Emera Inc 6-K, filed Aug 15, 2023
Emera Inc (EMA)
About this 6-K
Emera Inc filed this 6-K on August 15, 2023.
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 August, 2023
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: August 15, 2023 | By: | /s/ Stephen Aftanas | ||||
| Name: Stephen D. Aftanas | ||||||
| Title: Corporate Secretary | ||||||
EXHIBIT INDEX
Exhibit 99.1
Management’s Discussion & Analysis
As at August 11, 2023
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments during the second quarter of, and year-to-date 2023 relative to the same periods in 2022; and its financial position as at June 30, 2023 relative to December 31, 2022. Throughout this discussion, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. 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 discussion and analysis should be read in conjunction with the Emera unaudited condensed consolidated interim financial statements and supporting notes as at and for the three and six months ended June 30, 2023; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2022. Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR+ at www.sedarplus.ca.
Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). 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 June 30, 2023, 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”) (1) | 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 Systems, Inc. (“PGS”) (1) | FPSC | |
| New Mexico Gas Company, Inc. (“NMGC”) | New Mexico Public Regulation Commission (“NMPRC”) | |
| SeaCoast Gas Transmission, LLC (“SeaCoast”) | FPSC | |
| Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) | Canadian Energy Regulator (“CER”) | |
| Barbados Light & Power Company Limited (“BLPC”) | Fair Trading Commission, Barbados (“FTC”) | |
| Grand Bahama Power Company Limited (“GBPC”) | The Grand Bahama Port Authority (“GBPA”) | |
| Equity Investments | ||
| NSP Maritime Link Inc. (“NSPML”) | UARB | |
| Labrador Island Link Limited Partnership (“LIL”) | Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”) | |
| 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 (“NURC”) |
(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility was reorganized, resulting in a separate legal entity called Peoples Gas System, Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.
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 |
6 | |
| Significant Items Affecting Earnings |
6 | |
| Consolidated Financial Highlights |
6 | |
| Consolidated Income Statement Highlights |
8 | |
| Business Overview and Outlook |
10 | |
| Florida Electric Utility |
10 | |
| Canadian Electric Utilities |
10 | |
| Gas Utilities and Infrastructure |
12 | |
| Other Electric Utilities |
13 | |
| Other |
13 | |
| Consolidated Balance Sheet Highlights |
14 | |
| Financial Highlights |
15 | |
| Florida Electric Utility |
15 | |
| Canadian Electric Utilities |
16 |
| Gas Utilities and Infrastructure |
18 | |
| Other Electric Utilities |
19 | |
| Other |
20 | |
| Liquidity and Capital Resources |
21 | |
| Consolidated Cash Flow Highlights |
22 | |
| Contractual Obligations |
23 | |
| Debt Management |
24 | |
| Guarantees and Letters of Credit |
25 | |
| Outstanding Stock Data |
25 | |
| Transactions with Related Parties |
26 | |
| Risk Management including Financial Instruments |
27 | |
| Disclosure and Internal Controls |
28 | |
| Critical Accounting Estimates |
28 | |
| Changes in Accounting Policies and Practices |
28 | |
| Future Accounting Pronouncements |
28 | |
| Summary of Quarterly Results |
29 |
FORWARD-LOOKING INFORMATION
This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, carbon dioxide emissions reduction goals, business prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.
The forward-looking information 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 forward-looking information. 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; future dividend growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; 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; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental, 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, such as the COVID-19 novel coronavirus pandemic; market energy sales prices; labour relations; and availability of labour and management resources.
2
Readers are cautioned not to place undue reliance on forward-looking information, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this 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 forward-looking information as a result of new information, future events or otherwise.
INTRODUCTION AND STRATEGIC OVERVIEW
Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the United States 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 provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the 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 $8 – 9 billion over the 2023-to-2025 period, mainly focused in Florida. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2025. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization, and customer-focused technologies. Emera’s capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan (“DRIP”) and at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a priority of the Company.
Emera has provided annual dividend growth guidance of four to five per cent through 2025. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.
Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market (“MTM”) adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income and cash flows are impacted by movements in the USD relative to the CAD. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.
Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, digitization, decarbonization, complex regulatory environments, and decentralized generation.
3
Customers are looking for more choice, better control, and enhanced reliability in a time where costs of decentralized generation and storage have become more competitive in some regions. Advancing technologies are transforming the way utilities interact with their customers and generate and transmit energy. In addition, climate change and extreme weather are shaping how utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance reliability. Emera will play a role in all of these trends. Emera’s strategy is to fund investments in renewable energy and technology assets which protect the environment and benefit customers through fuel or operating cost savings.
For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, and the ongoing construction of solar generation and modernization of the Big Bend Power Station at TEC. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of safely delivering cleaner, reliable, and affordable energy for its customers.
Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.
This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a clear path to Emera’s interim carbon goals. With existing technologies and resources, and subject to supportive government and regulatory decisions, Emera is working to achieve the following goals compared to corresponding 2005 levels:
| • | 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. |
Achieving the above climate goals on these timelines is subject to the Company’s regulatory obligations and other external factors beyond Emera’s control.
Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.
Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships.
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures and ratios by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. These measures and ratios are discussed and reconciled below.
Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per Common Share (“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the effect of MTM adjustments, and the impact of the 2022 NSPML unrecoverable costs.
4
Management believes excluding from net income the effect of MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows, and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:
| · | held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions; |
| · | the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income; |
| · | equity securities held in BLPC; and |
| · | 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.
In February 2022, the UARB issued a decision to disallow recovery of $9 million in costs ($7 million after-tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were recognized in “Income from equity investments” in Emera’s Condensed Consolidated Statements of Income. Management believes excluding these unrecoverable costs from the calculation of adjusted net income better reflects the underlying operations in the period. For further details on the 2022 NSPML unrecoverable costs, refer to the “Financial Highlights – Canadian Electric Utilities” section.
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 2022 Annual MD&A.
Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial Highlights – Canadian Electric Utilities”, “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.
The following reconciles net income attributable to common shareholders to adjusted net income:
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars (except per share amounts) |
2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 28 | $ | (67) | $ | 588 | $ | 295 | ||||||||
|
|
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| MTM (loss) gain, after-tax (1) |
(134) | (223) | 158 | (96) | ||||||||||||
|
|
||||||||||||||||
| NSPML unrecoverable costs (2) |
- | - | - | (7) | ||||||||||||
|
|
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| Adjusted net income |
$ | 162 | $ | 156 | $ | 430 | $ | 398 | ||||||||
|
|
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| EPS – basic |
$ | 0.10 | $ | (0.25) | $ | 2.17 | $ | 1.12 | ||||||||
|
|
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| Adjusted EPS – basic |
$ | 0.60 | $ | 0.59 | $ | 1.58 | $ | 1.51 | ||||||||
|
|
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(1) Net of income tax recovery of $55 million for the three months ended June 30, 2023 (2022 – $91 million recovery) and $64 million income tax expense for the six months ended June 30, 2023 (2022 – $37 million recovery).
(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in “Income from equity investments” on Emera’s Condensed Consolidated Statements of Income.
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.
5
Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments and the 2022 NSPML unrecoverable costs.
The following is a reconciliation of net income to EBITDA and Adjusted EBITDA:
| For the | Three months ended June 30 |
Six months ended June 30 |
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| millions of dollars |
2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
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| Net income (loss) (1) |
$ | 44 | $ | (52) | $ | 620 | $ | 326 | ||||||||
|
|
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| Interest expense, net |
223 | 163 | 449 | 319 | ||||||||||||
|
|
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| Income tax (recovery) expense |
(51) | (66) | 111 | 29 | ||||||||||||
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| Depreciation and amortization |
263 | 230 | 519 | 460 | ||||||||||||
|
|
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| EBITDA |
$ | 479 | $ | 275 | $ | 1,699 | $ | 1,134 | ||||||||
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| MTM (loss) gain, excluding income tax |
(189) | (314) | 222 | (133) | ||||||||||||
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| NSPML unrecoverable costs (2) |
- | - | - | (7) | ||||||||||||
|
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| Adjusted EBITDA |
$ | 668 | $ | 589 | $ | 1,477 | $ | 1,274 | ||||||||
|
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(1) Net income (loss) is before Non-controlling interest in subsidiaries and Preferred stock dividends.
(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in “Income from equity investments” on Emera’s Condensed Consolidated Statements of Income.
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Earnings
Earnings Impact of After-Tax MTM (Loss) Gain
MTM loss, after-tax decreased $89 million to $134 million in Q2 2023, compared to $223 million in Q2 2022. Year-to-date, MTM loss, after-tax of $96 million in 2022, decreased $254 million to a $158 million MTM gain, after-tax, for the same period in 2023. The decreased MTM loss, after-tax in both periods were due to favourable changes in existing positions at Emera Energy Services (“EES”), partially offset by higher amortization of gas transportation assets at EES.
Consolidated Financial Highlights
| For the millions of dollars |
Three months ended June 30 |
Six months ended June 30 |
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| Adjusted Net Income |
2023 | 2022 | 2023 | 2022 | ||||||||||||
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|
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| Florida Electric Utility |
$ | 177 | $ | 161 | $ | 284 | $ | 273 | ||||||||
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| Canadian Electric Utilities |
49 | 39 | 141 | 137 | ||||||||||||
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| Gas Utilities and Infrastructure |
38 | 39 | 132 | 116 | ||||||||||||
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| Other Electric Utilities |
10 | 8 | 14 | 9 | ||||||||||||
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| Other |
(112) | (91) | (141) | (137) | ||||||||||||
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| Adjusted net income |
$ | 162 | $ | 156 | $ | 430 | $ | 398 | ||||||||
|
|
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| MTM (loss) gain, after-tax |
(134) | (223) | 158 | (96) | ||||||||||||
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| NSPML unrecoverable costs |
- | - | - | (7) | ||||||||||||
|
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| Net income (loss) attributable to common shareholders |
$ | 28 | $ | (67) | $ | 588 | $ | 295 | ||||||||
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6
The following table highlights significant changes in adjusted net income from 2022 to 2023:
| For the | Three months ended | Six months ended | ||||||
| millions of dollars | June 30 | June 30 | ||||||
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|
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| Adjusted net income – 2022 |
$ | 156 | $ | 398 | ||||
|
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| Operating Unit Performance |
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| Increased earnings at TEC due to new base rates, the impact of a weaker CAD and customer growth, partially offset by higher operating, maintenance and general expenses (“OM&G”), interest expense, depreciation and unfavourable weather | 16 | 11 | ||||||
|
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| Increased earnings at NSPI due to new base rates, increased sales volumes, customer growth and decreased income tax expense, partially offset by higher interest expense, OM&G, and depreciation. Year-over-year also partially offset by unfavourable weather | 6 | 3 | ||||||
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| Increased earnings at NMGC due to new base rates. Year-over-year earnings also increased due to higher asset optimization revenue, partially offset by increased OM&G | 4 | 24 | ||||||
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| Decreased earnings at EES quarter-over-quarter due to lower natural gas prices, and timing of recognition of transport and other costs. Year-over-year increase reflects favourable hedging opportunities and more available gas transport due to mild weather in Q1 2023 | (17) | 12 | ||||||
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| Corporate | ||||||||
| Increased income tax recovery primarily due to increased losses before provision for income taxes | 11 | - | ||||||
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| Increased interest expense, pre-tax, due to increased interest rates and increased total debt | (10) | (30) | ||||||
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| Other Variances | (4) | 12 | ||||||
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| Adjusted net income – 2023 | $ | 162 | $ | 430 | ||||
|
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For further details of reportable segments contributions, refer to the “Financial Highlights” section.
| For the | Six months ended June 30 | |||||||
| millions of dollars |
2023 | 2022 | ||||||
|
|
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| Operating cash flow before changes in working capital |
$ | 1,163 | $ | 746 | ||||
|
|
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| Change in working capital |
(212) | (73) | ||||||
|
|
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| Operating cash flow |
$ | 951 | $ | 673 | ||||
|
|
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| Investing cash flow |
$ | (1,343) | $ | (1,030) | ||||
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| Financing cash flow |
$ | 400 | $ | 238 | ||||
|
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|
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
|
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| As at | June 30 | December 31 | ||||||
| millions of dollars |
2023 | 2022 | ||||||
|
|
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| Total assets |
$ | 38,472 | $ | 39,742 | ||||
|
|
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| Total long-term debt (including current portion) |
$ | 16,537 | $ | 16,318 | ||||
|
|
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7
Consolidated Income Statement Highlights
| For the millions of dollars |
Three months ended June 30 |
Six months ended June 30 |
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| (except per share amounts) | 2023 | 2022 | Variance | 2023 | 2022 | Variance | ||||||||||||||||||
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| Operating revenues | $ | 1,418 | $ | 1,380 | $ | 38 | $ | 3,851 | $ | 3,395 | $ | 456 | ||||||||||||
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| Operating expenses | 1,295 | 1,389 | 94 | 2,834 | 2,825 | (9) | ||||||||||||||||||
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| Income (loss) from operations | $ | 123 | $ | (9) | $ | 132 | $ | 1,017 | $ | 570 | $ | 447 | ||||||||||||
|
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| Interest expense, net | $ | 223 | $ | 163 | $ | (60) | $ | 449 | $ | 319 | $ | (130) | ||||||||||||
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| Net income (loss) attributable to common shareholders | $ | 28 | $ | (67) | $ | 95 | $ | 588 | $ | 295 | $ | 293 | ||||||||||||
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| Adjusted net income | $ | 162 | $ | 156 | $ | 6 | $ | 430 | $ | 398 | $ | 32 | ||||||||||||
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| Weighted average shares of common stock outstanding (in millions) | 272.3 | 264.4 | 7.9 | 271.5 | 263.1 | 8.4 | ||||||||||||||||||
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| EPS – basic | $ | 0.10 | $ | (0.25) | $ | 0.35 | $ | 2.17 | $ | 1.12 | $ | 1.05 | ||||||||||||
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| EPS – diluted | $ | 0.10 | $ | (0.25) | $ | 0.35 | $ | 2.16 | $ | 1.12 | $ | 1.04 | ||||||||||||
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| Adjusted EPS – basic | $ | 0.60 | $ | 0.59 | $ | 0.01 | $ | 1.58 | $ | 1.51 | $ | 0.07 | ||||||||||||
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| Dividends per common share declared | $ | 0.6900 | $ | 0.6625 | $ | 0.0275 | $ | 1.3800 | $ | 1.3250 | $ | 0.0550 | ||||||||||||
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| Adjusted EBITDA | $ | 668 | $ | 589 | $ | 79 | $ | 1,477 | $ | 1,274 | $ | 203 | ||||||||||||
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Operating Revenues
For Q2 2023, operating revenues increased $38 million compared to Q2 2022 and, absent decreased MTM loss of $108 million, decreased $70 million. The decrease was due to lower fuel revenues at NMGC, TEC and PGS; a change in fuel cost recovery methodology for an industrial customer at NSPI; lower off-system sales at PGS; decreased marketing and trading margin at EES; and unfavourable weather at TEC. These decreases were partially offset by the impact of a weaker CAD; new base rates at TEC, NSPI and NMGC; storm cost recovery surcharge revenue at TEC; and customer growth at TEC and NSPI.
Year-to-date in 2023, operating revenues increased $456 million compared to 2022 and, absent decreased MTM loss of $325 million, increased by $131 million. The increase was due to the impact of a weaker CAD; new base rates at TEC, NSPI and NMGC; storm cost recovery surcharge revenue at TEC; increased marketing and trading margin at EES; customer growth at TEC and NSPI; and higher asset optimization revenue at NMGC. These increases were partially offset by a change in fuel cost recovery methodology for an industrial customer at NSPI; lower fuel revenues at TEC and NMGC; decreased off-system sales at PGS; and unfavourable weather at TEC and NSPI.
Operating Expenses
For Q2 2023, operating expenses decreased $94 million compared to the same period in 2022. The decrease was due to lower fuel expenses at TEC, NMGC, and PGS; and a change in fuel cost recovery methodology for an industrial customer at NSPI. These were partially offset by the impact of a weaker CAD; and higher OM&G at TEC.
Year-to-date 2023, operating expenses increased $9 million compared to the same periods in 2022. The increase was due to the impact of a weaker CAD; and higher OM&G at TEC. These were partially offset by lower fuel expenses at PGS, TEC, and NMGC; and a change in fuel cost recovery methodology for an industrial customer at NSPI.
Interest Expense, Net
For Q2 2023, interest expense, net increased $60 million and year-to-date 2023 increased $130 million compared to the same periods in 2022 due to higher interest rates; higher borrowings to support capital investments and ongoing operations; and the impact of a weaker CAD.
8
Net Income Attributable to Common Shareholders and Adjusted Net Income
For Q2 2023, net income attributable to common shareholders compared to Q2 2022, was favourably impacted by the $89 million decrease in after-tax MTM loss. Absent the favourable MTM changes, adjusted net income increased $6 million. The increase was primarily due to increased earnings at TEC, NSPI and NMGC; the impact of a weaker CAD on the translation of Emera’s non-Canadian affiliates; and higher income tax recovery at corporate. These were partially offset by decreased earnings at EES; and increased corporate interest expense due to higher interest rates and increased total debt.
Year-to-date 2023, net income attributable to common shareholders, compared to the same period in 2022, was favourably impacted by the $254 million decrease in after-tax MTM loss and favourably impacted by the $7 million in NSPML unrecoverable costs recognized in 2022. Absent these changes, adjusted net income increased $32 million. The increase was primarily due to increased earnings at NMGC, EES, TEC and NSPI; and the impact of a weaker CAD on the translation of Emera’s non-Canadian affiliates. These were partially offset by increased corporate interest expense due to higher interest rates and increased total debt.
EPS and Adjusted EPS – Basic
EPS and adjusted EPS – basic were higher in Q2 2023, as well as year-to-date in 2023, due to increased earnings as discussed above, partially offset by the impact of the increase in weighted average shares outstanding.
Effect of Foreign Currency Translation
Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2022 annual MD&A.
The relevant CAD/USD exchange rates for 2023 and 2022 are as follows:
| Three months ended June 30 |
Six months ended June 30 |
Year ended December 31 |
||||||||||||||||||
| For the |
2023 | 2022 | 2023 | 2022 | 2022 | |||||||||||||||
|
|
||||||||||||||||||||
| Weighted average CAD/USD |
$ | 1.37 | $ | 1.27 | $ | 1.34 | $ | 1.27 | $ | 1.34 | ||||||||||
|
|
||||||||||||||||||||
| Period end CAD/USD exchange rate |
$ | 1.2 | $ | 1.29 | $ | 1.32 | $ | 1.29 | $ | 1.35 | ||||||||||
|
|
||||||||||||||||||||
The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of USD |
2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Florida Electric Utility |
$ | 132 | $ | 126 | $ | 211 | $ | 214 | ||||||||
|
|
||||||||||||||||
| Gas Utilities and Infrastructure (1) |
24 | 21 | 89 | 79 | ||||||||||||
|
|
||||||||||||||||
| Other Electric Utilities |
7 | 6 | 10 | 7 | ||||||||||||
|
|
||||||||||||||||
| Other segment (2) |
(52) | (38) | (45) | (50) | ||||||||||||
|
|
||||||||||||||||
| Total (3) |
$ | 111 | $ | 115 | $ | 265 | $ | 250 | ||||||||
|
|
||||||||||||||||
(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.
