Emera Inc 6-K, filed Nov 12, 2024
Emera Inc (EMA)
About this 6-K
Emera Inc filed this 6-K on November 12, 2024.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16
UNDER THE SECURITIES EXCHANGE ACT OF 1934
For the month of November, 2024
Commission File Number: 000-54516
Emera Incorporated
(Exact name of registrant as specified in its charter)
5151 Terminal Road
Halifax NS B3J 1A1
Canada
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☑
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| EMERA INCORPORATED | ||||||
| Date: November 11, 2024 | By: | \s\ Brian Curry | ||||
| Name: Brian Curry | ||||||
|
Title: Corporate Secretary | ||||||
EXHIBIT INDEX
Exhibit 99.1
Management’s Discussion & Analysis
As at November 8, 2024
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the “Company”) during the third quarter of, and year-to-date 2024 relative to the same periods in 2023; and its financial position as at September 30, 2024 relative to December 31, 2023. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.
This MD&A should be read in conjunction with the Emera unaudited condensed consolidated interim financial statements and supporting notes as at and for the three and nine months ended September 30, 2024; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2023. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR+ at www.sedarplus.ca.
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At September 30, 2024, Emera’s rate-regulated subsidiaries and investments include:
| Emera Rate-Regulated Subsidiary or Equity Investment | Accounting Policies Approved/Examined By | |
| Subsidiary | ||
| Tampa Electric Company (“TEC”) | Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”) | |
| Nova Scotia Power Inc. (“NSPI”) | Nova Scotia Utility and Review Board (“UARB”) | |
| Peoples Gas System, Inc. (“PGS”) | FPSC | |
| New Mexico Gas Company, Inc. (“NMGC”) | New Mexico Public Regulation Commission (“NMPRC”) | |
| SeaCoast Gas Transmission, LLC (“SeaCoast”) | FPSC | |
| Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) | Canadian Energy Regulator (“CER”) | |
| Barbados Light & Power Company Limited (“BLPC”) | Fair Trading Commission, Barbados (“FTC”) | |
| Grand Bahama Power Company Limited (“GBPC”) | The Grand Bahama Port Authority (“GBPA”) | |
| Equity Investments | ||
| NSP Maritime Link Inc. (“NSPML”) | UARB | |
| Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”) | CER and FERC | |
| St. Lucia Electricity Services Limited (“Lucelec”) | National Utility Regulatory Commission |
On June 4, 2024, Emera completed the sale of its indirect minority equity interest in the Labrador Island Link Partnership (“LIL”). For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States dollars (“USD”) unless otherwise stated.
1
TABLE OF CONTENTS
| Forward-looking Information |
2 | |||
| Introduction and Strategic Overview |
3 | |||
| Non-GAAP Financial Measures and Ratios |
4 | |||
| Consolidated Financial Review |
7 | |||
| Significant Items Affecting Earnings |
7 | |||
| Consolidated Financial Highlights |
7 | |||
| Consolidated Income Statement Highlights |
9 | |||
| Business Overview and Outlook |
12 | |||
| Florida Electric Utility |
12 | |||
| Canadian Electric Utilities |
13 | |||
| Gas Utilities and Infrastructure |
15 | |||
| Other Electric Utilities |
15 | |||
| Other |
16 | |||
| Consolidated Balance Sheet Highlights |
17 | |||
| Other Developments |
18 | |||
| Financial Highlights |
20 | |||
| Florida Electric Utility |
20 | |||
| Canadian Electric Utilities |
21 |
| Gas Utilities and Infrastructure |
22 | |||
| Other Electric Utilities |
23 | |||
| Other |
24 | |||
| Liquidity and Capital Resources |
26 | |||
| Consolidated Cash Flow Highlights |
27 | |||
| Contractual Obligations |
28 | |||
| Debt Management |
29 | |||
| Guarantees and Letters of Credit |
30 | |||
| Outstanding Stock Data |
31 | |||
| Transactions with Related Parties |
31 | |||
| Risk Management including Financial Instruments |
32 | |||
| Disclosure and Internal Controls |
33 | |||
| Critical Accounting Estimates |
33 | |||
| Changes in Accounting Policies and Practices |
33 | |||
| Future Accounting Pronouncements |
33 | |||
| Summary of Quarterly Results |
35 |
FORWARD-LOOKING INFORMATION
This MD&A contains “forward-looking information” (“FLI”) and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, the expected timing and outcome of the pending sale of NMGC, carbon dioxide emissions reduction goals, business prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify FLI, although not all FLI contains these identifying words. The FLI reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.
FLI is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the FLI. Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; changes in credit ratings; future dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology (“IT”) infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats; market energy sales prices; labour relations; and availability of labour and management resources.
2
Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any FLI as a result of new information, future events or otherwise.
INTRODUCTION AND STRATEGIC OVERVIEW
Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in the United States (“US”), Canada and the Caribbean. Cost-of-service utilities provide essential electric and gas services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its customers.
The majority of Emera’s investments in rate-regulated businesses are located in Florida with other investments in Nova Scotia, New Mexico and the Caribbean. Emera’s portfolio of regulated utilities intends to provide reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.
Emera’s capital investment plan is forecasted to be 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 includes significant investments across the portfolio in renewable and cleaner generation, reliability and system integrity investments, infrastructure modernization and expansion to meet the needs of new and existing customers, and technologies to better support the business and customer experiences. It is anticipated that approximately 75 per cent of this capital investment will be made within Emera’s two utility operations in Florida. The pace of capital investment is expected to continue beyond 2026, resulting in an anticipated compound annual rate base growth of approximately seven per cent to eight per cent through 2029.
Emera’s capital investment plan is being funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity, and select asset sales. Generally, equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan (“DRIP”) and at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a priority of the Company.
Emera has provided an average compound annual adjusted EPS growth rate guidance of five to seven per cent through 2027, which will primarily be supported by the capital investment plan and related rate base growth.
Emera has provided annual dividend growth guidance of one to two per cent. 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 in the near term, it is expected to return to that range over time. For further information on the non-GAAP ratios “Adjusted EPS” and “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.
Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market (“MTM”) adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income and cash flows are impacted by movements in the USD relative to the CAD. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.
3
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 the energy provided by Emera’s utility operations 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 and driving a requirement for increased investments to replace aging infrastructure and harden systems to ensure system resiliency and reliability. These factors combined with inflation, higher interest rates and higher cost of capital, increase energy costs and thus customer rates, at a time when affordability is a challenge.
Emera’s strategy is centered on investing in its operating utilities to deliver value to their customers and in so doing grow earnings and cash flow for shareholders.
Building on the meaningful progress in reducing carbon emissions across its operations, Emera is continuing its efforts to reduce the emission profile of the energy delivered to customers and to meet government carbon reduction requirements.
Subject to the Company’s regulatory obligations and other external factors, Emera is working to achieve the following goals compared to corresponding 2005 levels:
| • | A 55 per cent reduction in carbon dioxide emissions by 2025. |
| • | The retirement of Emera’s last existing coal unit no later than 2040. |
| • | An 80 per cent reduction in carbon dioxide emissions by 2040. |
Emera seeks to deliver on these goals while maintaining its focus on investing in reliability and staying focused on 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.
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and are calculated by adjusting certain GAAP measures for specific items. They may not be comparable to similar measures presented by other entities. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. These measures and ratios are discussed and reconciled below.
Adjusted Net Income Attributable to Common Shareholders, Adjusted EPS – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the effect of MTM adjustments, charges related to the pending sale of NMGC, and the gain on sale, after tax and transaction costs, of Emera’s indirect minority equity interest in the LIL (“LIL equity interest”). For details of these adjustments, see below.
Emera calculates adjusted net income for the Gas Utilities and Infrastructure, Other Electric Utilities and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial Highlights – Gas Utilities and Infrastructure”, “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in Emera’s 2023 annual MD&A.
4
MTM Adjustments:
Management believes excluding from net income the effect of MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows. Management therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:
| • | held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions; |
| • | the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income; |
| • | equity securities held in BLPC and Emera Energy; and |
| • | FX hedges entered into to hedge USD denominated operating unit earnings exposure. |
For further detail on these MTM adjustments, refer to the “Consolidated Financial Review”, “Financial Highlights – Other Electric Utilities”, and “Financial Highlights – Other” sections.
Charges Related to the Pending Sale of NMGC:
On August 5, 2024, Emera entered into an agreement to sell NMGC. In Q3 2024, the Company recognized $206 million in non-cash goodwill and other impairment charges, after-tax and an additional loss of $19 million in estimated transaction costs, after-tax related to the pending sale. Management believes excluding these amounts from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. For further details on the pending sale of NMGC, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
Gain on Sale of LIL Equity Interest:
In Q2 2024, Emera recognized a $107 million gain, after tax and transaction costs, on the sale of its LIL equity interest. Management believes excluding the gain on sale, after tax and transaction costs from net income, better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. For further details related to the sale of Emera’s LIL equity interest, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
Reconciliation of Net Income Attributable to Common Shareholders to Adjusted Net Income
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of dollars (except per share amounts) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Net income attributable to common shareholders |
$ | 4 | $ | 101 | $ | 340 | $ | 689 | ||||||||
| Charges related to the pending sale of NMGC, after-tax (1)(2) |
(225) | - | (225) | - | ||||||||||||
| Gain on sale of LIL, after tax and transaction costs (3) |
- | - | 107 | - | ||||||||||||
| MTM (loss) gain, after-tax (4) |
(7) | (103) | (145) | 55 | ||||||||||||
| Adjusted net income |
$ | 236 | $ | 204 | $ | 603 | $ | 634 | ||||||||
| EPS – basic |
$ | 0.01 | $ | 0.37 | $ | 1.18 | $ | 2.53 | ||||||||
| Adjusted EPS – basic |
$ | 0.81 | $ | 0.75 | $ | 2.10 | $ | 2.33 | ||||||||
| (1) Represents (i) $206 million in non-cash goodwill and other impairment charges, after-tax and (ii) $19 million in transaction costs, after-tax for the three and nine months ended September 30, 2024 (2023 – nil). |
| |||||||||||||||
| (2) Net of income tax recovery of $20 million for the three and nine months ended September 30, 2024 (2023 – nil). |
| |||||||||||||||
| (3) Net of income tax expense of $75 million for the nine months ended September 30, 2024 (2023 – nil). |
| |||||||||||||||
| (4) Net of income tax recovery of $4 million for the three months ended September 30, 2024 (2023 – $40 million recovery) and $60 million income tax recovery for the nine months ended September 30, 2024 (2023 – $24 million expense). |
| |||||||||||||||
5
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA are non-GAAP financial measures used by Emera. These financial measures are used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital, and finance working capital requirements.
Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA excluding the income effect of MTM adjustments, charges related to the pending sale of NMGC, and the gain on sale of LIL, after transaction costs.
Reconciliation of Net Income to EBITDA and Adjusted EBITDA
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Net income (1) |
$ | 23 | $ | 118 | $ | 395 | $ | 738 | ||||||||
| Interest expense, net |
241 | 235 | 725 | 684 | ||||||||||||
| Income tax (recovery) expense |
(9) | (34) | 40 | 77 | ||||||||||||
| Depreciation and amortization |
293 | 266 | 866 | 785 | ||||||||||||
| EBITDA |
$ | 548 | $ | 585 | $ | 2,026 | $ | 2,284 | ||||||||
| Charges related to the pending sale of NMGC, excluding income tax |
(245) | - | (245) | - | ||||||||||||
| Gain on sale of LIL, after transaction costs, excluding income tax |
- | - | 182 | - | ||||||||||||
| MTM (loss) gain, excluding income tax |
(11) | (143) | (205) | 79 | ||||||||||||
| Adjusted EBITDA |
$ | 804 | $ | 728 | $ | 2,294 | $ | 2,205 | ||||||||
| (1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends. |
| |||||||||||||||
6
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Earnings
Charges Related to the Pending Sale of NMGC
In Q3 2024, Emera recognized non-cash goodwill and other impairment charges of $221 million ($206 after-tax, or $0.72 per common share) related to the NMGC reporting unit. These charges were recorded in “Impairment charges” on the Condensed Consolidated Statements of Income and included in the Other and Gas Utilities and Infrastructure segments, respectively. For further details on the pending sale of NMGC, refer to the “Other Developments” section. For further details on the non-cash goodwill impairment charge, refer to note 19 in the condensed consolidated interim financial statements.
Additionally, as of September 30, 2024, Emera recorded a loss of $24 million ($19 million after-tax, or $0.06 per common share) in estimated transaction costs related to the pending sale of NMGC. These transaction costs were recorded in “Other Income, net” on the Condensed Consolidated Statement of Income and included in the Other segment. For further details, refer to the “Other Developments” section.
Gain on Sale of LIL Equity Interest
On June 4, 2024, Emera completed the sale of its LIL equity interest. A gain on sale of $182 million after transaction costs ($107 million, after tax and transaction costs, or $0.37 per common share), was recognized in “Other Income, net” on the Condensed Consolidated Statements of Income and included in the Other segment. For further details on the transaction, refer to the “Other Developments” section.
Earnings Impact of MTM (Loss) Gain, After-Tax
MTM loss, after-tax, decreased $96 million to $7 million in Q3 2024, compared to $103 million in Q3 2023, primarily due to lower amortization of gas transportation assets at Emera Energy Services (“EES”) and a gain on Corporate FX hedges compared to a loss in the prior year. Year-to-date, the 2023 MTM gain, after-tax, of $55 million, decreased $200 million to a $145 million MTM loss, after-tax for the same period in 2024, primarily due to changes in existing positions at EES.
Consolidated Financial Highlights
| For the millions of dollars |
Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| Adjusted Net Income | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Florida Electric Utility |
$ | 252 | $ | 228 | $ | 524 | $ | 512 | ||||||||
| Canadian Electric Utilities |
26 | 38 | 155 | 179 | ||||||||||||
| Gas Utilities and Infrastructure |
38 | 23 | 180 | 155 | ||||||||||||
| Other Electric Utilities |
10 | 17 | 27 | 31 | ||||||||||||
| Other |
(90) | (102) | (283) | (243) | ||||||||||||
| Adjusted net income |
$ | 236 | $ | 204 | $ | 603 | $ | 634 | ||||||||
| Charges related to the pending sale of NMGC, after-tax |
(225) | - | (225) | - | ||||||||||||
| Gain on sale of LIL, after tax and transaction costs |
- | - | 107 | - | ||||||||||||
| MTM (loss) gain, after-tax |
(7) | (103) | (145) | 55 | ||||||||||||
| Net income attributable to common shareholders |
$ | 4 | $ | 101 | $ | 340 | $ | 689 | ||||||||
7
The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2023 to 2024:
| For the | Three months ended | Nine months ended | ||||||
| millions of dollars | September 30 | September 30 | ||||||
| Adjusted net income – 2023 |
$ | 204 | $ | 634 | ||||
| Operating Unit Performance |
||||||||
| Increased earnings at TEC due to higher revenues as a result of customer growth and new base rates, lower income tax expense and the impact of a weaker CAD, partially offset by unfavourable weather and higher depreciation. Year-over-year earnings was also partially offset by higher operating, maintenance and general expenses (“OM&G”) due to higher generation and transmission and distribution (“T&D”) costs | 24 | 12 | ||||||
| Increased earnings at PGS due to higher revenue from new base rates and customer growth, partially offset by increased depreciation, OM&G, interest expense and income tax expense | 15 | 47 | ||||||
| Increased earnings quarter-over-quarter at NSPI due to lower OM&G. Decreased earnings year-over-year due to higher OM&G due to increased reliability initiatives, partially offset by higher revenue from increased residential sales volumes | 4 | (12) | ||||||
| Decreased earnings year-over-year at NMGC due to lower asset optimization revenues and increased OM&G, partially offset by lower income tax expense | 1 | (18) | ||||||
| Decreased income from equity investments due to the sale of LIL equity interest |
(15) | (16) | ||||||
| Decreased earnings at Emera Energy due to the recognition of investment tax credits in 2023 related to Bear Swamp | (5) | (8) | ||||||
| Decreased earnings at EES due to less favourable market conditions. Year-over-year decrease also reflects favourable hedging opportunities in Q1 2023 as a result of higher natural gas pricing | (3) | (13) | ||||||
| Corporate |
||||||||
| Decreased OM&G, pre-tax, primarily due to the timing difference in the valuation of long-term incentive expense and related hedges | 32 | 15 | ||||||
| Increased preferred share dividends due to higher dividend rate for series B, C, and H preferred shares | (2) | (6) | ||||||
| Increased interest expense, pre-tax, due to increased interest rates and increased total debt | (6) | (29) | ||||||
| Decreased income tax recovery quarter-over-quarter due to decreased loss before provision for income taxes. Increased income tax recovery year-over-year due to increased loss before provision for income taxes | (7) | 8 | ||||||
| Other Variances |
(6) | (11) | ||||||
| Adjusted net income – 2024 |
$ | 236 | $ | 603 | ||||
For further details of contributions by reportable segments, refer to the “Financial Highlights” section.
8
| For the | Nine months ended September 30 |
|||||||
| millions of dollars | 2024 | 2023 | ||||||
| Operating cash flow before changes in working capital |
$ | 1,732 | $ | 1,813 | ||||
| Change in working capital |
220 | 5 | ||||||
| Operating cash flow |
$ | 1,952 | $ | 1,818 | ||||
| Investing cash flow |
$ | (1,289 | ) | $ | (2,045 | ) | ||
| Financing cash flow |
$ | (997 | ) | $ | 166 | |||
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
| As at |
September 30 | December 31 | ||||||
| millions of dollars |
2024 | 2023 | ||||||
| Total assets |
$ | 39,674 | $ | 39,480 | ||||
| Total long-term debt (including current portion) (1) |
$ | 17,262 | $ | 18,365 | ||||
| (1) Excludes NMGC balances classified as held for sale as at September 30, 2024. For further details refer to the “Other Developments” section and Note 4 in the condensed consolidated interim financial statements. |
| |||||||
Consolidated Income Statement Highlights
| For the | Three months ended | Nine months ended | ||||||||||||||||||||||
| millions of dollars | September 30 | September 30 | ||||||||||||||||||||||
| (except per share amounts) | 2024 | 2023 | Variance | 2024 | 2023 | Variance | ||||||||||||||||||
| Operating revenues |
$ | 1,802 | $ | 1,740 | $ | 62 | $ | 5,437 | $ | 5,591 | $ | (154) | ||||||||||||
| Operating expenses |
1,586 | 1,468 | (118) | 4,596 | 4,302 | (294) | ||||||||||||||||||
| Income from operations |
$ | 216 | $ | 272 | $ | (56) | $ | 841 | $ | 1,289 | $ | (448) | ||||||||||||
| Other income, net |
$ | 14 | $ | 15 | $ | (1) | $ | 232 | $ | 107 | $ | 125 | ||||||||||||
| Interest expense, net |
$ | 241 | $ | 235 | $ | (6) | $ | 725 | $ | 684 | $ | (41) | ||||||||||||
| Income tax (recovery) expense |
$ | (9) | $ | (34) | $ | (25) | $ | 40 | $ | 77 | $ | 37 | ||||||||||||
| Net income attributable to common shareholders |
$ | 4 | $ | 101 | $ | (97) | $ | 340 | $ | 689 | $ | (349) | ||||||||||||
| Adjusted net income |
$ | 236 | $ | 204 | $ | 32 | $ | 603 | $ | 634 | $ | (31) | ||||||||||||
| Weighted average shares of common stock outstanding (in millions) |
290.0 | 273.6 | 16.4 | 287.5 | 272.2 | 15.3 | ||||||||||||||||||
| EPS – basic |
$ | 0.01 | $ | 0.37 | $ | (0.36) | $ | 1.18 | $ | 2.53 | $ | (1.35) | ||||||||||||
| EPS – diluted |
$ | 0.01 | $ | 0.37 | $ | (0.36) | $ | 1.18 | $ | 2.53 | $ | (1.35) | ||||||||||||
| Adjusted EPS – basic |
$ | 0.81 | $ | 0.75 | $ | 0.06 | $ | 2.10 | $ | 2.33 | $ | (0.23) | ||||||||||||
| Dividends per common share declared |
$ | 0.7175 | $ | 0.6900 | $ | 0.0275 | $ | 2.1525 | $ | 2.0700 | $ | 0.0825 | ||||||||||||
| Adjusted EBITDA |
$ | 804 | $ | 728 | $ | 76 | $ | 2,294 | $ | 2,205 | $ | 89 | ||||||||||||
Operating Revenues
For Q3 2024, operating revenues increased $62 million compared to Q3 2023 and, excluding decreased MTM loss of $98 million, decreased $36 million. The decrease was due to lower fuel recovery clause and storm surcharge revenue (offset in OM&G) at TEC; decreased marketing and trading margin at EES; lower fuel revenue at NMGC; and unfavourable weather at TEC. These decreases were partially offset by new rates at PGS, NSPI and TEC; the impact of a weaker CAD; and increased customer growth at PGS and TEC.
Year-to-date in 2024, operating revenues decreased $154 million compared to 2023 and, excluding increased MTM loss of $268 million, increased $114 million. The increase was due to new rates at NSPI, PGS and TEC; a change in the fuel cost recovery methodology for an industrial customer in 2023 at NSPI; the impact of a weaker CAD; and increased customer growth at PGS, TEC and NSPI. These increases were partially offset by lower fuel recovery clause and storm surcharge revenue (offset in OM&G) at TEC; lower fuel and asset optimization revenues at NMGC; decreased marketing and trading margin at EES; and unfavourable weather at TEC.
9
Operating Expenses
Operating expenses for Q3 2024 increased $118 million compared to Q3 2023, and, excluding the goodwill and other impairment charges related to the pending sale of NMGC of $221 million, decreased $103 million due to lower OM&G as a result of lower storm cost recognition at TEC (offset in revenue); the timing difference in the valuation of long-term incentive expense and related hedges at Corporate; and lower fuel for generation and purchased power due to changes in natural gas prices at TEC. These decreases were partially offset by higher depreciation at TEC and PGS.
Operating expenses year-to-date 2024 increased $294 million, compared to 2023, and excluding the goodwill and other impairment charges related to the pending sale of NMGC of $221 million, increased $73 million due to higher depreciation at TEC and PGS; a change in fuel cost recovery for an industrial customer in 2023 at NSPI; higher OM&G due to increased T&D costs and higher regulatory deferrals at TEC, higher labour costs at PGS and NMGC and increased investment in reliability initiatives at NSPI. These increases were partially offset by lower fuel for generation and purchased power due to changes in natural gas prices at TEC; lower natural gas prices at NMGC and PGS; lower storm cost recognition at TEC (offset in revenue); timing difference in the valuation of long-term incentive expense and related hedges at Corporate; and the Nova Scotia Renewable Electric Regulations (“RER”) penalty recognized at NSPI in Q1 2023.
