Exhibit 99.1
Management’s Discussion & Analysis
As at May 12, 2023
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments during the first quarter of 2023 relative to the same quarter in 2022; and its financial position as at March 31, 2023 relative to December 31, 2022. Throughout this discussion, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.
This discussion and analysis should be read in conjunction with the Emera Incorporated unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2023; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2022. Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR at www.sedar.com.
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 March 31, 2023, Emera’s rate-regulated subsidiaries and investments include:
| Emera Rate-Regulated Subsidiary or Equity Investment | Accounting Policies Approved/Examined By | |
| Subsidiary | ||
| Tampa Electric Company (“TEC”) (1) | Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”) | |
| Nova Scotia Power Inc. (“NSPI”) | Nova Scotia Utility and Review Board (“UARB”) | |
| Peoples Gas Systems, Inc. (“PGS”) (1) | FPSC | |
| New Mexico Gas Company, Inc. (“NMGC”) | New Mexico Public Regulation Commission (“NMPRC”) | |
| SeaCoast Gas Transmission, LLC (“SeaCoast”) | FPSC | |
| Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) | Canadian Energy Regulator (“CER”) | |
| Barbados Light & Power Company Limited (“BLPC”) | Fair Trading Commission, Barbados (“FTC”) | |
| Grand Bahama Power Company Limited (“GBPC”) | The Grand Bahama Port Authority (“GBPA”) | |
| Equity Investments | ||
| NSP Maritime Link Inc. (“NSPML”) | UARB | |
| Labrador Island Link Limited Partnership (“LIL”) | Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”) | |
| Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”) | CER and FERC | |
| St. Lucia Electricity Services Limited (“Lucelec”) | National Utility Regulatory Commission (“NURC”) |
(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility was reorganized, resulting in a separate legal entity called Peoples Gas System, Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States dollars (“USD”) unless otherwise stated.
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TABLE OF CONTENTS
Forward-looking Information | 2 | |
Introduction and Strategic Overview | 3 | |
Non-GAAP Financial Measures and Ratios | 4 | |
Consolidated Financial Review | 6 | |
Significant Items Affecting Earnings | 6 | |
Consolidated Financial Highlights | 6 | |
Consolidated Income Statement Highlights | 7 | |
Business Overview and Outlook | 9 | |
Florida Electric Utility | 9 | |
Canadian Electric Utilities | 10 | |
Gas Utilities and Infrastructure | 12 | |
Other Electric Utilities | 12 | |
Other | 13 | |
Consolidated Balance Sheet Highlights | 13 | |
Financial Highlights | 14 | |
Florida Electric Utility | 14 | |
Canadian Electric Utilities | 14 | |
Gas Utilities and Infrastructure | 16 |
Other Electric Utilities | 17 | |
Other | 17 | |
Liquidity and Capital Resources | 19 | |
Consolidated Cash Flow Highlights | 19 | |
Contractual Obligations | 21 | |
Debt Management | 22 | |
Guarantees and Letters of Credit | 23 | |
Outstanding Stock Data | 23 | |
Transactions with Related Parties | 23 | |
Risk Management including Financial Instruments | 24 | |
Disclosure and Internal Controls | 25 | |
Critical Accounting Estimates | 25 | |
Changes in Accounting Policies and Practices | 25 | |
Future Accounting Pronouncements | 25 | |
Summary of Quarterly Results | 26 |
FORWARD-LOOKING INFORMATION
This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, carbon dioxide emissions reduction goals, business prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.
The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; future dividend growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology (“IT”) infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus pandemic; market energy sales prices; labour relations; and availability of labour and management resources.
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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.
The majority of Emera’s investments in rate-regulated businesses are located in Florida with other investments in Nova Scotia, New Mexico and the Caribbean. Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.
Emera’s capital investment plan is $8 – 9 billion over the 2023-to-2025 period, mainly focused in Florida. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2025. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization, and customer-focused technologies. Emera’s capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan (“DRIP”) and at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a priority of the Company.
Emera has provided annual dividend growth guidance of four to five per cent through 2025. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.
Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market (“MTM”) adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income and cash flows are impacted by movements in the USD relative to the CAD. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.
Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, digitization, decarbonization, complex regulatory environments, and decentralized generation.
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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 will play a role in all of these trends. Emera’s strategy is to fund investments in renewable energy and technology assets which protect the environment and benefit customers through fuel or operating cost savings.
For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, and the ongoing construction of solar generation and modernization of the Big Bend Power Station at TEC. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of safely delivering cleaner, reliable, and affordable energy for its customers.
Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.
This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a clear path to Emera’s interim carbon goals. With existing technologies and resources, and subject to supportive government and regulatory decisions, Emera is working to achieve the following goals compared to corresponding 2005 levels:
| • | A 55 per cent reduction in carbon dioxide emissions by 2025. |
| • | The retirement of Emera’s last existing coal unit no later than 2040. |
| • | An 80 per cent reduction in carbon dioxide emissions by 2040. |
Achieving the above climate goals on these timelines is subject to the Company’s regulatory obligations and other external factors beyond Emera’s control.
Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.
Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships.
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures and ratios by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. These measures and ratios are discussed and reconciled below.
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Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per Common Share (“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the effect of MTM adjustments, and the impact of the 2022 NSPML unrecoverable costs.
Management believes excluding from net income the effect of MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows, and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:
| • | held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions; |
| • | the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income; |
| • | equity securities held in BLPC; and |
| • | FX hedges entered into to hedge USD denominated operating unit earnings exposure. |
For further detail on these MTM adjustments, refer to the “Consolidated Financial Review”, “Financial Highlights – Other Electric Utilities”, and “Financial Highlights – Other” sections.
In February 2022, the UARB issued a decision to disallow recovery of $9 million in costs ($7 million after-tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were recognized in “Income from equity investments” in Emera’s Condensed Consolidated Statements of Income. Management believes excluding these unrecoverable costs from the calculation of adjusted net income better reflects the underlying operations in the period. For further details on the 2022 NSPML unrecoverable costs, refer to the “Financial Highlights – Canadian Electric Utilities” section.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in Emera’s 2022 Annual MD&A.
Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial Highlights – Canadian Electric Utilities”, “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.
