Emera Inc 6-K, filed Nov 16, 2022
Emera Inc (EMA)
About this 6-K
Emera Inc filed this 6-K on November 16, 2022.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16
UNDER THE SECURITIES EXCHANGE ACT OF 1934
For the month of November, 2022
Commission File Number: 000-54516
Emera Incorporated
(Exact name of registrant as specified in its charter)
5151 Terminal Road
Halifax NS B3J 1A1
Canada
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☑
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| EMERA INCORPORATED | ||||||
| Date: November 16, 2022 | By: | \s\ Stephen D. Aftanas | ||||
|
Name: Stephen D. Aftanas | ||||||
| Title: Corporate Secretary | ||||||
EXHIBIT INDEX
Exhibit 99.1
Management’s Discussion & Analysis
As at November 10, 2022
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments during the third quarter and year-to-date of 2022 relative to the same periods in 2021; and its financial position as at September 30, 2022 relative to December 31, 2021. 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 nine months ended September 30, 2022; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2021. 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 September 30, 2022, Emera’s rate-regulated subsidiaries and investments include:
| Emera Rate-Regulated Subsidiary or Equity Investment | Accounting Policies Approved/Examined By | |
| Subsidiary | ||
| Tampa Electric – Electric Division of Tampa Electric Company (“TEC”) | Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”) | |
| Nova Scotia Power Inc. (“NSPI”) | Nova Scotia Utility and Review Board (“UARB”) | |
| Peoples Gas System (“PGS”) – Gas Division of TEC | 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”) |
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 US dollars (“USD”) unless otherwise stated.
Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR at www.sedar.com.
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TABLE OF CONTENTS
| Forward-looking Information |
2 | |||
| Introduction and Strategic Overview |
3 | |||
| Non-GAAP Financial Measures and Ratios |
4 | |||
| Consolidated Financial Review |
6 | |||
| Significant Items Affecting Earnings |
6 | |||
| Consolidated Financial Highlights |
6 | |||
| Consolidated Income Statement Highlights |
8 | |||
| Business Overview and Outlook |
10 | |||
| COVID-19 Pandemic |
10 | |||
| Florida Electric Utility |
10 | |||
| Canadian Electric Utilities |
11 | |||
| Gas Utilities and Infrastructure |
14 | |||
| Other Electric Utilities |
15 | |||
| Other |
15 | |||
| Consolidated Balance Sheet Highlights |
16 | |||
| Other Developments |
17 | |||
| Financial Highlights |
18 | |||
| Florida Electric Utility |
18 | |||
| Canadian Electric Utilities |
19 |
| Gas Utilities and Infrastructure |
20 | |||
| Other Electric Utilities |
21 | |||
| Other |
22 | |||
| Liquidity and Capital Resources |
23 | |||
| Consolidated Cash Flow Highlights |
24 | |||
| Contractual Obligations |
25 | |||
| Guarantees and Letters of Credit |
26 | |||
| Debt Management |
26 | |||
| Credit Ratings Outstanding Stock Data |
|
27 28 |
| |
| Transactions with Related Parties |
28 | |||
| Risk Management including Financial Instruments |
29 | |||
| Disclosure and Internal Controls |
30 | |||
| Critical Accounting Estimates |
31 | |||
| Changes in Accounting Policies and Practices |
31 | |||
| Future Accounting Pronouncements |
31 | |||
| Summary of Quarterly Results |
31 |
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 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; 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 infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic; market energy sales prices; labour relations; and availability of labour and management resources.
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Readers are cautioned not to place undue reliance on 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.
Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have generally experienced stable regulatory policies and economic conditions. 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 (including a $240 million equity investment in the LIL in 2023). 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 and at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a priority of management.
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 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 US dollar relative to the Canadian dollar and benefit from a weaker Canadian dollar. 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.
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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 sees opportunity 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 Tampa Electric. 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 over the past 15 years, 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 the benefit of supportive regulatory decisions, Emera plans and expects to achieve the following goals compared to corresponding 2005 levels:
| • | A 55 per cent reduction in carbon dioxide emissions by 2025. |
| • | The retirement of Emera’s last existing coal unit no later than 2040. |
| • | An 80 per cent reduction in carbon dioxide emissions by 2040. |
Emera seeks to deliver on 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 the 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 Per Common Share – 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 mark-to-market (“MTM”) adjustments and the impact of the NSPML unrecoverable costs.
4
Management believes excluding from net income the effect of these MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows, and excludes these 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 a captive reinsurance company in the Other segment; and |
| • | FX cash flow hedges entered to manage FX earnings exposure. |
For further detail on 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 the 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 NSPML unrecoverable costs, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Financial Highlights – Canadian Electric Utilities” sections.
Adjusted earnings per common share – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above.
Emera calculates adjusted net income and adjusted earnings per common share – basic 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. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in Emera’s 2021 annual MD&A.
The following reconciles net income (loss) attributable to common shareholders to adjusted net income:
| Three months ended | Nine months ended | |||||||||||||||
| For the |
September 30 | September 30 | ||||||||||||||
| millions of dollars (except per share amounts) | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 167 | $ | (70) | $ | 462 | $ | 186 | ||||||||
| MTM loss, after-tax (1) |
(36) | (245) | (132) | (369) | ||||||||||||
| NSPML unrecoverable costs (2) |
- | - | (7) | - | ||||||||||||
| Adjusted net income |
$ | 203 | $ | 175 | $ | 601 | $ | 555 | ||||||||
| Earnings (loss) per common share – basic |
$ | 0.63 | $ | (0.27) | $ | 1.75 | $ | 0.73 | ||||||||
| Adjusted earnings per common share – basic |
$ | 0.76 | $ | 0.68 | $ | 2.27 | $ | 2.17 | ||||||||
| (1) Net of income tax recovery of $14 million for the three months ended September 30, 2022 (2021 - $100 million recovery) and $51 million recovery for the nine months ended September 30, 2022 (2021 - $149 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 NSPML unrecoverable costs.
The following is a reconciliation of net income (loss) to EBITDA and Adjusted EBITDA:
| Three months ended | Nine months ended | |||||||||||||
| For the |
September 30 | September 30 | ||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||
| Net income (loss) (1) |
$ | 184 | $ | (56) | $ | 510 | $ 223 | |||||||
| Interest expense, net |
184 | 150 | 503 | 460 | ||||||||||
| Income tax expense (recovery) |
2 | (92) | 31 | (91) | ||||||||||
| Depreciation and amortization |
238 | 228 | 698 | 675 | ||||||||||
| EBITDA |
$ | 608 | $ | 230 | $ | 1,742 | $ 1,267 | |||||||
| MTM loss, excluding income tax |
(50) | (345) | (183) | (518) | ||||||||||
| NSPML unrecoverable costs (2) |
- | - | (7) | - | ||||||||||
| Adjusted EBITDA |
$ | 658 | $ | 575 | $ | 1,932 | $ 1,785 | |||||||
(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 MTM Loss, After-Tax
MTM loss, after-tax decreased $209 million to $36 million in Q3 2022, compared to $245 million in Q3 2021 primarily due to changes in existing positions, partially offset by higher amortization of gas transportation assets in 2022 and larger reversal of MTM losses in 2021 at Emera Energy. Year-to-date, MTM loss, after-tax decreased $237 million to $132 million compared to $369 million for the same period in 2021 due to a larger reversal of MTM losses in 2022 and changes in existing positions, partially offset by higher amortization of gas transportation assets in 2022 at Emera Energy.
Consolidated Financial Highlights
| For the |
Three months ended | Nine months ended | ||||||||||||
| millions of dollars |
September 30 | September 30 | ||||||||||||
| Adjusted net income | 2022 | 2021 | 2022 | 2021 | ||||||||||
| Florida Electric Utility |
$ | 199 | $ | 169 | $ | 472 | $ 377 | |||||||
| Canadian Electric Utilities |
39 | 42 | 176 | 174 | ||||||||||
| Gas Utilities and Infrastructure |
33 | 29 | 149 | 143 | ||||||||||
| Other Electric Utilities |
12 | 8 | 21 | 15 | ||||||||||
| Other |
(80) | (73) | (217) | (154) | ||||||||||
| Adjusted net income |
$ | 203 | $ | 175 | $ | 601 | $ 555 | |||||||
| MTM loss, after-tax |
(36) | (245) | (132) | (369) | ||||||||||
| NSPML unrecoverable costs |
- | - | (7) | - | ||||||||||
| Net income (loss) attributable to common shareholders |
$ | 167 | $ | (70) | $ | 462 | $ 186 | |||||||
6
The following table highlights significant changes in adjusted net income from 2021 to 2022:
| For the |
Three months ended | Nine months ended | ||||
| millions of dollars | September 30 | September 30 | ||||
| Adjusted net income – 2021 | $ | 175 | $ 555 | |||
| Operating Unit Performance | ||||||
| Increased earnings at Tampa Electric due to higher revenues as a result of rate increases effective January 2022, customer growth and the impact of a weakening CAD. These were partially offset by higher operating, maintenance and general expenses (“OM&G”), increased interest expense and higher depreciation. Year-over-year also increased due to favourable weather | 30 | 95 | ||||
| Increased earnings at NSPI driven by higher sales volumes, partially offset by increased OM&G primarily due to increased information technology, storm restoration and power generation expenses | 2 | 10 | ||||
| Increased earnings at PGS due to reversal of accumulated depreciation as a result of the rate case settlement and higher off-system sales, partially offset by higher OM&G. Year-over-year also increased due to customer growth | 3 | 8 | ||||
| Increased earnings at Seacoast due to commencement of a 34-year pipeline lateral lease in 2022 | 2 | 6 | ||||
| Increased earnings at Emera Energy Services (“EES”) due to higher natural gas prices and volatility, which created profitable opportunities. Year-over-year increase was offset by the positive margin impact of Winter Storm Uri in Q1 2021 | 16 | - | ||||
| Corporate | ||||||
| Increased OM&G, pre-tax due to the timing of long-term compensation and related hedges | (17) | (36) | ||||
| Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX hedges entered into to hedge USD denominated operating unit earnings exposure | (6) | (19) | ||||
| Increased preferred stock dividends due to issuance of preferred shares in 2021 | (2) | (11) | ||||
| Increased interest expense, pre-tax, due to higher interest rates and increased total debt | (10) | (10) | ||||
| Other Variances | 10 | 3 | ||||
| Adjusted net income – 2022 | $ | 203 | $ 601 | |||
|
For further details of reportable segments contributions, refer to the “Financial Highlights” section. | ||||||
| For the |
Nine months ended September 30 | |||||
| millions of dollars | 2022 | 2021 | ||||
| Operating cash flow before changes in working capital |
$ 806 | $ 1,035 | ||||
| Change in working capital |
149 | 71 | ||||
| Operating cash flow |
$ 955 | $ 1,106 | ||||
| Investing cash flow |
$ (1,685) | $ (1,576) | ||||
| Financing cash flow |
$ 844 | $ 693 | ||||
|
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
| ||||||
| As at |
September 30 | December 31 | ||||
| millions of dollars | 2022 | 2021 | ||||
| Total assets |
$ 39,804 | $ 34,244 | ||||
| Total long-term debt (including current portion) |
$ 15,860 | $ 14,658 | ||||
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Consolidated Income Statement Highlights
| For the |
Three months ended | Nine months ended | ||||||||||||||||||||
| millions of dollars |
September 30 | September 30 | ||||||||||||||||||||
| (except per share amounts) |
2022 | 2021 | Variance | 2022 | 2021 | Variance | ||||||||||||||||
| Operating revenues | $ | 1,835 | $ | 1,148 | $ | 687 | $ | 5,230 | $ | 3,897 | $ 1,333 | |||||||||||
| Operating expenses | 1,496 | 1,201 | (295) | 4,321 | 3,483 | (838) | ||||||||||||||||
| Income from operations | $ | 339 | $ | (53) | $ | 392 | $ | 909 | $ | 414 | $ 495 | |||||||||||
| Net income (loss) attributable to common shareholders | $ | 167 | $ | (70) | $ | 237 | $ | 462 | $ | 186 | $ 276 | |||||||||||
| Adjusted net income | $ | 203 | $ | 175 | $ | 28 | $ | 601 | $ | 555 | $ 46 | |||||||||||
| Weighted average shares of common stock outstanding (in millions) (1) | 266.6 | 258.5 | 8.1 | 264.3 | 256.0 | 8.3 | ||||||||||||||||
| Earnings (loss) per common share – basic | $ | 0.63 | $ | (0.27) | $ | 0.90 | $ | 1.75 | $ | 0.73 | $ 1.02 | |||||||||||
| Earnings (loss) per common share – diluted | $ | 0.63 | $ | (0.27) | $ | 0.90 | $ | 1.74 | $ | 0.73 | $ 1.01 | |||||||||||
| Adjusted earnings per common share – basic | $ | 0.76 | $ | 0.68 | $ | 0.08 | $ | 2.27 | $ | 2.17 | $ 0.10 | |||||||||||
| Dividends per common share declared | $ | 0.6625 | $ | 0.6375 | $ | 0.0250 | $ | 1.9875 | $ | 1.9125 | $ 0.0750 | |||||||||||
| Adjusted EBITDA | $ | 658 | $ | 575 | $ | 83 | $ | 1,932 | $ | 1,785 | $ 147 | |||||||||||
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore excluded from weighted average shares of common stock outstanding.
Operating Revenues
For Q3 2022, operating revenues increased $687 million compared to Q3 2021 and, absent decreased MTM losses of $317 million, increased $370 million. Year-to-date 2022, operating revenues increased $1,333 million compared to 2021 and, absent decreased MTM losses of $360 million, increased by $973 million. The increases in both periods were due to higher fuel revenues at NMGC, Tampa Electric, PGS, and BLPC, new rates effective January 2022 and customer growth at Tampa Electric, the impact of a weaker CAD, increased sales volumes at NSPI, higher off-system sales at PGS, and increased marketing and trading margin at EES. Favourable weather at Tampa Electric and customer growth at PGS contributed to increased operating revenues year-over-year, partially offset by the margin impact at EES of Winter Storm Uri in Q1 2021.
Operating Expenses
For Q3 2022, operating expenses increased $295 million and year-to-date 2022, increased $838 million compared to the same periods in 2021. The increases in both periods were due to higher natural gas and fuel prices at the regulated utilities, the impact of a weaker CAD and increased OM&G at Tampa Electric, Corporate and NSPI.
Net Income and Adjusted Net Income
For Q3 2022, net income attributable to common shareholders compared to Q3 2021, was favourably impacted by the $209 million decrease in after-tax MTM losses. Absent the favourable MTM changes, adjusted net income increased $28 million. The increase was primarily due to higher earnings contribution from Tampa Electric and Emera Energy and the impact of a weaker CAD. These were partially offset by increased OM&G at Corporate due to the timing of long-term compensation and related hedges and higher interest expense due to higher interest rates and increased total debt.
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Year-to-date 2022, net income attributable to common shareholders, compared to the same period in 2021, was favourably impacted by the $237 million decrease in after-tax MTM losses and unfavourably impacted by the $7 million in NSPML unrecoverable costs. Absent these changes, adjusted net income increased $46 million. The increase was primarily due to higher earnings contributions from Tampa Electric, NSPI, PGS and Seacoast and the impact of a weaker CAD. These were partially offset by increased Corporate OM&G due to the timing of long-term compensation and related hedges, realized gains on Corporate cash flow hedges in 2021, increased preferred stock dividends and increased interest expense due to higher interest rates and increased total debt.
Earnings and Adjusted Earnings per Common Share – Basic
Earnings and adjusted earnings per common share – basic were higher for Q3 2022, and year-to-date 2022, due to the impact of higher earnings as discussed above, partially offset by the impact of the increase in weighted average shares of common stock outstanding.
Effect of Foreign Currency Translation
Emera operates in Canada, the United States and various Caribbean countries and, as such, generates revenues and incurs expenses denominated in local currencies which are translated into CAD for financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can positively or adversely affect results.
In general, Emera’s earnings benefit from a weakening CAD and are adversely impacted by a strengthening CAD. The impact in any period is driven by rate changes, the timing and percentage of earnings from foreign operations, and the impact of entered FX cash flow hedges to manage FX earnings exposure.
Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/USD exchange rates for 2022 and 2021 are as follows:
| Three months ended | Nine months ended | Year ended | ||||||||||||||||
| September 30 | September 30 | December 31 | ||||||||||||||||
| For the |
2022 | 2021 | 2022 | 2021 | 2021 | |||||||||||||
| Weighted average CAD/USD |
$ | 1.35 | $ | 1.28 | $ | 1.30 | $ | 1.27 | $ 1.26 | |||||||||
| Period end CAD/USD |
$ | 1.37 | $ | 1.27 | $ | 1.37 | $ | 1.27 | $ 1.27 | |||||||||
The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency.
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD |
2022 | 2021 | 2022 | 2021 | ||||||||||||
| Florida Electric Utility |
$ | 153 | $ | 135 | $ | 367 | $ | 302 | ||||||||
| Gas Utilities and Infrastructure (1) |
19 | 16 | 98 | 93 | ||||||||||||
| Other Electric Utilities |
9 | 6 | 16 | 12 | ||||||||||||
| Other segment (2) |
(30 | ) | (39 | ) | (80 | ) | (78 | ) | ||||||||
| Total (3) |
$ | 151 | $ | 118 | $ | 401 | $ | 329 | ||||||||
| (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 $22 million MTM loss, after-tax for the three months ended September 30, 2022 (2021 - $190 million) and $92 million MTM loss, after-tax, for the nine months ended September 30, 2022 (2021 - $286 million). |
| |||||||||||||||
The impact of the unrealized losses on FX hedges, partially offset by weakening of the CAD decreased net income by $12 million in Q3 2022 and year-to-date 2022, compared to the same periods in 2021. Weakening of the CAD increased adjusted net income by $7 million in Q3 2022 and $14 million year-to-date 2022, compared to the same periods in 2021. The impacts of the weakening CAD include the current quarter and year-to-date impacts of corporate FX hedges in the Other segment.
9
BUSINESS OVERVIEW AND OUTLOOK
COVID-19 Pandemic
The Company’s priorities continue to be reliable delivery of essential energy services to meet customers’ demands while maintaining the health and safety of its customers and employees and supporting the communities in which Emera operates. While the ongoing COVID-19 pandemic has had varying effects on the service territories in which Emera operates, on a consolidated basis, COVID-19 is not expected to have a material financial impact in 2022. For further information on COVID-19 and its potential future impacts on Emera and its businesses, refer to the “Business Overview and Outlook” and “Liquidity and Capital Resources” sections in Emera’s 2021 annual MD&A.
Florida Electric Utility
Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida.
Tampa Electric anticipates earning within its ROE range in 2022. New base rates effective January 1, 2022 are expected to result in higher 2022 USD earnings than in 2021. Tampa Electric expects customer growth rates in 2022 to be consistent with 2021, reflective of current economic growth in Florida.
Tampa Electric’s 2021 settlement agreement allows the company to request an increase to revenue and ROE due to increases in the 30-year United States Treasury bond yield rate. On July 1, 2022, Tampa Electric requested the FPSC to increase its annual base rates by $10 million USD effective September 1, 2022 and to increase its ROE. On August 16, 2022, the FPSC approved the change. Effective July 1, 2022, the new mid-point ROE is 10.20 per cent, and the range is 9.25 per cent to 11.25 per cent.
