Exhibit 99.1
Management Discussion & Analysis Management of Algonquin Power & Utilities Corp. (“AQN”, “Company” or the
“Corporation”) has prepared the following discussion and analysis to provide information to assist its securityholders’ understanding of the financial results for the three and twelve months ended December 31, 2023. This Management Discussion
& Analysis (“MD&A”) should be read in conjunction with AQN’s annual consolidated financial statements for the years ended December 31, 2023 and 2022. This material is available on SEDAR+ at www.sedarplus.com, on EDGAR at www.sec.gov/edgar, and on the AQN website at www.AlgonquinPowerandUtilities.com. Additional information about AQN, including the most recent Annual Information Form (“AIF”), can be found on SEDAR+ at www.sedarplus.com and on
EDGAR at www.sec.gov/edgar.
Contents
| Explanatory Notes | |||||
| Caution Concerning Forward-Looking Statements and Forward-Looking Information | |||||
| Caution Concerning Non-GAAP Measures | |||||
| Overview and Business Strategy | |||||
| Significant Updates | |||||
|
2023 Fourth Quarter Results From Operations
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2023 Annual Results from Operations
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2023 Net Earnings Summary
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2023 Adjusted EBITDA Summary
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| Regulated Services Group | |||||
| Renewable Energy Group | |||||
| AQN: Corporate and Other Expenses | |||||
| Non-GAAP Financial Measures | |||||
| Summary of Property, Plant and Equipment Expenditures | |||||
| Liquidity and Capital Reserves | |||||
| Share-Based Compensation Plans | |||||
| Management of Capital Structure | |||||
| Related Party Transactions | |||||
| Enterprise Risk Management | |||||
| Quarterly Financial Information | |||||
| Summary Financial Information of Atlantica | |||||
| Disclosure Controls and Procedures | |||||
| Critical Accounting Estimates and Policies | |||||
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Explanatory Notes
Unless otherwise indicated, financial information provided for the years ended December
31, 2023 and 2022 has been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). As a result, the Company's financial information may not be comparable with financial information of other
Canadian companies that provide financial information on another basis.
All monetary amounts are in U.S. dollars, except where otherwise noted. We denote any
amounts denominated in Canadian dollars with "C$" immediately prior to the stated amount. Certain amounts in this MD&A may not total due to rounding.
Capitalized terms used herein and not otherwise defined have the meanings assigned to
them in the Company's most recent AIF.
The term “rate base” is used in this document. Rate base is a measure specific to
rate-regulated utilities that is not intended to represent any financial measure as defined by U.S. GAAP. The measure is used by the regulatory authorities in the jurisdictions where the Company’s rate-regulated subsidiaries operate. The
calculation of this measure may not be comparable to similarly-titled measures used by other companies.
Unless noted otherwise, this MD&A is based on information available to management as
of March 8, 2024.
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Caution Concerning Forward-Looking Statements and Forward-Looking Information
This document may contain statements that constitute "forward-looking information"
within the meaning of applicable securities laws in each of the provinces and territories of Canada and the respective policies, regulations and rules under such laws or "forward-looking statements" within the meaning of the U.S. Private
Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words "aims", “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”,
“schedule”, “should”, “will”, “would”, "seeks", "strives", "targets" (and grammatical variations of such terms) and similar expressions are often intended to identify forward-looking information, although not all forward-looking information
contains these identifying words. Specific forward-looking information in this document includes, but is not limited to, statements relating to: expected future growth, earnings and results of operations; the sale of the Corporation's renewable
energy business and the anticipated impact thereof on the Corporation; liquidity, capital resources and operational requirements; sources of funding, including adequacy and availability of credit facilities, cash flows from operations, capital
markets financing, and asset recycling or asset sales initiatives; ongoing and planned acquisitions, dispositions, projects, initiatives or other transactions, including expectations regarding timing, costs, proceeds, financing, results,
ownership structures, regulatory matters, in-service dates and completion dates; financing plans; expectations regarding future macroeconomic conditions; expectations regarding the Company's corporate development activities and the results
thereof; expectations regarding regulatory hearings, motions, filings, appeals and approvals, including rate reviews, and the timing, impacts and outcomes thereof; expectations regarding the exercise of the Company's purchase option in respect of
the remaining 50% interests in the Sandy Ridge II and Shady Oaks II Wind Facilities; expectations regarding the redemption of outstanding notes; expected future generation, capacity and production of the Company’s energy facilities; expectations
regarding future capital investments, including expected timing, investment plans, sources of funds and impacts; capital management plans and objectives; expectations regarding the outcome of legal claims and disputes; strategy and goals;
dividends to shareholders, including expectations regarding the sustainability thereof and the Company's ability to achieve its targeted annual dividend payout ratio; expectations regarding future "greening the fleet" initiatives; credit ratings
and equity credit from rating agencies, including expectations regarding the resolution of rating watches related to the intended sale of the Corporation’s renewable energy business; expectations regarding debt repayment and refinancing; the
future impact on the Company of actual or proposed laws, regulations and rules; the expected impact of changes in customer usage on the Regulated Services Group’s revenue; accounting estimates; interest rates, including the anticipated effect of
an increase thereof; the implementation of new technology systems and infrastructure, including the expected timing thereof; financing costs; and currency exchange rates. All forward-looking information is given pursuant to the “safe harbour”
provisions of applicable securities legislation.
The forecasts and projections that make up the forward-looking information contained
herein are based on certain factors or assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; the absence of material adverse regulatory decisions being received and the
expectation of regulatory stability; the absence of any material equipment breakdown or failure; availability of financing (including tax equity financing and self-monetization transactions for U.S. federal tax credits) on commercially reasonable
terms; the stability of credit ratings of the Corporation and its subsidiaries; the absence of unexpected material liabilities or uninsured losses; the continued availability of commodity supplies and stability of commodity prices; the absence of
interest rate increases or significant currency exchange rate fluctuations; the absence of significant operational, financial or supply chain disruptions or liability, including relating to import controls and tariffs; the continued ability to
maintain systems and facilities to ensure their continued performance; the absence of a severe and prolonged downturn in general economic, credit, social or market conditions; the successful and timely development and construction of new
projects; the closing of pending acquisitions substantially in accordance with the expected timing for such acquisitions; the absence of capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of
long-term weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the
Corporation’s acquisitions and joint ventures; the absence of a change in applicable laws, political conditions, public policies and directions by governments materially negatively affecting the Corporation; the ability to obtain and maintain
licenses and permits; maintenance of adequate insurance coverage; the absence of material fluctuations in market energy prices; the absence of material disputes with taxation authorities or changes to applicable tax laws; continued maintenance of
information technology infrastructure and the absence of a material breach of cybersecurity; the successful implementation of new information technology systems and infrastructure; favourable relations with external stakeholders; favourable
labour relations; that the Corporation will be able to successfully integrate newly acquired entities, and the absence of any material adverse changes to such entities prior to closing; the absence of undisclosed liabilities of entities being
acquired; that such entities will maintain constructive regulatory relationships with applicable regulatory authorities; the ability of the Corporation to retain key personnel of acquired entities and the value of such employees; no adverse
developments in the business and affairs of the sellers during the period when transitional services are provided to the Corporation in connection with any acquisition; the ability of the Corporation to satisfy its liabilities and meet its debt
service obligations following completion of any acquisition; and the ability of the Corporation to successfully execute future “greening the fleet” initiatives; and the ability of the Corporation to effect a sale of its renewable energy business
and realize the anticipated benefits therefrom.
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The forward-looking information contained herein 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 which could cause results or events to differ materially from current expectations
include, but are not limited to: changes in general economic, credit, social or market conditions; changes in customer energy usage patterns and energy demand; reductions in the liquidity of energy markets; global climate change; the incurrence
of environmental liabilities; natural disasters, diseases, pandemics, public health emergencies and other force majeure events and the collateral consequences thereof, including the disruption of economic activity, volatility in capital and
credit markets and legislative and regulatory responses; critical equipment breakdown or failure; supply chain disruptions; the imposition of import controls or tariffs; the failure of information technology infrastructure and other cybersecurity
measures to protect against data, privacy and cybersecurity breaches; failure to successfully implement, and cost overruns and delays in connection with, new information technology systems and infrastructure; physical security breach; the loss of
key personnel and/or labour disruptions; seasonal fluctuations and variability in weather conditions and natural resource availability; reductions in demand for electricity, natural gas and water due to developments in technology; reliance on
transmission systems owned and operated by third parties; issues arising with respect to land use rights and access to the Corporation’s facilities; terrorist attacks; fluctuations in commodity and energy prices; capital expenditures; reliance on
subsidiaries; the incurrence of an uninsured loss; a credit rating downgrade; an increase in financing costs or limits on access to credit and capital markets; inflation; increases and fluctuations in interest rates and failure to manage exposure
to credit and financial instrument risk; currency exchange rate fluctuations; restricted financial flexibility due to covenants in existing credit agreements; an inability to refinance maturing debt on favourable terms; disputes with taxation
authorities or changes to applicable tax laws; failure to identify, acquire, develop or timely place in service projects to maximize the value of tax credits; requirement for greater than expected contributions to post-employment benefit plans;
default by a counterparty; inaccurate assumptions, judgments and/or estimates with respect to asset retirement obligations; failure to maintain required regulatory authorizations; changes in, or failure to comply with, applicable laws and
regulations; failure of compliance programs; failure to identify attractive acquisition or development candidates necessary to pursue the Corporation’s growth strategy; failure to dispose of assets (at all or at a competitive price) to fund the
Company’s operations and growth plans; delays and cost overruns in the design and construction of projects; loss of key customers; failure to complete or realize the anticipated benefits of acquisitions or joint ventures; Atlantica (as defined
herein) or a third party joint venture partner acting in a manner contrary to the Corporation’s interests; a drop in the market value of Atlantica's ordinary shares; facilities being condemned or otherwise taken by governmental entities;
increased external stakeholder activism adverse to the Corporation’s interests; fluctuations in the price and liquidity of the Corporation’s common shares and the Corporation's other securities; impact of significant demands placed on the
Corporation as a result of pending acquisitions or growth strategies; potential undisclosed liabilities of any entities being acquired by the Corporation; uncertainty regarding the length of time required to complete pending acquisitions; the
failure to implement the Corporation’s strategic objectives or achieve expected benefits relating to acquisitions, dispositions or other initiatives, including with respect to the intended sale of the Corporation's renewable energy business; the
possibility of adverse reactions or changes in business relationships or relationships with employees resulting from the announcement or completion of the intended sale of the Corporation's renewable energy business; risks relating to the
diversion of the Board’s (as defined herein) or management’s attention in connection with the intended sale of the Corporation's renewable energy business; indebtedness of any entity being acquired by the Corporation; unanticipated expenses
and/or cash payments as a result of change of control and/or termination provisions in purchase or sale agreements; and the reliance on third parties for certain transitional services following the completion of an acquisition. Although the
Corporation has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking information, there may be other factors that cause actions, events or results
not to be as anticipated, estimated or intended. Some of these and other factors are discussed in more detail under the heading Enterprise Risk Management in this MD&A and under the heading Enterprise Risk Factors in the Corporation's most
recent AIF.
Forward-looking information contained herein (including any financial outlook) is
provided for the purposes of assisting the reader in understanding the Corporation and its business, operations, risks, financial performance, financial position and cash flows as at and for the periods indicated and to present information about
management’s current expectations and plans relating to the future, and the reader is cautioned that such information may not be appropriate for other purposes. Forward-looking information contained herein is made as of the date of this document
and based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management on the date hereof. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future
events could differ materially from those anticipated in such forward-looking information. Accordingly, readers should not place undue reliance on forward-looking information. While subsequent events and developments may cause the Corporation’s
views to change, the Corporation disclaims any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information, except to the extent required by
applicable law. All forward-looking information contained herein is qualified by these cautionary statements.
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Caution Concerning Non-GAAP Measures
AQN uses a number of financial measures to assess the performance of its business lines.
Some measures are calculated in accordance with U.S. GAAP, while other measures do not have a standardized meaning under U.S. GAAP. These non-GAAP measures include non-GAAP financial measures and non-GAAP ratios, each as defined in Canadian
National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. AQN’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to
similar measures presented by other companies.
The terms “Adjusted Net Earnings”, “Adjusted Earnings Before Interest, Taxes,
Depreciation and Amortization” (“Adjusted EBITDA”), “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit", which are used throughout this MD&A, are non-GAAP financial measures. An
explanation of each of these non-GAAP financial measures is set out below and a reconciliation to the most directly comparable U.S. GAAP measure, in each case, can be found in this MD&A. In addition, “Adjusted Net Earnings” is presented
throughout this MD&A on a per common share basis. Adjusted Net Earnings per common share is a non-GAAP ratio and is calculated by dividing Adjusted Net Earnings by the weighted average number of common shares outstanding during the applicable
period.
AQN does not provide reconciliations for forward-looking non-GAAP financial measures as
AQN is unable to provide a meaningful or accurate calculation or estimation of reconciling items and the information is not available without unreasonable effort. This is due to the inherent difficulty of forecasting the timing or amount of
various events that have not yet occurred, are out of AQN’s control and/or cannot be reasonably predicted, and that would impact the most directly comparable forward-looking U.S. GAAP financial measure. For these same reasons, AQN is unable to
address the probable significance of the unavailable information. Forward-looking non-GAAP financial measures may vary materially from the corresponding U.S. GAAP financial measures.
The compositions of Adjusted EBITDA, Adjusted Net Earnings, Adjusted Funds from
Operations, and Divisional Operating Profit have been changed from those previously disclosed in AQN’s MD&A for the three and twelve months ended December 31, 2022 to exclude gains and losses on disposition of assets. This change was made as
gains and losses on disposition of assets are no longer used by management to evaluate the operating performance of the Company. Comparative figures for these metrics have been adjusted for the new compositions.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure used by many investors to compare
companies on the basis of ability to generate cash from operations. AQN uses these calculations to monitor the amount of cash generated by AQN. AQN uses Adjusted EBITDA to assess the operating performance of AQN without the effects of (as
applicable): depreciation and amortization expense, income tax expense or recoveries, acquisition and transition costs (including costs related to the 2023 strategic review of the Company's renewable energy business), certain litigation expenses,
interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, earnings attributable to non-controlling interests exclusive of Hypothetical Liquidation at Book Value ("HLBV")
income (which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities), non-service pension and post-employment costs, cost related to tax
equity financing, costs related to management succession and executive retirement, costs related to
prior period adjustments due to changes in tax law, costs related to condemnation proceedings, gain or loss on foreign
exchange, earnings or loss from discontinued operations, changes in value of investments carried at fair value, gains and losses on disposition of assets, and other typically non-recurring or unusual items. AQN adjusts for these factors as they
may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the Company. AQN believes that presentation of this measure will enhance an investor’s understanding of AQN’s operating
performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a
reconciliation of Adjusted EBITDA to net earnings, see Non-GAAP Financial Measures starting on page 38 of this MD&A.
Adjusted Net Earnings
Adjusted Net Earnings is a non-GAAP financial measure used by many investors to compare
net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact or items such as acquisition expenses or certain litigation expenses that are viewed as not directly
related to a company’s operating performance. AQN uses Adjusted Net Earnings to assess its performance without the effects of (as applicable): gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps,
acquisition and transition costs (including costs related to the 2023 strategic review of the Company's renewable energy business), one-time costs of arranging tax equity financing, certain litigation expenses and write down of intangibles and
property, plant and equipment, earnings or loss from discontinued operations, unrealized mark-to-market revaluation impacts, costs related to management succession and executive retirement, costs related to prior period adjustments due to changes
in tax law, costs related to condemnation proceedings, changes in value of investments carried at fair value, gains and losses on disposition of assets, and other typically non-recurring or unusual items as these are not reflective of the
performance of the underlying business
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of AQN. AQN believes that analysis and presentation of net earnings or loss on this
basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Net Earnings is not intended to be representative of net earnings or loss determined in accordance with U.S. GAAP, and can be impacted
positively or negatively by these items. For a reconciliation of Adjusted Net Earnings to net earnings, see Non-GAAP Financial Measures starting
on page 39 of this MD&A.
Adjusted Funds from Operations
Adjusted Funds from Operations is a non-GAAP financial measure used by investors to
compare cash provided by operating activities without the effects of certain volatile items that generally have no current economic impact or items such as acquisition expenses that are viewed as not directly related to a company’s operating
performance. AQN uses Adjusted Funds from Operations to assess its performance without the effects of (as applicable): changes in working capital balances, acquisition and transition costs, certain litigation expenses, cash provided by or used in
discontinued operations, cash provided by disposition of assets and other typically non-recurring items affecting cash from operations as these are not reflective of the long-term performance of the underlying businesses of AQN. AQN believes that
analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Funds from Operations is not intended to be representative of cash provided by
operating activities as determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Adjusted Funds from Operations to cash provided by operating activities, see Non-GAAP Financial Measures starting on page 40 of this MD&A.
Net Energy Sales
Net Energy Sales is a non-GAAP financial measure used by investors to identify revenue
after commodity costs used to generate revenue where such revenue generally increases or decreases in response to increases or decreases in the cost of the commodity used to produce that revenue. AQN uses Net Energy Sales to assess its revenues
without the effects of fluctuating commodity costs as such costs are predominantly passed through either directly or indirectly in the rates that are charged to customers. AQN believes that analysis and presentation of Net Energy Sales on this
basis will enhance an investor’s understanding of the revenue generation of the Renewable Energy Group. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP. For a reconciliation of Net Energy Sales to
revenue, see Renewable Energy Group - 2023 Renewable Energy Group Operating Results on page 33 of this MD&A.
Net Utility Sales
Net Utility Sales is a non-GAAP financial measure used by investors to identify utility
revenue after commodity costs, either water, natural gas or electricity, where these commodity costs are generally included as a pass through in rates to its utility customers. AQN uses Net Utility Sales to assess its utility revenues without the
effects of fluctuating commodity costs as such costs are predominantly passed through and paid for by utility customers. AQN believes that analysis and presentation of Net Utility Sales on this basis will enhance an investor’s understanding of
the revenue generation of the Regulated Services Group. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP. For a reconciliation of Net Utility Sales to revenue, see Regulated Services Group - 2023 Regulated Services Group Operating Results on page 23 of this MD&A.
Divisional Operating Profit
Divisional Operating Profit is a non-GAAP financial measure. AQN uses Divisional
Operating Profit to assess the operating performance of its business groups without the effects of (as applicable): depreciation and amortization expense, corporate administrative expenses, income tax expense or recoveries, acquisition costs,
certain litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, gain or loss on foreign exchange, earnings or loss from discontinued operations (excluding the sale of assets in the course of normal operations), non-service pension and
post-employment costs, gains and losses on disposition of assets, and other typically non-recurring or unusual items. AQN adjusts for these factors as they may be non-cash,
unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of interest, dividend and equity income earned from indirect investments, and HLBV income. AQN believes that presentation of this measure will enhance an investor’s understanding of AQN’s divisional
operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP, and can be impacted positively or negatively by
these items. For a reconciliation of Divisional Operating Profit to revenue for AQN's main business units, see Regulated Services Group - 2023 Regulated Services Group Operating Results on page 23 and Renewable Energy Group - 2023
Renewable Energy Group Operating Results on page 33 of this MD&A.
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Overview and Business Strategy
AQN is incorporated under the Canada Business Corporations Act. AQN
owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission assets. Through its activities, the Company aims to drive growth in earnings and cash flows to support a sustainable dividend and
share price appreciation. AQN strives to achieve these results while also seeking to maintain a business risk profile consistent with its BBB flat investment grade credit ratings and a strong focus on Environmental, Social and Governance factors.
AQN's current quarterly dividend to shareholders is $0.1085 per common share, or $0.4340
per common share on an annualized basis. AQN believes that, on a long-term basis, its targeted annual dividend payout will allow for both a return on investment for shareholders and retention of cash within AQN to partially fund growth
opportunities. Changes in the level of dividends paid by AQN are at the discretion of AQN’s Board of Directors (the “Board”), with dividend levels being reviewed periodically by the Board in the context of AQN’s financial performance and growth
prospects.
AQN’s operations are organized across two primary business units consisting of: the
Regulated Services Group, which primarily owns and operates a portfolio of regulated electric, water distribution and wastewater collection and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and
Chile; and the Renewable Energy Group, which primarily owns and operates, or has investments in, a diversified portfolio of non-regulated renewable and thermal energy generation assets.
The Company is pursuing a sale of its renewable energy business. Due to the uncertainty
regarding whether, when and on what terms such a sale may be consummated, the Company is not providing 2024 Adjusted Net Earnings per Common Share guidance (see Caution Concerning Non-GAAP Measures).
Summary Structure of the Business
The following chart depicts, in summary form, AQN’s key businesses. A more detailed
description of AQN’s organizational structure can be found in the most recent AIF.
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Regulated Services Group
The Regulated Services Group primarily operates a diversified portfolio of regulated
utility systems located in the United States, Canada, Bermuda and Chile serving approximately 1,256,000 customer connections as at December 31, 2023 (using an average of 2.5 customers per connection, this translates into approximately 3,140,000 customers). The Regulated Services Group seeks to provide safe, high quality, and reliable services to its customers and to deliver stable and predictable earnings to AQN. In
addition to encouraging and supporting organic growth within its service territories, the Regulated Services Group may seek to deliver long-term growth through acquisitions of additional utility systems and pursuing “greening the fleet”
opportunities.
The Regulated Services Group's regulated electrical distribution utility systems and
related generation assets are located in the U.S. states of Arkansas, California, Kansas, Missouri, Nevada, New Hampshire and Oklahoma, as well as in Bermuda, which together served approximately 309,000 electric customer connections as
at December 31, 2023. The group also owns and operates generating assets with a gross capacity of approximately 2.0 GW and has investments in generating assets with approximately 0.3 GW of net generation capacity.
The Regulated Services Group's regulated water distribution and wastewater collection
utility systems are located in the U.S. States of Arizona, Arkansas, California, Illinois, Missouri, New York, and Texas as well as in Chile which together served approximately 572,000 customer connections as at December 31, 2023.
The Regulated Services Group's regulated natural gas distribution utility systems are
located in the U.S. States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire, Missouri, and New York, and in the Canadian Province of New Brunswick, which together served approximately 375,000 natural gas customer connections as at
December 31, 2023.
Below is a breakdown of the Regulated Services Group’s Revenue by geographic area for
the twelve months ended December 31, 2023.
