of dollars 2023 2022 FX Equity FX Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in OM&G $ - $ 4 $ - $ (5) Unrealized gain (loss) in other income, net 28 - (18) - Realized loss in OM&G - (13) - (17) Realized loss in other income, net (11) - (6) - Total gains (losses) in net income $ 17 $ (9) $ (24) $ (22) |
Notional Volumes of Outstanding Derivatives | millions 2024 2025-2026 Physical natural gas purchases: Natural gas (MMBtu) 7 6 Commodity swaps and forwards purchases: Natural gas (MMBtu) 16 10 Power (MWh) 1 1 Coal (metric tonnes) 1 - FX swaps and forwards: FX contracts (millions of USD) $ 241 $ 70 Weighted average rate 1.3155 1.3197 % of USD requirements 63% 17% 2028 and millions 2024 2025 2026 2027 thereafter Natural gas purchases (Mmbtu) 296 80 50 38 30 Natural gas sales (Mmbtu) 338 86 16 6 4 Power purchases (MWh) 1 - - - - Power sales (MWh) 1 - - - - |
Summary of Concentration Risk | Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2023 December 31, 2022 millions of dollars % of total exposure millions of dollars % of total exposure Receivables, net Regulated utilities: Residential $ 476 31% $ 455 19% Commercial 194 13% 192 8% Industrial 84 5% 121 5% Other 103 7% 122 5% Cash collateral 94 6% - 0% 951 62% 890 37% Trading group: Credit rating of A- or above 47 3% 125 5% Credit rating of BBB- to BBB+ 33 2% 75 3% Not rated 108 7% 307 13% 188 12% 507 21% Other accounts receivable 151 10% 585 25% 1,290 84% 1,982 83% Derivative Instruments (current and long-term) Credit rating of A- or above 138 9% 202 9% Credit rating of BBB- to BBB+ 7 1% 8 0% Not rated 95 6% 186 8% 240 16% 396 17% $ 1,530 100% $ 2,378 100% |
Cash Collateral Positions | As at December 31 December 31 millions of dollars 2023 2022 Cash collateral provided to others $ 101 $ 224 Cash collateral received from others $ 22 $ 112 |
FV Measurements (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
FV Measurements [Abstract] | |
Classification of Fair Value of Derivatives | As at December 31, 2023 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 7 $ 6 $ - $ 13 - 3 - 3 7 9 - 16 HFT derivatives: (5) 23 - 18 42 108 34 184 37 131 34 202 Other derivatives: - 18 - 18 4 - - 4 4 18 - 22 Total assets 48 158 34 240 Liabilities Regulatory deferral: 43 30 - 73 - 3 - 3 43 33 - 76 HFT derivatives: - 24 - 24 13 19 365 397 13 43 365 421 Other derivatives: - 7 - 7 - 7 - 7 Total liabilities 56 83 365 504 Net assets (liabilities) $ (8) $ 75 $ (331) $ (264) As at December 31, 2022 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 120 $ 48 $ - $ 168 - 18 - 18 - - 52 52 120 66 52 238 HFT derivatives: 9 31 4 44 3 72 34 109 12 103 38 153 Other derivatives: - 5 - 5 Total assets 132 174 90 396 Liabilities Regulatory deferral: 15 9 - 24 - 1 - 1 15 10 - 25 HFT derivatives: 2 28 1 31 51 118 825 994 53 146 826 1,025 Other derivatives: - 23 - 23 5 - - 5 Total liabilities 73 179 826 1,078 Net assets (liabilities) $ 59 $ (5) $ (736) $ (682) |
Change in Fair Value of Level 3 Financial Assets | The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as follows: Regulatory Deferral HFT Derivatives Physical natural Natural millions of dollars gas purchases Power gas Total Balance, January 1, 2023 $ 52 $ 4 $ 34 $ 90 Realized gains (losses) included in fuel for generation and purchased power (49) - - (49) Unrealized gains (losses) included in regulatory assets and liabilities (3) - - (3) Total realized and unrealized gains (losses) included in non-regulated operating revenues - (4) - (4) Balance, December 31, 2023 $ - $ - $ 34 $ 34 |
Change in Fair Value of Level 3 Financial Liabilities | The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as follows: Natural millions of dollars Power gas Total Balance, January 1, 2023 $ 1 $ 825 $ 826 Total realized and unrealized gains included in non- regulated operating revenues (1) (460) (461) Balance, December 31, 2023 $ - $ 365 $ 365 |
Quantitative Information About Significant Unobservable Inputs Used in Level 3 Measurements | Significant Weighted millions of dollars FV Unobservable Input Low High average (1) Assets Liabilities As at December 31, 2023 HFT derivatives – Natural 34 365 Third-party pricing $1.27 $16.25 $4.85 gas swaps, futures, forwards and physical contracts Total $ 34 $ 365 Net liability $ 331 As at December 31, 2022 Regulatory deferral – Physical $ 52 $ - Third-party pricing $5.79 $31.85 $12.27 natural gas purchases HFT derivatives – Power 4 1 Third-party pricing $43.24 $269.10 $138.79 swaps and physical contracts HFT derivatives – Natural 34 825 Third-party pricing $2.45 $33.88 $12.01 gas swaps, futures, forwards and physical contracts Total $ 90 $ 826 Net liability $ 736 (1) Unobservable inputs were weighted by the relative FV of the instruments. |
Financial Liabilities not Measured at Fair Value on Consolidated Balance Sheets | Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The balance consisted of the following: As at Carrying millions of dollars Amount FV Level 1 Level 2 Level 3 Total December 31, 2023 $ 18,365 $ 16,621 $ - $ 16,363 $ 258 $ 16,621 December 31, 2022 $ 16,318 $ 14,670 $ - $ 14,284 $ 386 $ 14,670 |
Receivables and Other Current Assets (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Receivables and Other Current Assets [Abstract] | |
Summary of Receivables and Other Current Assets | 18. As at December 31 December 31 millions of dollars 2023 2022 Customer accounts receivable – billed $ 805 $ 1,096 Capitalized transportation capacity (1) 358 781 Customer accounts receivable – unbilled 363 424 Prepaid expenses 105 82 Income tax receivable 10 9 Allowance for credit losses (15) (17) NMGC gas hedge settlement receivable 162 Other 191 360 Total receivables and other current assets $ 1,817 $ 2,897 (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. (2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information, to note 6. |
Leases (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Leases [Abstract] | |
Lessee, Operating Leases and Additional Information | As at December 31 December 31 millions of dollars Classification 2023 2022 Right-of-use asset Other long-term assets $ 54 $ 58 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 55 59 Total lease liabilities $ 58 $ 62 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2023 2022 Cash paid for amounts included in the measurement of lease liabilities: $ 8 $ 8 Right-of-use assets obtained in exchange for lease obligations: $ 1 $ 1 Weighted average remaining lease term (years) 44 44 Weighted average discount rate- operating leases 3.93% 3.98% |
Lessee, Future Minimum Lease Payments Under Non-Cancellable Operating Leases | Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Minimum lease payments $ 6 $ 5 $ 3 $ 3 $ 3 $ 111 $ 131 Less imputed interest (73) Total $ 58 |
Lessor, Direct Finance and Sales-Type Leases | As at December 31 December 31 millions of dollars 2023 2022 Total minimum lease payment to be received $ 1,360 $ 1,393 Less: amounts representing estimated executory costs (190) (205) Minimum lease payments receivable $ 1,170 $ 1,188 Estimated residual value of leased property (unguaranteed) 183 183 Less: Credit loss reserve (2) - Less: unearned finance lease income (693) (733) Net investment in direct finance and sales-type leases $ 658 $ 638 Principal due within one year (included in "Receivables and other current assets") 37 34 Net Investment in direct finance and sales type leases - long-term $ 621 $ 604 |
Lessor, Future Minimum Lease Payments to be Received | As at December 31, 2023, future minimum lease payments to be received for each of the next five years and in aggregate thereafter were as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Minimum lease payments to be received $ 97 $ 99 $ 98 $ 97 $ 96 $ 873 $ 1,360 Less: executory costs (190) Total $ 1,170 |
Property, Plant and Equipment (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Regulated and Non-Regulated Assets | PP&E consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of dollars Estimated useful life 2023 2022 Generation 3 131 $ 13,500 $ 13,083 Transmission 10 80 2,835 2,731 Distribution 4 80 7,417 6,978 Gas transmission and distribution 6 92 5,536 5,061 General plant and other 2 71 2,985 2,723 Total cost 32,273 30,576 Less: Accumulated depreciation (1) (9,994) (9,574) 22,279 21,002 Construction work in progress (1) 2,097 1,994 Net book value $ 24,376 $ 22,996 (1) SeaCoast owns a 50 % undivided ownership interest in a jointly owned 26 -mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $ 27 27 accumulated depreciation of $ 2 1 funds and all operations are accounted for as if such participating interest were a wholly owned facility. expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income. |