(2) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt.
(3) Net of $132 million MTM loss, after-tax for the three months ended June 30, 2023 (2022 – $173 million loss) and $100 million MTM gain, after-tax, for the six months ended June 30, 2023 (2022 – $70 million loss).
The translation impact of a weaker CAD on US denominated earnings and the unrealized gains on FX hedges used to mitigate translation risk of USD earnings combined to increase net income by $8 million in Q2 2023 and $42 million year-to-date compared to the same periods in 2022. Weakening of the CAD increased adjusted net income by $6 million in Q2 2023 and $18 million year-to-date compared to the same periods in 2022. Impacts of the weakening CAD include the impacts of corporate FX hedges in the Other segment.
9
BUSINESS OVERVIEW AND OUTLOOK
There have been no material changes in Emera’s business overview and outlook from the Company’s 2022 annual MD&A other than the updates as disclosed below. Emera’s year-to-date results have been impacted by macroeconomic conditions, specifically higher interest rates as well as other impacts of inflation. These macroeconomic 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 2022 annual MD&A. For details on Emera’s reportable segments, refer to note 1 of the Q2 2023 unaudited condensed consolidated interim financial statements.
Florida Electric Utility
TEC anticipates earning within its ROE range in 2023. New base rates effective January 1, 2023, as a result of the 2021 settlement agreement, will result in higher 2023 USD earnings than in 2022. Normalizing 2022 for weather, TEC sales volumes in 2023 are projected to be higher than in 2022 due to customer growth. TEC expects customer growth rates in 2023 to be comparable to 2022, reflective of the current expected economic growth in Florida.
On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, and were effective beginning on April 1, 2023.
On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the previous approved storm reserve level of $56 million USD, for a total of approximately $131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge on April 2023 bills. The storm recovery is subject to review of the underlying costs for prudency by the FPSC. The review is expected to be completed by the end of 2023.
In 2023, capital investment in the Florida Electric Utility segment is expected to be $1.4 billion USD (2022 – $1.1 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, grid modernization and storm hardening investments.
Canadian Electric Utilities
NSPI
NSPI anticipates earning near the low end of its allowed ROE range in 2023 and expects earnings and sales volumes to be higher in 2023 than 2022.
Energy from renewable sources has increased due to the improved delivery of the NS Block of energy from Nalcor Energy’s (“Nalcor”) Muskrat Falls hydroelectric project (“Muskrat Falls”) to NSPI. For more information on the commissioning of LIL, refer to the “LIL” section below. For more information related to Nalcor’s delivery obligations of the NS Block of energy and the option for NSPI to purchase additional market-priced energy, refer to the “Business Overview and Outlook – Canadian Electric Utilities” section of Emera’s 2022 annual MD&A.
On March 27, 2023, the UARB issued its final order approving the new electricity rates related to the General Rate Application settlement agreement between NSPI, key customer representatives and participating interest groups. The new electricity rates were effective on February 2, 2023.
10
In 2023, NSPI’s capital investment is expected to be approximately $405 million (2022 – $540 million), including AFUDC. NSPI is investing primarily in capital projects required to support power system reliability and reliable service for customers.
Environmental Legislation and Regulation
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia (the “Province”). For further discussion on environmental legislation and regulations and associated risks, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Enterprise Risk and Risk Management” sections respectively of Emera’s 2022 annual MD&A. Recent developments related to provincial and federal environmental laws and regulations are outlined below.
Nova Scotia Cap-and-Trade Program Regulations:
On March 16, 2023, the Province amended the Nova Scotia Cap-and-Trade Program Regulations, providing NSPI with additional emissions allowances sufficient to achieve compliance for the 2019 through 2022 compliance period. Accrued compliance costs of $166 million related to the anticipated purchase of emissions credits were reversed in Q1 2023. Credits NSPI purchased from provincial auctions in the amount of $6 million will not be refunded and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-Trade Program.
Carbon Pricing Regulations:
In November 2022, the Province enacted amendments to the Environment Act which provided the framework for Nova Scotia to implement an output-based pricing system (“OBPS”) to comply with the federal government’s 2023 through 2030 carbon pollution pricing regulations, effective January 1, 2023. The federal government approved the Province’s proposed system, however the OBPS will be subject to an interim review by the federal government of the standards effective for 2026. Although subsequent provincial regulations are required to detail how the OBPS will operate, the Province has shared preliminary standards with NSPI. The OBPS implements greenhouse gas (“GHG”) emissions performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023 and will increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI’s fuel adjustment mechanism (“FAM”).
Nova Scotia Renewable Electricity Regulations (“RER”):
On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER compliance period ending in 2022. The penalty was recorded in OM&G on the Condensed Consolidated Statements of Income. On May 26, 2023, NSPI initiated an appeal of the penalty through a proceeding with the UARB, as permitted under the RER.
Performance Standards Penalty Amendment:
On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-compliance with current and future performance standards in a calendar year from $1 million to $25 million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot recover administrative penalties imposed through rates.
Emera Newfoundland & Labrador Holdings Inc. (“ENL”)
Total equity earnings from NSPML and LIL are expected to be higher in 2023, compared to 2022. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.
11
NSPML
In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023, subject to a holdback of up to $2 million a month. As of June 30, 2023, $18 million ($14 million related to 2022 and $4 million related to Q1 2023) in aggregate has been held back by NSPI, which represents the total holdback for the nine months in which NSPML did not achieve the 90 per cent required delivery of the NS Block. NSPML did not incur any additional holdback in each month of Q2 2023 as a result of achieving the full 90 per cent NS Block deliveries. Determination of allocation of the $18 million between NSPML or to NSPI’s FAM for the benefit of customers is subject to a regulatory process before the UARB, which commenced in March 2023. A decision from the UARB on the holdback is expected later in 2023. For more information on the commissioning of LIL, refer to the “LIL” section below.
NSPML does not anticipate any significant capital investment in 2023.
LIL
ENL is a limited partner with Nalcor in the LIL. Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canada’s Independent Engineer issuance of its Commissioning Certificate on April 13, 2023.
Upon issuance of the Commissioning Certificate, AFUDC equity earnings have ceased and in turn cash equity earnings and return of equity to Emera have commenced.
Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE of 8.5 per cent. Emera’s current equity investment is $754 million, comprised of $410 million in equity contribution and $344 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million once the final costing has been confirmed by Nalcor to determine the investment true-up.
Gas Utilities and Infrastructure
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2023 than 2022, primarily due to a base rate increase at NMGC.
PGS expects 2023 rate base growth to be consistent with 2022, with slightly lower USD earnings as a result of higher costs driven by customer growth and the effect of macroeconomic conditions, such as inflation and interest costs, which will more than offset higher revenue from new customers. As a result, PGS expects to earn below its allowed ROE range in 2023.
On April 4, 2023, PGS filed a rate case with the FPSC for new rates to become effective January 2024. PGS requested a $139 million USD increase in annual base rates, including $11 million USD from the cast iron and bare steel replacement rider. This reflects an 11 per cent midpoint ROE. The hearing for the matter is expected to be held in Q3 2023 with a final decision expected by the FPSC in Q4 2023.
The 2020 PGS rate case settlement provides the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. PGS had reversed $23 million USD accumulated depreciation through June 30, 2023, including $14 million USD reversed in 2022. The reversal of the remaining accumulated depreciation is expected to occur by December 31, 2023.
NMGC expects 2023 rate base and USD earnings to be higher in 2023 than 2022. Higher 2023 earnings are primarily due to base rate increases effective January 2023. NMGC anticipates earning near its authorized ROE in 2023 and expects customer growth rates to be consistent with historical trends.
12
In 2023, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $500 million USD (2022 – $436 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will continue to make investments to maintain the safety and reliability of its system and support customer growth.
Other Electric Utilities
Absent the impact of the GBPC impairment charge in Q4 2022, Other Electric Utilities’ USD earnings in 2023 are expected to increase over the prior year primarily as a result of higher earnings due to higher base rates at BLPC.
On October 4, 2021, BLPC submitted a general rate review application to the FTC. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities related to the self-insurance fund of $50 million USD and prior year benefits recognized on remeasurement of deferred income taxes of $5 million USD, and a regulatory asset related to accumulated depreciation of $11 million USD. The FTC also requested a compliance filing before setting final rates which was submitted by BLPC on March 8, 2023. On March 7, 2023, BLPC filed a Motion for Review and Variation of FTC’s decision and applied for a Stay of the Decision. The FTC has determined that it will hear the Motion for Review by way of an oral hearing and parties were invited to submit and exchange written submissions on these matters during Q2 2023. On May 12, 2023, the FTC granted the Stay of the Decision until the determination of the Motion for Review and Variation which is scheduled to be heard in Q3 2023. The final impacts to BLPC’s rate base and final rates are not yet determinable and have not been recorded but management does not expect the final decision to have a material impact on Emera’s adjusted net income. BLPC expects a decision on final rates from the FTC in 2023.
In 2023, capital investment in the Other Electric Utilities segment is expected to be approximately $65 million USD (2022 – $48 million USD).
Other
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million USD of margin).
Absent the TECO Guatemala Holdings (“TGH”) award in Q4 2022, the adjusted net loss from the Other segment is expected to be higher in 2023 due to increased interest expense, partially offset by decreased Corporate OM&G and decreased taxes due to a higher net loss. For details on the TGH award refer to the “Significant Items Affecting Earnings” section in Emera’s 2022 annual MD&A.
The Other segment does not anticipate any significant capital investment in 2023.
13
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2022 and June 30, 2023 include:
| millions of dollars | Increase (Decrease) |
Explanation | ||||
|
| ||||||
| Assets |
||||||
|
| ||||||
| Inventory |
$ | 57 | Increased due to higher costs and levels of fuel and materials inventory at NSPI and TEC, partially offset by lower commodity prices and natural gas volumes at EES | |||
|
| ||||||
| Derivative instruments (current and long-term) | (131) | Decreased due to lower commodity prices and settlements of derivative instruments at NSPI | ||||
|
| ||||||
| Regulatory assets (current and long-term) | (305) | Decreased due to higher fuel clause recoveries at TEC, the reversal of accrued Cap-and-Trade emission compliance charges at NSPI, and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by increased FAM deferrals due to a change in fuel cost recovery methodology for an industrial customer and higher deferred income tax regulatory asset at NSPI | ||||
|
| ||||||
| Receivables and other assets (current and long-term) | (1,107) | Decreased due to lower gas transportation assets, decreased cash collateral and lower trade receivables as a result of lower commodity prices at EES, and settlement of the gas hedge receivable and seasonal trends of the business at NMGC | ||||
|
| ||||||
| Property, Plant and Equipment (“PP&E”), net of accumulated depreciation and amortization | 411 | Increased due to capital additions in excess of depreciation and amortization, partially offset due to the effect of the FX translation of Emera’s non-Canadian affiliates | ||||
|
| ||||||
| Goodwill | (135) | Decreased due to the effect of the FX translation of Emera’s non-Canadian affiliates | ||||
|
| ||||||
| Liabilities and Equity | ||||||
|
| ||||||
| Short-term debt and long-term debt (including current portion) | $ | 345 | Issuance of debt at NSPI and proceeds from committed credit facilities at Emera, partially offset by the effect of the FX translation of Emera’s non-Canadian affiliates, net repayments under committed credit facilities at NSPI and repayment of debt at NMGC | |||
|
| ||||||
| Accounts payable | (742) | Decreased due to lower commodity prices at EES, TEC and NMGC, decreased cash collateral position on derivative instruments at NSPI, seasonal trends of the business at NMGC, and timing of payments at TEC | ||||
|
| ||||||
| Deferred income tax liabilities, net of deferred income tax assets | 132 | Increased due to tax deductions in excess of accounting depreciation related to PP&E, partially offset by the effect of the FX translation of Emera’s non-Canadian affiliates | ||||
|
| ||||||
| Derivative instruments (current and long-term) | (574) | Decreased due to the reversal of 2022 contracts and changes in existing positions at EES, partially offset by new contracts in 2023 | ||||
|
| ||||||
| Regulatory liabilities (current and long-term) | (366) | Decreased due to settlement of NMGC gas hedges and decreased deferrals related to derivative instruments at NSPI | ||||
|
| ||||||
| Other liabilities (current and long-term) | (145) | Decreased due to the reversal of accrued Cap-and-Trade emissions compliance charges at NSPI | ||||
|
| ||||||
| Common stock | 160 | Increased due to shares issued | ||||
|
| ||||||
| Accumulated other comprehensive income | (216) | Decreased due to the effect of the FX translation of Emera’s non-Canadian affiliates | ||||
|
| ||||||
| Retained earnings |
214 | Increased due to net income in excess of dividends paid | ||||
|
| ||||||
14
FINANCIAL HIGHLIGHTS
Florida Electric Utility
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of USD (except as indicated) | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Operating revenues – regulated electric |
$ | 677 | $ | 663 | $ | 1,229 | $ | 1,173 | ||||||||
|
|
||||||||||||||||
| Regulated fuel for generation and purchased power |
$ | 164 | $ | 225 | $ | 310 | $ | 361 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income |
$ | 132 | $ | 126 | $ | 211 | $ | 214 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income – CAD |
$ | 177 | $ | 161 | $ | 284 | $ | 273 | ||||||||
|
|
||||||||||||||||
| Electric sales volumes (Gigawatt hours (“GWh”)) |
5,136 | 5,270 | 9,610 | 9,743 | ||||||||||||
|
|
||||||||||||||||
| Electric production volumes (GWh) |
5,726 | 5,752 | 10,316 | 10,334 | ||||||||||||
|
|
||||||||||||||||
| Average fuel cost in dollars per megawatt hour (“MWh”) |
$ | 29 | $ | 39 | $ | 30 | $ | 35 | ||||||||
|
|
||||||||||||||||
The impact of the change in the FX rate increased CAD earnings for the three and six months ended June 30, 2023 by $9 million and $15 million, respectively.
Highlights of the net income changes are summarized in the following table:
| For the millions of USD |
Three months ended June 30 |
Six months ended June 30 |
||||||
|
|
||||||||
| Contribution to consolidated net income – 2022 |
$ | 126 | $ | 214 | ||||
|
|
||||||||
| Increased operating revenues due to storm cost recovery surcharge revenue, new base rates and customer growth, partially offset by changes in fuel recovery clause revenue and less favourable weather | 14 | 56 | ||||||
|
|
||||||||
| Decreased regulated fuel for generation and purchased power due to lower natural gas prices | 61 | 51 | ||||||
|
|
||||||||
| Increased OM&G due to storm restoration cost recognition related to the storm surcharge, timing of deferred clause recoveries, and higher generation maintenance | (47) | (58) | ||||||
|
|
||||||||
| Increased depreciation and amortization due to additions to facilities and the in-service of generation projects | (9) | (18) | ||||||
|
|
||||||||
| Increased interest expense due to higher interest rates and higher borrowings to support capital investments and ongoing operations | (19) | (39) | ||||||
|
|
||||||||
| Decreased AFUDC earnings due to power plant modernization and solar projects incorporated in base rates | (3) | (8) | ||||||
|
|
||||||||
| Decreased income tax expense primarily due to production tax credits related to solar facilities | 9 | 13 | ||||||
|
|
||||||||
| Contribution to consolidated net income – 2023 | $ | 132 | $ | 211 | ||||
|
|
||||||||
15
Canadian Electric Utilities
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars (except as indicated) | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Operating revenues – regulated electric |
$ | 340 | $ | 375 | $ | 844 | $ | 884 | ||||||||
|
|
||||||||||||||||
| Regulated fuel for generation and purchased power (1) |
$ | 227 | $ | 235 | $ | 330 | $ | 538 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated adjusted net income |
$ | 49 | $ | 39 | $ | 141 | $ | 137 | ||||||||
|
|
||||||||||||||||
| NSPML unrecoverable costs |
$ | - | $ | - | $ | - | $ | (7) | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income |
$ | 49 | $ | 39 | $ | 141 | $ | 130 | ||||||||
|
|
||||||||||||||||
| Electric sales volumes (GWh) |
2,315 | 2,380 | 5,446 | 5,571 | ||||||||||||
|
|
||||||||||||||||
| Electric production volumes (GWh) |
2,430 | 2,494 | 5,784 | 5,923 | ||||||||||||
|
|
||||||||||||||||
| Average fuel costs in dollars per MWh (2) |
$ | 93 | $ | 94 | $ | 57 | $ | 91 | ||||||||
|
|
||||||||||||||||
| (1) Regulated fuel for generation and purchased power includes NSPI’s FAM deferral on the Condensed Consolidated Statements of Income, however, it is excluded in the segment overview. (2) Average fuel costs for the six months ended June 30, 2023 include the reversal of the $166 million of Nova Scotia Cap-and-Trade Program provision (2022 – $112 million expense).
Canadian Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
|
| |||||||||||||||
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| NSPI |
$ | 23 | $ | 17 | $ | 91 | $ | 88 | ||||||||
|
|
||||||||||||||||
| Equity investment in LIL |
13 | 12 | 29 | 26 | ||||||||||||
|
|
||||||||||||||||
| Equity investment in NSPML (1) |
13 | 10 | 21 | 23 | ||||||||||||
|
|
||||||||||||||||
| Contribution to consolidated adjusted net income |
$ | 49 | $ | 39 | $ | 141 | $ | 137 | ||||||||
|
|
||||||||||||||||
(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the six months ended June 30, 2022.
16
Highlights of the net income changes are summarized in the following table:
| For the millions of dollars |
Three months ended June 30 |
Six months ended June 30 |
||||||
|
|
||||||||
| Contribution to consolidated net income – 2022 |
$ | 39 | $ | 130 | ||||
|
|
||||||||
| Decreased operating revenues due to changes in fuel cost recovery methodology for an industrial customer(1) and decreased industrial sales volumes. These were partially offset by new rates and increased residential, commercial and other sales volumes. Year-over-year decrease also due to unfavourable weather | (35) | (40) | ||||||
|
|
||||||||
| Decreased regulated fuel for generation and purchased power year-over-year primarily due to the reversal of the Nova Scotia Cap-and-Trade Program provision, compared to an expense in 2022. This was partially offset by increased commodity prices and the Nova Scotia OBPS carbon tax accrual | 8 | 208 | ||||||
|
|
||||||||
| Increased FAM deferral quarter-over-quarter primarily due to changes in the fuel cost recovery methodology for an industrial customer(1). Year-over-year, decreased primarily due to the reversal of the Nova Scotia Cap-and-Trade Program provision, partially offset by changes in the fuel recovery methodology for an industrial customer(1) | 53 | (129) | ||||||
|
|
||||||||
| Increased OM&G quarter-over-quarter due to higher costs for vegetation management and line services, year-over-year also due to recognition of the RER penalty at NSPI | (6) | (16) | ||||||
|
|
||||||||
| Increased depreciation and amortization due to increased PP&E in service | (7) | (11) | ||||||
|
|
||||||||
| Increased interest expense due to increased interest rates and higher debt levels | (9) | (20) | ||||||
|
|
||||||||
| Increased income from equity investments quarter-over-quarter primarily due to Maritime Link holdback recognized in 2022 | 4 | 1 | ||||||
|
|
||||||||
| Decreased income tax expense at NSPI due to increased tax deductions in excess of accounting depreciation related to PP&E, partially offset by an increase in the benefit of tax loss carryforwards recognized as a deferred income tax regulatory liability | 2 | 9 | ||||||
|
|
||||||||
| NSPML unrecoverable costs in 2022 | - | 7 | ||||||
|
|
||||||||
| Other | - | 2 | ||||||
|
|
||||||||
| Contribution to consolidated net income – 2023 |
$ | 49 | $ | 141 | ||||
|
|
||||||||
(1) For more information on the changes in fuel cost recovery methodology for an industrial customer, refer to note 6 in the Q2 2023 unaudited condensed consolidated interim financial statements
The Nova Scotia Cap-and-Trade Program provision related to the accrued cost of acquiring emissions credits for the 2019 through 2022 compliance period. As of December 31, 2022, NSPI had recognized a cumulative $166 million accrual in fuel costs related to the anticipated purchase of emissions credits and $6 million related to credits purchased from provincial auction. The accrued compliance costs of $166 million were reversed in Q1 2023 and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-Trade Program. For further information on the reversal of this non-cash accrual and the FAM regulatory balance, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPI” section and note 6 in the Q2 2023 unaudited condensed consolidated interim financial statements.