The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD and will be spread over customer bills from April 1, 2022 through December 2022. Tampa Electric continues to be impacted by increased fuel costs and expects to have an under-recovered fuel balance at the end 2022. Tampa Electric plans to file for recovery of this balance in late 2022 or early 2023 for collection in subsequent periods.
On September 28, 2022, Hurricane Ian made landfall in Southwest Florida as a Category 4 hurricane and as a result, approximately 291,000 customers lost power. The majority of Hurricane Ian restoration costs will be charged against Tampa Electric’s FPSC approved storm reserve, resulting in minimal impact to earnings for 2022. The total cost of restoration is estimated to be $130 million USD. As of September 30, 2022, Tampa Electric incurred $68 million USD in storm restoration cost and an additional $62 million USD in storm restoration costs are expected to be incurred in Q4 2022. Total restoration costs charged to the storm reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. Tampa Electric expects to petition the FPSC in late 2022 or early 2023 for recovery of the storm reserve regulatory asset and the replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for a total of approximately $136 million USD.
In 2022, capital investment in the Florida Electric Utility segment is expected to be approximately $1.1 billion USD (2021 - $1.2 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include continuation of the modernization of the Big Bend Power Station, solar investments, grid modernization, storm hardening investments, and operational infrastructure.
10
Canadian Electric Utilities
Canadian Electric Utilities includes NSPI and Emera Newfoundland & Labrador Holdings Inc. (“ENL”). NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and is the primary electricity supplier to customers in Nova Scotia. ENL is a holding company with equity investments in NSPML and LIL, two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador.
NSPI
NSPI anticipates earning near the low end of its allowed ROE range in 2022 and expects earnings to be consistent with 2021. Warmer than normal weather adversely affected NSPI’s sales volumes in 2021. NSPI expects sales volumes to be higher than 2021.
On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a post tropical storm equivalent to a Category 2 hurricane with sustained winds of over 100 kilometres per hour and peak gusts of approximately 180 kilometres per hour. This historic storm for Nova Scotia caused significant and widespread damage to NSPI’s transmission and distribution system and at the height of the storm approximately 415,000 customers lost power. The total cost of restoration is expected to be approximately $115 million. As of September 30, 2022, NSPI incurred $48 million in storm restoration costs, of which $39 million was capitalized to Property, plant and equipment (“PP&E”) and $9 million deferred to Other long-term assets for future amortization, subject to UARB approval. An estimated $67 million in additional storm restoration costs are expected to be incurred in Q4 2022 and NSPI anticipates that the allocation between PP&E and Other long-term assets will be similar to that of the costs incurred during Q3 2022.
NSPI is currently operating under a three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. The 2022 rates include approximately $162 million related to the recovery of Maritime Link costs (discussed below in the “ENL, NSPML” section).
On January 27, 2022, NSPI filed a General Rate Application (“GRA”) with the UARB, which was then amended on February 18, 2022. The GRA proposes a rate stability plan for 2022 through 2024 which includes average rate increases of 2.8 per cent per year on August 1, 2022, January 1, 2023 and January 1, 2024 to recover non-fuel costs. On September 2, 2022, NSPI filed a fuel update to the GRA proposing that the cost of fuel increases be smoothed over 2023 and 2024 and the forecast Fuel Adjustment Mechanism (“FAM”) balance at December 31, 2022 be recovered over three years (2023 through 2025), resulting in combined fuel rate increases of 1.6 per cent on January 1, 2023 and January 1, 2024 to recover fuel costs. The remaining recovery of the 2022 FAM balance is forecast to be collected in 2025 and would require an additional fuel rate increase of 1.3 per cent, subject to UARB approval in future rate applications. The effective timing of any approved increases would be determined by the UARB. The hearing for this matter concluded in September 2022 with closing submissions to be filed in Q4 2022. A decision by the UARB is expected in Q1 2023.
On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. The legislation pre-empts the pending UARB GRA decision and limits non-fuel rate increases, excluding increases relating to demand-side management costs, to a total of 1.8 per cent between the effective date of the UARB’s decision and the end of 2024. The legislation also:
| • | requires revenue generated from the non-fuel rate increase to be used only to improve the reliability of service to ratepayers; |
| • | limits NSPI’s return on equity to 9.25 per cent and equity ratio to 40 per cent; and |
| • | limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus 1.75 per cent, unless otherwise directed by the UARB. |
11
Actions required to address the impact of this legislation are likely to include a material reduction in NSPI’s planned capital investments and operating costs over the 2023 through 2024 period. As a result, planned expenditures for 2023 and 2024 will be deferred, resulting in higher customer costs in future periods. The legislation will have a direct and negative impact on the expected financial performance of NSPI such that it is not expected to earn within its currently allowed return on equity band in 2023 and 2024 at the currently approved equity ratio of 37.5 per cent. The Company has updated its principal risks disclosure to reflect this development. Refer to the “Risk Management and Financial Instruments” section and note 20 in the Q3 2022 unaudited condensed consolidated financial statements for this risk update.
Energy from renewable sources has increased with Nalcor Energy’s (“Nalcor”) NS Block delivery obligations from the Muskrat Falls hydroelectric project (“Muskrat Falls”) commencing August 15, 2021. Nalcor is obligated to provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, NSPI is also entitled to receive approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. Nalcor’s final commissioning of the LIL has experienced delays and Nalcor is working toward final commissioning of the LIL in Q4 2022. During these final stages of commissioning, there will be interruptions in supply, with any resultant delivery shortfalls being delivered at a date to be agreed to by the companies. NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from Nalcor for up to 1.8 TWh of energy in any given year and, on average, 1.2 TWh of energy per year through August 31, 2041.
In 2022, NSPI expects to invest $545 million (2021 – $388 million), including AFUDC, primarily in capital projects to support system reliability, renew hydroelectric infrastructure, and add renewable capacity.
Environmental Legislation and Regulations
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these laws and regulations to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated compliance will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPI’s operations and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management” and “Business Overview and Outlook – Canadian Electric Utilities” sections respectively of Emera’s 2021 annual MD&A. Recent developments related to provincial and federal environmental laws and regulations are outlined below.
Nova Scotia Cap-and-Trade Program Regulations:
NSPI is a participant in the Nova Scotia Cap-and-Trade Program and is subject to the 2019 through 2022 compliance period. NSPI received granted emission allowances under the Cap-and-Trade Program and is permitted to purchase up to five per cent of the credits available at provincial auctions or reserve credits, which are anticipated to be priced at a premium, from the provincial government. Lower than forecasted Muskrat Falls energy received during the compliance period has resulted in the increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has announced that it will provide $165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of compliance forecasted at the time of the September 2022 GRA fuel update. Discussions related to how this relief will be provided are ongoing.
12
Carbon Pricing Regulations:
On November 9, 2022, the Nova Scotia provincial government enacted Bill 208, “Environment Act (amended)”. The legislation provides the framework for Nova Scotia’s system to comply with the federal government’s 2023 through 2030 carbon pollution pricing regulations laid out in the Pan-Canadian Framework on Clean Growth and Climate Change. Nova Scotia’s proposed system utilizes an output-based pricing system that will implement performance standards for large industrial greenhouse gas emitters to achieve emission reduction goals. Subsequent regulations will be required to detail how the pricing system will operate. The Province of Nova Scotia’s proposed output-based pricing system is subject to the approval of the federal government. If an agreement is not reached between the federal and provincial governments on a Nova Scotia system that meets the federal compliance criteria, Nova Scotia will be subject to the federal carbon pollution pricing backstop which will start at $65 per tonne in 2023 and increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI anticipates that any prudently incurred costs required to comply with carbon pricing programs will be recoverable under NSPI’s regulatory framework.
Nova Scotia Renewable Energy Regulations:
The alternative compliance plan, under the provincially legislated Renewable Energy Regulations, requires NSPI to achieve 40 per cent of electric sales generated from renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as further interruptions in supply due to delays in the LIL, NSPI is not forecasting the ability to achieve the requirements of the alternative compliance plan. The Renewable Energy Regulations require NSPI to have acted in a duly diligent manner. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a maximum penalty of $10 million.
ENL
Absent the NSPML unrecoverable costs and potential holdback, equity earnings from NSPML and LIL are expected to be consistent in 2022, compared to 2021. Both NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.
The Maritime Link assets entered into service on January 15, 2018, enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, and supporting the efficiency and reliability of energy in both provinces. For further information on the NS Block, refer to the NSPI section above.
On August 3, 2022, NSPML submitted an application to the UARB requesting recovery of approximately $164 million in Maritime Link costs for 2023. A decision is expected in Q4 2022.
In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $1.8 billion less approximately $9 million of costs ($7 million after-tax) that would not otherwise have been recoverable if incurred by NSPI. NSPML also received approval to collect $168 million (2021- $172 million) from NSPI for the recovery of Maritime Link costs in 2022. This is subject to a monthly holdback of up to $2 million from April to December 2022 contingent on receiving at least 90 per cent of NS Block deliveries, including Supplementary Energy deliveries, and the cost of replacement energy.
NSPML does not anticipate any significant capital investment in 2022 (2021 – $6 million).
13
LIL
ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is working toward final commissioning in 2022.
Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $725 million, comprised of $410 million in equity contribution and $315 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after the Lower Churchill projects are completed.
Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, and until that point Emera will continue to record AFUDC earnings.
Gas Utilities and Infrastructure
Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s non-consolidated investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2022 than 2021, primarily due to customer growth and the reversal of accumulated depreciation at PGS, as discussed below.
PGS anticipates earning within its allowed ROE range in 2022 and expects rate base and USD earnings to be higher than in 2021. PGS expects favourable customer growth in 2022 and residential and commercial sales volumes in 2022 are expected to increase at a level slightly below customer growth. The PGS rate case settlement, which was approved in November 2020, also provides the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. Through September 2022, PGS reversed $14 million USD accumulated depreciation. The reversal of the remaining accumulated depreciation is expected to occur over the 2022 and 2023 periods.
In September 2022, Hurricane Ian impacted PGS’s operations in Fort Myers and Sarasota. The estimated restoration costs are expected to be up to $3 million USD and will be charged against PGS’s FPSC approved storm reserve, resulting in minimal impact to earnings.
NMGC anticipates earning below its authorized ROE in 2022 and expects rate base to be higher than 2021. NMGC expects customer growth rates to be consistent with historical trends.
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The proposed rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. A hearing was held in June 2022 and a decision from the NMPRC is expected in Q4 2022.
In 2018, SeaCoast executed a 34-year agreement to provide long-term firm gas transportation service via a 21-mile, 30-inch pipeline lateral. The lease of the pipeline lateral commenced January 1, 2022.
In 2022, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $440 million USD (2021 - $407 million USD), including AFUDC. PGS will make investments to support customer growth and expand its system to ensure reliability. NMGC will continue to make investments to maintain the reliability of its system.
14
Other Electric Utilities
Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island, and a 19.5 per cent interest in Lucelec on the island of St. Lucia which is accounted for on the equity basis.
On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”) for proceeds which approximated carrying value. Domlec was included in the Other Electric segment in Q1 2022. The sale did not have a material impact on earnings.
Other Electric Utilities’ USD earnings in 2022 are expected to increase over the prior year due to higher earnings due to higher base rates at GBPC and BLPC and the continued recovery in local economies from the impacts of COVID-19.
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023 the fuel pass through charge will be adjusted monthly in-line with actual fuel costs.
On January 14, 2022, the GBPA issued its decision on GBPC’s rate application. The approved increase in annual revenues of $3.5 million USD commenced on April 1, 2022.
On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country’s transition towards 100 per cent renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $3 million USD for the remainder of 2022. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022 and BLPC expects a decision on final rates from the FTC in 2022.
In 2022, capital investment in the Other Electric Utilities segment is expected to be $60 million USD (2021 – $88 million USD), primarily in more efficient and cleaner sources of generation.
Other
The Other segment includes business operations that in a normal year are below the required threshold for reporting as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments.
Business operations in the Other segment include Emera Energy and Emera Technologies LLC (“ETL”). Emera Energy consists of EES, a wholly owned physical energy marketing and trading business, and an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 633 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.
Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings recorded in “Intercompany revenue” and interest expense on corporate debt in both Canada and the United States. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.
15
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).
The adjusted net loss from the Other segment is expected to be higher in 2022 due to higher Corporate OM&G which is primarily driven by the timing of long-term compensation and related hedges, realized FX gains on cash flow hedges in 2021, increased interest expense, and additional preferred dividends. This is expected to be partially offset by decreased taxes due to a higher net loss.
The Other segment does not anticipate any significant capital investments in 2022. (2021 - $1 million).
| CONSOLIDATED BALANCE SHEET HIGHLIGHTS
| ||||
| Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2021 and September 30, 2022 include: | ||||
| millions of dollars | Increase (Decrease) |
Explanation | ||||
| Assets |
||||||
| Cash and cash equivalents | $ | 132 | Increased due to proceeds from short-term debt issuance at Emera and Tampa Electric, cash from operations, and issuance of common stock. These were partially offset by increased investment in PP&E at the regulated utilities and dividends on common stock | |||
| Inventory | 184 | Increased due to higher commodity prices at Emera Energy and NSPI and the effect of a weaker CAD on the translation of Emera’s foreign affiliates | ||||
| Derivative instruments (current and long-term) | 396 | Increased due to higher commodity prices at NSPI and reversal of 2021 contracts at Emera Energy, partially offset by settlements at NSPI | ||||
| Regulatory assets (current and long-term) | 865 | Increased due to higher fuel cost recovery clauses at Tampa Electric, the effect of a weaker CAD on the translation of Emera’s foreign affiliates, increased FAM deferrals at NSPI, increased deferred income tax regulatory assets at NSPI and Tampa Electric, and recognition of storm reserve asset at Tampa Electric due to restoration costs from Hurricane Ian in excess of the storm reserve liability. These were partially offset by recovery of gas costs from the NMGC 2021 winter event | ||||
| Receivables and other assets (current and long-term) | 1,116 | Increased due to higher gas transportation assets and cash collateral at Emera Energy, the effect of a weaker CAD on the translation of Emera’s foreign affiliates, and higher trade receivables at Tampa Electric | ||||
| PP&E, net of accumulated depreciation and amortization | 2,202 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, and capital additions. These were partially offset by reclassification of Seacoast’s pipeline lateral on commencement of the lease | ||||
| Net investment in direct finance and sales type leases | 101 | Increased due to commencement of the pipeline lease at Seacoast | ||||
| Goodwill | 462 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates | ||||
16
| millions of dollars | Increase (Decrease) |
Explanation | ||||
| Liabilities and Equity | ||||||
| Short-term debt and long-term debt (including current portion) | $ | 1,974 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, issuance of short-term debt at Emera and Tampa Electric, and net borrowings under the committed credit facility at NSPI | |||
| Accounts payable | 586 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates, higher cash collateral position on derivative instruments at NSPI, increased commodity prices at Emera Energy and Tampa Electric, and timing of payments at Tampa Electric and NSPI | ||||
| Deferred income tax liabilities, net of deferred income tax assets | 120 | Increased due to tax deductions in excess of accounting depreciation related to PP&E and increase in net regulatory assets, partially offset by net increase in tax loss carryforwards | ||||
| Derivative instruments (current and long-term) | 1,119 | Increased due to new contracts in 2022 and changes in existing positions, partially offset by reversal of 2021 contracts at Emera Energy | ||||
| Regulatory liabilities (current and long-term) | 317 | Increased due to deferrals related to derivative instruments at NSPI and the effect of a weaker CAD on the translation of Emera’s foreign affiliates, partially offset by decreased storm reserve at Tampa Electric due to restoration costs incurred from Hurricane Ian | ||||
| Other liabilities (current and long-term) | 392 | Increased due to accrued emissions compliance charges at NSPI, higher investment tax credits related to solar projects at Tampa Electric, and the effect of a weaker CAD on the translation of Emera’s foreign affiliates | ||||
| Common stock | 433 | Increased due to Emera’s ATM equity program and shares issued under the dividend reinvestment program | ||||
| Accumulated other comprehensive income | 638 | Increased due to the effect of a weaker CAD on the translation of Emera’s foreign affiliates | ||||
| Retained earnings | (63) | Decreased due to dividends paid in excess of net income | ||||
OTHER DEVELOPMENTS
USGAAP Reporting Extension
Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report its financial results in accordance with USGAAP (collectively the “Exemptive Relief”). The Exemptive Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have rate-regulated activities, the first day of the Company’s financial year that commences after the Company ceases to have rate-regulated activities; and (iii) the first day of the Company’s financial year that commences on or following the later of: (a) the effective date prescribed by the International Accounting Standards Board (“IASB”) for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities (“Mandatory Rate-regulated Standard”); and (b) two years after the IASB publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1, 2024.
Increase in Common Dividends
On September 22, 2022, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.76 from $2.65. The first payment will be effective November 15, 2022. Emera also extended its dividend growth rate target of four to five per cent through 2025.
17
Appointments
Effective July 1, 2022, Michael Barrett was appointed Executive Vice President and General Counsel for Emera. Mr. Barrett was most recently the General Counsel for Emera.
Effective June 30, 2022, Bruce Marchand was appointed Chief Risk and Sustainability Officer for Emera. Mr. Marchand was most recently the Chief Legal and Compliance Officer for Emera.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
All amounts are reported in USD, unless otherwise stated.
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD (except as indicated) |
2022 | 2021 | 2022 | 2021 | ||||||||||||
| Operating revenues – regulated electric |
$ | 753 | $ | 634 | $ | 1,926 | $ | 1,613 | ||||||||
| Regulated fuel for generation and purchased power |
$ | 270 | $ | 217 | $ | 631 | $ | 501 | ||||||||
| Contribution to consolidated net income |
$ | 153 | $ | 135 | $ | 367 | $ | 302 | ||||||||
| Contribution to consolidated net income (CAD) |
$ | 199 | $ | 169 | $ | 472 | $ | 377 | ||||||||
| Electric sales volumes (Gigawatt hours (“GWh”)) |
6,259 | 6,003 | 16,002 | 15,332 | ||||||||||||
| Electric production volumes (GWh) |
6,341 | 6,256 | 16,675 | 16,211 | ||||||||||||
| Average fuel cost per megawatt hour (“MWh”) |
$ | 43 | $ | 35 | $ | 38 | $ | 31 | ||||||||
The impact of the change in the FX rate increased CAD earnings for the three and nine months ended September 30, 2022 by $7 million and $13 million, respectively.