Other Income, Net
For Q3 2024, other income, net decreased $1 million compared to Q3 2024 due to transaction costs related to the pending sale of NMGC, partially offset by higher FX gains.
Year-to-date in 2024, other income, net increased $125 million compared to the same period in 2023 due to the gain on sale, after transaction costs, of Emera’s LIL equity interest, partially offset by transaction costs related to the pending sale of NMGC, lower interest income, and higher FX losses.
Interest Expense, Net
For Q3 2024, interest expense, net increased $6 million and year-to-date 2024 increased $41 million compared to the same periods in 2023 due to higher interest rates and increased borrowings to support ongoing operations.
Income Tax (Recovery) Expense
For Q3 2024, income tax recovery decreased $25 million compared to Q3 2023 due to increased income before provision for income taxes, excluding charges related to the pending sale of NMGC, increased production tax credits related to solar facilities and the tax impact of the charges related to the pending sale of NMGC.
Year-to-date in 2024, income tax expense decreased $37 million compared to 2023 due to decreased income before provision for income taxes, excluding the gain on sale of LIL equity interest and charges related to the pending sale of NMGC. This was partially offset by the net tax impact of the gain on sale of LIL equity interest and charges related to the pending sale of NMGC.
Net Income and Adjusted Net Income
For Q3 2024, net income attributable to common shareholders, compared to Q3 2023, was unfavourably impacted by $225 million in charges related to the pending sale of NMGC, after-tax, and favourably impacted by the $96 million decrease in MTM losses, after-tax. Excluding these changes, adjusted net income increased $32 million, primarily due to increased earnings at TEC, PGS, NSPI and NMGC; and lower Corporate OM&G due to the timing difference in the valuation of long-term incentive expense and related hedges. These were partially offset by decreased earnings at Emera Energy; lower equity earnings from LIL; lower Corporate income tax recovery due to decreased losses before provision for income taxes; increased Corporate interest expense due to increased interest rates and increased total debt; and increased Corporate preferred share dividends.
10
Year-to-date 2024, net income attributable to common shareholders, compared to the same period in 2023, was favourably impacted by the $107 million gain on sale, after tax, and transaction costs, of the LIL equity interest and unfavourably impacted by the $200 million increase in MTM losses, after-tax, and $225 million in charges related to the pending sale of NMGC, after-tax. Excluding these changes, adjusted net income decreased $31 million. The decrease was primarily due to decreased earnings at NMGC, Emera Energy, and NSPI; lower equity earnings from LIL; increased Corporate interest expense due to increased interest rates and increased total debt; and increased Corporate preferred share dividends. These were partially offset by increased earnings at PGS and TEC; decreased Corporate OM&G due to the timing difference in the valuation of long-term incentive expense and related hedges; and higher income tax recovery due to increased loss before provision for income taxes.
EPS – Basic and Adjusted EPS – Basic
EPS – basic was lower in Q3 2024 due to the impact of decreased earnings, as discussed above, and an increase in weighted average shares outstanding. Adjusted EPS – basic was higher in Q3 2024 due to increased adjusted earnings as discussed above, partially offset by an increase in weighted average shares outstanding.
EPS – basic and adjusted EPS – basic were lower year-over-year in 2024 due to the impact of an increase in weighted average shares outstanding and decreased earnings, as discussed above.
Effect of Foreign Currency Translation
Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2023 annual MD&A.
The relevant CAD/USD exchange rates for 2024 and 2023 are as follows:
| Three months ended | Nine months ended | Year ended | ||||||||||||||||||
| September 30 | September 30 | December 31 | ||||||||||||||||||
| For the | 2024 | 2023 | 2024 | 2023 | 2023 | |||||||||||||||
| Weighted average CAD/USD |
$ | 1.36 | $ | 1.34 | $ | 1.36 | $ | 1.34 | $ | 1.35 | ||||||||||
| Period end CAD/USD exchange rate |
$ | 1.35 | $ | 1.35 | $ | 1.35 | $ | 1.35 | $ | 1.32 | ||||||||||
The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Florida Electric Utility |
$ | 186 | $ | 170 | $ | 385 | $ | 381 | ||||||||
| Gas Utilities and Infrastructure (1)(2) |
25 | 12 | 122 | 101 | ||||||||||||
| Other Electric Utilities |
8 | 13 | 20 | 23 | ||||||||||||
| Other segment (3)(4) |
(58) | (32) | (108) | (77) | ||||||||||||
| Total (2)(4)(5) |
$ | 161 | $ | 163 | $ | 419 | $ | 428 | ||||||||
| (1) Includes USD adjusted net income from PGS, NMGC, SeaCoast and M&NP. |
| |||||||||||||||
| (2) Excludes $6 million USD after-tax in other impairment charges associated with the pending sale of NMGC |
| |||||||||||||||
| (3) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt. |
| |||||||||||||||
| (4) Excludes $160 million USD, after-tax in charges associated with the pending sale of NMGC |
| |||||||||||||||
| (5) Excludes $183 million USD MTM loss, after-tax, for the three months ended September 30, 2024 (2023 – $57 million USD MTM loss, after-tax) and $272 million USD MTM loss, after-tax, for the nine months ended September 30, 2024 (2023 – $43 million USD MTM gain, after-tax). |
| |||||||||||||||
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The translation impact of a weaker CAD on USD earnings increased net income by $7 million in Q3 2024 compared to the same period in 2023. Year-to-date 2024, the impact of a weaker CAD on US denominated earnings was more than offset by the realized and unrealized losses on FX hedges used to mitigate the translation risk of USD earnings, resulting in a $6 million decrease to net income compared to the same period in 2023. Weakening of the CAD increased adjusted net income by $2 million in Q3 2024 and $3 million year-to-date compared to the same periods in 2023. Impacts of the changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of USD earnings in the Other segment.
BUSINESS OVERVIEW AND OUTLOOK
There have been no material changes in Emera’s business overview and outlook from the Company’s 2023 annual MD&A, except for the updates disclosed below. Emera’s results have been impacted by macroeconomic conditions, specifically higher interest rates as well as other impacts of inflation. These conditions are likely to continue for the near term. For information on general economic risk, including interest rate and inflation risk, refer to the “Enterprise Risk and Risk Management – General Economic Risk” in Emera’s 2023 annual MD&A. For details on Emera’s reportable segments, refer to note 1 of the Q3 2024 unaudited condensed consolidated interim financial statements.
Florida Electric Utility
TEC anticipates earning towards the lower end of the ROE range in 2024 but expects earnings to be higher than 2023. Normalizing 2023 for weather, TEC sales volumes in 2024 are projected to be higher than 2023 due to customer growth. TEC expects customer growth rates in 2024 to be comparable to 2023, reflective of the expected economic growth in Florida.
On September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall approximately 200 miles north of Tampa, in Taylor County, as a Category 4 hurricane. TEC’s service territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number of customers out of 100,000. As of September 30, 2024, TEC deferred $45 million USD to the storm reserve for future recovery, with a minimal impact to earnings. Additional storm restoration costs expected to be deferred to the storm reserve regulatory account in Q4 2024 are estimated to be upwards of $10 million USD, with minimal impact expected to earnings.
On October 9, 2024, Hurricane Milton made landfall approximately 50 miles south of Tampa, near Sarasota, and was the worst weather event to impact the area in over 100 years. The Category 3 hurricane had a significant impact on TEC’s service territory which resulted in a peak number of customers out of 600,000. The total cost of restoration expected to be deferred to the storm reserve regulatory asset is estimated to be $320 million – $370 million USD, with minimal impact expected to earnings.
As at September 30, 2024, total restoration costs charged to the storm reserve account, including Q3 2024 costs related to Hurricane Helene, have exceeded the storm reserve balance (for additional details on the storm reserve, refer to note 6 in Emera’s 2023 annual audited consolidated financial statements) and therefore $35 million USD has been deferred as a regulatory asset for future recovery. The Q4 2024 restoration costs for Hurricane Helene and Milton will also be deferred to the storm reserve regulatory account. TEC expects to make a regulatory filing with the FPSC for the recovery of the storm reserve regulatory account balance and replenishment of the original storm reserve. TEC has not determined the recovery approach and timeframe at this time but is considering several alternatives.
On April 2, 2024, TEC requested a base rate increase, reflecting an increased revenue requirement of $297 million USD, effective January 1, 2025, and additional adjustments of $100 million USD and $72 million USD for 2026 and 2027, respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and other resiliency and reliability projects. The rate case hearing occurred in August 2024 and a decision by the FPSC is expected by early December 2024.
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On April 24, 2024, the US Environmental Protection Agency issued its final rules for certain electric generating units. The rules include new greenhouse gas standards, which apply only to existing coal-fired and new natural gas electric generating units and will therefore have limited impact on TEC. They also include new coal combustion residual (“CCR”) rules. TEC is currently evaluating the impact of the new CCR rule at the Big Bend Power Station. TEC expects that prudently incurred costs to comply with new environmental regulations would be eligible for recovery from customers through either the Environmental Cost Recovery Clause or base rates.
On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction is due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected 2024 costs in the fall of 2023. On May 7, 2024, the FPSC approved the mid-course adjustment.
In 2024, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2023 – $1.3 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, grid modernization, storm hardening investments and building resilience.
Canadian Electric Utilities
NSPI
NSPI expects earnings in 2024 to be consistent with, or higher than, 2023 and anticipates earning below its allowed ROE range in 2024. Sales volumes are expected to be higher in 2024 than 2023.
On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the Province of Nova Scotia (the “Province”) on terms and conditions for a federal loan guarantee (“FLG”) of $500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of the replacement energy that was required during the several years of delay in the Muskrat Falls hydroelectricity project. Subject to certain conditions, including regulatory approval by the UARB, the net proceeds of the NSPML debt issuance will be transferred to NSPI as a refund of a portion of previous NSPML assessment payments and be applied against the Fuel Adjustment Mechanism (“FAM”) regulatory asset balance. NSPML will then increase its annual assessment charge to NSPI to recover the refund and related financing costs over a 28-year period. On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. A decision on the NSPML application, which would trigger the debt issuance and refund to NSPI, is expected in Q4 2024. A decision on the NSPI application, which would reflect the necessary 2025 fuel rates to service the incremental NSPML debt, is expected in Q1 2025.
On June 27, 2024, the UARB approved the deferred recognition of $25 million in incremental operating costs incurred during the Hurricane Fiona storm restoration efforts in September 2022. Following UARB approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The UARB also directed NSPI to reclassify $10 million of undepreciated costs related to assets retired because of Hurricane Fiona to “Regulatory assets” from “PP&E” on the Condensed Consolidated Balance Sheets. NSPI began amortizing both of these regulatory assets over a 10-year period beginning July 1, 2024.
On June 13, 2024, the UARB approved $238 million of capital investment, including AFUDC, for the Battery Energy Storage System Project. The project is comprised of three 50 MW, four-hour battery facilities. Two facilities are anticipated to be in-service in late 2025 and the third facility in 2026.
On April 30, 2024, NSPI applied to the UARB for recovery of $22 million of major storm restoration costs deferred to NSPI’s UARB approved storm rider in 2023. If approved, the 2023 costs deferred to the storm rider would be recovered over a 12-month period beginning January 1, 2025. A decision from the UARB is expected by the end of 2024.
13
On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, which resulted in a corresponding decrease of the FAM regulatory asset. NSPI is collecting the amortization and financing costs related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period, which began in Q2 2024, and is remitting those amounts to Invest Nova Scotia quarterly.
In 2024, capital investment, including AFUDC, is expected to be $510 million (2023 – $451 million). NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.
Environmental Legislation and Regulations
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province. For further discussion on environmental legislation and regulations and associated risks, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Enterprise Risk and Risk Management” sections respectively of Emera’s 2023 annual MD&A. Recent developments related to provincial and federal environmental laws and regulations are outlined below.
Nova Scotia Energy Reform Act:
On April 5, 2024, the Province enacted Bill 404 - Energy Reform (2024) Act. This legislation implements certain recommendations made by the Clean Electricity Solutions Task Force, which was established by the Province to advise the provincial government on Nova Scotia’s transition away from coal to more renewable sources of energy. The legislation enacted the Energy and Regulatory Board Act, which established the Nova Scotia Energy Board (“NSEB”). The NSEB is a new board which will regulate energy and utility entities in Nova Scotia, with a mandate of increased focus on meeting energy transition demands. The legislation also enacts the More Access to Energy Act, which provides for the establishment of and phased transition to the Nova Scotia Independent Energy System Operator. NSPI is fully engaged in working with the Province on these initiatives.
RER:
On May 26, 2023, NSPI initiated an appeal, through a proceeding with the UARB, of the $10 million penalty levied on NSPI by the Province for non-compliance with the RER compliance period ending in 2022. The hearing for the matter is currently scheduled for April 2025.
NSPML
Equity earnings from NSPML in 2024 are expected to be consistent with 2023.
On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML, and the Province on terms and conditions for a FLG of $500 million in debt to be issued by NSPML. For further information, refer to the NSPI section above.
On July 4, 2024, NSPML submitted an application to the UARB requesting recovery of approximately $158 million in Maritime Link costs for 2025. A decision is expected in Q4 2024.
On December 21, 2023, NSPML received approval from the UARB to collect up to $164 million in 2024 from NSPI for the recovery of costs associated with the Maritime Link subject to a holdback of $4 million per month. There was no holdback recorded year-to-date in 2024. NSPML expects to file an application to terminate the holdback mechanism in late Q4 2024.
NSPML does not anticipate any significant capital investment in 2024.
LIL
On June 4, 2024, Emera completed the sale of its LIL equity interest. For further information, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
14
Gas Utilities and Infrastructure
On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024. For more information on the pending transaction, refer to the “Other Developments” section.
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2024 than 2023, primarily due to a base rate increase effective January 2024 at PGS and a base rate increase effective October 2024 at NMGC, partially offset by increased operating expenses and lower asset optimization revenues expected at NMGC.
PGS expects rate base to be higher than in 2023 and anticipates earning within its allowed ROE range in 2024. USD earnings for 2024 are expected to be significantly higher than in 2023 primarily due to higher revenue from new base rates in support of significant ongoing system investment and continued customer growth in 2024, which is expected to be consistent with Florida’s population growth rates.
NMGC expects 2024 rate base to be higher in 2024 than in 2023, with slightly lower USD earnings as a result of increased operating expenses and lower asset optimization revenues, partially offset by higher revenue from new base rates, effective October 2024. NMGC anticipates earning slightly below its authorized ROE in 2024. Customer growth is expected to be consistent with historical trends.
On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates. On March 1, 2024, NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30 million USD in annual base revenues and maintaining NMGC’s ROE at 9.375 per cent. The rates reflect the recovery of increased operating costs and capital investments in pipeline projects and related infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw, and to not reassert in a future rate case application, its request for a regulatory asset for costs associated with its 2022 application for a certificate of public convenience and necessity for a liquefied natural gas storage facility in New Mexico. The NMPRC approved the rate case settlement on July 25, 2024. New rates became effective October 1, 2024.
In 2024, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $450 million USD (2023 – $495 million USD), including AFUDC. PGS and NMGC will make investments to maintain the reliability of their systems and support customer growth.
Other Electric Utilities
Other Electric Utilities’ USD earnings in 2024 are expected to increase over the prior year due to higher sales volumes at BLPC.
On August 1, 2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement, GBPC filed a rate plan proposal. During Q2 2024, GBPC customers experienced power interruptions due to unscheduled generation outages. Subsequently, on October 1, 2024, the GBPA suspended its review of GBPC’s rate plan proposal until a period of reliability is re-established by GBPC. GBPC has been executing a comprehensive plan to improve service reliability for its customers during Q4 2024.
On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian regulator, regulate GBPC. The GBPA has opposed the legislated removal of its regulatory authority over GBPC, citing conflict with the Hawksbill Creek Agreement, the 1955 agreement with the Bahamian government that provided for the development and administration of the Freeport area. Management expects the matter of regulatory jurisdiction over GBPC to be the subject of legal proceedings, however, does not foresee that the legislation or the outcome of such proceedings will have a material impact to Emera.
15
On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation) Act into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs over a period to be approved by the FTC during a future rate setting process. A decision by the FTC is expected in Q4 2024.
On May 24, 2024, the Government of Barbados signed the Corporation Top-up Tax (Amendment) Act (“Top-up Tax Act”) into law. The legislation, effective January 1, 2024, establishes an effective tax rate of 15 per cent for qualifying entities through the imposition of a top-up tax. The Top-up Tax Act is not expected to have a material impact to Emera.
In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.
On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023 decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. The appeal is currently scheduled to be heard in December 2024. Management does not expect the final decision and order to have a material impact on adjusted net income.
In 2024, capital investment in the Other Electric Utilities segment is expected to be approximately $90 million USD (2023 – $47 million USD), primarily in projects to support system reliability.
Other
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is expected to deliver annual adjusted net income within its guidance range of $15 to $30 million USD.
The adjusted net loss from the Other segment is expected to be higher in 2024 due to increased interest expense, higher Corporate OM&G, higher preferred dividend expense, and a lower contribution to net income from Emera Energy primarily as a result of one-time investment tax credits at Bear Swamp in 2023.
The Other segment does not anticipate any significant capital investment in 2024.
16
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2023 and September 30, 2024 include:
| millions of dollars | Total Increase (Decrease) |
Increase (Decrease) due to held for sale classification (1) |
Other Increase (Decrease) |
Explanation of Other Increase (Decrease) | ||||||||||
| Assets | ||||||||||||||
| Cash and cash equivalents | $ | (327) | $ | (4) | $ | (323) | Decreased due to investment in PP&E, net repayments on committed credit facilities at Corporate, repayment of short-term debt at TEC, retirement of long-term debt at Emera, TEC and New Mexico Gas Intermediate, Inc. (“NMGI”), and dividends paid on Emera common stock. These were partially offset by cash from operations, proceeds from debt issuances at TEC and EUSHI Finance, Inc., proceeds received on the sale of the LIL equity interest and proceeds from common shares issued | |||||||
| Derivative instruments (current and long-term) | (67) | (14) | (53) | Decreased due to the reversal of 2023 contracts and changes in existing positions at EES | ||||||||||
| Regulatory assets (current and long-term) | (207) | (25) | (182) | Decreased due to lower deferred income tax regulatory assets due to the sale of LIL equity interest, decreased fuel clause recovery asset balance at TEC due to higher over-recoveries, and lower deferrals related to derivative instruments at NSPI. These were partially offset by increased storm cost recovery clause assets at TEC and NSPI | ||||||||||
| Receivables and other assets (current and long-term) | (269) | (85) | (184) | Decreased due to lower gas transportation assets and lower trade receivables due to lower commodity prices at EES and lower cash collateral position on derivative instruments and seasonal trends at NSPI. These were partially offset by higher unbilled revenue at TEC | ||||||||||
| Assets held for sale (current and long-term), net of liabilities | 885 | 885 | - | Increased due to the pending sale of NMGC | ||||||||||
| PP&E, net of accumulated depreciation and amortization | 83 | (1,672) | 1,755 | Increased due to capital additions in excess of depreciation and the effect of FX translation of Emera’s non-Canadian affiliates | ||||||||||
| Investments subject to significant influence | (750) | - | (750) | Decreased primarily due to sale of LIL equity interest | ||||||||||
| Goodwill |
(373) | (284) | (89) | Decreased due to the non-cash impairment charge recognized related to NMGC, partially offset by the effect of FX translation of Emera’s non-Canadian affiliates | ||||||||||
| (1) On August 5, 2024, Emera announced the sale of NMGC. As at September 30, 2024 NMGC’s assets and liabilities were classified as held for sale. For further details, refer to the ‘Other Developments’ section and note 3 in the condensed consolidated interim financial statements. | ||||||||||||||
17
| millions of dollars | Total Increase (Decrease) |
Increase (Decrease) due to held for sale classification (1) |
Other Increase (Decrease) |
Explanation of Other Increase (Decrease) | ||||||||||
| Liabilities and Equity |
|
|||||||||||||
| Short-term debt and long-term debt (including current portion) | $ | (1,127) | $ | (672) | $ | (455) | Decrease due to higher repayment of Emera’s committed credit facilities using the LIL transaction proceeds, repayment of short-term debt at TEC, and retirement of long-term debt at Corporate, TEC and NMGI. These were partially offset by proceeds from long-term debt issuance at TEC, issuance of junior subordinated notes at EUSHI Finance Inc. and the effect of FX translation of Emera’s non-Canadian affiliates | |||||||
| Accounts payable | (135) | (79) | (56) | Decreased due to lower commodity prices at EES | ||||||||||
| Deferred income tax liabilities, net of deferred income tax assets | (187) | (157) | (30) | No significant change after removing impact of held for sale classification | ||||||||||
| Regulatory liabilities (current and long-term) | (98) | (268) | 170 | Increased due to recognition of fuel clause recovery liability due to cost recovery in excess of regulatory asset at TEC, higher cost of removal at TEC and PGS, and the effect of FX translation of Emera’s non-Canadian affiliates | ||||||||||
| Other liabilities (current and long-term) | 167 | (30) | 197 | Increased due to timing of interest payments at Corporate and TEC, higher output-based pricing system (“OBPS”) carbon tax accrual at NSPI and the effect of FX translation of Emera’s non-Canadian affiliates | ||||||||||
| Common stock | 422 | - | 422 | Increased due to shares issued | ||||||||||
| Accumulated other comprehensive income | 207 | - | 207 | Increased due to the effect of FX translation of Emera’s non-Canadian affiliates | ||||||||||
| Retained earnings | (277) | - | (277) | Decreased due to dividends paid in excess of net income | ||||||||||
| (1) On August 5, 2024, Emera announced the sale of NMGC. As at September 30, 2024 NMGC’s assets and liabilities were classified as held for sale. For further details, refer to the ‘Other Developments’ section and note 3 in the condensed consolidated interim financial statements. | ||||||||||||||
OTHER DEVELOPMENTS
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement to sell its indirect wholly owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024.