Employee Benefit Plans (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Employee Benefit Plans [Abstract] | |
Changes in Benefit Obligation and Plan Assets and Funded Status | For the Year ended December 31 millions of dollars 2023 2022 Change in Projected Benefit Obligation ("PBO") and Accumulated Post- retirement Benefit Obligation ("APBO") Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Balance, January 1 $ 2,158 $ 243 $ 2,624 $ 318 Service cost 30 3 41 4 Plan participant contributions 6 6 6 6 Interest cost 111 13 80 9 Plan amendments - (14) - - Benefits paid (147) (29) (174) (31) Actuarial losses (gains) 146 10 (480) (79) Settlements and curtailments (8) - (6) - FX translation adjustment (23) (5) 67 16 Balance, December 31 $ 2,273 $ 227 $ 2,158 $ 243 Change in plan assets Balance, January 1 $ 2,163 $ 46 $ 2,702 $ 51 Employer contributions 42 23 45 24 Plan participant contributions 6 6 6 6 Benefits paid (147) (29) (174) (31) Actual return on assets, net of expenses 262 3 (489) (7) Settlements and curtailments (8) - (6) - FX translation adjustment (20) (1) 79 3 Balance, December 31 $ 2,298 $ 48 $ 2,163 $ 46 Funded status, end of year $ 25 $ (179) $ 5 $ (197) |
Plans with PBO/APBO in Excess of Plan Assets and Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 120 $ 205 $ 1,006 $ 221 FV of plan assets 37 - 914 - Funded status $ (83) $ (205) $ (92) $ (221) millions of dollars 2023 2022 Defined benefit pension plans Defined benefit pension plans ABO $ 114 $ 111 FV of plan assets 37 33 Funded status $ (77) $ (78) |
Amounts Recognized in Consolidated Balance Sheets | As at December 31 December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (5) $ (18) $ (13) $ (20) Long-term liabilities (78) (187) (80) (201) Other long-term assets 108 26 98 24 AOCI, net of tax and regulatory assets 385 20 358 22 Less: Deferred income tax (expense) recovery in AOCI (8) (1) (7) (1) Net amount recognized $ 402 $ (160) $ 356 $ (176) |
Amounts Recognized in AOCI and Regulatory Assets | Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of dollars Defined Benefit Pension Plans Balance, January 1, 2023 $ 336 $ 15 $ - Amortized in current period (6) (3) - Current year additions 1 41 - Change in FX rate (7) - - Balance, December 31, 2023 $ 324 $ 53 $ - Non-pension benefits plans Balance, January 1, 2023 $ 31 $ (10) $ - Amortized in current period 2 3 - Current year reductions (3) (1) (3) Change in FX rate (1) - 1 Balance, December 31, 2023 $ 29 $ (8) $ (2) As at December 31 December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 53 (8) $ 15 $ (10) Past service gains - (2) - - Deferred income tax expense 8 1 7 1 AOCI, net of tax 61 (9) 22 (9) Regulatory assets 324 29 336 31 AOCI, net of tax and regulatory assets $ 385 $ 20 $ 358 $ 22 |
Net Periodic Benefit Cost | As at Year ended December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 30 $ 3 $ 41 $ 4 Interest cost 111 13 80 9 Expected return on plan assets (161) (2) (144) - Current year amortization of: 1 (3) 8 - 6 (2) 21 2 Settlement, curtailments 2 - 2 - Total $ (11) $ 9 $ 8 $ 15 |
Pension Plan Asset Allocations | Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 10% Fixed income 34% to 49% Equities: 7% to 17% 35% to 59% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Cash and cash equivalents 0% to 10% Fixed income 29% to 49% Equities 48% to 68% |
Fair Value of Plan Assets | millions of dollars NAV Level 1 Level 2 Total Percentage As at December 31, 2023 Cash and cash equivalents $ - $ 40 $ - $ 40 2 % Net in-transits - (9) - (9) - % Equity securities: - 96 - 96 4 % - 141 - 141 6 % - 112 - 112 5 % Fixed income securities: - - 172 172 8 % - - 90 90 4 % - 4 5 9 - % Mutual funds - 50 - 50 2 % Other - 6 (1) 5 - % Open-ended investments measured at NAV 1,006 - - 1,006 44 % Common collective trusts measured at NAV (2) 586 - - 586 25 % Total $ 1,592 $ 440 $ 266 $ 2,298 100 % As at December 31, 2022 Cash and cash equivalents $ - $ 70 $ - $ 70 3 % Net in-transits - (70) - (70) (3) % Equity securities: - 87 - 87 4 % - 233 - 233 11 % - 186 - 186 8 % Fixed income securities: - - 104 104 5 % - - 83 83 4 % - 3 11 14 1 % Mutual funds - 68 - 68 3 % Other - - (3) (3) - % Open-ended investments measured at NAV 790 - - 790 36 % Common collective trusts measured at NAV (2) 601 - - 601 28 % Total $ 1,391 $ 577 $ 195 $ 2,163 100 % (1) Net asset value ("NAV") investments are open-ended or pooled funds. NAV’s are calculated (2) The common collective trusts are private funds valued at NAV. securities. Since the prices are not published to external sources, NAV primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour subscription and redemption activity regularly. |
Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Benefit Plans | millions of dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2024 $ 34 $ 19 Expected benefit payments 2024 172 21 2025 163 21 2026 166 21 2027 171 21 2028 173 20 2029 – 2033 890 95 |
Assumptions Used in Accounting for Defined Benefit Pension and Other Post-Retirement Benefit Plans | Assumptions: The following table shows the assumptions that have been used in accounting for DB pension and other post-retirement benefit plans: 2023 2022 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 4.89 % 4.89 % 5.33 % 5.31 % Discount rate - future service 4.88 % 4.89 % 5.34 % 5.32 % Rate of compensation increase 3.87 % 3.85 % 3.62 % 3.61 % Health care trend - 6.04 % - 5.40 % - 3.76 % - 3.77 % 2043 2043 Benefit cost for year ended December 31: Discount rate - past service 5.33 % 5.31 % 3.05 % 2.81 % Discount rate - future service 5.34 % 5.32 % 3.18 % 2.92 % Expected long-term return on plan assets 6.56 % 2.16 % 6.07 % 1.32 % Rate of compensation increase 3.62 % 3.61 % 3.31 % 3.29 % Health care trend - 5.40 % - 5.09 % - 3.77 % - 3.77 % 2043 2042 Actual assumptions used differ by plan. |
Goodwill (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Goodwill [Abstract] | |
Change in Goodwill | 22. The change in goodwill for the year ended December 31 was due to the following: millions of dollars 2023 2022 Balance, January 1 $ 6,012 $ 5,696 Change in FX rate (141) 389 GBPC impairment charge - (73) Balance, December 31 $ 5,871 $ 6,012 |
Short-Term Debt (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Short-Term Debt [Abstract] | |
Short-Term Debt and Related Weighted-Average Interest Rates | millions of dollars 2023 Weighted average interest rate 2022 Weighted average interest rate TEC Advances on revolving credit facilities $ 277 5.68 % $ 1,380 5.00 % Emera Non-revolving term facilities 796 6.07 % 796 5.19 % Bank indebtedness 9 - % - - % TECO Finance Advances on revolving credit and term facilities 245 6.54 % 481 5.47 % PGS Advances on revolving credit facilities 73 6.36 % - - % NMGC Advances on revolving credit facilities 25 6.46 % 59 5.15 % GBPC Advances on revolving credit facilities 8 5.54 % 10 5.25 % Short-term debt $ 1,433 $ 2,726 The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of dollars Maturity 2023 2022 TEC - Unsecured committed revolving credit facility 2026 $ 401 $ 1,084 TECO Energy/TECO Finance - revolving credit facility 2026 - 542 TECO Finance - Unsecured committed revolving credit facility 2026 529 - Emera - Unsecured non-revolving term facility 2024 400 400 Emera - Unsecured non-revolving term facility 2024 400 400 PGS - Unsecured revolving credit facility 2028 331 - TEC - Unsecured revolving facility 2024 265 542 TEC - Unsecured revolving facility 2024 265 - NMGC - Unsecured revolving credit facility 2026 165 169 Other - Unsecured committed revolving credit facilities Various 17 18 Total $ 2,773 $ 3,155 Less: Advances under revolving credit and term facilities 1,433 2,731 Letters of credit issued within the credit facilities 3 4 Total advances under available facilities 1,436 2,735 Available capacity under existing agreements $ 1,337 $ 420 |
Other Current Liabilities (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Other Current Liabilities | |