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Renewable Energy Group
The Renewable Energy Group generates and sells electrical energy produced by its diverse
portfolio of renewable power generation and clean power generation facilities located in the United States and Canada. The Renewable Energy Group seeks to deliver growth through new power generation projects and complementary projects, such as
energy storage.
The Renewable Energy Group has economic interests in hydroelectric, wind, solar,
renewable natural gas (“RNG”) and thermal facilities which, as of December 31, 2023, had a combined net generating capacity attributable to the Renewable Energy Group of approximately 2.7 GW. Approximately 84% of the electrical output is sold
pursuant to long-term contractual arrangements which as of December 31, 2023 had a production-weighted average remaining contract life of approximately 10 years.
In addition, the Renewable Energy Group has an approximately 42% indirect beneficial
interest in Atlantica Sustainable Infrastructure plc (“Atlantica”). Atlantica owns and operates a portfolio of international clean energy and water infrastructure assets under long-term contracts with a Cash Available for Distribution weighted
average remaining contract life of approximately 13 years as of December 31, 2023.
Below is a breakdown of the net generating capacity attributable to the Renewable Energy
Group as of December 31, 2023, including the Company’s approximately 42% interest in Atlantica.
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Significant Updates
Operating Results
AQN's operating results relative to the same period last year are as follows:
| (all dollar amounts in $ millions except per share information) |
Three months ended December 31
|
Twelve months ended December 31 | |||||||||||||||||||||||||||||||||
| 2023 | 2022 | Change | 2023 | 2022 | Change | ||||||||||||||||||||||||||||||
| Net earnings (loss) attributable to shareholders | $186.3 | $(74.4) | 350% | $28.7 | $(212.0) | 114% | |||||||||||||||||||||||||||||
|
Adjusted Net Earnings1,2
|
$115.5 | $97.6 | 18% | $372.0 | $420.3 | (11)% | |||||||||||||||||||||||||||||
|
Adjusted EBITDA1,3
|
$334.3 | $295.5 | 13% | $1,235.4 | $1,192.8 | 4% | |||||||||||||||||||||||||||||
| Net earnings (loss) per common share | $0.27 | $(0.11) | 345% | $0.03 | $(0.33) | 109% | |||||||||||||||||||||||||||||
|
Adjusted Net Earnings per common share1,2
|
$0.16 | $0.14 | 14% | $0.53 | $0.61 | (13)% | |||||||||||||||||||||||||||||
| 1 |
See Caution Concerning Non-GAAP Measures.
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| 2 |
Excludes gain on sale of renewable assets of $53.4 million and $54.6 million including tax
adjustments, respectively, for the three and twelve months ended December 31, 2022.
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| 3 |
Excludes gain on sale of renewable assets of $62.8 million and $64.0 million, respectively, for
the three and twelve months ended December 31, 2022.
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Termination of Acquisition of Kentucky Power Company and AEP Kentucky Transmission
Company, Inc.
On April 17, 2023, Liberty Utilities Co. (“Liberty Utilities”), an indirect subsidiary
of AQN, mutually agreed with American Electric Power Company, Inc. and AEP Transmission Company, LLC to terminate the stock purchase agreement regarding the acquisition of Kentucky Power Company and AEP Kentucky Transmission Company, Inc. (the
“Kentucky Power Transaction Termination”).
Proposed Sale of Renewable Energy Business
On May 11, 2023, the Company announced that the Board had initiated a strategic review
of its renewable energy business (the“Strategic Review”). To oversee the strategic review process, the Board formed a Strategic Review Committee, comprised of directors Chris Huskilson (Chair), Amee Chande and Dan Goldberg. On August 10, 2023,
the Company announced that it is pursuing a sale of its renewable energy business.
Business Simplification
Aligned with the Company’s previously stated goal to simplify its business, on January
4, 2024, the Company purchased the 50% interest previously owned by Ares (as defined herein) in Liberty Development Energy Solutions B.V. and Liberty Development JV Inc. (collectively “the Joint Ventures”), which the Company used as its
non-regulated development platform. As a result, the Company recorded a non-cash loss in 2023 of $18.9 million on development loans to the Joint Ventures for expenditures which would have been eligible for capitalization as development fees under
the previous structure. The redeemable non-controlling interest of $306.5 million held by the Joint Ventures was reclassified to long-term debt in 2024.
Additionally, on January 26, 2024, the Company began to wind down its international
non-regulated development activities and sold its interest in three development solar assets in Spain to Atlantica (as defined herein) for a nominal amount and recorded a write-down of $1.5 million.
Completion of renewable projects:
Deerfield II Wind Facility
On March 23, 2023, the Renewable Energy Group achieved full commercial operations
(“COD”) at its approximately 112 MW Deerfield II Wind Facility, located in Huron County, Michigan. The Deerfield II Wind Facility has agreed to sell all of its output to Siculus, Inc., a subsidiary of Meta, pursuant to a renewable energy purchase
agreement. On June 15, 2023, the Company completed the purchase of the remaining 50% equity interest in the Deerfield II Wind Facility which it did not previously own.
Sandy Ridge II Wind Facility
On September 16, 2023, the Renewable Energy Group achieved COD at the approximately 88 MW Sandy Ridge
II Wind Facility, located in both Center County and Blair County, Pennsylvania. The Sandy Ridge II Wind Facility has agreed to sell output to a leading technology company pursuant to a renewable energy purchase agreement. On February 15, 2024,
the Company completed the purchase of the remaining 50% equity interest in the Sandy Ridge II Wind Facility which it did not previously own.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
10
|
||||
Shady Oaks II Wind Facility
On October 10, 2023, the Renewable Energy Group achieved COD at the approximately 108 MW
Shady Oaks II Wind Facility, located in Illinois. The Shady Oaks II Wind Facility has agreed to sell output to a leading financial institution pursuant to a renewable energy purchase agreement. The Company holds a 50% equity interest in the
facility which is accounted for using the equity method of accounting and holds a purchase option on the remaining 50% equity interest.
New Market Solar Facility
On March 1, 2024, the Renewable Energy Group achieved COD at the approximately 100 MW
New Market Solar Facility, located in Ohio. The New Market Solar Facility has agreed to sell output to the City of Cincinnati and a leading electric service provider pursuant to renewable energy purchase agreements. The Company holds a 50% equity
interest in the facility which is accounted for using the equity method of accounting and holds a purchase option on the remaining 50% equity interest.
California Rate Cases
During March and April 2023, the Regulated Services Group received final rate case
orders at its Apple Valley Water, Park Water and CalPeco Electric systems, with aggregate annual revenue increases of $29.6 million, including approximately $9.7 million due to increases in rate base. A one-time net earnings benefit of
approximately $3.7 million from the retroactive impact of the orders was recorded in the first quarter of 2023, with a further $11.4 million in the second quarter of 2023.
Issuance of approximately $850 million of Senior Unsecured Notes
On January 12, 2024, Liberty Utilities completed an offering of
$500 million aggregate principal amount of 5.577% senior notes due January 31, 2029 and $350 million aggregate principal amount of 5.869% senior notes due January 31, 2034 (together the “Senior Note Offering”). Liberty Utilities used the net proceeds from the Senior Note Offering to repay indebtedness.
Issuance of approximately $305.5 million of Securitized Utility Tariff Bonds
On January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180.5 million of aggregate
principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125.0 million aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039 (collectively,
the “Securitization Bonds”), to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event (as defined herein) and energy transition costs related to the retirement of the Asbury generating plant.
The principal asset securing these bonds is the securitized utility tariff property.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 11 | ||||
2023 Fourth Quarter Results From Operations
|
Key Financial Information
|
Three months ended December 31 | ||||||||||
| (all dollar amounts in $ millions except per share information) | 2023 | 2022 | |||||||||
| Revenue | $ | 666.9 | $ | 748.0 | |||||||
| Net earnings (loss) attributable to shareholders | 186.3 | (74.4) | |||||||||
| Cash provided by operating activities | 200.7 | 214.6 | |||||||||
|
Adjusted Net Earnings1
|
115.5 | 97.6 | |||||||||
|
Adjusted EBITDA1
|
334.3 | 295.5 | |||||||||
|
Adjusted Funds from Operations1
|
198.9 | 191.9 | |||||||||
| Dividends declared to common shareholders | 75.6 | 123.7 | |||||||||
| Weighted average number of common shares outstanding | 688,717,137 | 683,281,170 | |||||||||
| Per share | |||||||||||
| Basic net earnings (loss) | $ | 0.27 | $ | (0.11) | |||||||
| Diluted net earnings (loss) | $ | 0.27 | $ | (0.11) | |||||||
|
Adjusted Net Earnings1
|
$ | 0.16 | $ | 0.14 | |||||||
| Dividends declared to common shareholders | $ | 0.11 | $ | 0.18 | |||||||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
For the three months ended December 31, 2023, AQN reported basic net earnings per common share of $0.27
as compared to basic net loss per common share of $0.11 during the same period in 2022, an increase of $0.38.
The net earnings attributable to shareholders of $186.3 million for the three months
ended December 31, 2023, was primarily driven by:
•Adjusted Net Earnings of $115.5 million, as further discussed below (see Caution Concerning Non-GAAP Measures); and
•a gain on investments carried at fair value (primarily the Company’s investment in Atlantica) of $122.8 million;
partially offset by
•an impairment of $23.5 million on development loans related to the simplification of the Company’s development
strategy; and
•other net losses of $13.9 million primarily due to costs associated with the Strategic Review and the pursuit of the
sale of the Company’s renewable energy business and write-off of deferred financing costs on the redemption of debt.
The net loss attributable to shareholders of $74.4 million for the three months ended
December 31 2022, was primarily driven by:
•Adjusted Net Earnings of $97.6 million, as further discussed below (see Caution Concerning Non-GAAP Measures);
•a gain on asset sales of $62.8 million in the Renewable Energy Group; and
•a gain on derivative financial instruments of $6.4 million; offset by
•non-cash losses on asset impairment charges of $159.6 million, mainly on the Senate Wind Facility (which began
commercial operations in 2012) due to declining forecasted energy prices in ERCOT and an impairment of $75.9 million on the equity-method investment in the Texas Coastal Wind Facilities (as defined herein) primarily as a result of continued
challenges with congestion at the facilities (collectively the “2022 Impairment”).
For the three months ended December 31, 2023 AQN reported Adjusted Net Earnings per
common share of $0.16 as compared to $0.14 per common share during the same period in 2022, an increase of $0.02 (see Caution Concerning Non-GAAP Measures). Adjusted Net Earnings increased by $17.9 million year over year (see Caution Concerning Non-GAAP Measures).
This increase was primarily driven by:
•an increase of $23.9 million in the Regulated Services Group’s operating profit primarily due to regulatory
mechanisms and the implementation of new rates;
•an increase of $6.1 million in the Renewable Energy Group’s operating profit primarily due to higher equity income
from the Texas Coastal Wind Facilities; and
•an increase in tax recovery of $7.0 million primarily due to higher recognition of investment tax credits (“ITCs”)
and production tax credits (“PTCs”) associated with renewable energy projects; partially offset by
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
12
|
||||
•an increase of $7.3 million in depreciation expense driven by additional capital invested by the Company; and
•an increase of $9.9 million in interest expense, driven by higher interest rates as well as increased borrowings to
support growth initiatives.
For the three months ended December 31, 2023, AQN experienced an average exchange rate
of Canadian to U.S. dollars of approximately 0.7343 as compared to 0.7364 in the same period in 2022, and an average exchange rate of Chilean pesos to U.S. dollars of approximately 0.0011 for the three months ended December 31, 2023 as compared
to 0.0011 for the same period in 2022. As such, any year over year variance in revenue or expenses, in local currency, at any of AQN’s Canadian or Chilean entities is affected by a change in the average exchange rate upon conversion to AQN’s
reporting currency.
For the three months ended December 31, 2023, AQN reported total revenue of $666.9
million as compared to $748.0 million during the same period in 2022, a decrease of $81.1 million or 10.8%. The major factors impacting AQN’s revenue in the three months ended December 31, 2023 as compared to the same period in 2022 are as
follows:
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 13 | ||||
| (all dollar amounts in $ millions) | Three months ended December 31 | ||||
| Comparative Prior Period Revenue | $ | 748.0 | |||
| REGULATED SERVICES GROUP | |||||
| Existing Facilities | |||||
|
Electricity: Decrease is primarily due to lower wind pricing of approximately $12.0 million
and unfavourable weather of approximately $6.0 million at the Empire (MO, KS, AR, OK) Electric System, with the remaining decrease primarily due to lower pass through commodity costs and other costs at the Granite State (NH) and Empire
Electric Systems.
|
(38.6) | ||||
|
Natural Gas: Decrease is primarily due to lower pass through commodity costs.
|
(54.6) | ||||
|
Water: Increase is primarily due to the inflationary rate increase mechanism at the Suralis
(Chile) Water System and organic growth at the Litchfield Park (AZ) Water and Sewer System and Gold Canyon (AZ) Sewer System.
|
5.4 | ||||
|
Other: Decrease is primarily due to lower activity in the non-regulated business in Bermuda.
|
(4.0) | ||||
| (91.8) | |||||
| Rate Reviews | |||||
|
Electricity: Increase is primarily due to the implementation of new rates at the CalPeco
(CA), Empire (OK), Granite State (NH) and Bermuda Electric Light Company (“BELCO”) Electric Systems.
|
11.1 | ||||
| Natural Gas: |
0.4 | ||||
|
Water: Increase is primarily due to the implementation of new rates at the Park Water (CA) and Pine Bluff (AR) Water
Systems.
|
5.2 | ||||
| 16.7 | |||||
| Foreign Exchange | 0.5 | ||||
| RENEWABLE ENERGY GROUP | |||||
| Existing Facilities | |||||
| Hydro: | (0.2) | ||||
| Wind CA: Decrease is primarily due to lower wind resources across all Canadian wind facilities. | (0.8) | ||||
| Wind U.S.: Decrease is primarily due to lower wind resources across the majority of the U.S. wind facilities and lower availability revenue at the Maverick Creek Wind Facility. | (8.7) | ||||
|
Solar: Increase is primarily due to favourable capacity revenues across majority of the Solar
facilities.
|
2.8 | ||||
|
Thermal & Renewable Natural Gas: Decrease is primarily due to unfavourable overall energy
market pricing for the Windsor Locks Thermal Facility partially offset by favourable capacity revenue for the Sanger Thermal Facility.
|
(0.6) | ||||
|
Other: Decrease is primarily due to lower portfolio optimization revenue.
|
(2.0) | ||||
| (9.5) | |||||
| New Facilities | |||||
|
Wind U.S: Increase is primarily driven by the Deerfield II Wind Facility (achieved COD in
March 2023)
|
3.3 | ||||
| 3.3 | |||||
| Foreign Exchange | (0.3) | ||||
| Current Period Revenue | $ | 666.9 | |||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 14 | ||||
2023 Annual Results From Operations
|
Key Financial Information
|
Twelve months ended December 31 | ||||||||||||||||
| (all dollar amounts in $ millions except per share information) | 2023 | 2022 | 2021 | ||||||||||||||
| Revenue | $ | 2,698.0 | $ | 2,765.0 | $ | 2,274.1 | |||||||||||
| Net earnings (loss) attributable to shareholders | 28.7 | (212.0) | 264.9 | ||||||||||||||
| Cash provided by operating activities | 628.0 | 619.1 | 157.5 | ||||||||||||||
|
Adjusted Net Earnings1
|
372.0 | 420.3 | 449.0 | ||||||||||||||
|
Adjusted EBITDA1
|
1,235.4 | 1,192.8 | 1,076.3 | ||||||||||||||
|
Adjusted Funds from Operations1
|
724.6 | 790.3 | 757.9 | ||||||||||||||
| Dividends declared to common shareholders | 301.8 | 486.0 | 423.0 | ||||||||||||||
| Weighted average number of common shares outstanding | 688,738,717 | 677,862,207 | 622,347,677 | ||||||||||||||
| Per share | |||||||||||||||||
| Basic net earnings (loss) | $ | 0.03 | $ | (0.33) | $ | 0.41 | |||||||||||
| Diluted net earnings (loss) | $ | 0.03 | $ | (0.33) | $ | 0.41 | |||||||||||
|
Adjusted Net Earnings1
|
$ | 0.53 | $ | 0.61 | $ | 0.71 | |||||||||||
| Dividends declared to common shareholders | $ | 0.43 | $ | 0.71 | $ | 0.67 | |||||||||||
| Total assets | 18,374.0 | 17,627.6 | 16,797.5 | ||||||||||||||
|
Long-term debt2
|
8,516.3 | 7,512.3 | 6,211.7 | ||||||||||||||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
| 2 | Includes current and long-term portion of debt and convertible debentures per the annual consolidated financial statements. | ||||
For the twelve months ended December 31, 2023, AQN reported basic net earnings per
common share of $0.03 as compared to basic net loss per common share of $0.33 during the same period in 2022, an increase of $0.36.
The net earnings attributable to shareholders of $28.7 million for the twelve months
ended December 31, 2023, was primarily driven by:
•Adjusted Net Earnings of $372.0 million, as further discussed below (see Caution Concerning Non-GAAP Measures); partially offset by
•a loss on investments carried at fair value (primarily the Company’s investment in Atlantica) of $230.0 million; and
•other net losses of $132.9 million, including the Securitization Write-Off (as defined herein) of $63.5 million, and
impairment of assets and other losses of $46.5 million incurred as a result of the Kentucky Power Transaction Termination (the “Kentucky Power Impairment”).
The net loss attributable to shareholders of $212.0 million for the twelve months ended
December 31, 2022, was primarily driven by:
•Adjusted Net Earnings of $420.3 million, as further discussed below (see Caution Concerning Non-GAAP Measures); and
•a gain on asset sales of $64.0 million in the Renewable Energy Group; offset by
•a loss on investments carried at fair value (primarily the Company’s investment in Atlantica) of $499.1 million; and
•the 2022 Impairment of $235.5 million.
For the twelve months ended December 31, 2023, AQN reported Adjusted Net Earnings per
common share of $0.53 compared to $0.61 per common share during the same period in 2022, a decrease of $0.08 (see Caution Concerning Non-GAAP Measures).
Adjusted Net Earnings decreased by $48.3 million year over year (see Caution Concerning Non-GAAP Measures), primarily due to:
•a decrease of $26.4 million in the Renewable Energy Group’s HLBV income as a result of the end of PTC eligibility on
projects commissioned in 2012;
•a decrease of $12.5 million in the Renewable Energy Group’s operating profit primarily as a result of a 5.3%
decrease in wind production compared to the same period in 2022;
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
15
|
||||
•an increase in earnings attributable to minority interest, exclusive of HLBV, of $34.6 million primarily due to the
Company’s sale in the fourth quarter of 2022 of a 49% ownership interest in the Odell, Deerfield and Sugar Creek Wind Facilities;
•an increase in interest expense of $75.1 million, driven by higher interest rates as well as increased borrowings to
support growth initiatives;
•an increase in depreciation expense of $11.5 million, driven by additional capital invested by the Company; and
•an increase in administrative expenses of $10.2 million primarily due to technology costs, including costs
associated with cyber security; partially offset by
•an increase of $90.5 million in the Regulated Services Group’s operating profit primarily due to the implementation
of new rates; and
•an increase in tax recovery of $39.2 million primarily due to higher recognition of ITCs and PTCs associated with
renewable energy projects, and the tax impact of lower net earnings.
For the twelve months ended December 31, 2023, AQN experienced an average exchange rate
of Canadian to U.S. dollars of approximately 0.7410 as compared to 0.7682 in the same period in 2022, and an average exchange rate of Chilean pesos to U.S. dollars of approximately 0.0012 for the twelve months ended December 31, 2023 as compared
to 0.0011 for the same period in 2022. As such, any year-over-year variance in revenue or expenses, in local currency, at any of AQN’s Canadian or Chilean entities is affected by a change in the average exchange rate upon conversion to AQN’s
reporting currency.