As the transaction proceeds will be lower than the carrying amount of the assets and liabilities being sold, Emera assessed the NMGC reporting unit for goodwill impairment by comparing the fair value (“FV”) of expected transaction proceeds to the carrying value of net assets, including goodwill of $366 million USD (“carrying amount”). The goodwill of the reporting unit was determined to be impaired and a non-cash goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million USD ($146 million USD, after-tax) was recorded in “Impairment Charges” on the Condensed Consolidated Statements of Income in Q3 2024.
18
Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an additional loss for the estimated future transaction costs of $16 million ($13 million after-tax), in addition to incurred transaction costs of $8 million ($6 million after-tax) recorded in “Other Income, net” on the Condensed Consolidated Statements of Income in Q3 2024.
The Company will continue to record depreciation on the NMGC assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $9 million ($7 million USD) has been recorded on these assets from August 5, 2024, the date they were classified as held for sale, to September 30, 2024.
Increase in Common Dividend
On September 18, 2024, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.90 from $2.87 per common share. The first payment will be effective November 15, 2024.
Canadian Tax Legislation Changes
On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March 28, 2023, was enacted. Bill C-59 includes the excessive interest and financing expenses limitation (“EIFEL”) regime, which is effective January 1, 2024. EIFEL applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of EBITDA for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be carried forward indefinitely. The Company is still in the process of assessing the impacts of the enactment of the EIFEL regime, including investigating opportunities to restructure its Canadian-based financing to ensure that any denied interest and financing expenses in the near-term will be utilized in future periods. There are no impacts required to be recognized in the Company’s financial statements as at September 30, 2024.
On June 20, 2024, Bill C-69, an Act to implement certain provisions of the budget tabled in Parliament on April 16, 2024, was enacted. Bill C-69 includes the Canadian Global Minimum Tax Act (“GMTA”), a regime based on the rules of the Organisation for Economic Co-operation and Development (“OECD”). The GMTA ensures that large multinational corporations are subject to a minimum effective tax rate of 15 per cent on their profits wherever they do business. The GMTA did not have a material impact on the Company in Q3 2024.
Sale of LIL Equity Interest
On June 4, 2024, Emera completed the sale of its 31.1 per cent LIL equity interest for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable is held at FV and included in the gain on sale, after transaction costs. As of September 30, 2024, the estimated FV of the escrow proceeds receivable is $25 million. A gain on sale, after tax and transaction costs, of $107 million, was included in the Other segment (the gain on sale, net of transaction costs of $182 million was recognized in “Other Income, net” on the Condensed Consolidated Statements of Income). Proceeds from the sale were used to reduce corporate debt and fund investment in the Company’s regulated utility businesses.
19
Appointments
Board of Directors
Effective June 26, 2024, Carla Tully joined the Emera Board of Directors. Ms. Tully is the former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company. She also previously served as Executive Vice President and Managing Director of Renewable Energy at MAP Energy and held various senior leadership roles with AES Corporation.
Effective March 6, 2024, Brian J. Porter joined the Emera Board of Directors. Mr. Porter is the former President and Chief Executive Officer of The Bank of Nova Scotia (Scotiabank), a global bank operating in Canada and the Americas.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD (except as indicated) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Operating revenues – regulated electric |
$ | 724 | $ | 795 | $ | 1,944 | $ | 2,024 | ||||||||
| Regulated fuel for generation and purchased power |
$ | 164 | $ | 210 | $ | 471 | $ | 520 | ||||||||
| Contribution to consolidated net income |
$ | 186 | $ | 170 | $ | 385 | $ | 381 | ||||||||
| Contribution to consolidated net income – CAD |
$ | 252 | $ | 228 | $ | 524 | $ | 512 | ||||||||
| Electric sales volumes (Gigawatt hours (“GWh”)) |
6,437 | 6,919 | 16,080 | 16,529 | ||||||||||||
| Electric production volumes (GWh) |
6,661 | 6,749 | 17,017 | 17,065 | ||||||||||||
| Average fuel cost in dollars per megawatt hour (“MWh”) |
$ | 25 | $ | 31 | $ | 28 | $ | 30 | ||||||||
The impact on Q3 2024 and year-to-date earnings related to the change in the FX rate increased CAD earnings by $4 million and $7 million, respectively.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of USD | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2023 |
$ | 170 | $ | 381 | ||||
| Decreased operating revenues primarily due to decreased fuel recovery clause revenue, lower storm surcharge revenue (offset in OM&G) and unfavourable weather of approximately $13 million and $22 million quarter-over-quarter and year-over-year, respectively. These decreases are partially offset by customer growth and new base rates | (71) | (80) | ||||||
| Decreased fuel for generation and purchased power due to lower natural gas prices | 46 | 49 | ||||||
| Decreased OM&G due to lower storm cost recognition (offset in revenue). Year-over-year decrease was partially offset by higher generation and T&D costs and timing of deferred clause recoveries | 34 | 31 | ||||||
| Increased depreciation and amortization due to additions to facilities and generation projects placed in service | (7) | (23) | ||||||
| Decreased interest expense due to lower borrowings | 2 | 7 | ||||||
| Decreased income tax expense due to increased production tax credits related to solar facilities | 6 | 18 | ||||||
| Other | 6 | 2 | ||||||
| Contribution to consolidated net income – 2024 | $ | 186 | $ | 385 | ||||
20
Canadian Electric Utilities
On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to the “Other Developments” section.
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars (except as indicated) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Operating revenues – regulated electric |
$ | 399 | $ | 388 | $ | 1,376 | $ | 1,232 | ||||||||
| Regulated fuel for generation and purchased power (1) |
$ | 243 | $ | 213 | $ | 725 | $ | 543 | ||||||||
| Contribution to consolidated net income |
$ | 26 | $ | 38 | $ | 155 | $ | 179 | ||||||||
| Electric sales volumes (GWh) |
2,285 | 2,331 | 7,849 | 7,777 | ||||||||||||
| Electric production volumes (GWh) |
2,428 | 2,471 | 8,361 | 8,255 | ||||||||||||
| Average fuel costs in dollars per MWh (2) |
$ | 100 | $ | 86 | $ | 87 | $ | 66 | ||||||||
| (1) Regulated fuel for generation and purchased power includes NSPI’s FAM on the Condensed Consolidated Statements of Income, however, it is excluded in the segment overview. |
| |||||||||||||||
| (2) Average fuel costs for the nine months ended September 30, 2023 include the reversal of the $166 million Nova Scotia Cap-and-Trade Program provision. |
| |||||||||||||||
Canadian Electric Utilities’ contribution to consolidated net income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| NSPI |
$ | 14 | $ | 10 | $ | 89 | $ | 101 | ||||||||
| Equity investment in NSPML |
12 | 13 | 38 | 34 | ||||||||||||
| Equity investment in LIL |
- | 15 | 28 | 44 | ||||||||||||
| Contribution to consolidated net income |
$ | 26 | $ | 38 | $ | 155 | $ | 179 | ||||||||
21
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of dollars | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2023 |
$ | 38 | $ | 179 | ||||
| Increased operating revenues at NSPI due to new rates, and higher residential sales volumes, partially offset by lower industrial revenue. Year-over-year also increased due to changes in fuel cost recovery methodology for an industrial customer(1) in 2023 | 11 | 144 | ||||||
| Increased regulated fuel for generation and purchased power at NSPI quarter-over-quarter due to change in generation mix and decreased Nova Scotia OBPS carbon tax accrual, partially offset by lower commodity prices. Increased year-over-year due to reversal of the Nova Scotia Cap-and-Trade Program provision(1) in 2023, change in generation mix, and increased sales volumes, partially offset by decreased commodity prices | (30) | (182) | ||||||
| Increased FAM at NSPI quarter-over-quarter due to a higher under-recovery of fuel costs. Increased year-over-year due to changes in the fuel cost recovery methodology for an industrial customer(1) in 2023 and higher under-recovery of fuel costs, partially offset by the reversal of the Nova Scotia Cap-and-Trade Program provision(1) in 2023 | 19 | 56 | ||||||
| Increased OM&G year-over-year at NSPI due to increased investment in reliability initiatives and higher IT costs, partially offset by lower storm restoration costs and the RER penalty recognized in Q1 2023 | 5 | (16) | ||||||
| Decreased income from equity investments due to the sale of LIL | (16) | (18) | ||||||
| Decreased income tax recovery year-over-year at NSPI due to decreased tax deductions in excess of accounting depreciation related to PP&E, partially offset by a decrease in the benefit of tax loss carryforwards recognized as a deferred income tax regulatory liability and decreased income before provision for income taxes | 3 | (7) | ||||||
| Other | (4) | (1) | ||||||
| Contribution to consolidated net income – 2024 | $ | 26 | $ | 155 | ||||
| (1) For more information on the changes in fuel cost recovery methodology for an industrial customer and the $166 million reversal related to the Nova Scotia Cap-and-Trade Program provision, refer to note 6 in Emera’s 2023 annual audited consolidated financial statements. |
| |||||||
Gas Utilities and Infrastructure
On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including regulatory approval by the NMPRC. The Company will continue to record depreciation on these assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. For more information on the pending transaction, refer to the “Other Developments” section.
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD (except as indicated) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Operating revenues – regulated gas (1) |
$ | 216 | $ | 193 | $ | 843 | $ | 824 | ||||||||
| Operating revenues – non-regulated |
5 | 4 | 12 | 12 | ||||||||||||
| Total operating revenue |
$ | 221 | $ | 197 | $ | 855 | $ | 836 | ||||||||
| Regulated cost of natural gas |
$ | 34 | $ | 44 | $ | 208 | $ | 292 | ||||||||
| Contribution to consolidated adjusted net income |
$ | 28 | $ | 17 | $ | 133 | $ | 115 | ||||||||
| Contribution to consolidated adjusted net income – CAD |
$ | 38 | $ | 23 | $ | 180 | $ | 155 | ||||||||
| Charges related to the pending sale of NMGC, after-tax (2) |
(6) | - | (6) | - | ||||||||||||
| Contribution to consolidated net income |
$ | 22 | $ | 17 | $ | 127 | $ | 115 | ||||||||
| Contribution to consolidated net income – CAD |
$ | 30 | $ | 23 | $ | 172 | $ | 155 | ||||||||
| Gas sales volumes (millions of Therms) |
729 | 705 | 2,370 | 2,333 | ||||||||||||
| (1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2023 – $12 million) for the three months ended September 30, 2024 and $34 million (2023 – $35 million) for the nine months ended September 30, 2024. |
| |||||||||||||||
| (2) Includes an other impairment charge, net of an income tax recovery of $2 million for the three and nine months ended September 30, 2024 (2023 – nil) |
| |||||||||||||||
22
Gas Utilities and Infrastructure’s contribution to consolidated adjusted net income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| PGS |
$ | 24 | $ | 13 | $ | 92 | $ | 58 | ||||||||
| NMGC |
(3) | (4) | 16 | 29 | ||||||||||||
| Other |
7 | 8 | 25 | 28 | ||||||||||||
| Contribution to consolidated adjusted net income |
$ | 28 | $ | 17 | $ | 133 | $ | 115 | ||||||||
The impact on Q3 2024 and year-to-date earnings related to the change in the FX rate increased CAD earnings and adjusted earnings by $1 million.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of USD | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2023 |
$ | 17 | $ | 115 | ||||
| Increased gas revenues due to new base rates and customer growth at PGS, partially offset by lower fuel revenues at NMGC | 24 | 27 | ||||||
| Decreased asset optimization revenues at NMGC | - | (8) | ||||||
| Decreased cost of natural gas due to lower natural gas prices at NMGC and PGS | 10 | 84 | ||||||
| Increased OM&G primarily due to the timing of deferred clause recoveries at PGS and higher labour cost at PGS and NMGC | (5) | (26) | ||||||
| Increased depreciation primarily due to asset growth at PGS, partially offset by reversal of accumulated depreciation in 2023 as a result of the 2021 rate case settlement at PGS | (7) | (26) | ||||||
| Increased interest expense, net primarily due to higher interest rates and increased borrowings to support ongoing operations and capital investments primarily at PGS | (2) | (16) | ||||||
| Increased income tax expense primarily due to increased income before provision for income taxes at PGS, partially offset by lower income before provision for income taxes at NMGC | (4) | (8) | ||||||
| Charges related to the pending sale of NMGC, after-tax | (6) | (6) | ||||||
| Other | (5) | (9) | ||||||
| Contribution to consolidated net income – 2024 | $ | 22 | $ | 127 | ||||
Other Electric Utilities.
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD (except as indicated) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Operating revenues – regulated electric |
$ | 110 | $ | 108 | $ | 306 | $ | 286 | ||||||||
| Regulated fuel for generation and purchased power |
$ | 58 | $ | 57 | $ | 160 | $ | 147 | ||||||||
| Contribution to consolidated adjusted net income |
$ | 8 | $ | 13 | $ | 20 | $ | 23 | ||||||||
| Contribution to consolidated adjusted net income – CAD |
$ | 10 | $ | 17 | $ | 27 | $ | 31 | ||||||||
| Equity securities MTM (loss) gain |
$ | - | $ | (1) | $ | 1 | $ | - | ||||||||
| Contribution to consolidated net income |
$ | 8 | $ | 12 | $ | 21 | $ | 23 | ||||||||
| Contribution to consolidated net income – CAD |
$ | 11 | $ | 16 | $ | 29 | $ | 31 | ||||||||
| Electric sales volumes (GWh) |
346 | 344 | 984 | 937 | ||||||||||||
| Electric production volumes (GWh) |
371 | 371 | 1,056 | 1,017 | ||||||||||||
| Average fuel costs in dollars per MWh |
$ | 156 | $ | 154 | $ | 152 | $ | 145 | ||||||||
23
Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| BLPC |
$ | 4 | $ | 6 | $ | 14 | $ | 14 | ||||||||
| GBPC |
4 | 7 | 8 | 11 | ||||||||||||
| Other |
- | - | (2) | (2) | ||||||||||||
| Contribution to consolidated adjusted net income |
$ | 8 | $ | 13 | $ | 20 | $ | 23 | ||||||||
The impact on Q3 2024 and year-to-date earnings related to the change in the FX rate on CAD earnings was minimal.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of USD | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2023 |
$ | 12 | $ | 23 | ||||
| Increased operating revenues – regulated electric year-over-year due to higher fuel revenue and higher sales volumes at BLPC | 2 | 20 | ||||||
| Increased regulated fuel for generation and purchased power year-over-year due to higher sales volumes at BLPC | (1) | (13) | ||||||
| Increased OM&G due to higher generation costs BLPC and GBPC |
(5) | (9) | ||||||
| Contribution to consolidated net income – 2024 |
$ | 8 | $ | 21 | ||||
Other
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Marketing and trading margin (1) (2) |
$ | (7) | $ | - | $ | 42 | $ | 61 | ||||||||
| Other non-regulated operating revenue |
7 | 7 | 22 | 22 | ||||||||||||
| Total operating revenues – non-regulated |
$ | - | $ | 7 | $ | 64 | $ | 83 | ||||||||
| Contribution to consolidated adjusted net (loss) income |
$ | (90) | $ | (102) | $ | (283) | $ | (243) | ||||||||
| Charges related to the pending sale of NMGC, after-tax (3) |
(217) | - | (217) | - | ||||||||||||
| Gain on sale, after tax and transaction costs (4)(5) |
- | - | 107 | - | ||||||||||||
| MTM (loss) gain, after-tax (6) |
(8) | (102) | (147) | 55 | ||||||||||||
| Contribution to consolidated net (loss) income |
$ | (315) | $ | (204) | $ | (540) | $ | (188) | ||||||||
| (1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services’ revenues. |
| |||||||||||||||
| (2) Marketing and trading margin excludes a pre-tax MTM loss of $37 million for the three months ended September 30, 2024 (2023 – $101 million loss) and a loss of $198 million year-to-date (2023 – $85 million gain). |
| |||||||||||||||
| (3) Includes a goodwill impairment charge of $210 million ($198 million after-tax) and transaction costs of $24 million ($19 million after-tax) for the three and nine months ended September 30, 2024 (2023 – nil). |
| |||||||||||||||
| (4) On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections. |
| |||||||||||||||
| (5) Net of income tax expense of $75 million for the nine months ended September 30, 2024 (2023 – nil). |
| |||||||||||||||
| (6) Net of income tax recovery of $4 million for the three months ended September 30, 2024 (2023 – $40 million recovery) and $60 million income tax recovery for the nine months ended September 30, 2024 (2023 – $24 million expense). |
| |||||||||||||||
24
Other’s contribution to consolidated adjusted net (loss) income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Emera Energy |
||||||||||||||||
| EES |
$ | (7) | $ | (4) | $ | 14 | $ | 27 | ||||||||
| Other |
2 | 7 | 4 | 12 | ||||||||||||
| Corporate – see breakdown of adjusted contribution below |
(82) | (99) | (287) | (265) | ||||||||||||
| Block Energy LLC |
(3) | (5) | (13) | (14) | ||||||||||||
| Other |
- | (1) | (1) | (3) | ||||||||||||
| Contribution to consolidated adjusted net (loss) income |
$ | (90) | $ | (102) | $ | (283) | $ | (243) | ||||||||
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of dollars | September 30 | September 30 | ||||||
| Contribution to consolidated net (loss) income – 2023 |
$ | (204) | $ | (188) | ||||
| Decreased marketing and trading margin quarter-over-quarter and year-over-year due to less favourable market conditions, specifically lower natural gas prices and volatility. Year-over-year decrease also reflects favourable hedging opportunities in Q1 2023 | (7) | (19) | ||||||
| Decreased OM&G primarily due to the timing difference in the valuation of long-term incentive expense and related hedges | 34 | 18 | ||||||
| Increased interest expense due to increased interest rates and increased total debt | (5) | (27) | ||||||
| Corporate FX losses on the translation of USD short-term debt balances | - | (5) | ||||||
| Decreased income tax recovery quarter-over-quarter due to decreased loss before provision for income taxes and the recognition of investment tax credits related to Bear Swamp facility upgrades in 2023. Increased income tax recovery year-over-year due to increased loss before provision for income taxes, partially offset by the recognition of investment tax credits related to Bear Swamp facility upgrades in 2023 | (12) | 4 | ||||||
| Charges related to the pending sale of NMGC, after-tax | (217) | (217) | ||||||
| Gain on sale of LIL, after tax and transaction costs | - | 107 | ||||||
| Decreased MTM loss, after-tax, quarter-over-quarter due to lower amortization of gas transportation assets at EES and a gain on Corporate FX hedges compared to a loss in prior year. Year-over-year, the 2023 MTM gain decreased to a loss for the same period in 2024 due to changes in existing positions at EES | 94 | (202) | ||||||
| Other | 2 | (11) | ||||||
| Contribution to consolidated net (loss) income – 2024 | $ | (315) | $ | (540) | ||||
25
Corporate
Corporate’s adjusted loss is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Operating expenses (1) |
$ | - | $ | (32) | $ | (51) | $ | (66) | ||||||||
| Interest expense |
(90) | (84) | (270) | (241) | ||||||||||||
| Income tax recovery |
27 | 34 | 94 | 86 | ||||||||||||
| Preferred dividends |
(18) | (16) | (54) | (48) | ||||||||||||
| Other (2)(3) |
(1) | (1) | (6) | 4 | ||||||||||||
| Corporate adjusted net loss (4)(5)(6) |
$ | (82) | $ | (99) | $ | (287) | $ | (265) | ||||||||
(1) Operating expenses include OM&G and depreciation.
(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings exposure.
(3) Includes a realized net loss, pre-tax of $3 million ($2 million after-tax) for the three months ended September 30, 2024 (2023 – $2 million net loss, pre-tax and $1 million loss, after-tax) and a $7 million net loss, pre-tax ($5 million after-tax) for the nine months ended September 30, 2024 (2023 – $7 million net loss, pre-tax and $5 million loss, after-tax) on FX hedges, as discussed above.
(4) Excludes a MTM gain, after-tax, of $6 million for the three months ended September 30, 2024 (2023 – $11 million loss, after-tax) and a MTM loss, after-tax of $6 million for the nine months ended September 30, 2024 (2023 – $5 million gain, after-tax).
(5) Excludes a gain on sale of LIL, after-tax and transaction costs, of $107 million for the three and nine months ended September 30, 2024 (2023 – nil).
(6) Excludes certain charges related to the pending sale of NMGC of $234 million ($217 million after-tax) for the three and nine months ended September 30, 2024 (2023 – nil).
LIQUIDITY AND CAPITAL RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include changes to global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity price changes on collateral requirements and timely recoveries of fuel and storm costs from customers, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and that they maintain their credit metrics.
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has an approximate $9 billion capital investment plan over the 2024 through 2026 period with approximately $2 billion of additional potential capital investments over the same period. Capital investments at Emera’s regulated utilities are subject to regulatory approval.
Emera plans to use cash from operations, debt raised at the utilities, equity, proceeds from the sale of its LIL equity interest, and the pending sale of NMGC, to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Generally, equity requirements in support of the Company’s capital investment plan are expected to be funded through issuance of preferred equity and issuance of common equity through Emera’s DRIP and ATM programs.
Emera has total committed credit facilities with varying maturities that cumulatively provide $2.8 billion CAD and $1.6 billion USD of credit, with approximately $1.5 billion CAD and $831 million USD undrawn and available at September 30, 2024. The Company was holding a cash balance of $244 million, which includes $4 million classified as assets held for sale, related to the pending sale of NMGC, at September 30, 2024. For further discussion, refer to the “Debt Management” section below.
26
Consolidated Cash Flow Highlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the nine months ended September 30, 2024 and 2023 include:
| millions of dollars | 2024 | 2023 | Change | |||||||||
| Cash, cash equivalents, and restricted cash, beginning of period |
$ | 588 | $ | 332 | $ | 256 | ||||||
| Provided by (used in): |
||||||||||||
| Operating cash flow before changes in working capital |
1,732 | 1,813 | (81) | |||||||||
| Change in working capital |
220 | 5 | 215 | |||||||||
| Operating activities |
$ | 1,952 | $ | 1,818 | $ | 134 | ||||||
| Investing activities |
(1,289) | (2,045) | 756 | |||||||||
| Financing activities |
(997) | 166 | (1,163) | |||||||||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale | 10 | 2 | 8 | |||||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period |
$ | 264 | $ | 273 | $ | (9) | ||||||
Cash Flow from Operating Activities
Net cash provided by operating activities increased $134 million to $1,952 million for the nine months ended September 30, 2024, compared to $1,818 million for the same period in 2023.