Components of Other Current Liabilities | As at December 31 December 31 millions of dollars 2023 2022 Accrued charges $ 172 $ 174 Nova Scotia Cap-and-Trade Program provision (note 6) - 172 Accrued interest on long-term debt 107 97 Pension and post-retirement liabilities (note 21) 23 33 Sales and other taxes payable 11 14 Income tax payable 2 9 Other 112 80 $ 427 $ 579 |
Long-Term Debt (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Long-term Debt [Abstract] | |
Summary of Long-Term Debt, Revolving Credit Facilities, Outstanding Borrowings and Available Capacity | Weighted average interest rate (1) millions of dollars 2023 2022 Maturity 2023 2022 Emera Bankers acceptances, SOFR loans Variable Variable 2027 $ 465 $ 403 Unsecured fixed rate notes 4.84% 2.90% 2030 500 500 Fixed to floating subordinated notes (2) 6.75% 6.75% 2076 1,587 1,625 $ 2,552 $ 2,528 Emera Finance Unsecured senior notes 3.65% 3.65% 2024 - 2046 $ 3,637 $ 3,725 TEC (3) Fixed rate notes and bonds 4.61% 4.15% 2024 - 2051 $ 5,654 $ 4,341 PGS Fixed rate notes and bonds 5.63% 3.78% 2028 - 2053 $ 1,223 $ 772 NMGC Fixed rate notes and bonds 3.78% 3.11% 2026 - 2051 $ 642 $ 521 Non-revolving term facility, floating rate Variable Variable 2024 30 108 $ 672 $ 629 NMGI Fixed rate notes and bonds 3.64% 3.64% 2024 $ 198 $ 203 NSPI Discount Notes (4) Variable Variable 2024 - 2027 $ 721 $ 881 Medium term fixed rate notes 5.13% 5.14% 2025 - 2097 3,165 2,665 $ 3,886 $ 3,546 EBP Senior secured credit facility Variable Variable 2026 $ 246 $ 249 ECI Secured senior notes Variable Variable 2027 $ 75 $ 86 Amortizing fixed rate notes 4.00% 3.97% 2026 79 100 Non-revolving term facility, floating rate Variable Variable 2025 29 30 Non-revolving term facility, fixed rate 2.15% 2.05% 2025 - 2027 155 91 Secured fixed rate senior notes (5) 3.09% 3.06% 2024 - 2029 84 142 $ 422 $ 449 Adjustments Fair market value adjustment - TECO Energy acquisition $ - $ 2 Debt issuance costs (125) (126) Amount due within one year (676) (574) $ (801) $ (698) Long-Term Debt $ 17,689 $ 15,744 (1) Weighted average interest rate of fixed rate long-term debt. (2) In 2023, the Company recognized $ 109 110 subordinated notes. (3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently bonds outstanding under TEC’s first mortgage bond indenture. (4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’ acceptances for a period of greater than one year. (5) Notes are issued and payable in either USD or BBD. The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of dollars Maturity 2023 2022 Emera – revolving credit facility (1) June 2027 $ 900 $ 900 TEC - Unsecured committed revolving credit facility December 2026 657 - NSPI - revolving credit facility (1) December 2027 800 800 NSPI - non-revolving credit facility July 2024 400 400 Emera - Unsecured non-revolving credit facility February 2024 400 - NMGC - Unsecured non-revolving credit facility March 2024 30 108 ECI – revolving credit facilities October 2024 10 11 Total $ 3,197 $ 2,219 Less: Borrowings under credit facilities 1,884 1,396 Letters of credit issued inside credit facilities 6 12 Use of available facilities $ 1,890 $ 1,408 Available capacity under existing agreements $ 1,307 $ 811 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $ 50 As at Financial Covenant Requirement December 31, 2023 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.57 |
Long-Term Debt Maturities | millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Emera $ 199 $ - $ 1,587 $ 266 $ - $ 500 $ 2,552 Emera US Finance LP 397 - 992 - - 2,248 3,637 TEC 397 - - - - 5,257 5,654 PGS - - - - 463 760 1,223 NMGC 30 - 93 - - 549 672 NMGI 198 - - - - - 198 NSPI 398 125 40 323 - 3,000 3,886 EBP - - 246 - - - 246 ECI 51 139 89 77 62 4 422 Total $ 1,670 $ 264 $ 3,047 $ 666 $ 525 $ 12,318 $ 18,490 |
Asset Retirement Obligations (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Asset Retirement Obligations [Abstract] | |
Change in Asset Retirement Obligations | The change in ARO for the years ended December 31 is as follows: millions of dollars 2023 2022 Balance, January 1 $ 174 $ 174 Accretion included in depreciation expense 9 9 Change in FX rate (1) 3 Additions - 1 Accretion deferred to regulatory asset (included in PP&E) 18 1 Liabilities settled (8) (1) Revisions in estimated cash flows - (13) Balance, December 31 $ 192 $ 174 |
Commitments and Contingencies (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Summary of Contractual Commitments | millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Transportation (1) $ 696 $ 495 $ 405 $ 388 $ 338 $ 2,597 $ 4,919 Purchased power (2) 274 249 263 312 312 3,435 4,845 Fuel, gas supply and storage 556 215 62 - 5 - 838 Capital projects 778 111 70 1 - - 960 Equity investment commitments (3) 240 - - - - - 240 Other 154 147 56 46 35 221 659 $ 2,698 $ 1,217 $ 856 $ 747 $ 690 $ 6,253 $ 12,461 (1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. $ 134 (2) Annual requirement to purchase electricity production from IPPs 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 contributions over the life of the partnership. respective investment obligations of the parties in relation 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. |
Cumulative Preferred Stock (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Cumulative Preferred Stock [Abstract] | |
Summary of Cumulative Preferred Stock | Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2023 December 31, 2022 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.5456 $ 25.00 4,866,814 $ 119 4,866,814 $ 119 Series B Floating $ 25.00 1,133,186 $ 28 1,133,186 $ 28 Series C $ 1.6085 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.00 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0505 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.5810 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Series J $ 1.0625 $ 25.00 8,000,000 $ 196 8,000,000 $ 196 Series L $ 1.1500 $ 26.00 9,000,000 $ 222 9,000,000 $ 222 Total 58,000,000 $ 1,422 58,000,000 $ 1,422 Characteristics of the First Preferred Shares: First Preferred Shares (1)(2) Initial Yield (%) Current Annual Dividend ($) Minimum Reset Dividend Yield (%) Earliest Redemption and/or Conversion Option Date Redemption Value ($) Right to Convert on a one for one basis Fixed rate reset (3)(4) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B 4.100 1.6085 2.65 August 15, 2028 25.00 Series D 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) 2.393 Floating 1.84 August 15, 2025 25.00 Series A (5)(7) 4.900 1.5810 4.90 August 15, 2028 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate 4.500 1.1250 25.00 (9) 4.600 1.1500 November 15, 2026 26.00 (1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation. (2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but dates fixed for redemption. (3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying 25.00 share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government Bond Yield on the applicable reset date, plus the applicable reset dividend yield 4.90 (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years for cash, in whole or in part at a price of $ 25.00 redemption and $ 25.50 of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively. yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 (5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series 2023. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, C Shares were converted into Series D Shares and no Series H Shares were converted into Series I shares. (6) The annual fixed dividend per share for Series C Shares was reset from $ 1.1802 1.6085 including August 15, 2028. (7) The annual fixed dividend per share for Series H Shares was reset from $ 1.2250 1.5810 including August 15, 2028. (8) First Preferred Shares, Series E are redeemable at $25.00 per share. (9) First Preferred Shares, Series L are redeemable at $ 26.00 $ 0.25 25.00 |
Non-Controlling Interest in Subsidiaries (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Non-Controlling Interest in Subsidiaries [Abstract] | |
Components of Non-Controlling Interest | 29. As at December 31 December 31 millions of dollars 2023 2022 Preferred shares of GBPC $ 14 $ 14 $ 14 $ 14 |
Preferred Shares of GBPC | Preferred shares of GBPC: Authorized: 10,000 2023 2022 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14 |