Highlights of the net income changes are summarized in the following table:
| For the millions of USD |
Three months ended September 30 |
Nine months ended September 30 |
||||||
| Contribution to consolidated net income – 2021 |
$ 135 | $ 302 | ||||||
| Increased operating revenues due to higher fuel recovery clause revenue as a result of increased fuel costs, new rates effective January 2022, and customer growth. Year-over-year also increased due to favourable weather | 119 | 313 | ||||||
| Increased fuel for generation and purchased power due to higher natural gas prices | (53) | (130) | ||||||
| Increased OM&G expenses due to timing of deferred clause recoveries, higher benefit costs, and higher transmission and distribution costs. Year-over-year also due to higher insurance costs | (18) | (46) | ||||||
| Increased depreciation and amortization due to additions to facilities and the in-service of generation projects | (4) | (10) | ||||||
| Increased interest expense due to higher interest rates and higher borrowings to support Tampa Electric’s ongoing capital investment | (11) | (16) | ||||||
| Decreased AFUDC earnings due to the timing of power plant modernization and solar projects | (3) | (6) | ||||||
| Increased income tax expense primarily due to increased income before provision for income taxes | (11) | (36) | ||||||
| Other | (1) | (4) | ||||||
| Contribution to consolidated net income – 2022 |
$ 153 | $ 367 | ||||||
18
Canadian Electric Utilities
| Three months ended | Nine months ended | |||||||||||||||
| For the |
September 30 | September 30 | ||||||||||||||
| millions of dollars (except as indicated) | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Operating revenues – regulated electric |
$ | 370 | $ | 328 | $ | 1,254 | $ | 1,112 | ||||||||
| Regulated fuel for generation and purchased power (1) |
$ | 239 | $ | 169 | $ | 777 | $ | 554 | ||||||||
| Contribution to consolidated adjusted net income |
$ | 39 | $ | 42 | $ | 176 | $ | 174 | ||||||||
| NSPML unrecoverable costs |
$ | - | $ | - | $ | (7) | $ | - | ||||||||
| Contribution to consolidated net income |
$ | 39 | $ | 42 | $ | 169 | $ | 174 | ||||||||
| Electric sales volumes (GWh) |
2,262 | 2,263 | 7,833 | 7,570 | ||||||||||||
| Electric production volumes (GWh) |
2,397 | 2,402 | 8,320 | 8,062 | ||||||||||||
| Average fuel costs per MWh |
$ | 100 | $ | 70 | $ | 93 | $ | 69 | ||||||||
| (1) Regulated fuel for generation and purchased power includes NSPI’s FAM and fixed cost deferrals on the Condensed Consolidated Statements of Income, however it is excluded in the segment overview. |
| |||||||||||||||
Canadian Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the |
September 30 | September 30 | ||||||||||||||
| millions of dollars |
2022 | 2021 | 2022 | 2021 | ||||||||||||
| NSPI |
$ | 20 | $ | 18 | $ | 108 | $ | 98 | ||||||||
| Equity investment in NSPML (1) |
5 | 12 | 28 | 39 | ||||||||||||
| Equity investment in LIL |
14 | 12 | 40 | 37 | ||||||||||||
| Contribution to consolidated adjusted net income |
$ | 39 | $ | 42 | $ | 176 | $ | 174 | ||||||||
| (1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the nine months ended September 30, 2022 (2021 – nil). |
| |||||||||||||||
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of dollars | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2021 |
$ 42 | $ 174 | ||||||
| Increased operating revenues due to increased electric revenues related to recovery of fuel costs from an industrial customer, increased residential and commercial class sales volumes, and increased sales volumes due to weather | 42 | 142 | ||||||
| Increased regulated fuel for generation and purchased power due to increased Nova Scotia Cap-and-Trade program provision, increased commodity prices and higher Maritime Link assessment costs, partially offset by a favourable change in generation mix. Year-to-date also due to increased sales volumes | (70) | (223) | ||||||
| Increased FAM and fixed cost deferrals due to current period under-recovery of fuel costs | 29 | 104 | ||||||
| Increased OM&G year-over-year, primarily due to increased information technology, storm restoration, and power generation expenses | (2) | (27) | ||||||
| Decreased income from equity investment in NSPML primarily due to the Maritime Link holdback | (7) | (11) | ||||||
| Decreased income tax expense primarily due to increased tax deductions in excess of accounting depreciation and amortization related to PP&E and deferrals, and decreased non-deductible pension expense | 6 | 11 | ||||||
| NSPML unrecoverable costs |
- | (7) | ||||||
| Other |
(1) | 6 | ||||||
| Contribution to consolidated net income – 2022 |
$ 39 | $ 169 | ||||||
19
The provision for the Nova Scotia Cap-and-Trade program was $40 million for the three months ended September 30, 2022 (2021 – $nil) and $152 million for the nine months ended September 30, 2022 (2021 – $3 million). For further information on this non-cash accrual, the estimated costs and the FAM regulatory balance, refer to note 6 in the Q3 2022 unaudited condensed consolidated interim financial statements.
Gas Utilities and Infrastructure
All amounts are reported in USD, unless otherwise stated.
| Three months ended | Nine months ended | |||||||||||||
| For the | September 30 | September 30 | ||||||||||||
| millions of USD (except as indicated) |
2022 | 2021 | 2022 | 2021 | ||||||||||
| Operating revenues – regulated gas (1) |
$ | 260 | $ | 189 | $ | 924 | $ 699 | |||||||
| Operating revenues – non-regulated |
4 | 3 | 10 | 10 | ||||||||||
| Total operating revenue |
$ | 264 | $ | 192 | $ | 934 | $ 709 | |||||||
| Regulated cost of natural gas |
$ | 115 | $ | 57 | $ | 433 | $ 236 | |||||||
| Contribution to consolidated net income |
$ | 25 | $ | 22 | $ | 117 | $ 113 | |||||||
| Contribution to consolidated net income (CAD) |
$ | 33 | $ | 29 | $ | 149 | $ 143 | |||||||
| Gas sales volumes (Therms) |
636 | 609 | 2,123 | 2,089 | ||||||||||
(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2021 - $11 million) for the three months ended September 30, 2022 and $34 million (2021 - $34 million) for the nine months ended September 30, 2022.
Gas Utilities and Infrastructure’s contribution is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||
| For the | September 30 | September 30 | ||||||||||||
| millions of USD |
2022 | 2021 | 2022 | 2021 | ||||||||||
| PGS |
$ | 16 | $ | 14 | $ | 65 | $ 60 | |||||||
| NMGC |
(4) | (4) | 13 | 18 | ||||||||||
| Other |
13 | 12 | 39 | 35 | ||||||||||
| Contribution to consolidated net income |
$ | 25 | $ | 22 | $ | 117 | $ 113 | |||||||
The impact of the change in the FX rate increased CAD earnings for the three and nine months ended September 30, 2022 by $1 million and $2 million, respectively.
Highlights of the net income changes are summarized in the following table:
| For the millions of USD |
Three months ended September 30 |
Nine months ended September 30 | ||||
| Contribution to consolidated net income – 2021 |
$ 22 | $ 113 | ||||
| Increased gas revenues due to higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices, and higher off-system sales at PGS. Year-over-year also increased due to customer growth at PGS | 71 | 225 | ||||
| Increased cost of natural gas sold due to higher gas prices at PGS and NMGC, and higher off-system sales at PGS | (58) | (197) | ||||
| Increased OM&G primarily due to higher labour and benefits costs at PGS and NMGC | (9) | (19) | ||||
| Decreased depreciation and amortization expense due to reversal of accumulated depreciation as a result of the rate case settlement at PGS, partially offset by increases due to asset growth at PGS and NMGC | 2 | 8 | ||||
| Increased interest expense due to higher interest rates | (4) | (6) | ||||
| Other |
1 | (7) | ||||
| Contribution to consolidated net income – 2022 |
$ 25 | $ 117 | ||||
20
Other Electric Utilities
All amounts are reported in USD, unless otherwise stated.
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD (except as indicated) | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Operating revenues – regulated electric |
$ | 104 | $ | 96 | $ | 300 | $ | 257 | ||||||||
| Regulated fuel for generation and purchased power |
$ | 58 | $ | 46 | $ | 169 | $ | 123 | ||||||||
| Contribution to consolidated adjusted net income |
$ | 9 | $ | 6 | $ | 16 | $ | 12 | ||||||||
| Contribution to consolidated adjusted net income (CAD) |
$ | 12 | $ | 8 | $ | 21 | $ | 15 | ||||||||
| Equity securities MTM loss |
$ | (1) | $ | - | $ | (5) | $ | (1) | ||||||||
| Contribution to consolidated net income |
$ | 8 | $ | 6 | $ | 11 | $ | 11 | ||||||||
| Contribution to consolidated net income (CAD) |
$ | 10 | $ | 8 | $ | 14 | $ | 14 | ||||||||
| Electric sales volumes (GWh) |
329 | 337 | 938 | 932 | ||||||||||||
| Electric production volumes (GWh) |
352 | 365 | 1,004 | 1,002 | ||||||||||||
Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| GBPC |
$ | 6 | $ | 3 | $ | 9 | $ | 8 | ||||||||
| BLPC |
3 | 3 | 6 | 5 | ||||||||||||
| Other |
- | - | 1 | (1) | ||||||||||||
| Contribution to consolidated adjusted net income |
$ | 9 | $ | 6 | $ | 16 | $ | 12 | ||||||||
The impact of the change in the FX rate on CAD earnings for the three months and nine months ended September 30, 2022 was minimal.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||
| millions of USD | September 30 | September 30 | ||
| Contribution to consolidated net income – 2021 |
$ 6 | $ 11 | ||
| Increased operating revenues – regulated electric due to higher fuel revenue at BLPC as a result of higher fuel prices, partially offset by the sale of Domlec in Q1 2022 | 8 | 43 | ||
| Increased regulated fuel for generation and purchased power as a result of higher fuel prices at BLPC | (12) | (46) | ||
| Decreased OM&G due to the sale of Domlec in Q1 2022 and lower generation costs at GBPC, partially offset by the recognition of Hurricane Dorian insurance proceeds at GBPC in 2021 | 6 | 6 | ||
| Other | - | (3) | ||
| Contribution to consolidated net income – 2022 |
$ 8 | $ 11 |
21
Other
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Marketing and trading margin (1) (2) |
$ | 24 | $ | (4) | $ | 71 | $ | 63 | ||||||||
| Other non-regulated operating revenue |
3 | 8 | 13 | 25 | ||||||||||||
| Total operating revenues – non-regulated |
$ | 27 | $ | 4 | $ | 84 | $ | 88 | ||||||||
| Contribution to consolidated adjusted net income (loss) |
$ | (80) | $ | (73) | $ | (217) | $ | (154) | ||||||||
| MTM loss, after-tax (3) |
(34) | (245) | (125) | (368) | ||||||||||||
| Contribution to consolidated net income (loss) |
$ | (114) | $ | (318) | $ | (342) | $ | (522) | ||||||||
(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 $32 million in Q3 2022 (2021 - $334 million loss) and a loss of $149 million year-to-date (2021 – $501 million loss).
(3) Net of income tax recovery of $14 million for the three months ended September 30, 2022 (2021 - $100 million recovery) and $51 million recovery for the nine months ended September 30, 2022 (2021 - $149 million recovery).
Other’s contribution to consolidated adjusted net income (loss) is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Emera Energy |
$ | 8 | $ | (5) | $ | 29 | $ | 37 | ||||||||
| Corporate – see breakdown of adjusted contribution below |
(84) | (59) | (230) | (174) | ||||||||||||
| Emera Technologies |
(3) | (7) | (13) | (13) | ||||||||||||
| Other |
(1) | (2) | (3) | (4) | ||||||||||||
| Contribution to consolidated adjusted net income (loss) |
$ | (80) | $ | (73) | $ | (217) | $ | (154) | ||||||||
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of dollars | September 30 | September 30 | ||||||
| Contribution to consolidated net income (loss) – 2021 |
$ | (318) | $ | (522) | ||||
| Increased marketing and trading margin due to higher natural gas prices and volatility, which created profitable opportunities for Emera Energy. Year-over-year increase was offset by the positive margin impact of Winter Storm Uri in Q1 2021 | 28 | 8 | ||||||
| Increased OM&G, pre-tax, primarily due to the timing of long-term compensation and related hedges | (17) | (36) | ||||||
| Increased interest expense, pre-tax, due to increased interest rates and increased total debt | (10) | (10) | ||||||
| Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX hedges entered into to hedge USD denominated operating unit earnings exposure | (6) | (19) | ||||||
| Increased income tax recovery primarily due to increased losses before provision for income taxes | 3 | 20 | ||||||
| Increased preferred stock dividends due to issuance of preferred shares in 2021 | (2) | (11) | ||||||
| Decreased MTM loss, after tax, quarter-over-quarter, primarily due to changes in existing positions, partially offset by higher amortization of gas transportation assets in 2022 and larger reversal of MTM losses in 2021 at Emera Energy. Decreased MTM loss, after tax, year-over-year primarily due to larger reversal of MTM losses in 2022 and changes in existing positions, partially offset by higher amortization of gas transportation assets in 2022 at Emera Energy | 211 | 243 | ||||||
| Other |
(3) | (15) | ||||||
| Contribution to consolidated net income (loss) – 2022 |
$ | (114) | $ | (342) | ||||
22
Corporate
Corporate’s adjusted loss is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Operating expenses (1) |
$ | 27 | $ | 10 | $ | 63 | $ | 27 | ||||||||
| Interest expense |
75 | 65 | 208 | 199 | ||||||||||||
| Income tax recovery |
(29) | (18) | (74) | (57) | ||||||||||||
| Preferred dividends |
16 | 14 | 47 | 36 | ||||||||||||
| Other (2) |
(5) | (12) | (14) | (31) | ||||||||||||
| Corporate adjusted net loss |
$ | (84) | $ | (59) | $ | (230) | $ | (174) | ||||||||
(1) Operating expenses include OM&G and depreciation. In 2021, OM&G and depreciation were offset by changes in long-term compensation. The value of long-term compensation and related hedges are impacted by the changes in Emera’s period end share price.
(2) 2021 includes $4 million quarter-to-date and $13 million year-to-date of realized gains on FX cash flow hedges to hedge FX earnings exposure. A loss of $1 million was recognized year-to-date in 2022.
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.
For information on COVID-19 and its potential future impacts on Emera’s liquidity and capital resources, refer to the “Business Overview and Outlook” and “Liquidity and Capital Resources” sections in Emera’s 2021 annual MD&A.
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 (including a $240 million equity investment in the LIL in 2023). 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 dividend reinvestment plan and ATM program.
Emera has credit facilities with varying maturities that cumulatively provide $4.6 billion of credit, with approximately $1.4 billion undrawn and available at September 30, 2022. The Company was holding a cash balance of $549 million at September 30, 2022. 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 unaudited condensed consolidated interim financial statements.
23
Consolidated Cash Flow Highlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the nine months ended September 30, 2022 and 2021 include:
| millions of dollars | 2022 | 2021 | Change | |||||||
| Cash, cash equivalents, and restricted cash, beginning of period |
$ | 417 | $ | 254 | $ 163 | |||||
| Provided by (used in): |
||||||||||
| Operating cash flow before change in working capital |
806 | 1,035 | (229) | |||||||
| Change in working capital |
149 | 71 | 78 | |||||||
| Operating activities |
$ | 955 | $ | 1,106 | $ (151) | |||||
| Investing activities |
(1,685) | (1,576) | (109) | |||||||
| Financing activities |
844 | 693 | 151 | |||||||
| Effect of exchange rate changes on cash, cash equivalents, and restricted cash |
18 | (1) | 19 | |||||||
| Cash, cash equivalents, and restricted cash, end of period |
$ | 549 | $ | 476 | $ 73 | |||||
Cash Flow from Operating Activities
Net cash provided by operating activities decreased $151 million to $955 million for the nine months ended September 30, 2022, compared to $1,106 million for the same period in 2021.
Cash from operations before changes in working capital decreased $229 million. This decrease was due to under-recovery of clause-related costs primarily due to higher natural gas prices at Tampa Electric, unfavourable changes in Tampa Electric’s storm reserve balance as a result of Hurricane Ian, and increased fuel for generation and purchased power at NSPI. This was partially offset by the 2021 deferral of gas costs at NMGC resulting from the extreme cold weather event, and increased revenues at Tampa Electric and NSPI.
Changes in working capital increased operating cash flows by $78 million year-over-year. This increase was due to favourable changes in accounts payable at Tampa Electric and NSPI, and favourable changes in cash collateral positions at Emera Energy. This was partially offset by unfavourable changes in accounts receivable at Tampa Electric, NSPI and GBPC, unfavourable changes in cash collateral positions on derivative instruments at NSPI, and the required prepayment of income taxes and related interest at NSPI.
Cash Flow from Investing Activities
Net cash used in investing activities increased $109 million to $1,685 million for the nine months ended September 30, 2022, compared to $1,576 million for the same period in 2021. The increase was due to higher capital investment in 2022.
Capital investments, including AFUDC, for the nine months ended September 30, 2022, were $1,742 million compared to $1,640 million for the same period in 2021. Details of the 2022 capital investment by segment are shown below:
| • | $980 million – Florida Electric Utility (2021 – $927 million); |
| • | $311 million – Canadian Electric Utilities (2021 – $248 million); |
| • | $405 million – Gas Utilities and Infrastructure (2021 – $378 million); |
| • | $43 million – Other Electric Utilities (2021 – $85 million); and |
| • | $3 million – Other (2021 – $2 million). |
24
Cash Flow from Financing Activities
Net cash provided by financing activities increased $151 million to $844 million for the nine months ended September 30, 2022, compared to $693 million for the same period in 2021. This increase was due to the retirement of long-term debt at NMGC in 2021, repayment of short-term debt at Tampa Electric and PGS in 2021, and increased proceeds from short-term debt at Emera and Tampa Electric in 2022. This was partially offset by lower issuances of long-term debt at NMGC, PGS and Tampa Electric, and the issuance of preferred shares in 2021.
Contractual Obligations
As at September 30, 2022, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | Total | |||||||||||||||||||||
| Long-term debt principal |
$ | 9 | 596 | 1,606 | 511 | 3,185 | 10,079 | $ | 15,986 | |||||||||||||||||||
| Interest payment obligations (1) |
269 | 695 | 674 | 625 | 532 | 7,497 | 10,292 | |||||||||||||||||||||
| Transportation (2) |
183 | 616 | 475 | 396 | 364 | 2,917 | 4,951 | |||||||||||||||||||||
| Purchased power (3) |
77 | 268 | 247 | 242 | 232 | 2,394 | 3,460 | |||||||||||||||||||||
| Fuel, gas supply and storage |
487 | 991 | 305 | 170 | 37 | - | 1,990 | |||||||||||||||||||||
| Capital projects |
399 | 253 | 88 | 4 | 1 | - | 745 | |||||||||||||||||||||
| Asset retirement obligations |
7 | 7 | 2 | 2 | 1 | 415 | 434 | |||||||||||||||||||||
| Pension and post-retirement obligations (4) |
8 | 40 | 35 | 34 | 34 | 173 | 324 | |||||||||||||||||||||
| Equity investment commitments (5) |
- | 240 | - | - | - | - | 240 | |||||||||||||||||||||
| Other |
46 | 86 | 81 | 60 | 44 | 223 | 540 | |||||||||||||||||||||
| $ | 1,485 | $ | 3,792 | $ | 3,513 | $ | 2,044 | $ | 4,430 | $ | 23,698 | $ | 38,962 | |||||||||||||||
(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 September 30, 2022, 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 $147 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 upon its commissioning.
NSPI has a contractual obligation to pay NSPML for the 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 and the approval to collect $168 million from NSPI for the recovery of Maritime Link costs in 2022. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.
Once LIL has been commissioned, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties relating to the Maritime Link and LIL.