Cash from operations before changes in working capital decreased $81 million year-over-year. This decrease was due to increased storm cost recovery regulatory asset related to Hurricane Helene at TEC, lower fuel clause recoveries at TEC, and reversal of the Nova Scotia Cap-and-Trade Program provision in Q1 2023. These were partially offset by the favourable change in regulatory liabilities due to the 2023 gas hedge settlements at NMGC, increased electric revenue at NSPI, proceeds from the FAM asset sale to Invest Nova Scotia at NSPI, and increased earnings and recovery of the conservation clause expense at PGS.
Changes in working capital increased operating cash flows by $215 million year-over-year. This increase was due to favourable changes in cash collateral positions at NSPI, reversal of the Nova Scotia Cap-and-Trade accrual at NSPI in Q1 2023, timing of accounts receivable at TEC, and favourable changes in fuel inventory at NSPI and TEC. These were partially offset by unfavourable changes in accounts receivable at NMGC due to the receipt of its 2023 gas hedge settlement and unfavourable changes in cash collateral positions and lower natural gas inventory at EES.
Cash Flow from Investing Activities
Net cash used in investing activities decreased $756 million to $1,289 million for the nine months ended September 30, 2024, compared to $2,045 million for the same period in 2023. The decrease was due to the proceeds of $927 million received on the sale of Emera’s LIL equity interest, partially offset by higher capital investment.
Capital investments, including AFUDC, for the nine months ended September 30, 2024, were $2,259 million, compared to $2,090 million for the same period in 2023. Details of the 2024 capital investment by segment are shown below:
| ● | $1,375 million – Florida Electric Utility (2023 – $1,212 million); |
| ● | $389 million – Canadian Electric Utilities (2023 – $346 million); |
| ● | $437 million – Gas Utilities and Infrastructure (2023 – $482 million); |
| ● | $54 million – Other Electric Utilities (2023 – $43 million); and |
| ● | $4 million – Other (2023 – $7 million). |
27
Cash Flow from Financing Activities
Net cash used in financing activities increased $1,163 million to $997 million for the nine months ended September 30, 2024, compared to cash provided by financing activities of $166 million for the same period in 2023. This increase was due to higher repayment of Emera’s committed credit facilities using the LIL transaction proceeds, repayment of short-term debt at TEC, 2023 proceeds of long-term debt at NSPI, and retirement of long-term debt at Emera, TEC and NMGI. These were partially offset by proceeds from the fixed-to-fixed reset rate junior subordinated notes issuance by EUSHI Finance Inc., issuance of long-term debt at TEC, higher issuance of common stock and lower net repayments under committed credit facilities at EES and NSPI.
Contractual Obligations
As at September 30, 2024, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total | |||||||||||||||||||||
| Long-term debt principal (1) |
$ | 24 | $ | 512 | $ | 3,112 | $ | 83 | $ | 582 | $ | 13,729 | $ | 18,042 | ||||||||||||||
| Interest payment obligations (2)(3) |
350 | 860 | 762 | 671 | 667 | 8,558 | 11,868 | |||||||||||||||||||||
| Transportation (4)(5) |
216 | 654 | 483 | 488 | 420 | 3,401 | 5,662 | |||||||||||||||||||||
| Purchased power (6) |
82 | 289 | 275 | 324 | 325 | 3,562 | 4,857 | |||||||||||||||||||||
| Capital projects |
712 | 245 | 62 | 10 | 1 | 1 | 1,031 | |||||||||||||||||||||
| Fuel, gas supply and storage (7) |
217 | 445 | 86 | 11 | 4 | - | 763 | |||||||||||||||||||||
| Asset retirement obligations |
6 | 3 | 1 | 1 | 2 | 406 | 419 | |||||||||||||||||||||
| Pension and post-retirement obligations (8) |
7 | 30 | 39 | 48 | 32 | 154 | 310 | |||||||||||||||||||||
| Other |
34 | 148 | 62 | 50 | 37 | 233 | 564 | |||||||||||||||||||||
| $ | 1,648 | $ | 3,186 | $ | 4,882 | $ | 1,686 | $ | 2,070 | $ | 30,044 | $ | 43,516 | |||||||||||||||
As detailed below, contractual obligations at September 30, 2024 includes those related to NMGC. On completion of the sale of NMGC, all of the remaining future contractual obligations will be transferred to the buyer. For further details on the pending transaction, refer to the “Other Developments” section.
(1) Includes $653 million related to NMGC (2026: $95 million and $558 million thereafter).
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at September 30, 2024, including any expected required payment under associated swap agreements.
(3) Includes $338 million related to NMGC (2024: $7 million, 2025: $24 million, 2026: $24 million, 2027: $22 million, 2028: $22 million, and $239 million thereafter).
(4) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $128 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(5) Includes $77 million related to NMGC (2024: $10 million, 2025: $27 million, 2026: $19 million, 2027: $12 million, and 2028: $9 million).
(6) Annual requirement to purchase electricity from Independent Power Producers or other utilities over varying contract lengths.
(7) Includes $203 million related to NMGC (2024: $52 million, 2025: $107 million, 2026: $36 million, 2027: $5 million, and 2028: $3 million).
(8) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans, plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In December 2023, the UARB approved the collection of up to $164 million from NSPI for the recovery of Maritime Link costs in 2024. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.
Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Nalcor Energy’s use, if requested, effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
28
Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD, per the table below as at September 30, 2024.
| millions of Canadian dollars (unless otherwise indicated) | Maturity | Credit Facilities |
Utilized | Undrawn and Available |
||||||||||||
|
|
||||||||||||||||
| Emera – Unsecured committed revolving credit facility |
June 2029 | $ | 1,300 | $ | 263 | $ | 1,037 | |||||||||
|
|
||||||||||||||||
| TEC (in USD) – Unsecured committed revolving credit facility |
December 2028 | 800 | 386 | 414 | ||||||||||||
|
|
||||||||||||||||
| NSPI – Unsecured committed revolving credit facility |
June 2029 | 800 | 291 | 509 | ||||||||||||
|
|
||||||||||||||||
| TECO Finance (in USD) – Unsecured committed revolving credit facility |
December 2028 | 400 | 294 | 106 | ||||||||||||
|
|
||||||||||||||||
| NSPI – Unsecured non-revolving facility |
June 2025 | 300 | 300 | - | ||||||||||||
|
|
||||||||||||||||
| PGS (in USD) – Unsecured revolving facility |
December 2028 | 250 | 65 | 185 | ||||||||||||
|
|
||||||||||||||||
| Emera – Unsecured non-revolving facility |
December 2024 | 200 | 200 | - | ||||||||||||
|
|
||||||||||||||||
| Emera – Unsecured non-revolving facility |
February 2025 | 200 | 200 | - | ||||||||||||
|
|
||||||||||||||||
| NMGC (in USD) – Unsecured revolving credit facility |
December 2026 | 125 | 16 | 109 | ||||||||||||
|
|
||||||||||||||||
| Other (in USD) – Unsecured committed revolving credit facilities |
Various | 21 | 4 | 17 | ||||||||||||
|
|
||||||||||||||||
Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at September 30, 2024.
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On July 12, 2024, TEC repaid a $300 million USD note upon maturity. This note was repaid with proceeds from commercial paper.
On April 1, 2024, TEC amended its $800 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in commercial terms from the prior agreement.
On January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 4.90 per cent with a maturity date of March 1, 2029. Proceeds from the issuance were primarily used for the repayment of short-term borrowings outstanding under the 5-year credit facility.
Canadian Electric Utilities
On June 24, 2024, NSPI amended its unsecured committed revolving credit facility to extend the maturity date from December 16, 2027 to June 24, 2029. There were no other material changes in commercial terms from the prior agreement.
On June 24, 2024, NSPI amended its unsecured non-revolving credit facility to extend the maturity date from July 15, 2024 to June 24, 2025 and reduce the facility from $400 million to $300 million. There were no other material changes in commercial terms from the prior agreement.
On June 13, 2024, NSPI entered a non-revolving credit facility to finance the Battery Energy Storage Project. NSPI can request funds under the facility quarterly for amounts related to incurred project costs up to the total commitment of the lessor of $120 million and 45.06 per cent of the total eligible project costs over the term of the agreement. The facility will be available until 6 months after completion of the project, not to exceed May 21, 2027 and matures 20 years following the end of the period. As at September 30, 2024, NSPI had utilized $16 million from the facility, which bears interest at 2.51 per cent.
Gas Utilities and Infrastructure
On July 30, 2024, NMGI repaid its $150 million USD fixed rate notes upon maturity.
29
Other Electric Utilities
On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend the maturity date from February 19, 2025 to July 19, 2028. There were no other material changes in commercial terms from the prior agreement.
Other
On June 24, 2024, Emera amended its unsecured committed revolving credit facility increasing the facility from $900 million to $1,300 million. Emera also extended the maturity date from June 24, 2027 to June 24, 2029. There were no other material changes in commercial terms from the prior agreement.
On June 24, 2024, Emera repaid its $400 million unsecured non-revolving credit facility set to mature in August 2024.
On June 18, 2024, EUSHI Finance, Inc., completed an issuance of $500 million USD fixed-to-fixed reset rate junior subordinated notes. The notes initially bear interest at a rate of 7.625 per cent, and will reset on December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S. treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, Inc., at its option, may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-annual interest payment date thereafter, at a redemption price equal to the principal amount.
Proceeds from the $500 million USD note issuance discussed above were used to repay an Emera US Finance LP $300 million USD senior note upon maturity in June 2024, and to repay an NMGI $150 million USD fixed rate notes upon maturity in July 2024. The remaining proceeds were used for general corporate purposes.
On June 17, 2024, Emera repaid $200 million from the December 2024 unsecured non-revolving facility, decreasing the facility from $400 million to $200 million. There were no other material changes in commercial terms from the prior agreement.
On April 1, 2024, TECO Finance amended its $400 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in commercial terms from the prior agreement.
On February 16, 2024, Emera amended its $400 million unsecured non-revolving facility to extend the maturity date from February 19, 2024 to February 19, 2025. There were no other changes in commercial terms from the prior agreement. On July 19, 2024, Emera reduced the amount of the facility from $400 million to $200 million.
Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2023
annual MD&A, with material updates as noted below:
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 2025. The amount committed as at September 30, 2024 was $58 million (December 31, 2023 – $56 million).
Emera has provided an indemnity to a counterparty in relation to certain future tax amounts that could arise from specific future changes in Canadian federal law, subject to certain conditions and limitations. No such changes in law have been proposed at this time. A reasonable estimate of the potential amount of future payments that could result from future claims under this indemnity cannot be calculated, but the risk of having to make any significant payments under this indemnity is considered to be remote.
30
Outstanding Stock Data
Common Stock
| Issued and outstanding: | millions of shares |
millions of dollars |
||||||
|
|
||||||||
| Balance, December 31, 2023 |
284.12 | $ | 8,462 | |||||
|
|
||||||||
| Issuance of common stock under ATM program (1) |
3.61 | 181 | ||||||
|
|
||||||||
| Issued under the DRIP, net of discounts |
4.61 | 217 | ||||||
|
|
||||||||
| Senior management stock options exercised and Employee Share Purchase Plan |
0.50 | 24 | ||||||
|
|
||||||||
| Balance, September 30, 2024 |
292.84 | $ | 8,884 | |||||
|
|
||||||||
(1) For the three months ended September 30, 2024, 2,882,000 common shares were issued under Emera’s ATM program at an average price of $51.18 per share for gross proceeds of $148 million ($146 million, net of after-tax issuance costs). For the nine months ended September 30, 2024, 3,606,996 common shares were issued under Emera’s ATM program at an average price of $50.58 per share for gross proceeds of $182 million ($181 million net of after-tax issuance costs). As at September 30, 2024, an aggregate gross sales limit of $18 million remained available for issuance under the ATM program.
As at November 6, 2024, the amount of issued and outstanding common shares was 292.9 million.
If all outstanding stock options were converted as at November 6, 2024, an additional 3.8 million common shares would be issued and outstanding.
Preferred Stock
As at November 6, 2024, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
TRANSACTIONS WITH RELATED PARTIES
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities, in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.
Significant transactions between Emera and its associated companies are as follows:
| ● | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $41 million for the three months ended September 30, 2024 (2023 – $44 million) and $123 million for the nine months ended September 30, 2024 (2023 – $122 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. For further details, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPML” and “Contractual Obligations” sections. |
| ● | Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $2 million for the three months ended September 30, 2024 (2023 – $2 million) and $8 million for the nine months ended September 30, 2024 (2023 – $10 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at September 30, 2024 and at December 31, 2023.
31
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2023 annual MD&A.
Derivative Assets and Liabilities Recognized on the Balance Sheet
| As at millions of dollars |
September 30 2024 |
December 31 2023 |
||||||||||
|
|
||||||||||||
| Regulatory Deferral: |
||||||||||||
| Derivative instrument assets (1) |
$ | 39 | $ | 16 | ||||||||
|
|
||||||||||||
| Derivative instrument liabilities (2) |
(46) | (76) | ||||||||||
|
|
||||||||||||
| Regulatory assets (1) |
54 | 88 | ||||||||||
|
|
||||||||||||
| Regulatory liabilities (2) |
(24) | (17) | ||||||||||
|
|
||||||||||||
| Net asset |
$ | 23 | $ | 11 | ||||||||
|
|
||||||||||||
| HFT Derivatives: |
||||||||||||
| Derivative instrument assets (1) |
$ | 131 | $ | 202 | ||||||||
|
|
||||||||||||
| Derivative instrument liabilities (2) |
(409) | (421) | ||||||||||
|
|
||||||||||||
| Net liability |
$ | (278) | $ | (219) | ||||||||
|
|
||||||||||||
| Other Derivatives: |
||||||||||||
| Derivative instrument assets (1) |
$ | 17 | $ | 22 | ||||||||
|
|
||||||||||||
| Derivative instrument liabilities (2) |
(2) | (7) | ||||||||||
|
|
||||||||||||
| Net asset |
$ | 15 | $ | 15 | ||||||||
|
|
||||||||||||
(1) Current, other and held for sale assets.
(2) Current, long-term and held for sale liabilities.
Realized and Unrealized Gains (Losses) Recognized in Net Income
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
|
|
||||||||||||||||
| Regulatory Deferral: |
||||||||||||||||
| Regulated fuel for generation and purchased power (1) |
$ | (15) | $ | 6 | $ | (36) | $ | 70 | ||||||||
|
|
||||||||||||||||
| HFT Derivatives: |
||||||||||||||||
| Non-regulated operating revenues |
$ | 59 | $ | 90 | $ | 209 | $ | 907 | ||||||||
|
|
||||||||||||||||
| Other Derivatives: |
||||||||||||||||
| OM&G |
$ | 22 | $ | (20) | $ | 8 | $ | (12) | ||||||||
|
|
||||||||||||||||
| Other income, net |
5 | (18) | (15) | - | ||||||||||||
|
|
||||||||||||||||
| Net gains (losses) |
$ | 27 | $ | (38) | $ | (7) | $ | (12) | ||||||||
|
|
||||||||||||||||
| Total net gains |
$ | 71 | $ | 58 | $ | 166 | $ | 965 | ||||||||
|
|
||||||||||||||||
(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.
As of September 30, 2024, the unrealized gain in accumulated other comprehensive income was $12 million, after-tax (December 31, 2023 – $14 million, after-tax). For the three and nine months ended September 30, 2024, unrealized gains of $1 million (2023 – $1 million) and $2 million (2023 – $2 million), respectively, have been reclassified into interest expense.
32
DISCLOSURE AND INTERNAL CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. The Company’s internal control framework is based on criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at September 30, 2024, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.
There were no changes in the Company’s ICFR during the quarter ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. In Q3 2024, the Company recognized $210 million CAD ($155 million USD), pre-tax, in non-cash goodwill impairment related to the pending sale of NMGC. For more formation on the goodwill impairment, refer to note 19 in the condensed consolidated interim financial statements. There were no other material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2023 annual MD&A.
CHANGES IN ACCOUNTING POLICIES AND PRACTICES
Future Accounting Pronouncements
The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.
33
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting–Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard updates are to be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements disclosures.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.
Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. The Company does not expect a material impact on its consolidated financial statements disclosures as a result of adoption of the standard.
34
SUMMARY OF QUARTERLY RESULTS
| For the quarter ended millions of dollars (except per share amounts) | |
Q3 2024 |
|
|
Q2 2024 |
|
|
Q1 2024 |
|
|
Q4 2023 |
|
|
Q3 2023 |
|
|
Q2 2023 |
|
|
Q1 2023 |
|
|
Q4 2022 |
| ||||||||
| Operating revenues |
$ | 1,802 | $ | 1,617 | $ | 2,018 | $ | 1,972 | $ | 1,740 | $ | 1,418 | $ | 2,433 | $ | 2,358 | ||||||||||||||||
| Net income attributable to common shareholders | $ | 4 | $ | 129 | $ | 207 | $ | 289 | $ | 101 | $ | 28 | $ | 560 | $ | 483 | ||||||||||||||||
| Adjusted net income |
$ | 236 | $ | 151 | $ | 216 | $ | 175 | $ | 204 | $ | 162 | $ | 268 | $ | 249 | ||||||||||||||||
| EPS – basic |
$ | 0.01 | $ | 0.45 | $ | 0.73 | $ | 1.04 | $ | 0.37 | $ | 0.10 | $ | 2.07 | $ | 1.80 | ||||||||||||||||
| EPS – diluted |
$ | 0.01 | $ | 0.45 | $ | 0.73 | $ | 1.04 | $ | 0.37 | $ | 0.10 | $ | 2.07 | $ | 1.80 | ||||||||||||||||
| Adjusted EPS – basic |
$ | 0.81 | $ | 0.53 | $ | 0.76 | $ | 0.63 | $ | 0.75 | $ | 0.60 | $ | 0.99 | $ | 0.93 |
Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the “Significant Items Affecting Earnings” section.
35
Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
September 30, 2024 and 2023
1
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars (except per share amounts) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
|
|
||||||||||||||||
| Operating revenues |
||||||||||||||||
| Regulated electric |
$ | 1,534 | $ | 1,598 | $ | 4,431 | $ | 4,333 | ||||||||
|
|
||||||||||||||||
| Regulated gas |
291 | 257 | 1,134 | 1,100 | ||||||||||||
|
|
||||||||||||||||
| Non-regulated |
(23) | (115) | (128) | 158 | ||||||||||||
|
|
||||||||||||||||
| Total operating revenues (note 5) |
1,802 | 1,740 | 5,437 | 5,591 | ||||||||||||
|
|
||||||||||||||||
| Operating expenses |
||||||||||||||||
| Regulated fuel for generation and purchased power |
484 | 530 | 1,487 | 1,401 | ||||||||||||
|
|
||||||||||||||||
| Regulated cost of natural gas |
46 | 58 | 282 | 392 | ||||||||||||
|
|
||||||||||||||||
| Operating, maintenance and general expenses (“OM&G”) |
432 | 497 | 1,415 | 1,398 | ||||||||||||
|
|
||||||||||||||||
| Provincial, state and municipal taxes |
110 | 117 | 325 | 326 | ||||||||||||
|
|
||||||||||||||||
| Depreciation and amortization |
293 | 266 | 866 | 785 | ||||||||||||
|
|
||||||||||||||||
| Impairment charges (note 19) |
221 | - | 221 | - | ||||||||||||
|
|
||||||||||||||||
| Total operating expenses |
1,586 | 1,468 | 4,596 | 4,302 | ||||||||||||
|
|
||||||||||||||||
| Income from operations |
216 | 272 | 841 | 1,289 | ||||||||||||
|
|
||||||||||||||||
| Income from equity investments (note 7) |
25 | 32 | 87 | 103 | ||||||||||||
|
|
||||||||||||||||
| Other income, net (note 8) |
14 | 15 | 232 | 107 | ||||||||||||
|
|
||||||||||||||||
| Interest expense, net (note 9) |
241 | 235 | 725 | 684 | ||||||||||||
|
|
||||||||||||||||
| Income before provision for income taxes |
14 | 84 | 435 | 815 | ||||||||||||
|
|
||||||||||||||||
| Income tax (recovery) expense (note 10) |
(9) | (34) | 40 | 77 | ||||||||||||
|
|
||||||||||||||||
| Net income |
23 | 118 | 395 | 738 | ||||||||||||
|
|
||||||||||||||||
| Non-controlling interest in subsidiaries (“NCI”) |
1 | 1 | 1 | 1 | ||||||||||||
|
|
||||||||||||||||
| Preferred stock dividends |
18 | 16 | 54 | 48 | ||||||||||||
|
|
||||||||||||||||
| Net income attributable to common shareholders |
$ | 4 | $ | 101 | $ | 340 | $ | 689 | ||||||||
|
|
||||||||||||||||
| Weighted average shares of common stock outstanding (in millions) (note 12) |
||||||||||||||||
| Basic |
290.0 | 273.6 | 287.5 | 272.2 | ||||||||||||
|
|
||||||||||||||||
| Diluted |
290.1 | 273.8 | 287.6 | 272.5 | ||||||||||||
|
|
||||||||||||||||
| Earnings per common share (note 12) |
||||||||||||||||
| Basic |
$ | 0.01 | $ | 0.37 | $ | 1.18 | $ | 2.53 | ||||||||
|
|
||||||||||||||||
| Diluted |
$ | 0.01 | $ | 0.37 | $ | 1.18 | $ | 2.53 | ||||||||
|
|
||||||||||||||||
| Dividends per common share declared |
$ | 0.7175 | $ | 0.6900 | $ | 2.1525 | $ | 2.0700 | ||||||||
|
|
||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
2
Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
|
|
||||||||||||||||
| Net income |
$ | 23 | $ | 118 | $ | 395 | $ | 738 | ||||||||
|
|
||||||||||||||||
| Other comprehensive income (loss) (“OCI”), net of tax |
||||||||||||||||
| Foreign currency translation adjustment (1) |
(165) | 233 | 240 | (14) | ||||||||||||
|
|
||||||||||||||||
| Unrealized gains (losses) on net investment hedges (2) |
22 | (33) | (33) | 3 | ||||||||||||
|
|
||||||||||||||||
| Cash flow hedges |
||||||||||||||||
| Net derivative gains |
- | - | - | 1 | ||||||||||||
|
|
||||||||||||||||
| Less: reclassification adjustment for gains included in income |
(1) | (1) | (2) | (2) | ||||||||||||
|
|
||||||||||||||||
| Net effects of cash flow hedges |
(1) | (1) | (2) | (1) | ||||||||||||
|
|
||||||||||||||||
| Unrealized gains on available-for-sale investment |
- | - | 1 | - | ||||||||||||
|
|
||||||||||||||||
| Net change in unrecognized pension and post-retirement benefit obligation |
- | 1 | 1 | (4) | ||||||||||||
|
|
||||||||||||||||
| OCI (3) |
$ | (144) | $ | 200 | $ | 207 | $ | (16) | ||||||||
|
|
||||||||||||||||
| Comprehensive (loss) income |
(121) | 318 | 602 | 722 | ||||||||||||
|
|
||||||||||||||||
| Comprehensive income attributable to NCI |
1 | 1 | 1 | 1 | ||||||||||||
|
|
||||||||||||||||
| Comprehensive (loss) income of Emera Incorporated |
$ | (122) | $ | 317 | $ | 601 | $ | 721 | ||||||||
|
|
||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Net of tax recovery of $2 million (2023 – $3 million expense) for the three months ended September 30, 2024 and tax expense of $3 million (2023 – $4 million recovery) for the nine months ended September 30, 2024.