The following reconciles net income attributable to common shareholders to adjusted net income:
| For the | Three months ended March 31 | |||||||
| millions of dollars (except per share amounts) | 2023 | ��2022 | ||||||
| Net income attributable to common shareholders | $ | 560 | $ | 362 | ||||
| MTM gain, after-tax (1) | 292 | 127 | ||||||
| NSPML unrecoverable costs (2) | - | (7) | ||||||
| Adjusted net income | $ | 268 | $ | 242 | ||||
| EPS – basic | $ | 2.07 | $ | 1.38 | ||||
| Adjusted EPS – basic | $ | 0.99 | $ | 0.92 | ||||
(1) Net of income tax expense of $119 million for the three months ended March 31, 2023 (2022 – $54 million expense).
(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.
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EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA are non-GAAP financial measures used by Emera. These financial measures are used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital, and finance working capital requirements.
Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments and the 2022 NSPML unrecoverable costs.
The following is a reconciliation of net income to EBITDA and Adjusted EBITDA:
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2023 | 2022 | ||||||
| Net income (1) | $ | 576 | $ | 378 | ||||
| Interest expense, net | 226 | 156 | ||||||
| Income tax expense | 162 | 95 | ||||||
| Depreciation and amortization | 256 | 230 | ||||||
| EBITDA | $ | 1,220 | $ | 859 | ||||
| MTM gain, excluding income tax | 411 | 181 | ||||||
| NSPML unrecoverable costs (2) | - | (7) | ||||||
| Adjusted EBITDA | $ | 809 | $ | 685 | ||||
(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.
(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in “Income from equity investments” on Emera’s Condensed Consolidated Statements of Income.
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Earnings
Earnings Impact of After-Tax MTM Gains
MTM gains, after-tax, increased $165 million to $292 million in Q1 2023 compared to $127 million in Q1 2022 due to favourable changes in existing positions at Emera Energy, partially offset by higher amortization of gas transportation assets at Emera Energy.
Consolidated Financial Highlights
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2023 | 2022 | ||||||
| Adjusted Net Income | ||||||||
| Florida Electric Utility | $ | 107 | $ | 112 | ||||
| Canadian Electric Utilities | 92 | 98 | ||||||
| Gas Utilities and Infrastructure | 94 | 77 | ||||||
| Other Electric Utilities | 4 | 1 | ||||||
| Other | (29) | (46) | ||||||
| Adjusted net income | $ | 268 | $ | 242 | ||||
| MTM gain, after-tax | 292 | 127 | ||||||
| NSPML unrecoverable costs | - | (7) | ||||||
| Net income attributable to common shareholders | $ | 560 | $ | 362 | ||||
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The following table highlights significant changes in adjusted net income from 2022 to 2023.
| For the | Three months ended | |||||||
| millions of dollars | March 31 | |||||||
| Adjusted net income – 2022 | $ 242 | |||||||
| Operating Unit Performance | ||||||||
| Increased earnings at Emera Energy Services (“EES”) reflecting favourable hedging opportunities, more available gas transport due to mild winter, weather driven price and volatility spikes, and timing of recognition of transport and other costs | 29 | |||||||
| Increased earnings at NMGC due to higher asset optimization revenues and new base rates | 20 | |||||||
| Decreased earnings at TEC due to higher interest expense and increased operating, maintenance and general expenses (“OM&G”), partially offset by new base rates and the impact of a weaker CAD | (5) | |||||||
| Corporate | ||||||||
| Decreased OM&G, pre-tax, due to timing of long-term compensation and related hedges | 9 | |||||||
| Increased interest expense, pre-tax, due to higher interest rates and increased total debt | (24) | |||||||
| Other Variances | (3) | |||||||
| Adjusted net income – 2023 | $ 268 | |||||||
For further details of reportable segment contributions, refer to the “Financial Highlights” section.
| For the | Three months ended March 31 | |||||||||
| millions of dollars | 2023 | 2022 | ||||||||
| Operating cash flow before changes in working capital | $ | 654 | $ | 482 | ||||||
| Change in working capital | (201) | 119 | ||||||||
| Operating cash flow | $ | 453 | $ | 601 | ||||||
| Investing cash flow | $ | (640) | $ | (513) | ||||||
| Financing cash flow | $ | 153 | $ | (98) | ||||||
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
| As at | March 31 | December 31 | ||||||||
| millions of dollars | 2023 | 2022 | ||||||||
| Total assets | $ | 38,817 | $ | 39,742 | ||||||
| Total long-term debt (including current portion) | $ | 16,489 | $ | 16,318 | ||||||
Consolidated Income Statement Highlights
| For the | Three months ended March 31 | |||||||||||
| millions of dollars (except per share amounts) | 2023 | 2022 | Variance | |||||||||
| Operating revenues | $ | 2,433 | $ | 2,015 | $ | 418 | ||||||
| Operating expenses | 1,539 | 1,436 | (103) | |||||||||
| Income from operations | $ | 894 | $ | 579 | $ | 315 | ||||||
| Interest expense, net | $ | 226 | $ | 156 | $ | (70) | ||||||
| Net income attributable to common shareholders | $ | 560 | $ | 362 | $ | 198 | ||||||
| Adjusted net income | $ | 268 | $ | 242 | $ | 26 | ||||||
| Weighted average shares of common stock outstanding (in millions) | 270.7 | 261.8 | 8.9 | |||||||||
| EPS – basic | $ | 2.07 | $ | 1.38 | $ | 0.69 | ||||||
| EPS – diluted | $ | 2.07 | $ | 1.38 | $ | 0.69 | ||||||
| Adjusted EPS – basic | $ | 0.99 | $ | 0.92 | $ | 0.07 | ||||||
| Dividends per common share declared | $ | 0.6900 | $ | 0.6625 | $ | 0.0275 | ||||||
| Adjusted EBITDA | $ | 809 | $ | 685 | $ | 124 | ||||||
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Operating Revenues
For Q1 2023, operating revenues increased $418 million compared to Q1 2022 and, absent increased MTM gains of $217 million, increased $201 million. The increase was due to the impact of a weaker CAD; higher fuel revenues at NMGC and TEC; new base rates at TEC, NSPI and NMGC; increased marketing and trading margin at EES reflecting favourable hedging opportunities, more available gas transport due to mild winter, weather driven price and volatility spikes and timing of recognition of transport and other costs; and higher asset optimization revenue at NMGC. These increases were partially offset by lower sales volumes at NSPI and lower fuel revenue at PGS.
Operating Expenses
For Q1 2023, operating expenses increased $103 million compared to Q1 2022. This increase was due to the impact of a weaker CAD; increased OM&G at TEC and NSPI; higher fuel expenses at NSPI, NMGC and TEC; and higher depreciation and amortization at TEC.