For the twelve months ended December 31, 2023, AQN reported total revenue of $2,698.0
million as compared to $2,765.0 million during the same period in 2022, a decrease of $67.0 million or 2.4%. The major factors resulting in the increase in AQN’s revenue for the twelve months ended December 31, 2023 as compared to the same period
in 2022 are as follows:
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 16 |
||||
| (all dollar amounts in $ millions) | Twelve months ended December 31 | ||||
| Comparative Prior Period Revenue | $ | 2,765.0 | |||
| REGULATED SERVICES GROUP | |||||
| Existing Facilities | |||||
| Electricity: Decrease is primarily due to lower wind pricing of approximately $27.0 million and unfavourable weather of approximately $27.0 million at the Empire (MO, KS, AR, OK) Electric System with the remaining decrease primarily due to one-time insurance proceeds for the Neosho Ridge Wind Facility. | (66.7) | ||||
|
Natural Gas: Decrease is primarily due to lower pass through commodity costs.
|
(72.0) | ||||
|
Water: Increase is primarily due to the inflationary rate increase mechanism at the Suralis
(Chile) Water System and organic growth at the Litchfield Park (AZ) Water and Sewer System and Gold Canyon (AZ) Sewer System.
|
21.3 | ||||
|
Other: Decrease is primarily due to lower activity in the non-regulated business in Bermuda.
|
(5.6) | ||||
| (123.0) | |||||
| Rate Reviews | |||||
| Electricity: Increase is primarily due to the implementation of new rates at the CalPeco (CA) Electric System retroactive to the first quarter of 2022, as well as the implementation of new rates at the Empire (OK, MO), Granite State (NH) and BELCO (Bermuda) Electric Systems. | 84.6 | ||||
| Natural Gas: Increase is primarily due to the
implementation of new rates at the EnergyNorth (NH), Peach State (GA), St. Lawrence (NY), Midstates (MO) and Empire (MO) Gas Systems. |
5.2 | ||||
|
Water: Increase is primarily due to the implementation of new rates at the Park (CA) Water
System with one-time retroactive revenues to the third quarter of 2022 and the implementation of new rates at the Pine Bluff (AR) Water System.
|
12.4 | ||||
| 102.2 | |||||
| Foreign Exchange | 3.4 | ||||
| RENEWABLE ENERGY GROUP | |||||
| Existing Facilities | |||||
| Hydro: Decrease is primarily driven by lower retail sales in the Maritimes Region and unfavourable energy market pricing for Western Canada Region. | (5.3) | ||||
| Wind CA: Decrease is primarily due to lower wind resources across all Canadian wind facilities. | (7.6) | ||||
|
Wind U.S.: Decrease is primarily due to lower wind resources across the U.S. wind facilities.
|
(14.8) | ||||
|
Solar: Decrease is primarily driven by unfavourable energy market pricing across majority of
the Solar facilities.
|
(2.1) | ||||
|
Thermal & Renewable Natural Gas: Decrease is primarily driven by unfavourable energy
market pricing at the Sanger and Windsor Locks Thermal Facilities.
|
(17.3) | ||||
|
Other: Decrease is primarily due to lower portfolio optimization revenue.
|
(7.4) | ||||
| (54.5) | |||||
| New Facilities | |||||
|
Wind U.S: Increase is primarily driven by the Deerfield II Wind Facility (achieved COD in
March 2023).
|
4.5 | ||||
|
Other: Increase is primarily driven by the Blue Hill Wind Facility (achieved COD in April
2022).
|
4.4 | ||||
| 8.9 | |||||
| Foreign Exchange | (4.0) | ||||
| Current Period Revenue | $ | 2,698.0 | |||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 17 | ||||
2023 Net Earnings Summary
Net earnings attributable to shareholders for the three months ended December 31, 2023
totaled $186.3 million as compared to net loss attributable to shareholders of $74.4 million during the same period in 2022, an increase of $260.7 million or 350.4%. Net earnings attributable to shareholders for the twelve months ended December
31, 2023 totaled $28.7 million as compared to net loss attributable to shareholders of $212.0 million during the same period in 2022, an increase of $240.7 million or 113.5%. The following table outlines the changes to net earnings (loss)
attributable to shareholders for the three and twelve months ended December 31, 2023 as compared to the same periods in 2022. A more detailed analysis of these factors can be found under AQN: Corporate and Other Expenses.
| Change in net earnings (loss) attributable to shareholders | Three months ended | Twelve months ended | |||||||||
| December 31 | December 31 | ||||||||||
| (all dollar amounts in $ millions) | 2023 | 2023 | |||||||||
|
Net loss attributable to shareholders – Prior Period Balance
|
$ | (74.4) | $ | (212.0) | |||||||
|
Adjusted EBITDA1
|
38.8 | 42.6 | |||||||||
| Net earnings attributable to the non-controlling interest, exclusive of HLBV | (10.5) | (34.6) | |||||||||
| Income tax recovery | (27.4) | 24.8 | |||||||||
| Interest expense | (9.9) | (75.1) | |||||||||
| Other net losses | (11.8) | (111.5) | |||||||||
| Asset impairment charge | 136.1 | 136.1 | |||||||||
| Impairment of equity-method investee | 75.9 | 75.9 | |||||||||
| Unrealized loss on energy derivatives included in revenue | (2.6) | (6.6) | |||||||||
| Pension and post-employment non-service costs | (0.2) | (8.9) | |||||||||
| Change in value of investments carried at fair value | 137.5 | 269.1 | |||||||||
| Tax equity issuance costs | — | (1.2) | |||||||||
| Gain on derivative financial instruments | (5.8) | 0.2 | |||||||||
| Gain on sale of assets | (62.8) | (64.0) | |||||||||
| Foreign exchange | 10.7 | 5.4 | |||||||||
| Depreciation and amortization | (7.3) | (11.5) | |||||||||
|
Net earnings attributable to shareholders – Current Period Balance
|
$ | 186.3 | $ | 28.7 | |||||||
| Change in Net Earnings ($) | $ | 260.7 | $ | 240.7 | |||||||
| Change in Net Earnings (%) | 350.4 | % | 113.5 | % | |||||||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
During the three months ended December 31, 2023, cash provided by operating activities
totaled $200.7 million as compared to $214.6 million during the same period in 2022, a decrease of $13.9 million primarily as a result of changes in working capital items. During the three months ended December 31, 2023, Adjusted Funds from
Operations totaled $198.9 million as compared to Adjusted Funds from Operations of $191.9 million during the same period in 2022, an increase of $7.0 million (see Caution Concerning Non-GAAP Measures).
During the three months ended December 31, 2023, Adjusted EBITDA totaled $334.3 million
as compared to $295.5 million during the same period in 2022, an increase of $38.8 million or 13.1% (see
Caution Concerning Non-GAAP Measures). A more detailed analysis of this variance is presented within the reconciliation of
Adjusted EBITDA to net earnings set out below under Non-GAAP Financial Measures.
During the twelve months ended December 31, 2023, cash provided by operating activities
totaled $628.0 million as compared to $619.1 million during the same period in 2022, an increase of $8.9 million primarily as a result of changes in working capital items. During the twelve months ended December 31, 2023, Adjusted Funds from
Operations totaled $724.6 million as compared to Adjusted Funds from Operations of $790.3 million during the same period in 2022, a decrease of $65.7 million (see Caution Concerning Non-GAAP Measures).
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
18
|
||||
During the twelve months ended December 31, 2023, Adjusted EBITDA totaled $1,235.4
million as compared to $1,192.8 million during the same period in 2022, an increase of $42.6 million or 3.6% (see Caution Concerning Non-GAAP Measures).
A more detailed analysis of this variance is presented within the reconciliation of Adjusted EBITDA to net earnings set out below under Non-GAAP Financial Measures.
2023 Adjusted EBITDA Summary
Adjusted EBITDA (see Caution Concerning Non-GAAP Measures) for the three months ended December 31, 2023 totaled $334.3 million as compared to $295.5 million during the same period in 2022, an increase of $38.8 million or 13.1%.
Adjusted EBITDA for the twelve months ended December 31, 2023 totaled $1,235.4 million as compared to $1,192.8 million during the same period in 2022, an increase of $42.6 million or 3.6%. The breakdown of Adjusted EBITDA
by the Company’s main business units and a summary of changes are shown below.
| Three months ended | Twelve months ended | ||||||||||||||||||||||
|
Adjusted EBITDA1 by business units
|
December 31 | December 31 | |||||||||||||||||||||
| (all dollar amounts in $ millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
|
Divisional Operating Profit for Regulated Services Group1
|
$ | 238.3 | $ | 214.4 | $ | 954.1 | $ | 863.6 | |||||||||||||||
|
Divisional Operating Profit for Renewable Energy Group1
|
107.6 | 101.5 | 371.8 | 410.7 | |||||||||||||||||||
| Administrative Expenses | (19.3) | (21.2) | (90.4) | (80.2) | |||||||||||||||||||
| Other Income & Expenses | 7.7 | 0.8 | (0.1) | (1.3) | |||||||||||||||||||
|
Total AQN Adjusted EBITDA1
|
$ | 334.3 | $ | 295.5 | $ | 1,235.4 | $ | 1,192.8 | |||||||||||||||
|
Change in Adjusted EBITDA1 ($)
|
$ | 38.8 | $ | 42.6 | |||||||||||||||||||
|
Change in Adjusted EBITDA1 (%)
|
13.1 | % | 3.6 | % | |||||||||||||||||||
|
Change in Adjusted EBITDA1 Breakdown
|
Three months ended December 31, 2023 | |||||||||||||
| (all dollar amounts in $ millions) | Regulated Services | Renewable Energy | Corporate | Total | ||||||||||
| Prior period balances | $ | 214.4 | $ | 101.5 | $ | (20.4) | $ | 295.5 | ||||||
| Existing Facilities and Investments | 12.1 | 5.4 | 6.9 | 24.4 | ||||||||||
| New Facilities and Investments | — | (1.4) | — | (1.4) | ||||||||||
| Rate Reviews | 11.7 | — | — | 11.7 | ||||||||||
| Foreign Exchange Impact | 0.1 | 2.1 | — | 2.2 | ||||||||||
| Administrative Expenses | — | — | 1.9 | 1.9 | ||||||||||
| Total change during the period | $ | 23.9 | $ | 6.1 | $ | 8.8 | $ | 38.8 | ||||||
| Current period balances | $ | 238.3 | $ | 107.6 | $ | (11.6) | $ | 334.3 | ||||||
|
Change in Adjusted EBITDA1 Breakdown
|
Twelve months ended December 31, 2023 | |||||||||||||
| (all dollar amounts in $ millions) | Regulated Services | Renewable Energy | Corporate | Total | ||||||||||
| Prior period balances | $ | 863.6 | $ | 410.7 | $ | (81.5) | $ | 1,192.8 | ||||||
| Existing Facilities and Investments | 26.7 | (45.4) | 1.2 | (17.5) | ||||||||||
| New Facilities and Investments | — | 9.1 | — | 9.1 | ||||||||||
| Rate Reviews | 62.6 | — | — | 62.6 | ||||||||||
| Foreign Exchange Impact | 1.2 | (2.6) | — | (1.4) | ||||||||||
| Administrative Expenses | — | — | (10.2) | (10.2) | ||||||||||
| Total change during the period | $ | 90.5 | $ | (38.9) | $ | (9.0) | $ | 42.6 | ||||||
| Current period balances | $ | 954.1 | $ | 371.8 | $ | (90.5) | $ | 1,235.4 | ||||||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 19 | ||||
REGULATED SERVICES GROUP
The Regulated Services Group primarily operates rate-regulated utilities that as of December 31, 2023 provided distribution services to
approximately 1,256,000 customer connections in the electric, natural gas, and water and wastewater sectors which is an increase of approximately 6,000 customer connections as compared to December 31, 2022.
The Regulated Services Group’s strategy is to grow its business organically and through
acquisitions. The Regulated Services Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing customer connections in the communities in which it operates.
| Utility System Type | As at December 31 | ||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||
| (all dollar amounts in $ millions) | Assets |
Net Utility Sales1
|
Total Customer Connections2
|
Assets |
Net Utility Sales1
|
Total Customer Connections2
|
|||||||||||||||||
| Electricity | 5,142.7 | 865.7 | 309,000 | 5,016.5 | 813.4 | 309,000 | |||||||||||||||||
| Natural Gas | 1,843.5 | 354.1 | 375,000 | 1,722.6 | 345.9 | 375,000 | |||||||||||||||||
| Water and Wastewater | 1,678.1 | 379.5 | 572,000 | 1,525.1 | 346.1 | 566,000 | |||||||||||||||||
| Other | 281.3 | 51.1 | 290.7 | 54.2 | |||||||||||||||||||
| Total | $ | 8,945.6 | $ | 1,650.4 | 1,256,000 | $ | 8,554.9 | $ | 1,559.6 | 1,250,000 | |||||||||||||
| Accumulated Deferred Income Taxes Liability | $ | 750.8 | $ | 689.1 | |||||||||||||||||||
| 1 |
Net Utility Sales for the twelve months ended December 31, 2023 and 2022. See Caution Concerning Non-GAAP Measures.
|
||||
| 2 | Total Customer Connections represents the sum of all active and vacant customer connections. | ||||
The Regulated Services Group aggregates the performance of its utility operations by utility system
type – electricity, natural gas, and water and wastewater systems.
The electric distribution systems are comprised of regulated electrical distribution
utility systems and served approximately 309,000 customer connections in the U.S. States of California, New Hampshire, Missouri, Kansas, Oklahoma and Arkansas and in Bermuda as at December 31, 2023.
The natural gas distribution systems are comprised of regulated natural gas distribution
utility systems and served approximately 375,000 customer connections located in the U.S. States of New Hampshire, Illinois, Iowa, Missouri, Georgia, Massachusetts and New York and in the Canadian Province of New Brunswick as at December 31,
2023.
The water and wastewater distribution systems are comprised of regulated water
distribution and wastewater collection utility systems and served approximately 572,000 customer connections located in the U.S. States of Arkansas, Arizona, California, Illinois, Missouri, New York, and Texas and in Chile as at December 31,
2023.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
20
|
||||
2023 Annual Usage Results
| Electric Distribution Systems | Three months ended December 31 | Twelve months ended December 31 | |||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Average Active Electric Customer Connections For The Period | |||||||||||||||||||||||
| Residential | 262,900 | 262,500 | 262500 | 262,700 | 261,900 | ||||||||||||||||||
| Commercial and industrial | 42,900 | 43,200 | 42,700 | 42,800 | |||||||||||||||||||
| Total Average Active Electric Customer Connections For The Period | 305,800 | 305,700 | 305,400 | 304,700 | |||||||||||||||||||
| Customer Usage (GW-hrs) | |||||||||||||||||||||||
| Residential | 635.1 | 653.3 | 2,741.5 | 2,899.6 | |||||||||||||||||||
| Commercial and industrial | 902.2 | 924.2 | 3,820.0 | 3,849.3 | |||||||||||||||||||
| Total Customer Usage (GW-hrs) | 1,537.3 | 1,577.5 | 6,561.5 | 6,748.9 | |||||||||||||||||||
For the three months ended December 31, 2023, the electric distribution systems' usage
totaled 1,537.3 GW-hrs as compared to 1,577.5 GW-hrs for the same period in 2022, a decrease of 40.2 GW-hrs or 2.5%. The decrease in electricity consumption is primarily due to warmer weather at the Empire Electric System.
For the twelve months ended December 31, 2023, the electric distribution systems' usage
totaled 6,561.5 GW-hrs as compared to 6,748.9 GW-hrs for the same period in 2022, a decrease of
187.4 GW-hrs or 2.8%. The decrease in electricity consumption is primarily
due to a warmer winter and a cooler summer at the Empire Electric System.
Approximately 47% of the Regulated Services Group's electric distribution systems' revenues are not expected to be impacted by changes in customer usage, as they are subject to volumetric
decoupling or represent fixed fee billings.
| Natural Gas Distribution Systems | Three months ended December 31 | Twelve months ended December 31 | |||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Average Active Natural Gas Customer Connections For The Period | |||||||||||||||||||||||
| Residential | 325,600 | 321,100 | 326,500 | 320,300 | |||||||||||||||||||
| Commercial and industrial | 40,800 | 39,100 | 40,600 | 38,800 | |||||||||||||||||||
| Total Average Active Natural Gas Customer Connections For The Period | 366,400 | 360,200 | 367,100 | 359,100 | |||||||||||||||||||
| Customer Usage (MMBTU) | |||||||||||||||||||||||
| Residential | 4,358,000 | 5,433,000 | 18,822,000 | 20,912,000 | |||||||||||||||||||
| Commercial and industrial | 4,894,000 | 5,723,000 | 20,215,000 | 20,607,000 | |||||||||||||||||||
| Total Customer Usage (MMBTU) | 9,252,000 | 11,156,000 | 39,037,000 | 41,519,000 | |||||||||||||||||||
For the three months ended December 31, 2023, usage at the natural gas distribution
systems totaled 9,252,000 MMBTU as compared to 11,156,000 MMBTU during the same period in 2022, a decrease of 1,904,000 MMBTU, or 17.1%. The decrease in customer usage was primarily due to warmer weather at the Mid-States and Empire District Gas
Systems.
For the twelve months ended December 31, 2023, usage at the natural gas distribution
systems totaled 39,037,000 MMBTU as compared to 41,519,000 MMBTU during the same period in 2022, a
decrease of 2,482,000 MMBTU, or 6.0%. The decrease in customer usage was primarily due to warmer weather at the Mid-States,
New England Gas and Empire District Gas Systems.
Approximately 86% of the Regulated Services Group's gas distribution systems' revenues are not expected to be impacted by changes in customer usage, as they are subject to volumetric decoupling
or represent fixed fee billings.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
21
|
||||
| Water and Wastewater Distribution Systems | Three months ended December 31 | Twelve months ended December 31 | |||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Average Active Customer Connections For The Period | |||||||||||||||||||||||
| Wastewater customer connections | 55,600 | 49,100 | 52,100 | 48,100 | |||||||||||||||||||
| Water distribution customer connections | 506,300 | 504,600 | 508,400 | 501,300 | |||||||||||||||||||
| Total Average Active Customer Connections For The Period | 561,900 | 553,700 | 560,500 | 549,400 | |||||||||||||||||||
| Gallons Provided (millions of gallons) | |||||||||||||||||||||||
| Wastewater treated | 869 | 822 | 3,350 | 3,233 | |||||||||||||||||||
| Water provided | 10,188 | 9,851 | 41,435 | 41,527 | |||||||||||||||||||
| Total Gallons Provided (millions of gallons) | 11,057 | 10,673 | 44,785 | 44,760 | |||||||||||||||||||
For the three months ended December 31, 2023, the water and wastewater distribution
systems provided approximately 10,188 million gallons of water to customers and treated approximately 869 million gallons of wastewater. This is compared to 9,851 million gallons of water provided and 822 million gallons of wastewater treated
during the same period in 2022, an increase in total gallons provided of 337 million or 3.4% and an increase in total gallons treated of 47 million or 5.7%. This increase in water provided is primarily due to customer growth at the Litchfield
Park Water System and the increase in wastewater treated is primarily due to customer growth at the Litchfield Park and Rio Rico Water Systems.
For the twelve months ended December 31, 2023, the water and wastewater distribution
systems provided approximately 41,435 million gallons of water to customers and treated approximately 3,350 million gallons of wastewater. This is compared to 41,527 million gallons of water provided and 3,233 million gallons of wastewater
treated during the same period in 2022, a decrease in total gallons provided of 92 million or 0.2% and an increase in total gallons treated of 117 million or 3.6%. This decrease in water provided is mainly due to California drought restrictions
at the Park Water System. The increase in wastewater treated is primarily due to customer growth at the Litchfield Park and Rio Rico Water Systems.
Approximately 50% of the Regulated Services Group's water and wastewater distribution
systems' revenues are not expected to be impacted by changes in customer usage, as they are subject to volumetric decoupling or represent fixed fee billings.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 22 | ||||
2023 Regulated Services Group Operating Results
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||||||
| (all dollar amounts in $ millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Revenue | |||||||||||||||||||||||
| Regulated electricity distribution | $ | 297.0 | $ | 325.8 | $ | 1,295.5 | $ | 1,278.9 | |||||||||||||||
| Less: Regulated electricity purchased | (95.7) | (124.2) | (429.8) | (465.5) | |||||||||||||||||||
|
Net Utility Sales - electricity1
|
201.3 | 201.6 | 865.7 | 813.4 | |||||||||||||||||||
| Regulated gas distribution | 167.4 | 221.8 | 621.2 | 686.7 | |||||||||||||||||||
| Less: Regulated gas purchased | (71.6) | (125.5) | (267.1) | (340.8) | |||||||||||||||||||
|
Net Utility Sales - natural gas1
|
95.8 | 96.3 | 354.1 | 345.9 | |||||||||||||||||||
| Regulated water reclamation and distribution | 100.5 | 89.0 | 399.1 | 364.4 | |||||||||||||||||||
| Less: Regulated water purchased | (5.9) | (8.6) | (19.6) | (18.3) | |||||||||||||||||||
|
Net Utility Sales - water reclamation and distribution1
|
94.6 | 80.4 | 379.5 | 346.1 | |||||||||||||||||||
|
Other revenue2
|
11.6 | 14.5 | 51.1 | 54.2 | |||||||||||||||||||
|
Net Utility Sales1,3
|
403.3 | 392.8 | 1,650.4 | 1,559.6 | |||||||||||||||||||
| Operating expenses | (193.4) | (185.8) | (786.6) | (736.5) | |||||||||||||||||||
|
Income from long-term investments
|
11.6 | 5.2 | 45.0 | 21.9 | |||||||||||||||||||
|
HLBV4
|
16.8 | 2.2 | 45.3 | 18.6 | |||||||||||||||||||
|
Divisional Operating Profit1,5
|
$ | 238.3 | $ | 214.4 | $ | 954.1 | $ | 863.6 | |||||||||||||||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
| 2 |
See Note 21 in the annual
consolidated financial statements.
|
||||
| 3 |
This table contains a reconciliation of Net Utility Sales to revenue. The relevant sections of
the table are derived from and should be read in conjunction with the consolidated
statement of operations and Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Net Utility Sales and provides additional
information related to the operating performance of the Regulated Services Group. Investors are cautioned that Net Utility Sales should not be construed as an alternative to revenue.
|
||||
| 4 |
HLBV income represents the value of net tax attributes monetized by the Regulated Services
Group in the period at the Luning and Turquoise Solar Facilities and the Neosho Ridge, Kings Point and North Fork Ridge Wind Facilities.
|
||||
| 5 |
This table contains a reconciliation of Divisional Operating Profit to revenue for the
Regulated Services Group. The relevant sections of the table are derived from and should be read in conjunction with the consolidated statement of operations and Note 21 in the annual
consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Divisional Operating Profit and provides additional information related to the operating
performance of the Regulated Services Group. Investors are cautioned that Divisional Operating Profit should not be construed as an alternative to revenue.
|
||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
23
|
||||
2023 Fourth Quarter Operating Results
For the three months ended December 31, 2023, the Regulated Services Group reported
revenue of $564.9 million (i.e., $297.0 million of regulated electricity distribution, $167.4 million of regulated gas distribution and $100.5 million of regulated water reclamation and distribution) as compared to revenue of $636.6 million in
the comparable period in the prior year (i.e., $325.8 million of regulated electricity distribution, $221.8 million of regulated gas distribution and $89.0 million of regulated water reclamation and distribution).
For the three months ended December 31, 2023, the Regulated Services Group reported a
Divisional Operating Profit (excluding corporate administration expenses) of $238.3 million as compared to $214.4 million for the comparable period in the prior year (see Caution Concerning Non-GAAP Measures).
Highlights of the changes are summarized in the following table:
| (all dollar amounts in $ millions) | Three months ended December 31 | ||||
|
Prior Period Divisional Operating Profit1
|
$ | 214.4 | |||
| Existing Facilities | |||||
| Electricity: Increase is primarily due to higher HLBV income, partially offset by unfavourable weather at the Empire (MO, KS, AR, OK) Electric System. | 10.5 | ||||
| Natural Gas: | (0.9) | ||||
| Water: Decrease is primarily due to higher operating expenses. | (2.8) | ||||
|
Other: Increase is primarily driven by higher interest income on regulatory asset accounts.
|
5.3 | ||||
| 12.1 | |||||
| Rate Reviews | |||||
|
Electricity: Increase is primarily due to the implementation of new rates at the CalPeco
(CA), Empire (OK), Granite State (NH) and BELCO (Bermuda) Electric Systems.
|
6.1 | ||||
| Natural Gas: | 0.4 | ||||
|
Water: Increase is primarily due to the implementation of new rates at the Park Water (CA)
and Pine Bluff (AR) Water Systems.
|
5.2 | ||||
| 11.7 | |||||
| Foreign Exchange | 0.1 | ||||
|
Current Period Divisional Operating Profit1
|
$ | 238.3 | |||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
24
|
||||
2023 Annual Operating Results
For the twelve months ended December 31, 2023, the Regulated Services Group reported
revenue of $2,315.7 million (comprised of $1,295.5 million of regulated electricity distribution revenue, $621.2 million of regulated natural gas distribution revenue and $399.1 million of regulated water reclamation and distribution revenue) as
compared to revenue of $2,330.0 million in the same period in the prior year (comprised of $1,278.9 million of regulated electricity distribution revenue, $686.7 million of regulated natural gas distribution revenue and $364.4 million of
regulated water reclamation and distribution revenue).