(2) The Company has designated $1.2 billion United States dollar (“USD”) denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations.
(3) Net of tax recovery of $2 million (2023 – $3 million expense) for the three months ended September 30, 2024 and tax expense of $3 million (2023 – $4 million recovery) for the nine months ended September 30, 2024.
3
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at | September 30 | December 31 | ||||||
| millions of dollars | 2024 | 2023 | ||||||
|
|
||||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 240 | $ | 567 | ||||
|
|
||||||||
| Restricted cash |
20 | 21 | ||||||
|
|
||||||||
| Inventory |
746 | 790 | ||||||
|
|
||||||||
| Derivative instruments (notes 14 and 15) |
129 | 174 | ||||||
|
|
||||||||
| Regulatory assets (note 6) |
202 | 339 | ||||||
|
|
||||||||
| Receivables and other current assets (note 17) |
1,528 | 1,817 | ||||||
|
|
||||||||
| Assets held for sale (note 3) |
108 | - | ||||||
|
|
||||||||
| 2,973 | 3,708 | |||||||
| Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $10,320 and $9,994, respectively |
24,459 | 24,376 | ||||||
|
|
||||||||
| Other assets |
||||||||
| Deferred income taxes (note 10) |
224 | 208 | ||||||
|
|
||||||||
| Derivative instruments (notes 14 and 15) |
44 | 66 | ||||||
|
|
||||||||
| Regulatory assets (note 6) |
2,696 | 2,766 | ||||||
|
|
||||||||
| Net investment in direct finance and sales type leases |
607 | 621 | ||||||
|
|
||||||||
| Investments subject to significant influence (note 7) |
652 | 1,402 | ||||||
|
|
||||||||
| Goodwill (note 19) |
5,498 | 5,871 | ||||||
|
|
||||||||
| Other long-term assets |
482 | 462 | ||||||
|
|
||||||||
| Assets held for sale (note 3) |
2,039 | - | ||||||
|
|
||||||||
| 12,242 | 11,396 | |||||||
|
|
||||||||
| Total assets |
$ | 39,674 | $ | 39,480 | ||||
|
|
||||||||
4
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited) – Continued
| Liabilities and Equity |
||||||||
| Current liabilities |
||||||||
| Short-term debt (note 20) |
$ | 1,409 | $ | 1,433 | ||||
|
|
||||||||
| Current portion of long-term debt (note 21) |
82 | 676 | ||||||
|
|
||||||||
| Accounts payable |
1,319 | 1,454 | ||||||
|
|
||||||||
| Derivative instruments (notes 14 and 15) |
364 | 386 | ||||||
|
|
||||||||
| Regulatory liabilities (note 6) |
302 | 168 | ||||||
|
|
||||||||
| Other current liabilities |
535 | 427 | ||||||
|
|
||||||||
| Liabilities associated with assets held for sale (note 3) |
132 | - | ||||||
|
|
||||||||
| 4,143 | 4,544 | |||||||
|
|
||||||||
| Long-term liabilities |
||||||||
| Long-term debt (note 21) |
17,180 | 17,689 | ||||||
|
|
||||||||
| Deferred income taxes (note 10) |
2,181 | 2,352 | ||||||
|
|
||||||||
| Derivative instruments (notes 14 and 15) |
93 | 118 | ||||||
|
|
||||||||
| Regulatory liabilities (note 6) |
1,372 | 1,604 | ||||||
|
|
||||||||
| Pension and post-retirement liabilities (note 18) |
254 | 265 | ||||||
|
|
||||||||
| Other long-term liabilities (note 7) |
879 | 820 | ||||||
|
|
||||||||
| Liabilities associated with assets held for sale (note 3) |
1,130 | - | ||||||
|
|
||||||||
| 23,089 | 22,848 | |||||||
|
|
||||||||
| Equity |
||||||||
| Common stock (note 11) |
8,884 | 8,462 | ||||||
|
|
||||||||
| Cumulative preferred stock |
1,422 | 1,422 | ||||||
|
|
||||||||
| Contributed surplus |
84 | 82 | ||||||
|
|
||||||||
| Accumulated other comprehensive income (“AOCI’) (note 13) |
512 | 305 | ||||||
|
|
||||||||
| Retained earnings |
1,526 | 1,803 | ||||||
|
|
||||||||
| Total Emera Incorporated equity |
12,428 | 12,074 | ||||||
|
|
||||||||
| NCI |
14 | 14 | ||||||
|
|
||||||||
| Total equity |
12,442 | 12,088 | ||||||
|
|
||||||||
| Total liabilities and equity |
$ | 39,674 | $ | 39,480 | ||||
|
|
||||||||
Commitments and contingencies (note 22)
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
Approved on behalf of the Board of Directors
| “M. Jacqueline Sheppard” |
“Scott Balfour” | |
| Chair of the Board |
President and Chief Executive Officer | |
5
Emera Incorporated
Condensed Consolidated Statements of Cash Flows (Unaudited)
| For the | Nine months ended September 30 | |||||||
| millions of dollars | 2024 | 2023 | ||||||
|
|
||||||||
| Operating activities |
||||||||
| Net income |
$ | 395 | $ | 738 | ||||
|
|
||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
878 | 794 | ||||||
|
|
||||||||
| Income from equity investments, net of dividends |
(10) | (17) | ||||||
|
|
||||||||
| Allowance for funds used during construction (“AFUDC”) – equity |
(36) | (27) | ||||||
|
|
||||||||
| Deferred income taxes, net |
14 | 57 | ||||||
|
|
||||||||
| Net change in pension and post-retirement liabilities |
(40) | (56) | ||||||
|
|
||||||||
| Fuel adjustment mechanism (“FAM”) |
18 | (35) | ||||||
|
|
||||||||
| Net change in fair value (“FV”) of derivative instruments |
50 | (633) | ||||||
|
|
||||||||
| Net change in regulatory assets and liabilities |
231 | 387 | ||||||
|
|
||||||||
| Net change in capitalized transportation capacity |
134 | 556 | ||||||
|
|
||||||||
| Goodwill impairment charge |
210 | - | ||||||
|
|
||||||||
| Gain on sale of LIL, excluding transaction costs |
(191) | - | ||||||
|
|
||||||||
| Other operating activities, net |
79 | 49 | ||||||
|
|
||||||||
| Changes in non-cash working capital (note 23) |
220 | 5 | ||||||
|
|
||||||||
| Net cash provided by operating activities |
1,952 | 1,818 | ||||||
|
|
||||||||
| Investing activities |
||||||||
| Additions to PP&E |
(2,223) | (2,063) | ||||||
|
|
||||||||
| Proceeds from disposal of investment subject to significant influence |
927 | - | ||||||
|
|
||||||||
| Other investing activities |
7 | 18 | ||||||
|
|
||||||||
| Net cash used in investing activities |
(1,289) | (2,045) | ||||||
|
|
||||||||
| Financing activities |
||||||||
|
|
||||||||
| Change in short-term debt, net |
(83) | 47 | ||||||
|
|
||||||||
| Proceeds from long-term debt, net of issuance costs |
1,359 | 537 | ||||||
|
|
||||||||
| Retirement of long-term debt |
(1,082) | (113) | ||||||
|
|
||||||||
| Net (repayments) proceeds under committed credit facilities |
(941) | 93 | ||||||
|
|
||||||||
| Issuance of common stock, net of issuance costs |
200 | 23 | ||||||
|
|
||||||||
| Dividends on common stock |
(399) | (358) | ||||||
|
|
||||||||
| Dividends on preferred stock |
(54) | (48) | ||||||
|
|
||||||||
| Other financing activities |
3 | (15) | ||||||
|
|
||||||||
| Net cash (used in) provided by financing activities |
(997) | 166 | ||||||
|
|
||||||||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash associated with assets held for sale |
10 | 2 | ||||||
|
|
||||||||
| Net decrease in cash, cash equivalents, restricted cash, and cash associated with assets held for sale |
(324) | (59) | ||||||
|
|
||||||||
| Cash, cash equivalents and restricted cash, beginning of period |
588 | 332 | ||||||
|
|
||||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period |
$ | 264 | $ | 273 | ||||
|
|
||||||||
| Cash, cash equivalents, and restricted cash consists of: |
||||||||
| Cash |
$ | 235 | $ | 250 | ||||
|
|
||||||||
| Short-term investments |
5 | 4 | ||||||
|
|
||||||||
| Restricted cash |
20 | 19 | ||||||
|
|
||||||||
| Cash associated with assets held for sale |
4 | - | ||||||
|
|
||||||||
| Total |
$ | 264 | $ | 273 | ||||
|
|
||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
6
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| millions of dollars | Common
Stock |
Preferred
Stock |
Contributed
Surplus |
AOCI | Retained
Earnings |
NCI | Total
Equity |
|||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the three months ended September 30, 2024 |
| |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, June 30, 2024 |
$ | 8,657 | $ | 1,422 | $ | 83 | $ | 656 | $ | 1,729 | $ | 14 | $ | 12,561 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 22 | 1 | 23 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OCI, net of tax recovery of $2 million |
- | - | - | (144) | - | - | (144) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on preferred stock (1) |
- | - | - | - | (18) | - | (18) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on common stock ($0.7175/share) |
- | - | - | - | (207) | - | (207) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts |
75 | - | - | - | - | - | 75 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs |
146 | - | - | - | - | - | 146 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”) |
6 | - | 1 | - | - | - | 7 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
- | - | - | - | - | (1) | (1) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, September 30, 2024 |
$ | 8,884 | $ | 1,422 | $ | 84 | $ | 512 | $ | 1,526 | $ | 14 | $ | 12,442 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the nine months ended September 30, 2024 |
| |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, December 31, 2023 |
$ | 8,462 | $ | 1,422 | $ | 82 | $ | 305 | $ | 1,803 | $ | 14 | $ | 12,088 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 394 | 1 | 395 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OCI, net of tax expense of $3 million |
- | - | - | 207 | - | - | 207 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on preferred stock (2) |
- | - | - | - | (54) | - | (54) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on common stock ($2.1525/share) |
- | - | - | - | (617) | - | (617) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issued under the DRIP, net of discounts |
217 | - | - | - | - | - | 217 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issuance of common stock under ATM program, net of after-tax issuance costs |
181 | - | - | - | - | - | 181 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Senior management stock options exercised and ECSPP |
24 | - | 2 | - | - | - | 26 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
- | - | - | - | - | (1) | (1) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, September 30, 2024 |
$ | 8,884 | $ | 1,422 | $ | 84 | $ | 512 | $ | 1,526 | $ | 14 | $ | 12,442 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Series A; $0.1364/share, Series B; $0.4298/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3953/share; Series J; $0.2656/share and Series L; $0.2875/share
(2) Series A; $0.4092/share, Series B; $1.2948/share, Series C; $1.2064/share, Series E; $0.8438/share, Series F; $0.7879/share; Series H; $1.1858/share; Series J; $0.7969/share and Series L; $0.8625/share
7
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| millions of dollars | Common
Stock |
Preferred
Stock |
Contributed
Surplus |
AOCI | Retained
Earnings |
NCI | Total
Equity |
|||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the three months ended September 30, 2023 |
| |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, June 30, 2023 |
$ | 7,922 | $ | 1,422 | $ | 81 | $ | 362 | $ | 1,798 | $ | 14 | $ | 11,599 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 117 | 1 | 118 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OCI, net of tax expense of $3 million | - | - | - | 200 | - | - | 200 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on preferred stock (1) |
- | - | - | - | (16) | - | (16) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on common stock ($0.6900/share) |
- | - | - | - | (188) | - | (188) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issued under the DRIP, net of discounts |
66 | - | - | - | - | - | 66 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Senior management stock options exercised and ECSPP |
5 | - | 1 | - | - | - | 6 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
- | - | - | - | - | (1) | (1) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, September 30, 2023 |
$ | 7,993 | $ | 1,422 | $ | 82 | $ | 562 | $ | 1,711 | $ | 14 | $ | 11,784 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the nine months ended September 30, 2023 |
| |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, December 31, 2022 |
$ | 7,762 | $ | 1,422 | $ | 81 | $ | 578 | $ | 1,584 | $ | 14 | $ | 11,441 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 737 | 1 | 738 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OCI, net of tax recovery of $4 million | - | - | - | (16) | - | - | (16) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on preferred stock (2) |
- | - | - | - | (48) | - | (48) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on common stock ($2.0700/share) |
- | - | - | - | (562) | - | (562) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issued under the DRIP, net of discount |
205 | - | - | - | - | - | 205 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Senior management stock options exercised and ECSPP |
26 | - | 1 | - | - | - | 27 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
- | - | - | - | - | (1) | (1) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, September 30, 2023 |
$ | 7,993 | $ | 1,422 | $ | 82 | $ | 562 | $ | 1,711 | $ | 14 | $ | 11,784 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Series A; $0.1364/share, Series B; $0.3955/share, Series C; $0.2951/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3063/share; Series J; $0.2656/share and Series L; $0.2875/share
(2) Series A; $0.4092/share, Series B; $1.1302/share, Series C; $0.8852/share, Series E; $0.8438/share, Series F; $0.7879/share; Series H; $0.9188/share; Series J; $0.7969/share and Series L; $0.8625/share
8
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at September 30, 2024 and 2023
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company that invests in electricity generation, transmission and distribution, and gas transmission and distribution.
At September 30, 2024, Emera’s reportable segments include the following:
| • | Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated electric utility in West Central Florida. |
| • | Canadian Electric Utilities, which includes: |
| • | Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia; and |
| • | a 100 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.8 billion, including AFUDC, transmission project between the island of Newfoundland and Nova Scotia. |
On June 4, 2024, Emera completed the sale of its 31.1 per cent indirect minority equity interest in the Labrador Island Link Partnership (“LIL”), which was previously included in the Canadian Electric Utilities segment. For further details, refer to note 3.
| • | Gas Utilities and Infrastructure, which includes: |
| • | Peoples Gas System, Inc. (“PGS”), a regulated gas distribution utility operating across Florida; |
| • | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico. On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the New Mexico Public Regulation Commission (“NMPRC”). For more information on the pending transaction, refer to note 3; |
| • | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy North America Canada Partnership (“Repsol Energy”), which expires in 2034; |
| • | SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida; and |
| • | a 12.9 per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, that transports natural gas throughout markets in Atlantic Canada and the northeastern United States. |
| • | Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include: |
| • | The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados; |
| • | Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island; and |
| • | a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia. |
9
| • | Emera’s other segment includes investments in energy-related non-regulated companies that are below the required threshold for reporting as separate segments and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments. This includes: |
| • | Emera Energy, which consists of: |
| • | Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; |
| • | Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and |
| • | a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. |
| • | Emera US Finance LP (“Emera Finance”), EUSHI Finance, Inc., and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera; |
| • | Block Energy LLC, a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers; |
| • | Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and |
| • | Other investments. |
Basis of Presentation
These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2023.
In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2024.
All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated.
Use of Management Estimates
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. In Q3 2024, the Company recognized $210 million CAD ($155 million USD), pre-tax, in non-cash goodwill impairment related to the pending sale of NMGC. For more formation on the goodwill impairment, refer to note 19. There were no other material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2023 annual audited consolidated financial statements.
10
Seasonal Nature of Operations
Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity and gas sales, and related transmission and distribution, vary during the year. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Certain quarters may also be impacted by weather and the number and severity of storms.
2. FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting–Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard updates are to be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements disclosures.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.
Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. The Company does not expect a material impact on its consolidated financial statements disclosures as a result of adoption of the standard.
11
3. DISPOSITIONS
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement to sell its indirect wholly owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024.
As the transaction proceeds will be lower than the carrying amount of the assets and liabilities being sold, Emera assessed the NMGC reporting unit for goodwill impairment by comparing the fair value (“FV”) of expected transaction proceeds to the carrying value of net assets, including goodwill of $366 million USD (“carrying amount”). The goodwill of the reporting unit was determined to be impaired and a non-cash goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million USD ($146 million USD, after-tax) was recorded in “Impairment Charges” on the Condensed Consolidated Statements of Income in Q3 2024.
Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an additional loss for the estimated future transaction costs of $16 million ($13 million after-tax), in addition to incurred transaction costs of $8 million ($6 million after-tax) recorded in “Other Income, net” on the Condensed Consolidated Statements of Income in Q3 2024.
The Company will continue to record depreciation on the NMGC assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $9 million ($7 million USD) has been recorded on these assets from August 5, 2024, the date they were classified as held for sale, to September 30, 2024.
12
Details of the assets and liabilities classified as held for sale are as follows:
| As at millions of dollars |
September 30 2024 |
|||
|
|
||||
| Cash and cash equivalents |
$ | 4 | ||
|
|
||||
| Inventory |
9 | |||
|
|
||||
| Derivative instruments |
14 | |||
|
|
||||
| Regulatory assets |
19 | |||
|
|
||||
| Receivables and other current assets |
62 | |||
|
|
||||
| Current assets held for sale |
$ | 108 | ||
|
|
||||
| PP&E |
1,672 | |||
|
|
||||
| Deferred income taxes |
54 | |||
|
|
||||
| Regulatory assets |
6 | |||
|
|
||||
| Goodwill |
284 | |||
|
|
||||
| Other long-term assets |
23 | |||
|
|
||||
| Long-term assets held for sale |
$ | 2,039 | ||
|
|
||||
| Total assets held for sale |
$ | 2,147 | ||
|
|
||||
| Short-term debt |
$ | 19 | ||
|
|
||||
| Regulatory liabilities |
13 | |||
|
|
||||
| Accounts payable and other current liabilities |
100 | |||
|
|
||||
| Current liabilities associated with assets held for sale |
132 | |||
|
|
||||
| Long-term debt |
653 | |||
|
|
||||
| Deferred income taxes |
211 | |||
|
|
||||
| Regulatory liabilities |
255 | |||
|
|
||||
| Other long-term liabilities |
11 | |||
|
|
||||
| Long-term liabilities associated with assets held for sale |
$ | 1,130 | ||
|
|
||||
| Total liabilities associated with assets held for sale |
$ | 1,262 | ||
|
|
||||
Sale of LIL Equity Interest
On June 4, 2024, Emera completed the sale of its 31.1 per cent indirect minority equity interest in the LIL for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable is held at FV and included in the gain on sale, after transaction costs. As of September 30, 2024, the estimated FV of the escrow proceeds receivable is $25 million. A gain on sale, after transaction costs, of $182 million, ($107 million, after tax and transaction costs), was recognized in “Other Income, net” on the Condensed Consolidated Statements of Income and included in the Other segment.
13
4. SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker.
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Gas Utilities and Infrastructure |
Other Electric Utilities |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the three months ended September 30, 2024 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 985 | $ | 399 | $ | 297 | $ | 150 | $ | (29 | ) | $ | - | $ | 1,802 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| Inter-segment revenues (1) | 3 | - | 3 | - | (8 | ) | 2 | - | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
988 | 399 | 300 | 150 | (37 | ) | 2 | 1,802 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 224 | 185 | - | 78 | - | (3 | ) | 484 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 46 | - | - | - | 46 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 196 | 87 | 103 | 39 | 12 | (5 | ) | 432 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 73 | 12 | 24 | 1 | - | - | 110 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 156 | 71 | 46 | 18 | 2 | - | 293 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 12 | 4 | 1 | 8 | - | 25 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income (expenses), net | 15 | 7 | 5 | 2 | (5 | ) | (10 | ) | 14 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 66 | 41 | 38 | 5 | 91 | - | 241 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Impairment charges | - | - | 11 | - | 210 | - | 221 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 36 | (4 | ) | 11 | - | (52 | ) | - | (9 | ) | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| NCI | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 18 | - | 18 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 252 | $ | 26 | $ | 30 | $ | 11 | $ | (315 | ) | $ | - | $ | 4 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| For the nine months ended September 30, 2024 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 2,639 | $ | 1,376 | $ | 1,150 | $ | 416 | $ | (144 | ) | $ | - | $ | 5,437 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| Inter-segment revenues (1) | 7 | - | 10 | - | 10 | (27 | ) | - | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
2,646 | 1,376 | 1,160 | 416 | (134 | ) | (27 | ) | 5,437 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 641 | 639 | - | 217 | - | (10 | ) | 1,487 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 282 | - | - | - | 282 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 587 | 299 | 333 | 106 | 105 | (15 | ) | 1,415 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 207 | 36 | 78 | 3 | 1 | - | 325 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 462 | 209 | 135 | 54 | 6 | - | 866 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 67 | 14 | 3 | 3 | - | 87 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income, net | 44 | 21 | 12 | 7 | 146 | 2 | 232 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 197 | 126 | 115 | 16 | 271 | - | 725 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Impairment charges | - | - | 11 | - | 210 | - | 221 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 72 | - | 60 | - | (92 | ) | - | 40 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| NCI | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 54 | - | 54 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 524 | $ | 155 | $ | 172 | $ | 29 | $ | (540 | ) | $ | - | $ | 340 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| As at September 30, 2024 |
|
|||||||||||||||||||||||||||
| Total assets | $ | 22,552 | $ | 7,697 | $ | 7,929 | $ | 1,337 | $ | 1,393 | $ | (1,234 | ) | $ | 39,674 | |||||||||||||
|
|
||||||||||||||||||||||||||||
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established by the related parties. Eliminated transactions are included in determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $8 million for the three months ended September 30, 2024, and $22 million for the nine months ended September 30, 2024 between the Gas Utilities and Infrastructure and Other segments.