Interest Expense, Net
For Q1 2023, interest expense, net increased $70 million compared to Q1 2022 due to higher interest rates; higher borrowings to support capital investments and ongoing operations; and the impact of a weaker CAD.
Net Income and Adjusted Net Income
For Q1 2023, the increase in net income attributable to common shareholders, compared to Q1 2022, was favourably impacted by the $165 million increase in after-tax MTM gains and the $7 million in NSPML unrecoverable costs recognized in 2022. Absent these changes, adjusted net income increased $26 million. The increase was primarily due to higher earnings contribution from EES and NMGC; the impact of a weaker CAD; and decreased Corporate OM&G due to timing of long-term compensation and related hedges. These were partially offset by increased interest expense due to higher interest rates and increased total debt and lower earnings contributions from TEC.
Earnings and Adjusted EPS – Basic
Earnings and Adjusted EPS – basic were higher for Q1 2023 compared to Q1 2022 due to increased earnings as discussed above, partially offset by the impact of the increase in weighted average shares outstanding.
Effect of Foreign Currency Translation
Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2022 annual MD&A.
The relevant CAD/USD exchange rates for 2023 and 2022 are as follows:
| Three months ended | Year ended | |||||||||||
| March 31 | December 31 | |||||||||||
| 2023 | 2022 | 2022 | ||||||||||
| Weighted average CAD/USD | $ | 1.34 | $ | 1.27 | $ | 1.34 | ||||||
| Period end CAD/USD exchange rate | $ | 1.35 | $ | 1.25 | $ | 1.35 | ||||||
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The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency.
| For the | Three months ended March 31 | |||||||
| millions of USD | 2023 | 2022 | ||||||
| Florida Electric Utility | $ | 79 | $ | 88 | ||||
| Gas Utilities and Infrastructure (1) | 65 | 58 | ||||||
| Other Electric Utilities | 3 | 1 | ||||||
| Other segment (2) | 7 | (12) | ||||||
| Total (3) | $ | 154 | $ | 135 | ||||
(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 $232 million in MTM gains, after-tax for the three months ended March 31, 2023 (2022 – $103 million MTM gains, after-tax).
The impact of the weakening CAD increased net income by $34 million and increased adjusted net income by $12 million in Q1 2023 compared to the same period in 2022. Impacts of the weakening CAD include the impacts of corporate FX hedges in the Other segment.
BUSINESS OVERVIEW AND OUTLOOK
There have been no material changes in Emera’s business overview and outlook from the Company’s 2022 annual MD&A other than the updates as disclosed below. For details on Emera’s reportable segments, refer to note 1 of the Q1 2023 unaudited condensed consolidated interim financial statements.
Florida Electric Utility
TEC anticipates earning within its ROE range in 2023. New base rates effective January 1, 2023, as a result of the 2021 settlement agreement, will result in higher 2023 USD earnings than in 2022. Normalizing 2022 for weather, TEC sales volumes in 2023 are projected to be higher than in 2022 due to customer growth. TEC expects customer growth rates in 2023 to be comparable to 2022, reflective of the current expected economic growth in Florida.
On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, and were effective beginning on April 1, 2023.
On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the previous approved storm reserve level of $56 million USD, for a total of approximately $131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge on April 2023 bills. The storm recovery is subject to review of the underlying costs for prudency by the FPSC. The review is expected to be completed by the end of 2023.
In 2023, capital investment in the Florida Electric Utility segment is expected to be $1.4 billion USD (2022 – $1.1 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, grid modernization and storm hardening investments.
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Canadian Electric Utilities
NSPI
NSPI anticipates earning near the low end of its allowed ROE range in 2023 and expects earnings and sales volumes to be higher in 2023 than 2022.
Energy from renewable sources has increased due to the improved delivery of the NS Block of energy from Nalcor Energy’s (“Nalcor”) Muskrat Falls hydroelectric project (“Muskrat Falls”) to NSPI. For more information on the commissioning of LIL, refer to the “LIL” section below. For more information related to Nalcor’s delivery obligations of the NS Block of energy and the option for NSPI to purchase additional market-priced energy, refer to the “Business Overview and Outlook – Canadian Electric Utilities” section of Emera’s 2022 annual MD&A.
On March 27, 2023, the UARB issued its final order approving the new electricity rates related to the General Rate Application settlement agreement between NSPI, key customer representatives and participating interest groups. The new electricity rates were effective on February 2, 2023.
In 2023, NSPI’s capital investment is expected to be approximately $405 million (2022 – $540 million), including AFUDC. NSPI is investing primarily in capital projects required to support power system reliability and reliable service for customers.
Environmental Legislation and Regulation
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia (the “Province”). For further discussion on environmental legislation and regulations and associated risks, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Enterprise Risk and Risk Management” sections respectively of Emera’s 2022 annual MD&A. Recent developments related to provincial and federal environmental laws and regulations are outlined below.
Nova Scotia Cap-and-Trade Program Regulations:
On March 16, 2023, the Province amended the Nova Scotia Cap-and-Trade Program Regulations, providing NSPI with additional emissions allowances sufficient to achieve compliance for the 2019 through 2022 compliance period. Compliance costs accrued of $166 million related to the anticipated purchase of emissions credits were reversed in Q1 2023. Credits NSPI purchased from provincial auctions in the amount of $6 million will not be refunded and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-Trade Program.
Carbon Pricing Regulations:
In November 2022, the Province enacted amendments to the Environment Act which provided the framework for Nova Scotia to implement an output-based pricing system (“OBPS”) to comply with the federal government’s 2023 through 2030 carbon pollution pricing regulations, effective January 1, 2023. The federal government approved the Province’s proposed system, however the OBPS will be subject to an interim review by the federal government of the standards effective for 2026. Although subsequent provincial regulations are required to detail exactly how the OBPS will operate, the Province has shared preliminary standards to facilitate regulatory and legal filings for NSPI. The OBPS implements greenhouse gas (“GHG”) emissions performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023 and will increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI’s fuel adjustment mechanism (“FAM”).
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Nova Scotia Renewable Electricity Regulations (“RER”):
On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER compliance period ending in 2022. The penalty was recorded in OM&G on the Condensed Consolidated Statements of Income. NSPI intends to appeal the penalty through a proceeding with the UARB, as permitted under the RER.
Performance Standards Penalty Amendment:
On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-compliance with current and future performance standards in a calendar year from $1 million to $25 million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot recover administrative penalties imposed through rates.
Emera Newfoundland & Labrador Holdings Inc. (“ENL”)
Total equity earnings from NSPML and LIL are expected to be higher in 2023, compared to 2022. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.