Supplementary Information to Consolidated Statements of Cash Flows (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Supplementary Information to Consolidated Statements of Cash Flows [Abstract] | |
Summary of Supplementary Information to Consolidated Statement of Cash Flows | For the Year ended December 31 millions of dollars 2023 2022 Changes in non-cash working capital: $ (31) $ (214) (1) 653 (636) (538) 423 (2) (179) 193 Total non-cash working capital $ (95) $ (234) (1) Includes $ 162 162 ) million). Offsetting regulatory liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities. (2) Includes ($ 166 ) million related to the Nova Scotia Cap-and-Trade program (2022 – $ 172 6. Offsetting regulatory asset (FAM) balance is cash provided by operating activities. For the Year ended December 31 millions of dollars 2023 2022 Supplemental disclosure of cash paid: Interest $ 930 $ 699 Income taxes $ 43 $ 67 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 271 $ 237 Decrease in accrued capital expenditures $ (19) $ (13) Reclassification of short-term debt to long-term debt $ 657 $ - Reclassification of long-term debt to short-term debt $ - $ 500 Supplemental disclosure of operating activities: Net change in short-term regulatory assets and liabilities $ 123 $ (157) |
Stock Based Compensation (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Stock-Based Compensation [Abstract] | |
Weighted Average Fair Values per Stock Option and Assumptions for Options Granted | 2023 2022 Weighted average FV per option $ 6.32 $ 5.35 Expected term (1) 5 5 Risk-free interest rate (2) 3.53 % 1.79 % Expected dividend yield (3) 5.05 % 4.55 % Expected volatility (4) 20.07 % 18.87 % (1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government bond yields. (3) Incorporates current dividend rates and historical dividend increase patterns. (4) Estimated using the five-year historical volatility. |
Summary of Stock Option Information | Total Options Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2022 2,853,879 $ 50.41 1,348,400 $ 4.08 Granted 483,100 54.64 483,100 6.32 Exercised (146,475) 43.94 N/A N/A Forfeited (94,900) 56.32 (51,625) 3.61 Vested N/A N/A (526,620) 3.58 Options outstanding December 31, 2023 3,095,604 $ 51.20 1,253,255 $ 5.17 Options exercisable December 31, 2023 (2)(3) 1,842,349 $ 48.39 (1) As at December 31, 2023, there was $ 5 expected to be recognized over a weighted average period of approximately 3 4 3 (2) As at December 31, 2023, the weighted average remaining term of vested options was 5 $ 8 5 10 (3) As at December 31, 2023, the FV of options that vested in the year was $ 2 2 |
Summary of Activity Related to Employee and Director Deferred Share Units | Employee DSU Weighted Average Grant Date FV Director DSU Weighted Average Grant Date FV Outstanding as at December 31, 2022 627,223 $ 41.55 664,258 $ 45.83 Granted including DRIP 85,740 47.66 117,893 49.99 Exercised N/A N/A (53,093) 49.39 Outstanding and exercisable as at December 31, 2023 712,963 $ 42.29 729,058 $ 46.24 |
Summary of Activity Related to Employee Performance Share Units | Employee PSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2022 690,446 $ 56.24 $ 40 Granted including DRIP 386,261 52.71 Exercised (323,155) 54.62 Forfeited (10,187) 55.15 Outstanding as at December 31, 2023 743,365 $ 55.13 $ 41 |
Summary of Activity Related to Employee Restricted Share Units | Employee RSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2022 508,468 $ 56.25 $ 30 Granted including DRIP 236,537 52.07 Exercised (171,537) 54.62 Forfeited (10,827) 54.76 Outstanding as at December 31, 2023 562,641 $ 55.01 $ 32 |
Variable Interest Entities (Tables) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Variable Interest Entities [Abstract] | |
Summary of Material Unconsolidated Variable Interest Entities | As at December 31, 2023 December 31, 2022 Maximum Maximum millions of dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 489 $ 6 $ 501 $ 6 |
Summary of Significant Accounting Policies (Narrative) (Details) |
12 Months Ended | ||||
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Dec. 31, 2023
CAD ($)
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Dec. 31, 2022
CAD ($)
|
Dec. 31, 2022
USD ($)
|
Dec. 31, 2022
CAD ($)
|
Dec. 31, 2021
CAD ($)
|
|
Asset Impairment Charges | |||||
Impairment charge | $ 0 | $ 73,000,000 | |||
Goodwill | |||||
Goodwill | 5,871,000,000 | $ 6,012,000,000 | $ 5,696,000,000 | ||
Goodwill impairment charge | $ 0 | 73,000,000 | |||
Lease, Practical Expedient, Lessor Single Lease Component [true false] | true | ||||
Long-Lived Assets | |||||
Asset Impairment Charges | |||||
Impairment charge | $ 0 | 0 | |||
Equity Method Investments | |||||
Asset Impairment Charges | |||||
Impairment charge | 0 | 0 | |||
Financial Assets | |||||
Asset Impairment Charges | |||||
Impairment charge | 0 | 0 | |||
TECO Energy | |||||
Goodwill | |||||
Goodwill | 5,868,000,000 | ||||
GBPC | |||||
Goodwill | |||||
Goodwill | |||||
Goodwill impairment charge | $ 73,000,000 | ||||
NMGC | |||||
Goodwill | |||||
Goodwill impairment charge | $ 0 |
Dispositions (Narrative) (Details) |
Mar. 31, 2022 |
---|---|
Dolmec [Member] | Disposition | |
Details of the assets and liabilities classified as held for sale [Line items] | |
Sale of ownership interest | 51.90% |
Segment Information (Geographical) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | $ 7,563 | $ 7,588 |
Property, Plant and Equipment, Net | 24,376 | 22,996 |
Canada | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 1,727 | 1,725 |
Property, Plant and Equipment, Net | 4,878 | 4,689 |
United States | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 5,310 | 5,346 |
Property, Plant and Equipment, Net | 18,588 | 17,382 |
Barbados | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 389 | 384 |
Property, Plant and Equipment, Net | 576 | 583 |
The Bahamas | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 137 | 122 |
Property, Plant and Equipment, Net | 334 | 342 |
Dominica | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | $ 0 | $ 11 |
Segment Information (Narrative) (Details) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
Segment Information [Abstract] | |
Segment Reporting, Factors Used to Identify Entity's Reportable Segments | 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. |
Revenue (Remaining Performance Obligations) (Narrative) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 488 | $ 450 |
Revenue, Remaining Performance Obligation, Expected Timing Of Satisfaction (Year) | 2043 | |
SeaCoast Gas Transmission, LLC | PGS | ||
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 134 | |
Revenue, Remaining Performance Obligation, Expected Timing Of Satisfaction (Year) | 2040 |
Investments Subject to Significant Influence and Equity Income (Summary of Investments Subject to Significant Influence - NSPML) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
Dec. 31, 2021 |
---|---|---|---|
Balance Sheets | |||
Current assets | $ 3,708 | $ 4,896 | |
Property, plant and equipment | 24,376 | 22,996 | |
Regulatory assets | 2,766 | 3,018 | |
Non-current assets | 11,396 | 11,850 | |
Total assets | 39,480 | 39,742 | |
Current liabilities | 4,544 | 7,287 | |
Non-current liabilities | 22,848 | 21,014 | |
Equity | 12,088 | 11,441 | $ 10,150 |
Total liabilities and equity | 39,480 | 39,742 | |
Variable Interest Entity, Not Primary Beneficiary | NSPML | |||
Balance Sheets | |||
Current assets | 21 | 17 | |
Property, plant and equipment | 1,473 | 1,517 | |
Regulatory assets | 272 | 265 | |
Non-current assets | 29 | 29 | |
Total assets | 1,795 | 1,828 | |
Current liabilities | 48 | 48 | |
Long-term debt | 1,109 | 1,149 | |
Non-current liabilities | 149 | 130 | |
Equity | 489 | 501 | |
Total liabilities and equity | $ 1,795 | $ 1,828 |
Other Income, Net (Components of Other Expense, Net) (Details) - CAD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 15, 2022 |
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Other Income, Net [Abstract] | |||
Interest income | $ 43 | $ 25 | |
AFUDC | 38 | 52 | |
Pension non-current service cost recovery | 35 | 24 | |
FX gains (losses) | 20 | (26) | |
TECO Guatemala Holdings award | $ 63 | 0 | 63 |
Other | 22 | 7 | |
Other income (expenses), net | $ 158 | $ 145 |