14
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Gas Utilities and Infrastructure |
Other Electric Utilities |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the three months ended September 30, 2023 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 1,064 | $ | 388 | $ | 263 | $ | 145 | $ | (120 | ) | $ | - | $ | 1,740 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| Inter-segment revenues (1) | 2 | - | 1 | - | 26 | (29 | ) | - | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
1,066 | 388 | 264 | 145 | (94 | ) | (29 | ) | 1,740 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 282 | 173 | - | 76 | - | (1 | ) | 530 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 58 | - | - | - | 58 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 237 | 92 | 94 | 31 | 46 | (3 | ) | 497 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 83 | 12 | 20 | 1 | 1 | - | 117 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 143 | 68 | 36 | 17 | 2 | - | 266 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 29 | 5 | 1 | (3 | ) | - | 32 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income (expenses), net | 17 | 8 | 1 | 1 | (37 | ) | 25 | 15 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 67 | 43 | 34 | 5 | 86 | - | 235 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 43 | (1 | ) | 5 | - | (81 | ) | - | (34) | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| NCI | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 16 | - | 16 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 228 | $ | 38 | $ | 23 | $ | 16 | $ | (204 | ) | $ | - | $ | 101 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| For the nine months ended September 30, 2023 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 2,715 | $ | 1,232 | $ | 1,117 | $ | 385 | $ | 142 | $ | - | $ | 5,591 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Inter-segment revenues (1) | 6 | - | 8 | - | 26 | (40 | ) | - | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
2,721 | 1,232 | 1,125 | 385 | 168 | (40 | ) | 5,591 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 699 | 512 | - | 197 | - | (7 | ) | 1,401 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 392 | - | - | - | 392 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 621 | 283 | 295 | 93 | 123 | (17 | ) | 1,398 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 218 | 34 | 68 | 3 | 3 | - | 326 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 425 | 206 | 98 | 50 | 6 | - | 785 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 81 | 16 | 2 | 4 | - | 103 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income, net | 53 | 22 | 7 | 5 | 4 | 16 | 107 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 204 | 128 | 91 | 17 | 244 | - | 684 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 95 | (7 | ) | 49 | - | (60 | ) | - | 77 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| NCI | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 48 | - | 48 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income attributable to common shareholders | $ | 512 | $ | 179 | $ | 155 | $ | 31 | $ | (188 | ) | $ | - | $ | 689 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| As at December 31, 2023 |
| |||||||||||||||||||||||||||
| Total assets |
$ | 21,119 | $ | 8,634 | $ | 7,735 | $ | 1,311 | $ | 1,938 | $ | (1,257) | $ | 39,480 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established by the related parties. Eliminated transactions are included in determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $26 million for the three months ended September 30, 2023, and $69 million for the nine months ended September 30, 2023 between the Florida Electric Utility, Gas Utilities and Infrastructure and Other segments.
15
5. REVENUE
The following disaggregates the Company’s revenue by major source:
| Electric |
Gas | Other |
||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||||||
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Other Electric Utilities |
Gas Utilities and Infrastructure |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| For the three months ended September 30, 2024 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 643 | $ | 191 | $ | 56 | $ | 107 | $ | - | $ | - | $ | 997 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Commercial |
258 | 118 | 78 | 97 | - | - | 551 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Industrial |
56 | 70 | 9 | 24 | - | (4) | 155 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other electric |
101 | 10 | 1 | - | - | - | 112 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulatory deferrals |
(76) | - | 5 | - | - | - | (71) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other (1) |
6 | 10 | 1 | 51 | - | (3) | 65 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 16 | - | - | 16 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
988 | 399 | 150 | 295 | - | (7) | 1,825 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | (7) | - | (7) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 5 | 7 | (5) | 7 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | (37) | 14 | (23) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 5 | (37) | 9 | (23) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 988 | $ | 399 | $ | 150 | $ | 300 | $ | (37) | $ | 2 | $ | 1,802 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| For the nine months ended September 30, 2024 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 1,580 | $ | 737 | $ | 149 | $ | 499 | $ | - | $ | - | $ | 2,965 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Commercial |
710 | 371 | 224 | 361 | - | - | 1,666 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Industrial |
168 | 207 | 22 | 71 | - | (11) | 457 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other electric |
318 | 31 | 4 | - | - | - | 353 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulatory deferrals |
(145) | - | 13 | - | - | - | (132) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other (1) |
15 | 30 | 4 | 167 | - | (7) | 209 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 47 | - | - | 47 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
2,646 | 1,376 | 416 | 1,145 | - | (18) | 5,565 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 42 | - | 42 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 15 | 22 | (16) | 21 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | (198) | 7 | (191) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 15 | (134) | (9) | (128) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 2,646 | $ | 1,376 | $ | 416 | $ | 1,160 | $ | (134) | $ | (27) | $ | 5,437 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
(1) Other includes rental revenues which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
16
| Electric | Gas | Other | ||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||||||
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Other Electric Utilities |
Gas Utilities and Infrastructure |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| For the three months ended September 30, 2023 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 761 | $ | 179 | $ | 54 | $ | 100 | $ | - | $ | - | $ | 1,094 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Commercial |
313 | 111 | 74 | 76 | - | - | 574 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Industrial |
76 | 81 | 9 | 23 | - | (1) | 188 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other electric |
96 | 8 | 2 | - | - | - | 106 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulatory deferrals |
(184) | - | 3 | - | - | - | (181) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other (1) |
4 | 9 | 3 | 44 | - | (2) | 58 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 16 | - | - | 16 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
1,066 | 388 | 145 | 259 | - | (3) | 1,855 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 5 | 7 | (6) | 6 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | (101) | (20) | (121) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 5 | (94) | (26) | (115) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 1,066 | $ | 388 | $ | 145 | $ | 264 | $ | (94) | $ | (29) | $ | 1,740 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| For the nine months ended September 30, 2023 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 1,777 | $ | 671 | $ | 136 | $ | 529 | $ | - | $ | - | $ | 3,113 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Commercial |
813 | 345 | 204 | 311 | - | - | 1,673 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Industrial |
205 | 159 | 25 | 68 | - | (8) | 449 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other electric |
311 | 29 | 5 | - | - | - | 345 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulatory deferrals |
(399) | - | 9 | - | - | - | (390) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other (1) |
14 | 28 | 6 | 154 | - | (6) | 196 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 47 | - | - | 47 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
2,721 | 1,232 | 385 | 1,109 | - | (14) | 5,433 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 61 | - | 61 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 16 | 22 | (18) | 20 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | 85 | (8) | 77 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 16 | 168 | (26) | 158 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 2,721 | $ | 1,232 | $ | 385 | $ | 1,125 | $ | 168 | $ | (40) | $ | 5,591 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
(1) Other includes rental revenues which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
Remaining Performance Obligations:
Remaining performance obligations primarily represent gas transportation contracts, lighting contracts, and long-term steam supply arrangements with fixed contract terms. As of September 30, 2024, the aggregate amount of the transaction price allocated to remaining performance obligations was $453 million (2023 – $461 million), including $5 million related to NMGC. This amount includes $128 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2044.
17
6. REGULATORY ASSETS AND LIABILITIES
A summary of regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 6 in Emera’s 2023 annual audited consolidated financial statements. Updates to regulatory environments are included below.
| As at millions of dollars |
September 30 2024 (1) |
December 31 2023 |
||||||||||
|
|
||||||||||||
| Regulatory assets |
||||||||||||
| Deferred income tax regulatory assets |
$ | 1,117 | $ | 1,233 | ||||||||
|
|
||||||||||||
| TEC capital cost recovery for early retired assets |
693 | 671 | ||||||||||
|
|
||||||||||||
| NSPI FAM |
377 | 395 | ||||||||||
|
|
||||||||||||
| Pension and post-retirement medical plan |
360 | 364 | ||||||||||
|
|
||||||||||||
| Storm cost recovery clauses |
117 | 52 | ||||||||||
|
|
||||||||||||
| Deferrals related to derivative instruments |
46 | 88 | ||||||||||
|
|
||||||||||||
| Cost recovery clauses |
30 | 151 | ||||||||||
|
|
||||||||||||
| Environmental remediations |
26 | 26 | ||||||||||
|
|
||||||||||||
| Stranded cost recovery |
26 | 25 | ||||||||||
|
|
||||||||||||
| Other (2) |
106 | 100 | ||||||||||
|
|
||||||||||||
| $ | 2,898 | $ | 3,105 | |||||||||
|
|
||||||||||||
| Current |
$ | 202 | $ | 339 | ||||||||
|
|
||||||||||||
| Long-term |
2,696 | 2,766 | ||||||||||
|
|
||||||||||||
| Total regulatory assets |
$ | 2,898 | $ | 3,105 | ||||||||
|
|
||||||||||||
| Regulatory liabilities |
||||||||||||
| Deferred income tax regulatory liabilities |
$ | 806 | $ | 830 | ||||||||
|
|
||||||||||||
| Accumulated reserve – cost of removal |
686 | 849 | ||||||||||
|
|
||||||||||||
| Cost recovery clauses |
117 | 32 | ||||||||||
|
|
||||||||||||
| Deferrals related to derivative instruments |
24 | 17 | ||||||||||
|
|
||||||||||||
| BLPC Self-insurance fund (“SIF”) (note 24) |
30 | 29 | ||||||||||
|
|
||||||||||||
| Other (2) |
11 | 15 | ||||||||||
|
|
||||||||||||
| $ | 1,674 | $ | 1,772 | |||||||||
|
|
||||||||||||
| Current |
$ | 302 | $ | 168 | ||||||||
|
|
||||||||||||
| Long-term |
1,372 | 1,604 | ||||||||||
|
|
||||||||||||
| Total regulatory liabilities |
$ | 1,674 | $ | 1,772 | ||||||||
|
|
||||||||||||
(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at September 30, 2024, NMGC’s assets and liabilities were classified as held for sale and excluded from the table above. For further details on the pending transaction, refer to note 3.
(2) Comprised of regulatory assets and liabilities that are not individually significant.
Florida Electric Utility
Storm Reserve:
On September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall approximately 200 miles north of Tampa, in Taylor County, as a Category 4 hurricane. TEC’s service territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number of customers out of 100,000. As of September 30, 2024, TEC deferred $45 million USD to the storm reserve for future recovery, with a minimal impact to earnings. As at September 30, 2024, total restoration costs charged to the storm reserve account, including Q3 2024 costs related to Hurricane Helene, have exceeded the storm reserve balance and therefore $35 million USD has been deferred as a regulatory asset for future recovery.
Base Rates:
On April 2, 2024, TEC requested a base rate increase, reflecting an increased revenue requirement of $297 million USD, effective January 1, 2025, and additional adjustments of $100 million USD and $72 million USD for 2026 and 2027, respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and other resiliency and reliability projects. The rate case hearing occurred in August 2024.
18
Fuel Recovery:
On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction is due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected 2024 costs in the fall of 2023. On May 7, 2024, the Florida Public Service Commission approved the mid-course adjustment.
Canadian Electric Utilities
NSPI
Federal Loan Guarantee (“FLG”):
On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML, and the Province of Nova Scotia (the “Province”) on terms and conditions for a FLG of $500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of the replacement energy that was required during the several years of delay in the Muskrat Falls hydroelectricity project. Subject to certain conditions, including regulatory approval by the Nova Scotia Utility and Review Board (“UARB”), the net proceeds of the NSPML debt issuance will be transferred to NSPI as a refund of a portion of previous NSPML assessment payments and be applied against the FAM regulatory asset balance. NSPML will then increase its annual assessment charge to NSPI to recover the refund and related financing costs over a 28-year period. On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. A decision on the NSPML application would trigger the debt issuance and refund to NSPI and a decision on the NSPI application would reflect the necessary 2025 fuel rates to service the incremental NSPML debt.
Hurricane Fiona:
On June 27, 2024, the UARB approved the deferred recognition of $25 million in incremental operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. Following UARB approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The UARB also directed NSPI to reclassify $10 million of undepreciated costs related to assets retired because of Hurricane Fiona to “Regulatory assets” from “PP&E” on the Condensed Consolidated Balance Sheets. NSPI began amortizing both regulatory assets over a 10-year period beginning July 1, 2024.
Storm Rider:
On April 30, 2024, NSPI applied to the UARB for recovery of $22 million of major storm restoration costs deferred to NSPI’s UARB approved storm rider in 2023. If approved, the 2023 costs deferred to the storm rider would be recovered over a 12-month period beginning January 1, 2025.
Fuel Recovery:
On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, which resulted in a corresponding decrease of the FAM regulatory asset. NSPI is collecting the amortization and financing costs related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period, which began in Q2 2024, and is remitting those amounts to Invest Nova Scotia quarterly.
NSPML
On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the Province on terms and conditions for a FLG of $500 million in debt to be issued by NSPML. For further information, refer to the NSPI section above.
On July 4, 2024, NSPML submitted an application to the UARB requesting recovery of approximately $158 million in Maritime Link costs for 2025.
On December 21, 2023, NSPML received approval from the UARB to collect up to $164 million in 2024 from NSPI for the recovery of costs associated with the Maritime Link subject to a holdback of $4 million per month. There was no holdback recorded year-to-date in 2024.
19
Gas Utilities and Infrastructure
NMGC
Base Rates:
On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates. On March 1, 2024, NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30 million USD in annual base revenues and maintaining NMGC’s return on equity (“ROE”) at 9.375 per cent. The rates reflect the recovery of increased operating costs and capital investments in pipeline projects and related infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw, and to not reassert in a future rate case application, its request for a regulatory asset for costs associated with its 2022 application for a certificate of public convenience and necessity for a liquefied natural gas storage facility in New Mexico. The NMPRC approved the rate case settlement on July 25, 2024. New rates became effective October 1, 2024.
Other Electric Utilities
BLPC
Barbados Domestic Tax Rate Change:
On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation) Act into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs over a period to be approved by the Fair Trading Commission, Barbados (“FTC”) during a future rate setting process.
Clean Energy Transition Rider (“CETR”):
On May 31, 2023, the FTC approved BLPC’s application to establish a CETR to recover prudently incurred costs associated with its clean energy transition project. The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the mechanism. On May 6, 2024, the FTC approved certain aspects of BLPC’s application, including the recovery for capital investment in a 15 MW battery storage system. BLPC is currently evaluating the impact of operationalizing the decision.
Base Rates:
In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.
On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023 decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. The appeal is currently scheduled to be heard in December 2024.
20
GBPC
Base Rates:
On August 1, 2024, as required by the Grand Bahamas Port Authority (“GBPA”) Operating Protocol and Regulatory Framework Agreement, GBPC filed a rate plan proposal. During Q2 2024, GBPC customers experienced power interruptions due to unscheduled generation outages. Subsequently, on October 1, 2024, the GBPA suspended its review of GBPC’s rate plan proposal until a period of reliability is re-established by GBPC.
Electricity Act, 2024:
On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian regulator, regulate GBPC.
7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
| September 30 | Carrying Value as at December 31 |
Equity Income (loss) for the three months ended September 30 |
Equity Income for the nine months ended September 30 |
Percentage of Ownership |
||||||||||||||||||||||||
| millions of dollars |
2024 | 2023 | 2024 | 2023 | 2024 | 2023 | 2024 | |||||||||||||||||||||
| NSPML |
$ | 483 | $ | 489 | $ | 12 | $ | 13 | $ | 38 | $ | 34 | 100.0 | |||||||||||||||
| M&NP (1) |
117 | 118 | 4 | 5 | 14 | 16 | 12.9 | |||||||||||||||||||||
| Lucelec (1) |
52 | 48 | 1 | 1 | 3 | 2 | 19.5 | |||||||||||||||||||||
| LIL (2) |
- | 747 | - | 16 | 29 | 47 | - | |||||||||||||||||||||
| Bear Swamp (3) |
- | - | 8 | (3) | 3 | 4 | 50.0 | |||||||||||||||||||||
| $ | 652 | $ | 1,402 | $ | 25 | $ | 32 | $ | 87 | $ | 103 | |||||||||||||||||
(1) Emera has significant influence over the operating and financial decisions of these companies through Board representation and therefore, records its investment in these entities using the equity method.
(2) On June 4, 2024, Emera completed the sale of its equity interest in the LIL. For further details, refer to note 3.
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $84 million (2023 – $81 million) is recorded in Other long-term liabilities on the Condensed Consolidated Balance Sheets.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 24). NSPML’s consolidated summarized balance sheet is as follows:
| As at millions of dollars |
September 30 2024 |
December 31 2023 |
||||||
| Current assets |
$ | 49 | $ | 21 | ||||
| PP&E |
1,438 | 1,473 | ||||||
| Regulatory assets |
285 | 272 | ||||||
| Non-current assets |
27 | 29 | ||||||
| Total assets |
$ | 1,799 | $ | 1,795 | ||||
| Current liabilities |
$ | 62 | $ | 48 | ||||
| Long-term debt (1) |
1,090 | 1,109 | ||||||
| Non-current liabilities |
164 | 149 | ||||||
| Equity |
483 | 489 | ||||||
| Total liabilities and equity |
$ | 1,799 | $ | 1,795 | ||||
(1) The project debt has been guaranteed by the Government of Canada.
21
8. OTHER INCOME, NET
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Gain on sale of LIL, net of transaction costs (1) |
$ | - | $ | - | $ | 182 | $ | - | ||||||||
| AFUDC - equity |
15 | 10 | 36 | 27 | ||||||||||||
| Pension non-service cost recovery |
8 | 9 | 26 | 25 | ||||||||||||
| Interest income |
4 | 11 | 13 | 36 | ||||||||||||
| FX gains (losses) |
6 | (18) | (16) | 3 | ||||||||||||
| Transaction costs related to the pending sale of NMGC (1) |
(24) | - | (24) | - | ||||||||||||
| Other |
5 | 3 | 15 | 16 | ||||||||||||
| $ | 14 | $ | 15 | $ | 232 | $ | 107 | |||||||||
(1) For more information related to the gain on sale, after transaction costs, of Emera’s indirect minority equity interest in the LIL and the pending sale of NMGC, refer to note 3.
9. INTEREST EXPENSE, NET
Interest expense, net consisted of the following:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Interest on debt |
$ | 252 | $ | 244 | $ | 753 | $ | 706 | ||||||||
| Allowance for borrowed funds used during construction |
(6) | (4) | (15) | (11) | ||||||||||||
| Other |
(5) | (5) | (13) | (11) | ||||||||||||
| $ | 241 | $ | 235 | $ | 725 | $ | 684 | |||||||||
10. INCOME TAXES
The income tax provision differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Income before provision for income taxes |
$ | 14 | $ | 84 | $ | 435 | $ | 815 | ||||||||
| Statutory income tax rate |
29% | 29% | 29% | 29% | ||||||||||||
| Income taxes, at statutory income tax rate |
4 | 24 | 126 | 236 | ||||||||||||
| Goodwill impairment charge |
48 | - | 48 | - | ||||||||||||
| Tax credits |
(22) | (15) | (47) | (32) | ||||||||||||
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (8) | (8) | (38) | (53) | ||||||||||||
| Amortization of deferred income tax regulatory liabilities |
(14) | (16) | (30) | (32) | ||||||||||||
| Foreign tax rate variance |
(11) | (14) | (26) | (33) | ||||||||||||
| Additional impact from the sale of LIL equity interest |
- | - | 22 | - | ||||||||||||
| Tax effect of equity earnings |
(4) | (4) | (12) | (11) | ||||||||||||
| Other |
(2) | (1) | (3) | 2 | ||||||||||||
| Income tax (recovery) expense |
$ | (9) | $ | (34) | $ | 40 | $ | 77 | ||||||||
| Effective income tax rate |
(64%) | (40%) | 9% | 9% | ||||||||||||
22
Excessive Interest and Financing Expenses Limitation (“EIFEL”) Regime:
On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March 28, 2023, was enacted. Bill C-59 includes the EIFEL regime, which is effective January 1, 2024. EIFEL applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of earnings before interest, income taxes, depreciation, and amortization for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be carried forward indefinitely. The EIFEL regime did not have a material impact on the Company in Q3 2024.
Canadian Global Minimum Tax Act (“GMTA”):
On June 20, 2024, Bill C-69, an Act to implement certain provisions of the budget tabled in Parliament on April 16, 2024, was enacted. Bill C-69 includes the GMTA, a regime based on the rules of the Organisation for Economic Co-operation and Development (“OECD”). The GMTA ensures that large multinational corporations are subject to a minimum effective tax rate of 15 per cent on their profits wherever they do business. The GMTA did not have a material impact on the Company in Q3 2024.
Barbados Domestic Tax Rate Change:
On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation) Act into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs over a period to be approved by the FTC during a future rate setting process.
United States Inflation Reduction Act (“IRA”):
On August 16, 2022, the 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 September 30, 2024, the Company has recorded a $70 million (December 31, 2023 – $30 million) regulatory liability on the Condensed Consolidated Balance Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers.
11. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
| Issued and outstanding: | millions of shares | millions of dollars | ||||||
| Balance, December 31, 2023 |
284.12 | $ | 8,462 | |||||
| Issuance of common stock under ATM program (1) |
3.61 | 181 | ||||||
| Issued under the DRIP, net of discounts |
4.61 | 217 | ||||||
| Senior management stock options exercised and ECSPP |
0.50 | 24 | ||||||
| Balance, September 30, 2024 |
292.84 | $ | 8,884 | |||||
(1) For the three months ended September 30, 2024, 2,882,000 common shares were issued under Emera’s ATM program at an average price of $51.18 per share for gross proceeds of $148 million ($146 million, net of after-tax issuance costs). For the nine months ended September 30, 2024, 3,606,996 common shares were issued under Emera’s ATM program at an average price of $50.58 per share for gross proceeds of $182 million ($181 million net of after-tax issuance costs). As at September 30, 2024, an aggregate gross sales limit of $18 million remained available for issuance under the ATM program.