NSPML
In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023, subject to a holdback of up to $2 million a month. As of March 31, 2023, $18 million ($14 million related to 2022 and $4 million related to 2023) in aggregate has been held back by NSPI, which represents the total holdback for the nine months in which NSPML did not achieve the 90 per cent required delivery of the NS Block. Determination of allocation of the $18 million between NSPML or to NSPI’s FAM for the benefit of customers is subject to a regulatory process before the UARB, which commenced in March 2023. A decision from the UARB on the holdback is expected later in 2023. For more information on the commissioning of LIL, refer to the “LIL” section below.
NSPML does not anticipate any significant capital investment in 2023.
LIL
ENL is a limited partner with Nalcor in the LIL. Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canada’s Independent Engineer issuance of its Commissioning Certificate on April 14, 2023.
Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE of 8.5 per cent. Emera’s current equity investment is $755 million, comprised of $410 million in equity contribution and $345 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million once the final costing has been confirmed by Nalcor to determine the investment true-up.
Upon issuance of the Commissioning Certificate, AFUDC earnings have ceased and in turn cash earnings and return of equity to Emera have commenced.
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Gas Utilities and Infrastructure
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2023 than 2022, primarily due to a base rate increase at NMGC.
PGS expects 2023 rate base growth to be consistent with 2022, with slightly lower USD earnings as a result of higher costs driven by customer growth and the effect of inflation, which will more than offset higher revenue from new customers. PGS expects to earn below its allowed ROE range in 2023 primarily due to rate base growth and macroeconomic impacts, such as inflation and interest costs.
On April 4, 2023, PGS filed a rate case with the FPSC for new rates to become effective January 2024. PGS requested a $139 million USD increase in annual base rates, including $11 million USD from the cast iron and bare steel replacement rider. This reflects an 11 per cent midpoint ROE. The hearing for the matter is expected to be held in Q3 2023 with a final decision expected by the FPSC in Q4 2023.
The 2020 PGS rate case settlement provides the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. PGS has reversed $19 million USD accumulated depreciation through March 31, 2023, including $14 million USD reversed in 2022. The reversal of the remaining accumulated depreciation is expected to occur by December 31, 2023.
NMGC expects 2023 rate base and USD earnings to be higher in 2023 than 2022 primarily due to base rate increases effective January 2023. NMGC anticipates earning near its authorized ROE in 2023 and expects customer growth rates to be consistent with historical trends.
In 2023, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $500 million USD (2022 – $436 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will continue to make investments to maintain the safety and reliability of its system and support customer growth.
Other Electric Utilities
Absent the impact of the GBPC impairment charge in Q4 2022, Other Electric Utilities’ USD earnings in 2023 are expected to increase over the prior year primarily as a result of higher earnings due to higher base rates at BLPC.
On October 4, 2021 BLPC submitted a general rate review application to the FTC. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities related to the self-insurance fund of $50 million USD and prior year benefits recognized on remeasurement of deferred income taxes of $5 million USD, and a regulatory asset related to accumulated depreciation of $11 million USD. The FTC also requested a compliance filing before setting final rates which was submitted by BLPC on March 8, 2023. On March 7, 2023, BLPC filed a Motion for Review and Variation of FTC’s decision and applied for a Stay of the Decision. The FTC has determined that it will hear the Motion for Review by way of an oral hearing and parties have been invited to submit and exchange written submissions on these matters during Q2 2023. The final impacts to BLPC’s rate base and final rates are not yet determinable and have not been recorded but management does not expect the final decision to have a material impact on Emera’s adjusted net income. BLPC expects a decision on final rates from the FTC in 2023.
In 2023, capital investment in the Other Electric Utilities segment is expected to be approximately $65 million USD (2022 – $48 million USD).
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Other
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million USD of margin). Despite the Q1 2023 results, EES is maintaining its 2023 earnings guidance as transport and storage costs for the remainder of the year are expected to be higher than previous years.
Absent the TECO Guatemala Holdings (“TGH”) award in Q4 2022, the adjusted net loss from the Other segment is expected to be higher in 2023 due to increased interest expense, partially offset by decreased Corporate OM&G and decreased taxes due to a higher net loss. For details on the TGH award refer to the “Significant Items Affecting Earnings” section in Emera’s 2022 annual MD&A.
The Other segment does not anticipate any significant capital investment in 2023.
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2022 and March 31, 2023 include:
| millions of dollars | Increase (Decrease) | Explanation | ||||
| Assets | ||||||
| Derivative instruments (current and long-term) | $ | (115) | Decreased due to lower commodity prices and settlement of derivative instruments at NSPI | |||
| Regulatory assets (current and long-term) | (201) | Decreased due to lower FAM deferrals mainly due to the reversal of accrued Cap-and-Trade emissions compliance charges at NSPI and higher fuel clause recoveries at TEC | ||||
| Receivables and other assets (current and long-term) | (786) | Decreased due to lower cash collateral and lower trade receivables as a result of lower commodity prices at Emera Energy, settlement of the gas hedge receivable at NMGC, and seasonal trends of the business at NMGC and NSPI | ||||
| Property, Plant and Equipment (“PP&E”), net of accumulated depreciation and amortization | 368 | Increased due to capital additions in excess of depreciation and amortization | ||||
| Liabilities and Equity | ||||||
| Short-term debt and long-term debt (including current portion) | $ | 278 | Issuance of debt, partially offset by net repayments under committed credit facilities at NSPI | |||
| Accounts payable | (721) | Decreased due to lower commodity prices at Emera Energy, TEC and NMGC, timing of payments at TEC and NSPI, and decreased cash collateral position on derivative instruments at NSPI | ||||
| Deferred income tax liabilities, net of deferred income tax assets | 186 | Increased due to tax deductions in excess of accounting depreciation related to PP&E and changes in derivative instruments | ||||