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, the date the NS Block delivery obligation commenced, and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
25
Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2021 annual MD&A, with material updates as noted below:
The Company has standby letters of credit and surety bonds in the amount of $125 million USD (December 31, 2021 - $148 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually, as required.
Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will automatically terminate on the date upon which the obligations have been repaid in full.
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm service agreement, which expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.
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.
| millions of dollars | Maturity | Credit Facilities |
Utilized | Undrawn and Available |
||||||||||||
| Emera – Unsecured committed revolving credit facility |
June 2026 | $ | 900 | $ | 583 | $ | 317 | |||||||||
| TEC (in USD) – Unsecured committed revolving credit facility (1) |
December 2026 | 800 | 351 | 449 | ||||||||||||
| NSPI – Unsecured committed revolving credit facility |
December 2026 | 600 | 120 | 480 | ||||||||||||
| TEC (in USD) – Unsecured non-revolving facility (2) |
December 2022 | 500 | 500 | - | ||||||||||||
| Emera – Unsecured non-revolving facility |
December 2022 | 400 | 400 | - | ||||||||||||
| TECO Finance (in USD) – Unsecured committed revolving credit facility |
December 2026 | 400 | 348 | 52 | ||||||||||||
| NSPI – Unsecured non-revolving facility |
July 2024 | 400 | 400 | - | ||||||||||||
| Emera – Unsecured non-revolving facility |
August 2023 | 400 | 400 | - | ||||||||||||
| NMGC (in USD) – Unsecured revolving credit facility |
December 2026 | 125 | 39 | 86 | ||||||||||||
| NMGC (in USD) – Unsecured non-revolving facility |
March 2024 | 80 | 80 | - | ||||||||||||
| Other (in USD) – Unsecured committed revolving credit facilities |
Various | 21 | 11 | 10 | ||||||||||||
(1) This facility is available for use by Tampa Electric and PGS. At September 30, 2022, $295 million USD was used by Tampa Electric and $56 million USD was used by PGS.
(2) This facility is available for use by Tampa Electric and PGS. At September 30, 2022, $400 million USD was used by Tampa Electric and $100 million USD was used by PGS.
Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at September 30, 2022.
26
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using existing credit facilities.
On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included $300 million USD senior notes that bear an interest rate of 3.875 per cent with a maturity date of July 12, 2024, and $300 million USD senior notes that bear an interest rate of 5 per cent with a maturity date of July 15, 2052. Proceeds from the issuance were used to repay TEC’s $470 million USD commercial paper, due in 2022, and for general corporate purposes.
Canadian Electric Utilities
On July 15, 2022, NSPI entered into a $400 million non-revolving term facility which matures on July 15, 2024. The credit agreement contains customary representation and warranties, events of default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin. Proceeds from this issuance were used for general corporate purposes.
Gas Utilities and Infrastructure
On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving credit facility to extend the maturity from September 23, 2022, to March 22, 2024. There were no other significant changes in commercial terms from the prior agreement.
On June 30, 2022, Brunswick Pipeline amended its credit agreement to extend the maturity from June 30, 2025 to June 30, 2026. There were no other changes in commercial terms from the prior agreement.
Other Electric Utilities
On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25, 2022 to March 25, 2027. There were no other changes in commercial terms from the prior agreement.
Other
On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on August 2, 2023. The credit agreement contains customary representation and warranties, events of default and financial and other covenants and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin. Proceeds from this issuance were used for general corporate purposes.
Credit Ratings
On November 2, 2022, Moody’s Investor Services (“Moody’s”) affirmed its Baa3 issuer rating for Emera Inc. Moody’s also affirmed ratings on TECO Finance and TEC, affirming the TECO Finance Baa1 issuer rating and A3 issuer rating for TEC. Emera and subsidiaries’ outlook was changed to negative from stable.
On October 24, 2022, S&P Global Ratings (“S&P”) affirmed its BBB issuer rating for Emera Inc. S&P also affirmed ratings on NSPI, TECO Energy, and TEC affirming the BBB+ issuer credit ratings for NSPI and TEC. Emera and subsidiaries’ outlook was changed to negative from stable.
On June 2, 2022, Moody’s affirmed its Baa1 issuer rating for TECO Finance. Moody’s also affirmed TEC’s A3 issuer rating and changed the outlook to stable from positive.
27
| Outstanding Stock Data
Common Stock |
| |||||||
| Issued and outstanding: | millions of shares |
millions of dollars |
||||||
| Balance, December 31, 2021 |
261.07 | $ | 7,242 | |||||
| Issuance of common stock under ATM program (1) |
3.79 | 233 | ||||||
| Issued under the Dividend Reinvestment Program, net of discounts |
2.86 | 171 | ||||||
| Senior management stock options exercised and Employee Share Purchase Plan |
0.51 | 29 | ||||||
| Balance, September 30, 2022 |
268.23 | $ | 7,675 | |||||
(1) In Q3 2022, 1,715,056 common shares were issued under Emera’s ATM program at an average price of $61.87 per share for gross proceeds of $106 million ($105 million net of after-tax issuance costs). For the nine months ended September 30, 2022, 3,793,924 common shares were issued under Emera’s ATM program at an average price of $61.85 per share for gross proceeds of $235 million ($233 million net of after-tax issuance costs). As at September 30, 2022, an aggregate gross sales limit of $222 million remained available for issuance under the ATM program.
As at November 8, 2022, the amount of issued and outstanding common shares was 268.3 million.
If all outstanding stock options were converted as at November 8, 2022, an additional 2.9 million common shares would be issued and outstanding.
Preferred Stock
As at November 8, 2022, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
TRANSACTIONS WITH RELATED PARTIES
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities, in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.
Significant transactions between Emera and its associated companies are as follows:
| • | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $41 million for the three months ended September 30, 2022 (2021 - $27 million) and $118 million for the nine months ended September 30, 2022 (2021 - $91 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 $1 million for the three months ended September 30, 2022 (2021 - $4 million) and $7 million for the nine months ended September 30, 2022 (2021 - $14 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at September 30, 2022 and at December 31, 2021.
28
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 2021 annual MD&A, except for the following additional disclosure under “Regulatory and Political Risk”:
On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. This government intervention in the regulatory process has resulted in an increase in political risk and a reduction in the stability and predictability of NSPI’s regulatory environment. This legislation sets an unfavourable precedent and significantly increases the risk associated with NSPI’s current and future ability to recover prudently incurred costs including capital investments and regulatory assets.
Derivatives Assets and Liabilities Recognized on the Balance Sheet
| As at | September 30 | December 31 | ||||||
| millions of dollars | 2022 | 2021 | ||||||
| Regulatory Deferral: |
||||||||
| Derivative instrument assets (1) |
$ | 447 | $ | 237 | ||||
| Derivative instrument liabilities (2) |
(32) | (20) | ||||||
| Regulatory assets (1) |
61 | 23 | ||||||
| Regulatory liabilities (2) |
(448) | (241) | ||||||
| Net asset (liability) |
$ | 28 | $ | (1) | ||||
| HFT Derivatives: |
||||||||
| Derivative instrument assets (1) |
$ | 245 | $ | 53 | ||||
| Derivatives instruments liabilities (2) |
(1,724) | (662) | ||||||
| Net liability |
$ | (1,479) | $ | (609) | ||||
| Other Derivatives: |
||||||||
| Derivative instrument assets (1) |
$ | 5 | $ | 11 | ||||
| Derivatives instruments liabilities (2) |
(45) | - | ||||||
| Net asset (liability) |
$ | (40) | $ | 11 | ||||
(1) Current and other assets.
(2) Current and long-term liabilities.
29
Realized and Unrealized Gains (Losses) Recognized in Net Income
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Regulatory Deferral: |
||||||||||||||||
| Regulated fuel for generation and purchased power (1) |
$ | 51 | $ | 13 | $ | 142 | $ | 9 | ||||||||
| HFT Derivatives: |
||||||||||||||||
| Non-regulated operating revenues |
$ | (567) | $ | (235) | $ | (635) | $ | (226) | ||||||||
| Non-regulated fuel for generation and purchased power |
- | - | - | 1 | ||||||||||||
| Net losses |
$ | (567) | $ | (235) | $ | (635) | $ | (225) | ||||||||
| Other Derivatives: |
||||||||||||||||
| OM&G |
$ | (12) | $ | 3 | $ | (21) | $ | 9 | ||||||||
| Other income, net |
(32) | (1) | (31) | 2 | ||||||||||||
| Net gains (losses) |
$ | (44) | $ | 2 | $ | (52) | $ | 11 | ||||||||
| Total net losses |
$ | (560) | $ | (220) | $ | (545) | $ | (205) | ||||||||
(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.
As of September 30, 2022, the unrealized gain in Accumulated other comprehensive income was $16 million, net of tax (2021 - $18 million, net of tax). For the three and nine months ended September 30, 2022, unrealized gains of $1 million (2021 - $1 million) and $2 million (2021 - $1 million), respectively, have been reclassified into interest expense. As of September 30, 2022, there were no outstanding cash flow hedges.
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 September 30, 2022, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.
There were no changes in the Company’s ICFR during the quarter ended September 30, 2022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
30
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 the 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 2021 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.
SUMMARY OF QUARTERLY RESULTS
| For the quarter ended millions of dollars |
Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||||||||
| (except per share amounts) | 2022 | 2022 | 2022 | 2021 | 2021 | 2021 | 2021 | 2020 | ||||||||||||||||||||||
| Operating revenues |
$ | 1,835 | $ | 1,380 | $ | 2,015 | $ | 1,868 | $ | 1,148 | $ | 1,137 | $ | 1,612 | $ 1,537 | |||||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 167 | $ | (67) | $ | 362 | $ | 324 | $ | (70) | $ | (17) | $ | 273 | $ 273 | |||||||||||||||
| Adjusted net income |
$ | 203 | $ | 156 | $ | 242 | $ | 168 | $ | 175 | $ | 137 | $ | 243 | $ 188 | |||||||||||||||
| Earnings (loss) per common share – basic |
$ | 0.63 | $ | (0.25) | $ | 1.38 | $ | 1.24 | $ | (0.27) | $ | (0.07) | $ | 1.08 | $ 1.09 | |||||||||||||||
| Earnings (loss) per common share – diluted |
$ | 0.63 | $ | (0.25) | $ | 1.38 | $ | 1.20 | $ | (0.27) | $ | (0.07) | $ | 1.08 | $ 1.08 | |||||||||||||||
| Adjusted earnings per common share – basic |
$ | 0.76 | $ | 0.59 | $ | 0.92 | $ | 0.64 | $ | 0.68 | $ | 0.54 | $ | 0.96 | $ 0.75 | |||||||||||||||
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.
31
Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
September 30, 2022 and 2021
1
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars (except per share amounts) | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Operating revenues |
||||||||||||||||
| Regulated electric |
$ | 1,489 | $ | 1,244 | $ | 4,111 | $ | 3,445 | ||||||||
| Regulated gas |
338 | 237 | 1,179 | 874 | ||||||||||||
| Non-regulated |
8 | (333) | (60) | (422) | ||||||||||||
| Total operating revenues (note 5) |
1,835 | 1,148 | 5,230 | 3,897 | ||||||||||||
| Operating expenses |
||||||||||||||||
| Regulated fuel for generation and purchased power |
612 | 476 | 1,630 | 1,263 | ||||||||||||
| Regulated cost of natural gas |
149 | 71 | 554 | 297 | ||||||||||||
| Operating, maintenance and general expenses (“OM&G”) |
399 | 341 | 1,164 | 1,002 | ||||||||||||
| Provincial, state and municipal taxes |
98 | 85 | 275 | 246 | ||||||||||||
| Depreciation and amortization |
238 | 228 | 698 | 675 | ||||||||||||
| Total operating expenses |
1,496 | 1,201 | 4,321 | 3,483 | ||||||||||||
| Income (loss) from operations |
339 | (53) | 909 | 414 | ||||||||||||
| Income from equity investments (note 7) |
32 | 33 | 92 | 111 | ||||||||||||
| Other income (expense), net |
(1) | 22 | 43 | 67 | ||||||||||||
| Interest expense, net |
184 | 150 | 503 | 460 | ||||||||||||
| Income (loss) before provision for income taxes |
186 | (148) | 541 | 132 | ||||||||||||
| Income tax expense (recovery) (note 8) |
2 | (92) | 31 | (91) | ||||||||||||
| Net income (loss) |
184 | (56) | 510 | 223 | ||||||||||||
| Non-controlling interest in subsidiaries |
1 | - | 1 | 1 | ||||||||||||
| Preferred stock dividends |
16 | 14 | 47 | 36 | ||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 167 | $ | (70) | $ | 462 | $ | 186 | ||||||||
| Weighted average shares of common stock outstanding (in millions) (note 10) |
||||||||||||||||
| Basic |
266.6 | 258.5 | 264.3 | 256.0 | ||||||||||||
| Diluted |
267.0 | 258.5 | 264.8 | 256.4 | ||||||||||||
| Earnings (loss) per common share (note 10) |
||||||||||||||||
| Basic |
$ | 0.63 | $ | (0.27) | $ | 1.75 | $ | 0.73 | ||||||||
| Diluted |
$ | 0.63 | $ | (0.27) | $ | 1.74 | $ | 0.73 | ||||||||
| Dividends per common share declared |
$ | 0.6625 | $ | 0.6375 | $ | 1.9875 | $ | 1.9125 | ||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
2
Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Net income (loss) |
$ | 184 | $ | (56) | $ | 510 | $ | 223 | ||||||||
| Other comprehensive income (loss), net of tax |
||||||||||||||||
| Foreign currency translation adjustment (1) |
616 | 243 | 763 | (1) | ||||||||||||
| Unrealized losses on net investment hedges (2) (3) |
(95) | (35) | (116) | (1) | ||||||||||||
| Cash flow hedges |
||||||||||||||||
| Net derivative gains (4) |
- | - | - | 18 | ||||||||||||
| Less: reclassification adjustment for gains included in income |
(1) | (1) | (2) | (1) | ||||||||||||
| Net effects of cash flow hedges |
(1) | (1) | (2) | 17 | ||||||||||||
| Unrealized losses on available-for-sale investment |
(1) | - | (1) | - | ||||||||||||
| Net change in unrecognized pension and post-retirement benefit obligation |
2 | 4 | (6) | 13 | ||||||||||||
| Other comprehensive income (5) |
521 | 211 | 638 | 28 | ||||||||||||
| Comprehensive income |
705 | 155 | 1,148 | 251 | ||||||||||||
| Comprehensive income attributable to non-controlling interest |
1 | - | 1 | 1 | ||||||||||||
| Comprehensive income of Emera Incorporated |
$ | 704 | $ | 155 | $ | 1,147 | $ | 250 | ||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Net of tax expense of $10 million (2021 - nil) for the three months ended September 30, 2022 and tax expense of $10 million (2021 – $5 million expense) for the nine months ended September 30, 2022.
(2) The Company has designated $1.2 billion United States dollar (“USD”) denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. “
(3) Net of tax recovery of $2 million (2021 - $6 million recovery) for the three months ended September 30, 2022 and tax recovery of $6 million (2021 – nil) for the nine months ended September 30, 2022.
(4) Net of tax expense of nil (2021 - nil) for the three months ended September 30, 2022 and tax expense of nil (2021 – $6 million expense) for the nine months ended September 30, 2022.
(5) Net of tax expense of $8 million (2021 - $6 million recovery) for the three months ended September 30, 2022 and tax expense of $4 million (2021 – $11 million expense) for the nine months ended September 30, 2022.