Interest Expense, Net (Components of Interest Expense, Net) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Interest Expense, Net [Abstract] | ||
Interest on debt | $ 954 | $ 727 |
Allowance for borrowed funds used during construction | (16) | (21) |
Other | (13) | 3 |
Interest expense, net | $ 925 | $ 709 |
Income Taxes (Reconciliation of Effective Income Tax Rate) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Income before provision for income taxes | $ 1,173 | $ 1,194 |
Statutory income tax rate | 29.00% | 29.00% |
Income taxes, at statutory income tax rates | $ 340 | $ 346 |
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (72) | (70) |
Tax credits | (53) | (18) |
Foreign tax rate variance | (36) | (44) |
Amortization of deferred income tax regulatory liabilities | (33) | (33) |
Tax effect of equity earnings | (15) | (10) |
GBPC impairment charge | 0 | 21 |
Other | (3) | (7) |
Income tax expense | $ 128 | $ 185 |
Effective income tax rate | 11.00% | 15.00% |
Regulatory Liabilities | $ 1,772 | $ 2,273 |
Incremental tax benefits payable to customers [Member] | ||
Regulatory Liabilities | $ 30 | $ 9 |
Income Taxes (Composition of Taxes on Income from Continuing Operations) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Deferred income taxes | $ 97 | $ 152 |
Income tax expense | 128 | 185 |
Canada | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 26 | 25 |
Deferred income taxes | 93 | 122 |
Operating loss carry forwards | (93) | (94) |
United States | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 5 | 8 |
Deferred income taxes | 128 | 252 |
Investment tax credits | (29) | (7) |
Operating loss carry forwards | $ (2) | $ (121) |
Income Taxes (Composition of Income Before Provision for Income Taxes) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Composition of taxes on income from continuing operations [Line items] | ||
Income before provision for income taxes | $ 1,173 | $ 1,194 |
Canada | ||
Composition of taxes on income from continuing operations [Line items] | ||
Income before provision for income taxes | 171 | 173 |
United States | ||
Composition of taxes on income from continuing operations [Line items] | ||
Income before provision for income taxes | 964 | 1,063 |
Other | ||
Composition of taxes on income from continuing operations [Line items] | ||
Income before provision for income taxes | $ 38 | $ (42) |
Income Taxes (Schedule of Deferred Income Tax Assets and Liabilities) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Deferred income tax assets: | ||
Tax loss carryforwards | $ 1,195 | $ 1,207 |
Tax credit carryforwards | 454 | 415 |
Derivative instruments | 205 | 45 |
Regulatory liabilities | 175 | 264 |
Other | 372 | 341 |
Total deferred income tax assets before valuation allowance | 2,401 | 2,272 |
Valuation allowance | (363) | (312) |
Total deferred income tax assets after valuation allowance | 2,038 | 1,960 |
Deferred income tax (liabilities): | ||
PP&E | (3,223) | (2,981) |
Derivative instruments | (235) | (125) |
Investments subject to significant influence | (216) | (181) |
Regulatory assets | (196) | (310) |
Other | (312) | (322) |
Total deferred income tax liabilities | (4,182) | (3,919) |
Consolidated Balance Sheets presentation: | ||
Long-term deferred income tax assets | 208 | 237 |
Long-term deferred income tax liabilities | (2,352) | (2,196) |
Net deferred income tax liabilities | $ (2,144) | $ (1,959) |
Income Taxes (Details of Change in Unrecognized Tax Benefits) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning, January 1 | $ 33 | $ 28 |
Increases due to tax positions related to current year | 5 | 5 |
Increases due to tax positions related to a prior year | 1 | 2 |
Decreases due to tax positions related to a prior year | (2) | (2) |
Balance, December 31 | $ 37 | $ 33 |
Income Taxes (Unrecognized tax benefits) (Details) - CAD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Temporary Differences/Potential change | $ 4,700,000,000 | $ 3,800,000,000 |
Net amount in dispute | 126,000,000 | 126,000,000 |
Prepaid amount in dispute | 55,000,000 | |
Deferred Tax Assets, Allowance | 363,000,000 | 312,000,000 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract] | ||
Amount that could affect effective tax rate | 37,000,000 | 33,000,000 |
Accrued interest | 9,000,000 | 7,000,000 |
Income Tax Examination, Interest Expense | 2,000,000 | $ 1,000,000 |
Accrued penalties | $ 0 |
Earnings Per Share (Computation of Basic and Diluted Earnings per Share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Numerator | ||
Net income attributable to common shareholders | $ 977.7 | $ 945.1 |
Diluted numerator | $ 977.7 | $ 945.1 |
Denominator | ||
Weighted average shares of common stock outstanding - basic | 273.6 | 265.5 |
Stock-based compensation | 0.2 | 0.4 |
Weighted average shares of common stock outstanding- diluted | 273.8 | 265.9 |
Earnings per common share | ||
Basic | $ 3.57 | $ 3.56 |
Diluted | $ 3.57 | $ 3.55 |
Inventory (Components of Inventory) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Inventory [Abstract] | ||
Fuel | $ 382 | $ 404 |
Materials | 408 | 365 |
Inventory Total | $ 790 | $ 769 |
Derivatives Instruments (Cash Flow Hedges Recorded in AOCI) (Details) - CAD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
May 26, 2021 |
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Cash Flow Hedges | |||
Realized gain in interest expense, net | $ 2 | $ 2 | |
Total gains in net income | 2 | 2 | |
Total unrealized gain in AOCI - effective portion, net of tax | 14 | $ 16 | |
Unrealized gains currently in AOCI to be reclassified into net income within the next twelve months | $ 2 | ||
Cash flow hedges | Treasury lock | |||
Cash Flow Hedges | |||
Derivative gain loss amortization period | 10 years | ||
Total unrealized gain in AOCI - effective portion, net of tax | $ 19 |
Derivatives Instruments (Realized and Unrealized Gains (Losses) on HFT Derivatives) (Details) - HFT derivatives - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | $ 1,037 | $ 64 |
Operating revenues | Power | Non-Regulated | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | (6) | 17 |
Operating revenues | Natural gas | Non-Regulated | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | $ 1,043 | $ 47 |
Derivatives Instruments (Credit Risk) (Narrative) (Details) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023
CAD ($)
Days
|
Dec. 31, 2022
CAD ($)
|
|
Credit Derivatives [Line Items] | ||
Total cash deposits/collateral on hand | $ 101 | $ 224 |
Financial Asset, Past Due [Member] | ||
Credit Derivatives [Line Items] | ||
Financial assets, considered to be past due | 142 | 131 |
Credit Concentration Risk | ||
Credit Derivatives [Line Items] | ||
Concentration Risk, maximum exposure | 1,200 | 1,900 |
Total cash deposits/collateral on hand | 310 | 386 |
Credit Concentration Risk | Receivables, net | ||
Credit Derivatives [Line Items] | ||
Fair Value, Financial assets, considered to be past due | $ 127 | $ 114 |
Average number of days financial asset outstanding | Days | 64 |
Derivatives Instruments (Cash Collateral Positions) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Derivative Instruments | ||
Cash collateral provided to others | $ 101 | $ 224 |
Cash collateral received from others | 22 | 112 |
Total fair value of these derivatives, in a liability position | $ 504 | $ 1,078 |
FV Measurements (Change in Fair Value of Level 3 Financial Liabilities) (Details) - HFT derivatives - Energy Related derivative - Non-regulated operating revenues $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2023
CAD ($)
| |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | $ 826 |
Total realized and unrealized gains included in non-regulated operating revenues | (461) |
Ending Balance | 365 |
Power | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 1 |
Total realized and unrealized gains included in non-regulated operating revenues | (1) |
Ending Balance | 0 |
Natural gas | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 825 |
Total realized and unrealized gains included in non-regulated operating revenues | (460) |
Ending Balance | $ 365 |
FV Measurements (Financial Liabilities not Measured at Fair Value on Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Fair Value Measurement [Domain] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | $ 16,621 | $ 14,670 |