| Derivative instruments (current and long-term) | (598) | Decreased due to reversal of 2022 contracts and changes in existing positions at Emera Energy, partially offset by new contracts in 2023 | ||||
| Regulatory liabilities (current and long-term) | (295) | Decreased due to settlement of the NMGC gas hedges and decreased deferrals related to derivative instruments at NSPI | ||||
| Other liabilities (current and long-term) | (81) | Decreased due to the reversal of accrued Cap-and-Trade emissions compliance charges at NSPI, partially offset by timing of interest payments on long-term debt at Corporate | ||||
| Common stock | 77 | Increased due to shares issued under the DRIP | ||||
| Retained earnings | 374 | Increased due to net income in excess of dividends paid | ||||
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FINANCIAL HIGHLIGHTS
Florida Electric Utility
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended March 31 | |||||||
| millions of USD (except as indicated) | 2023 | 2022 | ||||||
| Operating revenues – regulated electric | $ | 552 | $ | 510 | ||||
| Regulated fuel for generation and purchased power | $ | 146 | $ | 136 | ||||
| Contribution to consolidated net income | $ | 79 | $ | 88 | ||||
| Contribution to consolidated net income – CAD | $ | 107 | $ | 112 | ||||
| Electric sales volumes (Gigawatt hours (“GWh”)) | 4,474 | 4,473 | ||||||
| Electric production volumes (GWh) | 4,590 | 4,582 | ||||||
| Average fuel cost in dollars per megawatt hour (“MWh”) | $ | 32 | $ | 30 | ||||
The impact of the change in the FX rate increased CAD earnings for the three months ended March 31, 2023 by $6 million.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | |||
| millions of USD | March 31 | |||
| Contribution to consolidated net income – 2022 | $ 88 | |||
| Increased operating revenues primarily due to new base rates, customer growth, and higher recovery in fuel clause revenue | 42 | |||
| Increased fuel for generation and purchased power due to fuel under-recoveries in 2022 | (10) | |||
| Increased OM&G due to timing of deferred clause recoveries, higher transmission and distribution, generation maintenance, customer support and IT costs | (11) | |||
| Increased depreciation and amortization due to additions to facilities and the in-service of generation projects | (9) | |||
| Increased interest expense due to higher interest rates and higher borrowings to support capital investments and ongoing operations | (20) | |||
| Other | (1) | |||
| Contribution to consolidated net income – 2023 | $ 79 | |||
Canadian Electric Utilities
| For the | Three months ended March 31 | |||||||
| millions of dollars (except as indicated) | 2023 | 2022 | ||||||
| Operating revenues – regulated electric | $ | 504 | $ | 509 | ||||
| Regulated fuel for generation and purchased power (1) | $ | 103 | $ | 303 | ||||
| Contribution to consolidated adjusted net income | $ | 92 | $ | 98 | ||||
| NSPML unrecoverable costs | $ | - | $ | (7) | ||||
| Contribution to consolidated net income | $ | 92 | $ | 91 | ||||
| Electric sales volumes (GWh) | 3,131 | 3,191 | ||||||
| Electric production volumes (GWh) | 3,354 | 3,429 | ||||||
| Average fuel costs in dollars per MWh (2) | $ | 31 | $ | 88 | ||||
(1) Regulated fuel for generation and purchased power includes NSPI’s FAM deferral on the Condensed Consolidated Statements of Income, however it is excluded in the segment overview.
(2) Average fuel costs include the reversal of $166 million of the Nova Scotia Cap-and-Trade Program provision for the three months ended March 31, 2023 (2022 – $73 million expense)
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Canadian Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2023 | 2022 | ||||||
| NSPI | $ | 68 | $ | 71 | ||||
| Equity investment in LIL | 16 | 14 | ||||||
| Equity investment in NSPML (1) | 8 | 13 | ||||||
| Contribution to consolidated adjusted net income | $ | 92 | $ | 98 | ||||
(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the three months ended March 31, 2022.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | |||
| millions of dollars | March 31 | |||
| Contribution to consolidated net income – 2022 | $ 91 | |||
| Decreased operating revenues due to lower industrial sales volumes and unfavourable weather, partially offset by new rates and increased residential, commercial and other sales volumes | (5) | |||
| Decreased regulated fuel for generation and purchased power, primarily due to the reversal of the Nova Scotia Cap-and-Trade Program provision, compared to an expense in 2022. This is partially offset by increased commodity prices and the Nova Scotia’s OBPS carbon tax accrual | 200 | |||
| Decreased FAM deferral due to increased recovery of fuel costs at NSPI, primarily due to reversal of the Nova Scotia Cap-and-Trade Program provision | (182) | |||
| Increased OM&G due to recognition of the RER penalty at NSPI | (10) | |||
| Increased interest expense, net due to increased interest rates and higher debt levels | (11) | |||
| Decreased income from equity investments due to Maritime Link holdback in 2023, partially offset by higher AFUDC earnings in LIL | (3) | |||
| NSPML unrecoverable costs in 2022 | 7 | |||
| Decreased income tax expense at NSPI due to increased tax deductions in excess of accounting depreciation related to PP&E, partially offset by an increase in the benefit of tax loss carryforwards recognized as a deferred income tax regulatory liability | 7 | |||
| Other | (2) | |||
| Contribution to consolidated net income – 2023 | $ 92 | |||
The Nova Scotia Cap-and-Trade Program provision is related to the accrued cost of acquiring emissions credits for the 2019 through 2022 compliance period. As of December 31, 2022, NSPI had recognized a cumulative $166 million accrual in fuel costs related to the anticipated purchase of emissions credits and $6 million related to credits purchased from provincial auction. The compliance costs of $166 million were reversed in Q1 2023 and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-Trade Program. For further information on the reversal of this non-cash accrual and the FAM regulatory balance, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPI” section and note 6 in the Q1 2023 unaudited condensed consolidated interim financial statements.
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Gas Utilities and Infrastructure
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended March 31 | |||||||
| millions of USD (except as indicated) | 2023 | 2022 | ||||||
| Operating revenues – regulated gas (1) | $ | 422 | $ | 398 | ||||
| Operating revenues – non-regulated | 4 | 3 | ||||||
| Total operating revenue | $ | 426 | $ | 401 | ||||
| Regulated cost of natural gas | $ | 205 | $ | 202 | ||||
| Contribution to consolidated net income | $ | 70 | $ | 61 | ||||
| Contribution to consolidated net income – CAD | $ | 94 | $ | 77 | ||||
| Gas sales volumes (Therms) | 930 | 833 | ||||||
(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline for the three months ended March 31, 2023 (2022 – $11 million).