3
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at | September 30 | December 31 | ||||||
| millions of dollars | 2022 | 2021 | ||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 526 | $ | 394 | ||||
| Restricted cash (note 22) |
23 | 23 | ||||||
| Inventory |
722 | 538 | ||||||
| Derivative instruments (notes 12 and 13) |
554 | 195 | ||||||
| Regulatory assets (note 6) |
846 | 253 | ||||||
| Receivables and other current assets (note 15) |
2,679 | 1,733 | ||||||
| 5,350 | 3,136 | |||||||
| Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $9,548 and $8,739, respectively | 22,555 | 20,353 | ||||||
| Other assets |
||||||||
| Deferred income taxes (note 8) |
361 | 295 | ||||||
| Derivative instruments (notes 12 and 13) |
143 | 106 | ||||||
| Regulatory assets (note 6) |
2,585 | 2,313 | ||||||
| Net investment in direct finance and sales type leases (note 16) |
604 | 503 | ||||||
| Investments subject to significant influence (note 7) |
1,418 | 1,382 | ||||||
| Goodwill |
6,158 | 5,696 | ||||||
| Other long-term assets |
630 | 460 | ||||||
| 11,899 | 10,755 | |||||||
| Total assets |
$ | 39,804 | $ | 34,244 | ||||
| Liabilities and Equity |
||||||||
| Current liabilities |
||||||||
| Short-term debt (note 18) |
$ | 2,514 | $ | 1,742 | ||||
| Current portion of long-term debt (note 19) |
575 | 462 | ||||||
| Accounts payable |
2,071 | 1,485 | ||||||
| Derivative instruments (notes 12 and 13) |
1,545 | 533 | ||||||
| Regulatory liabilities (note 6) |
488 | 290 | ||||||
| Other current liabilities |
497 | 366 | ||||||
| 7,690 | 4,878 | |||||||
| Long-term liabilities |
||||||||
| Long-term debt (note 19) |
15,285 | 14,196 | ||||||
| Deferred income taxes (note 8) |
2,054 | 1,868 | ||||||
| Derivative instruments (notes 12 and 13) |
256 | 149 | ||||||
| Regulatory liabilities (note 6) |
1,884 | 1,765 | ||||||
| Pension and post-retirement liabilities (note 17) |
367 | 370 | ||||||
| Other long-term liabilities (note 7) |
1,129 | 868 | ||||||
| 20,975 | 19,216 | |||||||
| Equity |
||||||||
| Common stock (note 9) |
7,675 | 7,242 | ||||||
| Cumulative preferred stock |
1,422 | 1,422 | ||||||
| Contributed surplus |
80 | 79 | ||||||
| Accumulated other comprehensive income (“AOCI’) (note 11) |
663 | 25 | ||||||
| Retained earnings |
1,285 | 1,348 | ||||||
| Total Emera Incorporated equity |
11,125 | 10,116 | ||||||
| Non-controlling interest in subsidiaries |
14 | 34 | ||||||
| Total equity |
11,139 | 10,150 | ||||||
| Total liabilities and equity |
$ | 39,804 | $ | 34,244 | ||||
| Commitments and contingencies (note 20) | Approved on behalf of the Board of Directors | |||
|
The accompanying notes are an integral part of these condensed consolidated interim financial statements. |
“M. Jacqueline Sheppard” | “Scott Balfour” | ||
|
Chair of the Board |
President and Chief Executive Officer | |||
4
Emera Incorporated
Condensed Consolidated Statements of Cash Flows (Unaudited)
| For the | Nine months ended September 30 | |||||||
| millions of dollars | 2022 | 2021 | ||||||
| Operating activities |
||||||||
| Net income |
$ | 510 | $ | 223 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
703 | 682 | ||||||
| Income from equity investments, net of dividends |
(43) | (56) | ||||||
| Allowance for equity funds used during construction |
(37) | (44) | ||||||
| Deferred income taxes, net |
7 | (111) | ||||||
| Net change in pension and post-retirement liabilities |
(40) | (25) | ||||||
| Regulated fuel adjustment mechanism |
(185) | (71) | ||||||
| Net change in fair value of derivative instruments |
804 | 416 | ||||||
| Net change in regulatory assets and liabilities |
(471) | (124) | ||||||
| Net change in capitalized transportation capacity |
(620) | 96 | ||||||
| Other operating activities, net |
178 | 49 | ||||||
| Changes in non-cash working capital (note 21) |
149 | 71 | ||||||
| Net cash provided by operating activities |
955 | 1,106 | ||||||
| Investing activities |
||||||||
| Additions to PP&E |
(1,704) | (1,596) | ||||||
| Other investing activities |
19 | 20 | ||||||
| Net cash used in investing activities |
(1,685) | (1,576) | ||||||
| Financing activities |
||||||||
| Change in short-term debt, net |
661 | 88 | ||||||
| Repayment of short-term debt with maturities greater than 90 days |
- | (377) | ||||||
| Proceeds from long-term debt, net of issuance costs |
772 | 2,329 | ||||||
| Retirement of long-term debt |
(359) | (1,541) | ||||||
| Net repayments under committed credit facilities |
(82) | (87) | ||||||
| Issuance of common stock, net of issuance costs |
256 | 236 | ||||||
| Issuance of preferred stock, net of issuance costs |
- | 416 | ||||||
| Dividends on common stock |
(352) | (329) | ||||||
| Dividends on preferred stock |
(47) | (36) | ||||||
| Other financing activities |
(5) | (6) | ||||||
| Net cash provided by financing activities |
844 | 693 | ||||||
| Effect of exchange rate changes on cash, cash equivalents and restricted cash |
18 | (1) | ||||||
| Net increase in cash, cash equivalents, and restricted cash |
132 | 222 | ||||||
| Cash, cash equivalents and restricted cash, beginning of period |
417 | 254 | ||||||
| Cash, cash equivalents and restricted cash, end of period |
$ | 549 | $ | 476 | ||||
| Cash, cash equivalents, and restricted cash consists of: |
||||||||
| Cash |
$ | 360 | $ | 198 | ||||
| Short-term investments |
166 | 242 | ||||||
| Restricted cash |
23 | 36 | ||||||
| Cash, cash equivalents and restricted cash |
$ | 549 | $ | 476 | ||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
5
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 September 30, 2022 |
| |||||||||||||||||||||||||||
| Balance, June 30, 2022 | $ | 7,509 | $ | 1,422 | $ | 80 | $ | 142 | $ | 1,295 | $ | 14 | $ | 10,462 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 183 | 1 | 184 | |||||||||||||||||||||
| Other comprehensive income, net of tax expense of $8 million | - | - | - | 521 | - | - | 521 | |||||||||||||||||||||
| Dividends declared on preferred stock (1) | - | - | - | - | (16) | - | (16) | |||||||||||||||||||||
| Dividends declared on common stock ($0.6625/share) | - | - | - | - | (176) | - | (176) | |||||||||||||||||||||
| Issued under the Dividend Reinvestment Program, net of discounts | 54 | - | - | - | - | - | 54 | |||||||||||||||||||||
| Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs | 105 | - | - | - | - | - | 105 | |||||||||||||||||||||
| Senior management stock options exercised and Employee Share Purchase Plan | 7 | - | - | - | - | - | 7 | |||||||||||||||||||||
| Other | - | - | - | - | (1) | (1) | (2) | |||||||||||||||||||||
| Balance, September 30, 2022 |
$ | 7,675 | $ | 1,422 | $ | 80 | $ | 663 | $ | 1,285 | $ | 14 | $ | 11,139 | ||||||||||||||
| For the nine months ended September 30, 2022 |
| |||||||||||||||||||||||||||
| Balance, December 31, 2021 | $ | 7,242 | $ | 1,422 | $ | 79 | $ | 25 | $ | 1,348 | $ | 34 | $ | 10,150 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 509 | 1 | 510 | |||||||||||||||||||||
| Other comprehensive income, net of tax expense of $4 million | - | - | - | 638 | - | - | 638 | |||||||||||||||||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (47) | - | (47) | |||||||||||||||||||||
| Dividends declared on common stock ($1.9875/share) | - | - | - | - | (524) | - | (524) | |||||||||||||||||||||
| Disposal of non-controlling interest of Dominica Electricity Services Ltd (“Domlec”) | - | - | - | - | - | (20) | (20) | |||||||||||||||||||||
| Issued under the Dividend Reinvestment Program, net of discounts | 171 | - | - | - | - | - | 171 | |||||||||||||||||||||
| Issuance of common stock under ATM program, net of after-tax issuance costs | 233 | - | - | - | - | - | 233 | |||||||||||||||||||||
| Senior management stock options exercised and Employee Share Purchase Plan | 29 | - | 1 | - | - | - | 30 | |||||||||||||||||||||
| Other | - | - | - | - | (1) | (1) | (2) | |||||||||||||||||||||
| Balance, September 30, 2022 |
$ | 7,675 | $ | 1,422 | $ | 80 | $ | 663 | $ | 1,285 | $ | 14 | $ | 11,139 | ||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Series A; $0.1364/share, Series B; $0.1803/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; $0.4092/share, Series B; $0.4326/share, Series C; $0.88518/share, Series E; $0.84375/share, Series F; $0.78789/share; Series H; $0.91875/share; Series J; $0.79688/share and Series L; $0.86250/share
6
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 September 30, 2021 |
| |||||||||||||||||||||||||||
| Balance, June 30, 2021 | $ | 6,957 | $ | 1,200 | $ | 79 | $ | (262) | $ | 1,431 | $ | 34 | $ | 9,439 | ||||||||||||||
| Net loss of Emera Incorporated | - | - | - | - | (56) | - | (56) | |||||||||||||||||||||
| Other comprehensive income, net of tax recovery of $6 million | - | - | - | 211 | - | - | 211 | |||||||||||||||||||||
| Dividends declared on preferred stock (1) | - | - | - | - | (14) | - | (14) | |||||||||||||||||||||
| Dividends declared on common stock ($0.6375/share) | - | - | - | - | (164) | - | (164) | |||||||||||||||||||||
| Issuance of preferred stock, net of after-tax issuance costs | - | 222 | - | - | - | - | 222 | |||||||||||||||||||||
| Issued under the Dividend Reinvestment Program, net of discounts | 55 | - | - | - | - | - | 55 | |||||||||||||||||||||
| Issuance of common stock under ATM program, net of after-tax issuance costs | 83 | - | - | - | - | - | 83 | |||||||||||||||||||||
| Senior management stock options exercised and Employee Share Purchas Plan | 8 | - | - | - | - | - | 8 | |||||||||||||||||||||
| Other | - | - | - | - | - | - | - | |||||||||||||||||||||
| Balance, September 30, 2021 | $ | 7,103 | $ | 1,422 | $ | 79 | $ | (51) | $ | 1,197 | $ | 34 | $ | 9,784 | ||||||||||||||
| For the nine months ended September 30, 2021 |
| |||||||||||||||||||||||||||
| Balance, December 31, 2020 |
$ | 6,705 | $ | 1,004 | $ | 79 | $ | (79) | $ | 1,495 | $ | 34 | $ | 9,238 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 222 | 1 | 223 | |||||||||||||||||||||
| Other comprehensive income, net of tax expense of $11 million | - | - | - | 28 | - | - | 28 | |||||||||||||||||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (36) | - | (36) | |||||||||||||||||||||
| Dividends declared on common stock ($1.9125/share) | - | - | - | - | (486) | - | (486) | |||||||||||||||||||||
| Issuance of preferred stock, net of after-tax issuance costs | - | 418 | - | - | - | - | 418 | |||||||||||||||||||||
| Issued under the Dividend Reinvestment Program, net of discounts | 174 | - | - | - | - | - | 174 | |||||||||||||||||||||
| Issuance of common stock under ATM program, net of after-tax issuance costs | 211 | - | - | - | - | - | 211 | |||||||||||||||||||||
| Senior management stock option exercised and Employee Share Purchase Plan | 10 | - | - | - | - | - | 10 | |||||||||||||||||||||
| Other |
3 | - | - | - | 2 | (1) | 4 | |||||||||||||||||||||
| Balance, September 30, 2021 |
$ | 7,103 | $ | 1,422 | $ | 79 | $ | (51) | $ | 1,197 | $ | 34 | $ | 9,784 | ||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Series A; $0.1364/share, Series B; $0.1222/share, Series C; $0.29506/share, Series E; $0.28125/share, Series F; $0.26263/share; Series H; $0.30625/share and Series J; $0.38134/share
(2) Series A; $0.4092/share, Series B; $0.3613/share, Series C; $0.88518/share, Series E; $0.84375/share, Series F; $0.78789/share; Series H; $0.91875/share and Series J; $0.38134/share
7
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at September 30, 2022 and 2021
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 September 30, 2022, Emera’s reportable segments include the following:
| • | Florida Electric Utility, which consists of Tampa Electric, 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 (including AFUDC) transmission project; and |
| • | a 34.7 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 System (“PGS”), a regulated gas distribution utility operating across Florida; |
| • | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico; |
| • | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada, 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. |
8
| • | 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 Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates; |
| • | Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera; |
| • | 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. |
The outbreak of COVID-19 in 2020 resulted in governments worldwide enacting emergency measures to combat the spread of the virus. Management considered the impact of COVID-19 on the Company’s estimates and results, and concluded the unaudited condensed consolidated interim financial statements as at and for the three and nine months ended September 30, 2022, were not materially impacted.
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, 2021.
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, 2022.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
Use of Management Estimates
The preparation of unaudited condensed consolidated interim financial statements 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 the 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 2021 annual audited consolidated financial statements.
9
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.
10
4. SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker.
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Gas Utilities and Infrastructure |
Other Electric Utilities |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||
| For the three months ended September 30, 2022 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 982 | $ | 370 | $ | 343 | $ | 136 | $ | 4 | $ | - | $ | 1,835 | ||||||||||||||
| Inter-segment revenues (1) | 2 | - | 1 | - | (9) | 6 | - | |||||||||||||||||||||
| Total operating revenues |
984 | 370 | 344 | 136 | (5) | 6 | 1,835 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power | 353 | 185 | - | 75 | - | (1) | 612 | |||||||||||||||||||||
| Regulated cost of natural gas | - | - | 149 | - | - | - | 149 | |||||||||||||||||||||
| OM&G | 161 | 74 | 94 | 31 | 40 | (1) | 399 | |||||||||||||||||||||
| Provincial, state and municipal taxes | 67 | 11 | 19 | - | 1 | - | 98 | |||||||||||||||||||||
| Depreciation and amortization | 129 | 65 | 28 | 14 | 2 | - | 238 | |||||||||||||||||||||
| Income from equity investments | - | 20 | 6 | 1 | 5 | - | 32 | |||||||||||||||||||||
| Other income (expense), net | 16 | 7 | 4 | (1) | (19) | (8) | (1) | |||||||||||||||||||||
| Interest expense, net (2) | 49 | 34 | 21 | 5 | 75 | - | 184 | |||||||||||||||||||||
| Income tax expense (recovery) |
42 | (11) | 10 | - | (39) | - | 2 | |||||||||||||||||||||
| Non-controlling interest in subsidiaries | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 16 | - | 16 | |||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 199 | $ | 39 | $ | 33 | $ | 10 | $ | (114) | $ | - | $ | 167 | ||||||||||||||
| For the nine months ended September 30, 2022 |
||||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 2,471 | $ | 1,254 | $ | 1,191 | $ | 386 | $ | (72) | $ | - | $ | 5,230 | ||||||||||||||
| Inter-segment revenues (1) | 5 | - | 4 | - | 7 | (16) | - | |||||||||||||||||||||
| Total operating revenues |
2,476 | 1,254 | 1,195 | 386 | (65) | (16) | 5,230 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power | 813 | 603 | - | 217 | - | (3) | 1,630 | |||||||||||||||||||||
| Regulated cost of natural gas | - | - | 554 | - | - | - | 554 | |||||||||||||||||||||
| OM&G | 450 | 249 | 270 | 93 | 114 | (12) | 1,164 | |||||||||||||||||||||
| Provincial, state and municipal taxes | 177 | 32 | 62 | 2 | 2 | - | 275 | |||||||||||||||||||||
| Depreciation and amortization | 373 | 192 | 81 | 46 | 6 | - | 698 | |||||||||||||||||||||
| Income from equity investments | - | 64 | 15 | 3 | 10 | - | 92 | |||||||||||||||||||||
| Other income (expense), net | 44 | 18 | 11 | (2) | (29) | 1 | 43 | |||||||||||||||||||||
| Interest expense, net (2) | 127 | 99 | 57 | 14 | 206 | - | 503 | |||||||||||||||||||||
| Income tax expense (recovery) | 108 | (8) | 48 | - | (117) | - | 31 | |||||||||||||||||||||
| Non-controlling interest in subsidiaries | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 47 | - | 47 | |||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 472 | $ | 169 | $ | 149 | $ | 14 | $ | (342) | $ | - | $ | 462 | ||||||||||||||
| As at September 30, 2022 |
|
|||||||||||||||||||||||||||
| Total assets | $ | 20,966 | $ | 8,168 | $ | 7,390 | $ | 1,414 | $ | 3,329 | $ | (1,463) | $ | 39,804 | ||||||||||||||
(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 $4 million in Q3 2022 and $10 million year-to-date between the Gas Utilities and Infrastructure and Other segments.
11
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Gas Utilities and Infrastructure |
Other Electric Utilities |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||
| For the three months ended September 30, 2021 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) |
$ | 796 | $ | 328 | $ | 241 | $ | 120 | $ | (337) | $ | - | $ | 1,148 | ||||||||||||||
| Inter-segment revenues (1) |
2 | - | 1 | - | 7 | (10) | - | |||||||||||||||||||||
| Total operating revenues |
798 | 328 | 242 | 120 | (330) | (10) | 1,148 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power | 274 | 144 | - | 59 | - | (1) | 476 | |||||||||||||||||||||
| Regulated cost of natural gas | - | - | 71 | - | - | - | 71 | |||||||||||||||||||||
| OM&G | 133 | 72 | 79 | 37 | 27 | (7) | 341 | |||||||||||||||||||||
| Provincial, state and municipal taxes | 58 | 11 | 16 | - | - | - | 85 | |||||||||||||||||||||
| Depreciation and amortization | 120 | 61 | 31 | 14 | 2 | - | 228 | |||||||||||||||||||||
| Income from equity investments | - | 25 | 5 | 1 | 2 | - | 33 | |||||||||||||||||||||
| Other income, net | 16 | 4 | 3 | 3 | (6) | 2 | 22 | |||||||||||||||||||||
| Interest expense, net (2) | 34 | 32 | 15 | 6 | 63 | - | 150 | |||||||||||||||||||||
| Income tax expense (recovery) | 26 | (5) | 9 | - | (122) | - | (92) | |||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 14 | - | 14 | |||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 169 | $ | 42 | $ | 29 | $ | 8 | $ | (318) | $ | - | $ | (70) | ||||||||||||||
| For the nine months ended September 30, 2021 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 2,012 | $ | 1,112 | $ | 886 | $ | 321 | $ | (434) | $ | - | $ | 3,897 | ||||||||||||||
| Inter-segment revenues (1) | 5 | - | 3 | - | 21 | (29) | - | |||||||||||||||||||||
| Total operating revenues | 2,017 | 1,112 | 889 | 321 | (413) | (29) | 3,897 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power | 628 | 484 | - | 154 | - | (3) | 1,263 | |||||||||||||||||||||
| Regulated cost of natural gas | - | - | 297 | - | - | - | 297 | |||||||||||||||||||||
| OM&G | 381 | 222 | 238 | 98 | 83 | (20) | 1,002 | |||||||||||||||||||||
| Provincial, state and municipal taxes | 158 | 32 | 53 | 3 | - | - | 246 | |||||||||||||||||||||
| Depreciation and amortization | 351 | 184 | 90 | 44 | 6 | - | 675 | |||||||||||||||||||||
| Income from equity investments | - | 78 | 15 | 3 | 15 | - | 111 | |||||||||||||||||||||
| Other income, net | 42 | 9 | 8 | 7 | (5) | 6 | 67 | |||||||||||||||||||||
| Interest expense, net (2) | 105 | 100 | 48 | 16 | 191 | - | 460 | |||||||||||||||||||||
| Income tax expense (recovery) | 59 | 3 | 43 | 1 | (197) | - | (91) | |||||||||||||||||||||
| Non-controlling interest in subsidiaries | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 36 | - | 36 | |||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 377 | $ | 174 | $ | 143 | $ | 14 | $ | (522) | $ | - | $ | 186 | ||||||||||||||
| As at December 31, 2021 |
| |||||||||||||||||||||||||||
| Total assets | $ | 17,903 | $ | 7,418 | $ | 6,666 | $ | 1,402 | $ | 2,034 | $ | (1,179) | $ | 34,244 | ||||||||||||||
(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 in Q3 2021 and $10 million year-to-date in 2021 between the Gas Utilities and Infrastructure and Other segments.
12
5. REVENUE
The following disaggregates the Company’s revenue by major source:
| Electric | Gas | Other | ||||||||||||||||||||||||||||||||||
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Other Electric Utilities |
Gas Utilities and Infrastructure |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||||||||||
| For the three months ended September 30, 2022 |
| |||||||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||||||
| Residential | $ | 581 | $ | 157 | $ | 49 | $ | 125 | $ | - | $ | - | $ | 912 | ||||||||||||||||||||||
| Commercial | 253 | 99 | 73 | 91 | - | 1 | 517 | |||||||||||||||||||||||||||||
| Industrial | 60 | 98 | 10 | 23 | - | (4) | 187 | |||||||||||||||||||||||||||||
| Other regulatory deferrals | 87 | 7 | 2 | - | - | - | 96 | |||||||||||||||||||||||||||||
| Other (1) | 3 | 9 | 2 | 86 | - | - | 100 | |||||||||||||||||||||||||||||
| Finance income (2)(3) | - | - | - | 15 | - | - | 15 | |||||||||||||||||||||||||||||
| Regulated revenue |
984 | 370 | 136 | 340 | - | (3) | 1,827 | |||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) | - | - | - | - | 24 | - | 24 | |||||||||||||||||||||||||||||
| Other non-regulated operating revenue | - | - | - | 4 | 3 | (3) | 4 | |||||||||||||||||||||||||||||
| Mark-to-market (3) | - | - | - | - | (32) | 12 | (20) | |||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 4 | (5) | 9 | 8 | |||||||||||||||||||||||||||||
| Total operating revenues |
$ | 984 | $ | 370 | $ | 136 | $ | 344 | $ | (5) | $ | 6 | $ | 1,835 | ||||||||||||||||||||||
| For the nine months ended September 30, 2022 |
| |||||||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||||||
| Residential |
$ | 1,367 | $ | 624 | $ | 137 | $ | 541 | $ | - | $ | - | $ | 2,669 | ||||||||||||||||||||||
| Commercial |
644 | 318 | 209 | 323 | - | - | 1,494 | |||||||||||||||||||||||||||||
| Industrial |
165 | 266 | 25 | 60 | - | (4) | 512 | |||||||||||||||||||||||||||||
| Other regulatory deferrals |
287 | 21 | 9 | - | - | - | 317 | |||||||||||||||||||||||||||||
| Other (1) |
13 | 25 | 6 | 215 | - | (5) | 254 | |||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 44 | - | - | 44 | |||||||||||||||||||||||||||||
| Regulated revenue |
2,476 | 1,254 | 386 | 1,183 | - | (9) | 5,290 | |||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 71 | - | 71 | |||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 12 | 13 | (9) | 16 | |||||||||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | (149) | 2 | (147) | |||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 12 | (65) | (7) | (60) | |||||||||||||||||||||||||||||
| Total operating revenues |
$ | 2,476 | $ | 1,254 | $ | 386 | $ | 1,195 | $ | (65) | $ | (16) | $ | 5,230 | ||||||||||||||||||||||
(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.