For the twelve months ended December 31, 2023, the Regulated Services Group reported a
Divisional Operating Profit (excluding corporate administration expenses) of $954.1 million as compared to $863.6 million in the comparable period in the prior year (see Caution Concerning Non-GAAP Measures).
Highlights of the changes are summarized in the following table:
| (all dollar amounts in $ millions) | Twelve months ended December 31 | ||||
|
Prior Period Divisional Operating Profit1
|
$ | 863.6 | |||
| Existing Facilities | |||||
| Electricity: Increase is primarily due to higher HLBV income partially offset by unfavourable weather at the Empire (MO, KS, OK, AR) Electric System and one-time insurance proceeds for the Neosho Ridge Facility. | 2.7 | ||||
| Natural Gas: | (0.3) | ||||
| Water: Increase is primarily due to organic growth at the Litchfield Park (AZ) Water and Sewer System and Gold Canyon (AZ) Sewer System. | 2.3 | ||||
|
Other: Increase is primarily driven by higher interest income on regulatory asset accounts.
|
22.0 | ||||
| 26.7 | |||||
| Rate Reviews | |||||
| Electricity: Increase is primarily due to the implementation of new rates at the CalPeco (CA) Electric System retroactive to the first quarter of 2022, as well as the implementation of new rates at the Empire (OK, MO), Granite State (NH) and BELCO (Bermuda) Electric Systems. | 45.0 | ||||
| Natural Gas: Increase is primarily due to the
implementation of new rates at the EnergyNorth (NH), Peach State (GA), St. Lawrence (NY), Midstates (MO) and Empire (MO) Gas Systems. |
5.2 | ||||
|
Water: Increase is primarily due to the implementation of new rates at the Park (CA) Water
System with one-time retroactive revenues to the third quarter of 2022 and the implementation of new rates at the Pine Bluff (AR) Water System.
|
12.4 | ||||
| 62.6 | |||||
| Foreign Exchange | 1.2 | ||||
|
Current Period Divisional Operating Profit1
|
$ | 954.1 | |||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
25
|
||||
Regulatory Proceedings
The following table summarizes the major regulatory proceedings currently underway or
completed or effective in 2023 within the Regulated Services Group.
| Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) |
Current Status | ||||||||||||||||
| Completed Rate Reviews | ||||||||||||||||||||
| BELCO | Bermuda | General Rate Case ("GRC") | $34.8 |
On September 30, 2021, filed its revenue allowance application in which it requested a $34.8
million increase for 2022 and a $6.1 million increase for 2023. On March 18, 2022, the Regulatory Authority (“RA”) approved an annual increase of $22.8 million, for a revenue allowance of $224.1 million for 2022 and $226.2 million for
2023. The RA authorized a 7.16% rate of return, comprised of a 62% equity and an 8.92% return on equity (“ROE”). In April 2022, BELCO filed an appeal in the Supreme Court of Bermuda challenging the decisions made by the RA through the
recent Retail Tariff Review. On February 19, 2024, the Bermuda Supreme Court issued an order denying the BELCO appeal. Any further appeal must be filed by April 4, 2024.
|
||||||||||||||||
| Apple Valley Water System | California | GRC | $2.9 |
On July 2, 2021, filed an application requesting revenue increases of $2.9 million for 2022,
$2.1 million for 2023, and $2.3 million for 2024 based on an ROE of 9.4% and on a 57% equity capital structure. The California Public Utilities Commission ("CPUC") Public Advocates Office issued its report in January 2022. Rebuttal
testimony was filed in February 2022 and a hearing was held in March 2022. On February 3, 2023, the CPUC issued a Final Order authorizing an annual revenue increase of $1.5 million in 2022, and subsequent expected increases of $1.6
million and $1.5 million in 2023 and 2024, respectively. New rates became effective April 7, 2023 retroactive to July 1, 2022.
|
||||||||||||||||
| Park Water System | California | GRC | $5.5 |
On July 2, 2021, filed an application requesting revenue increases of $5.5 million for 2022,
$1.8 million for 2023, and $1.8 million for 2024 based on an ROE of 9.4% and on a 57% equity capital structure. CPUC Public Advocates Office issued its report in January 2022. Rebuttal testimony was filed in February 2022 and a hearing
was held in March 2022. On February 3, 2023, the CPUC issued a Final Order authorizing an annual revenue increase of $1.1 million in 2022, and subsequent expected increases of $1.5 million and $1.5 million in 2023 and 2024,
respectively. New rates became effective April 7, 2023 retroactive to July 1, 2022.
|
||||||||||||||||
| CalPeco Electric System | California | GRC | $35.7 |
On May 28, 2021, filed an application requesting a revenue increase of $35.7 million for 2022
based on an ROE of 10.5% and on a 54% equity capital structure. CPUC Public Advocates Office issued its report on February 23, 2022 and CalPeco filed its rebuttal testimony in March 2022. In May 2022, a settlement was reached resolving
all issues except ROE. The CPUC issued a Final Order on April 27, 2023 authorizing an annual revenue increase of $27.0 million. New rates became effective July 1, 2023 retroactive to January 2022.
|
||||||||||||||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
26
|
||||
| Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) |
Current Status | ||||||||||||||||
|
St. Lawrence Gas
|
New York | GRC | $4.1 |
On November 24, 2021, filed an application requesting a revenue increase of $3.4 million based
on an ROE of 10.5% and a capital structure of 50% equity. On January 31, 2022, filed a supplemental filing to update the requested revenue increase to $4.1 million. New York State Department of Public Service Staff filed testimony on
June 3, 2022 and St. Lawrence Gas filed rebuttal testimony on June 24, 2022. On March 31, 2023, a joint proposal was filed by the parties resolving all issues. On June 22, 2023, the Commission issued an Order approving the terms of the
joint proposal and authorizing a revenue increase of $5.2 million to be implemented over the course of 2023-2025. New rates became effective July 1, 2023.
|
||||||||||||||||
| Pine Bluff Water | Arkansas | GRC | $5.9 |
On September 30, 2022, filed an application seeking an increase in revenues of $5.9 million
based on an ROE of 10.5% and an equity ratio of 52% to be phased in over three years. On August 4, 2023, the Arkansas Public Service Commission issued an Order approving a unanimous settlement agreement filed by the parties authorizing
an annual revenue increase of $3.4 million. New rates became effective August 15, 2023.
|
||||||||||||||||
|
Gas New Brunswick
|
New Brunswick | GRC | -$0.6 |
On March 3, 2023, filed an application for a revenue decrease of $0.6 million based on the
Energy & Utilities Board's recent decisions authorizing a capital structure of 45% equity and an ROE of 9.8%. On September 21, 2023 the Energy & Utilities Board issued a decision authorizing a revenue decrease of $0.7 million.
|
||||||||||||||||
| Empire Electric | Arkansas | GRC | $7.3 | On February 14, 2023, filed an application seeking an increase in revenues of $7.3 million based on an ROE of 10.25% and an equity ratio of 56% to be phased in over three years. On December 7, 2023, the Arkansas Public Service Commission issued an Order approving the settlement agreement authorizing a revenue increase of $5.3 million. New rates became effective January 1, 2024. | ||||||||||||||||
| Various | Various | Various | $0.1 | On February 22, 2023, the Arizona Corporation Commission issued an Order approving the proposed consolidation of rates and tariffs for two wastewater utilities and new rates to be effective March 1, 2023. | ||||||||||||||||
| Pending Rate Reviews | ||||||||||||||||||||
| Granite State Electric | New Hampshire | GRC | $15.5 |
On May 5, 2023, filed an application seeking a permanent increase in revenues of $15.5 million
based on an ROE of 10.35% and an equity ratio of 55%. Temporary rates of $5.5 million were implemented on July 1, 2023. On December 13, 2023, the Department of Energy filed a motion seeking to dismiss the case. An evidentiary hearing
was held on January 23, 2024. The case has been stayed by the New Hampshire Public Utilities Commission (“NHPUC”) until April 15, 2024 so that it may contemplate the motion and so that the Company can provide the Commission with a
third-party review of the financial information within the rate application.
|
||||||||||||||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 27 | ||||
| Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) |
Current Status | ||||||||||||||||
| New York Water | New York | GRC | $39.7 | On May 4, 2023, filed an application seeking an increase in revenues of $39.7 million based on an ROE of 10% and an equity ratio of 50%. | ||||||||||||||||
| EnergyNorth Gas | New Hampshire | GRC | $27.5 |
On July 27, 2023, filed an application seeking an increase in revenues of $27.5 million based
on an ROE of 10.35% and an equity ratio of 55%. Temporary rates of $8.7 million were approved by the Commission on October 31, 2023. The temporary rate increase is retroactive to October 1, 2023. On February 5, 2024, the Company
requested that the NHPUC stay the case until April 12, 2024 so that the Company can provide the Commission with a third-party review of the financial information upon which the revenue requirement is predicated. On February 16, 2024,
the Department of Energy filed a motion seeking to dismiss the case. A hearing was held on March 6, 2024 on the motion to dismiss and the request for the stay.
|
||||||||||||||||
| Midstates Gas | Illinois | GRC | $5.3 | On December 20, 2023, filed an application seeking an increase in revenues of $5.3 million based on an ROE of 10.80% and an equity ratio of 54%. | ||||||||||||||||
| Rio Rico Water & Sewer, Bella Vista Water, Beardsley Water, Cordes Lakes Water | Arizona | GRC | $5.4 | On December 28, 2023, filed an application seeking an increase in revenues of $5.4 million based on an ROE of 10.95% and an equity ratio of 54%. | ||||||||||||||||
| Park Water | California | GRC | $9.3 | On January 2, 2024, filed an application seeking an increase in revenues of $9.3 million based on an ROE of 9.35% and an equity ratio of 57%. | ||||||||||||||||
| Apple Valley Water | California | GRC | $3.1 | On January 2, 2024, filed an application seeking an increase in revenues of $3.1 million based on an ROE of 9.35% and an equity ratio of 57%. | ||||||||||||||||
Proceedings related to the Midwest Extreme Weather Event and the Retirement of Asbury
The February 2021 extreme winter storm conditions experienced in Texas and parts of the
central U.S. (the "Midwest Extreme Weather Event") resulted in an extraordinary increase in costs incurred by Empire Electric for the purchase of fuel and power on behalf of its customers.
When Empire Electric filed its most recent Missouri rate case (the "Empire Rate Case")
in May 2021, a request to recover the costs related to the Midwest Extreme Weather Event was included. In July 2021, Missouri House Bill 734 was signed into law, creating an option for utilities to finance the recovery of extraordinary weather
event costs through securitization (the "Securitization Statute"). When it filed its surrebuttal testimony in January 2022, Empire Electric removed all costs related to the Midwest Extreme Weather Event from its rate request. Pursuant to the
Securitization Statute, Empire Electric sought authorization for the issuance of approximately $222 million in securitized utility tariff bonds associated with the Midwest Extreme Weather Event.
In addition, as part of its 2017 and 2019 Integrated Resource Plans (“IRPs”), Empire
Electric analyzed the effects of retiring Asbury, a coal-fired generation unit that was constructed in 1970, and determined that doing so would generate significant savings to customers. Asbury was retired on March 1, 2020. On July 23, 2020, the
Missouri Public Service Commission ("MPSC") issued an Administrative Accounting Order ("AAO") that directed Empire Electric to establish regulatory asset and liability accounts, beginning January 1, 2020, to reflect the impact of the closure of
Asbury on operating and capital expenses in Missouri.
Empire Electric initially sought to recover its Asbury related revenues and expenses,
along with the balance of the AAO, in the Empire Rate Case. Following the passage of the Securitization Statute, all Asbury related balances were removed from the Empire Rate Case and, on March 21, 2022, Empire Electric filed a petition to
securitize the Asbury related balances pursuant to the Securitization Statute. Empire Electric sought authority to issue approximately $141 million in securitized utility tariff bonds for its Asbury costs, which include approximately $21 million
in Asset Retirement Obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 28 | ||||
On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, the
cases regarding the quantum financeable through securitization for Asbury and the Midwest Extreme Weather Event, which hearing was held the week of June 13, 2022. On August 18, 2022, and September 22, 2022, the MPSC issued and amended,
respectively, a Report and Order authorizing Empire Electric to securitize approximately $290.4 million in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with
the proposed securitization (the “Securitization Order”). The amounts authorized by the Securitization Order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed a request for
rehearing seeking reconsideration of the MPSC’s denial of recovery of five percent of the Midwest Extreme Weather Event costs, its calculation of accumulated deferred income taxes, and the exclusion of certain carrying charges associated with the
Asbury plant, among other issues. On October 12, 2022, the MPSC denied all rehearing motions. Empire Electric appealed to the Missouri Court of Appeals – Western District on November 10, 2022. Oral arguments were heard in July 2023. On August 1,
2023, the court affirmed the amount eligible for securitization of $290.4 million as well as certain additional carrying costs to the date of issuance. The Company completed its issuance of Securitization Bonds in the aggregate principal amount
of $305.5 million on January 30, 2024 in line with the MPSC’s order to recover the costs associated with the Midwest Extreme Weather Event and the remaining book value of Asbury. The MPSC's order excluded a portion of carrying costs and taxes
associated with Asbury, and the Company incurred a one-time net loss of $63.5 million ($48.5 million net of tax) (the “Securitization Write-Off”).
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 29 | ||||
RENEWABLE ENERGY GROUP
|
2023 Electricity Generation Performance
|
|||||||||||||||||||||||||||||||||||
|
Long-Term Average Resource1
|
Three months ended December 31 |
Long-Term Average Resource1
|
Twelve months ended December 31 | ||||||||||||||||||||||||||||||||
| (Performance in GW-hrs sold) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||||||||||
| Hydro Facilities: | |||||||||||||||||||||||||||||||||||
| Maritime Region | 37.6 | 43.3 | 48.2 | 148.2 | 157.1 | 149.1 | |||||||||||||||||||||||||||||
| Quebec Region | 72.6 | 76.7 | 74.1 | 273.3 | 294.8 | 292.0 | |||||||||||||||||||||||||||||
| Ontario Region | 26.2 | 29.9 | 27.9 | 120.4 | 107.7 | 116.0 | |||||||||||||||||||||||||||||
| Western Region | 12.6 | 11.0 | 10.2 | 65.0 | 51.8 | 52.1 | |||||||||||||||||||||||||||||
| 149.0 | 160.9 | 160.4 | 606.9 | 611.4 | 609.2 | ||||||||||||||||||||||||||||||
| Canadian Wind Facilities: | |||||||||||||||||||||||||||||||||||
| St. Damase | 22.7 | 19.1 | 23.4 | 76.9 | 64.0 | 77.7 | |||||||||||||||||||||||||||||
| St. Leon | 121.4 | 116.3 | 125.4 | 430.2 | 373.6 | 435.0 | |||||||||||||||||||||||||||||
|
Red Lily2
|
24.1 | 24.9 | 25.3 | 88.5 | 80.0 | 90.8 | |||||||||||||||||||||||||||||
| Morse | 30.5 | 29.6 | 26.1 | 108.8 | 92.8 | 103.7 | |||||||||||||||||||||||||||||
| Amherst | 67.9 | 60.2 | 67.6 | 229.8 | 187.0 | 219.5 | |||||||||||||||||||||||||||||
|
Blue Hill3
|
200.4 | 144.5 | 140.2 | 683.2 | 501.4 | 464.2 | |||||||||||||||||||||||||||||
|
EBR3
|
21.0 | 15.5 | 21.1 | 74.4 | 53.7 | 71.0 | |||||||||||||||||||||||||||||
| 488.0 | 410.1 | 429.1 | 1,691.8 | 1,352.5 | 1,461.9 | ||||||||||||||||||||||||||||||
| U.S. Wind Facilities: | |||||||||||||||||||||||||||||||||||
| Sandy Ridge | 43.6 | 34.9 | 11.7 | 158.3 | 114.4 | 105.5 | |||||||||||||||||||||||||||||
| Minonk | 189.8 | 166.4 | 208.5 | 673.7 | 580.4 | 696.9 | |||||||||||||||||||||||||||||
| Senate | 140.0 | 115.3 | 114.2 | 520.4 | 463.2 | 490.0 | |||||||||||||||||||||||||||||
| Shady Oaks | 100.5 | 94.7 | 114.9 | 355.6 | 318.7 | 362.2 | |||||||||||||||||||||||||||||
|
Odell5
|
238.0 | 203.2 | 250.9 | 831.8 | 738.7 | 869.3 | |||||||||||||||||||||||||||||
|
Deerfield5
|
167.9 | 151.3 | 168.8 | 546.0 | 481.3 | 554.9 | |||||||||||||||||||||||||||||
|
Sugar Creek5
|
212.6 | 177.5 | 193.0 | 724.8 | 606.9 | 661.4 | |||||||||||||||||||||||||||||
| Maverick Creek | 480.2 | 354.0 | 362.6 | 1,920.6 | 1,472.1 | 1,620.9 | |||||||||||||||||||||||||||||
|
Deerfield II6
|
116.0 | 89.5 | — | 281.6 | 181.1 | — | |||||||||||||||||||||||||||||
|
Sandy Ridge II9
|
75.1 | 64.7 | — | 87.8 | 70.5 | — | |||||||||||||||||||||||||||||
|
Shady Oaks II10
|
95.8 | 79.2 | — | 95.8 | 79.2 | — | |||||||||||||||||||||||||||||
| 1,859.5 | 1,530.7 | 1,424.6 | 6,196.4 | 5,106.5 | 5,361.1 | ||||||||||||||||||||||||||||||
| Solar Facilities: | |||||||||||||||||||||||||||||||||||
| Cornwall | 2.2 | 1.8 | 2.4 | 14.7 | 14.0 | 14.8 | |||||||||||||||||||||||||||||
| Bakersfield | 13.0 | 9.4 | 9.9 | 77.2 | 61.9 | 67.2 | |||||||||||||||||||||||||||||
| Great Bay | 37.6 | 46.6 | 44.1 | 205.7 | 211.7 | 214.7 | |||||||||||||||||||||||||||||
| Altavista | 31.4 | 35.0 | 33.0 | 164.4 | 169.0 | 167.7 | |||||||||||||||||||||||||||||
| Croton | 0.9 | 1.0 | 1.1 | 5.4 | 5.1 | 5.4 | |||||||||||||||||||||||||||||
|
Dalewood7
|
0.2 | 0.1 | — | 1.0 | 0.8 | — | |||||||||||||||||||||||||||||
|
Hayhurst New Mexico11
|
5.8 | 6.2 | — | 5.8 | 6.2 | — | |||||||||||||||||||||||||||||
| 91.1 | 100.1 | 90.5 | 474.2 | 468.7 | 469.8 | ||||||||||||||||||||||||||||||
| Renewable Energy Performance | 2,587.6 | 2,201.8 | 2,104.6 | 8,969.3 | 7,539.1 | 7,902.0 | |||||||||||||||||||||||||||||
| Thermal Facilities: | |||||||||||||||||||||||||||||||||||
| Windsor Locks |
N/A7
|
30.9 | 29.7 |
N/A7
|
118.0 | 127.5 | |||||||||||||||||||||||||||||
| Sanger |
N/A7
|
0.8 | — |
N/A7
|
11.9 | 149.1 | |||||||||||||||||||||||||||||
| 31.7 | 29.7 | 129.9 | 276.6 | ||||||||||||||||||||||||||||||||
|
Total Performance12
|
2,233.5 | 2,134.3 | 7,669.0 | 8,178.6 | |||||||||||||||||||||||||||||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
30
|
||||
| 1 |
Long-Term Average Resource ("LTAR") is based on weather resource studies done at the inception
of each project.
|
||||
| 2 | AQN owns a 75% equity interest but accounts for the facility using the equity method. Figures show full energy produced by the facility. | ||||
| 3 | The Blue Hill Wind Facility achieved COD on April 14, 2022. AQN owns a 20% equity interest but accounts for the facility using the equity method. Figures show expected LTAR and full energy produced by the facility during the quarter. | ||||
| 4 |
AQN owns a 50% equity interest but accounts for the facility using the equity method. Figures
show full energy produced by the facility during the quarter.
|
||||
| 5 | AQN owns a 51% equity interest in the Sugar Creek, Odell and Deerfield Wind Facilities but consolidates the facilities for accounting purposes. Figures show full energy produced by the facilities during the quarter. | ||||
| 6 |
The Deerfield II Wind Facility achieved COD on March 23, 2023. Prior to June 15, 2023, AQN
owned a 50% interest in the facility. On June 15, 2023, AQN acquired the remaining 50% interest that it did not previously own. Figures show full energy produced by the facility during the quarter.
|
||||
| 7 | The Dalewood Solar Facility achieved COD on December 21, 2022. | ||||
| 8 | Natural gas fired co-generation facility. | ||||
| 9 |
The Sandy Ridge II Wind Facility achieved COD on September 16, 2023. AQN owns a 50% interest in
the facility, but accounts for the facility using the equity method. Figures show full energy produced by the facility during the quarter.
|
||||
| 10 | The Shady Oaks II Wind Facility achieved COD on October 10, 2023. AQN owns a 50% interest in the facility, but accounts for the facility using the equity method. Figures show full energy produced by the facility during the quarter. | ||||
| 11 | The Hayhurst New Mexico Solar Facility achieved COD on November 6, 2023. AQN owns 50% equity interest but accounts for the facility using the equity method. Figures show expected LTAR and full energy produced by the facility during the quarter. | ||||
| 12 |
Total Performance represents actual energy produced by each facility. Lower than expected
turbine availability will contribute to generation shortfalls relative to LTAR in some instances. The Company recognizes availability revenue when such shortfalls are compensated for under various long term service and maintenance
agreements. The compensated generation is not reflected in the actual energy produced by each facility.
|
||||
2023 Fourth Quarter Renewable Energy Group Performance
For the three months ended December 31, 2023, the Renewable Energy Group generated
2,233.5 GW-hrs of electricity as compared to 2,134.3 GW-hrs during the same period in 2022.
For the three months ended December 31, 2023, the hydro facilities generated 160.9
GW-hrs of electricity as compared to 160.4 GW-hrs produced in the same period in 2022, an increase of 0.3%. Electricity generated represented 108.0% of LTAR as compared to 107.7% during the same period in 2022.