Gas Utilities and Infrastructure’s contribution is summarized in the following table:
| For the | Three months ended March 31 | |||||||
| millions of USD | 2023 | 2022 | ||||||
| NMGC | $ | 33 | $ | 19 | ||||
| PGS | 26 | 30 | ||||||
| Other | 11 | 12 | ||||||
| Contribution to consolidated net income | $ | 70 | $ | 61 | ||||
The impact of the change in the FX rate increased CAD earnings for the three months ended March 31, 2023, by $6 million.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | |||
| millions of USD | March 31 | |||
| Contribution to consolidated net income – 2022 | $ 61 | |||
| Increased gas operating revenues due to new base rates at NMGC, partially offset by lower fuel revenues and unfavourable weather at PGS | 14 | |||
| Increased asset optimization revenues at NMGC | 11 | |||
| Increased cost of natural gas due to higher prices in NMGC, partially offset by lower prices at PGS | (3) | |||
| Increased OM&G expenses primarily due to higher labour, contractor and material costs at PGS | (4) | |||
| Increased interest expense due to higher interest rates and increased borrowings to support ongoing operations and capital investments | (5) | |||
| Other | (4) | |||
| Contribution to consolidated net income – 2023 | $ 70 | |||
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Other Electric Utilities
All amounts are reported in USD, unless otherwise stated.
| For the | Three months ended March 31 | |||||||
| millions of USD (except as indicated) | 2023 | 2022 | ||||||
| Operating revenues – regulated electric | $ | 85 | $ | 94 | ||||
| Regulated fuel for generation and purchased power | $ | 42 | $ | 50 | ||||
| Contribution to consolidated adjusted net income | $ | 3 | $ | 1 | ||||
| Contribution to consolidated adjusted net income – CAD | $ | 4 | $ | 1 | ||||
| Equity securities MTM gain (loss) | $ | 1 | $ | (2) | ||||
| Contribution to consolidated net income (loss) | $ | 4 | $ | (1) | ||||
| Contribution to consolidated net income (loss) – CAD | $ | 6 | $ | (1) | ||||
| Electric sales volumes (GWh) | 283 | 307 | ||||||
| Electric production volumes (GWh) | 300 | 324 | ||||||
| Average fuel costs in dollars per MWh | 140 | 154 | ||||||
Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
| For the | Three months ended March 31 | |||||||
| millions of USD | 2023 | 2022 | ||||||
| GBPC | $ | 2 | $ | 2 | ||||
| BLPC | 2 | 2 | ||||||
| Other | (1) | (3) | ||||||
| Contribution to consolidated adjusted net income | $ | 3 | $ | 1 | ||||
The impact of the change in the FX rate on earnings in Q1 2023 was minimal.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | |||
| millions of USD | March 31 | |||
| Contribution to consolidated net income – 2022 | $ (1) | |||
| Decreased operating revenues due to the sale of Dominica Electricity Services Ltd. (“Domlec”) in Q1 2022 and lower fuel revenue at BLPC | (9) | |||
| Decreased regulated fuel for generation and purchased power due to changes in generation mix at BLPC and the sale of Domlec in Q1 2022 | 8 | |||
| Increased MTM gain on equity securities held at BLPC | 3 | |||
| Other | 3 | |||
| Contribution to consolidated net income – 2023 | $ 4 | |||
Other
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2023 | 2022 | ||||||
| Marketing and trading margin (1) (2) | $ | 95 | $ | 49 | ||||
| Other non-regulated operating revenue | 6 | 7 | ||||||
| Total operating revenues – non-regulated | $ | 101 | $ | 56 | ||||
| Contribution to consolidated adjusted net income (loss) | $ | (29) | $ | (46) | ||||
| MTM gain, after-tax (3) | 290 | 129 | ||||||
| Contribution to consolidated net income | $ | 261 | $ | 83 | ||||
(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a pre-tax MTM gain of $435 million for the three months ended March 31, 2023 (2022 – $190 million gain).
(3) Net of income tax expense of $119 million for the three months ended March 31, 2023 (2022 – $54 million expense).
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Other’s contribution to consolidated adjusted net income is summarized in the following table:
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2023 | 2022 | ||||||
| Emera Energy | $ | 56 | $ | 27 | ||||
| Corporate – see breakdown of adjusted contribution below | (80) | (67) | ||||||
| Block Energy LLC (1) | (4) | (5) | ||||||
| Other | (1) | (1) | ||||||
| Contribution to consolidated adjusted net income (loss) | $ | (29) | $ | (46) | ||||
(1) Previously named Emera Technologies LLC
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | |||
| millions of dollars | March 31 | |||
| Contribution to consolidated net income – 2022 | $ 83 | |||
| Increased marketing and trading margin reflecting favourable hedging opportunities, more available gas transport due to mild winter, weather driven price and volatility spikes, and timing of recognition of transport and other costs at Emera Energy | 46 | |||
| Decreased OM&G, pre-tax, primarily due to the timing of long-term compensation and related hedges | 9 | |||
| Increased interest expense, pre-tax, primarily due to increased interest rates and increased total debt | (24) | |||
| Decreased income tax recovery primarily due to decreased losses before provision for income taxes | (11) | |||
| Increased MTM gain, net of tax, primarily due to favourable changes in existing positions partially offset by higher amortization of gas transportation assets at Emera Energy | 161 | |||
| Other | (3) | |||
| Contribution to consolidated net income – 2023 | $ 261 | |||
Corporate
Corporate’s adjusted contribution is summarized in the following table:
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2023 | 2022 | ||||||
| Operating expenses (1) | $ | 6 | $ | 15 | ||||
| Interest expense | 89 | 65 | ||||||
| Income tax recovery | (26) | (21) | ||||||
| Preferred dividends | 16 | 16 | ||||||
| Other (2)(3) | (5) | (8) | ||||||
| Corporate adjusted net loss (4) | $ | (80) | $ | (67) | ||||
(1) Operating expenses include OM&G and depreciation.
(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings exposure.
(3) Includes a realized, pre-tax, net loss of $3 million on FX hedges ($2 million after-tax), as discussed above (2022 – nil).
(4) Excludes a MTM gain, after-tax, of $5 million for the three months ended March 31, 2023 (2022 – $1 million).
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LIQUIDITY AND CAPITAL RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include changes to global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity price changes on collateral requirements and timely recoveries of fuel costs from customers, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and maintain their credit metrics.
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has an $8 – 9 billion capital investment plan over the 2023-to-2025 period, mainly focused in Florida. This plan includes significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. Capital investments at the regulated utilities are subject to regulatory approval.
Emera plans to use cash from operations and debt raised at the utilities to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s DRIP and ATM program.
Emera has credit facilities with varying maturities that cumulatively provide $4.9 billion of credit, with approximately $1.5 billion undrawn and available at March 31, 2023. The Company was holding a cash balance of $302 million at March 31, 2023. For further discussion, refer to the “Debt Management” section below. For additional information regarding the credit facilities, refer to notes 18 and 19 in the Q1 2023 unaudited condensed consolidated interim financial statements.