17
Gas Utilities and Infrastructure
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of USD (except as indicated) | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Operating revenues – regulated gas (1) |
$ | 209 | $ | 266 | $ | 631 | $ | 664 | ||||||||
|
|
||||||||||||||||
| Operating revenues – non-regulated |
4 | 3 | 8 | 6 | ||||||||||||
|
|
||||||||||||||||
| Total operating revenue |
$ | 213 | $ | 269 | $ | 639 | $ | 670 | ||||||||
|
|
||||||||||||||||
| Regulated cost of natural gas |
$ | 43 | $ | 116 | $ | 248 | $ | 318 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income |
$ | 28 | $ | 31 | $ | 98 | $ | 92 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income – CAD |
$ | 38 | $ | 39 | $ | 132 | $ | 116 | ||||||||
|
|
||||||||||||||||
| Gas sales volumes (millions of Therms) |
698 | 654 | 1,628 | 1,487 | ||||||||||||
|
|
||||||||||||||||
| (1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2022 – $12 million) for the three months ended June 30, 2023 and $23 million (2022 – $23 million) for the six months ended June 30, 2023.
Gas Utilities and Infrastructure’s contribution is summarized in the following table:
|
| |||||||||||||||
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of USD | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| PGS |
$ | 19 | $ | 19 | $ | 45 | $ | 49 | ||||||||
|
|
||||||||||||||||
| NMGC |
- | (2) | 33 | 17 | ||||||||||||
|
|
||||||||||||||||
| Other |
9 | 14 | 20 | 26 | ||||||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income |
$ | 28 | $ | 31 | $ | 98 | $ | 92 | ||||||||
|
|
||||||||||||||||
The impact of the change in the FX rate increased CAD earnings for the three and six months ended June 30, 2023 by $1 million and $7 million, respectively.
Highlights of the net income changes are summarized in the following table:
| For the millions of USD |
Three months ended June 30 |
Six months ended June 30 |
||||||
|
|
||||||||
| Contribution to consolidated net income – 2022 |
$ | 31 | $ | 92 | ||||
|
|
||||||||
| Decreased operating revenues - regulated gas due to lower fuel revenues and off-system sales at PGS, partially offset by new base rates at NMGC and customer growth at PGS | (57) | (43) | ||||||
|
|
||||||||
| Increased asset optimization revenue at NMGC | 1 | 12 | ||||||
|
|
||||||||
| Decreased regulated cost of natural gas sold due to lower natural gas prices at PGS and NMGC | 73 | 70 | ||||||
|
|
||||||||
| Increased OM&G primarily due to higher labour and benefit costs at PGS | (7) | (11) | ||||||
|
|
||||||||
| Increased interest expense due to higher interest rates and increased borrowings to support ongoing operations and capital investments | (10) | (15) | ||||||
|
|
||||||||
| Other | (3) | (7) | ||||||
|
|
||||||||
| Contribution to consolidated net income – 2023 |
$ | 28 | $ | 98 | ||||
|
|
||||||||
18
Other Electric Utilities
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of USD (except as indicated) | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Operating revenues – regulated electric |
$ | 93 | $ | 102 | $ | 178 | $ | 196 | ||||||||
|
|
||||||||||||||||
| Regulated fuel for generation and purchased power |
$ | 48 | $ | 61 | $ | 90 | $ | 111 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated adjusted net income |
$ | 7 | $ | 6 | $ | 10 | $ | 7 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated adjusted net income – CAD |
$ | 10 | $ | 8 | $ | 14 | $ | 9 | ||||||||
|
|
||||||||||||||||
| Equity securities MTM (loss) gain |
$ | - | $ | (2) | $ | 1 | $ | (4) | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income |
$ | 7 | $ | 4 | $ | 11 | $ | 3 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income – CAD |
$ | 9 | $ | 5 | $ | 15 | $ | 4 | ||||||||
|
|
||||||||||||||||
| Electric sales volumes (GWh) |
310 | 302 | 593 | 609 | ||||||||||||
|
|
||||||||||||||||
| Electric production volumes (GWh) |
346 | 335 | 646 | 659 | ||||||||||||
|
|
||||||||||||||||
| Average fuel costs in dollars per MWh |
$ | 139 | $ | 182 | $ | 139 | $ | 168 | ||||||||
|
|
||||||||||||||||
|
Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
|
| |||||||||||||||
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of USD | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| BLPC |
$ | 6 | $ | 1 | $ | 8 | $ | 3 | ||||||||
|
|
||||||||||||||||
| GBPC |
2 | 1 | 4 | 3 | ||||||||||||
|
|
||||||||||||||||
| Other |
(1) | 4 | (2) | 1 | ||||||||||||
|
|
||||||||||||||||
| Contribution to consolidated adjusted net income |
$ | 7 | $ | 6 | $ | 10 | $ | 7 | ||||||||
|
|
||||||||||||||||
The impact of the change in the FX rate on CAD earnings for the three months and six months ended June 30, 2023 was minimal.
Highlights of the net income changes are summarized in the following table:
| For the millions of USD |
Three months ended June 30 |
Six months ended June 30 |
||||||
|
|
||||||||
| Contribution to consolidated net income – 2022 |
$ | 4 | $ | 3 | ||||
|
|
||||||||
| Decreased operating revenues due to lower fuel revenues at BLPC, partially offset by interim rates at BLPC and increased sales volumes at GBPC. Year-over-year also decreased due to the sale of Dominica Electricity Services Ltd. in Q1 2022 | (9) | (18) | ||||||
|
|
||||||||
| Decreased regulated fuel for generation and purchased power due to lower fuel prices and changes in the generation mix at BLPC | 13 | 21 | ||||||
|
|
||||||||
| Increased MTM gain on equity securities held at BLPC | 2 | 5 | ||||||
|
|
||||||||
| Other | (3) | - | ||||||
|
|
||||||||
| Contribution to consolidated net income – 2023 |
$ | 7 | $ | 11 | ||||
|
|
||||||||
19
Other
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Marketing and trading margin (1) (2) |
$ | (34) | $ | (2) | $ | 61 | $ | 47 | ||||||||
|
|
||||||||||||||||
| Other non-regulated operating revenue |
9 | 3 | 15 | 10 | ||||||||||||
|
|
||||||||||||||||
| Total operating revenues – non-regulated |
$ | (25) | $ | 1 | $ | 76 | $ | 57 | ||||||||
|
|
||||||||||||||||
| Contribution to consolidated adjusted net income (loss) |
$ | (112) | $ | (91) | $ | (141) | $ | (137) | ||||||||
|
|
||||||||||||||||
| MTM (loss) gain, after-tax (3) |
(133) | (220) | 157 | (91) | ||||||||||||
|
|
||||||||||||||||
| Contribution to consolidated net income (loss) |
$ | (245) | $ | (311) | $ | 16 | $ | (228) | ||||||||
|
|
||||||||||||||||
| (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 MTM loss, pre-tax of $249 million in Q2 2023 (2022 – $307 million loss) and a gain of $186 million year-to-date (2022 – $117 million loss). (3) Net of income tax recovery of $55 million for the three months ended June 30, 2023 (2022 – $91 million recovery) and $64 million income tax expense for the six months ended June 30, 2023 (2022 – $37 million recovery).
Other’s contribution to consolidated adjusted net income (loss) is summarized in the following table:
|
| |||||||||||||||
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Emera Energy |
$ | (20) | $ | (6) | $ | 36 | $ | 21 | ||||||||
|
|
||||||||||||||||
| Corporate – see breakdown of adjusted contribution below |
(86) | (79) | (166) | (146) | ||||||||||||
|
|
||||||||||||||||
| Block Energy LLC (1) |
(5) | (5) | (9) | (10) | ||||||||||||
|
|
||||||||||||||||
| Other |
(1) | (1) | (2) | (2) | ||||||||||||
|
|
||||||||||||||||
| Contribution to consolidated adjusted net income (loss) |
$ | (112) | $ | (91) | $ | (141) | $ | (137) | ||||||||
|
|
||||||||||||||||
(1) Previously Emera Technologies LLC
Highlights of the net income changes are summarized in the following table:
| For the millions of dollars |
Three months ended June 30 |
Six months ended June 30 |
||||||
|
|
||||||||
| Contribution to consolidated net income (loss) – 2022 |
$ | (311) | $ | (228) | ||||
|
|
||||||||
| Decreased marketing and trading margin quarter-over-quarter primarily due to lower natural gas prices and timing of recognition of transport and other costs at EES. Year-over-year increase reflects favourable hedging opportunities and more available gas transport due to mild weather in Q1 2023 at EES | (32) | 14 | ||||||
|
|
||||||||
| Increased interest expense, pre-tax, due to increased interest rates and increased total debt | (10) | (30) | ||||||
|
|
||||||||
| Realized FX gain on translation of foreign currency bank balances | 6 | 2 | ||||||
|
|
||||||||
| Increased income tax recovery primarily due to increased losses before provision for income taxes | 11 | - | ||||||
|
|
||||||||
| Decreased MTM loss, after-tax primarily due to favourable changes in existing positions partially offset by higher amortization of gas transportation assets at EES | 87 | 248 | ||||||
|
|
||||||||
| Other | 4 | 10 | ||||||
|
|
||||||||
| Contribution to consolidated net income (loss) – 2023 |
$ | (245) | $ | 16 | ||||
|
|
||||||||
20
Corporate
Corporate’s adjusted loss is summarized in the following table:
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars |
2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Operating expenses (1) |
$ | 28 | $ | 21 | $ | 34 | $ | 36 | ||||||||
|
|
||||||||||||||||
| Interest expense |
75 | 65 | 157 | 127 | ||||||||||||
|
|
||||||||||||||||
| Income tax recovery |
(27) | (24) | (52) | (45) | ||||||||||||
|
|
||||||||||||||||
| Preferred dividends |
16 | 15 | 32 | 31 | ||||||||||||
|
|
||||||||||||||||
| Other (2) (3) |
(6) | 2 | (5) | (3) | ||||||||||||
|
|
||||||||||||||||
| Corporate adjusted net loss (4) |
$ | (86) | $ | (79) | $ | (166) | $ | (146) | ||||||||
|
|
||||||||||||||||
(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 $2 million ($2 million after-tax) for the three months ended June 30, 2023 (2022 – nil) and a $5 million net loss, pre-tax ($4 million after-tax) for the six months ended June 30, 2023 (2022 – nil) on FX hedges, as discussed above.
(4) Excludes a MTM gain, after-tax, of $12 million for the three months ended June 30, 2023 (2022 – nil) and a MTM gain, after-tax of $16 million for the six months ended June 30, 2023 (2022 – $1 million gain, after-tax).
LIQUIDITY AND CAPITAL RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include changes to global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity price changes on collateral requirements and timely recoveries of fuel 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 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 $8 – 9 billion capital investment plan over the 2023-to-2025 period, mainly focused in Florida. This plan includes significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. Capital investments at the regulated utilities are subject to regulatory approval.
Emera plans to use cash from operations and debt raised at the utilities 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. 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 DRIP and ATM programs.
Emera has credit facilities with varying maturities that cumulatively provide $5.1 billion of credit, with approximately $1.3 billion undrawn and available at June 30, 2023. The Company was holding a cash balance of $335 million at June 30, 2023. For further discussion, refer to the “Debt Management” section below. For additional information regarding the credit facilities, refer to notes 18 and 19 in the Q2 2023 unaudited condensed consolidated interim financial statements.
21
Consolidated Cash Flow Highlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the six months ended June 30, 2023 and 2022 include:
| millions of dollars |
2023 | 2022 | Change | |||||||||
|
|
||||||||||||
| Cash, cash equivalents, and restricted cash, beginning of period |
$ | 332 | $ | 417 | $ | (85) | ||||||
|
|
||||||||||||
| Provided by (used in): |
||||||||||||
| Operating cash flow before changes in working capital |
1,163 | 746 | 417 | |||||||||
|
|
||||||||||||
| Change in working capital |
(212) | (73) | (139) | |||||||||
|
|
||||||||||||
| Operating activities |
$ | 951 | $ | 673 | $ | 278 | ||||||
|
|
||||||||||||
| Investing activities |
(1,343) | (1,030) | (313) | |||||||||
|
|
||||||||||||
| Financing activities |
400 | 238 | 162 | |||||||||
|
|
||||||||||||
| Effect of exchange rate changes on cash, cash equivalents, and restricted cash |
(5) | (2) | (3) | |||||||||
|
|
||||||||||||
| Cash, cash equivalents, and restricted cash, end of period |
$ | 335 | $ | 296 | $ | 39 | ||||||
|
|
||||||||||||
Cash Flow from Operating Activities
Net cash provided by operating activities increased $278 million to $951 million for the six months ended June 30, 2023, compared to $673 million for the same period in 2022.
Cash from operations before changes in working capital increased $417 million. This increase was due to higher fuel clause recoveries at TEC, and decreased fuel for generation and purchased power expense driven by the decreased Nova Scotia Cap-and-Trade Program provision. This was partially offset by a decrease in regulatory liabilities due to 2022 gas hedge settlements at NMGC.
Changes in working capital decreased operating cash flows by $139 million year-over-year. This decrease was due to the timing of accounts payable payments at NSPI and TEC, unfavourable changes in cash collateral positions at NSPI, decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges, and unfavourable change in fuel inventory at NSPI. This was partially offset by favourable changes in accounts receivable at NMGC due to the receipt of its 2022 gas hedge settlement, and favourable changes in cash collateral positions at Emera Energy.
Cash Flow from Investing Activities
Net cash used in investing activities increased $313 million to $1,343 million for the six months ended June 30, 2023, compared to $1,030 million for the same period in 2022. The increase was due to higher capital investment in 2023.
Capital investments, including AFUDC, for the six months ended June 30, 2023, were $1,368 million compared to $1,065 million for the same period in 2022. Details of the 2023 capital investment by segment are shown below:
| · | $778 million – Florida Electric Utility (2022 – $586 million); |
| · | $222 million – Canadian Electric Utilities (2022 – $196 million); |
| · | $335 million – Gas Utilities and Infrastructure (2022 – $250 million); |
| · | $28 million – Other Electric Utilities (2022 – $31 million); and |
| · | $5 million – Other (2022 – $2 million). |
Cash Flow from Financing Activities
Net cash provided by financing activities increased $162 million to $400 million for the six months ended June 30, 2023, compared to $238 million for the same period in 2022. This increase was due to proceeds from long-term debt at NSPI, and higher net proceeds from committed credit facilities at Emera. This was partially offset by higher repayments of committed credit facilities at NSPI, TECO Finance and GBPC, lower issuance of common stock, and higher repayments in 2023 of short-term and long-term debt at NMGC.
22
Contractual Obligations
As at June 30, 2023, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Long-term debt principal |
$ | 16 | 1,539 | 259 | 3,048 | 997 | 10,808 | $ | 16,667 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest payment obligations (1) |
414 | 761 | 714 | 627 | 532 | 7,291 | 10,339 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Transportation (2) |
366 | 566 | 440 | 397 | 380 | 2,780 | 4,929 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Purchased power (3) |
149 | 242 | 241 | 256 | 305 | 3,583 | 4,776 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Fuel, gas supply and storage |
462 | 327 | 122 | 47 | 5 | 1 | 964 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Capital projects |
623 | 184 | 5 | 6 | 1 | - | 819 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Asset retirement obligations |
7 | 2 | 2 | 3 | 1 | 411 | 426 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Pension and post-retirement obligations (4) |
19 | 30 | 30 | 80 | 58 | 168 | 385 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Equity investment commitments (5) |
- | 240 | - | - | - | - | 240 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
83 | 155 | 139 | 52 | 45 | 211 | 685 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| $ | 2,139 | $ | 4,046 | $ | 1,952 | $ | 4,516 | $ | 2,324 | $ | 25,253 | $ | 40,230 | |||||||||||||||
|
|
||||||||||||||||||||||||||||
(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at June 30, 2023, including any expected required payment under associated swap agreements.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $136 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(3) Annual requirement to purchase electricity production from Independent Power Producers or other utilities over varying contract lengths.
(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
(5) Emera has a commitment to make equity contributions to the LIL. The commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be made in 2024.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2022, the UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.
Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canada’s Independent Engineer issuance of its Commissioning Certificate on April 13, 2023.
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
23
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 June 30, 2023.
| millions of dollars | Maturity | Credit Facilities |
Utilized | Undrawn and Available |
||||||||||||
|
|
||||||||||||||||
| Emera – Unsecured committed revolving credit facility |
June 2027 | $ | 900 | $ | 686 | $ | 214 | |||||||||
|
|
||||||||||||||||
| TEC (in USD) – Unsecured committed revolving credit facility |
December 2026 | 800 | 795 | 5 | ||||||||||||
|
|
||||||||||||||||
| NSPI – Unsecured committed revolving credit facility |
December 2027 | 800 | 264 | 536 | ||||||||||||
|
|
||||||||||||||||
| Emera – Unsecured non-revolving facility |
December 2023 | 400 | 400 | - | ||||||||||||
|
|
||||||||||||||||
| Emera – Unsecured non-revolving facility |
August 2024 | 400 | 400 | - | ||||||||||||
|
|
||||||||||||||||
| TEC (in USD) – Unsecured non-revolving facility |
December 2023 | 400 | 400 | - | ||||||||||||
|
|
||||||||||||||||
| TECO Finance (in USD) – Unsecured committed revolving credit facility |
December 2026 | 400 | 300 | 100 | ||||||||||||
|
|
||||||||||||||||
| NSPI – Unsecured non-revolving facility |
July 2024 | 400 | 400 | - | ||||||||||||
|
|
||||||||||||||||
| TEC (in USD) - Unsecured revolving facility |
February 2024 | 200 | 30 | 170 | ||||||||||||
|
|
||||||||||||||||
| TEC (in USD) - Unsecured revolving facility |
April 2024 | 200 | - | 200 | ||||||||||||
|
|
||||||||||||||||
| NMGC (in USD) – Unsecured revolving credit facility |
December 2026 | 125 | 14 | 111 | ||||||||||||
|
|
||||||||||||||||
| NMGC (in USD) – Unsecured non-revolving facility |
March 2024 | 45 | 45 | - | ||||||||||||
|
|
||||||||||||||||
| Other (in USD) – Unsecured committed revolving credit facilities |
Various | 21 | 11 | 10 | ||||||||||||
|
|
||||||||||||||||
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 June 30, 2023.