For the three months ended December 31, 2023, the wind facilities produced 1,940.8 GW-hrs of
electricity as compared to 1,853.7 GW-hrs produced in the same period in 2022, an increase of 4.70%. Excluding the Deerfield II Wind Facility, which achieved COD on March 23, 2023, the Sandy Ridge II Wind Facility, which achieved COD on September
16, 2023, and the Shady Oaks II Wind Facility, which achieved COD on October 10, 2023, production was 7.9% below the same period last year. The wind facilities, including new facilities, generated electricity equal to 82.7% of LTAR as
compared to 90.0% during the same period in 2022.
For the three months ended December 31, 2023, the solar facilities generated 100.1
GW-hrs of electricity as compared to 90.5 GW-hrs of electricity in the same period in 2022, an increase of 10.6%. Excluding the Dalewood Solar Facility, which achieved COD on December 21, 2022, and the Hayhurst New Mexico Solar Facility, which
achieved COD on November 6, 2023, production was 3.6% above the same period last year. The solar facilities, including new facilities, generated electricity equal to 109.9% of LTAR as compared to 106.3% in the same period in 2022.
For the three months ended December 31, 2023, the thermal facilities generated 31.7
GW-hrs of electricity as compared to 29.7 GW-hrs of electricity during the same period in 2022. During the same period, the Windsor Locks Thermal Facility generated 144.9 billion lbs of steam as compared to 130.5 billion lbs of steam during the
same period in 2022.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
31
|
||||
2023 Annual Renewable Energy Group Performance
For the twelve months ended December 31, 2023, the Renewable Energy Group generated
7,669.0 GW-hrs of electricity as compared to 8,178.6 GW-hrs during the same period in 2022.
For the twelve months ended December 31, 2023, the hydro facilities generated 611.4
GW-hrs of electricity as compared to 609.2 GW-hrs produced in the same period in 2022, an increase of 0.4%. Electricity generated represented 100.7% of LTAR as compared to 100.4% during the same period in 2022.
For the twelve months ended December 31, 2023, the wind facilities produced 6,459.0 GW-hrs of
electricity as compared to 6,823.0 GW-hrs produced in the same period in 2022, a decrease of 5.3%. Excluding the Blue Hill Wind Facility, which achieved COD on April 14, 2022, the Deerfield II Wind Facility, which achieved COD on March 23, 2023,
the Sandy Ridge II Wind Facility, which achieved COD on September 16, 2023, and the Shady Oaks II Wind Facility, which achieved COD on October 10, 2023, production was 11.5% below the same period last year. The wind facilities generated
electricity equal to 81.9% of LTAR as compared to 93.5% during the same period in 2022.
For the twelve months ended December 31, 2023, the solar facilities generated 468.7
GW-hrs of electricity as compared to 469.8 GW-hrs of electricity produced in the same period in 2022, a decrease of 0.2%. Excluding the Dalewood Solar Facility, which achieved COD on December 21, 2022, and the Hayhurst New Mexico Solar Facility,
which achieved COD on November 6, 2023, production was 1.7% below the same period last year. The solar facilities generated electricity equal to 98.8% of LTAR as compared to 100.5% in the same period in 2022.
For the twelve months ended December 31, 2023, the thermal facilities generated 129.9
GW-hrs of electricity as compared to 276.6 GW-hrs of electricity during the same period in 2022. For the twelve months ended December 31, 2023, the Windsor Locks Thermal Facility generated 523.9 billion lbs of steam as compared to 520.2 billion
lbs of steam during the same period in 2022.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
32
|
||||
|
2023 Renewable Energy Group Operating Results
|
|||||||||||||||||||||||
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||||||
| (all dollar amounts in $ millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
|
Revenue1
|
|||||||||||||||||||||||
| Hydro | $ | 9.0 | $ | 13.1 | $ | 35.4 | $ | 51.5 | |||||||||||||||
| Wind | 59.4 | 64.5 | 199.5 | 221.4 | |||||||||||||||||||
| Solar | 6.6 | 2.8 | 31.0 | 30.1 | |||||||||||||||||||
| Thermal | 7.1 | 8.2 | 30.4 | 47.8 | |||||||||||||||||||
| Total Non-Regulated Energy Sales | $ | 82.1 | $ | 88.6 | $ | 296.3 | $ | 350.8 | |||||||||||||||
| Less: | |||||||||||||||||||||||
|
Cost of Sales - Energy2
|
(0.3) | (0.2) | (2.6) | (7.1) | |||||||||||||||||||
| Cost of Sales - Thermal | (3.7) | (5.2) | (16.9) | (34.5) | |||||||||||||||||||
|
Net Energy Sales 3,4
|
$ | 78.1 | $ | 83.2 | $ | 276.8 | $ | 309.2 | |||||||||||||||
|
Renewable Energy Credits5
|
5.9 | 7.6 | 27.5 | 27.8 | |||||||||||||||||||
| Other Revenue | 2.0 | 0.3 | 5.9 | 0.6 | |||||||||||||||||||
| Total Net Revenue | $ | 86.0 | $ | 91.1 | $ | 310.2 | $ | 337.6 | |||||||||||||||
| Expenses & Other Income | |||||||||||||||||||||||
| Operating expenses | (30.5) | (31.7) | (119.0) | (114.5) | |||||||||||||||||||
|
Dividend, interest, equity and other income6
|
32.8 | 21.6 | 109.3 | 91.2 | |||||||||||||||||||
|
HLBV income7
|
19.3 | 20.5 | 71.3 | 96.4 | |||||||||||||||||||
|
Divisional Operating Profit3,8,9
|
$ | 107.6 | $ | 101.5 | $ | 371.8 | $ | 410.7 | |||||||||||||||
| 1 |
Many of the Renewable Energy Group’s PPAs include annual rate increases. However, a change to
the weighted average production levels resulting from higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division as compared to the same period in the
prior year.
|
||||
| 2 | Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Hydro Facility which is sold to retail and industrial customers under multi-year contracts. | ||||
| 3 |
See Caution Concerning Non-GAAP Measures.
|
||||
| 4 |
This table contains a reconciliation of Net Energy Sales to revenue. The relevant sections of the table are derived from and should be read in conjunction with the consolidated
statement of operations and Note 21 in the annual consolidated financial statements, “Segmented information”. This supplementary disclosure
is intended to more fully explain disclosures related to Net Energy Sales and provides additional information related to the operating performance of AQN. Investors are cautioned that Net Energy Sales should not be construed as an alternative to revenue.
|
||||
| 5 | Qualifying renewable energy projects receive renewable energy certificates (“RECs”) for the generation and delivery of renewable energy to the power grid. The RECs represent proof that 1 MW-hr of electricity was generated from an eligible energy source. | ||||
| 6 |
Includes dividends received from Atlantica and related parties (see Notes 8 and 16 in the annual consolidated financial statements) as well as the equity investment in the Stella, Cranell, East Raymond and West Raymond Wind Facilities (collectively,
the "Texas Coastal Wind Facilities").
|
||||
| 7 |
HLBV income represents the value of net tax attributes earned by the Renewable Energy Group in
the period primarily from electricity generated by certain of its U.S. wind and U.S. solar generation facilities.
PTCs are earned as wind energy is generated based on a dollar
per kW-hr rate prescribed in applicable federal and state statutes. For the twelve months ended December 31, 2023, the Renewable Energy Group's eligible facilities generated 3,299.0 GW-hrs representing approximately $92.4 million in
PTCs earned as compared to 4,998.9 GW-hrs representing $130.0 million in PTCs earned during the same period in 2022. The majority of the PTCs have been allocated to tax equity investors to monetize the value to AQN of the PTCs and other
tax attributes which are the primary drivers of HLBV income offset by the return earned by the investor. Some PTCs have been utilized directly by the Company which has lowered its overall effective tax rate.
|
||||
| 8 | Certain prior year items have been reclassified to conform to current year presentation. | ||||
| 9 |
This table contains a reconciliation of Divisional Operating Profit to revenue for the
Renewable Energy Group. The relevant sections of the table are derived from and should be read in conjunction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to
Divisional Operating Profit and provides additional information related to the operating performance of the Renewable Energy Group. Investors are cautioned that Divisional Operating Profit should not be construed as an alternative to
revenue.
|
||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
33
|
||||
2023 Fourth Quarter Operating Results
For the three months ended December 31, 2023, the Renewable Energy Group’s facilities
generated operating revenue of $82.1 million (i.e., non-regulated energy sales) as compared to $88.6 million in the comparable period in the prior year.
For the three months ended December 31, 2023, the Renewable Energy Group's facilities
generated $107.6 million of Divisional Operating Profit as compared to $101.5 million during the same period in 2022, which represents an increase of $6.1 million or 6.0% (see Caution Concerning Non-GAAP Measures).
Highlights of the changes are summarized in the following table:
| (all dollar amounts in $ millions) | Three months ended December 31 | ||||
|
Prior Period Divisional Operating Profit1
|
$ | 101.5 | |||
| Existing Facilities and Investments | |||||
| Hydro: Increase is primarily driven by lower operating expenses across Hydro facilities | 1.8 | ||||
| Wind CA: Decrease is primarily due to lower wind resources across all Canadian wind facilities. | (1.9) | ||||
| Wind U.S.: Decrease is primarily due to lower wind resources across the majority of the U.S. wind facilities and lower availability revenue at the Maverick Creek Wind Facility. This is partially offset by lower operating expenses across most U.S. wind facilities. | (6.1) | ||||
| Solar: Increase is primarily due to favourable HLBV income as a result of tax attribute eligibility on the Great Bay Solar I Facility commissioned in 2018 ending and favourable capacity revenues for majority of the Solar Facilities. | 4.3 | ||||
| Thermal & Renewable Natural Gas: Increase is primarily driven by favourable capacity revenues at the Sanger Thermal Facility. | 1.7 | ||||
|
Investments and Other: Increase is primarily due to higher equity income from the Texas
Coastal Wind Facilities partially offset by unfavourable portfolio optimization revenue.
|
5.6 | ||||
| 5.4 | |||||
| New Facilities and Investments | |||||
|
Wind U.S: Decrease is primarily driven by the Deerfield II Wind Facility HLBV loss (achieved
COD in March 2023)
|
(1.4) | ||||
| (1.4) | |||||
| Foreign Exchange | 2.1 | ||||
|
Current Period Divisional Operating Profit1
|
$ | 107.6 | |||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
34
|
||||
2023 Annual Operating Results
For the twelve months ended December 31, 2023, the Renewable Energy Group’s facilities generated operating revenue of
$296.3 million (i.e., non-regulated energy sales) as compared to $350.8 million in the comparable period in the prior year.
For the twelve months ended December 31, 2023, the Renewable Energy Group’s
facilities generated $371.8 million of Divisional Operating Profit as compared to $410.7 million during the same period in 2022, which represents a decrease of $38.9 million or 9.5% (see Caution Concerning Non-GAAP Measures).
Highlights of the changes are summarized in the following table:
| (all dollar amounts in $ millions) | Twelve months ended December 31 | ||||
|
Prior Period Divisional Operating Profit1
|
$ | 410.7 | |||
| Existing Facilities | |||||
|
Hydro: Increase is primarily driven by lower purchased power in the Maritimes Region and
lower operating expenses across Hydro Facilities.
|
4.7 | ||||
| Wind CA: Decrease is primarily due to lower wind resources across all Canadian wind facilities. | (10.0) | ||||
| Wind U.S.: Decrease is primarily driven by lower wind resources across all U.S. wind facilities and lower HLBV income as a result of tax attribute eligibility on projects commissioned in 2012 ending. | (41.3) | ||||
| Solar: Decrease is primarily driven by unfavourable energy market pricing across majority of the Solar facilities. This is partially offset favourable capacity revenues across majority of the Solar facilities. | (4.8) | ||||
| Thermal & Renewable Natural Gas: | (0.2) | ||||
|
Investments and Other: Increase is primarily due to higher equity income from the Texas
Coastal Wind Facilities partially offset by unfavourable portfolio optimization revenue.
|
6.2 | ||||
| (45.4) | |||||
| New Facilities and Investments | |||||
|
Wind U.S.: Increase is primarily driven by the Deerfield II Wind Facility (achieved COD in
March 2023).
|
2.5 | ||||
|
Thermal & RNG: Increase is primarily driven by the Five Star and Bach RNG Facilities
(Fully acquired in August 2022).
|
2.3 | ||||
|
Other: Increase is primarily driven by the Blue Hill Wind Facility (achieved COD in April 2022).
|
4.3 | ||||
| 9.1 | |||||
| Foreign Exchange | (2.6) | ||||
|
Current Period Divisional Operating Profit1
|
$ | 371.8 | |||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
35
|
||||
AQN: CORPORATE AND OTHER EXPENSES
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||||||
| (all dollar amounts in $ millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Corporate and other expenses: | |||||||||||||||||||||||
| Administrative expenses | $ | 19.3 | $ | 21.2 | $ | 90.4 | $ | 80.2 | |||||||||||||||
| Loss on foreign exchange | 3.4 | 14.1 | 8.4 | 13.8 | |||||||||||||||||||
| Interest expense | 87.9 | 78.0 | 353.7 | 278.6 | |||||||||||||||||||
| Depreciation and amortization | 122.1 | 114.8 | 467.0 | 455.5 | |||||||||||||||||||
| Change in value of investments carried at fair value | (122.8) | 14.7 | 230.0 | 499.1 | |||||||||||||||||||
|
Interest, dividend, equity, and other loss (income)1
|
(7.8) | (2.5) | 0.7 | 3.2 | |||||||||||||||||||
| Pension and other post-employment non-service costs | 4.8 | 4.6 | 19.9 | 11.0 | |||||||||||||||||||
| Other net losses | 13.9 | 2.1 | 132.9 | 21.4 | |||||||||||||||||||
| Gain on derivative financial instruments | (0.6) | (6.4) | (4.6) | (4.4) | |||||||||||||||||||
| Income tax recovery | (1.2) | (28.6) | (86.3) | (61.5) | |||||||||||||||||||
| 1 | Excludes income directly pertaining to the Regulated Services and Renewable Energy Groups (disclosed in the relevant sections). | ||||
2023 Fourth Quarter Corporate and Other Expenses
For the three months ended December 31, 2023, administrative expenses totaled $19.3 million as compared
to $21.2 million in the same period in 2022. The decrease is primarily due to timing of expenses.
For the three months ended December 31, 2023, interest expense totaled $87.9 million as
compared to $78.0 million in the same period in 2022. The increase was approximately one-quarter due to the funding of capital deployed in 2023 and three-quarters due to the increase in interest rates on variable rate borrowings.
For the three months ended December 31, 2023, depreciation expense totaled $122.1
million as compared to $114.8 million in the same period in 2022.
For the three months ended December 31, 2023, change in investments carried at fair
value totaled a gain of $122.8 million as compared to a loss of $14.7 million in the same period in 2022. The Company records certain of its investments, including Atlantica, using the fair value method and accordingly any change in the fair
value of the investment is recorded in the consolidated statement of operations (see Note 8 in the annual consolidated financial statements).
For the three months ended December 31, 2023, pension and post-employment non-service
costs totaled $4.8 million as compared to $4.6 million in the same period in 2022. The increase was primarily due to higher interest costs and lower expected return on plan assets.
For the three months ended December 31, 2023, other net losses were $13.9 million as
compared to $2.1 million in the same period in 2022. The increase was primarily due to costs associated with the pursuit of a sale of the Company’s renewable energy business of $5.0 million, and $8.5 million for write-off of deferred financing
costs on the redemption of the Company’s 6.875% fixed-to-floating subordinated notes – Series 2018-A (the “2018 Subordinated Notes”). See Note 19 in the annual consolidated
financial statements.
For the three months ended December 31, 2023, the gain on derivative financial
instruments totaled $0.6 million as compared to a gain of $6.4 million in the same period in 2022. AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. The gains in the
fourth quarter of both 2023 and 2022 were primarily related to mark-to-markets on interest rate derivatives.
For the three months ended December 31, 2023, an income tax recovery of $1.2 million was
recorded as compared to an income tax recovery of $28.6 million during the same period in 2022. The decrease in income tax recovery was primarily due to increased earnings and the tax impact associated with the change in fair value of the
investment in Atlantica. The decrease in income tax recovery was partially offset by the tax impact associated with the valuation allowance recorded on the Renewable Energy Group in 2022 and accrued tax credits. For the three months ended
December 31, 2023, the Company accrued $19.3 million of ITCs and PTCs primarily associated with renewable energy projects that had been placed in service by the end of 2023 as compared to a $4.7 million recorded in the same period in 2022.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
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|
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2023 Annual Corporate and Other Expenses
During the twelve months ended December 31, 2023, administrative expenses totaled $90.4
million as compared to $80.2 million in the same period in 2022. The increase is primarily due to technology costs, including costs associated with cyber security, as well as costs previously shown as operating expenses now shown within
administrative expenses as the Company increased usage of its shared services model in an effort to drive future operational efficiencies.
For the twelve months ended December 31, 2023, interest expense totaled $353.7 million
as compared to $278.6 million in the same period in 2022. The increase was approximately one-quarter due to the funding of capital deployed in 2023 and three-quarters due to the increase in interest rates on variable rate borrowings.
For the twelve months ended December 31, 2023, depreciation expense totaled $467.0
million as compared to $455.5 million in the same period in 2022. The increase was primarily due to higher overall property, plant and equipment.
For the twelve months ended December 31, 2023, change in investments carried at fair
value totaled a loss of $230.0 million as compared to a loss of $499.1 million in the same period in 2022. The Company records certain of its investments, including Atlantica, using the fair value method and accordingly any change in the fair
value of the investment is recorded in the consolidated statement of operations (see Note 8 in the annual consolidated financial statements).
For the twelve months ended December 31, 2023, pension and post-employment non-service
costs totaled $19.9 million as compared to $11.0 million in the same period in 2022. The increase was primarily due to higher interest cost and lower expected return on plan assets.
For the twelve months ended December 31, 2023, other net losses were $132.9 million as
compared to $21.4 million in the same period in 2022. The increase was primarily due to the $46.5 million Kentucky Power Impairment, the Securitization Write-Off of $63.5 million, write-off of deferred financing costs on the redemption of the
2018 Subordinated Notes of $8.5 million and costs associated with the Strategic Review and the pursuit of a sale of the Company’s renewable energy business of $12.5 million, partially offset by a $12.0 million contingent gain resulting from
settlement of the purchase price of the Suralis Water System acquired in 2020. See Note 19 in the annual consolidated financial statements.
For the twelve months ended December 31, 2023, the gain on derivative financial
instruments totaled $4.6 million as compared to a gain of $4.4 million in the same period in 2022. AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. The gains for both
the twelve months ended December 31, 2023 and for the twelve months ended December 31, 2022 were primarily related to mark-to-markets on interest rate derivatives.
For the twelve months ended December 31, 2023, an income tax recovery of $86.3 million
was recorded as compared to an income tax recovery of $61.5 million during the same period in 2022. The increase in income tax recovery was primarily due to the tax impact associated with the valuation allowance recorded on the Renewable Energy
Group in 2022 and accrued tax credits. These tax recoveries were partially offset by the tax impact associated with the change in fair value of the investment in Atlantica and an increase in earnings. For the twelve months ended December 31,
2023, the Company accrued $54.8 million of ITCs and PTCs primarily associated with renewable energy projects that had been placed in service by the end of 2023 as compared to $18.4 million recorded in the same period in 2022.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
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|
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NON-GAAP FINANCIAL MEASURES
Reconciliation of Adjusted EBITDA to Net Earnings
The following table is derived from and should be read in conjunction with the
consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted EBITDA and provides additional information related to the operating performance of AQN. Investors are cautioned
that this measure should not be construed as an alternative to U.S. GAAP consolidated net earnings.
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||||||
| (all dollar amounts in $ millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net earnings (loss) attributable to shareholders | $ | 186.3 | $ | (74.4) | $ | 28.7 | $ | (212.0) | |||||||||||||||
| Add (deduct): | |||||||||||||||||||||||
| Net earnings attributable to the non-controlling interest, exclusive of HLBV | 16.5 | 6.0 | 53.5 | 18.9 | |||||||||||||||||||
| Income tax recovery | (1.2) | (28.6) | (86.3) | (61.5) | |||||||||||||||||||
| Interest expense | 87.9 | 78.0 | 353.7 | 278.6 | |||||||||||||||||||
|
Other net losses1
|
13.9 | 2.1 | 132.9 | 21.4 | |||||||||||||||||||
|
Unrealized loss (gain) on energy derivatives included in revenue2
|
0.5 | (2.1) | 7.5 | 0.9 | |||||||||||||||||||
| Asset impairment charge | 23.5 | 159.6 | 23.5 | 159.6 | |||||||||||||||||||
| Impairment of equity-method investee | — | 75.9 | — | 75.9 | |||||||||||||||||||
| Pension and post-employment non-service costs | 4.8 | 4.6 | 19.9 | 11.0 | |||||||||||||||||||
|
Change in value of investments carried at fair value3
|
(122.8) | 14.7 | 230.0 | 499.1 | |||||||||||||||||||
| Costs related to tax equity financing | — | — | 1.2 | — | |||||||||||||||||||
| Gain on derivative financial instruments | (0.6) | (6.4) | (4.6) | (4.4) | |||||||||||||||||||
| Gain on sale of renewable assets | — | (62.8) | — | (64.0) | |||||||||||||||||||
| Loss on foreign exchange | 3.4 | 14.1 | 8.4 | 13.8 | |||||||||||||||||||
| Depreciation and amortization | 122.1 | 114.8 | 467.0 | 455.5 | |||||||||||||||||||
| Adjusted EBITDA | $ | 334.3 | $ | 295.5 | $ | 1,235.4 | $ | 1,192.8 | |||||||||||||||
| 1 |
See Note 19 in the annual
consolidated financial statements.
|
||||
| 2 |
Includes $7.1 million of unrealized losses on derivatives included in equity income for the
twelve months ended December 31, 2023. See Note 8 in the annual consolidated financial statements.
|
||||
| 3 |
See Note 8 in the annual
consolidated financial statements.
|
||||
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|
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Reconciliation of Adjusted Net Earnings to Net Earnings
The following table is derived from and should be read in conjunction with the
consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Net Earnings and provides additional information related to the operating performance of AQN. Investors are
cautioned that this measure should not be construed as an alternative to consolidated net earnings in accordance with U.S. GAAP.