Consolidated Cash Flow Highlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 2023 and 2022 include:
| millions of dollars | 2023 | 2022 | Change | |||||||||
| Cash, cash equivalents, and restricted cash, beginning of period | $ | 332 | $ | 417 | $ | (85) | ||||||
| Provided by (used in): | ||||||||||||
Operating cash flow before changes in working capital | 654 | 482 | 172 | |||||||||
Change in working capital | (201) | 119 | (320) | |||||||||
| Operating activities | $ | 453 | $ | 601 | $ | (148) | ||||||
| Investing activities | (640) | (513) | (127) | |||||||||
| Financing activities | 153 | (98) | 251 | |||||||||
| Effect of exchange rate changes on cash, cash equivalents, and restricted cash | 4 | (3) | 7 | |||||||||
| Cash, cash equivalents, and restricted cash, end of period | $ | 302 | $ | 404 | $ | (102) | ||||||
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Cash Flow from Operating Activities
Net cash provided by operating activities decreased $148 million to $453 million for the three months ended March 31, 2023, compared to $601 million for the same period in 2022.
Cash from operations before changes in working capital increased $172 million. This increase was due to decreased fuel for generation and purchased power expense driven by the decreased Nova Scotia Cap-and-Trade Program provision, higher recoveries in the fuel clause at TEC, increased marketing and trading margin at Emera Energy, and increased earnings at NMGC. This was partially offset by a decrease in regulatory liabilities due to the 2022 gas hedge settlements at NMGC.
Changes in working capital decreased operating cash flows by $320 million year-over-year. This decrease was due to unfavourable changes in cash collateral positions at NSPI, decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges, and the timing of accounts payable payments at NSPI and TEC. This was partially offset by favourable changes in accounts receivable at NMGC due to the receipt of the 2022 gas hedge settlement, and favourable changes in cash collateral positions at Emera Energy.
Cash Flow from Investing Activities
Net cash used in investing activities increased $127 million to $640 million for the three months ended March 31, 2023, compared to $513 million for the same period in 2022. The increase was due to higher capital investment in 2023.
Capital investments, including AFUDC, for the three months ended March 31, 2023, were $646 million compared to $533 million for the same period in 2022. Details of the 2023 capital investment by segment are shown below:
| ● | $347 million – Florida Electric Utility (2022 – $292 million); |
| ● | $115 million – Canadian Electric Utilities (2022 – $100 million); |
| ● | $170 million – Gas Utilities and Infrastructure (2022 – $125 million); |
| ● | $11 million – Other Electric Utilities (2022 – $15 million); and |
| ● | $3 million – Other (2022 – $1 million). |
Cash Flow from Financing Activities
Net cash provided by financing activities increased $251 million to $153 million for the three months ended March 31, 2023, compared to cash used in financing activities of $98 million for the same period in 2022. This increase was due to proceeds from long-term debt at NSPI, and higher net proceeds from committed credit facilities at Emera. This was partially offset by higher repayments of committed credit facilities at NSPI, lower issuance of common stock, and higher repayments of short-term debt at NMGC.
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Contractual Obligations
As at March 31, 2023, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total | |||||||||||||||||||||
| Long-term debt principal | $ | 566 | 1,613 | 262 | 3,109 | 637 | 10,433 | $ | 16,620 | |||||||||||||||||||
| Interest payment obligations (1) | 648 | 723 | 675 | 586 | 490 | 7,340 | 10,462 | |||||||||||||||||||||
| Transportation (2) | 563 | 565 | 445 | 402 | 385 | 2,821 | 5,181 | |||||||||||||||||||||
| Purchased power (3) | 220 | 244 | 241 | 231 | 246 | 2,197 | 3,379 | |||||||||||||||||||||
| Fuel, gas supply and storage | 630 | 253 | 118 | 42 | 5 | 7 | 1,055 | |||||||||||||||||||||
| Capital projects | 570 | 153 | 4 | 1 | - | - | 728 | |||||||||||||||||||||
| Asset retirement obligations | 7 | 2 | 2 | 3 | 1 | 413 | 428 | |||||||||||||||||||||
| Pension and post-retirement obligations (4) | 29 | 30 | 30 | 82 | 59 | 170 | 400 | |||||||||||||||||||||
| Equity investment commitments (5) | 240 | - | - | - | - | - | 240 | |||||||||||||||||||||
| Other | 117 | 158 | 132 | 50 | 46 | 213 | 716 | |||||||||||||||||||||
| $ | 3,590 | $ | 3,741 | $ | 1,909 | $ | 4,506 | $ | 1,869 | $ | 23,594 | $ | 39,209 | |||||||||||||||
(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2023, including any expected required payment under associated swap agreements.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $141 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(3) Annual requirement to purchase electricity production from Independent Power Producers or other utilities over varying contract lengths.
(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
(5) Emera has a commitment to make equity contributions to the LIL. The commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be made later in 2023.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2022, the UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.
Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canada’s Independent Engineer issuance of its Commissioning Certificate on April 14, 2023.
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, 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.
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Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD, per the table below as at March 31, 2023.
| millions of dollars | Maturity | Credit Facilities | Utilized | Undrawn and Available | ||||||||||||
| Emera – Unsecured committed revolving credit facility | June 2027 | $ | 900 | $ | 362 | $ | 538 | |||||||||
| TEC (in USD) – Unsecured committed revolving credit facility | December 2026 | 800 | 784 | 16 | ||||||||||||
| NSPI – Unsecured committed revolving credit facility | December 2027 | 800 | 227 | 573 | ||||||||||||
| Emera – Unsecured non-revolving facility | December 2023 | 400 | 400 | - | ||||||||||||
| Emera – Unsecured non-revolving facility | August 2023 | 400 | 400 | - | ||||||||||||
| TEC (in USD) – Unsecured non-revolving facility | December 2023 | 400 | 400 | - | ||||||||||||
| TECO Finance (in USD) – Unsecured committed revolving credit facility | December 2026 | 400 | 315 | 85 | ||||||||||||
| NSPI – Unsecured non-revolving facility | July 2024 | 400 | 400 | - | ||||||||||||
| TEC (in USD) – Unsecured revolving facility | February 2024 | 200 | - | 200 | ||||||||||||
| NMGC (in USD) – Unsecured revolving credit facility | December 2026 | 125 | 2 | 123 | ||||||||||||
| NMGC (in USD) – Unsecured non-revolving facility | March 2024 | 80 | 80 | - | ||||||||||||
| Other (in USD) – Unsecured committed revolving credit facilities | Various | 21 | 8 | 13 | ||||||||||||
Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at March 31, 2023.