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On March 1, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit facility which matures on February 28, 2024. The credit facility contains customary representations and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term secured overnight financing rate (“SOFR”), the Bank of Nova Scotia’s prime rate, the federal funds rate or the one-month SOFR, plus a margin. Proceeds from this facility will be used for general corporate purposes.
On April 3, 2023, TEC entered into an additional 364-day, $200 million USD senior unsecured revolving credit facility which matures on April 1, 2024. The credit agreement contains customary representation and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term SOFR, Wells Fargo’s prime rate, the federal funds rate or the one-month SOFR, plus a margin. Proceeds from this facility will be used for general corporate purposes.
Canadian Electric Utilities
On March 24, 2023, NSPI issued $500 million in unsecured notes. The issuance included $300 million unsecured notes that bear interest at 4.95 per cent with a maturity date of November 15, 2032, and $200 million unsecured notes that bear interest at 5.36 per cent with a maturity date of March 24, 2053. Proceeds from these issuances were added to the general funds of the Company and applied primarily to refinance existing indebtedness, to finance capital investment and for general corporate purposes.
Other Electric Utilities
On May 24, 2023, GBPC issued a $28 million USD non-revolving term loan that bears interest at 4.00 per cent with a maturity date of May 24, 2028. Proceeds from this issuance were used to repay GBPC’s $28 million USD bond, which matured in May 2023.
24
Other
On June 30, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the maturity date from August 2, 2023 to August 2, 2024. There were no other changes in commercial terms from the prior agreement.
On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent with a maturity date of May 2, 2030. The proceeds were used to repay Emera’s $500 million unsecured fixed rate notes, which matured in June 2023.
Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2022 annual MD&A, with material updates as noted below:
NSPI renewed guarantees of $15 million USD with terms of varying lengths. As at June 30, 2023, NSPI had $109 million USD (2022 – $119 million USD) of guarantees outstanding with terms of varying lengths, all of which are issued on behalf of its subsidiary, NS Power Energy Marking Incorporated.
Outstanding Stock Data
Common Stock
| Issued and outstanding: | millions of shares |
millions of dollars |
||||||
|
|
||||||||
| Balance, December 31, 2022 |
269.95 | $ | 7,762 | |||||
|
|
||||||||
| Issued under the DRIP, net of discounts |
2.53 | 139 | ||||||
|
|
||||||||
| Senior management stock options exercised and Employee Share Purchase Plan |
0.43 | 21 | ||||||
|
|
||||||||
| Balance, June 30, 2023 |
272.91 | $ | 7,922 | |||||
|
|
||||||||
As at August 8, 2023, the amount of issued and outstanding common shares was 273.0 million.
If all outstanding stock options were converted as at August 8, 2023, an additional 3.2 million common shares would be issued and outstanding.
Preferred Stock
As at August 8, 2023, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
On July 6, 2023, Emera announced that it would not redeem the 10,000,000 outstanding Cumulative Rate Reset Preferred Shares, Series C (“Series C Shares”) or the 12,000,000 outstanding Cumulative Minimum Rate Reset First Preferred Shares, Series H (“Series H Shares”) on August 15, 2023. Additionally, during the conversion period between July 17, 2023 and July 31, 2023, subject to certain conditions, the holders of the Series C Shares had the right, at their option, to convert all or any of their Series C Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series D of the Company (the “Series D Shares”) and the holders of the Series H Shares had the right, at their option, to convert all or any of their Series H Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series I of the Company (the “Series I Shares”), in each case on August 15, 2023.
25
On August 4, 2023, Emera announced that after having taken into account all conversion notices received from holders, no Series C Shares would be converted into Series D Shares and no Series H Shares would be converted into Series I Shares. The holders of the Series C Shares will be entitled to receive a dividend of 6.434 per cent per annum on the Series C Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of) August 14, 2028 ($0.40213 per Series C Share per quarter). The holders of the Series H Shares will be entitled to receive a dividend of 6.324 per cent per annum on the Series H Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of) August 14, 2028 ($0.39525 per Series H Share per quarter).
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 June 30, 2023 (2022 – $43 million) and $78 million for the six months ended June 30, 2023 (2022 – $77 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 – ENL” 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 $3 million for the three months ended June 30, 2023 (2022 – $2 million) and $8 million for the six months ended June 30, 2023 (2022 – $6 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at June 30, 2023 and at December 31, 2022.
26
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 2022 annual MD&A.
Derivatives Assets and Liabilities Recognized on the Balance Sheet
| As at millions of dollars |
June 30 2023 |
December 31 2022 |
||||||||||
|
|
||||||||||||
| Regulatory Deferral: |
||||||||||||
| Derivative instrument assets (1) |
$ | 81 | $ | 238 | ||||||||
|
|
||||||||||||
| Derivative instrument liabilities (2) |
(43) | (25) | ||||||||||
|
|
||||||||||||
| Regulatory assets (1) |
55 | 30 | ||||||||||
|
|
||||||||||||
| Regulatory liabilities (2) |
(80) | (230) | ||||||||||
|
|
||||||||||||
| Net asset |
$ | 13 | $ | 13 | ||||||||
|
|
||||||||||||
| HFT Derivatives: |
||||||||||||
| Derivative instrument assets (1) |
$ | 163 | $ | 153 | ||||||||
|
|
||||||||||||
| Derivatives instrument liabilities (2) |
(450) | (1,025) | ||||||||||
|
|
||||||||||||
| Net liability |
$ | (287) | $ | (872) | ||||||||
|
|
||||||||||||
| Other Derivatives: |
||||||||||||
| Derivative instrument assets (1) |
$ | 20 | $ | 5 | ||||||||
|
|
||||||||||||
| Derivatives instrument liabilities (2) |
(11) | (28) | ||||||||||
|
|
||||||||||||
| Net asset (liability) |
$ | 9 | $ | (23) | ||||||||
|
|
||||||||||||
(1) Current and other assets.
(2) Current and long-term liabilities.
Realized and Unrealized Gains (Losses) Recognized in Net Income
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars |
2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Regulatory Deferral: |
||||||||||||||||
| Regulated fuel for generation and purchased power (1) |
$ | (2) | $ | 27 | $ | 64 | $ | 91 | ||||||||
|
|
||||||||||||||||
| HFT Derivatives: |
||||||||||||||||
| Non-regulated operating revenues |
$ | (22) | $ | (258) | $ | 817 | $ | (68) | ||||||||
|
|
||||||||||||||||
| Other Derivatives: |
||||||||||||||||
| OM&G |
$ | (3) | $ | (5) | $ | 8 | $ | (9) | ||||||||
|
|
||||||||||||||||
| Other income, net |
15 | - | 18 | 1 | ||||||||||||
|
|
||||||||||||||||
| Net gains (losses) |
$ | 12 | $ | (5) | $ | 26 | $ | (8) | ||||||||
|
|
||||||||||||||||
| Total net gains (losses) |
$ | (12) | $ | (236) | $ | 907 | $ | 15 | ||||||||
|
|
||||||||||||||||
(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 at | June 30, 2023 | June 30, 2022 | ||||||||||||||
|
|
||||||||||||||||
| millions of dollars | Interest rate hedge |
FX forwards |
Interest rate hedge |
FX forwards |
||||||||||||
|
|
||||||||||||||||
| Total unrealized gain in AOCI – net of tax |
$ | 15 | $ | 1 | $ | 16 | $ | - | ||||||||
|
|
||||||||||||||||
For the three and six months ended June 30, 2023, unrealized gains of nil (2022 – nil) and $1 million (2022 – $1 million), respectively, have been reclassified into interest expense.
27
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 the 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 June 30, 2023, 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 June 30, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2022 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”). ASUs issued by FASB, but which are not yet effective, were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the unaudited condensed consolidated interim financial statements.
28
SUMMARY OF QUARTERLY RESULTS
| For the quarter ended millions of dollars (except per share amounts) |
Q2 2023 |
Q1 2023 |
Q4 2022 |
Q3 2022 |
Q2 2022 |
Q1 2022 |
Q4 2021 |
Q3 2021 |
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Operating revenues |
$ | 1,418 | $ | 2,433 | $ | 2,358 | $ | 1,835 | $ | 1,380 | $ | 2,015 | $ | 1,868 | $ | 1,148 | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 28 | $ | 560 | $ | 483 | $ | 167 | $ | (67) | $ | 362 | $ | 324 | $ | (70) | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Adjusted net income |
$ | 162 | $ | 268 | $ | 249 | $ | 203 | $ | 156 | $ | 242 | $ | 168 | $ | 175 | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| EPS – basic |
$ | 0.10 | $ | 2.07 | $ | 1.80 | $ | 0.63 | $ | (0.25) | $ | 1.38 | $ | 1.24 | $ | (0.27) | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| EPS – diluted |
$ | 0.10 | $ | 2.07 | $ | 1.80 | $ | 0.63 | $ | (0.25) | $ | 1.38 | $ | 1.20 | $ | (0.27) | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Adjusted EPS – basic |
$ | 0.60 | $ | 0.99 | $ | 0.93 | $ | 0.76 | $ | 0.59 | $ | 0.92 | $ | 0.64 | $ | 0.68 | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
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.
29
Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
June 30, 2023 and 2022
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars (except per share amounts)
|
2023
|
2022
|
2023
|
2022
|
||||||||||||
|
|
||||||||||||||||
| Operating revenues |
||||||||||||||||
| Regulated electric |
$ | 1,373 | $ | 1,349 | $ | 2,735 | $ | 2,622 | ||||||||
|
|
||||||||||||||||
| Regulated gas |
277 | 339 | 843 | 841 | ||||||||||||
|
|
||||||||||||||||
| Non-regulated |
(232) | (308) | 273 | (68) | ||||||||||||
|
|
||||||||||||||||
| Total operating revenues (note 5) |
1,418 | 1,380 | 3,851 | 3,395 | ||||||||||||
|
|
||||||||||||||||
| Operating expenses |
||||||||||||||||
| Regulated fuel for generation and purchased power |
396 | 541 | 871 | 1,018 | ||||||||||||
|
|
||||||||||||||||
| Regulated cost of natural gas |
58 | 149 | 334 | 405 | ||||||||||||
|
|
||||||||||||||||
| Operating, maintenance and general expenses (“OM&G”) |
471 | 378 | 901 | 765 | ||||||||||||
|
|
||||||||||||||||
| Provincial, state and municipal taxes |
107 | 91 | 209 | 177 | ||||||||||||
|
|
||||||||||||||||
| Depreciation and amortization |
263 | 230 | 519 | 460 | ||||||||||||
|
|
||||||||||||||||
| Total operating expenses |
|
1,295 |
|
1,389 |
|
2,834 |
|
2,825 | ||||||||
|
|
||||||||||||||||
| Income (loss) from operations |
123 | (9) | 1,017 | 570 | ||||||||||||
|
|
||||||||||||||||
| Income from equity investments (note 7) |
36 | 33 | 71 | 60 | ||||||||||||
|
|
||||||||||||||||
| Other income, net |
57 |
|
21 |
|
92 | 44 | ||||||||||
|
|
||||||||||||||||
| Interest expense, net (note 8) |
223 | 163 | 449 |
|
319 |
| ||||||||||
|
|
||||||||||||||||
| Income (loss) before provision for income taxes |
(7) | (118) | 731 | 355 | ||||||||||||
|
|
||||||||||||||||
| Income tax (recovery) expense (note 9) |
(51) | (66) | 111 | 29 | ||||||||||||
|
|
||||||||||||||||
| Net income (loss) |
44 | (52) | 620 | 326 | ||||||||||||
|
|
||||||||||||||||
| Preferred stock dividends |
16 | 15 | 32 | 31 | ||||||||||||
|
|
||||||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 28 | $ | (67) | $ | 588 | $ | 295 | ||||||||
|
|
||||||||||||||||
| Weighted average shares of common stock outstanding |
||||||||||||||||
| (in millions) (note 11) |
||||||||||||||||
| Basic |
272.3 | 264.4 | 271.5 | 263.1 | ||||||||||||
|
|
||||||||||||||||
| Diluted |
272.6 | 264.4 | 271.8 | 263.6 | ||||||||||||
|
|
||||||||||||||||
| Earnings (loss) per common share (note 11) |
||||||||||||||||
| Basic |
$ | 0.10 | $ | (0.25) | $ | 2.17 | $ | 1.12 | ||||||||
|
|
||||||||||||||||
| Diluted |
$ | 0.10 | $ | (0.25) | $ | 2.16 | $ | 1.12 | ||||||||
|
|
||||||||||||||||
| Dividends per common share declared |
$ | 0.6900 | $ | 0.6625 | $ | 1.3800 | $ | 1.3250 | ||||||||
|
|
||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Net income (loss) |
$ | 44 | $ | (52) | $ | 620 | $ | 326 | ||||||||
|
|
||||||||||||||||
| Other comprehensive income (loss), net of tax |
||||||||||||||||
| Foreign currency translation adjustment (1) |
(250) | 285 | (247) | 147 | ||||||||||||
|
|
||||||||||||||||
| Unrealized gains (losses) on net investment hedges (2) (3) |
35 | (40) | 36 | (21) | ||||||||||||
|
|
||||||||||||||||
| Cash flow hedges |
||||||||||||||||
| Net derivative gains |
1 | - | 1 | - | ||||||||||||
|
|
||||||||||||||||
| Less: reclassification adjustment for gains included in income
|
- | - | (1) | (1) | ||||||||||||
|
|
||||||||||||||||
| Net effects of cash flow hedges |
1 | - | - | (1) | ||||||||||||
|
|
||||||||||||||||
| Net change in unrecognized pension and post-retirement benefit obligation |
(1) | 2 | (5) | (8) | ||||||||||||
|
|
||||||||||||||||
| Other comprehensive (loss) income (4) |
$ | (215) | $ | 247 | $ | (216) | $ | 117 | ||||||||
|
|
||||||||||||||||
| Comprehensive income (loss) of Emera Incorporated |
$ | (171) | $ | 195 | $ | 404 | $ | 443 | ||||||||
|
|
||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Net of tax recovery of $3 million (2022 – nil) for the three months ended June 30, 2023 and tax recovery of $7 million (2022 – nil) for the six months ended June 30, 2023.
(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 expense of nil (2022 – $7 million recovery) for the three months ended June 30, 2023 and tax expense of nil (2022 – $4 million recovery) for the six months ended June 30, 2023.
(4) Net of tax recovery of $3 million (2022 – $7 million recovery) for the three months ended June 30, 2023 and tax recovery of $7 million (2022 – $4 million recovery) for the six months ended June 30, 2023.