13
| Electric | Gas | Other | ||||||||||||||||||||||||||||||||||
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Other Electric Utilities |
Gas Utilities and Infrastructure |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||||||||||
| For the three months ended September 30, 2021 |
| |||||||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||||||
| Residential |
$ | 454 | $ | 154 | $ | 44 | $ | 102 | $ | - | $ | - | $ | 754 | ||||||||||||||||||||||
| Commercial |
214 | 97 | 64 | 76 | - | - | 451 | |||||||||||||||||||||||||||||
| Industrial |
58 | 61 | 8 | 16 | - | - | 143 | |||||||||||||||||||||||||||||
| Other regulatory deferrals |
70 | 7 | 2 | - | - | - | 79 | |||||||||||||||||||||||||||||
| Other (1) |
2 | 9 | 2 | 29 | - | (3) | 39 | |||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 15 | - | - | 15 | |||||||||||||||||||||||||||||
| Regulated revenue |
798 | 328 | 120 | 238 | - | (3) | 1,481 | |||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | (4) | - | (4) | |||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 4 | 8 | (4) | 8 | |||||||||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | (334) | (3) | (337) | |||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 4 | (330) | (7) | (333) | |||||||||||||||||||||||||||||
| Total operating revenues |
$ | 798 | $ | 328 | $ | 120 | $ | 242 | $ | (330) | $ | (10) | $ | 1,148 | ||||||||||||||||||||||
| For the nine months ended September 30, 2021 |
| |||||||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||||||
| Residential |
$ | 1,086 | $ | 588 | $ | 121 | $ | 430 | $ | - | $ | - | $ | 2,225 | ||||||||||||||||||||||
| Commercial |
550 | 303 | 166 | 268 | - | - | 1,287 | |||||||||||||||||||||||||||||
| Industrial |
156 | 176 | 21 | 48 | - | (1) | 400 | |||||||||||||||||||||||||||||
| Other regulatory deferrals |
214 | 21 | 5 | - | - | - | 240 | |||||||||||||||||||||||||||||
| Other (1) |
11 | 24 | 8 | 88 | - | (7) | 124 | |||||||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 43 | - | - | 43 | |||||||||||||||||||||||||||||
| Regulated revenue |
2,017 | 1,112 | 321 | 877 | - | (8) | 4,319 | |||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 63 | - | 63 | |||||||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 12 | 25 | (15) | 22 | |||||||||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | (501) | (6) | (507) | |||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 12 | (413) | (21) | (422) | |||||||||||||||||||||||||||||
| Total operating revenues |
$ | 2,017 | $ | 1,112 | $ | 321 | $ | 889 | $ | (413) | $ | (29) | $ | 3,897 | ||||||||||||||||||||||
(1) Other includes rental revenues which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
Remaining Performance Obligations
Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of September 30, 2022, the aggregate amount of the transaction price allocated to remaining performance obligations was $465 million (2021 – $435 million). This amount includes $147 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 2042.
14
6. REGULATORY ASSETS AND LIABILITIES
A summary of the Company’s 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 2021 annual audited consolidated financial statements.
| As at millions of dollars |
September 30 2022 |
December 31 2021 |
||||||
| Regulatory assets |
||||||||
| Deferred income tax regulatory assets |
$ | 1,147 | $ | 1,045 | ||||
| Tampa Electric capital cost recovery for early retired assets |
688 | 657 | ||||||
| Cost recovery clauses |
605 | 114 | ||||||
| Regulated fuel adjustment mechanism (“FAM”) |
330 | 145 | ||||||
| Pension and post-retirement medical plan |
296 | 291 | ||||||
| NMGC winter event gas cost recovery |
83 | 117 | ||||||
| Deferrals related to derivative instruments |
61 | 23 | ||||||
| Storm restoration regulatory asset |
38 | 35 | ||||||
| Environmental remediations |
30 | 27 | ||||||
| Storm reserve |
29 | - | ||||||
| Stranded cost recovery |
28 | 26 | ||||||
| Other |
96 | 86 | ||||||
| $ | 3,431 | $ | 2,566 | |||||
| Current |
$ | 846 | $ | 253 | ||||
| Long-term |
2,585 | 2,313 | ||||||
| Total regulatory assets |
$ | 3,431 | $ | 2,566 | ||||
| Regulatory liabilities |
||||||||
| Deferred income tax regulatory liabilities |
$ | 911 | $ | 863 | ||||
| Accumulated reserve - cost of removal |
888 | 819 | ||||||
| Deferrals related to derivative instruments |
448 | 241 | ||||||
| Cost recovery clauses |
74 | 35 | ||||||
| Self-insurance fund (note 22) |
30 | 28 | ||||||
| Storm reserve |
1 | 58 | ||||||
| Other |
20 | 11 | ||||||
| $ | 2,372 | $ | 2,055 | |||||
| Current |
$ | 488 | $ | 290 | ||||
| Long-term |
1,884 | 1,765 | ||||||
| Total regulatory liabilities |
$ | 2,372 | $ | 2,055 | ||||
Tampa Electric
Storm Reserve
In September 2022, Tampa Electric was impacted by Hurricane Ian. The majority of Hurricane Ian restoration costs will be charged against Tampa Electric’s Florida Public Service Commission (“FPSC”) approved storm reserve, resulting in minimal impact on earnings for 2022. The total cost of restoration is estimated to be $130 million USD. As of September 30, 2022, Tampa Electric incurred $68 million USD in storm restoration cost and an additional $62 million USD in storm restoration costs are expected to be incurred in Q4 2022. Total restoration costs charged to the storm reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. Tampa Electric expects to petition the FPSC in late 2022 or early 2023 for recovery of the storm reserve regulatory asset and the replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for a total of approximately $136 million USD.
Storm Protection Plan (“SPP”) Cost Recovery Clause
On April 11, 2022, Tampa Electric filed a new SPP with the FPSC to determine the storm hardening activities and related costs in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved Tampa Electric’s SPP.
15
ROE Adjustment
Tampa Electric’s 2021 settlement agreement allows the company to request an increase to revenue and ROE due to increases in the 30-year United States Treasury bond yield rate. On July 1, 2022, Tampa Electric requested the FPSC to increase its annual base rates by $10 million USD effective September 1, 2022 and to increase its ROE. On August 16, 2022, the FPSC approved the change. Effective July 1, 2022, the new mid-point ROE is 10.20 per cent, and the range is 9.25 per cent to 11.25 per cent.
Mid-Course Fuel Adjustment
The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD and will be spread over customer bills from April 1, 2022 through December 2022.
NSPI
General Rate Application
On January 27, 2022, NSPI filed a General Rate Application (“GRA”) with the Nova Scotia Utility and Review Board (“UARB”), which was then amended on February 18, 2022. The GRA proposes a rate stability plan for 2022 through 2024 which includes average rate increases of 2.8 per cent per year on August 1, 2022, January 1, 2023 and January 1, 2024 to recover non-fuel costs. On September 2, 2022, NSPI filed a fuel update to the GRA proposing that the cost of fuel increases be smoothed over 2023 and 2024 and the forecast FAM balance at December 31, 2022 be recovered over three years (2023 through 2025), resulting in combined fuel rate increases of 1.6 per cent on January 1, 2023 and January 1, 2024 to recover fuel costs. The remaining recovery of the 2022 FAM balance is forecast to be collected in 2025 and would require an additional fuel rate increase of 1.3 per cent subject to UARB approval in future rate applications. The effective timing of any approved increases would be determined by the UARB. The hearing for this matter concluded in September 2022 with closing submissions to be filed in Q4 2022. A decision by the UARB is expected in Q1 2023.
On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. The legislation pre-empts the pending UARB GRA decision and limits non-fuel rate increases, excluding increases relating to demand-side management costs, to a total of 1.8 per cent between the effective date of the UARB’s decision and the end of 2024. The legislation also:
| • | requires revenue generated from the non-fuel rate increase to be used only to improve the reliability of service to ratepayers; |
| • | limits NSPI’s return on equity to 9.25 per cent and equity ratio to 40 per cent; and |
| • | limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus 1.75 per cent, unless otherwise directed by the UARB. |
Nova Scotia Cap-and-Trade Program
As at September 30, 2022, the FAM includes a recovery of $190 million (December 31, 2021 – $38 million) non-cash accrual representing the estimated future cost of acquiring emissions credits for the 2019 through 2022 Nova Scotia Cap-and-Trade compliance period. These costs are estimated based on forecast emissions for the compliance period and are sensitive to changes to forecasts of energy received from Muskrat Falls for the remainder of 2022 and the actual emissions profile. Each 1 per cent change in forecasted emissions for the balance of the compliance period would result in a $2 million change in the expense and liability, which NSPI anticipates being recoverable through the FAM.
Lower than forecasted Muskrat Falls energy received during the compliance period has resulted in the increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has announced that it will provide $165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of compliance forecasted at the time of the September 2022 GRA fuel update. Discussions related to how this relief will be provided are ongoing and have not been reflected in the accrued compliance costs recognized to date.
16
NSPML
On August 3, 2022, NSPML submitted an application to the UARB requesting recovery of approximately $164 million in Maritime Link costs for 2023. A decision is expected in Q4 2022.
PGS
In September 2022, Hurricane Ian impacted PGS’s operations in Fort Myers and Sarasota. The estimated restoration costs are expected to be up to $3 million USD and will be charged against PGS’s FPSC approved storm reserve, resulting in minimal impact to earnings.
NMGC
On December 13, 2021, NMGC filed a rate case with the New Mexico Public Regulation Commission (“NMPRC”) for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The proposed rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. A hearing was held in June 2022 and a decision from the NMPRC is expected in Q4 2022.
BLPC
On October 4, 2021 BLPC submitted a general rate review application to the Fair Trading Commission (“FTC”). The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country’s transition towards 100 per cent renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of $3 million USD for the remainder of 2022. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022 and BLPC expects a decision on final rates from the FTC in 2022.
GBPC
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023 the fuel pass through charge will be adjusted monthly in-line with actual fuel costs.
On January 14, 2022, The Grand Bahama Port Authority issued its decision on GBPC’s rate application. The approved increase in annual revenues of $3.5 million USD commenced on April 1, 2022.
17
7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
| Carrying Value as at | Equity Income for the three months ended |
Equity Income for the nine months ended |
Percentage of |
|||||||||||||||||||||||||
| September 30 | December 31 | September 30 | September 30 | Ownership | ||||||||||||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | 2022 | 2021 | 2022 | |||||||||||||||||||||
| LIL (1) |
$ | 725 | $ | 682 | $ | 15 | $ | 13 | $ | 43 | $ | 39 | 34.7 | |||||||||||||||
| NSPML |
514 | 533 | 5 | 12 | 21 | 39 | 100.0 | |||||||||||||||||||||
| M&NP (2) |
129 | 123 | 6 | 5 | 15 | 15 | 12.9 | |||||||||||||||||||||
| Lucelec (2) |
50 | 44 | 1 | 1 | 3 | 3 | 19.5 | |||||||||||||||||||||
| Bear Swamp (3) |
- | - | 5 | 2 | 10 | 15 | 50.0 | |||||||||||||||||||||
| $ | 1,418 | $ | 1,382 | $ | 32 | $ | 33 | $ | 92 | $ | 111 | |||||||||||||||||
(1) Emera indirectly owns 100 per cent of the LIL Class B units, which comprises 24.9 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 $104 million (2021 – $105 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 22). NSPML’s consolidated summarized balance sheet is as follows:
| As at millions of dollars |
September 30 2022 |
December 31 2021 |
||||||
| Current assets |
$ | 44 | $ | 25 | ||||
| PP&E |
1,533 | 1,587 | ||||||
| Regulatory assets |
263 | 247 | ||||||
| Non-current assets |
30 | 31 | ||||||
| Total assets |
$ | 1,870 | $ | 1,890 | ||||
| Current liabilities |
$ | 60 | $ | 50 | ||||
| Long-term debt (1) |
1,169 | 1,189 | ||||||
| Non-current liabilities |
127 | 118 | ||||||
| Equity |
514 | 533 | ||||||
| Total liabilities and equity |
$ | 1,870 | $ | 1,890 | ||||
(1) The project debt has been guaranteed by the Government of Canada.
18
8. INCOME TAXES
The income tax provision differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:
| Three months ended | Nine months ended | |||||||||||||||
| For the |
September 30 | September 30 | ||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Income (loss) before provision for income taxes |
$ | 186 | $ | (148) | $ | 541 | $ | 132 | ||||||||
| Statutory income tax rate |
29.0% | 29.0% | 29.0% | 29.0% | ||||||||||||
| Income taxes, at statutory income tax rate |
54 | (43) | 157 | 38 | ||||||||||||
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities |
(20) | (16) | (55) | (47) | ||||||||||||
| Foreign tax rate variance |
(14) | (11) | (30) | (27) | ||||||||||||
| Amortization of deferred income tax regulatory liabilities |
(14) | (12) | (27) | (28) | ||||||||||||
| Tax effect of equity earnings |
(2) | (3) | (7) | (12) | ||||||||||||
| Tax credits |
(3) | (3) | (7) | (10) | ||||||||||||
| Manufacturing allowance |
(1) | (2) | (4) | (5) | ||||||||||||
| Other |
2 | (2) | 4 | - | ||||||||||||
| Income tax (recovery) expense |
$ | 2 | $ | (92) | $ | 31 | $ | (91) | ||||||||
| Effective income tax rate |
1% | 62% | 6% | (69%) | ||||||||||||
On August 16, 2022, the United States Inflation Reduction Act was signed into legislation and includes numerous tax incentives for clean energy, including solar, as well as several revenue raising provisions. Emera is evaluating the impact of the new legislation and does not expect a material impact on the consolidated financial statements.
During 2022, the Canada Revenue Agency (“CRA”) issued notices of reassessment to NSPI for the 2013 through 2016 taxation years. NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $126 million (2021 - $62 million), including interest. NSPI has prepaid $55 million (2021 - $23 million) of the amount in dispute, as required by the CRA.
On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be available in subsequent years.
Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.
NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not determinable at this time.
19
9. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
| Issued and outstanding: | millions of shares | millions of dollars | ||||||
| Balance, December 31, 2021 |
261.07 | $ | 7,242 | |||||
| Issuance of common stock under ATM program (1) |
3.79 | 233 | ||||||
| Issued under the Dividend Reinvestment Program, net of discounts |
2.86 | 171 | ||||||
| Senior management stock options exercised and Employee Share Purchase Plan |
0.51 | 29 | ||||||
| Balance, September 30, 2022 |
268.23 | $ | 7,675 | |||||
(1) In Q3 2022, 1,715,056 common shares were issued under Emera’s ATM program at an average price of $61.87 per share for gross proceeds of $106 million ($105 million net of after-tax issuance costs). For the nine months ended September 30, 2022, 3,793,924 common shares were issued under Emera’s ATM program at an average price of $61.85 per share for gross proceeds of $235 million ($233 million net of after-tax issuance costs). As at September 30, 2022, an aggregate gross sales limit of $222 million remained available for issuance under the ATM program.
10. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
| Three months ended | Nine months ended | |||||||||||||||
| For the |
September 30 | September 30 | ||||||||||||||
| millions of dollars (except per share amounts) | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Numerator |
||||||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 167.1 | $ | (70.0) | $ | 461.6 | $ | 186.4 | ||||||||
| Diluted numerator |
167.1 | (70.0) | 461.6 | 186.4 | ||||||||||||
| Denominator |
||||||||||||||||
| Weighted average shares of common stock outstanding |
266.6 | 257.3 | 264.3 | 254.7 | ||||||||||||
| Weighted average deferred share units outstanding (1) |
- | 1.2 | - | 1.3 | ||||||||||||
| Weighted average shares of common stock outstanding – basic |
266.6 | 258.5 | 264.3 | 256.0 | ||||||||||||
| Stock-based compensation (2) |
0.4 | - | 0.5 | 0.4 | ||||||||||||
| Weighted average shares of common stock outstanding – diluted |
267.0 | 258.5 | 264.8 | 256.4 | ||||||||||||
| Earnings (loss) per common share |
||||||||||||||||
| Basic |
$ | 0.63 | $ | (0.27) | $ | 1.75 | $ | 0.73 | ||||||||
| Diluted |
$ | 0.63 | $ | (0.27) | $ | 1.74 | $ | 0.73 | ||||||||
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore no longer included in the calculation of earnings per common share.
(2) The potential common shares from 0.5 million related to stock-based compensation were excluded from diluted EPS for the three months ended September 30, 2021, as the Company had net loss in this quarter.