The following table shows the reconciliation of net earnings to Adjusted Net Earnings
exclusive of these items:
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||||||
| (all dollar amounts in $ millions except per share information) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net earnings (loss) attributable to shareholders | $ | 186.3 | $ | (74.4) | $ | 28.7 | $ | (212.0) | |||||||||||||||
| Add (deduct): | |||||||||||||||||||||||
| Gain on derivative financial instruments | (0.6) | (6.4) | (4.6) | (4.4) | |||||||||||||||||||
| Gain on sale of renewable assets | — | (62.8) | — | (64.0) | |||||||||||||||||||
|
Other net losses1
|
13.9 | 2.1 | 132.9 | 21.4 | |||||||||||||||||||
| Asset impairment charge | 23.5 | 159.6 | 23.5 | 159.6 | |||||||||||||||||||
| Impairment of equity-method investee | — | 75.9 | — | 75.9 | |||||||||||||||||||
| Loss on foreign exchange | 3.4 | 14.1 | 8.4 | 13.8 | |||||||||||||||||||
|
Unrealized loss (gain) on energy derivatives included in revenue2
|
0.5 | (2.1) | 7.5 | 0.9 | |||||||||||||||||||
|
Change in value of investments carried at fair value3
|
(122.8) | 14.7 | 230.0 | 499.1 | |||||||||||||||||||
| Costs related to tax equity financing | — | — | 1.2 | — | |||||||||||||||||||
| Adjustment for taxes related to above | 11.3 | (23.1) | (55.6) | (70.0) | |||||||||||||||||||
| Adjusted Net Earnings | $ | 115.5 | $ | 97.6 | $ | 372.0 | $ | 420.3 | |||||||||||||||
| Adjusted Net Earnings per common share | $ | 0.16 | $ | 0.14 | $ | 0.53 | $ | 0.61 | |||||||||||||||
| 1 |
See Note 19 in the annual
consolidated financial statements.
|
||||
| 2 |
Includes $7.1 million of unrealized losses on derivatives included in equity income for the
twelve months ended December 31, 2023. See Note 8 in the annual consolidated financial statements.
|
||||
| 3 |
See Note 8 in the annual
consolidated financial statements.
|
||||
For the three months ended December 31, 2023, Adjusted Net Earnings totaled $115.5 million as compared
to Adjusted Net Earnings of $97.6 million for the same period in 2022, an increase of $17.9 million.
For the twelve months ended December 31, 2023, Adjusted Net Earnings totaled $372.0 million as compared
to Adjusted Net Earnings of $420.3 million for the same period in 2022,a decrease of $48.3 million.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
39
|
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Reconciliation of Adjusted Funds from Operations to Cash Provided by Operating
Activities
The following table is derived from and should be read in conjunction with the
consolidated statement of operations and consolidated statement of cash flows. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Funds from Operations and provides additional information related to
the operating performance of AQN. Investors are cautioned that this measure should not be construed as an alternative to cash provided by operating activities in accordance with U.S GAAP.
The following table shows the reconciliation of cash provided by operating activities to
Adjusted Funds from Operations exclusive of these items:
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||||||
| (all dollar amounts in $ millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Cash provided by operating activities | $ | 200.7 | $ | 214.6 | $ | 628.0 | $ | 619.1 | |||||||||||||||
| Add (deduct): | |||||||||||||||||||||||
| Changes in non-cash operating items | (1.8) | 41.2 | 86.3 | 221.6 | |||||||||||||||||||
| Production based cash contributions from non-controlling interests | — | — | 9.1 | 6.2 | |||||||||||||||||||
|
Gain on sale of renewable assets
|
— | (62.8) | — | (64.0) | |||||||||||||||||||
| Costs related to tax equity financing | — | — | 1.2 | — | |||||||||||||||||||
| Acquisition-related costs | — | (1.1) | — | 7.4 | |||||||||||||||||||
| Adjusted Funds from Operations | $ | 198.9 | $ | 191.9 | $ | 724.6 | $ | 790.3 | |||||||||||||||
For the three months ended December 31, 2023, Adjusted Funds from Operations totaled
$198.9 million as compared to Adjusted Funds from Operations of $191.9 million for the same period in 2022, an increase of $7.0 million primarily due to higher cash interest paid in 2023.
For the twelve months ended December 31, 2023, Adjusted Funds from Operations totaled
$724.6 million as compared to Adjusted Funds from Operations of $790.3 million for the same period in 2022, a decrease of $65.7 million primarily due to higher cash interest paid in 2023.
SUMMARY OF PROPERTY, PLANT AND EQUIPMENT EXPENDITURES
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| December 31 | December 31 | ||||||||||||||||||||||
| (all dollar amounts in $ millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Regulated Services Group | |||||||||||||||||||||||
|
Rate Base Maintenance1
|
89.4 | $ | 78.5 | 347.4 | 316.5 | ||||||||||||||||||
| Rate Base Growth | 137.7 | 253.5 | 394.6 | 669.1 | |||||||||||||||||||
|
Property, Plant & Equipment Acquired2
|
— | — | — | 609.3 | |||||||||||||||||||
| $ | 227.1 | $ | 332.0 | $ | 742.0 | $ | 1,594.9 | ||||||||||||||||
|
Renewable Energy Group
|
$ | 32.6 | $ | 103.4 | $ | 320.3 | $ | 176.6 | |||||||||||||||
| Total Capital Expenditures | $ | 259.7 | $ | 435.4 | $ | 1,062.3 | $ | 1,771.5 | |||||||||||||||
| 1 | Maintenance expenditures are calculated based on the depreciation expense for the period. | |||||||
| 2 | Includes expenditures on Property, Plant & Equipment, equity-method investees, and acquisitions of operating entities that may have been jointly developed by the Company with another third party developer. Excludes temporary advances to joint venture partners in connection with capital projects under development or construction. | |||||||
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||||
2023 Fourth Quarter Property, Plant and Equipment Expenditures
During the three months ended December 31, 2023, the Regulated Services Group made
capital expenditures of $227.1 million as compared to $332.0 million during the same period in 2022. The Regulated Services Group's investments during the fourth quarter of 2023 were primarily related to the construction of transmission and
distribution main replacements, work on new and existing substation assets, and initiatives relating to the safety and reliability of water, electric and natural gas systems.
During the three months ended December 31, 2023, the Renewable Energy Group made capital
expenditures of $32.6 million as compared to $103.4 million during the same period in 2022. The Renewable Energy Group's investments during the fourth quarter of 2023 were primarily related to the development and/or construction of various
projects and ongoing maintenance capital at existing operating sites.
2023 Annual Plant and Equipment Expenditures
During the twelve months ended December 31, 2023, the Regulated Services Group incurred
capital expenditures of $742.0 million as compared to $1,594.9 million during the same period in 2022. The Regulated Services Group's investments in 2023 were primarily related to the construction of transmission and distribution main
replacements, work on new and existing substation assets, and initiatives relating to the safety and reliability of electric and natural gas systems. The Regulated Services Group's investments in 2022
included $609.0 million for the acquisition of Liberty Utilities (New York Water) Corp. (formerly New York American Water Company Inc.).
During the twelve months ended December 31, 2023, the Renewable
Energy Group incurred capital expenditures of $320.3 million as compared to $176.6 million during the same period in 2022.
The Renewable Energy Group's investments in 2023 were primarily related to the acquisition of the previously unowned portion of the Deerfield II Wind Facility and the development and/or construction of various projects and ongoing sustaining
capital at existing operating sites.
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|
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LIQUIDITY AND CAPITAL RESERVES
AQN has revolving credit and letter of credit facilities as well as separate credit
facilities for the Regulated Services Group and the Renewable Energy Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).
Bank Credit Facilities
The following table sets out the Bank Credit Facilities available to AQN and its
operating groups as at December 31, 2023:
| As at December 31, 2023 | As at December 31, 2022 | ||||||||||||||||||||||||||||
| (all dollar amounts in $ millions) | Corporate | Regulated Services Group | Renewable Energy Group | Total | Total | ||||||||||||||||||||||||
| Revolving and term credit facilities | $ | 1,075.0 |
1
|
$ | 2,387.0 |
2
|
$ | 1,100.0 |
3
|
$ | 4,562.0 | $ | 4,513.3 | ||||||||||||||||
| Funds drawn on facilities / commercial paper issued | (779.1) | (1,851.2) | (262.6) | (2,892.9) | (1,532.5) | ||||||||||||||||||||||||
| Letters of credit issued | (37.9) | (39.2) | (392.0) | (469.1) | (465.2) | ||||||||||||||||||||||||
| Liquidity available under the facilities | 258.0 | 496.6 | 445.4 | 1,200.0 | 2,515.6 | ||||||||||||||||||||||||
| Undrawn portion of uncommitted letter of credit facilities | (39.5) | — | (214.6) | (254.1) | (226.9) | ||||||||||||||||||||||||
| Cash on hand | 56.1 | 57.6 | |||||||||||||||||||||||||||
| Total Liquidity and Capital Reserves | $ | 218.5 | $ | 496.6 | $ | 230.8 | $ | 1,002.0 | $ | 2,346.3 | |||||||||||||||||||
|
1 Includes a $75 million uncommitted standalone letter of credit facility.
|
|||||||||||||||||||||||||||||
|
2 Includes $176.5 million fully drawn term facilities of Suralis and BELCO as at December 31, 2023 ($163.3 million as at December
31, 2022).
|
|||||||||||||||||||||||||||||
|
3 Includes $600 million of uncommitted standalone letter of credit facilities.
|
|||||||||||||||||||||||||||||
Corporate
On March 31, 2023, the Company's senior unsecured revolving credit facility (the
"Corporate Credit Facility") was amended and restated to increase the borrowing capacity from $500.0 million to $1.0 billion with a new maturity date of March 31, 2028. As at December 31, 2023, the Corporate Credit Facility had $779.1 million
drawn and had $2.4 million of outstanding letters of credit.
On March 31, 2023, the Company entered into a new $75.0 million uncommitted bi-lateral
credit facility. On June 1, 2023, the Company terminated its former $50.0 million uncommitted bi-lateral credit facility. As at December 31, 2023, the Company had issued $35.5 million of letters of credit from its $75.0 million uncommitted letter
of credit facility.
Regulated Services Group
As at December 31, 2023, the Regulated Services Group's $1.0 billion senior unsecured
revolving credit facility (the "Long-Term Regulated Services Credit Facility") had $371.0 million drawn and had $39.2 million of outstanding letters of credit. The Long-Term Regulated Services Credit Facility matures on April 29, 2027. As at
December 31, 2023, the Regulated Services Group had $481.7 million of commercial paper issued and outstanding. On October 27, 2023, the Company extended the maturity date of the Regulated Services Group's $500.0 million senior unsecured revolving
credit facility (the "Short-Term Regulated Services Credit Facility") from February 28, 2024 to October 25, 2024. As at December 31, 2023, the Short-Term Regulated Services Credit Facility had $125.0 million drawn and no outstanding letters of
credit.
As at December 31, 2023, the Regulated Services Group's $75.0 million senior unsecured
revolving credit facility (the "Bermuda Credit Facility") had $75.0 million drawn. Subsequent to the quarter end, on January 29, 2024, the Company amended the Bermuda Credit Facility, increasing the limit by $25 million to $100 million.
As at December 31, 2023, the Regulated Services Group's $25.0 million senior unsecured
bilateral revolving credit facility (the "Bermuda Working Capital Facility") had $11.5 million drawn.
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|
||||
On November 30, 2022, the Regulated Services Group amended and restated its $1.1
billion senior unsecured syndicated delayed draw term facility ("the "Regulated Services Delayed Draw Term Facility") with a new maturity date of November 29, 2023. On April 25, 2023, the Company elected to terminate the remaining undrawn amount
of $489.6 million. On October 27, 2023, the Company extended the maturity date of the Regulated Services Delayed Draw Term Facility from November 29, 2023 to October 25, 2024. As at December 31, 2023, the Regulated Services Delayed Draw Term Facility had $610.4 million drawn in connection with the acquisition of Liberty NY
Water.
Renewable Energy Group
As at December 31, 2023, the Renewable Energy Group's $500.0 million senior unsecured
syndicated revolving credit facility (the "Renewable Energy Credit Facility") had $262.6 million drawn and had $6.6 million in outstanding letters of credit. The Renewable Energy Credit Facility matures on July 22, 2027.
As at December 31, 2023, the Renewable Energy Group's bank lines consisted of $600.0
million letter of credit facilities (the "Renewable Energy LC Facilities"), including a $250.0 million uncommitted bilateral letter of credit facility and a $350.0 million uncommitted letter of credit facility. As at December 31, 2023, the
Renewable Energy LC Facilities had $385.4 million in outstanding letters of credit.
Long-Term Debt
On March 13, 2023, the Company repaid a $15.0 million senior unsecured note on its
maturity.
On July 31, 2023, the Company repaid a $75.0 million senior unsecured note on its
maturity.
On November 1, 2023, the Company repaid a $5.0 million senior unsecured note on its
maturity.
On November 6, 2023, the Company redeemed all $287.5 million of its 2018 Subordinated
Notes at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.
Issuance of $850 Million of Senior Unsecured Notes
On January 12, 2024, Liberty Utilities completed the Senior note Offering of $500
million aggregate principal amount of 5.577% senior notes due January 31, 2029; (the "2029 Notes") and $350 million aggregate principal amount of 5.869% senior notes due January 31, 2034 (the "2034 Notes" and, together with the 2029 Notes, the
"Senior Notes"). The Senior Notes are unsecured and unsubordinated obligations of Liberty Utilities and rank equally with all of Liberty Utilities' existing and future unsecured and unsubordinated indebtedness and senior in right of payment to
any existing and future Liberty Utilities subordinated indebtedness. The 2029 Notes were priced at an issue price of 99.996% of their face value and the 2034 Notes were priced at an issue price of 99.995% of their face value. Liberty Utilities
used the net proceeds from the sale of the Senior Notes to repay indebtedness.
Issuance of $305.5 Million of Securitized Utility Tariff Bonds
On January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The
Empire District Electric Company, completed an offering of Securitization Bonds comprised of approximately $180.5 million of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125.0
million aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy
transition costs related to the retirement of the Asbury generating plant. The principal asset securing the Securitization Bonds is the securitized utility tariff property.
Issuance of approximately $1.1 Billion of Subordinated Notes
On January 18, 2022, the Company closed (i) an underwritten public offering in the
United States of $750 million aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B due January 18, 2082 (the "U.S. Notes"); and (ii) an underwritten public offering in Canada of C$400 million aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A due
January 18, 2082 (the "Canadian Notes" and, together with the U.S. Notes, the "Subordinated Notes"). The following table summarizes the expected use of the net proceeds from the offerings of the Subordinated Notes compared to the actual use of
such net proceeds:
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|
||||
| Expected Use of Net Proceeds | Actual Use of Net Proceeds | ||||
|
As disclosed in the Company’s prospectus supplements dated January 12, 2022 relating to the
offerings of the Subordinated Notes, the Company previously expected that the net proceeds of the offerings of the Subordinated Notes would be used to partially finance the proposed acquisition of Kentucky Power Company and AEP Kentucky
Transmission Company, Inc. (the “Kentucky Power Acquisition”); provided that, in the “short-term”, prior to the closing of the Kentucky Power Acquisition, the Company expected to use the net proceeds to reduce indebtedness as follows:
(i) approximately $385.0 million to the Corporate Credit Facility; (ii) approximately $40.0 million to the Renewable Energy Credit Facility; (iii) approximately $415.0 million of commercial paper issued by Liberty Utilities; and (iv)
approximately $219.9 million to the Long-Term Regulated Services Credit Facility.
|
As a result of the Kentucky Power Transaction Termination, the Company’s actual use of the
net proceeds from the offerings of the Subordinated Notes is the reduction of indebtedness in such amounts as previously disclosed as the "short-term" use of the proceeds.
|
||||
Credit Ratings
AQN has a long-term consolidated corporate credit rating of BBB
from Standard & Poor’s Financial Services LLC, (“S&P”), a BBB rating from DBRS Limited (“DBRS”) and a BBB issuer rating from Fitch Ratings Inc. (“Fitch”). Liberty Utilities has a corporate credit rating of BBB from S&P, a BBB issuer
rating from Fitch and a Baa2 issuer rating from Moody’s Investor Service, Inc. (“Moody's”). Debt issued by Liberty Utilities has a rating of BBB from S&P, BBB+ from Fitch and Baa2 from Moody’s. Debt issued by Liberty Utilities Finance GP1
(“Liberty GP”) has a rating of BBB (high) from DBRS, BBB+ from Fitch, BBB from S&P and Baa2 from Moody's. Empire has an issuer rating of BBB from S&P and a Baa1 rating from Moody's. Liberty Utilities (Canada) LP, the parent company for
the Canadian regulated utilities under the Regulated Services Group, has an issuer rating of BBB from DBRS. Algonquin Power Co. (“APCo”) has a BBB issuer rating from S&P, a BBB issuer rating from DBRS and a BBB issuer rating from Fitch. The fixed-rate securitized utility tariff bonds (series 2024-A) issued by Empire District Bondco,
LLC have a rating of AAA (sf) from S&P and Moody’s.
In April 2023, following the announcement of the Kentucky Power Transaction Termination,
each of DBRS, Fitch, S&P and Moody’s made announcements regarding the credit ratings of the Corporation and its subsidiaries. DBRS and Fitch both affirmed their ratings and stable outlook on the Corporation and its subsidiaries, S&P
affirmed its ratings and revised its outlooks to stable from negative on the Corporation and its subsidiaries and Moody’s affirmed its ratings and stable outlooks on Liberty Utilities and Liberty GP.
In May 2023, following the announcement of the Strategic Review, S&P placed APCo on
credit watch with negative implications. APCo is the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group. In August 2023, following the conclusion of the Strategic Review and the Company’s announcement that
it will pursue the sale of its renewable energy business, S&P and Fitch made announcements regarding the credit ratings of the Corporation and its subsidiaries. S&P affirmed its ratings on AQN and its regulated utility subsidiaries and
revised the outlook on APCo from credit watch with negative implications to developing. Fitch affirmed the ratings of AQN and placed APCo on rating watch evolving. Both S&P and Fitch expect to resolve their respective rating watch on APCo
once more details are known on the transaction.
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Contractual Obligations
Information concerning contractual obligations as of December 31, 2023 is shown below:
| (all dollar amounts in $ millions) | Total | Due in less than 1 year |
Due in 1 to 3 years |
Due in 4 to 5 years |
Due after 5 years |
||||||||||||||||||||||||
|
Principal repayments on debt obligations1,2
|
$ | 8,537.7 | $ | 621.9 | $ | 1,333.8 | $ | 2,100.0 | $ | 4,482.0 | |||||||||||||||||||
| Advances in aid of construction | 88.1 | 3.6 | — | — | 84.5 | ||||||||||||||||||||||||
|
Interest on long-term debt obligations2
|
4,910.3 | 391.5 | 602.8 | 420.0 | 3,496.0 | ||||||||||||||||||||||||
| Purchase obligations | 765.3 | 765.3 | — | — | — | ||||||||||||||||||||||||
| Environmental obligations | 46.2 | 3.1 | 22.6 | 1.8 | 18.7 | ||||||||||||||||||||||||
| Derivative financial instruments: | |||||||||||||||||||||||||||||
| Cross currency interest rate swaps | 16.4 | 2.4 | 4.2 | 0.1 | 9.7 | ||||||||||||||||||||||||
| Interest rate swaps | 11.8 | 11.8 | — | — | — | ||||||||||||||||||||||||
| Energy derivative and commodity contracts | 76.3 | 14.3 | 29.3 | 20.6 | 12.1 | ||||||||||||||||||||||||
| Purchased power | 256.6 | 55.3 | 46.1 | 25.3 | 129.9 | ||||||||||||||||||||||||
| Gas delivery, service and supply agreements | 454.6 | 121.2 | 114.6 | 64.0 | 154.8 | ||||||||||||||||||||||||
| Service agreements | 557.7 | 73.7 | 118.5 | 106.0 | 259.5 | ||||||||||||||||||||||||
| Capital projects | 5.6 | 5.6 | — | — | — | ||||||||||||||||||||||||
| Land easements | 614.0 | 16.4 | 30.3 | 31.1 | 536.2 | ||||||||||||||||||||||||
| Contract adjustment payments on equity units | 39.6 | 39.6 | — | — | — | ||||||||||||||||||||||||
| Other obligations | 282.1 | 29.4 | 2.9 | 2.3 | 247.5 | ||||||||||||||||||||||||
|
Total Obligations3
|
$ | 16,662.3 | $ | 2,155.1 | $ | 2,305.1 | $ | 2,771.2 | $ | 9,430.9 | |||||||||||||||||||
| 1 | Exclusive of deferred financing costs, bond premium/discount, and fair value adjustments at the time of issuance or acquisition. | ||||
| 2 |
The Company's subordinated unsecured notes have a maturity in 2079 and 2082, respectively. However, the Company currently
anticipates repaying such notes in advance of maturity upon exercise of the Company’s redemption rights in accordance with the terms of the applicable indenture.
|
||||
| 3 |
Excludes performance guarantees and other commitments on behalf of variable interest entities. See Note 8 in the annual consolidated financial statements.
|
||||
Equity
The common shares of AQN are publicly traded on the Toronto Stock Exchange ("TSX") and
the New York Stock Exchange ("NYSE") under the trading symbol "AQN". As at March 6, 2024, AQN had 689,436,570 issued and outstanding common shares.
AQN may issue an unlimited number of common shares. The holders of common shares are
entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of AQN upon liquidation, dissolution or winding up of AQN.
All common shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.
AQN is also authorized to issue an unlimited number of preferred shares, issuable in one
or more series, containing terms and conditions as approved by the Board. As at March 7, 2024, AQN had outstanding:
•4,800,000 Cumulative Rate Reset Preferred Shares, Series A, yielding 6.576% annually for the five-year period ending
on December 31, 2028: and
•4,000,000 Cumulative Rate Reset Preferred Shares, Series D, yielding 5.091% annually for the five year period ending
on March 31, 2024.
In addition, AQN’s outstanding equity units (the "Green Equity Units") (that are in the
form of "corporate units") are listed on the NYSE under the ticker symbol "AQNU". As at March 7, 2024, there were 23,000,000 Green Equity Units outstanding. Pursuant to the purchase contract forming part of each outstanding Green Equity Unit,
holders are required to purchase AQN common shares by no later than June 15, 2024. The minimum settlement rate under each purchase contract is 2.7778 common shares and the maximum settlement rate is 3.3333 common shares, resulting in a minimum of
63,889,400 common shares and a maximum of 76,665,900 common shares issuable on settlement of the purchase contracts.