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at | June 30 | December 31 | ||||||
| millions of dollars
|
2023
|
2022
|
||||||
|
|
||||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 313 | $ | 310 | ||||
|
|
||||||||
| Restricted cash (note 23) |
22 | 22 | ||||||
|
|
||||||||
| Inventory |
826 | 769 | ||||||
|
|
||||||||
| Derivative instruments (notes 13 and 14) |
199 | 296 | ||||||
|
|
||||||||
| Regulatory assets (note 6) |
514 | 602 | ||||||
|
|
||||||||
| Receivables and other current assets (note 16) |
1,763 | 2,897 | ||||||
|
|
||||||||
| 3,637 | 4,896 | |||||||
| Property, plant and equipment (“PP&E”), net of accumulated depreciation
and amortization of $9,681 and $9,574, respectively |
23,407 | 22,996 | ||||||
|
|
||||||||
| Other assets |
||||||||
| Deferred income taxes (note 9) |
187 | 237 | ||||||
|
|
||||||||
| Derivative instruments (notes 13 and 14) |
66 | 100 | ||||||
|
|
||||||||
| Regulatory assets (note 6) |
2,801 | 3,018 | ||||||
|
|
||||||||
| Net investment in direct finance and sales type leases |
592 | 604 | ||||||
|
|
||||||||
| Investments subject to significant influence (note 7) |
1,417 | 1,418 | ||||||
|
|
||||||||
| Goodwill |
5,877 | 6,012 | ||||||
|
|
||||||||
| Other long-term assets |
488 | 461 | ||||||
|
|
||||||||
| 11,428 | 11,850 | |||||||
|
|
||||||||
| Total assets |
$ | 38,472 | $ | 39,742 | ||||
|
|
||||||||
| Liabilities and Equity |
||||||||
| Current liabilities |
||||||||
| Short-term debt (note 18) |
$ | 2,852 | $ | 2,726 | ||||
|
|
||||||||
| Current portion of long-term debt (note 19) |
96 | 574 | ||||||
|
|
||||||||
| Accounts payable |
1,283 | 2,025 | ||||||
|
|
||||||||
| Derivative instruments (notes 13 and 14) |
399 | 888 | ||||||
|
|
||||||||
| Regulatory liabilities (note 6) |
245 | 495 | ||||||
|
|
||||||||
| Other current liabilities |
392 | 579 | ||||||
|
|
||||||||
| 5,267 | 7,287 | |||||||
|
|
||||||||
|
|
||||||||
| Long-term liabilities |
||||||||
| Long-term debt (note 19) |
16,441 | 15,744 | ||||||
|
|
||||||||
| Deferred income taxes (note 9) |
2,278 | 2,196 | ||||||
|
|
||||||||
| Derivative instruments (notes 13 and 14) |
105 | 190 | ||||||
|
|
||||||||
| Regulatory liabilities (note 6) |
1,662 | 1,778 | ||||||
|
|
||||||||
| Pension and post-retirement liabilities (note 17) |
253 | 281 | ||||||
|
|
||||||||
| Other long-term liabilities (note 7) |
867 | 825 | ||||||
|
|
||||||||
| 21,606 | 21,014 | |||||||
|
|
||||||||
| Equity |
||||||||
| Common stock (note 10) |
7,922 | 7,762 | ||||||
|
|
||||||||
| Cumulative preferred stock |
1,422 | 1,422 | ||||||
|
|
||||||||
| Contributed surplus |
81 | 81 | ||||||
|
|
||||||||
| Accumulated other comprehensive income (“AOCI’) (note 12) |
362 | 578 | ||||||
|
|
||||||||
| Retained earnings |
1,798 | 1,584 | ||||||
|
|
||||||||
| Total Emera Incorporated equity |
11,585 | 11,427 | ||||||
|
|
||||||||
| Non-controlling interest in subsidiaries |
14 | 14 | ||||||
|
|
||||||||
| Total equity |
11,599 | 11,441 | ||||||
|
|
||||||||
| Total liabilities and equity |
$ | 38,472 | $ | 39,742 | ||||
|
|
||||||||
| Commitments and contingencies (note 20) | Approved on behalf of the Board of Directors | |||
| The accompanying notes are an integral part of | “M. Jacqueline Sheppard” | “Scott Balfour” | ||
| these consolidated financial statements. | Chair of the Board | President and Chief Executive Officer | ||
Emera Incorporated
Condensed Consolidated Statements of Cash Flows (Unaudited)
| For the | Six months ended June 30 | |||||||
| millions of dollars
|
2023
|
2022
|
||||||
|
|
||||||||
| Operating activities |
||||||||
| Net income |
$ | 620 | $ | 326 | ||||
|
|
||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
522 | 457 | ||||||
|
|
||||||||
| Income from equity investments, net of dividends |
(20) | (26) | ||||||
|
|
||||||||
| Allowance for funds used during construction (“AFUDC”) – equity |
(17) | (24) | ||||||
|
|
||||||||
| Deferred income taxes, net |
93 | 13 | ||||||
|
|
||||||||
| Net change in pension and post-retirement liabilities |
(35) | (21) | ||||||
|
|
||||||||
| Fuel adjustment mechanism (“FAM”) |
10 | (126) | ||||||
|
|
||||||||
| Net change in fair value of derivative instruments |
(601) | 217 | ||||||
|
|
||||||||
| Net change in regulatory assets and liabilities |
160 | (126) | ||||||
|
|
||||||||
| Net change in capitalized transportation capacity |
378 | (92) | ||||||
|
|
||||||||
| Other operating activities, net |
53 | 148 | ||||||
|
|
||||||||
| Changes in non-cash working capital (note 22) |
(212) | (73) | ||||||
|
|
||||||||
| Net cash provided by operating activities |
951 | 673 | ||||||
|
|
||||||||
| Investing activities |
||||||||
| Additions to PP&E |
(1,351) | (1,041) | ||||||
|
|
||||||||
| Other investing activities |
8 | 11 | ||||||
|
|
||||||||
| Net cash used in investing activities |
(1,343) | (1,030) | ||||||
|
|
||||||||
| Financing activities |
||||||||
| Change in short-term debt, net |
172 | 285 | ||||||
|
|
||||||||
| Proceeds from long-term debt, net of issuance costs |
537 | 2 | ||||||
|
|
||||||||
| Retirement of long-term debt |
(105) | (21) | ||||||
|
|
||||||||
| Net proceeds under committed credit facilities |
55 | 90 | ||||||
|
|
||||||||
| Issuance of common stock, net of issuance costs |
19 | 149 | ||||||
|
|
||||||||
|
|
||||||||
| Dividends on common stock |
(235) | (233) | ||||||
|
|
||||||||
| Dividends on preferred stock |
(32) | (31) | ||||||
|
|
||||||||
| Other financing activities |
(11) | (3) | ||||||
|
|
||||||||
| Net cash provided by financing activities |
400 | 238 | ||||||
|
|
||||||||
| Effect of exchange rate changes on cash, cash equivalents and restricted cash |
(5) | (2) | ||||||
|
|
||||||||
| Net increase (decrease) in cash, cash equivalents, and restricted cash |
3 | (121) | ||||||
|
|
||||||||
| Cash, cash equivalents and restricted cash, beginning of period |
332 | 417 | ||||||
|
|
||||||||
| Cash, cash equivalents and restricted cash, end of period |
$ | 335 | $ | 296 | ||||
|
|
||||||||
| Cash, cash equivalents, and restricted cash consists of: |
||||||||
| Cash |
$ | 303 | $ | 201 | ||||
|
|
||||||||
| Short-term investments |
10 | 74 | ||||||
|
|
||||||||
| Restricted cash |
22 | 21 | ||||||
|
|
||||||||
| Cash, cash equivalents and restricted cash |
$ | 335 | $ | 296 | ||||
|
|
||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| millions of dollars | Common
Stock |
Preferred
Stock |
Contributed
Surplus |
AOCI | Retained
Earnings |
Non-
Controlling
Interest |
Total
Equity |
|||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the three months ended June 30, 2023 |
| |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, March 31, 2023 |
$ | 7,839 | $ | 1,422 | $ | 81 | $ | 577 | $ | 1,958 | $ | 14 | $ | 11,891 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 44 | - | 44 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other comprehensive loss, net of tax recovery of $3 million | - | - | - | (215) | - | - | (215) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on preferred stock (1) | - | - | - | - | (16) | - | (16) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on common stock ($0.6900/share) | - | - | - | - | (188) | - | (188) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts | 70 | - | - | - | - | - | 70 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”) | 13 | - | - | - | - | - | 13 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, June 30, 2023 |
$ | 7,922 | $ | 1,422 | $ | 81 | $ | 362 | $ | 1,798 | $ | 14 | $ | 11,599 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the six months ended June 30, 2023 |
| |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, December 31, 2022 |
$ | 7,762 | $ | 1,422 | $ | 81 | $ | 578 | $ | 1,584 | $ | 14 | $ | 11,441 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 620 | - | 620 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other comprehensive loss, net of tax recovery of $7 million | - | - | - | (216) | - | - | (216) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (32) | - | (32) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on common stock ($1.3800/share) | - | - | - | - | (374) | - | (374) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issued under the DRIP, net of discounts | 139 | - | - | - | - | - | 139 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Senior management stock options exercised and ECSPP | 21 | - | - | - | - | - | 21 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, June 30, 2023 |
$ | 7,922 | $ | 1,422 | $ | 81 | $ | 362 | $ | 1,798 | $ | 14 | $ | 11,599 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Series A; $0.1364/share, Series B; $0.3777/share, Series C; $0.29506/share, Series E; $0.28125/share, Series F; $0.26263/share; Series H; $0.30625/share; Series J; $0.265625/share and Series L; $0.2875/share
(2) Series A; $0.2728/share, Series B; $0.7347/share, Series C; $0.59012/share, Series E; $0.5625/share, Series F; $0.52526/share; Series H; $0.6125/share; Series J; $0.53125/share and Series L; $0.575/share
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| Non- | ||||||||||||||||||||||||||||
| Common | Preferred | Contributed | Retained | Controlling | Total | |||||||||||||||||||||||
| millions of dollars | Stock | Stock | Surplus | AOCI | Earnings | Interest | Equity | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the three months ended June 30, 2022 |
| |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, March 31, 2022 | $ | 7,365 | $ | 1,422 | $ | 79 | $ | (105) | $ | 1,537 | $ | 14 | $ | 10,312 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net loss of Emera Incorporated | - | - | - | - | (52) | - | (52) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other comprehensive income, net of tax recovery of $7 million | - | - | - | 247 | - | - | 247 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on preferred stock (1) | - | - | - | - | (15) | - | (15) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on common stock ($0.6625/share) | - | - | - | - | (175) | - | (175) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs | 72 | - | - | - | - | - | 72 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issued under the DRIP, net of discounts | 56 | - | - | - | - | - | 56 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Senior management stock options exercised and ECSPP | 16 | - | 1 | - | - | - | 17 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, June 30, 2022 | $ | 7,509 | $ | 1,422 | $ | 80 | $ | 142 | $ | 1,295 | $ | 14 | $ | 10,462 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the six months ended June 30, 2022 |
| |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, December 31, 2021 | $ | 7,242 | $ | 1,422 | $ | 79 | $ | 25 | $ | 1,348 | $ | 34 | $ | 10,150 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 326 | - | 326 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other comprehensive income, net of tax recovery of $4 million | - | - | - | 117 | - | - | 117 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (31) | - | (31) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Dividends declared on common stock ($1.3250/share) | - | - | - | - | (348) | - | (348) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Disposal of non-controlling interest of Dominica Electricity Services Ltd (“Domlec”) | - | - | - | - | - | (20) | (20) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issuance of common stock under ATM program, net of after-tax issuance costs | 128 | - | - | - | - | - | 128 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Issued under the DRIP, net of discount | 116 | - | - | - | - | - | 116 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Senior management stock options exercised and ECSPP | 23 | - | 1 | - | - | - | 24 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Balance, June 30, 2022 | $ | 7,509 | $ | 1,422 | $ | 80 | $ | 142 | $ | 1,295 | $ | 14 | $ | 10,462 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Series A; $0.1364/share, Series B; $0.1270/share, Series C; $0.29506/share, Series E; $0.28125/share, Series F; $0.26263/share; Series H; $0.30625/share; Series J; $0.265625/share and Series L; $0.2875/share
(2) Series A; $0.2728/share, Series B; $0.2523/share, Series C; $0.59012/share, Series E; $0.5625/share, Series F; $0.52526/share, Series H; $0.6125/share, Series J; $0.53125/share and Series L; $0.575/share
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at June 30, 2023 and 2022
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, and gas transmission and distribution.
At June 30, 2023, 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 |
| · | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission investments related to an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy. ENL’s two investments are: |
| · | a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.8 billion transmission project, including AFUDC; and |
| · | a 31 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador. |
| · | Gas Utilities and Infrastructure, which includes: |
| · | Peoples Gas Systems, Inc. (“PGS”), a regulated gas distribution utility operating across Florida. Effective January 1, 2023, Peoples Gas System ceased to be a division of Tampa Electric Company and the gas utility was reorganized, resulting in a separate legal entity called Peoples Gas Systems, Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.; |
| · | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico; |
| · | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy North America Canada Partnership, 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 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. |
| · | Emera’s other reportable segment includes investments in energy-related non-regulated companies which 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 pumped storage hydroelectric facility in northwestern Massachusetts. |
| · | Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera; |
| · | Block Energy LLC (previously Emera Technologies 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, 2022.
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, 2023.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
Use of Management Estimates
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2022 annual audited consolidated financial statements.
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”). ASUs issued by FASB, but which are not yet effective, were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the unaudited condensed consolidated interim financial statements.
3. DISPOSITIONS
On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Domlec for proceeds which approximated its carrying value. Domlec was included in the Company’s Other Electric reportable segment up to its date of sale. The sale did not have a material impact on earnings.
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 June 30, 2023 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 907 | $ | 340 | $ | 282 | $ | 126 | $ | (237) | $ | - | $ | 1,418 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Inter-segment revenues (1) | 2 | - | 4 | - | (37) | 31 | - | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
909 | 340 | 286 | 126 | (274) | 31 | 1,418 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 220 | 115 | - | 64 | - | (3) | 396 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 58 | - | - | - | 58 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 217 | 90 | 99 | 32 | 43 | (10) | 471 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 72 | 11 | 22 | 1 | 1 | - | 107 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 141 | 71 | 32 | 17 | 2 | - | 263 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 28 | 6 | - | 2 | - | 36 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income (expense), net | 19 | 7 | 3 | 3 | 69 | (44) | 57 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 70 | 41 | 32 | 6 | 74 | - | 223 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 31 | (2) | 14 | - | (94) | - | (51) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 16 | - | 16 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 177 | $ | 49 | $ | 38 | $ | 9 | $ | (245) | $ | - | $ | 28 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| For the six months ended June 30, 2023 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 1,651 | $ | 844 | $ | 854 | $ | 240 | $ | 262 | $ | - | $ | 3,851 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Inter-segment revenues (1) | 4 | - | 7 | - | - | (11) | - | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
1,655 | 844 | 861 | 240 | 262 | (11) | 3,851 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 417 | 339 | - | 121 | - | (6) | 871 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 334 | - | - | - | 334 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 384 | 191 | 201 | 62 | 77 | (14) | 901 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 135 | 22 | 48 | 2 | 2 | - | 209 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 282 | 138 | 62 | 33 | 4 | - | 519 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 52 | 11 | 1 | 7 | - | 71 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income (expense), net | 36 | 14 | 6 | 4 | 41 | (9) | 92 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 137 | 85 | 57 | 12 | 158 | - | 449 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 52 | (6) | 44 | - | 21 | - | 111 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 32 | - | 32 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income attributable to common shareholders | $ | 284 | $ | 141 | $ | 132 | $ | 15 | $ | 16 | $ | - | $ | 588 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| As at June 30, 2023 |
|
|||||||||||||||||||||||||||
| Total assets | $ | 20,878 | $ | 8,345 | $ | 7,418 | $ | 1,295 | $ | 1,781 | $ | (1,245) | $ | 38,472 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
(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 June 30, 2023, and $43 million for the six months ended June 30, 2023 between the Florida Electric Utility, Gas Utilities and Infrastructure and Other segments.
| 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 June 30, 2022 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) |
$ | 845 | $ | 375 | $ | 341 | $ | 131 | $ | (312) | $ | - | $ | 1,380 | ||||||||||||||
| Inter-segment revenues (1) |
1 | - | 2 | - | 6 | (9) | - | |||||||||||||||||||||
| Total operating revenues |
846 | 375 | 343 | 131 | (306) | (9) | 1,380 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power |
288 | 176 | - | 79 | - | (2) | 541 | |||||||||||||||||||||
| Regulated cost of natural gas |
- | - | 149 | - | - | - | 149 | |||||||||||||||||||||
| OM&G |
147 | 84 | 86 | 31 | 37 | (7) | 378 | |||||||||||||||||||||
| Provincial, state and municipal taxes |
60 | 10 | 20 | 1 | - | - | 91 | |||||||||||||||||||||
| Depreciation and amortization |
124 | 64 | 26 | 14 | 2 | - | 230 | |||||||||||||||||||||
| Income from equity investments |
- | 24 | 4 | 1 | 4 | - | 33 | |||||||||||||||||||||
| Other income (expense), net |
15 | 6 | 5 | 3 | (8) | - | 21 | |||||||||||||||||||||
| Interest expense, net |
40 | 32 | 19 | 5 | 67 | - | 163 | |||||||||||||||||||||
| Income tax expense (recovery) |
41 | - | 13 | - | (120) | - | (66) | |||||||||||||||||||||
| Preferred stock dividends |
- | - | - | - | 15 | - | 15 | |||||||||||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 161 | $ | 39 | $ | 39 | $ | 5 | $ | (311) | $ | - | $ | (67) | ||||||||||||||
| For the six months ended June 30, 2022 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) |
$ | 1,489 | $ | 884 | $ | 848 | $ | 250 | $ | (76) | $ | - | $ | 3,395 | ||||||||||||||
| Inter-segment revenues (1) |
3 | - | 3 | - | 16 | (22) | - | |||||||||||||||||||||
| Total operating revenues |
1,492 | 884 | 851 | 250 | (60) | (22) | 3,395 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power |
460 | 418 | - | 142 | - | (2) | 1,018 | |||||||||||||||||||||
| Regulated cost of natural gas |
- | - | 405 | - | - | - | 405 | |||||||||||||||||||||
| OM&G |
289 | 175 | 176 | 62 | 74 | (11) | 765 | |||||||||||||||||||||
| Provincial, state and municipal taxes |
110 | 21 | 43 | 2 | 1 | - | 177 | |||||||||||||||||||||
| Depreciation and amortization |
244 | 127 | 53 | 32 | 4 | - | 460 | |||||||||||||||||||||
| Income from equity investments |
- | 44 | 9 | 2 | 5 | - | 60 | |||||||||||||||||||||
| Other income (expense), net |
28 | 11 | 7 | (1) | (10) | 9 | 44 | |||||||||||||||||||||
| Interest expense, net |
78 | 65 | 36 | 9 | 131 | - | 319 | |||||||||||||||||||||
| Income tax expense (recovery) |
66 | 3 | 38 | - | (78) | - | 29 | |||||||||||||||||||||
| Preferred stock dividends |
- | - | - | - | 31 | - | 31 | |||||||||||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 273 | $ | 130 | $ | 116 | $ | 4 | $ | (228) | $ | - | $ | 295 | ||||||||||||||
| As at December 31, 2022 |
|
|||||||||||||||||||||||||||
| Total assets |
$ | 21,053 | $ | 8,223 | $ | 7,737 | $ | 1,337 | $ | 2,835 | $ | (1,443) | $ | 39,742 | ||||||||||||||
(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 $3 million for the three months ended June 30, 2022, and $6 million for the six months ended June 30, 2022 between the Gas Utilities and Infrastructure and Other segments.
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 June 30, 2023 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 577 | $ | 199 | $ | 42 | $ | 115 | $ | - | $ | - | $ | 933 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Commercial |
270 | 107 | 68 | 80 | - | - | 525 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Industrial |
66 | 14 | 8 | 20 | - | (3) | 105 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other electric and regulatory deferrals |
(9) | 10 | 6 | - | - | - | 7 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other (1) |
5 | 10 | 2 | 50 | - | (2) | 65 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 15 | - | - | 15 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
909 | 340 | 126 | 280 | - | (5) | 1,650 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | (34) | - | (34) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 6 | 9 | (9) | 6 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | (249) | 45 | (204) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 6 | (274) | 36 | (232) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 909 | $ | 340 | $ | 126 | $ | 286 | $ | (274) | $ | 31 | $ | 1,418 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| For the six months ended June 30, 2023 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 1,016 | $ | 492 | $ | 82 | $ | 429 | $ | - | $ | - | $ | 2,019 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Commercial |
500 | 234 | 130 | 235 | - | - | 1,099 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Industrial |
129 | 78 | 16 | 45 | - | (7) | 261 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other electric and regulatory deferrals |
- | 21 | 9 | - | - | - | 30 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other (1) |
10 | 19 | 3 | 110 | - | (4) | 138 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 31 | - | - | 31 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
1,655 | 844 | 240 | 850 | - | (11) | 3,578 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 61 | - | 61 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 11 | 15 | (12) | 14 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | 186 | 12 | 198 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 11 | 262 | - | 273 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 1,655 | $ | 844 | $ | 240 | $ | 861 | $ | 262 | $ | (11) | $ | 3,851 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
(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.
| 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 June 30, 2022 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 444 | $ | 182 | $ | 45 | $ | 139 | $ | - | $ | - | $ | 810 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Commercial |
218 | 97 | 74 | 95 | - | - | 484 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Industrial |
58 | 80 | 8 | 19 | - | - | 165 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other electric and regulatory deferrals |
120 | 7 | 2 | - | - | - | 129 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other (1) |
6 | 9 | 2 | 71 | - | (3) | 85 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 15 | - | - | 15 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
846 | 375 | 131 | 339 | - | (3) | 1,688 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | (2) | - | (2) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 4 | 3 | (1) | 6 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | (307) | (5) | (312) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 4 | (306) | (6) | (308) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 846 | $ | 375 | $ | 131 | $ | 343 | $ | (306) | $ | (9) | $ | 1,380 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| For the six months ended June 30, 2022 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 786 | $ | 467 | $ | 88 | $ | 416 | $ | - | $ | - | $ | 1,757 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Commercial |
391 | 219 | 136 | 232 | - | (1) | 977 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Industrial |
105 | 168 | 15 | 37 | - | - | 325 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other electric and regulatory deferrals |
200 | 14 | 7 | - | - | - | 221 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other (1) |
10 | 16 | 4 | 129 | - | (5) | 154 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 29 | - | - | 29 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
1,492 | 884 | 250 | 843 | - | (6) | 3,463 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 47 | - | 47 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 8 | 10 | (6) | 12 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | (117) | (10) | (127) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 8 | (60) | (16) | (68) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 1,492 | $ | 884 | $ | 250 | $ | 851 | $ | (60) | $ | (22) | $ | 3,395 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
(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 June 30, 2023, the aggregate amount of the transaction price allocated to remaining performance obligations was $466 million (2022 – $432 million). This amount includes $136 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 2043.