20
11. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of AOCI, net of tax, are as follows:
| millions of dollars | Unrealized self-sustaining |
Net change in net investment hedges |
(Losses) gains on derivatives recognized as cash flow hedges |
Net change in available- for-sale |
Net change in unrecognized pension and post- retirement benefit costs |
Total AOCI | ||||||||||||||||||
| For the nine months ended September 30, 2022 |
| |||||||||||||||||||||||
| Balance, January 1, 2022 | $ | 10 | $ | 35 | $ | 18 | $ | (1) | $ | (37) | $ | 25 | ||||||||||||
| Other comprehensive income (loss) before reclassifications | 763 | (116) | - | (1) | - | 646 | ||||||||||||||||||
| Amounts reclassified from AOCI | - | - | (2) | - | (6) | (8) | ||||||||||||||||||
| Net current period other comprehensive income (loss) | 763 | (116) | (2) | (1) | (6) | 638 | ||||||||||||||||||
| Balance, September 30, 2022 | $ | 773 | $ | (81) | $ | 16 | $ | (2) | $ | (43) | $ | 663 | ||||||||||||
| For the nine months ended September 30, 2021 |
| |||||||||||||||||||||||
| Balance, January 1, 2021 | $ | 52 | $ | 30 | $ | 1 | $ | (1) | $ | (161) | $ | (79) | ||||||||||||
| Other comprehensive income (loss) before reclassifications | (1) | (1) | 18 | - | - | 16 | ||||||||||||||||||
| Amounts reclassified from AOCI | - | - | (1) | - | 13 | 12 | ||||||||||||||||||
| Net current period other comprehensive income (loss) | (1) | (1) | 17 | - | 13 | 28 | ||||||||||||||||||
| Balance, September 30, 2021 | $ | 51 | $ | 29 | $ | 18 | $ | (1) | $ | (148) | $ | (51) | ||||||||||||
| The reclassifications out of AOCI are as follows:
|
| |||||||||||||||||
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| Affected line item in the Consolidated Interim Financial Statements |
Amounts reclassified from AOCI | |||||||||||||||||
| Gain on derivatives recognized as cash flow hedges |
||||||||||||||||||
| Interest rate hedge |
Interest expense, net | $ | (1) | $ | (1) | $ | (2) | $ | (1) | |||||||||
| Total |
$ | (1) | $ | (1) | $ | (2) | $ | (1) | ||||||||||
| Net change in unrecognized pension and post-retirement benefit costs |
| |||||||||||||||||
| Actuarial losses |
Other income, net | $ | 2 | $ | 4 | $ | 6 | $ | 13 | |||||||||
| Amounts reclassified into obligations |
Pension and post-retirement liabilities | - | - | (12) | - | |||||||||||||
| Total |
2 | 4 | (6) | 13 | ||||||||||||||
| Total reclassifications out of AOCI, for the period |
$ | 1 | $ | 3 | $ | (8) | $ | 12 | ||||||||||
21
12. 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 the 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 the 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. Tampa Electric 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, 2022. |
| 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. |
22
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| As at millions of dollars |
September 30 2022 |
December 31 2021 |
September 30 2022 |
December 31 2021 |
||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ 355 | $ 146 | $ 58 | $ 16 | ||||||||||||
| FX forwards |
22 | 7 | - | 8 | ||||||||||||
| Physical natural gas purchases |
96 | 88 | - | - | ||||||||||||
| 473 | 241 | 58 | 24 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
186 | 33 | 177 | 32 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts |
493 | 208 | 1,981 | 818 | ||||||||||||
| 679 | 241 | 2,158 | 850 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| Equity derivatives |
- | 11 | 10 | - | ||||||||||||
| FX forwards |
5 | - | 35 | - | ||||||||||||
| 5 | 11 | 45 | - | |||||||||||||
| Total gross current derivatives |
1,157 | 493 | 2,261 | 874 | ||||||||||||
| Impact of master netting agreements: |
||||||||||||||||
| Regulatory deferral |
(26) | (4) | (26) | (4) | ||||||||||||
| HFT derivatives |
(434) | (188) | (434) | (188) | ||||||||||||
| Total impact of master netting agreements |
(460) | (192) | (460) | (192) | ||||||||||||
| Total derivatives |
$ 697 | $ 301 | $ 1,801 | $ 682 | ||||||||||||
| Current (1) |
554 | 195 | 1,545 | 533 | ||||||||||||
| Long-term (1) |
143 | 106 | 256 | 149 | ||||||||||||
| Total derivatives |
$ 697 | $ 301 | $ 1,801 | $ 682 | ||||||||||||
(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 the treasury lock was settled for a gain of $19 million USD that will be amortized through interest expense over 10 years. As of September 30, 2022, the unrealized gain in AOCI was $16 million, net of tax (2021 - $18 million, net of tax). For the three and nine months ended September 30, 2022, unrealized gains of $1 million (2021 - $1 million) and $2 million (2021 - $1 million), respectively, have been reclassified into interest expense. The company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged item settles. As of September 30, 2022, there were no outstanding cash flow hedges.
23
Regulatory Deferral
The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:
| millions of dollars | Physical natural gas purchases |
Commodity swaps and forwards |
Foreign exchange forwards |
Physical natural gas purchases |
Commodity swaps and forwards |
Foreign exchange forwards |
||||||||||||||||||
| For the three months ended September 30 | 2022 | 2021 | ||||||||||||||||||||||
| Unrealized gain (loss) in regulatory assets |
$ | - | $ | (30) | $ | 1 | $ | - | $ | 10 | $ | 11 | ||||||||||||
| Unrealized gain in regulatory liabilities |
8 | 92 | 15 | - | 177 | 3 | ||||||||||||||||||
| Realized (gain) loss in regulatory assets |
- | 19 | - | - | (1) | - | ||||||||||||||||||
| Realized (gain) loss in regulatory liabilities |
- | (12) | - | - | 1 | - | ||||||||||||||||||
| Realized loss in inventory (1) |
- | (42) | - | - | (4) | - | ||||||||||||||||||
| Realized gain in regulated fuel for generation and purchased power (2) | (5) | (45) | (1) | - | (13) | - | ||||||||||||||||||
| Total change in derivative instruments |
$ | 3 | $ | (18) | $ | 15 | $ | - | $ | 170 | $ | 14 | ||||||||||||
| millions of dollars | Physical natural gas purchases |
Commodity swaps and forwards |
Foreign exchange forwards |
Physical natural gas purchases |
Commodity swaps and forwards |
Foreign exchange forwards |
||||||||||||||||||
| For the nine months ended September 30 | 2022 | 2021 | ||||||||||||||||||||||
| Unrealized gain (loss) in regulatory assets |
$ | - | $ | (68) | $ | 2 | $ | - | $ | 21 | $ | 8 | ||||||||||||
| Unrealized gain (loss) in regulatory liabilities |
47 | 421 | 17 | - | 264 | (1) | ||||||||||||||||||
| Realized (gain) loss in regulatory assets |
- | 35 | - | - | (3) | - | ||||||||||||||||||
| Realized gain in regulatory liabilities |
- | (34) | - | - | (1) | - | ||||||||||||||||||
| Realized (gain) loss in inventory (1) |
- | (84) | 4 | - | 2 | 3 | ||||||||||||||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) | (39) | (103) | - | - | (13) | 4 | ||||||||||||||||||
| Total change in derivative instruments |
$ | 8 | $ | 167 | $ | 23 | $ | - | $ | 270 | $ | 14 | ||||||||||||
(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; hedging relationships that have been terminated or the hedged transaction is no longer probable.
As at September 30, 2022, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:
| millions | 2022 | 2023-2025 | ||||||
| Physical natural gas purchases: |
||||||||
| Natural gas (Mmbtu) |
2 | 6 | ||||||
| Commodity swaps and forwards purchases: |
||||||||
| Natural gas (Mmbtu) |
10 | 28 | ||||||
| Heavy fuel oil (Bbls) |
- | 1 | ||||||
| Power (MWh) |
- | 3 | ||||||
| FX swaps and forwards: |
||||||||
| FX contracts (millions of USD) |
$ | 31 | $ | 190 | ||||
| Weighted average rate |
1.2487 | 1.2533 | ||||||
| % of USD requirements |
50 | % | 23 | % | ||||
24
HFT Derivatives
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Power swaps and physical contracts in non-regulated operating revenues | $ | 5 | $ | 1 | $ | 9 | $ 3 | |||||||||
| Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | (572) | (236) | (644) | (229) | ||||||||||||
| Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power | - | - | - | 1 | ||||||||||||
| Total losses in net income |
$ | (567) | $ | (235) | $ | (635) | $ (225) | |||||||||
As at September 30, 2022, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
| millions | 2022 | 2023 | 2024 | 2025 | 2026 and thereafter |
|||||||||||||||
| Natural gas purchases (Mmbtu) |
129 | 254 | 85 | 38 | 166 | |||||||||||||||
| Natural gas sales (Mmbtu) |
205 | 420 | 181 | 101 | 12 | |||||||||||||||
| Power purchases (MWh) |
1 | 2 | - | - | - | |||||||||||||||
| Power sales (MWh) |
1 | 2 | - | - | - | |||||||||||||||
Other Derivatives
As at September 30, 2022, 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 2022. The FX forwards have a combined notional amount of $477 million USD and expire throughout 2022, 2023, and 2024.
The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives:
| millions of dollars | Foreign exchange forwards |
Equity derivatives |
Foreign exchange forwards |
Equity derivatives |
||||||||||||
| For the three months ended September 30 |
2022 | 2021 | ||||||||||||||
| Unrealized gain (loss) in OM&G |
$ | - | $ | (12) | $ | - | $ | 3 | ||||||||
| Unrealized loss in other income, net |
(31 | ) | - | (5) | - | |||||||||||
| Realized gain (loss) in other income, net |
(1 | ) | - | 4 | - | |||||||||||
| Total gains (losses) in net income |
$ | (32 | ) | $ | (12) | $ | (1 | ) | $ | 3 | ||||||
| millions of dollars | Foreign exchange forwards |
Equity derivatives |
Foreign exchange forwards |
Equity derivatives |
||||||||||||
| For the nine months ended September 30 |
2022 | 2021 | ||||||||||||||
| Unrealized gain (loss) in OM&G |
$ | - | $ | (21) | $ | - | $ | 9 | ||||||||
| Unrealized loss in other income, net |
(30 | ) | - | (11) | - | |||||||||||
| Realized gain (loss) in other income, net |
(1 | ) | - | 13 | - | |||||||||||
| Total gains (losses) in net income |
$ | (31 | ) | $ | (21) | $ | 2 | $ | 9 | |||||||
25
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 September 30, 2022, the Company had $140 million (December 31, 2021 - $114 million) in financial assets considered to be past due, which had been outstanding for an average 59 days. The fair value of these financial assets was $119 million (December 31, 2021 - $93 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 millions of dollars |
September 30 2022 |
December 31 2021 |
||||||
| Cash collateral provided to others |
$ | 306 | $ | 212 | ||||
| Cash collateral received from others |
$ | 249 | $ | 100 | ||||
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.
26
As at September 30, 2022, the total fair value of derivatives in a liability position was $1,801 million (December 31, 2021 – $682 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.
13. 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 12), 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.
27
The following tables set out the classification of the methodology used by the Company to fair value its derivatives:
| As at | September 30, 2022 | |||||||||||||||
| millions of dollars |
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 221 | $ | 108 | $ | - | $ | 329 | ||||||||
| FX forwards |
- | 22 | - | 22 | ||||||||||||
| Physical natural gas purchases |
- | - | 96 | 96 | ||||||||||||
| 221 | 130 | 96 | 447 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
4 | 74 | 10 | 88 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
(12 | ) | 97 | 72 | 157 | |||||||||||
| (8 | ) | 171 | 82 | 245 | ||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 5 | - | 5 | ||||||||||||
| Total assets |
213 | 306 | 178 | 697 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
14 | 18 | - | 32 | ||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
6 | 69 | 4 | 79 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
61 | 234 | 1,350 | 1,645 | ||||||||||||
| 67 | 303 | 1,354 | 1,724 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 35 | - | 35 | ||||||||||||
| Equity derivatives |
10 | - | - | 10 | ||||||||||||
| 10 | 35 | - | 45 | |||||||||||||
| Total liabilities |
91 | 356 | 1,354 | 1,801 | ||||||||||||
| Net assets (liabilities) |
$ | 122 | $ | (50) | $ | (1,176 | ) | $ | (1,104) | |||||||
28
| As at | December 31, 2021 | |||||||||||||||
| millions of dollars |
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 101 | $ | 41 | $ | - | $ | 142 | ||||||||
| FX forwards |
- | 7 | - | 7 | ||||||||||||
| Physical natural gas purchases and sales |
- | - | 88 | 88 | ||||||||||||
| 101 | 48 | 88 | 237 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
4 | 5 | 4 | 13 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
(1) | 29 | 12 | 40 | ||||||||||||
| 3 | 34 | 16 | 53 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| Equity derivatives |
11 | - | - | 11 | ||||||||||||
| Total assets |
115 | 82 | 104 | 301 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
7 | 5 | - | 12 | ||||||||||||
| FX forwards |
- | 8 | - | 8 | ||||||||||||
| 7 | 13 | - | 20 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
4 | 5 | 3 | 12 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
13 | 122 | 515 | 650 | ||||||||||||
| 17 | 127 | 518 | 662 | |||||||||||||
| Total liabilities |
24 | 140 | 518 | 682 | ||||||||||||
| Net assets (liabilities) |
$ | 91 | $ | (58) | $ | (414) | $ | (381) | ||||||||
The change in the fair value of the Level 3 financial assets for the three months ended September 30, 2022 was as follows:
| Regulatory Deferral | HFT Derivatives | |||||||||||||||
| millions of dollars | Physical natural gas purchases |
Power | Natural gas | Total | ||||||||||||
| Balance, beginning of period |
$ 93 | $ | 8 | $ | 59 | $ | 160 | |||||||||
| Realized gain included in fuel for generation and purchased power |
(5) | - | - | (5) | ||||||||||||
| Unrealized gains included in regulatory liabilities |
8 | - | - | 8 | ||||||||||||
| Total realized and unrealized gains included in non-regulated operating revenues |
- | 2 | 13 | 15 | ||||||||||||
| Balance, September 30, 2022 |
$ 96 | $ | 10 | $ | 72 | $ | 178 | |||||||||
The change in the fair value of the Level 3 financial liabilities for the three months ended September 30, 2022 was as follows:
| HFT Derivatives | ||||||||||||
| millions of dollars | Power | Natural gas | Total | |||||||||
| Balance, beginning of period |
$ | 5 | $ 691 | $ | 696 | |||||||
| Total realized and unrealized gains (losses) included in non-regulated operating revenues |
(1 | ) | 659 | 658 | ||||||||
| Balance, September 30, 2022 |
$ | 4 | $ 1,350 | $ | 1,354 | |||||||
29
The change in the fair value of the Level 3 financial assets for the nine months ended September 30, 2022 was as follows:
| Regulatory Deferral | HFT Derivatives | |||||||||||||||
| millions of dollars | Physical natural gas purchases |
Power | Natural gas | Total | ||||||||||||
| Balance, beginning of period |
$ 88 | $ 4 | $ 12 | $ 104 | ||||||||||||
| Realized gains included in fuel for generation and purchased power |
(39) | - | - | (39) | ||||||||||||
| Unrealized gains included in regulatory assets |
47 | - | - | 47 | ||||||||||||
| Total realized and unrealized gains included in non-regulated operating revenues |
- | 6 | 60 | 66 | ||||||||||||
| Balance, September 30, 2022 |
$ 96 | $ 10 | $ 72 | $ 178 | ||||||||||||
The change in the fair value of the Level 3 financial liabilities for the nine months ended September 30, 2022 was as follows:
| HFT Derivatives | ||||||||||||
| millions of dollars | Power | Natural gas | Total | |||||||||
| Balance, beginning of period |
$ 3 | $ 515 | $ 518 | |||||||||
| Total realized and unrealized gains included in non-regulated operating revenues |
1 | 835 | 836 | |||||||||
| Balance, September 30, 2022 |
$ 4 | $ 1,350 | $ 1,354 | |||||||||
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:
| September 30, 2022 | ||||||||||||||||||||||||
| As at millions of dollars |
Fair Value | |
Significant Unobservable Input |
|
Low | High | |
Weighted average (1) |
| |||||||||||||||
| Assets | Liabilities | |||||||||||||||||||||||
| Regulatory deferral – Physical natural gas purchases | $ | 96 | $ | - | Third-party pricing | $6.74 | $48.31 | $17.38 | ||||||||||||||||
| HFT derivatives – Power swaps and physical contracts | 10 | 4 | Third-party pricing | $453.48 | $286.25 | $249.33 | ||||||||||||||||||
| HFT derivatives – Natural gas swaps, futures, forwards and physical contracts | 72 | 1,350 | Third-party pricing | $2.61 | $35.81 | $21.41 | ||||||||||||||||||
| Total |
$ | 178 | $ | 1,354 | ||||||||||||||||||||
| Net liability |
$ | 1,176 | ||||||||||||||||||||||
(1) Unobservable inputs were weighted by the relative fair value of the instruments.
30
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 millions of dollars |
Carrying Amount |
Fair Value | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||
| September 30, 2022 |
$ | 15,860 | $ | 14,343 | $ | - | $ | 13,892 | $ | 451 | $ | 14,343 | ||||||||||||
| December 31, 2021 |
$ | 14,658 | $ | 16,775 | $ | - | $ | 16,308 | $ | 467 | $ | 16,775 | ||||||||||||
The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency loss of $95 million was recorded in AOCI for the three months ended September 30, 2022 (2021 – $35 million after-tax loss) and an after-tax foreign currency loss of $116 million for the nine months ended September 30, 2022 (2021 – $1 million after tax loss).
14. RELATED PARTY TRANSACTIONS
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities, in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.
Significant transactions between Emera and its associated companies are as follows:
| • | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $41 million for the three months ended September 30, 2022 (2021 - $27 million) and $118 million for the nine months ended September 30, 2022 (2021 - $91 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 $1 million for the three months ended September 30, 2022 (2021 - $4 million) and $7 million for the nine months ended September 30, 2022 (2021 - $14 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at September 30, 2022 and at December 31, 2021.
31
15. RECEIVABLES AND OTHER CURRENT ASSETS
Receivables and other current assets consisted of the following:
| As at millions of dollars |
September 30 2022 |
December 31 2021 |
||||||
| Customer accounts receivable – billed |
$ | 924 | $ | 767 | ||||
| Customer accounts receivable – unbilled |
322 | 318 | ||||||
| Allowance for credit losses |
(21) | (21) | ||||||
| Capitalized transportation capacity (1) |
923 | 316 | ||||||
| Income tax receivable |
12 | 8 | ||||||
| Prepaid expenses |
106 | 65 | ||||||
| Other |
413 | 280 | ||||||
| Total receivables and other current assets |
$ | 2,679 | $ | 1,733 | ||||
(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.
16. LEASES
Lessor
The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, Seacoast, compressed natural gas (“CNG”) stations and heat pumps.
Commencing in January 2022, the Company leased a Seacoast pipeline, a 21-mile, 30-inch lateral that is classified as a sales-type lease. The term of the pipeline lateral lease is 34 years with a net investment of $100 million USD. The lessee of the new pipeline lateral has renewal options for an additional 16 years. These renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably certain that they will be exercised.
For further information on the Brunswick Pipeline lease, CNG stations and heat pumps, refer to note 19 in Emera’s 2021 annual audited consolidated financial statements.