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During the year ended December 31, 2023, 100 Series C preferred shares of AQN that had
previously been issued in exchange for 100 Class B limited partnership units of St. Leon Wind Energy LP were redeemed for $14.5 million, and a loss of $2.4 million related to the redemption has been recognized.
Declaration of 2024 First Quarter Dividend of $0.1085 (C$0.1468) per Common Share
AQN currently targets annual growth in dividends payable to shareholders underpinned by
increases in earnings and cash flow.
The Board has declared a first quarter 2024 dividend of $0.1085 per common share payable
on April 15, 2024 to shareholders of record on March 29, 2024.
The Canadian dollar equivalent for the first quarter 2024 dividend is C$0.1468 per
common share.
The previous four quarter U.S. and Canadian dollar equivalent dividends per common share have been as
follows:
| Q2 2023 | Q3 2023 | Q4 2023 | Q1 2024 | Total | |||||||||||||
| U.S. dollar dividend | $ | 0.1085 | $ | 0.1085 | $ | 0.1085 | $ | 0.1085 | $0.4340 | ||||||||
| Canadian dollar equivalent | $ | 0.1453 | $ | 0.1460 | $ | 0.1497 | $ | 0.1468 | $0.5878 | ||||||||
At-The-Market Equity Program
On August 15, 2022, AQN re-established an at-the-market equity
program (“ATM Program”) that allowed the Company to issue up to $500 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price when issued on the TSX, the NYSE or any other
existing trading market for the common shares of the Company in Canada or the United States.
During the twelve months ended December 31, 2023, the Company did not issue any common
shares under the ATM Program. The ATM Program terminated in accordance with its terms on December 19, 2023.
The Company has issued, since the inception of its initial ATM Program in 2019, a
cumulative total of 36,815 common shares at an average price of $0.02 per share for gross proceeds of approximately $551.1 million (approximately $544.3 million net of commissions). Other related costs, primarily related to the establishment and
subsequent re-establishments of the ATM Program, were approximately $4.8 million.
Dividend Reinvestment Plan
Effective March 16, 2023, AQN suspended its shareholder dividend reinvestment plan ("the
Reinvestment Plan") for registered holders of common shares of AQN. Effective for the first quarter 2023 dividend (paid on April 14, 2023 to shareholders of record on March 31, 2023), shareholders participating in the Reinvestment Plan began
receiving cash dividends. If the Company elects to reinstate the Reinvestment Plan in the future, shareholders who were enrolled in the Reinvestment Plan at its suspension and remain enrolled at reinstatement will automatically resume
participation in the Reinvestment Plan.
As at December 31, 2023, 168,595,010 common shares representing approximately 24% of
total common shares outstanding had been registered with the Reinvestment Plan. On January 13, 2023, 4,370,289 common shares were issued under the Reinvestment Plan in connection with the Company's fourth quarter 2022 dividend.
SHARE-BASED COMPENSATION PLANS
For the three and twelve months ended December 31, 2023, AQN recorded $3.5 million and
$11.3 million in total share-based compensation expense, respectively, as compared to $3.9 million and $10.9 million for the same periods in 2022. The compensation expense is recorded as part of operating expenses in the consolidated statement of
operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As at December 31, 2023, total unrecognized compensation costs related to non-vested
share-based awards was $23.9 million and is expected to be recognized over a period of 1.8 years.
Stock Option Plan
AQN has a stock option plan that permits the grant of share options to officers,
directors, employees and selected service providers. Except in certain circumstances, the term of an option shall not exceed ten (10) years from the date of the grant of the option.
AQN determines the fair value of options granted using the Black-Scholes option-pricing
model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as an expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost
recognized at least equals the value of the
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vested portion of the award at that date. During the twelve months ended December 31,
2023, the Company granted 1,368,744 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of C$10.76, the market price of the underlying common share at the date of grant. One-third
of the options vest on each of December 31, 2023, 2024 and 2025. The options may be exercised up to eight years following the date of grant. No stock options were exercised during the twelve months ended December 31, 2023.
As at December 31, 2023, a total of 2,667,725 options were issued and outstanding under
the stock option plan.
Performance and Restricted Share Units
AQN issues performance share units (“PSUs”) and restricted share units ("RSUs") to
certain employees as part of AQN’s long-term incentive program. During the twelve months ended December 31, 2023, the Company granted (including dividends) a combined total of 2,841,967 PSUs and RSUs to employees of the Company. The
awards vest based on the terms of each agreement ranging from February 2023 to January 2025. During the twelve months ended December 31, 2023, the Company settled 922,883 PSUs, of which 451,003 PSUs were exchanged for common shares issued from treasury and
471,880 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs.
As at December 31, 2023, a combined total of 3,577,747 PSUs and RSUs were granted and
outstanding under the performance and restricted share unit plan.
Directors' Deferred Share Units
AQN has a Directors' Deferred Share Unit Plan. Under the plan, non-employee directors of
AQN receive all or any portion of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs. During the twelve months ended December 31,
2023, the Company issued 181,328 DSUs (including DSUs in lieu of dividends) to the non-employee directors of the Company. During the twelve months ended December 31, 2023, the Company settled 102,460 DSUs, of which 50,677 DSUs were exchanged for
common shares issued from treasury and 51,783 DSUs were settled at their cash value as payment for tax withholdings related to the settlement of DSUs.
As at December 31, 2023, a total of 724,583 DSUs were outstanding under the Directors’ Deferred Share Unit
Plan.
Bonus Deferral Restricted Share Units
The Company has a bonus deferral RSU program that is available to certain employees. The
eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in common shares, and therefore these RSUs are accounted for as equity awards. During the twelve
months ended December 31, 2023, the Company settled 69,115 bonus RSUs, of which 31,455 were exchanged for common shares issued from treasury and 37,660 RSUs were settled at their cash value as payment for tax withholdings related to the
settlement of the RSUs. In addition, during the twelve months ended December 31, 2023, 77,981 bonus deferral RSUs were granted (including RSUs in lieu of dividends) to employees of the Company pursuant to the bonus deferral RSU program. The RSUs
are 100% vested.
Employee Share Purchase Plan
AQN has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to
use a portion of their earnings to purchase common shares of AQN. The aggregate number of common shares reserved for issuance from treasury by AQN under this plan shall not exceed 4,000,000 shares. During the twelve months ended December 31,
2023, the Company issued 752,582 common shares to employees under the ESPP.
As at December 31, 2023, a total of 3,110,532 common shares had been issued under the
ESPP.
MANAGEMENT OF CAPITAL STRUCTURE
AQN views its capital structure in terms of its debt and equity levels at its individual
operating groups and at an overall company level.
AQN’s objectives when managing capital are:
•To maintain its capital structure consistent with investment grade credit metrics appropriate to the sectors in
which AQN operates;
•To maintain appropriate debt and equity levels and to limit financial constraints on the use of capital;
•To have available capital to finance capital expenditures sufficient to maintain existing assets;
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•To generate sufficient cash to fund sustainable dividends to shareholders as well as meet current tax and internal
capital requirements; and
•To have appropriately sized revolving credit facilities available for ongoing investment in growth and development
opportunities.
AQN monitors its cash position on a regular basis in an effort to have available funds
to meet normal course capital and other expenditures.
RELATED PARTY TRANSACTIONS
Equity-method investments
The Company entered into a number of transactions with equity-method investees in 2023
and 2022 (see Note 16 in the annual consolidated financial statements).
The Company provides administrative and development services to its equity-method
investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees1
$72.5 million in 2023, as compared to $63.9 million in 2022. Additionally, one of the equity-method investees (Liberty Development JV Inc., the Company’s former joint venture with funds managed by the Infrastructure and Power strategy of Ares
Management, LLC for its non-regulated development platform) provides development services to the Company on specified projects, for which it earns a development fee that is capitalized by the Company, upon reaching certain milestones. During the
year, the development fees charged to the Company were $27.9 million (2022 - $12.6 million). See Note 16
in the annual consolidated financial statements.
On July 5, 2023, the Company provided a $35 million non-interest-bearing loan to Liberty
Development JV Inc. The joint venture used these funds to return equity to its shareholders through which the Company received $17.5 million.
Redeemable non-controlling interest held by related party
Redeemable non-controlling interest held by related party represents a preference share
in a consolidated subsidiary of the Company acquired by Liberty Development Energy Solutions B.V. (a joint venture between the Company and Ares), an equity-method investee of the Company. (see Note 16 in the annual consolidated
financial statements). Redemption is not considered probable as at December 31, 2023. The preference share was used to finance a portion of the Company's investment in Atlantica. During the year ended December 31, 2023, the Company incurred
non-controlling interest attributable to Liberty Development Energy Solutions B.V. of $25.9 million, as compared to $15.2 million during the same period in 2022, and recorded distributions of $25.4 million, for the year ended December 31, 2023 as
compared to $13.8 million during the same period in 2022 (see Note 16 in the annual consolidated financial statements).
Liberty Development Energy Solutions B.V. has a secured credit facility in the amount of
$306.5 million maturing on September 30, 2024. It is collateralized through a pledge of Atlantica ordinary shares. A collateral shortfall would occur if the net obligation as defined in the credit agreement would equal or exceed 50% of the market
value of such Atlantica shares, in which case the lenders would have the right to sell Atlantica shares to eliminate the collateral shortfall. The Liberty Development Energy Solutions B.V. secured credit facility is repayable on demand if
Atlantica ceases to be a public company or if certain other events are announced or completed that could restrict AY Holdings’ ability to sell or transfer its Atlantica ordinary shares.
On January 4, 2024, the Company purchased the remaining 50% of the equity of Liberty
Development JV Inc. and Liberty Development Energy Solutions B.V. for $7.9 million. As a result, the redeemable non-controlling interest held by related party will be reclassified to long-term debt in 2024.
Non-controlling interest held by related party
Non-controlling interest held by related party represents interest in a consolidated
subsidiary of the Company acquired by a subsidiary of Atlantica in May 2019 for $96.8 million and an interest in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company, acquired by Liberty Development JV Inc. in November 2021 for
$39.4 million. The interest was used to finance a portion of the Company's investment in the Amherst Island Wind Facility. During the year ended December 31, 2023, the Company recorded distributions of $17.1 million, as compared to $21.0 million
during the same period in 2022.
1 Primarily Liberty Development JV Inc. and its
subsidiaries, Blue Hill Wind Energy Project Partnership and Red Lily Wind Energy Partnership.
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Transactions with Atlantica
On December 28, 2023, Liberty Development Spain, S.A., a wholly owned subsidiary of the
Company entered into an agreement to sell its 100% equity interests in Liberty Jimena, S.L. and Liberty Caparacena, S.L., and its 80% equity interest in Liberty Infrastructuras, S.L. to Atlantica for a nominal amount. As a result, the Company
recorded an impairment loss of $1.5 million. The transaction closed on January 23, 2024.
The above related party transactions have been recorded at the exchange amounts agreed
to by the parties to the transactions.
ENTERPRISE RISK MANAGEMENT
The Corporation is subject to a number of risks and uncertainties, certain of which are described
below. The risks discussed below are not intended to be a complete list of all risks that AQN, its subsidiaries and affiliates are encountering or may encounter. Please see the Company's most recent AIF available on SEDAR+ and EDGAR for a further
discussion of risk factors to which the Company is subject. To the extent of any inconsistency, the risks discussed below are intended to provide an update on those that were previously disclosed.
Risks Related to Changes in Laws and Regulations
The operations and activities of the Company, its subsidiaries and its business units
are subject to the laws, regulations, orders and other requirements of a variety of federal, state, provincial and local governments, including regulatory commissions, environmental agencies and other regulatory bodies, which laws, regulations,
orders, rules and other requirements affect the operations and activities of, and costs incurred by, the Company. The Company is accordingly subject to: risks associated with changing political conditions and changes in, modifications to,
reinterpretations of or application of existing laws, rules, orders or regulations, the imposition of new laws, rules, orders or regulations (including the power of eminent domain), and the taking of other action by governmental or regulatory
authorities, including, but not limited to, revocation, lapse, limitation or non-renewal of utility franchises or other rights to provide utility services to existing or new customers, potential limitations on water rights used by utilities in
providing service, actions to municipalize utility service areas or limitations on utility growth and/or expansions of service areas, any of which could adversely affect the Company’s business, regulatory approvals, assets, results of operations
and financial condition. If the Company or any of its subsidiaries or business units were found to be in violation of such applicable laws, regulations, orders or other requirements, they could be subject to significant penalties or legal
actions.
Treasury Risk Management
Downgrade in the Company's Credit Rating Risk
AQN has a long-term consolidated corporate credit rating of BBB from S&P, a BBB
issuer rating from DBRS and a BBB issuer rating from Fitch. APCo, the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group, has a BBB issuer credit rating from S&P, a BBB issuer rating from DBRS and a
BBB issuer rating from Fitch. Liberty Utilities, the parent company for the U.S. regulated utilities under the Regulated Services Group, has a issuer credit rating of BBB from S&P, a BBB issuer rating from Fitch and a Baa2 issuer rating from
Moody’s. Debt issued by Liberty Utilities has a rating of BBB from S&P, BBB+ from Fitch and Baa2 from Moody’s. Debt issued by Liberty GP, a special purpose financing entity of Liberty Utilities, has a rating of BBB (high) from DBRS, BBB+ from
Fitch, BBB from S&P and Baa2 from Moody’s. Empire has a BBB issuer rating from S&P and a Baa1 issuer rating from Moody's. Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services
Group has a BBB issuer rating from DBRS. The fixed-rate securitized utility tariff bonds (series 2024-A) issued by Empire District Bondco, LLC have a rating of AAA (sf) from S&P and Moody’s. There can be no assurance that any of the current
ratings of AQN or its subsidiaries will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.
The ratings indicate the agencies’ assessment of the ability to pay the interest and
principal of debt securities issued by such entities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost
of the securities when they are sold. A downgrade in AQN’s or any of its subsidiaries' issuer corporate credit ratings would result in an increase in AQN’s borrowing costs under its bank credit facilities and future long-term debt securities
issued. Any such downgrade could also adversely impact the market price of the outstanding securities of the Company, could impact the Company's ability to acquire additional regulated utilities and could require the Company or its subsidiaries
to post additional or replacement security under certain contracts and hedging arrangements, which could result in increased costs to the Company. If any of AQN’s ratings fall below investment grade (defined as BBB- or above for S&P and
Fitch, BBB (low) or above for DBRS and Baa3 or above for Moody's), AQN’s ability to issue short-term debt or other securities or to market those securities would be constrained or made more difficult or expensive. Therefore, any downgrade could
have a material adverse effect on AQN’s business, cost of capital, financial condition and results of operations.
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The Company is not adopting or endorsing such ratings, and such ratings do not indicate
AQN’s assessment of its own ability to pay the interest or principal of debt securities it issues. The Company is providing such ratings only to assist with the assessment of future risks and effects of ratings on the Company’s financing costs.
Each rating agency employs proprietary scoring methodologies that assess business and
financial risks of the entity rated. There can be no assurance that the principles on which the rating is based remain consistently applied, and these principles are subject to change from time to time at each rating agency’s discretion. For
example, a rating agency’s views on total allowable leverage, specific industry risk factors, country risk and the company’s business mix, among other factors, may change. Such changes could require AQN to adjust its business and strategy in
order to maintain its credit ratings. AQN currently anticipates that to continue to maintain a BBB flat investment grade credit rating, it will, among other things, need to execute its growth and asset recycling strategies in a manner that
preserves financial leverage targets and continues to generate at least 70% of EBITDA (as determined by applicable rating agency methodologies) from AQN’s Regulated Services Group. There can be no assurance that AQN will be successful, and the
failure to do so could have a negative impact on AQN’s credit ratings. The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within
the Renewable Energy Group. The Corporation is pursuing a sale of its renewable energy business, which, if completed, is expected to impact the activities needed in order to maintain a BBB flat investment grade rating. APCo’s credit ratings may
be subject to evaluation and/or downgrade by one or more notches (including to a sub-investment grade rating) in connection with the Company’s pursuit of a sale of its renewable energy business.
Capital Markets and Liquidity Risk
As at December 31, 2023, the Company had approximately $8,516.3 million of long-term
consolidated indebtedness. Management of the Company believes, based on its current expectations as to the Company's future performance, that the cash flow from operations, the funds available under its credit facilities, the proceeds of the
proposed sale of the renewable energy business or from other potential future dispositions, and its ability to access capital markets will be adequate to enable the Company to finance its operations, execute its business strategy and maintain an
adequate level of liquidity. However, the Company's expected revenue and capital expenditures are only estimates. Moreover, actual cash flows from operations will depend on regulatory, market and other conditions that are beyond the Company's
control and which may be impacted by the risk factors herein. As a result, there can be no assurance that management’s expectations as to future performance will be realized.
The Company's ability to obtain additional debt or equity or issue other securities, on
favourable terms or at all, may be adversely affected by negative perceptions of the Company, any adverse financial or operational performance, financial market disruptions, the failure or collapse of any financial institution, prevailing market
views or perceptions, or other factors outside the Company's control. In addition, the Company may at times incur indebtedness in excess of its long-term leverage targets, in advance of raising the additional equity or similar securities or
executing on asset recycling strategies necessary to repay such indebtedness and maintain its long-term leverage target. Any increase in the Company’s leverage or degradation of key credit metrics below threshold levels could, among other things:
limit the Company’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict the Company’s flexibility
and discretion to operate its business; limit the Company’s ability to declare dividends or maintain prior dividend levels; require the Company to dedicate a portion of cash flows from operations to the payment of interest on its existing
indebtedness, in which case such cash flows would not be available for other purposes; cause rating agencies to re-evaluate or downgrade the Company’s existing credit ratings; require the Company to post additional collateral security under some
of its contracts and hedging arrangements; expose the Company to increased interest expense on borrowings at variable rates; limit the Company’s ability to adjust to changing market conditions; place the Company at a competitive disadvantage
compared to its competitors; make the Company vulnerable to any downturn in general economic conditions; render the Company unable to make expenditures that are important to its future growth strategies and require the Company to pursue
alternative funding strategies, which may include accelerated asset recycling initiatives.
The Company will need to refinance or reimburse amounts outstanding under the Company’s
existing consolidated indebtedness over time. There can be no assurance the Company will be successful in refinancing its indebtedness when necessary or that additional financing will be obtained when needed, on commercially reasonable terms or
at all. In the event that the Company cannot refinance its indebtedness or raise additional indebtedness on terms that are no less favourable than the current terms, the Company's cash flows and ability to declare dividends or repay its
indebtedness may be adversely affected.
The Company's ability to meet its debt service requirements will depend on its ability
to generate cash in the future, which depends on many factors, including the Company's financial performance, debt service obligations, the realization of the anticipated benefits of acquisition, disposition and investment activities, and working
capital and capital expenditure requirements. In addition, the Company's ability to borrow funds in the future to make payments on outstanding debt will depend on the satisfaction of covenants in existing credit agreements and other agreements. A
failure to comply with any covenants or obligations under the Company’s consolidated indebtedness could result in a default under one or more such
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instruments, which, if not cured or waived, could result in the termination of dividends
by the Company and permit acceleration of the relevant indebtedness. There can be no assurance that, if such indebtedness were to be accelerated, the Company's assets would be sufficient to repay such indebtedness in full. There can also be no
assurance that the Company will generate cash flow in amounts sufficient to pay its outstanding indebtedness or to fund the Company's liquidity needs.
Interest Rate Risk
The Company is exposed to interest rate risk due to the impact of increasing benchmark
interest rates and credit spreads on certain outstanding variable interest indebtedness, as well as any new borrowings on existing and new credit facilities and other debt issuances. Fluctuations in interest rates may also impact the costs to
obtain other forms of capital and the feasibility of planned growth initiatives.
In addition, for the Regulated Services Group, costs resulting from interest rate
increases may not be recoverable in whole or in part, and “regulatory lag” may cause a time delay in the payment to the Regulated Services Group of any such costs that are recoverable. Rising interest rates may also negatively impact the
economics of development projects, acquisitions, dispositions and energy facilities, especially where project financing is being renewed or arranged.
As a result, fluctuations in interest rates, including the rate increases experienced in
2022 and 2023, could materially increase the Corporation’s financing costs, limit the Corporation’s options for financing or investment and adversely affect its results of operations, cash flows, key credit metrics, borrowing capacity and ability
to implement its business strategy.
As at December 31, 2023, approximately 85% of debt outstanding in AQN and its
subsidiaries was subject to a fixed rate of interest and as a result, such debt is not subject to significant interest rate risk in the short-term time horizon.
Borrowings subject to variable interest rates can fluctuate significantly from month to
month, quarter to quarter and year to year. AQN's target is to maintain a minimum of 85% fixed rate debt. As a result, the Company hedges the interest rate risk on its variable interest rate borrowings from time to time. On December 17, 2022, the
Company entered into an interest rate cap agreement in the amount of $390 million for the period between January 15, 2023 and January 15, 2024. On September 29, 2023, the Company entered into a new interest rate cap agreement in the amount of
$390 million for the period between January 15, 2024 and June 17, 2024.
Based on amounts outstanding as at December 31, 2023, the impact to interest expense on
variable rate loans from changes in interest rates are as follows:
•the Corporate Credit Facility is subject to a variable interest rate and had $779.1 million outstanding as at
December 31, 2023. The Corporate Credit Facility has locked in $197.5 million of the variable rate until March 29, 2024, $245.0 million of the variable rate until April 5, 2024 and $30.0 million of the variable rate until June 28, 2024 through a
six month interest election request. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $3.1 million annually;
•the Long-Term Regulated Services Credit Facility is subject to a variable interest rate and had $371.0 million outstanding as at December 31, 2023. As a
result, a 100 basis point change in the variable rate charged would impact interest expense by $3.7 million annually;
•the Short-Term Regulated Services Credit Facility is subject to a variable interest rate and had $125.0 million outstanding as at December 31, 2023. As a
result, a 100 basis point change in the variable rate charged would impact interest expense by $1.3 million annually;
•the Regulated Services Delayed Draw Term Facility is subject to a variable interest rate and had $610.4 million
outstanding as at December 31, 2023. The Regulated Services Group has locked in the variable rate
until April 27, 2024 through an interest election request. As a result, a 100 basis point change in the variable rate
charged would not impact interest expense;
•the Bermuda Credit Facility is subject to a variable interest rate and had $75.0 million outstanding as at December
31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.8 million annually;
•the Bermuda Working Capital Facility is subject to a variable interest rate and had $11.5 million outstanding as at
December 31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.1 million annually;
•the Regulated Services Group's commercial paper program is subject to a variable interest rate and had $481.7
million outstanding as at December 31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $4.8 million annually;
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•the Renewable Energy Credit Facility is subject to a variable interest rate and had $262.6 million outstanding as at
December 31, 2023. The Renewable Energy Credit Facility has locked in $120.0 million of the variable rate until June 28, 2024. As a result, a 100 basis point change in the variable rate charged would impact interest expense by
$1.4 million annually; and
•term facilities at Suralis that are subject to variable interest rates had $115.6 million outstanding as at December
31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.2 million annually.