Fair Value Measurement [Domain] | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 0 | 0 |
Fair Value Measurement [Domain] | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 16,363 | 14,284 |
Fair Value Measurement [Domain] | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 258 | 386 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 18,365 | 16,318 |
Financial assets and liabilities | $ 16,621 | $ 14,670 |
FV Measurements (Hybrid Notes) (Narrative) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Hybrid Instruments [Line Items] | ||
Hybrid Notes as a hedge of the foreign currency exposure | $ 1,200 | $ 1,100 |
Net investment in United States dollar denominated operations | ||
Hybrid Instruments [Line Items] | ||
Hybrid Notes as a hedge of the foreign currency exposure | 1,200 | |
After-tax foreign currency gain (loss) | $ 38 | $ (97) |
Related Paty Transactions (Narrative) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
NSPML | Regulated | ||
Related Party Transaction [Line Items] | ||
Purchases from Related Party | $ 163 | $ 157 |
M&NP | Non-Regulated | ||
Related Party Transaction [Line Items] | ||
Purchases from Related Party | $ 14 | $ 9 |
Receivables and Other Current Assets (Summary of Receivables and Other Current Assets) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Receivables and Other Current Assets [Abstract] | ||
Customer accounts receivable - billed | $ 805 | $ 1,096 |
Capitalized transportation capacity | 358 | 781 |
Customer accounts receivable - unbilled | 363 | 424 |
Prepaid expenses | 105 | 82 |
Income taxes receivable | 10 | 9 |
Allowance for credit losses | (15) | (17) |
NMGC gas hedge settlement receivable | 162 | |
Other | 191 | 360 |
Total receivables and other current assets | $ 1,817 | $ 2,897 |
Leases (Narrative) (Details) $ in Millions, $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2023
CAD ($)
|
Dec. 31, 2022
CAD ($)
|
Oct. 31, 2023
USD ($)
|
|
Lessee, Operating Leases | |||
Lessee, Operating Lease, Description | The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain they will be exercised. | ||
Lease, Expense | $ 127 | $ 138 | |
Variable costs for power generation facility finance leases | $ 119 | 131 | |
Lessee, Operating Lease, Existence of Option to Extend [true false] | true | ||
Lessee, Operating Lease, Option to Extend | The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain they will be exercised | ||
Lessee, Lease, Description [Line Items] | |||
Net Investment in Lease | $ 658 | $ 638 | |
Renewable Natural Gas Facility [Member] | |||
Lessee, Lease, Description [Line Items] | |||
Lessor, sales-type lease, term of contract | 15 years | ||
Lessor Sales Type Lease Assumptions And Judgments Value Of Underlying Asset Amount | $ 35 | ||
Brunswick Pipeline Lease [Member] | |||
Lessee, Lease, Description [Line Items] | |||
Lessor, operating lease, term of contract | 34 years | ||
Net Investment in Lease | $ 100 | ||
Lessor lease option to extend | 16 years | ||
Minimum | |||
Lessee, Lease, Description [Line Items] | |||
Lessee, operating lease, renewal term | 1 year | ||
Maximum | |||
Lessee, Lease, Description [Line Items] | |||
Lessee, operating lease, renewal term | 62 years |
Leases (Lessee, Operating Leases and Additional Information) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Assets and Liabilities, Lessee | ||
Right-of-use asset | $ 54 | $ 58 |
Lease liabilities, Current | 3 | 3 |
Lease liabilities, Long-term | 55 | 59 |
Total lease liabilities | 58 | 62 |
Cash paid for amounts included in the measurement of lease liabilities: | ||
Operating cash flows for operating leases | 8 | 8 |
Right-of-use assets obtained in exchange for lease obligations: Operating leases | $ 1 | $ 1 |
Weighted average remaining lease term (years) | 44 years | 44 years |
Weighted average discount rate - operating leases | 3.93% | 3.98% |
Leases (Lessee, Future Minimum Lease Payments Under Non-Cancellable Operating Leases) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter | ||
2024 | $ 6 | |
2025 | 5 | |
2026 | 3 | |
2027 | 3 | |
2028 | 3 | |
Thereafter | 111 | |
Minimum lease payments, Total | 131 | |
Less imputed interest | (73) | |
Total | $ 58 | $ 62 |
Leases (Lessor, Direct Finance and Sales-Type Leases) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Net investment in direct finance and sales-type leases | ||
Total minimum lease payments to be received | $ 1,360 | $ 1,393 |
Less: amounts representing estimated executory costs | (190) | (205) |
Minimum lease payments receivable | 1,170 | 1,188 |
Estimated residual value of leased property (unguaranteed) | 183 | 183 |
Less: Credit loss reserve | (2) | 0 |
Less: unearned finance lease income | (693) | (733) |
Net investment in direct finance and sales-type leases | 658 | 638 |
Principal due within one year (included in "Receivables and other current assets") | 37 | 34 |
Net Investment in direct finance leases - long-term | $ 621 | $ 604 |
Leases (Lessor, Future Minimum Lease Payments to be Received) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Leases [Abstract] | ||
2024 | $ 97 | |
2025 | 99 | |
2026 | 98 | |
2027 | 97 | |
2028 | 96 | |
Thereafter | 873 | |
Total minimum lease payments to be received | 1,360 | $ 1,393 |
Less: executory costs | (190) | (205) |
Minimum lease payments receivable | $ 1,170 | $ 1,188 |
Property, Plant and Equipment (Regulated and Non-Regulated Assets) (Narrative) (Details) - Pipeline lateral - SeaCoast Gas Transmission, LLC - General plant and other $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023
USD ($)
mi
|
Dec. 31, 2022
USD ($)
|
|
Jointly Owned Pipleline lateral | ||
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% | 50.00% |
Length of pipeline, in miles | mi | 26 | |
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | $ 27 | $ 27 |
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | $ 2 | $ 1 |
Employee Benefit Plans (Plans with PBO/APBO in Excess of Plan Assets) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Defined benefit pension plans | ||
Plans with PBO/APBO in Excess of Plan Assets | ||
PBO/APBO | $ 120 | $ 1,006 |
FV of plan assets | 37 | 914 |
Funded Status | (83) | (92) |
Non-pension Benefit Plans | ||
Plans with PBO/APBO in Excess of Plan Assets | ||
PBO/APBO | 205 | 221 |
FV of plan assets | 0 | 0 |
Funded Status | $ (205) | $ (221) |
Employee Benefit Plans (Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | ||
ABO for the defined benefit pension plans | $ 2,172 | $ 2,080 |
Defined benefit pension plans | ||
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | ||
ABO | 114 | 111 |
Fair value of plan assets | 37 | 33 |
Funded Status | $ (77) | $ (78) |
Employee Benefit Plans (Amounts Recognized in Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Balance Sheet | ||
Other current liabilities | $ (23) | $ (33) |
Long-term liabilities | (265) | (281) |
Defined benefit pension plans | ||
Balance Sheet | ||
Other current liabilities | (5) | (13) |
Long-term liabilities | (78) | (80) |
Other long-term assets | 108 | 98 |
AOCI, net of tax and regulatory assets | 385 | 358 |
Less: Deferred income tax (expense) recovery in AOCI | (8) | (7) |
Net amount recognized | 402 | 356 |
Non-pension Benefit Plans | ||
Balance Sheet | ||
Other current liabilities | (18) | (20) |
Long-term liabilities | (187) | (201) |
Other long-term assets | 26 | 24 |
AOCI, net of tax and regulatory assets | 20 | 22 |
Less: Deferred income tax (expense) recovery in AOCI | (1) | (1) |
Net amount recognized | $ (160) | $ (176) |
Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Defined Benefit Plan Disclosure [Line Items] | ||
Expected return on plan assets | $ (2,577) | $ (2,482) |
Defined benefit pension plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 30 | 41 |
Interest cost | 111 | 80 |
Expected return on plan assets | (161) | (144) |
Current year amortization of: Actuarial losses | 1 | 8 |
Regulatory assets (liability) | 6 | 21 |
Settlement, curtailments | 2 | 2 |
Net Periodic Benefit Cost, Total | (11) | 8 |
Non-pension Benefit Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 3 | 4 |
Interest cost | 13 | 9 |
Expected return on plan assets | (2) | 0 |
Current year amortization of: Actuarial losses | (3) | 0 |
Regulatory assets (liability) | (2) | 2 |
Settlement, curtailments | 0 | 0 |