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On March 1, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit facility which matures on February 28, 2024. The credit facility contains customary representations and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term secured overnight financing rate (“SOFR”), the Bank of Nova Scotia’s prime rate, the federal funds rate or the one-month SOFR, plus a margin. Proceeds from this facility will be used for general corporate purposes.
On April 3, 2023, TEC entered into an additional 364-day, $200 million USD senior unsecured revolving credit facility which matures on April 1, 2024. The credit agreement contains customary representation and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term SOFR, Wells Fargo’s prime rate, the federal funds rate or the one-month SOFR, plus a margin. Proceeds from this facility will be used for general corporate purposes.
Canadian Electric Utilities
On March 24, 2023, NSPI issued $500 million in unsecured notes. The issuance included $300 million unsecured notes that bear interest at 4.95 per cent with a maturity date of November 15, 2032, and $200 million unsecured notes that bear interest at 5.36 per cent with a maturity date of March 24, 2053. Proceeds from these issuances were added to the general funds of the Company and applied primarily to refinance existing indebtedness, to finance capital investment and for general corporate purposes.
Other
On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent with a maturity date of May 2, 2030. The proceeds will be used to repay Emera’s $500 million unsecured fixed rate notes, due in 2023.
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Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2022 annual MD&A, with material updates as noted below:
NSPI renewed guarantees of $7 million USD with terms of varying lengths. As at March 31, 2023, NSPI had $101 million USD (2022 – $119 million USD) of guarantees outstanding, all issued on behalf of its subsidiary, NS Power Energy Marking Incorporated.
Outstanding Stock Data
Common Stock
| Issued and outstanding: | millions of shares | millions of dollars | ||||||
| Balance, December 31, 2022 | 269.95 | $ | 7,762 | |||||
| Issued under the DRIP, net of discounts | 1.31 | 69 | ||||||
| Senior management stock options exercised and Employee Share Purchase Plan | 0.16 | 8 | ||||||
| Balance, March 31, 2023 | 271.42 | $ | 7,839 | |||||
As at March 31, 2023, an aggregate gross sales limit of $207 million remained available for issuance under the ATM program.
As at May 9, 2023 the amount of issued and outstanding common shares was 271.7 million.
If all outstanding stock options were converted as at May 9, 2023, an additional 3.3 million common shares would be issued and outstanding.
Preferred Stock
As at May 9, 2023, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
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 $37 million for the three months ended March 31, 2023 (2022 – $34 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. |
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| ● | 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 March 31, 2023 (2022 – $4 million). |
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2023 and at December 31, 2022.
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2022 annual MD&A.
Derivatives Assets and Liabilities Recognized on the Balance Sheet
As at millions of dollars | March 31 2023 | December 31 2022 | ||||||
| Regulatory Deferral: | ||||||||
Derivative instrument assets (1) | $ | 84 | $ | 238 | ||||
Derivative instrument liabilities (2) | (40) | (25) | ||||||
Regulatory assets (1) | 45 | 30 | ||||||
Regulatory liabilities (2) | (84) | (230) | ||||||
| Net asset | $ | 5 | $ | 13 | ||||
| HFT Derivatives: | ||||||||
Derivative instrument assets (1) | $ | 178 | $ | 153 | ||||
Derivatives instruments liabilities (2) | (416) | (1,025) | ||||||
| Net liability | $ | (238) | $ | (872) | ||||
| Other Derivatives: | ||||||||
Derivative instrument assets (1) | $ | 19 | $ | 5 | ||||
Derivatives instruments liabilities (2) | (24) | (28) | ||||||
| Net liability | $ | (5) | $ | (23) | ||||
| (1) Current and other assets. |
| |||||||
| (2) Current and long-term liabilities. |
| |||||||
Realized and Unrealized Gains (Losses) Recognized in Net Income
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2023 | 2022 | ||||||
| Regulatory Deferral: | ||||||||
Regulated fuel for generation and purchased power (1) | $ | 66 | $ | 64 | ||||
| HFT Derivatives: | ||||||||
Non-regulated operating revenues | $ | 839 | $ | 190 | ||||
| Other Derivatives: | ||||||||
OM&G | $ | 11 | $ | (4) | ||||
Other income, net | 3 | 1 | ||||||
| Net gains (losses) | $ | 14 | $ | (3) | ||||
| Total net gains | $ | 919 | $ | 251 | ||||
(1) Realized gains on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.
As of March 31, 2023, the unrealized gain in accumulated other comprehensive income was $15 million, net of tax (2022 – $16 million, net of tax). For the three months ended March 31, 2023, unrealized gains of $1 million (2022 – $1 million), have been reclassified into interest expense.
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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 March 31, 2023, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.
There were no changes in the Company’s ICFR during the quarter ended March 31, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2022 annual MD&A.
CHANGES IN ACCOUNTING POLICIES AND PRACTICES
Future Accounting Pronouncements
The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). ASUs issued by FASB, but which are not yet effective, were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the unaudited condensed consolidated interim financial statements.
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SUMMARY OF QUARTERLY RESULTS
For the quarter ended millions of dollars | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | ||||||||||||||||||||||||
| (except per share amounts) | 2023 | 2022 | 2022 | 2022 | 2022 | 2021 | 2021 | 2021 | ||||||||||||||||||||||||
| Operating revenues | $ | 2,433 | $ | 2,358 | $ | 1,835 | $ | 1,380 | $ | 2,015 | $ | 1,868 | $ | 1,148 | $ | 1,137 | ||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 560 | $ | 483 | $ | 167 | $ | (67) | $ | 362 | $ | 324 | $ | (70) | $ | (17) | ||||||||||||||||
| Adjusted net income | $ | 268 | $ | 249 | $ | 203 | $ | 156 | $ | 242 | $ | 168 | $ | 175 | $ | 137 | ||||||||||||||||
| EPS – basic | $ | 2.07 | $ | 1.80 | $ | 0.63 | $ | (0.25) | $ | 1.38 | $ | 1.24 | $ | (0.27) | $ | (0.07) | ||||||||||||||||
| EPS – diluted | $ | 2.07 | $ | 1.80 | $ | 0.63 | $ | (0.25) | $ | 1.38 | $ | 1.20 | $ | (0.27) | $ | (0.07) | ||||||||||||||||
| Adjusted EPS – basic | $ | 0.99 | $ | 0.93 | $ | 0.76 | $ | 0.59 | $ | 0.92 | $ | 0.64 | $ | 0.68 | $ | 0.54 | ||||||||||||||||
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.
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