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 7 in Emera’s 2022 annual audited consolidated financial statements.
| As at millions of dollars |
June 30 2023 |
December 31 2022 |
||||||||||
|
|
||||||||||||
| Regulatory assets |
||||||||||||
| Deferred income tax regulatory assets |
$ | 1,210 | $ | 1,166 | ||||||||
|
|
||||||||||||
| TEC capital cost recovery for early retired assets |
653 | 674 | ||||||||||
|
|
||||||||||||
| Cost recovery clauses |
469 | 707 | ||||||||||
|
|
||||||||||||
| Pension and post-retirement medical plan |
355 | 369 | ||||||||||
|
|
||||||||||||
| FAM |
299 | 307 | ||||||||||
|
|
||||||||||||
| Storm reserve |
59 | 103 | ||||||||||
|
|
||||||||||||
| Deferrals related to derivative instruments |
55 | 30 | ||||||||||
|
|
||||||||||||
| NMGC winter event gas cost recovery |
32 | 69 | ||||||||||
|
|
||||||||||||
| Storm restoration |
29 | 35 | ||||||||||
|
|
||||||||||||
| Environmental remediations |
27 | 27 | ||||||||||
|
|
||||||||||||
| Stranded cost recovery |
27 | 27 | ||||||||||
|
|
||||||||||||
| Other |
100 | 106 | ||||||||||
|
|
||||||||||||
| $ | 3,315 | $ | 3,620 | |||||||||
|
|
||||||||||||
| Current |
$ | 514 | $ | 602 | ||||||||
|
|
||||||||||||
| Long-term |
2,801 | 3,018 | ||||||||||
|
|
||||||||||||
| Total regulatory assets |
$ | 3,315 | $ | 3,620 | ||||||||
|
|
||||||||||||
| Regulatory liabilities |
||||||||||||
| Accumulated reserve - cost of removal |
$ | 881 | $ | 895 | ||||||||
|
|
||||||||||||
| Deferred income tax regulatory liabilities |
846 | 877 | ||||||||||
|
|
||||||||||||
| Deferrals related to derivative instruments |
80 | 230 | ||||||||||
|
|
||||||||||||
| Cost recovery clauses |
61 | 70 | ||||||||||
|
|
||||||||||||
| Self-insurance fund (“SIF”) (note 23) |
29 | 30 | ||||||||||
|
|
||||||||||||
| NMGC gas hedge settlements |
- | 162 | ||||||||||
|
|
||||||||||||
| Other |
10 | 9 | ||||||||||
|
|
||||||||||||
| $ | 1,907 | $ | 2,273 | |||||||||
|
|
||||||||||||
| Current |
$ | 245 | $ | 495 | ||||||||
|
|
||||||||||||
| Long-term |
1,662 | 1,778 | ||||||||||
|
|
||||||||||||
| Total regulatory liabilities |
$ | 1,907 | $ | 2,273 | ||||||||
|
|
||||||||||||
Florida Electric Utility
Fuel Recovery:
On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The changes were approved by the Florida Public Service Commission (“FPSC”) on March 7, 2023, and were effective beginning on April 1, 2023.
Storm Reserve:
On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the previous approved storm reserve level of $56 million USD, for a total of approximately $131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge on April 2023 bills. The storm recovery is subject to review of the underlying costs for prudency by the FPSC. The review is expected to be completed by the end of 2023.
Canadian Electric Utilities
NSPI
Extra Large Industrial Active Demand Tariff:
On July 5, 2023, NSPI received approval from the Nova Scotia Utility and Review Board (“UARB”) to change the methodology in which fuel cost recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, effective January 1, 2022, results in a shifting of fuel costs from this industrial customer to the FAM. This adjustment has been recorded in Q2 2023 resulting in a $51 million increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables and other current assets. This adjustment had minimal impact on earnings.
General Rate Application:
On March 27, 2023, the UARB issued its final order approving the new electricity rates related to the General Rate Application settlement agreement between NSPI, key customer representatives and participating interest groups. The new electricity rates were effective on February 2, 2023.
Nova Scotia Cap-and-Trade Program:
As of December 31, 2022, the FAM included a cumulative $166 million in fuel costs related to the accrued purchase of emissions credits and $6 million related to credits purchased from provincial auctions. On March 16, 2023, the Province of Nova Scotia amended the Nova Scotia Cap-and-Trade Program Regulations, providing NSPI with additional emissions allowances sufficient to achieve compliance for the 2019 through 2022 period. Accrued compliance costs of $166 million related to the anticipated purchase of emissions credits were reversed in Q1 2023. Credits NSPI purchased from provincial auctions in the amount of $6 million will not be refunded and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-Trade Program.
NSPML
In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023, subject to a holdback of up to $2 million a month. As of June 30, 2023, $18 million ($14 million related to 2022 and $4 million related to Q1 2023) in aggregate has been held back by NSPI, which represents the total holdback for the nine months in which NSPML did not achieve the 90 per cent required delivery of the NS Block. NSPML did not incur any additional holdback in each month of Q2 2023 as a result of achieving the full 90 per cent NS Block deliveries. Determination of allocation of the $18 million between NSPML or to NSPI’s FAM for the benefit of customers is subject to a regulatory process before the UARB, which commenced in March 2023. A decision from the UARB on the holdback is expected later in 2023.
Gas Utilities and Infrastructure
PGS
On April 4, 2023, PGS filed a rate case with the FPSC for new rates to become effective January 2024. PGS requested a $139 million USD increase in annual base rates, including $11 million USD from the cast iron and bare steel replacement rider. This reflects an 11 per cent midpoint ROE. The hearing for the matter is expected to be held in Q3 2023 with a final decision expected by the FPSC in Q4 2023.
Other Electric Utilities
BLPC
Clean Energy Transition Program (“CETP”):
On May 31, 2023, the Fair Trading Commission, Barbados (“FTC”) approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. BLPC has given notice to the FTC of its intention to submit applications in 2023 for costs to be recovered through the CETP.
General Rate Review Application:
On October 4, 2021, BLPC submitted a general rate review application to the FTC. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities related to the SIF of $50 million USD and prior year benefits recognized on remeasurement of deferred income taxes of $5 million USD, and a regulatory asset related to accumulated depreciation of $11 million USD. The FTC also requested a compliance filing before setting final rates which was submitted by BLPC on March 8, 2023. On March 7, 2023, BLPC filed a Motion for Review and Variation of FTC’s decision and applied for a Stay of the Decision. The FTC has determined that it will hear the Motion for Review by way of an oral hearing and parties were invited to submit and exchange written submissions on these matters during Q2 2023. On May 12, 2023, the FTC granted the Stay of the Decision until the determination of the Motion for Review and Variation which is scheduled to be heard in Q3 2023. BLPC expects a decision on final rates from the FTC in 2023.
7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
| Carrying Value as at | Equity Income for the three months ended |
Equity Income for the six months ended |
Percentage of |
|||||||||||||||||||||||||
| June 30 | December 31 | June 30 | June 30 | Ownership | ||||||||||||||||||||||||
| millions of dollars |
2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| LIL (1) |
$ | 754 | $ | 740 | $ | 15 | $ | 14 | $ | 31 | $ | 28 | 31.0 | |||||||||||||||
|
|
||||||||||||||||||||||||||||
| NSPML |
493 | 501 | 13 | 10 | 21 | 16 | 100.0 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| M&NP (2) |
123 | 128 | 6 | 4 | 11 | 9 | 12.9 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Lucelec (2) |
47 | 49 | - | 1 | 1 | 2 | 19.5 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Bear Swamp (3) |
- | - | 2 | 4 | 7 | 5 | 50.0 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| $ | 1,417 | $ | 1,418 | $ | 36 | $ | 33 | $ | 71 | $ | 60 | |||||||||||||||||
|
|
||||||||||||||||||||||||||||
(1) Emera indirectly owns 100 per cent of the LIL Class B units, which comprises 24.5 per cent of the total units issued. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments.
(2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method.
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $86 million (2022 – $95 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 23). NSPML’s consolidated summarized balance sheet is as follows:
| As at | June 30 | December 31 | ||||||
| millions of dollars | 2023 | 2022 | ||||||
|
|
||||||||
| Current assets |
$ | 16 | $ | 17 | ||||
|
|
||||||||
| PP&E |
1,499 | 1,517 | ||||||
|
|
||||||||
| Regulatory assets |
264 | 265 | ||||||
|
|
||||||||
| Non-current assets |
29 | 29 | ||||||
|
|
||||||||
| Total assets |
$ | 1,808 | $ | 1,828 | ||||
|
|
||||||||
| Current liabilities |
$ | 47 | $ | 48 | ||||
|
|
||||||||
| Long-term debt (1) |
1,129 | 1,149 | ||||||
|
|
||||||||
| Non-current liabilities |
139 | 130 | ||||||
|
|
||||||||
| Equity |
493 | 501 | ||||||
|
|
||||||||
| Total liabilities and equity |
$ | 1,808 | $ | 1,828 | ||||
|
|
||||||||
(1) The project debt has been guaranteed by the Government of Canada.
8. INTEREST EXPENSE, NET
Interest expense, net consisted of the following:
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Interest on debt |
$ | 232 | $ | 165 | $ | 462 | $ | 325 | ||||||||
|
|
||||||||||||||||
| Allowance for borrowed funds used during construction |
(4) | (4) | (7) | (9) | ||||||||||||
|
|
||||||||||||||||
| Other |
(5) | 2 | (6) | 3 | ||||||||||||
|
|
||||||||||||||||
| $ | 223 | $ | 163 | $ | 449 | $ | 319 | |||||||||
|
|
||||||||||||||||
9. 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 | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Income (loss) before provision for income taxes |
$ | (7) | $ | (118) | $ | 731 | $ | 355 | ||||||||
|
|
||||||||||||||||
| Statutory income tax rate |
29.0% | 29.0% | 29.0% | 29.0% | ||||||||||||
|
|
||||||||||||||||
| Income taxes, at statutory income tax rate |
(2) | (34) | 212 | 103 | ||||||||||||
|
|
||||||||||||||||
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities |
(13) | (10) | (45) | (35) | ||||||||||||
|
|
||||||||||||||||
| Foreign tax rate variance |
(11) | (9) | (19) | (16) | ||||||||||||
|
|
||||||||||||||||
| Tax credits |
(10) | (1) | (17) | (4) | ||||||||||||
|
|
||||||||||||||||
| Amortization of deferred income tax regulatory liabilities |
(11) | (8) | (16) | (13) | ||||||||||||
|
|
||||||||||||||||
| Tax effect of equity earnings |
(4) | (3) | (7) | (5) | ||||||||||||
|
|
||||||||||||||||
| Other |
- | (1) | 3 | (1) | ||||||||||||
|
|
||||||||||||||||
| Income tax (recovery) expense |
$ | (51) | $ | (66) | $ | 111 | $ | 29 | ||||||||
|
|
||||||||||||||||
| Effective income tax rate |
729% | 56% | 15% | 8% | ||||||||||||
|
|
||||||||||||||||
On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024 and introduces new technology-neutral clean energy related tax credits beginning in 2025. As of June 30, 2023, the Company has recorded a $20 million regulatory liability in recognition of its obligation to pass the incremental tax benefits realized to customers.
10. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
| Issued and outstanding: | millions of shares | millions of dollars | ||||||||||
|
|
||||||||||||
| Balance, December 31, 2022 |
269.95 | $ | 7,762 | |||||||||
|
|
||||||||||||
| Issued under the DRIP, net of discounts |
2.53 | 139 | ||||||||||
|
|
||||||||||||
| Senior management stock options exercised and ECSPP |
0.43 | 21 | ||||||||||
|
|
||||||||||||
| Balance, June 30, 2023 |
272.91 | $ | 7,922 | |||||||||
|
|
||||||||||||
As at June 30, 2023, an aggregate gross sales limit of $207 million remained available for issuance under the ATM program.
11. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars (except per share amounts) | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Numerator |
||||||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 27.5 | $ | (67.2) | $ | 587.9 | $ | 294.5 | ||||||||
|
|
||||||||||||||||
| Diluted numerator |
27.5 | (67.2) | 587.9 | 294.5 | ||||||||||||
|
|
||||||||||||||||
| Denominator |
||||||||||||||||
| Weighted average shares of common stock outstanding – basic |
272.3 | 264.4 | 271.5 | 263.1 | ||||||||||||
|
|
||||||||||||||||
| Stock-based compensation (1) |
0.3 | - | 0.3 | 0.5 | ||||||||||||
|
|
||||||||||||||||
| Weighted average shares of common stock outstanding – diluted |
272.6 | 264.4 | 271.8 | 263.6 | ||||||||||||
|
|
||||||||||||||||
| Earnings (loss) per common share |
||||||||||||||||
| Basic |
$ | 0.10 | $ | (0.25) | $ | 2.17 | $ | 1.12 | ||||||||
|
|
||||||||||||||||
| Diluted |
$ | 0.10 | $ | (0.25) | $ | 2.16 | $ | 1.12 | ||||||||
|
|
||||||||||||||||
(1) The potential common shares from 0.5 million related to stock-based compensation were excluded from diluted EPS for the three months ended June 30, 2022, as the Company had net loss in this quarter.
12. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of AOCI, net of tax, are as follows:
| millions of dollars | Unrealized (loss) gain on translation of self-sustaining foreign operations |
Net change in net investment hedges |
Gains (losses) on derivatives recognized as cash flow |
Net change in available- for-sale investments |
Net change in unrecognized pension and post- retirement |
Total AOCI | ||||||||||||||||||
| For the six months ended June 30, 2023 |
| |||||||||||||||||||||||
|
|
||||||||||||||||||||||||
| Balance, January 1, 2023 | $ | 639 | $ | (62) | $ | 16 | $ | (2) | $ | (13) | $ | 578 | ||||||||||||
|
|
||||||||||||||||||||||||
| Other comprehensive (loss) income before reclassifications | (247) | 36 | 1 | - | - | (210) | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Amounts reclassified from AOCI | - | - | (1) | - | (5) | (6) | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Net current period other comprehensive (loss) income | (247) | 36 | - | - | (5) | (216) | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Balance, June 30, 2023 | $ | 392 | $ | (26) | $ | 16 | $ | (2) | $ | (18) | $ | 362 | ||||||||||||
|
|
||||||||||||||||||||||||
| For the six months ended June 30, 2022 |
| |||||||||||||||||||||||
|
|
||||||||||||||||||||||||
| Balance, January 1, 2022 | $ | 10 | $ | 35 | $ | 18 | $ | (1) | $ | (37) | $ | 25 | ||||||||||||
|
|
||||||||||||||||||||||||
| Other comprehensive income (loss) before reclassifications | 147 | (21) | - | - | - | 126 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Amounts reclassified from AOCI | - | - | (1) | - | (8) | (9) | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Net current period other comprehensive income (loss) | 147 | (21) | (1) | - | (8) | 117 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Balance, June 30, 2022 | $ | 157 | $ | 14 | $ | 17 | $ | (1) | $ | (45) | $ | 142 | ||||||||||||
|
|
||||||||||||||||||||||||
The reclassifications out of AOCI are as follows:
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Affected line item in the Condensed |
|
Amounts reclassified from AOCI |
| |||||||||||||
|
Consolidated Interim Financial Statements |
||||||||||||||||
|
|
||||||||||||||||
| Gain on derivatives recognized as cash flow hedges |
||||||||||||||||
| Interest rate hedge |
Interest expense, net | $ | - | $ | - | $ (1) | $ | (1) | ||||||||
|
|
||||||||||||||||
| Net change in unrecognized pension and post-retirement benefit costs |
||||||||||||||||
| Actuarial losses |
Other income, net | $ | - | $ | 2 | $ - | $ | 4 | ||||||||
|
|
||||||||||||||||
| Amounts reclassified
into obligations |
Pension and post-retirement
benefits |
(1) | - | (5) | (12) | |||||||||||
|
|
||||||||||||||||
| Total |
(1) | 2 | (5) | (8) | ||||||||||||
|
|
||||||||||||||||
| Total reclassifications out of AOCI, for the period |
$ | (1) | $ | 2 | $ (6) | $ | (9) | |||||||||
|
|
||||||||||||||||
13. 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 fair value 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 fair value 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 fair value with any changes in fair value 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 fair value on the balance sheet as derivative assets or liabilities. The change in fair value 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. TEC and PGS have no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2024. |
| 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 fair value, 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. |
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
|
|
||||||||||||||||
| As at millions of dollars |
June 30 2023 |
December 31 2022 |
June 30 2023 |
December 31 2022 |
||||||||||||
|
|
||||||||||||||||
| Cash flow hedges: |
||||||||||||||||
| FX forwards |
$ | 1 | $ | - | $ | - | $ | - | ||||||||
|
|
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
81 | 186 | 51 | 42 | ||||||||||||
|
|
||||||||||||||||
| FX forwards |
5 | 18 | 4 | 1 | ||||||||||||
|
|
||||||||||||||||
| Physical natural gas purchases |
7 | 52 | - | - | ||||||||||||
|
|
||||||||||||||||
| 93 | 256 | 55 | 43 | |||||||||||||
|
|
||||||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
46 | 89 | 42 | 77 | ||||||||||||
|
|
||||||||||||||||
| Natural gas swaps, futures, forwards, physical |
254 | 340 | 545 | 1,224 | ||||||||||||
| contracts |
||||||||||||||||
|
|
||||||||||||||||
| 300 | 429 | 587 | 1,301 | |||||||||||||
|
|
||||||||||||||||
| Other derivatives: |
||||||||||||||||
| Equity derivatives |
3 | - | - | 5 | ||||||||||||
|
|
||||||||||||||||
| FX forwards |
17 | 5 | 11 | 23 | ||||||||||||
|
|
||||||||||||||||
| 20 | 5 | 11 | 28 | |||||||||||||
|
|
||||||||||||||||
| Total gross current derivatives |
414 | 690 | 653 | 1,372 | ||||||||||||
|
|
||||||||||||||||
| Impact of master netting agreements: |
||||||||||||||||
| Regulatory deferral |
(12) | (18) | (12) | (18) | ||||||||||||
|
|
||||||||||||||||
| HFT derivatives |
(137) | (276) | (137) | (276) | ||||||||||||
|
|
||||||||||||||||
| Total impact of master netting agreements |
(149) | (294) | (149) | (294) | ||||||||||||
|
|
||||||||||||||||
| Total derivatives |
$ | 265 | $ | 396 | $ | 504 | $ | 1,078 | ||||||||
|
|
||||||||||||||||
| Current (1) |
199 | 296 | 399 | 888 | ||||||||||||
|
|
||||||||||||||||
| Long-term (1) |
66 | 100 | 105 | 190 | ||||||||||||
|
|
||||||||||||||||
| Total derivatives |
$ | 265 | $ | 396 | $ | 504 | $ | 1,078 | ||||||||
|
|
||||||||||||||||
| (1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
Cash Flow Hedges
On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. The Company has FX forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.
The amounts related to cash flow hedges recorded in AOCI consisted of the following:
|
| |||||||||||||||
| As at | June 30, 2023 | December 31, 2022 | ||||||||||||||
|
|
||||||||||||||||
| Interest rate | FX | Interest rate | FX | |||||||||||||
| millions of dollars | hedge | forwards | hedge | forwards | ||||||||||||
|
|
||||||||||||||||
| Total unrealized gain in AOCI, net of tax |
$ | 15 | $ | 1 | $ | 16 | $ | - | ||||||||
|
|
||||||||||||||||
For the three and six months ended June 30, 2023, unrealized gains of nil (2022 – nil) and $1 million (2022 – $1 million) respectively have been reclassified from AOCI into interest expense. The Company expects $3 million of unrealized gains currently in AOCI to be reclassified into net income within the next 12 months.