The total net investment in direct finance and sales-type leases consist of the following:
| As at millions of dollars |
September 30 2022 |
December 31 2021 |
||||||
| Total minimum lease payment to be received |
$ | 1,418 | $ | 947 | ||||
| Less: amounts representing estimated executory costs |
(209) | (165) | ||||||
| Minimum lease payments receivable |
$ | 1,209 | $ | 782 | ||||
| Estimated residual value of leased property (unguaranteed) |
182 | 183 | ||||||
| Less: unearned finance lease income |
(753) | (443) | ||||||
| Net investment in direct finance and sales-type leases |
$ | 638 | $ | 522 | ||||
| Principal due within one year (included in “Receivables and other current assets”) |
34 | 19 | ||||||
| Net Investment in direct finance and sales type leases - long-term |
$ | 604 | $ | 503 | ||||
As at September 30, 2022, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows:
| millions of dollars | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | Total | |||||||||||||||||||||
| Minimum lease payments to be received |
$ | 23 | $ | 93 | $ | 93 | $ | 94 | $ | 93 | $ | 1,022 | $ | 1,418 | ||||||||||||||
| Less: executory costs |
(209) | |||||||||||||||||||||||||||
| Total |
$ | 1,209 | ||||||||||||||||||||||||||
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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:
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of dollars | 2022 | 2021 | 2022 | 2021 | ||||||||||||
| Defined benefit pension plans |
||||||||||||||||
| Service cost |
$ | 10 | $ | 10 | $ | 31 | $ | 32 | ||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
20 | 16 | 60 | 50 | ||||||||||||
| Expected return on plan assets |
(36) | (33) | (108) | (99) | ||||||||||||
| Current year amortization of: |
||||||||||||||||
| Actuarial losses |
2 | 4 | 6 | 13 | ||||||||||||
| Regulatory asset |
5 | 8 | 15 | 21 | ||||||||||||
| Settlements and curtailments |
1 | - | 1 | - | ||||||||||||
| Total non-service costs |
(8) | (5) | (26) | (15) | ||||||||||||
| Total defined benefit pension plans |
2 | 5 | 5 | 17 | ||||||||||||
| Non-pension benefit plans |
||||||||||||||||
| Service cost |
1 | 1 | 3 | 4 | ||||||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
3 | 2 | 7 | 6 | ||||||||||||
| Expected return on plan assets |
(1) | (1) | (1) | (2) | ||||||||||||
| Current year amortization of regulatory asset |
1 | 2 | 2 | 4 | ||||||||||||
| Total non-service costs |
3 | 3 | 8 | 8 | ||||||||||||
| Total non-pension benefit plans |
4 | 4 | 11 | 12 | ||||||||||||
| Total defined benefit plans |
$ | 6 | $ | 9 | $ | 16 | $ | 29 | ||||||||
Emera’s pension and non-pension contributions related to these defined-benefit plans for the three months ended September 30, 2022 were $24 million (2021 – $24 million), and for the nine months ended September 30, 2022 were $55 million (2021 – $53 million). Annual employer contributions to the defined benefit pension plans are estimated to be $41 million for 2022. Emera’s contributions related to these defined contribution plans for the three months ended September 30, 2022 were $11 million (2021 – $10 million) and $30 million (2021 – $29 million) for the nine months ended September 30, 2022.
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 2021 annual audited consolidated financial statements, and below for 2022 short-term debt financing activity.
Recent Significant Financing Activity by Segment:
Other
On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on August 2, 2023. The credit agreement contains customary representation and warranties, events of default and financial and other covenants and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin.
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19. LONG-TERM DEBT
For details regarding long-term debt, refer to note 25 in Emera’s 2021 annual audited consolidated financial statements, and below for 2022 long-term debt financing activity.
Recent Significant Financing Activity by Segment:
Florida Electric Utilities
On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using existing credit facilities.
On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included $300 million USD senior notes that bear an interest rate of 3.875 per cent with a maturity date of July 12, 2024, and $300 million USD senior notes that bear an interest rate of 5 per cent with a maturity date of July 15, 2052. Proceeds from the issuance were used to repay TEC’s $470 million USD commercial paper, due in 2022.
Canadian Electric Utilities
On July 15, 2022, NSPI entered into a $400 million non-revolving term facility which matures on July 15, 2024. The credit agreement contains customary representation and warranties, events of default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin.
Gas Utilities and Infrastructure
On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving credit facility to extend the maturity from September 23, 2022, to March 22, 2024. There were no other significant changes in commercial terms from the prior agreement.
On June 30, 2022, Brunswick Pipeline amended its credit agreement to extend the maturity from June 30, 2025 to June 30, 2026. There were no other changes in commercial terms from the prior agreement.
Other Electric Utilities
On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25, 2022 to March 25, 2027. There were no other changes in commercial terms from the prior agreement.
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20. COMMITMENTS AND CONTINGENCIES
A. Commitments
As at September 30, 2022, 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 | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | Total | |||||||||||||||||||||
| Transportation (1) |
$ | 183 | 616 | 475 | 396 | 364 | 2,917 | $ | 4,951 | |||||||||||||||||||
| Purchased power (2) |
77 | 268 | 247 | 242 | 232 | 2,394 | 3,460 | |||||||||||||||||||||
| Fuel, gas supply and storage |
487 | 991 | 305 | 170 | 37 | - | 1,990 | |||||||||||||||||||||
| Capital projects |
399 | 253 | 88 | 4 | 1 | - | 745 | |||||||||||||||||||||
| Equity investment commitments (3) |
- | 240 | - | - | - | - | 240 | |||||||||||||||||||||
| Other |
45 | 81 | 81 | 60 | 44 | 223 | 534 | |||||||||||||||||||||
| $ | 1,191 | $ | 2,449 | $ | 1,196 | $ | 872 | $ | 678 | $ | 5,534 | $ | 11,920 | |||||||||||||||
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $147 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 upon its commissioning.
NSPI has a contractual obligation to pay NSPML for the 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 and the approval to collect $168 million from NSPI for the recovery of Maritime Link costs in 2022. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.
Once LIL has been commissioned, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties relating to the Maritime Link and LIL.
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, the date the NS Block delivery obligation commenced, and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
B. Legal Proceedings
TECO Guatemala Holdings (“TGH”)
Prior to Emera’s acquisition of TECO Energy in 2016, TGH, a wholly owned subsidiary of TECO Energy, divested of its indirect investment in the Guatemala electricity sector, but retained certain claims against the Republic of Guatemala (“Guatemala”). In 2013, TGH asserted an arbitration claim against Guatemala with the International Centre for the Settlement of Investment Disputes (“ICSID”) under the Dominican Republic Central America – United States Free Trade Agreement. The arbitration concerned TGH’s allegation that Guatemala unfairly set the distribution tariff for a local distribution company which harmed TGH’s investment in that company. A tribunal established by the ICSID ruled in favour of TGH (the “First Award”) and in November 2020, Guatemala made a payment of approximately $38 million USD in full and final satisfaction of the First Award.
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On September 23, 2016, TGH had filed a request for resubmission to arbitration seeking damages in addition to those awarded in the First Award. On May 13, 2020, an ICSID tribunal awarded TGH additional damages and costs against Guatemala of more than $35 million USD plus interest (the “Second Award”). TGH subsequently requested a reconsideration of the interest quantum awarded in connection with this Second Award. On October 16, 2020, the tribunal granted TGH’s request for additional interest. The additional amount is approximately $2 million USD. On February 12, 2021, Guatemala filed an application for annulment of the Second Award with ICSID. On March 31, 2021, ICSID constituted an ad hoc Committee to oversee the annulment proceeding. A three-day hearing was held before the ad hoc Committee beginning on July 27, 2022. A decision on the annulment of the Second Award is expected in Q4 2023. To date, the total of the Second Award, with interest, is approximately $64 million USD. Results to date do not reflect any benefit of the Second Award.
Superfund and Former Manufactured Gas Plant Sites
TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at September 30, 2022, TEC has estimated its financial liability to be $19 million ($14 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 TEC. The estimates to perform the work are based on TEC’s 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, TEC could be liable for more than TEC’s 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 2021 annual audited consolidated financial statements. Risks associated with derivative instruments and fair value measurements are discussed in note 12 and note 13. There have been no material changes to the principal financial risks as of September 30, 2022, except for the following:
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. Regulatory and political risk can include change in regulatory frameworks, shifts in government policy, and regulatory decisions.
36
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. Emera also holds investments in entities in which it has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, M&NP and Lucelec. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the Canadian Energy Regulator (“CER”) on a complaint basis, as opposed to the regulatory approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement expiring in 2034, with Repsol Energy Canada (“REC”). The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.
Changes in government and shifts in government policy can impact the commercial and regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that could adversely affect operations, net income and cash flows. State and local policies in some US jurisdictions have sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and regulations could adversely impact PGS and NMGC.
Emera’s rate-regulated subsidiaries are subject to regulatory processes. During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.
On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. This government intervention in the regulatory process has resulted in an increase in political risk and a reduction in the stability and predictability of NSPI’s regulatory environment. This legislation sets an unfavourable precedent and significantly increases the risk associated with NSPI’s current and future ability to recover prudently incurred costs including capital investments and regulatory assets.
D. Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2021 audited annual consolidated financial statements, with material updates as noted below:
The Company has standby letters of credit and surety bonds in the amount of $125 million USD (December 31, 2021 - $148 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually, as required.
Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will automatically terminate on the date upon which the obligations have been repaid in full.
37
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm service agreement, which expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.
21. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the | Nine months ended September 30 | |||||||
| millions of dollars | 2022 | 2021 | ||||||
| Changes in non-cash working capital: |
||||||||
| Inventory |
$ | (162) | $ | (76) | ||||
| Receivables and other current assets |
(259) | (223) | ||||||
| Accounts payable |
471 | 282 | ||||||
| Other current liabilities |
99 | 88 | ||||||
| Total non-cash working capital |
$ | 149 | $ | 71 | ||||
| Supplemental disclosure of non-cash activities: |
||||||||
| Common share dividends reinvested |
$ | 172 | $ | 157 | ||||
| Reclassification of long-term debt to short-term debt |
$ | 500 | - | |||||
| Decrease in accrued capital expenditures |
$ | (8) | $ | (1) | ||||
22. VARIABLE INTEREST ENTITIES
The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”) or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.
VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method.
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of NSPML. Thus, Emera records NSPML as an equity investment.
38
BLPC has established a Self-Insurance Fund (“SIF”), primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission, and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the 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 | September 30, 2022 | December 31, 2021 | ||||||||||||||
| millions of dollars | Total assets |
Maximum exposure to loss |
Total assets |
Maximum exposure to loss |
||||||||||||
| Unconsolidated VIEs in which Emera has variable interests |
||||||||||||||||
| NSPML (equity accounted) |
$ | 514 | $ | 6 | $ | 533 | $ | 11 | ||||||||
23. COMPARATIVE INFORMATION
These unaudited condensed consolidated interim financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.
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 November 10, 2022, the date the unaudited condensed consolidated interim financial statements were issued.
39
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 September 30, 2022.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2022 and ended on September 30, 2022 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: November 10, 2022
| “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 September 30, 2022.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2022 and ended on September 30, 2022 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: November 10, 2022
| “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 nine months ended September 30, 2022.
The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended September 30, 2022.
| Twelve months ended September 30, 2022 | ||
| Earnings Coverage (1) |
2.12 |
(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 $87 million for the twelve months ended September 30, 2022. Emera’s interest requirements for the twelve months ended September 30, 2022 amounted to $677 million. Emera’s consolidated income before interest and income tax for the twelve months ended September 30, 2022 was $1,616 million, which is 2.12 times Emera’s aggregate preferred dividends and interest requirements for this period.
Exhibit 99.6
Emera Reports 2022 Third Quarter Financial Results
HALIFAX, Nova Scotia — Today Emera (TSX: EMA) reported 2022 third quarter financial results.
Highlights
| ● | Quarterly adjusted EPS (1) increased $0.08 or 12% to $0.76 compared to $0.68 in Q3 2021. Quarterly reported EPS increased $0.90 to $0.63 in Q3 2022 compared to a net loss per common share of $(0.27) in Q3 2021 due to lower mark-to-market (“MTM”) losses in 2022. |
| ● | Year-to-date, adjusted EPS (1) increased $0.10 or 5% to $2.27 compared to $2.17 in Q3 2021. Year-to-date reported EPS increased by $1.02 to $1.75 from $0.73 in 2021 due to lower MTM losses in 2022. |
| ● | Adjusted EPS (1) contributions from regulated utilities increased 11% for the quarter and 12% year-to-date primarily driven by the impact of favourable weather and new rates at Tampa Electric, as well as from customer growth at both Tampa Electric and People’s Gas (“PGS”). Higher marketing and trading margin increased adjusted EPS1 by $0.05 for the quarter due to higher natural gas prices and volatility, which created profitable opportunities for Emera Energy Services (“EES”). These increases were partially offset by higher corporate costs, and a higher share count. |
| ● | On track to deploy $2.7 billion of capital investment in 2022, principally focused on decarbonization and reliability investments across the portfolio. |
“In the face of the devastating storm impacts and extensive system outages resulting from Hurricanes Fiona and Ian, the restoration efforts of our teams in Nova Scotia and Tampa were remarkable” said Scott Balfour, President and CEO of Emera Inc. “For the quarter, we continued to invest in meeting our customers needs for cleaner, reliable and cost-effective energy, and in so doing also delivered for our shareholders. Emera’s solid 5% growth in year-to-date earnings per share, and 12% growth in quarterly earnings per share year-over-year was principally driven by continued strong performance from our Florida utilities. Looking forward, continuing strong economic and customer growth in Florida is also supporting our updated $8-$9 billion capital plan and 7-8 % consolidated rate base growth over the 2023 – 2025 period, with approximately 75% of our capital plan expected to be invested in Tampa Electric and Peoples Gas.”
Q3 2022 Financial Results
Q3 2022 reported net income was $167 million, or $0.63 per common share, compared with a net loss of $70 million, or $(0.27) per common share, in Q3 2021. Reported net income included a $36 million after-tax MTM loss, primarily at EES, compared to a $245 million loss in Q3 2021.
Q3 2022 adjusted net income(1) was $203 million, or $0.76 per common share, compared with $175 million, or $0.68 per common share, in Q3 2021. The increase was primarily due to higher earnings contribution from Tampa Electric and EES and the impact of a weaker Canadian dollar (“CAD”). These were partially offset by increased corporate costs due to timing impacts of long-term compensation and related hedges, as well as higher interest expense due to higher interest rates.
Year-to-date Financial Results
Year-to-date reported net income was $462 million or $1.75 per common share, compared with a net income of $186 million or $0.73 per common share year-to-date in 2021. Year-to-date reported net income included a $132
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million after-tax MTM loss primarily at EES, compared to $369 million in 2021 and $7 million of NSP Maritime Link Inc. (“NSPML”) unrecoverable costs.
Year-to-date adjusted net income(1) was $601 million or $2.27 per common share, compared with $555 million or $2.17 per common share year-to-date in 2021.
Growth in year-to-date adjusted net income was primarily due to higher earnings contributions from Tampa Electric, PGS and Seacoast and the impact of a weaker CAD. These were partially offset by increased corporate costs due to the timing of long-term compensation and related hedges, the net impact of corporate foreign exchange hedges, increased preferred stock dividends and increased interest expense due to higher interest rates.
The impact of the unrealized losses on foreign exchange hedges, partially offset by the weakening of the CAD decreased net income by $12 million in Q3 2022 and year-to-date 2022, compared to the same periods in 2021. The weakening of the CAD increased adjusted net income by $7 million in Q3 2022 and $14 million year-to-date 2022, compared to the same periods in 2021. The impacts of the weakening CAD include the current quarter and year-to-date impacts of corporate foreign exchange hedges in the Other segment.
(1) See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” below for reconciliation to nearest GAAP measure.
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Consolidated Financial Review
The following table highlights significant changes in adjusted net income attributable to common shareholders from 2021 to 2022.
| For the millions of Canadian dollars |
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
| ||
| Adjusted net income – 2021 1,2 |
$ | 175 | $ | 555 | ||||
| Operating Unit Performance |
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| Increased earnings at Tampa Electric due to higher revenues as a result of rate increases effective January 2022 customer growth and the impact of a weakening CAD. These were partially offset by higher operating, maintenance and general expenses (“OM&G”), increased interest expense and higher depreciation. Year-over-year also increased due to favourable weather | 30 | 95 | ||||||
| Increased earnings at Nova Scotia Power (“NSPI”) driven by higher sales volumes, partially offset by increased OM&G primarily due to increased information technology, storm restoration and power generation expenses | 2 | 10 | ||||||
| Increased earnings at PGS due to the reversal of accumulated depreciation as a result of the rate case settlement and higher off-system sales, partially offset by higher OM&G. Year-over-year also increased due to customer growth | 3 | 8 | ||||||
| Increased earnings at Seacoast due to the commencement of a 34-year pipeline lateral lease in 2022 | 2 | 6 | ||||||
| Increased earnings at EES due to higher natural gas prices and volatility, which created profitable opportunities. Year-over-year increase offset by the positive margin impact of Winter Storm Uri in Q1 2021 | 16 | - | ||||||
| Corporate |
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| Increased OM&G, pre-tax due to the timing of long-term compensation and related hedges | (17) | (36) | ||||||
| Increased foreign exchange loss, pre-tax, primarily due to realized gains in 2021 on foreign exchange hedges entered into to hedge USD denominated operating unit earnings exposure | (6) | (19) | ||||||
| Increased preferred stock dividends due to issuance of preferred shares in 2021 | (2) | (11) | ||||||
| Increased interest expense, pre-tax, due to higher interest rates and increased total debt | (10) | (10) | ||||||
| Other Variances |
10 | 3 | ||||||
| Adjusted net income – 2022 1,2 |
$ | 203 | $ | 601 |
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, net of tax, and the impact of the NSPML unrecoverable costs.
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Segment Results and Non-GAAP Reconciliation
| For the | Three months ended September 30 |
Nine Months ended September 30 |
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| millions of Canadian dollars (except per share amounts) |
2022 | 2021 | 2022 | 2021 | ||||||||||||
| Adjusted net income 1,2 |
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| Florida Electric Utility |
$ | 199 | $ | 169 | $ | 472 | $ | 377 | ||||||||
| Canadian Electric Utilities3 |
39 | 42 | 176 | 174 | ||||||||||||
| Gas Utilities and Infrastructure |
33 | 29 | 149 | 143 | ||||||||||||
| Other Electric Utilities4 |
12 | 8 | 21 | 15 | ||||||||||||
| Other 4,5 |
(80) | (73) | (217) | (154) | ||||||||||||
| Adjusted net income1,2 |
$ | 203 | $ | 175 | $ | 601 | $ | 555 | ||||||||
| MTM loss, after-tax6 |
(36) | (245) | (132) | (369) | ||||||||||||
| NSPML unrecoverable costs7 |
- | - | (7) | - | ||||||||||||
| Net income (loss) attributable to common shareholders |
$ | 167 | $ | (70) | $ | 462 | $ | 186 | ||||||||
| Earnings (loss) per share (basic) |
$ | 0.63 | $ | (0.27) | $ | 1.75 | $ | 0.73 | ||||||||
| Adjusted Earnings per share (basic) 1,2 |
$ | 0.76 | $ | 0.68 | $ | 2.27 | $ | 2.17 | ||||||||
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.
3 Excludes the impact of the NSPML unrecoverable costs.
4 Excludes the effect of MTM adjustments.
5 Primarily due to timing of long-term compensation and related hedges, higher foreign exchange expense largely driven by realized gains on foreign exchange hedges in 2021, increased preferred share financing costs and higher interest expense.
6 Net of income tax recovery of $14 million for the three months ended September 30, 2022 (2021 - $100 million recovery) and $51 million recovery for the nine months ended September 30, 2022 (2021 - $149 million recovery).
7 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 earnings per common share – basic, refer to the “Non-GAAP Financial Measures and Ratios” section of the Emera’s Q3 2022 MD&A which is incorporated herein by reference and can be found on SEDAR at www.sedar.com. 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.sedar.com.
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Teleconference Call
The company will be hosting a teleconference today, Friday, November 11, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q3 2022 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 $40 billion in assets and 2021 revenues of more than $5.7 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.sedar.com.
Emera Inc.
Investor Relations
Dave Bezanson, VP, Investor Relations & Pensions
902-474-2126
dave.bezanson@emera.com
Arianne Amirkhalkhali, Manager, Investor Relations
902-425-8130
arianne.amirkhalkhali@emera.com
Media
902-222-2683
media@emera.com
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