Net Periodic Benefit Cost, Total | $ 9 | $ 15 |
Employee Benefit Plans (Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Benefit Plans) (Details) $ in Millions |
Dec. 31, 2023
CAD ($)
|
---|---|
Defined benefit pension plans | |
Expected employer contributions | |
Expected employer contributions, 2024 | $ 34 |
Expected benefit payments | |
Expected benefit payments, 2024 | 172 |
Expected benefit payments, 2025 | 163 |
Expected benefit payments, 2026 | 166 |
Expected benefit payments, 2027 | 171 |
Expected benefit payments, 2028 | 173 |
Expected benefit payments, 2029 - 2033 | 890 |
Non-pension Benefit Plans | |
Expected employer contributions | |
Expected employer contributions, 2024 | 19 |
Expected benefit payments | |
Expected benefit payments, 2024 | 21 |
Expected benefit payments, 2025 | 21 |
Expected benefit payments, 2026 | 21 |
Expected benefit payments, 2027 | 21 |
Expected benefit payments, 2028 | 20 |
Expected benefit payments, 2029 - 2033 | $ 95 |
Employee Benefit Plans (Narrative) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Description | 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. | |
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description | The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period. | |
Defined Benefit Plan, Plan Assets, Expected Long-term Rate-of-Return, Description | The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. | |
Defined Benefit Plan, Expected Return on Plan Assets | $ 2,577 | $ 2,482 |
Contribution Amount | $ 45 | 41 |
Plan assets recognition period | 5 years | |
Defined benefit pension plans | ||
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Expected Return on Plan Assets | $ 161 | 144 |
Non-pension Benefit Plans | ||
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Expected Return on Plan Assets | $ 2 | $ 0 |
Goodwill (Change in Goodwill) (Details) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2023
USD ($)
|
Dec. 31, 2023
CAD ($)
|
Dec. 31, 2022
CAD ($)
|
|
Goodwill [Roll Forward] | |||
Balance, January 1 | $ 6,012,000,000 | $ 5,696,000,000 | |
Change in FX rate | (141,000,000) | 389,000,000 | |
GBPC impairment charge | 0 | (73,000,000) | |
Balance, December 31 | 5,871,000,000 | 6,012,000,000 | |
Tampa Electric and PGS | |||
Goodwill [Roll Forward] | |||
GBPC impairment charge | $ 0 | ||
NMGC | |||
Goodwill [Roll Forward] | |||
GBPC impairment charge | $ 0 | ||
GBPC | |||
Goodwill [Roll Forward] | |||
Balance, January 1 | |||
GBPC impairment charge | $ (73,000,000) | ||
Balance, December 31 |
Other Current Liabilities (Components of Other Current Liabilities) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Other Current Liabilities | ||
Accrued charges | $ 172 | $ 174 |
Nova Scotia Cap-and-Trade Program provision | 0 | 172 |
Accrued interest on long-term debt | 107 | 97 |
Pension and post-retirement liabilities | 23 | 33 |
Sales and other taxes payable | 11 | 14 |
Income taxes payable | 2 | 9 |
Other | 112 | 80 |
Other current liabilities, Total | $ 427 | $ 579 |
Long-Term Debt (Significant Covenants) (Details) |
Dec. 31, 2023 |
---|---|
Maximum | |
Debt Instrument [Line Items] | |
Debt to capital ratio | 0.70 |
Syndicated credit facilities | |
Debt Instrument [Line Items] | |
Debt to capital ratio | 0.57 |
Asset Retirement Obligation (Change in Asset Retirement Obligations) (Details) - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Change in ARO | ||
Balance, January 1 | $ 174 | $ 174 |
Accretion included in depreciation expense | 9 | 9 |
Change in FX rate | (1) | 3 |
Additions | 0 | 1 |
Accretion deferred to regulatory asset (included in PP&E) | 18 | 1 |
Liabilities settled | (8) | (1) |
Revisions in estimated cash flows | 0 | (13) |
Balance, December 31 | $ 192 | $ 174 |
Commitments and Contingencies (Legal Proceedings) (Narrative) (Details) - Dec. 31, 2023 $ in Millions, $ in Millions |
CAD ($) |
USD ($) |
---|---|---|
Prime Rate [Member] | Tampa Electric | ||
Loss Contingencies [Line Items] | ||
Loss Contingency, Estimate of Possible Loss | $ 15 | $ 11 |
Commitments and Contingencies (Guarantees and Letters of Credit) (Narrative) (Details) $ in Millions, $ in Millions |
Dec. 31, 2023
USD ($)
|
Dec. 31, 2023
CAD ($)
|
Dec. 31, 2022
USD ($)
|
Dec. 31, 2022
CAD ($)
|
---|---|---|---|---|
Nova Scotia Power Inc. [Member] | ||||
Guarantor Obligations [Line Items] | ||||
Guaranty Liabilities | $ 104 | $ 119 | ||
Letters of Credit Outstanding, Amount | $ 56 | $ 63 | ||
TECO Energy | ||||
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | 13 | |||
Guarantor Obligations, Maximum Exposure, Undiscounted | 13 | |||
TECO Energy | SeaCoast Gas Transmission, LLC | ||||
Guarantor Obligations [Line Items] | ||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 45 | |||
ECI | ||||
Guarantor Obligations [Line Items] | ||||
Guaranty Liabilities | 66 | |||
Payment Guarantee | SeaCoast Gas Transmission, LLC | ||||
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | 27 | |||
Surety Bonds | ||||
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | $ 103 | $ 145 |
Commitments and Contingencies (Collaborative Arrangements) (Narrative) (Details) - Jointly Owned Electricity Generation Plant - NSPI - CAD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items] | ||
Regulated fuel for generation and purchased power | $ 8 | $ 12 |
Operating, maintenance and general (OM&G) | $ 3 | $ 3 |
Cumulative Preferred Stock (Narrative) (Details) |
12 Months Ended |
---|---|
Dec. 31, 2023 | |
First Preferred Shares | |
Class of Stock [Line Items] | |
Preferred Stock Dividend Preference Or Restrictions | First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting. |
Non-Controlling Interest in Subsidiaries (Components of Non-Controlling Interest) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Noncontrolling Interest [Line Items] | ||
Stockholders' Equity Attributable to Noncontrolling Interest | $ 14 | $ 14 |
GBPC | ||
Noncontrolling Interest [Line Items] | ||
Noncontrolling Interest, Amount Represented by Preferred Stock | $ 14 | $ 14 |
Non-Controlling Interest in Subsidiaries (Preferred Shares of GBPC) (Details) - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Noncontrolling Interest [Line Items] | ||
Number of shares issued and outstanding | 58,000,000 | 58,000,000 |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | GBPC | ||
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Shares Authorized | 10,000 | |
Number of shares issued and outstanding | 10,000 | 10,000 |
Outstanding as at December 31 | $ 14 | $ 14 |
Non-Controlling Interest in Subsidiaries (Narrative) (Details) - GBPC |
12 Months Ended |
---|---|
Dec. 31, 2023
$ / shares
| |
Noncontrolling Interest [Line Items] | |
Preferred Stock, Dividend Payment Terms | 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually |
Preferred Stock, Redemption Terms | The preferred shares are redeemable by GBPC after June 17, 2021 |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | |
Noncontrolling Interest [Line Items] | |
Preferred Stock, Redemption Price Per Share | $ 1,000 |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | USD preferred shares | |
Noncontrolling Interest [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 6.00% |
Stock-Based Compensation (Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan) (Narrative) (Details) shares in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2023
CAD ($)
shares
|
Dec. 31, 2023
USD ($)
shares
|
Dec. 31, 2022
CAD ($)
|
|
Employee Common Share Purchase Plan | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Employee Common Share Purchase Plan, Description | Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows reinvestment of dividends for all participants except where prohibited by law. | Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows reinvestment of dividends for all participants except where prohibited by law. | |
Defined Contribution Plan, Minimum Annual Contributions Per Employee, Amount | $ 25 | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount | $ 20,000 | $ 15,000 | |
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 20.00% | 20.00% | |
Compensation cost for shares issued | $ 3,000,000 | $ 3,000,000 | |