As at June 30, 2023, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:
| millions | 2023 | |||
|
|
||||
| FX forwards (USD) sales |
$ | 27 | ||
|
|
||||
Regulatory Deferral
The Company has recorded the following changes with respect to derivatives receiving regulatory deferral:
| millions of dollars | Physical natural gas purchases |
Commodity swaps and forwards |
FX forwards |
Physical natural gas purchases |
Commodity swaps and forwards |
FX forwards |
||||||||||||||||||
|
|
||||||||||||||||||||||||
| For the three months ended June 30 |
2023 | 2022 | ||||||||||||||||||||||
|
|
||||||||||||||||||||||||
| Unrealized gain (loss) in regulatory assets |
$ | - | $ | (9) | $ | (3) | $ | - | $ | (30) | $ | 3 | ||||||||||||
|
|
||||||||||||||||||||||||
| Unrealized gain (loss) in regulatory liabilities | 1 | 8 | (4) | 18 | 108 | 6 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Realized (gain) loss in regulatory assets | - | (4) | - | - | 14 | - | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Realized (gain) loss in regulatory liabilities | - | 3 | - | - | (13) | - | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Realized (gain) loss in inventory (1) | - | 4 | (4) | - | (32) | 2 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) | (3) | 7 | (2) | (5) | (22) | - | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Total change in derivative instruments | $ | (2) | $ | 9 | $ | (13) | $ | 13 | $ | 25 | $ | 11 | ||||||||||||
|
|
||||||||||||||||||||||||
| millions of dollars | Physical natural gas purchases |
Commodity swaps and forwards |
FX forwards |
Physical natural gas purchases |
Commodity swaps and forwards |
FX forwards |
||||||||||||||||||
|
|
||||||||||||||||||||||||
| For the six months ended June 30 | 2023 | 2022 | ||||||||||||||||||||||
|
|
||||||||||||||||||||||||
| Unrealized gain (loss) in regulatory assets | $ | - | $ | (29) | $ | (3) | $ | - | $ | (38) | $ | 1 | ||||||||||||
|
|
||||||||||||||||||||||||
| Unrealized gain (loss) in regulatory liabilities | (3) | (59) | (2) | 39 | 329 | 2 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Realized loss in regulatory assets | - | - | - | - | 16 | - | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Realized (gain) loss in regulatory liabilities | - | 4 | - | - | (22) | - | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Realized (gain) loss in inventory (1) | - | 5 | (9) | - | (42) | 4 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) | (42) | (20) | (2) | (34) | (58) | 1 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Other |
- | (15) | - | - | - | - | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| Total change in derivative instruments |
$ | (45) | $ | (114) | $ | (16) | $ | 5 | $ | 185 | $ | 8 | ||||||||||||
|
|
||||||||||||||||||||||||
(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 June 30, 2023, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:
| millions | 2023 | 2024-2026 | ||||||
|
|
||||||||
| Physical natural gas purchases: |
||||||||
| Natural gas (MMBtu) |
2 | - | ||||||
|
|
||||||||
| Commodity swaps and forwards purchases: |
||||||||
| Natural gas (MMBtu) |
12 | 15 | ||||||
|
|
||||||||
| Power (MWh) |
1 | 1 | ||||||
|
|
||||||||
| FX swaps and forwards: |
||||||||
| FX contracts (millions of USD) |
$ | 147 | $ | 248 | ||||
|
|
||||||||
| Weighted average rate |
1.3247 | 1.3118 | ||||||
|
|
||||||||
| % of USD requirements |
123% | 35% | ||||||
|
|
||||||||
HFT Derivatives
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Power swaps and physical contracts in non-regulated operating revenues |
$ | - | $ | 8 | $ | - | $ | 4 | ||||||||
|
|
||||||||||||||||
| Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues |
(22) | (266) | 817 | (72) | ||||||||||||
|
|
||||||||||||||||
| Total gains (losses) in net income |
$ | (22) | $ | (258) | $ | 817 | $ | (68) | ||||||||
|
|
||||||||||||||||
As at June 30, 2023, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
| millions | 2023 | 2024 | 2025 | 2026 | 2027 and thereafter |
|||||||||||||||
|
|
||||||||||||||||||||
| Natural gas purchases (MMBtu) |
234 | 141 | 52 | 39 | 137 | |||||||||||||||
|
|
||||||||||||||||||||
| Natural gas sales (MMBtu) |
337 | 276 | 123 | 11 | 23 | |||||||||||||||
|
|
||||||||||||||||||||
| Power purchases (MWh) |
1 | - | - | - | - | |||||||||||||||
|
|
||||||||||||||||||||
| Power sales (MWh) |
1 | - | - | - | - | |||||||||||||||
|
|
||||||||||||||||||||
Other Derivatives
As at June 30, 2023, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.8 million shares and extends until December 2023. The FX forwards have a combined notional amount of $574 million USD and expire in 2023 through 2025.
The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives:
| FX | Equity | FX | Equity | |||||||||||||
| millions of dollars | forwards | derivatives | forwards | derivatives | ||||||||||||
|
|
||||||||||||||||
| For the three months ended June 30 |
2023 | 2022 | ||||||||||||||
|
|
||||||||||||||||
| Unrealized loss in OM&G |
$ | - | $ | (3) | $ | - | $ | (5) | ||||||||
|
|
||||||||||||||||
| Unrealized gain in other income, net |
17 | - | - | - | ||||||||||||
|
|
||||||||||||||||
| Realized loss in other income, net |
(2) | - | - | - | ||||||||||||
|
|
||||||||||||||||
| Total gains (losses) in net income |
$ | 15 | $ | (3) | $ | - | $ | (5) | ||||||||
|
|
||||||||||||||||
| FX | Equity | FX | Equity | |||||||||||||
| millions of dollars | forwards | derivatives | forwards | derivatives | ||||||||||||
|
|
||||||||||||||||
| For the six months ended June 30 |
2023 | 2022 | ||||||||||||||
|
|
||||||||||||||||
| Unrealized gain (loss) in OM&G |
$ | - | $ | 8 | $ | - | $ | (9) | ||||||||
|
|
||||||||||||||||
| Unrealized gain in other income, net |
23 | - | 1 | - | ||||||||||||
|
|
||||||||||||||||
| Realized loss in other income, net |
(5) | - | - | |||||||||||||
|
|
||||||||||||||||
| Total gains (losses) in net income |
$ | 18 | $ | 8 | $ | 1 | $ | (9) | ||||||||
|
|
||||||||||||||||
Credit Risk
The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts.
The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company internally assesses credit risk for counterparties that are not rated.
It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North American Energy Standards Board agreements and/or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.
As at June 30, 2023, the Company had $144 million (December 31, 2022 – $131 million) in financial assets considered to be past due, which had been outstanding for an average 60 days. The fair value of these financial assets was $126 million (December 31, 2022 – $114 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.
Cash Collateral
The Company’s cash collateral positions consisted of the following:
| As at | June 30 | December 31 | ||||||
| millions of dollars | 2023 | 2022 | ||||||
|
|
||||||||
| Cash collateral provided to others |
$ | 104 | $ | 224 | ||||
|
|
||||||||
| Cash collateral received from others |
$ | 11 | $ | 112 | ||||
|
|
||||||||
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.
As at June 30, 2023, the total fair value of derivatives in a liability position was $504 million (December 31, 2022 – $1,078 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.
14. FAIR VALUE MEASUREMENTS
The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 13), and uses a market approach to do so. The three levels of the fair value 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 fair value measurement.
The following tables set out the classification of the methodology used by the Company to fair value its derivatives:
| As at | June 30, 2023 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
|
|
||||||||||||||||
| Assets |
||||||||||||||||
| Cash flow hedges: |
||||||||||||||||
| FX forwards |
$ | - | $ | 1 | $ | - | $ | 1 | ||||||||
|
|
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
37 | 32 | - | 69 | ||||||||||||
|
|
||||||||||||||||
| FX forwards |
- | 5 | - | 5 | ||||||||||||
|
|
||||||||||||||||
| Physical natural gas purchases |
- | - | 7 | 7 | ||||||||||||
|
|
||||||||||||||||
| 37 | 37 | 7 | 81 | |||||||||||||
|
|
||||||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
6 | 26 | - | 32 | ||||||||||||
|
|
||||||||||||||||
| Natural gas swaps, futures, forwards, physical
contracts and related transportation |
22 | 84 | 25 | 131 | ||||||||||||
|
|
||||||||||||||||
| 28 | 110 | 25 | 163 | |||||||||||||
|
|
||||||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 17 | - | 17 | ||||||||||||
|
|
||||||||||||||||
| Equity derivatives |
3 | - | - | 3 | ||||||||||||
|
|
||||||||||||||||
| 3 | 17 | - | 20 | |||||||||||||
|
|
||||||||||||||||
| Total assets |
68 | 165 | 32 | 265 | ||||||||||||
|
|
||||||||||||||||
| Liabilities |
||||||||||||||||
|
|
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
28 | 11 | - | 39 | ||||||||||||
|
|
||||||||||||||||
| FX forwards |
- | 4 | - | 4 | ||||||||||||
|
|
||||||||||||||||
| 28 | 15 | - | 43 | |||||||||||||
|
|
||||||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
1 | 25 | 1 | 27 | ||||||||||||
|
|
||||||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
27 | 40 | 356 | 423 | ||||||||||||
|
|
||||||||||||||||
| 28 | 65 | 357 | 450 | |||||||||||||
|
|
||||||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 11 | - | 11 | ||||||||||||
|
|
||||||||||||||||
| Total liabilities |
56 | 91 | 357 | 504 | ||||||||||||
|
|
||||||||||||||||
| Net assets (liabilities) |
$ | 12 | $ | 74 | $ | (325) | $ | (239) | ||||||||
|
|
||||||||||||||||
| As at | December 31, 2022 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
|
|
||||||||||||||||
| Assets |
||||||||||||||||
|
|
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 120 | $ | 48 | $ | - | $ | 168 | ||||||||
|
|
||||||||||||||||
| FX forwards |
- | 18 | - | 18 | ||||||||||||
|
|
||||||||||||||||
| Physical natural gas purchases and sales |
- | - | 52 | 52 | ||||||||||||
|
|
||||||||||||||||
| 120 | 66 | 52 | 238 | |||||||||||||
|
|
||||||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
9 | 31 | 4 | 44 | ||||||||||||
|
|
||||||||||||||||
| Natural gas swaps, futures, forwards, physical
contracts and related transportation |
3 | 72 | 34 | 109 | ||||||||||||
|
|
||||||||||||||||
| 12 | 103 | 38 | 153 | |||||||||||||
|
|
||||||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 5 | - | 5 | ||||||||||||
|
|
||||||||||||||||
| Total assets |
132 | 174 | 90 | 396 | ||||||||||||
|
|
||||||||||||||||
| Liabilities |
||||||||||||||||
|
|
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
15 | 9 | - | 24 | ||||||||||||
|
|
||||||||||||||||
| FX forwards |
- | 1 | - | 1 | ||||||||||||
|
|
||||||||||||||||
| 15 | 10 | - | 25 | |||||||||||||
|
|
||||||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
2 | 28 | 1 | 31 | ||||||||||||
|
|
||||||||||||||||
| Natural gas swaps, futures, forwards and
physical contracts |
51 | 118 | 825 | 994 | ||||||||||||
|
|
||||||||||||||||
| 53 | 146 | 826 | 1,025 | |||||||||||||
|
|
||||||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 23 | - | 23 | ||||||||||||
| Equity derivatives |
5 | - | - | 5 | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
| 5 | 23 | - | 28 | |||||||||||||
|
|
||||||||||||||||
| Total liabilities |
73 | 179 | 826 | 1,078 | ||||||||||||
|
|
||||||||||||||||
| Net assets (liabilities) |
$ | 59 | $ | (5) | $ | (736) | $ | (682) | ||||||||
|
|
||||||||||||||||
The change in the fair value of the Level 3 financial assets for the three months ended June 30, 2023 was as follows:
| Regulatory Deferral
|
HFT Derivatives
|
|||||||||||||||
| millions of dollars | Physical natural gas purchases |
Power | Natural gas | Total | ||||||||||||
|
|
||||||||||||||||
| Balance, beginning of period |
$ 9 | $ | (1) | $ | 39 | $ | 47 | |||||||||
|
|
||||||||||||||||
| Realized gains included in fuel for generation and purchased power |
(3) | - | - | (3) | ||||||||||||
|
|
||||||||||||||||
| Unrealized gains included in regulatory liabilities |
1 | - | - | 1 | ||||||||||||
|
|
||||||||||||||||
| Total realized and unrealized gains (losses) included in non-regulated operating revenues | - | 1 | (14) | (13) | ||||||||||||
|
|
||||||||||||||||
| Balance, June 30, 2023 |
$ 7 | $ | - | $ | 25 | $ | 32 | |||||||||
|
|
||||||||||||||||
The change in the fair value of the Level 3 financial liabilities for the three months ended June 30, 2023 was as follows:
| HFT Derivatives | ||||||||||||
| millions of dollars | Power | Natural gas | Total | |||||||||
|
|
||||||||||||
| Balance, beginning of period |
$ | 2 | $ | 326 | $ | 328 | ||||||
|
|
||||||||||||
| Total realized and unrealized (gains) losses included in non-regulated operating revenues |
(1) | 30 | 29 | |||||||||
|
|
||||||||||||
| Balance, June 30, 2023 |
$ | 1 | $ | 356 | $ | 357 | ||||||
|
|
||||||||||||
The change in the fair value of the Level 3 financial assets for the six months ended June 30, 2023 was as follows:
| Regulatory Deferral
|
HFT Derivatives
|
|||||||||||||||
| millions of dollars | Physical natural gas purchases |
Power | Natural gas | Total | ||||||||||||
|
|
||||||||||||||||
| Balance, beginning of period |
$ 52 | $ | 4 | $ | 34 | $ | 90 | |||||||||
|
|
||||||||||||||||
| Realized gains included in fuel for generation and purchased power |
(42) | - | - | (42) | ||||||||||||
|
|
||||||||||||||||
| Unrealized gains included in regulatory liabilities |
(3) | - | - | (3) | ||||||||||||
|
|
||||||||||||||||
| Total realized and unrealized losses included in non-regulated operating revenues | - | (4) | (9) | (13) | ||||||||||||
|
|
||||||||||||||||
| Balance, June 30, 2023 |
$ 7 | $ | - | $ | 25 | $ | 32 | |||||||||
|
|
||||||||||||||||
The change in the fair value of the Level 3 financial liabilities for the six months ended June 30, 2023 was as follows:
| HFT Derivatives | ||||||||||||
| millions of dollars | Power | Natural gas | Total | |||||||||
|
|
||||||||||||
| Balance, beginning of period |
$ | 1 | $ | 825 | $ | 826 | ||||||
|
|
||||||||||||
| Total realized and unrealized gains included in non-regulated operating revenues |
- | (469) | (469) | |||||||||
|
|
||||||||||||
| Balance, June 30, 2023 |
$ | 1 | $ | 356 | $ | 357 | ||||||
|
|
||||||||||||
Significant unobservable inputs used in the fair value 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) fair value 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 fair value of Level 3 derivative instruments. The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:
| June 30, 2023 | ||||||||||||||||||||||||
| As at | Weighted | |||||||||||||||||||||||
|
millions of dollars |
Fair Value | Significant Unobservable Input |
Low | High | average(1) | |||||||||||||||||||
|
|
||||||||||||||||||||||||
| Assets | Liabilities | |||||||||||||||||||||||
|
|
||||||||||||||||||||||||
| Regulatory deferral – Physical |
$ | 7 | $ | - | Third-party pricing | $3.99 | $6.96 | $4.91 | ||||||||||||||||
| natural gas purchases |
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
| HFT derivatives – Power |
- | 1 | Third-party pricing | $28.07 | $148.65 | $62.39 | ||||||||||||||||||
| swaps and physical contracts |
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
| HFT derivatives – Natural |
25 | 356 | Third-party pricing | $1.07 | $18.64 | $7.06 | ||||||||||||||||||
| gas swaps, futures, forwards
and physical contracts |
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
| Total |
$ | 32 | $ | 357 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||
| Net liability |
$ | 325 | ||||||||||||||||||||||
|
|
||||||||||||||||||||||||
(1) Unobservable inputs were weighted by the relative fair value of the instruments.
Long-term debt is a financial liability not measured at fair value on the Condensed Consolidated Balance Sheets. The balance consisted of the following:
| As at | Carrying | |||||||||||||||||||||||
| millions of dollars | Amount | Fair Value | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||
|
|
||||||||||||||||||||||||
| June 30, 2023 |
$ | 16,537 | $ | 15,144 | $ | 166 | $ | 14,727 | $ | 251 | $ | 15,144 | ||||||||||||
|
|
||||||||||||||||||||||||
| December 31, 2022 |
$ | 16,318 | $ | 14,670 | $ | - | $ | 14,284 | $ | 386 | $ | 14,670 | ||||||||||||
|
|
||||||||||||||||||||||||
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 $35 million was recorded in AOCI for the three months ended June 30, 2023 (2022 – $40 million after-tax loss) and an after-tax foreign currency gain of $36 million was recorded for the six months ended June 30, 2023 (2022 – $21 million after-tax loss).
15. 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 June 30, 2023 (2022 – $43 million) and $78 million for the six months ended June 30, 2023 (2022 – $77 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 $3 million for the three months ended June 30, 2023 (2022 – $2 million) and $8 million for the six months ended June 30, 2023 (2022 – $6 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at June 30, 2023 and at December 31, 2022.
16. RECEIVABLES AND OTHER CURRENT ASSETS
| As at | June 30 | December 31 | ||||||
| millions of dollars | 2023 | 2022 | ||||||
|
|
||||||||
| Customer accounts receivable – billed |
$ | 734 | $ | 1,096 | ||||
|
|
||||||||
| Capitalized transportation capacity (1) |
395 | 781 | ||||||
|
|
||||||||
| Customer accounts receivable – unbilled |
316 | 424 | ||||||
|
|
||||||||
| Prepaid expenses |
123 | 82 | ||||||
|
|
||||||||
| Income tax receivable |
11 | 9 | ||||||
|
|
||||||||
| Allowance for credit losses |
(18) | (17) | ||||||
|
|
||||||||
| NMGC gas hedge settlement receivable (2) |
- | 162 | ||||||
|
|
||||||||
| Other |
202 | 360 | ||||||
|
|
||||||||
| Total receivables and other current assets |
$ | 1,763 | $ | 2,897 | ||||
|
|
||||||||
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.
(2) Related amount is included in regulatory liabilities for NMGC as gas hedges are part of the purchased gas adjustment clause. Refer to note 7 in Emera’s 2022 annual audited consolidated financial statements.