23
12. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars (except per share amounts) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Numerator |
||||||||||||||||
| Net income attributable to common shareholders |
$ | 3.7 | $ | 100.6 | $ | 339.9 | $ | 688.5 | ||||||||
| Diluted numerator |
3.7 | 100.6 | 339.9 | 688.5 | ||||||||||||
| Denominator |
||||||||||||||||
| Weighted average shares of common stock outstanding – basic |
290.0 | 273.6 | 287.5 | 272.2 | ||||||||||||
| Stock-based compensation |
0.1 | 0.2 | 0.1 | 0.3 | ||||||||||||
| Weighted average shares of common stock outstanding – diluted |
290.1 | 273.8 | 287.6 | 272.5 | ||||||||||||
| Earnings per common share |
||||||||||||||||
| Basic |
$ | 0.01 | $ | 0.37 | $ | 1.18 | $ | 2.53 | ||||||||
| Diluted |
$ | 0.01 | $ | 0.37 | $ | 1.18 | $ | 2.53 | ||||||||
13. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of AOCI, net of tax, are as follows:
| millions of dollars | Unrealized gain on translation of self-sustaining foreign operations |
Net change in net investment hedges |
Gains (losses) on derivatives recognized as cash flow hedges |
Net change in available- for-sale investments |
Net change in unrecognized pension and post -retirement benefit costs |
Total AOCI |
||||||||||||||||||
| For the nine months ended September 30, 2024 |
| |||||||||||||||||||||||
| Balance, January 1, 2024 |
$ | 369 | $ | (24) | $ | 14 | $ | (2) | $ | (52) | $ | 305 | ||||||||||||
| OCI before reclassifications |
240 | (33) | - | 1 | - | 208 | ||||||||||||||||||
| Amounts reclassified from AOCI |
- | - | (2) | - | 1 | (1) | ||||||||||||||||||
| Net current period OCI |
240 | (33) | (2) | 1 | 1 | 207 | ||||||||||||||||||
| Balance, September 30, 2024 |
$ | 609 | $ | (57) | $ | 12 | $ | (1) | $ | (51) | $ | 512 | ||||||||||||
| For the nine months ended September 30, 2023 |
| |||||||||||||||||||||||
| Balance, January 1, 2023 |
$ | 639 | $ | (62) | $ | 16 | $ | (2) | $ | (13) | $ | 578 | ||||||||||||
| OCI before reclassifications |
(14) | 3 | 1 | - | - | (10) | ||||||||||||||||||
| Amounts reclassified from AOCI |
- | - | (2) | - | (4) | (6) | ||||||||||||||||||
| Net current period OCI |
(14) | 3 | (1) | - | (4) | (16) | ||||||||||||||||||
| Balance, September 30, 2023 |
$ | 625 | $ | (59) | $ | 15 | $ | (2) | $ | (17) | $ | 562 | ||||||||||||
The reclassifications out of AOCI are as follows:
| Three months ended | Nine months ended | |||||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||||
| Affected line item in the Condensed Consolidated Interim Financial Statements |
Amounts reclassified from AOCI | |||||||||||||||||
| Gain on derivatives recognized as cash flow hedges | ||||||||||||||||||
| Interest rate hedge |
Interest expense, net | $ | (1) | $ | (1) | $ | (2) | $ | (2) | |||||||||
| Net change in unrecognized pension and post-retirement benefit costs |
| |||||||||||||||||
| Amounts reclassified into obligations |
Pension and post-retirement benefits | - | 1 | 1 | (4) | |||||||||||||
| Total reclassifications out of AOCI, for the period |
$ | (1) | $ | - | $ | (1) | $ | (6) | ||||||||||
24
14. DERIVATIVE INSTRUMENTS
The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:
| • | commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations; |
| • | foreign exchange (“FX”) fluctuations on foreign currency denominated purchases and sales; |
| • | interest rate fluctuations on debt securities; and |
| • | share price fluctuations on stock-based compensation. |
The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:
| 1. | Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue treatment of these contracts under this exception if the criteria are no longer met. |
| 2. | Derivatives that qualify for hedge accounting are recorded at FV on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically, for cash flow hedges, the change in the FV of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. |
Where documentation or effectiveness requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.
| 3. | Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at FV on the balance sheet as derivative assets or liabilities. The change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Based on current direction from the FPSC, TEC and PGS have no derivatives related to hedging. |
| 4. | Derivatives that do not meet any of the above criteria are designated as held-for-trading (“HFT”) derivatives and are recorded on the balance sheet at FV, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. |
25
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| As at | September 30 | December 31 | September 30 | December 31 | ||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 36 | $ | 16 | $ | 46 | $ | 76 | ||||||||
| FX forwards |
7 | 3 | 4 | 3 | ||||||||||||
| 43 | 19 | 50 | 79 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
14 | 29 | 13 | 36 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts |
249 | 319 | 528 | 531 | ||||||||||||
| 263 | 348 | 541 | 567 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| Equity derivatives |
13 | 4 | - | - | ||||||||||||
| FX forwards |
4 | 18 | 2 | 7 | ||||||||||||
| 17 | 22 | 2 | 7 | |||||||||||||
| Total gross derivatives |
323 | 389 | 593 | 653 | ||||||||||||
| Impact of master netting agreements: |
||||||||||||||||
| Regulatory deferral |
(4) | (3) | (4) | (3) | ||||||||||||
| HFT derivatives |
(132) | (146) | (132) | (146) | ||||||||||||
| Total impact of master netting agreements |
(136) | (149) | (136) | (149) | ||||||||||||
| Less: Derivatives classified as held for sale (1) |
(14) | - | - | - | ||||||||||||
| Total derivatives |
$ | 173 | $ | 240 | $ | 457 | $ | 504 | ||||||||
| Current (2) |
129 | 174 | 364 | 386 | ||||||||||||
| Long-term (2) |
44 | 66 | 93 | 118 | ||||||||||||
| Total derivatives |
$ | 173 | $ | 240 | $ | 457 | $ | 504 | ||||||||
(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at September 30, 2024, NMGC’s assets and liabilities were classified as held for sale. For further details on the pending transaction, refer to note 3.
(2) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
Cash Flow Hedges
On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. As of September 30, 2024, the unrealized gain in AOCI was $12 million, after-tax (December 31, 2023 – $14 million, after-tax). For the three and nine months ended September 30, 2024, unrealized gains of $1 million (2023 – $1 million) and $2 million (2023 – $2 million) respectively have been reclassified from AOCI into interest expense, net. The Company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months.
26
Regulatory Deferral
The Company has recorded the following changes with respect to derivatives receiving regulatory deferral:
| millions of dollars | Commodity swaps and forwards |
FX forwards |
Physical natural gas |
Commodity swaps and forwards |
FX forwards |
|||||||||||||||
| For the three months ended September 30 |
2024 | 2023 | ||||||||||||||||||
| Unrealized gain (loss) in regulatory assets |
$ | (14) | $ | (1) | $ | - | $ | 11 | $ | 4 | ||||||||||
| Unrealized gain (loss) in regulatory liabilities |
(6) | (1) | - | 12 | 6 | |||||||||||||||
| Realized gain in regulatory assets |
(3) | - | - | (5) | - | |||||||||||||||
| Realized (gain) loss in regulatory liabilities |
1 | - | - | (1) | - | |||||||||||||||
| Realized (gain) loss in inventory (1) |
3 | (1) | - | 2 | (1) | |||||||||||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) | 16 | (1) | (6) | - | - | |||||||||||||||
| Total change in derivative instruments |
$ | (3) | $ | (4) | $ | (6) | $ | 19 | $ | 9 | ||||||||||
| For the nine months ended September 30 |
2024 | 2023 | ||||||||||||||||||
| Unrealized gain (loss) in regulatory assets |
$ | (1) | $ | - | $ | - | $ | (18) | $ | 1 | ||||||||||
| Unrealized gain (loss) in regulatory liabilities |
6 | 13 | (3) | (47) | 4 | |||||||||||||||
| Realized gain in regulatory assets |
(7) | - | - | (5) | - | |||||||||||||||
| Realized loss in regulatory liabilities |
1 | - | - | 3 | - | |||||||||||||||
| Realized (gain) loss in inventory (1) |
10 | (5) | - | 7 | (10) | |||||||||||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) | 41 | (5) | (48) | (20) | (2) | |||||||||||||||
| Other |
- | - | - | (15) | - | |||||||||||||||
| Total change in derivative instruments |
$ | 50 | $ | 3 | $ | (51) | $ | (95) | $ | (7) | ||||||||||
(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 September 30, 2024, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:
| millions | 2024 | 2025-2026 | ||||||
| Physical natural gas purchases: |
||||||||
| Natural gas (MMBtu) |
2 | 6 | ||||||
| Commodity swaps and forwards purchases: |
||||||||
| Natural gas (MMBtu) |
9 | 28 | ||||||
| Heavy fuel oil (bbls) |
- | 1 | ||||||
| Power (MWh) |
- | 1 | ||||||
| Coal (metric tonnes) |
- | 1 | ||||||
| FX swaps and forwards: |
||||||||
| FX contracts (millions of USD) |
$ | 86 | $ | 272 | ||||
| Weighted average rate |
1.3436 | 1.3330 | ||||||
| % of USD requirements |
90% | 33% | ||||||
27
HFT Derivatives
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Power swaps and physical contracts in non-regulated operating revenues | $ | - | $ | (2) | $ | 11 | $ | (2) | ||||||||
| Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | 59 | 92 | 198 | 909 | ||||||||||||
| Total gains in net income |
$ | 59 | $ | 90 | $ | 209 | $ | 907 | ||||||||
As at September 30, 2024, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
| millions | 2024 | 2025 | 2026 | 2027 | 2028 and thereafter |
|||||||||||||||
| Natural gas purchases (MMBtu) |
87 | 191 | 86 | 41 | 103 | |||||||||||||||
| Natural gas sales (MMBtu) |
111 | 201 | 46 | 13 | 10 | |||||||||||||||
| Power purchases (MWh) |
- | 1 | - | - | - | |||||||||||||||
| Power sales (MWh) |
- | 1 | - | - | - | |||||||||||||||
Other Derivatives
As at September 30, 2024, the Company had equity derivatives in place to manage cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.9 million shares and extends until December 2024. The FX forwards have a combined notional amount of $458 million USD and expire in 2024 through 2026.
The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives:
| millions of dollars | FX forwards |
Equity derivatives |
FX forwards |
Equity derivatives |
||||||||||||
| For the three months ended September 30 | 2024 | 2023 | ||||||||||||||
| Unrealized gain (loss) in OM&G | $ | - | $ | 22 | $ | - | $ | (20) | ||||||||
| Unrealized gain (loss) in other income, net | 8 | - | (16) | - | ||||||||||||
| Realized loss in other income, net | (3) | - | (2) | - | ||||||||||||
| Total gains (losses) in net income | $ | 5 | $ | 22 | $ | (18) | $ | (20) | ||||||||
| For the nine months ended September 30 | 2024 | 2023 | ||||||||||||||
| Unrealized gain (loss) in OM&G | $ | - | $ | 8 | $ | - | $ | (12) | ||||||||
| Unrealized gain (loss) in other income, net | (8) | - | 7 | - | ||||||||||||
| Realized loss in other income, net | (7) | - | (7) | - | ||||||||||||
| Total gains (losses) in net income |
$ | (15) | $ | 8 | $ | - | $ | (12) | ||||||||
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.
28
The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company internally assesses credit risk for counterparties that are not rated.
It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North American Energy Standards Board agreements and/or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.
As at September 30, 2024, the Company had $124 million (December 31, 2023 – $142 million) in financial assets considered to be past due, which had been outstanding for an average 64 days. The FV of these financial assets was $112 million (December 31, 2023 – $127 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.
| As at millions of dollars |
September 30 2024 |
December 31 2023 |
||||||
| Cash collateral provided to others |
$ | 67 | $ | 101 | ||||
| Cash collateral received from others |
$ | 7 | $ | 22 | ||||
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.
As at September 30, 2024, the total FV of derivatives in a liability position was $457 million (December 31, 2023 – $504 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.
29
15. FV MEASUREMENTS
The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 14), and uses a market approach to do so. The three levels of the FV hierarchy are defined as follows:
Level 1 – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
Level 2 – Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.
Level 3 – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:
| • | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. |
| • | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. |
| • | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the FV measurement.
30
The following tables set out the classification of the methodology used by the Company to FV its derivatives:
| As at | September 30, 2024 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 9 | $ | 23 | $ | - | $ | 32 | ||||||||
| FX forwards |
- | 7 | - | 7 | ||||||||||||
| 9 | 30 | - | 39 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
- | 8 | 3 | 11 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
33 | 69 | 18 | 120 | ||||||||||||
| 33 | 77 | 21 | 131 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 4 | - | 4 | ||||||||||||
| Equity derivatives |
13 | - | - | 13 | ||||||||||||
| 13 | 4 | - | 17 | |||||||||||||
| Less: Derivatives classified as held for sale (1) |
- | (14) | - | (14) | ||||||||||||
| Total assets |
55 | 97 | 21 | 173 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
29 | 13 | - | 42 | ||||||||||||
| FX forwards |
- | 4 | - | 4 | ||||||||||||
| 29 | 17 | - | 46 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
1 | 6 | 3 | 10 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
8 | 26 | 365 | 399 | ||||||||||||
| 9 | 32 | 368 | 409 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 2 | - | 2 | ||||||||||||
| Total liabilities |
38 | 51 | 368 | 457 | ||||||||||||
| Net assets (liabilities) |
$ | 17 | $ | 46 | $ | (347) | $ | (284) | ||||||||
(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at September 30, 2024, NMGC’s assets and liabilities were classified as held for sale. For further details on the pending transaction, refer to note 3.
31
| As at | December 31, 2023 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 7 | $ | 6 | $ | - | $ | 13 | ||||||||
| FX forwards |
- | 3 | - | 3 | ||||||||||||
| 7 | 9 | - | 16 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
(5) | 23 | - | 18 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
42 | 108 | 34 | 184 | ||||||||||||
| 37 | 131 | 34 | 202 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| Equity derivatives |
4 | - | - | 4 | ||||||||||||
| FX forwards |
- | 18 | - | 18 | ||||||||||||
| 4 | 18 | - | 22 | |||||||||||||
| Total assets |
48 | 158 | 34 | 240 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
43 | 30 | - | 73 | ||||||||||||
| FX forwards |
- | 3 | - | 3 | ||||||||||||
| 43 | 33 | - | 76 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
- | 24 | - | 24 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
13 | 19 | 365 | 397 | ||||||||||||
| 13 | 43 | 365 | 421 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 7 | - | 7 | ||||||||||||
| Total liabilities |
56 | 83 | 365 | 504 | ||||||||||||
| Net assets (liabilities) |
$ | (8) | $ | 75 | $ | (331) | $ | (264) | ||||||||
The change in the FV of the Level 3 financial assets and liabilities was as follows:
| Three months ended | Nine months ended | |||||||||||||||||||||||
| September 30, 2024 | September 30, 2024 | |||||||||||||||||||||||
|
HFT Derivatives |
HFT Derivatives |
|||||||||||||||||||||||
| millions of dollars | Power | Natural gas |
Total | Power | Natural gas |
Total | ||||||||||||||||||
| Assets |
||||||||||||||||||||||||
| Balance, beginning of period |
$ | 3 | $ | 13 | $ | 16 | $ | - | $ | 34 | $ | 34 | ||||||||||||
| Total realized and unrealized gains (losses) included in non-regulated operating revenues | - | 5 | 5 | 3 | (16) | (13) | ||||||||||||||||||
| Balance, September 30, 2024 |
$ | 3 | $ | 18 | $ | 21 | $ | 3 | $ | 18 | $ | 21 | ||||||||||||
| Liabilities |
||||||||||||||||||||||||
| Balance, beginning of period |
$ | 2 | $ | 374 | $ | 376 | $ | - | $ | 365 | $ | 365 | ||||||||||||
| Total realized and unrealized gains (losses) included in non-regulated operating revenues | 1 | (9) | (8) | 3 | - | 3 | ||||||||||||||||||
| Balance, September 30, 2024 |
$ | 3 | $ | 365 | $ | 368 | $ | 3 | $ | 365 | $ | 368 | ||||||||||||
32
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:
| September 30, 2024 | ||||||||||||||||||||||
| As at millions of dollars |
FV | Significant Unobservable Input |
Low | High | Weighted Average (1) |
|||||||||||||||||
| Assets | Liabilities | |||||||||||||||||||||
| HFT derivatives – Power swaps and physical contracts | 3 | 3 | Third-party pricing | $ | 23.75 | $ | 125.70 | $74.84 | ||||||||||||||
| HFT derivatives – Natural gas swaps, futures, forwards and physical contracts | 18 | 365 | Third-party pricing | $1.50 | $14.86 | $6.29 | ||||||||||||||||
| Total |
$ | 21 | $ | 368 | ||||||||||||||||||
| Net liability |
$ | 347 | ||||||||||||||||||||
(1) Unobservable inputs were weighted by the relative FV of the instruments.
Long-term debt is a financial liability not measured at FV on the Condensed Consolidated Balance Sheets. The balance consisted of the following:
| As at millions of dollars |
Carrying Amount |
FV | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||
| September 30, 2024 |
$ | 17,262 | $ | 16,757 | $ | - | $ | 16,516 | $ | 241 | $ | 16,757 | ||||||||||||
| December 31, 2023 |
$ | 18,365 | $ | 16,621 | $ | - | $ | 16,363 | $ | 258 | $ | 16,621 | ||||||||||||
The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency gain of $22 million was recorded in AOCI for the three months ended September 30, 2024 (2023 – $33 million after-tax loss) and an after-tax foreign currency loss of $33 million was recorded for the nine months ended September 30, 2024 (2023 – $3 million after-tax gain).
33
16. RELATED PARTY TRANSACTIONS
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities, in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.
Significant transactions between Emera and its associated companies are as follows:
| • | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $41 million for the three months ended September 30, 2024 (2023 – $44 million) and $123 million for the nine months ended September 30, 2024 (2023 – $122 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. |
| • | Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $2 million for the three months ended September 30, 2024 (2023 – $2 million) and $8 million for the nine months ended September 30, 2024 (2023 – $10 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at September 30, 2024 and at December 31, 2023.
17. RECEIVABLES AND OTHER CURRENT ASSETS
| As at | September 30 | December 31 | ||||||
| millions of dollars | 2024 | 2023 | ||||||
| Customer accounts receivable – billed |
$ | 715 | $ | 805 | ||||
| Customer accounts receivable – unbilled |
304 | 363 | ||||||
| Capitalized transportation capacity (1) |
227 | 358 | ||||||
| Prepaid expenses |
136 | 105 | ||||||
| Income tax receivable |
3 | 10 | ||||||
| Allowance for credit losses |
(12) | (15) | ||||||
| Other |
155 | 191 | ||||||
| Total receivables and other current assets |
$ | 1,528 | $ | 1,817 | ||||
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.
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18. EMPLOYEE BENEFIT PLANS
Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.
Emera’s net periodic benefit cost included the following:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| DB pension plans |
||||||||||||||||
| Service cost |
$ | 9 | $ | 8 | $ | 26 | $ | 23 | ||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
27 | 27 | 82 | 83 | ||||||||||||
| Expected return on plan assets |
(40) | (40) | (120) | (121) | ||||||||||||
| Current year amortization of: |
||||||||||||||||
| Actuarial losses |
- | - | 1 | - | ||||||||||||
| Regulatory asset |
3 | 2 | 7 | 5 | ||||||||||||
| Settlements and curtailments |
- | 2 | - | 2 | ||||||||||||
| Total non-service costs |
(10) | (9) | (30) | (31) | ||||||||||||
| Total DB pension plans |
(1) | (1) | (4) | (8) | ||||||||||||
| Non-pension benefit plans |
||||||||||||||||
| Service cost |
1 | 1 | 2 | 2 | ||||||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
3 | 3 | 9 | 10 | ||||||||||||
| Expected return on plan assets |
(1) | - | (2) | (1) | ||||||||||||
| Current year amortization of: |
||||||||||||||||
| Actuarial gains |
- | (1) | - | (1) | ||||||||||||
| Regulatory asset |
(1) | (1) | (3) | (3) | ||||||||||||
| Total non-service costs |
1 | 1 | 4 | 5 | ||||||||||||
| Total non-pension benefit plans |
2 | 2 | 6 | 7 | ||||||||||||
| Total DB plans |
$ | 1 | $ | 1 | $ | 2 | $ | (1) | ||||||||
Emera’s pension and non-pension contributions related to these DB plans for the three months ended September 30, 2024 were $13 million (2023 – $20 million), and for the nine months ended September 30, 2024 were $41 million (2023 – $55 million). Annual employer contributions to the DB pension plans are estimated to be $34 million for 2024. Emera’s contributions related to the DC plans for the three months ended September 30, 2024 were $12 million (2023 – $11 million) and $37 million (2023 – $33 million) for the nine months ended September 30, 2024.
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19. GOODWILL
The change in goodwill was due to the following:
| As at | September 30 | December 31 | ||||||
| millions of dollars | 2024 | 2023 | ||||||
| Balance, January 1 |
$ | 5,871 | $ | 6,012 | ||||
| Impairment charge |
(210) | - | ||||||
| Classified as assets held for sale (1) |
(284) | - | ||||||
| Change in FX rate |
121 | (141) | ||||||
| Total goodwill |
$ | 5,498 | $ | 5,871 | ||||
(1) As at September 30, 2024, NMGC’s assets and liabilities were classified as held for sale. For further details on the pending transaction, refer to note 3.
On August 5, 2024, Emera announced an agreement to sell NMGC. As the expected transaction proceeds on the pending sale will be less than the carrying value of net assets, including goodwill (“carrying amount”), in Q3 2024, the Company performed a quantitative goodwill impairment assessment for the NMGC reporting unit. It was determined that the carrying amount exceeded the FV of the expected transaction proceeds, and as a result, a non-cash goodwill impairment charge of $210 million, pre-tax, was recorded in Q3 2024, reducing the NMGC reporting unit goodwill balance to $284 million as at September 30, 2024. This non-cash charge is included in “Impairment charges” on the Condensed Consolidated Statements of Income.
20. SHORT-TERM DEBT
Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt, refer to note 23 in Emera’s 2023 annual audited consolidated financial statements, and below for 2024 short-term debt financing activity.
Florida Electric Utilities
On April 1, 2024, TEC amended its $800 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in commercial terms from the prior agreement.
Other
On June 17, 2024, Emera repaid $200 million from the December 2024 unsecured non-revolving facility, decreasing the facility from $400 million to $200 million. There were no other material changes in commercial terms from the prior agreement.
On April 1, 2024, TECO Finance amended its $400 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in commercial terms from the prior agreement.
On February 16, 2024, Emera amended its $400 million unsecured non-revolving facility to extend the maturity date from February 19, 2024 to February 19, 2025. There were no other changes in commercial terms from the prior agreement. On July 19, 2024, Emera reduced the amount of the facility from $400 million to $200 million.