Dividend Reinvestment Plan | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Employee Common Share Purchase Plan, Description | The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023. | The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023. | |
Maximum aggregate number of common shares reserved for issuance | shares | 7 | 7 | |
Discount from Market Price, Purchase Date | 2.00% | ||
Dividend Reinvestment Plan | Maximum | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Discount from Market Price, Purchase Date | 5.00% | 5.00% |
Stock-Based Compensation (Narrative) (Details) $ / shares in Units, $ in Thousands, shares in Millions, $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2023
CAD ($)
$ / shares
shares
|
Dec. 31, 2022
CAD ($)
$ / shares
shares
|
Dec. 31, 2022
USD ($)
|
Dec. 31, 2021 |
|
Stock option plan, Additional information | ||||
Percentage of outstanding stock maximum | 10.00% | |||
Dividend Reinvestment Plan | ||||
Stock option plan, Additional information | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 7.0 | |||
Share Unit Plans | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 7.0 | |||
DSU Plan | ||||
Share Unit Plans | ||||
Cash payments made during the year | $ 3,000 | $ 8,000 | ||
Employee Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Maximum term | 10 years | |||
Maximum aggregate number of common shares reserved for issuance | shares | 6.0 | 6.0 | ||
Terms of award | P10Y | |||
Share Unit Plans | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 6.0 | 6.0 | ||
Share Unit Plans | ||||
Stock option plan, Additional information | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 2.0 | 2.7 | ||
Share Unit Plans | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 2.0 | 2.7 | ||
First Anniversary | DSU Plan | Executive and senior management | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25.00% | |||
First Anniversary | DSU Plan | Executive and senior management | Minimum | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 50.00% | |||
Vesting period after date of retirement | Employee Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Vesting period | 27 months | |||
Vesting period after termination without just cause or death | Employee Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Vesting period | 6 months | 6 months | 6 months | |
Vesting period after termination for just cause or resignation | Employee Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Vesting period | 60 days | 60 days | 60 days | |
Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Share-based payment award, description | The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock Exchange on the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with this requirement. Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. | |||
Maximum aggregate number of common shares reserved for issuance | shares | 14.7 | |||
Vesting rights | The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. | |||
Percentage of outstanding stock maximum | 5.00% | |||
Policy for issuing shares upon exercise | The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. | |||
Cash received for options exercised | $ 6,000 | $ 9,000 | ||
Total intrinsic value of options exercised | $ 2,000 | $ 4,000 | ||
Exercise price range, lower range limit | $ / shares | $ 32.35 | $ 32.35 | ||
Exercise price range, upper range limit | $ / shares | $ 60.03 | $ 60.03 | ||
Fair value assumptions, method used | The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. | |||
Share Unit Plans | ||||
Compensation cost recognized for employee and director | $ 2,000 | $ 2,000 | ||
Maximum aggregate number of common shares reserved for issuance | shares | 14.7 | |||
Stock Option Plan, Granted 2021 | First Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25.00% | |||
Stock Option Plan, Granted 2021 | Second Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25.00% | |||
Stock Option Plan, Granted 2021 | Third Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25.00% | |||
Stock Option Plan, Granted 2021 | Fourth Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25.00% | |||
Stock Option Plan, Granted 2022 | First Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20.00% | 20.00% | ||
Stock Option Plan, Granted 2022 | Second Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20.00% | 20.00% | ||
Stock Option Plan, Granted 2022 | Third Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20.00% | 20.00% | ||
Stock Option Plan, Granted 2022 | Fourth Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20.00% | 20.00% | ||
Stock Option Plan, Granted 2022 | Fifth Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20.00% | 20.00% | ||
Share Unit Plans | Share Unit Plans | ||||
Stock option plan, Additional information | ||||
Share-based payment award, description | The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. | |||
Deferred Share Unit Plans | ||||
Share Unit Plans | ||||
Compensation cost recognized for employee and director | $ 2,000 | $ 6,000 | ||
Tax expense related to compensation costs for share units realized | 1,000 | 2,000 | ||
Deferred Share Unit Plans | Employee | ||||
Share Unit Plans | ||||
Share Unit Plans: Aggregate intrinsic value | 36,000 | 33,000 | ||
Deferred Share Unit Plans | Director | ||||
Share Unit Plans | ||||
Share Unit Plans: Aggregate intrinsic value | $ 37,000 | 34,000 | ||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | ||||
Share Unit Plans | ||||
Deferred share unit plan, description | When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash. In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee (“MRCC”), to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives. | |||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Executive and senior management | ||||
Share Unit Plans | ||||
Deferred share unit plan, description | Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met. | |||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Director | ||||
Share Unit Plans | ||||
Deferred share unit plan, description | Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are redeemed. | |||
Performance Share Unit Plan | ||||
Stock option plan, Additional information | ||||
Award service period | 3 years | |||
Share Unit Plans | ||||
Tax expense related to compensation costs for share units realized | $ 3,000 | 5,000 | ||
Cash payments made during the year | 19,000 | 24,000 | ||
Performance Share Unit Plan | Employee | ||||
Share Unit Plans | ||||
Share Unit Plans: Aggregate intrinsic value | $ 41,000 | 40,000 | ||
Performance Share Unit Plan | Share Unit Plans | ||||
Stock option plan, Additional information | ||||
Share-based payment award, description | Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement. | |||
Compensation cost recognized for stock options | $ 11,000 | 18,000 | ||
Restricted Share Unit Plan | ||||
Stock option plan, Additional information | ||||
Award service period | 3 years | |||
Share Unit Plans | ||||
Tax expense related to compensation costs for share units realized | $ 3,000 | $ 2 | ||
Share Unit Plans: Aggregate intrinsic value | 32,000 | |||
Cash payments made during the year | $ 10,000 | |||
Restricted Share Unit Plan | Employee | ||||
Share Unit Plans | ||||
Share Unit Plans: Aggregate intrinsic value | 30,000 | |||
Restricted Share Unit Plan | Share Unit Plans | ||||
Stock option plan, Additional information | ||||
Share-based payment award, description | Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement. | |||
Compensation cost recognized for stock options | $ 10,000 | $ 9,000 |
Stock-Based Compensation (Weighted Average Fair Values per Stock Option and Assumptions for Options Granted) (Details) - $ / shares |
12 Months Ended | |
---|---|---|
Dec. 31, 2023 |
Dec. 31, 2022 |
|
Stock-Based Compensation [Abstract] | ||
Weighted average FV per option | $ 6.32 | $ 5.35 |
Expected term | 5 years | 5 years |
Risk-free interest rate | 3.53% | 1.79% |
Expected dividend yield | 5.05% | 4.55% |
Expected volatility | 20.07% | 18.87% |
Variable Interest Entities (Summary of Material Unconsolidated Variable Interest Entities) (Details) - NSPML - NSPML - CAD ($) $ in Millions |
Dec. 31, 2023 |
Dec. 31, 2022 |
---|---|---|
Variable Interest Entity [Line Items] | ||
Equity Method Investment, Underlying Equity in Net Assets | $ 489 | $ 501 |
Maximum exposure to loss | $ 6 | $ 6 |
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