17. EMPLOYEE BENEFIT PLANS
Emera maintains a number of contributory defined-benefit and defined-contribution 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 | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2023 | 2022 | 2023 | 2022 | ||||||||||||
|
|
||||||||||||||||
| Defined benefit pension plans |
||||||||||||||||
| Service cost |
$ | 7 | $ | 11 | $ | 15 | $ | 21 | ||||||||
|
|
||||||||||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
28 | 20 | 56 | 40 | ||||||||||||
|
|
||||||||||||||||
| Expected return on plan assets |
(41) | (37) | (81) | (72) | ||||||||||||
|
|
||||||||||||||||
| Current year amortization of: |
||||||||||||||||
| Actuarial losses |
- | 2 | - | 4 | ||||||||||||
|
|
||||||||||||||||
| Regulatory asset |
2 | 6 | 3 | 10 | ||||||||||||
|
|
||||||||||||||||
| Total non-service costs |
(11) | (9) | (22) | (18) | ||||||||||||
|
|
||||||||||||||||
| Total defined benefit pension plans |
(4) | 2 | (7) | 3 | ||||||||||||
|
|
||||||||||||||||
| Non-pension benefit plans |
||||||||||||||||
| Service cost |
1 | 1 | 1 | 2 | ||||||||||||
|
|
||||||||||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
4 | 2 | 7 | 4 | ||||||||||||
|
|
||||||||||||||||
| Expected return on plan assets |
(1) | - | (1) | - | ||||||||||||
|
|
||||||||||||||||
| Current year amortization of regulatory asset |
(1) | - | (2) | 1 | ||||||||||||
|
|
||||||||||||||||
| Total non-service costs |
2 | 2 | 4 | 5 | ||||||||||||
|
|
||||||||||||||||
| Total non-pension benefit plans |
3 | 3 | 5 | 7 | ||||||||||||
|
|
||||||||||||||||
| Total defined benefit plans |
$ | (1) | $ | 5 | $ | (2) | $ | 10 | ||||||||
|
|
||||||||||||||||
Emera’s pension and non-pension contributions related to these defined-benefit plans for the three months ended June 30, 2023 were $21 million (2022 – $17 million), and for the six months ended June 30, 2023 were $35 million (2022 – $31 million). Annual employer contributions to the defined benefit pension plans are estimated to be $44 million for 2023. Emera’s contributions related to these defined contribution plans for the three months ended June 30, 2023 were $11 million (2022 – $10 million) and $22 million (2022 – $19 million) for the six months ended June 30, 2023.
18. 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 2022 annual audited consolidated financial statements, and below for 2023 short-term debt financing activity.
Florida Electric Utilities
On March 1, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit facility which matures on February 28, 2024. The credit facility contains customary representations and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term secured overnight financing rate (“SOFR”), the Bank of Nova Scotia’s prime rate, the federal funds rate or the one-month SOFR, plus a margin.
On April 3, 2023, TEC entered into an additional 364-day, $200 million USD senior unsecured revolving credit facility which matures on April 1, 2024. The credit agreement contains customary representation and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term SOFR, Wells Fargo’s prime rate, the federal funds rate or the one-month SOFR, plus a margin.
Other
On June 30, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the maturity date from August 2, 2023 to August 2, 2024. There were no other changes in commercial terms from the prior agreement.
19. LONG-TERM DEBT
For details regarding long-term debt, refer to note 25 in Emera’s 2022 annual audited consolidated financial statements, and below for 2023 long-term debt financing activity.
Canadian Electric Utilities
On March 24, 2023, NSPI issued $500 million in unsecured notes. The issuance included $300 million unsecured notes that bear interest at 4.95 per cent with a maturity date of November 15, 2032, and $200 million unsecured notes that bear interest at 5.36 per cent with a maturity date of March 24, 2053.
Other Electric Utilities
On May 24, 2023, GBPC issued a $28 million USD non-revolving term loan that bears interest at 4.00 per cent with a maturity date of May 24, 2028.
Other
On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent with a maturity date of May 2, 2030.
20. COMMITMENTS AND CONTINGENCIES
| A. | Commitments |
As at June 30, 2023, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Transportation (1) |
$ | 366 | 566 | 440 | 397 | 380 | 2,780 | $ | 4,929 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Purchased power (2) |
149 | 242 | 241 | 256 | 305 | 3,583 | 4,776 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Fuel, gas supply and storage |
462 | 327 | 122 | 47 | 5 | 1 | 964 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Capital projects |
623 | 184 | 5 | 6 | 1 | - | 819 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Equity investment commitments (3) |
- | 240 | - | - | - | - | 240 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
80 | 155 | 139 | 52 | 45 | 211 | 682 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| $ | 1,680 | $ | 1,714 | $ | 947 | $ | 758 | $ | 736 | $ | 6,575 | $ | 12,410 | |||||||||||||||
|
|
||||||||||||||||||||||||||||
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $136 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(2) Annual requirement to purchase electricity production from Independent Power Producers or other utilities over varying contract lengths.
(3) Emera has a commitment to make equity contributions to the LIL. The commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be made in 2024.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2022, the UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.
Construction of the LIL is complete, and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canada’s Independent Engineer issuance of its Commissioning Certificate on April 13, 2023.
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
| 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 June 30, 2023, the aggregate financial liability of the Florida utilities is estimated to be $17 million ($13 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 Condensed Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.
The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities. The estimates to perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, the Florida utilities could be liable for more than their actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.
| C. | Principal Financial Risks and Uncertainties |
For information on principal financial risks which could materially affect the Company in the normal course of business, refer to note 27 in Emera’s 2022 annual audited consolidated financial statements. Risks associated with derivative instruments and fair value measurements are discussed in note 13 and note 14. There have been no material changes to the principal financial risks as of June 30, 2023.
| D. | Guarantees and Letters of Credit |
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2022 audited annual consolidated financial statements, with material updates as noted below:
NSPI renewed guarantees of $15 million USD with terms of varying lengths. As at June 30, 2023, NSPI had $109 million USD (2022 – $119 million USD) of guarantees outstanding with terms of varying lengths, all of which are issued on behalf of its subsidiary, NS Power Energy Marking Incorporated.
21. CUMULATIVE PREFERRED STOCK
For details regarding cumulative preferred stock, refer to note 28 in Emera’s 2022 annual audited consolidated financial statements, and below for 2023 preferred stock activity.
On July 6, 2023, Emera announced that it would not redeem the 10,000,000 outstanding Cumulative Rate Reset Preferred Shares, Series C (“Series C Shares”) or the 12,000,000 outstanding Cumulative Minimum Rate Reset First Preferred Shares, Series H (“Series H Shares”) on August 15, 2023. Additionally, during the conversion period between July 17, 2023 and July 31, 2023, subject to certain conditions, the holders of the Series C Shares had the right, at their option, to convert all or any of their Series C Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series D of the Company (the “Series D Shares”) and the holders of the Series H Shares had the right, at their option, to convert all or any of their Series H Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series I of the Company (the “Series I Shares”), in each case on August 15, 2023.
On August 4, 2023, Emera announced that after having taken into account all conversion notices received from holders, no Series C Shares would be converted into Series D Shares and no Series H Shares would be converted into Series I Shares. The holders of the Series C Shares will be entitled to receive a dividend of 6.434 per cent per annum on the Series C Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of) August 14, 2028 ($0.40213 per Series C Share per quarter). The holders of the Series H Shares will be entitled to receive a dividend of 6.324 per cent per annum on the Series H Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of) August 14, 2028 ($0.39525 per Series H Share per quarter).
22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the | Six months ended June 30 | |||||||
| millions of dollars | 2023 | 2022 | ||||||
|
|
||||||||
| Changes in non-cash working capital: |
||||||||
| Inventory |
$ | (67) | $ | (59) | ||||
|
|
||||||||
| Receivables and other current assets (1) |
728 | (290) | ||||||
|
|
||||||||
| Accounts payable |
(678) | 289 | ||||||
|
|
||||||||
| Other current liabilities (2) |
(195) | (13) | ||||||
|
|
||||||||
| Total non-cash working capital |
$ | (212) | $ | (73) | ||||
|
|
||||||||
| 1) The six months ended June 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 six months ended June 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.
|
| |||||||
| Supplemental disclosure of non-cash activities: |
||||||||
| Common share dividends reinvested |
$ | 139 | $ | 115 | ||||
|
|
||||||||
| Increase in accrued capital expenditures |
$ | 30 | $ | 18 | ||||
|
|
||||||||
| Reclassification of long-term debt to short-term debt |
$ | - | $ | 500 | ||||
|
|
||||||||
| Reclassification of short-term debt from current to long-term |
$ | - | $ | 602 | ||||
|
|
||||||||
| Supplemental disclosure of operating activities: |
||||||||
| Net change in short-term regulatory assets and liabilities |
$ | (71) | $ | (190) | ||||
|
|
||||||||
23. 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 in 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 NSPML. Thus, Emera records NSPML 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 in “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.
The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.
The following table provides information about Emera’s portion of material unconsolidated VIEs:
| As at | June 30, 2023 | December 31, 2022 | ||||||||||||||
|
|
||||||||||||||||
| Maximum | Maximum | |||||||||||||||
| millions of dollars | Total assets |
exposure to loss |
Total assets |
exposure to loss |
||||||||||||
|
|
||||||||||||||||
| Unconsolidated VIEs in which Emera has variable interests |
||||||||||||||||
| NSPML (equity accounted) |
$ | 493 | $ | 6 | $ | 501 | $ | 6 | ||||||||
|
|
||||||||||||||||
24. 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 August 11, 2023, the date the unaudited condensed consolidated interim financial statements were issued.
Exhibit 99.3
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 June 30, 2023.
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 April 1, 2023 and ended on June 30, 2023 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: August 10, 2023
| “Scott Balfour” |
|
|
|
Scott Balfour President and Chief Executive Officer |
Exhibit 99.4
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 June 30, 2023.
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 April 1, 2023 and ended on June 30, 2023 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: August 10, 2023
“Greg Blunden”
Greg Blunden
Chief Financial Officer
Exhibit 99.5
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 six months ended June 30, 2023.
The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended June 30, 2023.
| Twelve months ended June 30, 2023 | ||
| Earnings Coverage (1) | 2.54 |
(1) Earnings coverage is equal to consolidated net income attributable to common shareholders plus: income taxes, interest on debt, amortization of debt financing costs, allowance for funds used during construction and preferred share dividends declared during the period together with undeclared preferred share dividends, if any, divided by the sum of interest on debt, amortization of debt financing costs, allowance for funds used during construction, capitalized interest and preferred dividends grossed up to a before-tax equivalent using an effective tax rate of 29.0 per cent.
Emera’s dividend requirements on all of its preferred shares, grossed up to a before-tax equivalent using an effective income tax rate of 29.0 per cent, amounted to $90 million for the twelve months ended June 30, 2023. Emera’s interest requirements for the twelve months ended June 30, 2023 amounted to $857 million. Emera’s consolidated income before interest and income tax for the twelve months ended June 30, 2023 was $2,408 million, which is 2.54 times Emera’s aggregate preferred dividends and interest requirements for this period.
Exhibit 99.6
Emera Reports 2023 Second Quarter Financial Results
HALIFAX, Nova Scotia – Today Emera (TSX: EMA) reported 2023 second quarter financial results.
Highlights
| · | Quarterly adjusted EPS (1) increased $0.01 to $0.60 compared to $0.59 in Q2 2022. Quarterly reported net income per common share increased $0.35 to $0.10 in Q2 2023 compared to a net loss per common share of $(0.25) in Q2 2022 due to lower mark-to-market (“MTM”) losses. |
| · | Year-to-date, adjusted EPS (1) increased $0.07 or 5% to $1.58 compared to $1.51 in 2022. Year-to-date reported EPS increased by $1.05 to $2.17 from $1.12 in 2022 due to MTM gains in 2023 compared to MTM losses in 2022. |
| · | Adjusted EPS(1) contributions from our regulated utilities increased 8% for the quarter and 3% year-to-date primarily driven by rate supported capital investments and continued customer growth partially offset by higher interest expense and less favourable weather. On a consolidated basis these increases were partially offset by higher corporate interest expense and lower contributions from Emera Energy Services (“EES”) during the quarter. |
| · | On track to deploy $2.8 billion in capital in 2023 with $1.4 billion invested in the first half of the year. |
“Our team continues to execute well on our proven strategy and despite the continued headwinds of high interest rates and overall inflationary pressures, we are driving solid results for customers and shareholders,” said Scott Balfour, President and CEO of Emera Inc. “As economic growth continues in our service territories, we remain focused on meeting growing demand and achieving a balanced energy transition that delivers increasingly clean energy while maintaining grid reliability and continues to consider cost impacts for customers, all while providing predictable, reliable earnings and cash flow growth for our shareholders.”
Q2 2023 Financial Results
Q2 2023 reported net income was $28 million, or $0.10 per common share, compared with a net loss of $67 million, or $(0.25) per common share, in Q2 2022. Reported net income for the quarter included a $134 million MTM loss, after-tax, primarily at EES compared to a $223 million loss in Q2 2022.
Q2 2023 adjusted net income(1) was $162 million, or $0.60 per common share, compared with $156 million, or $0.59 per common share, in Q2 2022. The increase was primarily due to higher earnings at Tampa Electric (“TEC”), Nova Scotia Power (“NSPI”), and New Mexico Gas (“NMGC”), the impact of a weaker Canadian dollar (“CAD”) on the translation of Emera’s non-Canadian affiliates, and higher income tax recovery at corporate. This was partially offset by decreased earnings at EES, and increased corporate interest expense due to higher interest rates and increased total debt.
Year-to-date Financial Results
Year-to-date reported net income was $588 million or $2.17 per common share, compared with net income of $295 million or $1.12 per common share year-to-date in 2022. Year-to-date reported net income included a $158 million MTM gain, after-tax, primarily at EES, compared to a $96 million loss in 2022.
Year-to-date adjusted net income(1) was $430 million or $1.58 per common share, compared with $398 million or $1.51 per common share year-to-date in 2022.
1
Growth in year-to-date adjusted net income was primarily due to higher earnings at NMGC, EES, TEC and NSPI, and the impact of a weaker CAD on the translation of Emera’s non-Canadian affiliates. This was partially offset by increased corporate interest expense due to higher interest rates and increased total debt.
The translation impact of a weakening CAD on our US denominated earnings and the unrealized gains on FX hedges used to mitigate translation risk of US dollar earnings combined to increase net income by $8 million in Q2 2023 and $42 million year-to-date compared to the same periods in 2022. Weakening of the CAD increased adjusted net income by $6 million in Q2 2023 and $18 million year-to-date compared to the same period in 2022.
(1) See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” below for reconciliation to nearest USGAAP measure.
Consolidated Financial Review
The following table highlights significant changes in adjusted net income attributable to common shareholders from 2022 to 2023.
| For the millions of Canadian dollars |
Three months ended June 30 |
Six months ended June 30 |
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| Adjusted net income – 2022 1,2 |
$ | 156 | $ | 398 | ||||
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| Operating Unit Performance |
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| Increased earnings at TEC due to new base rates, the impact of a weaker CAD and customer growth, partially offset by higher operating, maintenance and general expenses (“OM&G”), interest expense, depreciation and unfavourable weather | 16 | 11 | ||||||
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| Increased earnings at NMGC due to new base rates. Year-over-year earnings also increased due to higher asset optimization revenue, partially offset by increased OM&G | 4 | 24 | ||||||
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| Increased earnings at NSPI due to new base rates, increased sales volumes, customer growth and decreased income tax expense, partially offset by higher interest expense, OM&G and depreciation. Year-over-year also partially offset by unfavourable weather | 6 | 3 | ||||||
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| Decreased earnings at EES quarter-over-quarter due to lower natural gas prices, and timing of recognition of transport and other costs. Year-over-year increase reflects favourable hedging opportunities and more available gas transport due to mild weather in Q1 2023 | (17) | 12 | ||||||
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| Corporate |
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| Increased income tax recovery primarily due to increased losses before provision for income taxes | 11 | - | ||||||
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| Increased interest expense, pre-tax, due to increased interest rates and increased total debt | (10) | (30) | ||||||
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| Other Variances |
(4) | 12 | ||||||
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| Adjusted net income – 2023 1,2 |
$ | 162 | $ | 430 | ||||
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1 See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” for reconciliation to nearest GAAP measure.
2 Excludes the effect of MTM adjustments, after- tax, and the impact of the NSPML unrecoverable costs.
2
Segment Results and Non-GAAP Reconciliation
| For the | Three months ended June 30 |
Six Months ended June 30 |
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| millions of Canadian dollars (except per share amounts) |
2023 | 2022 | 2023 | 2022 | ||||||||||||
| Adjusted net income 1,2 |
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| Florida Electric Utility |
$ | 177 | $ | 161 | 284 | 273 | ||||||||||
| Canadian Electric Utilities |
49 | 39 | 141 | 137 | ||||||||||||
| Gas Utilities and Infrastructure |
38 | 39 | 132 | 116 | ||||||||||||
| Other Electric Utilities |
10 | 8 | 14 | 9 | ||||||||||||
| Other 3 |
(112) | (91) | (141) | (137) | ||||||||||||
| Adjusted net income1,2 |
$ | 162 | $ | 156 | 430 | 398 | ||||||||||
| MTM (loss) gain, after-tax4 |
(134) | (223) | 158 | (96) | ||||||||||||
| NSPML unrecoverable costs5 |
— | — | — | (7) | ||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 28 | $ | (67) | 588 | 295 | ||||||||||
| Earnings (loss) per share (basic) |
$ | 0.10 | $ | (0.25) | 2.17 | 1.12 | ||||||||||
| Adjusted Earnings per share (basic) 1,2 |
$ | 0.60 | $ | 0.59 | 1.58 | 1.51 | ||||||||||
1 See “Non-GAAP Financial Measures and Ratios” noted below.
2 Excludes the effect of MTM adjustments, and the impact of the NSPML unrecoverable costs in 2022.
3 Lower earnings quarter-over-quarter, primarily due to lower contributions from EES. Year-over-year change primarily due to increased interest expense, partially offset by higher contributions from EES.
4 Net of income tax recovery of $55 million for the three months ended June 30, 2023 (2022- $91 million recovery) and $64 million recovery for the six months ended June 30, 2023 (2022- $37 million recovery).
5 After-tax unrecoverable costs were recorded in “Income from equity investments” on Emera’s Condensed Consolidated Statements of Income
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 Q2 2023 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
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The company will be hosting a teleconference today, Friday, August 11, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q2 2023 financial results.
Analysts and other interested parties in North America are invited to participate by dialing 1-888-886-7786. International parties are invited to participate by dialing 1-416-764-8658. Participants should dial in at least 10 minutes prior to the start of the call. No pass code is required.
A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available on the Company’s website two hours after the conclusion of the call.
About Emera
Emera Inc. is a geographically diverse energy and services company headquartered in Halifax, Nova Scotia, with approximately $38 billion in assets and 2022 revenues of more than $7.5 billion. The company primarily invests in regulated electricity generation and electricity and gas transmission and distribution with a strategic focus on transformation from high carbon to low carbon energy sources. Emera has investments in Canada, the United States and in three Caribbean countries. Emera’s common and preferred shares are listed on the Toronto Stock Exchange and trade respectively under the symbol EMA, EMA.PR.A, EMA.PR.B, EMA.PR.C, EMA.PR.E, EMA.PR.F, EMA.PR.H, EMA.PR.J and EMA.PR.L. Depositary receipts representing common shares of Emera are listed on the Barbados Stock Exchange under the symbol EMABDR and on The Bahamas International Securities Exchange under the symbol EMAB. Additional information can be accessed at www.emera.com or at www.sedarplus.com.
Emera Inc.
Investor Relations
Dave Bezanson, VP, Investor Relations & Pensions
902-474-2126
dave.bezanson@emera.com
Arianne Amirkhalkhali, Senior Manager, Investor Relations
902-425-8130
arianne.amirkhalkhali@emera.com
Media
902-222-2683
media@emera.com
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