36
21. LONG-TERM DEBT
For details regarding long-term debt, refer to note 25 in Emera’s 2023 annual audited consolidated financial statements, and below for 2024 long-term debt financing activity.
Florida Electric Utilities
On July 12, 2024, TEC repaid a $300 million USD note upon maturity. This note was repaid with proceeds from commercial paper.
On January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 4.90 per cent with a maturity date of March 1, 2029. Proceeds from the issuance were primarily used for the repayment of short-term borrowings outstanding under the 5-year credit facility.
Canadian Electric Utilities
On June 24, 2024, NSPI amended its unsecured committed revolving credit facility to extend the maturity date from December 16, 2027 to June 24, 2029. There were no other material changes in commercial terms from the prior agreement.
On June 24, 2024, NSPI amended its unsecured non-revolving credit facility to extend the maturity date from July 15, 2024 to June 24, 2025 and reduce the facility from $400 million to $300 million. There were no other material changes in commercial terms from the prior agreement.
On June 13, 2024, NSPI entered a non-revolving credit facility to finance the Battery Energy Storage Project. NSPI can request funds under the facility quarterly for amounts related to incurred project costs up to the total commitment of the lessor of $120 million and 45.06 per cent of the total eligible project costs over the term of the agreement. The facility will be available until 6 months after completion of the project, not to exceed May 21, 2027 and matures 20 years following the end of the period. As at September 30, 2024, NSPI had utilized $16 million from the facility, which bears interest at 2.51 per cent.
Gas Utilities and Infrastructure
On July 30, 2024, New Mexico Gas Intermediate, Inc. repaid its $150 million USD fixed rate notes upon maturity.
Other Electric Utilities
On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend the maturity date from February 19, 2025 to July 19, 2028. There were no other material changes in commercial terms from the prior agreement.
Other
On June 24, 2024, Emera amended its unsecured committed revolving credit facility increasing the facility from $900 million to $1,300 million. Emera also extended the maturity date from June 24, 2027 to June 24, 2029. There were no other material changes in commercial terms from the prior agreement.
On June 24, 2024, Emera repaid its $400 million unsecured non-revolving credit facility set to mature in August 2024.
On June 15, 2024, Emera Finance repaid its $300 million USD senior notes upon maturity.
37
On June 18, 2024, EUSHI Finance, Inc., completed an issuance of $500 million USD fixed-to-fixed reset rate junior subordinated notes. The notes initially bear interest at a rate of 7.625 per cent, and will reset on December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S. treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, Inc., at its option, may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-annual interest payment date thereafter, at a redemption price equal to the principal amount.
22. COMMITMENTS AND CONTINGENCIES
A. Commitments
As at September 30, 2024, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars |
2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total | |||||||||||||||||||||
| Transportation (1)(2) |
$ | 216 | $ | 654 | $ | 483 | $ | 488 | $ | 420 | $ | 3,401 | $ | 5,662 | ||||||||||||||
| Purchased power (3) |
82 | 289 | 275 | 324 | 325 | 3,562 | 4,857 | |||||||||||||||||||||
| Capital projects |
712 | 245 | 62 | 10 | 1 | 1 | 1,031 | |||||||||||||||||||||
| Fuel, gas supply and storage (4) |
217 | 445 | 86 | 11 | 4 | - | 763 | |||||||||||||||||||||
| Other |
34 | 148 | 62 | 50 | 37 | 233 | 564 | |||||||||||||||||||||
| $ | 1,261 | $ | 1,781 | $ | 968 | $ | 883 | $ | 787 | $ | 7,197 | $ | 12,877 |
As detailed below, commitments at September 30, 2024 include those related to NMGC. On completion of the sale of NMGC, all the remaining future commitments will be transferred to the buyer. For further details on the pending transaction, refer to note 3.
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $128 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(2) Includes $77 million related to NMGC (2024: $10 million, 2025: $27 million, 2026: $19 million, 2027: $12 million, 2028: $9 million).
(3) Annual requirement to purchase electricity from Independent Power Producers or other utilities over varying contract lengths.
(4) Includes $203 million related to NMGC (2024: $52 million, 2025: $107 million, 2026: $36 million, 2027: $5 million, 2028: $3 million).
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In December 2023, the UARB approved the collection of up to $164 million from NSPI for the recovery of Maritime Link costs in 2024. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.
Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Nalcor Energy’s use, if requested, effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
B. Legal Proceedings
Superfund and Former Manufactured Gas Plant Sites
Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). While the aggregate joint and several liability associated with these sites has not changed as a result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at September 30, 2024, the aggregate financial liability of the Florida utilities is estimated to be $15 million ($11 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.
38
The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities. The estimates to perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, the Florida utilities could be liable for more than their actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.
C. Principal Financial Risks and Uncertainties
For information on principal financial risks which could materially affect the Company in the normal course of business, refer to note 27 in Emera’s 2023 annual audited consolidated financial statements. Risks associated with derivative instruments and FV measurements are discussed in note 14 and note 15. There have been no material changes to the principal financial risks as of September 30, 2024.
D. Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2023 audited annual consolidated financial statements, with material updates as noted below:
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 2025. The amount committed as at September 30, 2024 was $58 million (December 31, 2023 – $56 million).
Emera has provided an indemnity to a counterparty in relation to certain future tax amounts that could arise from specific future changes in Canadian federal law, subject to certain conditions and limitations. No such changes in law have been proposed at this time. A reasonable estimate of the potential amount of future payments that could result from future claims under this indemnity cannot be calculated, but the risk of having to make any significant payments under this indemnity is considered to be remote.
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23. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the |
Nine months ended September 30 | |||||||||||
| millions of dollars |
2024 | 2023 | ||||||||||
| Changes in non-cash working capital: |
||||||||||||
| Inventory |
$ | 44 | $ | (71) | ||||||||
| Receivables and other current assets (1) |
155 | 731 | ||||||||||
| Accounts payable |
(64) | (541) | ||||||||||
| Other current liabilities (2) |
85 | (114) | ||||||||||
| Total non-cash working capital |
$ | 220 | $ | 5 | ||||||||
1) The nine months ended September 30, 2023, includes $162 million related to the January 2023 settlement of NMGC gas hedges. Offsetting change in regulatory liabilities is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.
2) The nine months ended September 30, 2023, includes $(166) million related to the decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges. Offsetting regulatory asset (FAM) balance is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.
| For the |
Nine months ended September 30 | |||||||||||
| millions of dollars |
2024 | 2023 | ||||||||||
| Supplemental disclosure of non-cash activities: |
||||||||||||
| Common share dividends reinvested |
$ | 217 | $ | 205 | ||||||||
| Increase in accrued capital expenditures |
$ | 12 | $ | 45 | ||||||||
| Accrued proceeds from disposal of investment subject to significant influence |
$ | 25 | $ | - | ||||||||
| Reclassification of short-term debt and current portion of long-term debt to long-term debt |
$ | - | $ | 135 | ||||||||
| Supplemental disclosure of operating activities: |
||||||||||||
| Net change in short-term regulatory assets and liabilities |
$ | 216 | $ | 54 | ||||||||
24. VARIABLE INTEREST ENTITIES
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes, as it has authority over the majority of the direct activities expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.
BLPC established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission, and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as an “Other long-term asset”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.
The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.
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The following table provides information about Emera’s portion of material unconsolidated VIEs:
| As at |
September 30, 2024 | December 31, 2023 | ||||||||||||||
| millions of dollars |
|
Total assets |
|
|
Maximum exposure to |
|
|
Total assets |
|
|
Maximum exposure to |
| ||||
| Unconsolidated VIEs in which Emera has variable interests |
||||||||||||||||
| NSPML (equity accounted) |
$ | 483 | $ | 6 | $ | 489 | $ | 6 | ||||||||
25. SUBSEQUENT EVENTS
These unaudited condensed consolidated interim financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through November 8, 2024, the date the unaudited condensed consolidated interim financial statements were issued.
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Exhibit 99.3
Emera Incorporated
Earnings Coverage Ratio
Pursuant to Section 8.4 of National Instrument 44-102, this updated calculation of the earnings coverage ratio is filed as an exhibit to the unaudited condensed consolidated financial statements of Emera Incorporated (“Emera”) for the nine months ended September 30, 2024.
The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended September 30, 2024.
| Twelve months ended September 30, 2024 | ||
| Earnings Coverage (1) |
1.62 |
(1) Earnings coverage is equal to consolidated net income attributable to common shareholders plus: income taxes, interest on debt, amortization of debt financing costs, allowance for funds used during construction and preferred share dividends declared during the period together with undeclared preferred share dividends, if any, divided by the sum of interest on debt, amortization of debt financing costs, allowance for funds used during construction, capitalized interest and preferred dividends grossed up to a before-tax equivalent using an effective tax rate of 29.0 per cent.
Emera’s dividend requirements on all of its preferred shares, grossed up to a before-tax equivalent using an effective income tax rate of 29.0 per cent, amounted to $103 million for the twelve months ended September 30, 2024. Emera’s interest requirements for the twelve months ended September 30, 2024 amounted to $985 million. Emera’s consolidated income before interest and income tax for the twelve months ended September 30, 2024 was $1,759 million, which is 1.62 times Emera’s aggregate preferred dividends and interest requirements for this period.
Exhibit 99.4
Emera Reports 2024 Third Quarter Financial Results
HALIFAX, Nova Scotia -- Today Emera Inc. (“Emera”) (TSX: EMA) reported financial results for the third quarter and year-to-date 2024.
Highlights
| • | Increase in Adjusted Earnings Per Share1 (“Adjusted EPS”): Adjusted EPS increased by 8% or $0.06 to $0.81 compared to adjusted EPS of $0.75 in Q3 2023. |
| ○ | Customer growth at both Florida utilities, and new base rates at Peoples Gas (“PGS”) resulted in higher contributions; |
| ○ | Corporate costs were lower, primarily due to the timing difference in the valuation of long-term incentive expense and related hedges; |
| ○ | These increases were partially offset by lower contributions from Canadian Electric Utilities driven by the sale of the Labrador Island Link (“LIL”) in June 2024 and lower contributions from Nova Scotia Power (“NSPI”) driven by an increase in reliability and customer experience-related operating costs. |
| • | Decrease in Reported Earnings Per Share (“EPS”): Reported EPS decreased by $0.36 to $0.01 in Q3 2024, compared to $0.37 in Q3 2023. This decrease was primarily driven by charges related to the pending sale of New Mexico Gas Company (“NMGC”). |
| • | Strengthened Financial Position: In late September, NSPI finalized a $500 million federal loan guarantee with the Government of Canada and the Government of Nova Scotia. This guarantee provides important cost relief to electricity customers in Nova Scotia and protects the overall financial health of the utility by way of a $500 million debt reduction. This builds on the Q3 announcement of the US$1.252 billion pending sale of NMGC. |
| • | Investing for the Future: Emera remains on track to fully deploy its $2.9 billion capital plan in 2024, with two-thirds of new rate base investments committed to date. The investment plan remains focused on reliability and resiliency, grid modernization, renewable energy integration, technology innovations focused on cost efficiency and customer experience, and customer growth driven infrastructure expansion. |
“Emera’s third quarter results were strong, with an 8 per cent increase in adjusted earnings per share over Q3 2023, principally driven by solid operational performance across the portfolio and particularly strong financial performance from our Florida utilities.” said Scott Balfour, President and CEO of Emera Inc. “The successful storm response following the recent back-to-back hurricanes in Florida is a testament to our local teams’ expertise, and the resilience of our electric and gas infrastructure. The PGS gas system experienced minimal impacts from both Helene and Milton, while grid restoration efforts for Tampa Electric were completed in record time given the severity of the events.”
Q3 2024 Financial Results
Q3 2024 reported net income was $4 million, or $0.01 per common share, compared with reported net income of $101 million, or $0.37 per common share, in Q3 2023. Reported net income for the quarter included $225 million in
1
charges related to the pending sale of NMGC, after tax and a $7 million MTM loss, after-tax, primarily at Emera Energy Services (“EES”) compared to a $103 million loss, after-tax, in Q3 2023.
Q3 2024 adjusted net income(1) was $236 million, or $0.81 per common share, compared with $204 million, or $0.75 per common share, in Q3 2023. The increase in adjusted net income was primarily due to increased earnings at TEC, PGS, NSPI and NMGC; and lower Corporate operating, maintenance and general expenses (“OM&G”) largely due to the timing difference in the valuation of long-term incentive expense and related hedges. These were partially offset by decreased earnings at Emera Energy; lower equity earnings as a result of the sale of Emera’s LIL equity interest; lower Corporate income tax recovery due to decreased losses before provision for income taxes; increased Corporate interest expense due to increased interest rates and increased total debt; and increased Corporate preferred share dividends.
Year-to-date Financial Results
Year-to-date reported net income was $340 million or $1.18 per common share, compared with reported net income of $689 million or $2.53 per common share year-to-date in 2023. Year-to-date reported net income included a $107 million gain, after tax and transaction costs, on the sale of Emera’s LIL equity interest and was unfavourably impacted by the $225 million charges, after-tax, related to the pending sale of NMGC, and the $145 million MTM losses, after-tax, primarily at EES, compared to a $55 million gain, after-tax, in 2023.
Year-to-date adjusted net income(1) was $603 million or $2.10 per common share, compared with $634 million or $2.33 per common share year-to-date in 2023.
The year-to-date decrease in adjusted net income was primarily due to decreased earnings at NMGC, Emera Energy, and NSPI; lower equity earnings as a result of the sale of Emera’s LIL equity interest; increased Corporate interest expense due to increased interest rates and increased total debt; and increased Corporate preferred share dividends. These were partially offset by increased earnings at PGS and TEC; decreased Corporate OM&G due to the timing difference in the valuation of long-term incentive expense and related hedges; and higher income tax recovery due to increased loss before provision for income taxes.
The translation impact of a weaker CAD on US denominated earnings increased net income by $7 million in Q3 2024 compared to the same period in 2023. Year-to-date 2024, the impact of a weaker CAD on US denominated earnings was more than offset by the realized and unrealized losses on FX hedges used to mitigate the translation risk of USD earnings, resulting in a $6 million decrease to net income compared to the same period in 2023. Weakening of the CAD increased adjusted net income by $2 million in Q3 2024 and $3 million year-to-date compared to the same periods in 2023. Impacts of the changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of USD earnings in the Other segment.
(1) See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” below for reconciliation to nearest USGAAP measure.
2
Segment Results and Non-GAAP Reconciliation
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of Canadian dollars (except per share amounts) | 2024 | 2023 | 2024 | 2023 | ||||||||||||
| Adjusted net income 1,2 |
||||||||||||||||
| Florida Electric Utility |
$ | 252 | $ | 228 | 524 | 512 | ||||||||||
| Canadian Electric Utilities |
26 | 38 | 155 | 179 | ||||||||||||
| Gas Utilities and Infrastructure |
38 | 23 | 180 | 155 | ||||||||||||
| Other Electric Utilities |
10 | 17 | 27 | 31 | ||||||||||||
|
Other3 |
(90) | (102) | (283) | (243) | ||||||||||||
| Adjusted net income 1,2 |
$ | 236 | $ | 204 | 603 | 634 | ||||||||||
| Charges related to the pending sale of NMGC, after-tax 4,5 |
(225) | - | (225) | - | ||||||||||||
| Gain on sale of LIL, after tax and transaction costs 6 |
- | - | 107 | - | ||||||||||||
| MTM (loss) gain, after-tax 7 |
(7) | (103) | (145) | 55 | ||||||||||||
| Net income attributable to common shareholders |
$ | 4 | $ | 101 | 340 | 689 | ||||||||||
| EPS (basic) |
$ | 0.01 | $ | 0.37 | 1.18 | 2.53 | ||||||||||
| Adjusted EPS (basic) 1,2 |
$ | 0.81 | $ | 0.75 | 2.10 | 2.33 | ||||||||||
1 See “Non-GAAP Financial Measures and Ratios” noted below.
2 Excludes the charges related to the pending sale of NMGC, after-tax, the gain on sale, after tax and transaction costs of Emera’s LIL equity interest and the effect of MTM adjustments.
3 Higher earnings quarter-over-quarter, primarily due to lower OM&G, partially offset by decreased income tax recovery, increased interest expense and lower contributions from Emera Energy. Year-over-year change primarily due to increased interest expense and lower contributions from Emera Energy, partially offset by lower operating expenses and increased income tax recovery.
4 Represents (i) $206 million in non-cash goodwill and other impairment charges, after-tax and (ii) $19 million in estimated transaction costs, after-tax for the three and nine months ended September 30, 2024 (2023 – nil).
5 Net of income tax recovery of $20 million for the three and nine months ended September 30, 2024 (2023 – nil).
6 Net of income tax expense of $75 million for the nine months ended September 30, 2024 (2023 – nil).
7 Net of income tax recovery of $4 million for the three months ended September 30, 2024 (2023 – $40 million recovery) and $60 million income tax recovery for the nine months ended September 30, 2024 (2023 – $24 million expense).
3
Consolidated Financial Review
The following table highlights significant year-over-year changes in adjusted net income attributable to common shareholders from 2023 to 2024.
| For the | Three months ended | Nine months ended | ||||||
| millions of Canadian dollars | September 30 | September 30 | ||||||
| Adjusted net income – 2023 1,2 |
$ | 204 | $ | 634 | ||||
| Operating Unit Performance |
||||||||
| Increased earnings at TEC due to higher revenues as a result of customer growth and new base rates, lower income tax expense and the impact of a weaker CAD, partially offset by unfavourable weather and higher depreciation. Year-over-year earnings was also partially offset by higher OM&G due to higher generation and transmission and distribution (“T&D”) costs | 24 | 12 | ||||||
| Increased earnings at PGS due to higher revenue from new base rates and customer growth, partially offset by increased depreciation, OM&G, interest expense and income tax expense | 15 | 47 | ||||||
| Increased earnings quarter-over-quarter at NSPI due to lower OM&G. Decreased earnings year-over-year due to higher OM&G due to increased reliability initiatives, partially offset by higher revenue from increased residential sales volumes | 4 | (12) | ||||||
| Decreased earnings year-over-year at NMGC due to lower asset optimization revenues and increased OM&G, partially offset by lower income tax expense | 1 | (18) | ||||||
| Decreased income from equity investments due to the sale of LIL equity interest | (15) | (16) | ||||||
| Decreased earnings at Emera Energy due to the recognition of investment tax credits in 2023 related to Bear Swamp | (5) | (8) | ||||||
| Decreased earnings at EES due to less favourable market conditions. Year-over-year decrease also reflects favourable hedging opportunities in Q1 2023 as a result of higher natural gas pricing | (3) | (13) | ||||||
| Corporate |
||||||||
| Decreased OM&G, pre-tax, primarily due to the timing difference in the valuation of long-term incentive expense and related hedges | 32 | 15 | ||||||
| Increased preferred share dividends due to higher dividend rate for series B, C, and H preferred shares | (2) | (6) | ||||||
| Increased interest expense, pre-tax, due to increased interest rates and increased total debt | (6) | (29) | ||||||
| Decreased income tax recovery quarter-over-quarter due to decreased loss before provision for income taxes. Increased income tax recovery year-over-year due to increased loss before provision for income taxes | (7) | 8 | ||||||
| Other Variances |
(6) | (11) | ||||||
| Adjusted net income – 2024 1,2 |
$ | 236 | $ | 603 | ||||
1 See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” for reconciliation to nearest USGAAP measure.
2 Excludes the charges related to the pending sale of NMGC, after-tax, the gain on sale, after tax and transaction costs of Emera’s LIL equity interest and the effect of MTM adjustments.
4
1 Non-GAAP Financial Measures and Ratios
Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures and ratios by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes the ongoing operations of the business. For further information on the non-GAAP financial measure, adjusted net income, and the non-GAAP ratio, adjusted EPS – basic, refer to the “Non-GAAP Financial Measures and Ratios” section of the Emera’s Q3 2024 MD&A which is incorporated herein by reference and can be found on SEDAR+ at www.sedarplus.ca. Reconciliation to the nearest GAAP measure is included in “Segment Results and Non-GAAP Reconciliation” above.
Forward-Looking Information
This news release contains forward-looking information within the meaning of applicable securities laws. By its nature, forward-looking information requires Emera to make assumptions and is subject to inherent risks and uncertainties. These statements reflect Emera management’s current beliefs and are based on information currently available to Emera management. There is a risk that predictions, forecasts, conclusions and projections that constitute forward-looking information will not prove to be accurate, that Emera’s assumptions may not be correct and that actual results may differ materially from such forward-looking information. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Business Risks and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR+ at www.sedarplus.ca.
Teleconference Call
The company will be hosting a teleconference today, Friday, November 8, at 6:00 p.m. Atlantic (5:00 p.m. Eastern) to discuss the Q3 2024 financial results.
Analysts and other interested parties in North America are invited to participate by dialing 1-800-717-1738. International parties are invited to participate by dialing 1-289-514-5100. Participants should dial in at least 10 minutes prior to the start of the call. No pass code is required.
A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available on the Company’s website two hours after the conclusion of the call.
About Emera
Emera (TSX: EMA) is a leading North American provider of energy services headquartered in Halifax, Nova Scotia, with investments in regulated electric and natural gas utilities, and related businesses and assets. The Emera family of companies delivers safe, reliable energy to approximately 2.5 million customers in Canada, the United States and the Caribbean. Our team of 7,300 employees is committed to our purpose of energizing modern life and delivering a cleaner energy future for all. Emera’s common and preferred shares are listed and trade on the Toronto Stock Exchange. Additional information can be accessed at www.emera.com or www.sedarplus.ca.
Emera Inc.
Investor Relations
5
Dave Bezanson, VP, Investor Relations & Pensions
902-474-2126
dave.bezanson@emera.com
Media
902-222-2683
media@emera.com
6
Exhibit 99.5
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Scott Balfour, President and Chief Executive Officer of Emera Incorporated, certify the following:
1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended September 30, 2024.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2024 and ended on September 30, 2024 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: November 8, 2024 |
| “Scott Balfour”
|
| Scott Balfour |
| President and Chief Executive Officer |
Exhibit 99.6
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Greg Blunden, Chief Financial Officer of Emera Incorporated, certify the following:
1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended September 30, 2024.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2024 and ended on September 30, 2024 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: November 8, 2024 |
| “Greg Blunden” |
|
|
|
Greg Blunden |
| Chief Financial Officer |