The term loan facility at BELCO is subject to variable interest
rates. However, the Company separately entered into an interest swap agreement to hedge the risk associated with interest rate fluctuation.
Foreign Currency Risk
The functional currency of most of AQN's operations is the U.S. dollar, however AQN is
exposed to currency fluctuations from its Canadian and Chilean operations and may utilize equipment and/or commodities purchased from foreign suppliers.
AQN may enter into derivative contracts to hedge all or a portion of currency exchange
rate exposure that is transactional in nature and where a natural economic hedge does not exist (see Note
24 (b)(iii) in the annual consolidated financial statements). To the extent that the Company does enter into currency
hedges, the Company may not realize the full benefits of favourable exchange rate movement, and is subject to risks that the counterparty to the hedging contracts may prove unable or unwilling to perform their obligations under the contracts.
Canadian operations
The Company is exposed to currency fluctuations from its Canadian-based operations. AQN
manages this risk primarily through the use of natural hedges by using long-term debt in Canadian Dollars to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases.
Chilean operations
The Company is exposed to currency fluctuations from its Chilean-based operations. AQN
manages this risk primarily through the use of natural hedges by using long-term debt in Chilean pesos or indexed to the Chilean Peso to finance its Chilean operations.
Tax Risk and Uncertainty
The Corporation is subject to income and other taxes primarily in the United States,
Canada, Bermuda, and Chile, though it is subject to tax in other jurisdictions. Changes in tax laws or interpretations or applications thereof, which may or may not have a retroactive effect, in the jurisdictions in which the Corporation does
business could adversely affect the Company's results from operations, returns to shareholders, and cash flows.
Pending tax law changes that may adversely impact the Corporation’s effective tax rate
(and hence, financial results) or result in additional cash taxes include, but are not limited to:
•legislation proposed in Canada to generally limit the deductibility of interest and financing expenses to 30% of tax EBITDA. If enacted in the form
proposed, this legislation will generally apply to taxation years of the Corporation beginning on or after October 1, 2023; and
•implementation of global minimum tax rules in the various jurisdictions in which the Corporation operates pursuant
to the Organization for Economic Development’s initiative to prevent perceived base erosion and profit shifting. Legislation has been proposed in Canada pursuant to this initiative which, if enacted in the form proposed, will generally be
applicable for fiscal years of a “qualifying MNE group” (as defined in such proposed legislation) beginning on or after December 31, 2023.
The proposed rules are complex and once enacted will be subject to the Corporation’s
judgment in its application until further guidance is available.
The Corporation cannot provide assurance that the Canada Revenue Agency, the Internal
Revenue Service or any other applicable taxation authority will agree with the tax positions taken by the Corporation, including with respect to claimed expenses and the cost amount of the Corporation’s depreciable properties. A successful
challenge by an applicable taxation authority regarding such tax positions could adversely affect the results of operations and financial position of the Corporation.
Development by the Corporation of renewable power generation facilities in the United
States depends in part on federal tax credits and other tax incentives. The Inflation Reduction Act has extended and expanded certain energy credits, providing greater certainty regarding the availability of these credits on a going forward
basis. However, the rules governing these tax credits still include technical requirements for credit eligibility. If the Corporation is unable to complete construction on current or planned projects within certain deadlines or satisfy certain
new requirements relating to prevailing wage and apprenticeship requirements, the reduced incentives or elimination of incentives may be insufficient to
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support continued development or may result in substantially reduced financial benefits
from facilities that are completed. In addition, the Corporation has entered into certain tax equity financing transactions with financial partners for certain of its renewable power facilities in the United States, under which allocations of
future cash flows to the Corporation from the applicable facility could be adversely affected in the event that there are changes in U.S. tax laws that apply to facilities previously placed in service.
Credit/Counterparty Risk
AQN and its subsidiaries are subject to credit risk with respect to the ability of
customers and other counterparties to perform their obligations to the Company, including paying amounts that they owe to AQN or its subsidiaries. This credit risk exists with respect to utility customers, banks and other financing sources, as
well as counterparties to long-term PPAs, trade receivables, derivative financial instruments, energy management agreements, Engineering, Procurement, and Construction contracts, manufacturer contracts, and natural gas supply agreements, among
others. Additionally, bank deposits in excess of deposit insurance limits are subject to the risk that such excess amounts could be lost or forfeited in the event of a bank failure.
The Renewable Energy Group's revenues are approximately 11% of total Company revenues
with the majority earned from large investment-grade customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P and Fitch or BBB or higher by DBRS.
The remaining revenue of the Company is primarily earned by the Regulated Services
Group.
The credit exposure attributed to the Regulated Services Group's accounts receivable
balances at the water and wastewater distribution systems total $83.6 million which is spread over approximately 572,000 customer connections, resulting in an average outstanding balance of approximately $150 dollars per customer connection.
The natural gas distribution systems accounts receivable balances related to the natural
gas utilities total $126.6 million, while electric distribution systems accounts receivable balances related to the electric utilities total $150.8 million. The natural gas and electrical utilities both derive over 85% of their revenue from
residential customers and have a per customer connection average outstanding balance of $338 dollars and $488 dollars respectively. Counterparty performance risk also exists in the natural gas distribution utilities where suppliers could
potentially fail to supply natural gas leading to disruptions and potentially higher procurement costs. These risks are mitigated through the receipt of collateral from counterparties.
Adverse conditions in the energy and water industries or in the general economy, as well
as circumstances of individual customers or counterparties, may adversely affect the ability of a customer or counterparty to perform as required under its contract with the Company. Losses from a utility customer may not be offset by bad debt
reserves approved by the applicable utility regulator. If a customer under a PPA, unit contingent or fixed-shape offtake contract or other energy offtake or hedging arrangement with the Company is unable to perform, the Renewable Energy Group may
be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, RECs and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to
the facility or otherwise have a material adverse effect. Default by other counterparties, including lenders and counterparties to supply and construction contracts, service contracts, hedging contracts that are in an asset position, short-term
investments, agreements for the purchase of goods or services or other agreements, also could adversely affect the financial results of the Corporation. Losses associated with equipment failure, defects, design flaws or other issues resulting
from counterparty non-performance may not be covered by warranties or insurance.
Market Price Risk
The Renewable Energy Group enters into long-term offtake contracts at project inception.
Offtake contracts are either unit contingent (volumes are contingent on energy produced and price is fixed) or fixed for floating financial swaps (fixed contract volumes and pricing). These offtake contracts can be exposed to market settlements
related to transmission congestion, hedge shortfall and uncontracted generation prices.
Basis risk exists on both unit contingent and fixed volume financial swaps if the
offtake contract settles at a different point (i.e. hub settlement point vs. the point of injection to the system or the asset price node). In an effort to mitigate basis risk, the Company has from time to time entered into additional financial
contracts to fix the basis price.
There is a risk that the Renewable Energy Group is not able to generate the specified
amount of power at the specified time resulting in production shortfalls which can impact the settlement of fixed volume financial swaps. This risk is known as "hedge shortfall". A fixed volume financial swap pays the Renewable Energy Group a
fixed price for a fixed volume. When the energy produced is less than the fixed volume, the asset pays the settled market price (i.e. price node value) to the offtaker. In an effort to mitigate the risk of production shortfalls under hedges, the
Renewable Energy Group has from time to time sized the hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Events that can reduce production include (but are not
limited to) weather events (such as icing, low wind resource, cloud cover), transmission outages and mechanical failure.
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Merchant (uncontracted) generation may increase earnings volatility. In a rising price
environment, merchant generation generally results in higher earnings than a fully contracted portfolio. In a falling price environment, merchant generation generally results in lower earnings than a fully contracted portfolio. The Renewable
Energy Group is subject to the risk of impairment to its renewable power generation assets associated with potential declines in long-term forecasted power prices if the forecasted power prices are materially lower than current contracted prices
for the period following the expiration of the offtake agreement. The market price risk for the Renewable Energy Group is primarily within the ERCOT, PJM, and MISO markets.
The Company has elected the fair value option under ASC 825, Financial Instruments to
account for its investment in Atlantica, with changes in fair value reflected in the annual consolidated statement of operations. As a result, each dollar change in the traded price of Atlantica shares will correspondingly affect the Company's
net earnings by approximately $44 million.
Commodity Price Risk
The Regulated Services Group is exposed to energy and natural gas price risks at its
electric and natural gas systems. The Renewable Energy Group's exposure to commodity prices is primarily limited to exposure to natural gas price risk. In this regard, a representative discussion of these risks is set out as follows:
Regulated Services Group
The CalPeco Electric System provides electric service to the Lake Tahoe California basin
and surrounding areas at rates approved by the CPUC. The CalPeco Electric System purchases the energy, capacity, and related service requirements for its customers from NV Energy via a PPA at rates reflecting NV Energy’s system average costs.
The CalPeco Electric System's tariffs allow for the pass-through of energy costs to its
rate payers on a dollar for dollar basis, through the Energy Cost Adjustment Clause ("ECAC") mechanism, which allows for the recovery or refund of changes in energy costs that are caused by the fluctuations in the price of fuel and purchased
power. On a monthly basis, energy costs are compared to the CPUC approved base tariff energy rates and the difference is deferred to a balancing account. Annually, based on the balance of the ECAC balancing account, if the ECAC revenues were to
increase or decrease by more than 5%, the CalPeco Electric System's ECAC tariff allows for a potential adjustment to the ECAC rates which would eliminate the risk associated with the fluctuating cost of fuel and purchased power.
The Granite State Electric System is an open access electric utility allowing for its
customers to procure commodity services from competitive energy suppliers. For those customers that do not choose their own competitive energy supplier, Granite State Electric System provides a Default Service offering to each class of customers
through a competitive bidding process. This process is undertaken semi-annually for all Default Service customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric
System’s Default Service customers. Since this is a full requirements service, the winning bidder(s) take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State
Electric System which in turn receives pass-through rate recovery through a formal filing and approval process with the NHPUC on a semi-annual basis. The Granite State Electric System is only committed to the winning Default Service supplier(s)
after approval by the NHPUC so that there is no risk of commodity commitment without pass-through rate recovery.
The EnergyNorth Natural Gas System purchase pipeline capacity, storage and commodity
from a variety of counterparties. The EnergyNorth Natural Gas System's portfolio of assets and its planning and forecasting methodology are commonly approved periodically by the NHPUC through Least Cost Integrated Resource Plan filings which
typically are filed bi-annually but can be as long as a five-year interim period depending on the length of the review process. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity
costs on an annual basis through the Cost of Gas ("COG") filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC's approval of its filed COG. These rates are designed to fully recover
its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 16% of its normal winter period purchases under a NHPUC
approved hedging program. All costs associated with the fixed basis hedging program are allowed to be a pass-through to customers through the COG filing and the approved rates in said filing. Should commodity prices increase or decrease relative
to the initial annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its COG rates going forward up to 25% in order to minimize any under or over collection of its natural gas costs. In addition, any
under collections may be carried forward with interest to the next year’s corresponding COG period (i.e. winter to winter and summer to summer).
The Midstates Gas and Empire Gas Systems purchases pipeline capacity, storage and
commodity from a variety of counterparties, and file with the individual state commissions for recovery of their respective transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The
Midstates Gas Systems serves customers in Missouri, Illinois and Iowa and establishes rates for its customers within the PGA filing in each state and these rates are designed to fully recover its anticipated transportation, storage and commodity
costs. In order to minimize
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commodity price fluctuations, the Midstates Gas System has implemented a commodity
hedging program, consistent with regulator expectations and approvals, designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging program are allowed to be a
pass-through to customers through the PGA filing and are embedded in the approved rates in said filing. Rates can be adjusted on a monthly or quarterly basis in order to account for any commodity price increase or decrease relative to the initial
PGA rate, minimizing any under or over collection of its natural gas costs. Similar to the Midstates Gas System, the Empire Gas System serves customers in Missouri, and also implements a commodity hedging program designed to hedge 70% to 90% of
its winter demand inclusive of storage volumes withdrawn during the winter period. All related costs are embedded in approved rates and allowed to be a pass through to customers in the PGA. The Empire Gas System is permitted to file an Actual
Cost Adjustment (“ACA”) once a year which also includes a PGA filing. In addition to the ACA filing, three more optional PGA filings are allowed during the year. The Empire Gas System’s ACA year is from September 1 to August 31 for each year.
The Peach State Gas System purchases pipeline capacity, storage and commodity from a
variety of counterparties, and files with the Georgia Public Service Commission ("PSC") for recovery of its transportation, storage and commodity costs through a monthly PGA filing process. The Peach State Gas System establishes rates for its
customers within the PGA filings and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the annual Gas Supply Plan filed by the Company and
approved by the Georgia PSC includes a commodity hedging program designed to hedge approximately 30% of its non-storage related commodity purchases during the winter months. All gains and losses associated with the hedging program are passed
through to customers in the PGA filings and are embedded in the approved rates in such filings. Rates can be adjusted on a monthly basis in order to account for any differences in natural gas costs relative to the amounts assumed in the PGA
filings, minimizing any under or over collection of its natural gas costs.
The Empire Electric System’s natural gas procurement program for electrical generation
is designed to manage costs to mitigate volatile natural gas prices. The Empire Electric System periodically enters into fixed price contracts with counterparties to hedge future natural gas prices in an attempt to lessen the volatility in fuel
expenditures. Generally, the over/under variances associated with the hedging program are passed through to customers in the fuel adjustment clause assuming they are deemed to be prudently incurred.
BELCO purchases Heavy Fuel Oil, Light Fuel Oil and diesel which are transported and
stored in facilities in Bermuda until such time as they are delivered and consumed in its electricity generation operations. While the cost of this fuel is included in traditional rate filings through a Fuel Adjustment Rate (“FAR”), the
variability in the commodity pricing has led the Regulatory Authority of Bermuda to establish a quarterly reconciliation and adjustment to the FAR. This filing evaluates current commodity pricing and usage as well as projected commodity pricing
to develop the FAR for the upcoming quarter. Additionally, BELCO has periodically used hedging to lock in commodity rates in an effort to reduce pricing volatility and protect customer rates.
Renewable Energy Group
The Sanger Thermal Facility sells capacity (Reserve Adequacy) in the California market
which carries dispatch obligations to CAISO. Sanger is dispatched in the CAISO energy market based on the price of its energy offers submitted to CAISO. These energy offers are priced using Sanger’s cost of production which includes fuel costs,
fuel energy required (Heat rate), variable operating costs and environmental offsets. As the fuel price changes, Sanger’s cost of production and CAISO energy market offers are adjusted accordingly thereby insulating Sanger from fuel price
exposure.
OPERATIONAL RISK MANAGEMENT
Dispositions, including Risks Relating to the Planned Sale of the Company's Renewable
Energy Business
For financial, strategic and other reasons, the Corporation may from time to time
dispose of, or desire to dispose of, businesses or assets (in whole or in part) that it owns. Any disposition by the Corporation may result in recognition of a loss upon such a sale and may result in a decrease to its revenues, cash flows and net
income and a change to its business mix. A disposition may also result in liabilities to the Corporation, including as a result of any post-closing indemnities or purchase price adjustments. In addition, the Corporation may not be able to dispose
of businesses or assets that the Corporation desires to sell for financial, strategic and other business reasons at all or at a price acceptable to the Corporation. Failure to execute on any planned disposition may require the Corporation to seek
alternative sources of funds, including one or more potential issuances of equity, or incur additional indebtedness, which may, among other things, cause rating agencies to re-evaluate or downgrade the Corporation’s existing credit ratings. Each
of the foregoing items may have an adverse effect on the Corporation’s business, results of operations, cost of capital or financial condition.
On August 10, 2023, the Company announced its pursuit of a sale of its renewable energy
business. There can be no assurance about the outcome of this sale process, the specific assets that will be sold (if any), that any specific transaction will be identified or consummated, or that any such transaction will achieve any expected
result or benefit. Divesting any or all of the assets comprising the Company’s renewable energy business involves a number of risks and uncertainties, including complexities involved in separating assets that may be sold from assets the Company
will retain, the need to
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obtain regulatory approvals and other third-party consents, which could, among other
things, disrupt customer and supplier relationships, and the fact that the Company may be subject to additional tax obligations or loss of certain tax benefits. If the Company disposes of all or a portion of the assets comprising the Company’s
renewable energy business, it may not be able to successfully cause a buyer to assume the liabilities related to such assets or, even if such liabilities are assumed, the Company may have difficulties enforcing its rights, contractual or
otherwise, against the buyer. The Company may be required to provide transitional services to the buyer for a period of time following closing of a transaction, and the Company may retain obligations related to divested assets, and may be subject
to potential liabilities that arise because of the disposition or the subsequent breaches of obligations or duties by the buyer. There are factors that could delay, prevent or otherwise adversely affect the planned sale, including but not limited
to market conditions or delays in obtaining necessary counterparty approvals, regulatory approvals or clearances. In addition, whether or not any specific transaction is identified, pursued and/or consummated, the process could cause disruptions
in the business of the Company by diverting the attention of the Board and management and diverting other resources (including costs) towards such process and the preparation of the Company to pursue and consummate a transaction. The process
could also impact the Company’s relationships with employees, including by increasing employee departures and turnover, could give rise to disputes with potential buyers and could result in accounting changes, restructuring and other disposition
charges, as well as potential impairment charges or losses. The sale of any or all of the assets comprising the Company's renewable energy business could negatively impact the Company’s profitability, financial results and dividends because of
losses that may result from such a sale, the loss of revenues or a decrease in cash flows or cash available for distribution. In addition, APCo may be subject to one or more credit rating downgrades as a result of the Corporation’s pursuit of its
renewable energy business. Following a sale of any or all of the assets comprising the Company's renewable energy business, the Company would also have less diversity in the asset mix of its business and in the markets it serves. Any or all of
these risks could impact the Company’s financial results and business reputation.
Mechanical and Operational Risks
AQN's profitability could be impacted by, among other things, equipment failure, the
failure of a major customer to fulfill its contractual obligations, reductions in average energy prices, a strike or lock-out at a facility, natural disasters, diseases and other force majeure events, interruption in supply chain and expenses
related to claims or clean-up to adhere to environmental and safety standards.
The Regulated Services Group's water and wastewater distribution systems operate under
pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other
property. In addition, contamination of water or equipment in a in drinking water distribution system could result in severe injury, illness or death to those who drink the impacted water.
The Regulated Services Group's electric distribution systems are subject to storm
events, usually winter storm events, whereby power lines can be brought down, with the attendant risk to individuals and property. Wildfires have occurred, and may in the future occur, within the Regulated Services Group’s electric distribution
service territories, including, without limitation, in California and other parts of the United States in which the Corporation operates, such as the Mountain View fire that occurred on November 17, 2020 within the CalPeco Electric System’s
service territory in California. Trees falling on and lightning strikes to, distribution lines or equipment, can ignite wildfires which may pose a risk to life and property. If the Company is accused or found to be responsible for such a fire
(regardless of whether it is at fault or negligent), the Company could suffer costs, losses and damages, including inverse condemnation, all or some of which may not be recoverable through insurance, legal, regulatory recovery and other
processes.
The Regulated Services Group's natural gas distribution systems are subject to risks
which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.
The Company's hydro assets utilize dams to pond water for generation and if the dams
fail/breach potentially catastrophic amounts of water would flood downriver from the facility. The dams can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to fall short of
either hedged or PPA committed production levels. The risks of the hydro facilities are mitigated by regular dam inspections and a maintenance program of the facility to lessen the risk of dam failure.
The Company's assets could catch on fire and, depending on the season, could ignite
significant amounts of forest or crop downwind from the wind farms. The wind units could also be affected by large atmospheric conditions, which could lower wind levels below the Company's PPA and hedge minimum production levels. The wind units
can experience failures in the turbine blades or in the supporting towers. Production risks associated with the wind turbine generators failures is mitigated by properly maintaining the units, using long-term maintenance agreements with the
turbine O&Ms which provide for regular inspections and maintenance of property, and liability insurance policies.
The Company's Thermal Energy Division uses natural gas and oil, and produces exhaust
gases, which if not properly treated and monitored could cause hazardous chemicals to be released into the atmosphere. The units could also be restricted
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from purchasing natural gas/oil due to either shortages or pollution levels, which could
hamper output of the facility. The mechanical and operational risks at the thermal facilities are mitigated through the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged in
part by long-term purchases.
All of the Renewable Energy Group's electric generating stations are subject to
mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.
In general, these risks are, in part, mitigated through the diversification of AQN’s
operations, both operationally and geographically. In addition, AQN seeks to mitigate these risks through the use of regular maintenance programs, including pipeline safety programs and compliance programs, the provision of adequate insurance, an
active Enterprise Risk Management program and the establishment of reserves for expenses.
Regulatory Risk
Profitability of AQN businesses is, in part, dependent on regulatory climates in the
jurisdictions in which those businesses operate. In the case of some of Renewable Energy Group's hydroelectric facilities, water rights are owned by governments that reserve the right to control water levels, which may affect revenue.
The Regulated Services Group’s facilities are subject to rate setting by its regulatory
agencies. The Regulated Services Group operates utilities in 13 U.S. states, one Canadian province, Bermuda and Chile and therefore is subject to regulation from 17 different regulatory agencies including FERC. The time between the incurrence of
costs and the granting of the rates to recover those costs by regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects and timing delays may impact the ability to recover expenses and/or capital costs,
and profitability could be impacted. In order to mitigate this exposure, the Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses and
capital costs. A fundamental risk faced by any regulated utility is the disallowance of operating expenses or capital costs to be placed into its revenue requirement by the utility's regulator. As the Company is in the process of updating its
technology infrastructure systems, there is a risk that financial data required for rate filings could be difficult to produce or deemed unreliable for ratemaking purposes, thus increasing the risk of disallowance and/or regulatory lag. In
addition, capital investments that have become stranded may pose additional risk for cost recovery and could be subject to legislative proposals that would impact the extent to which such costs could be recovered. To the extent proposed costs are
not included in the utility's revenue requirement, the utility will be required to find other efficiencies, growth opportunities or cost savings to achieve its allowed returns.
The Regulated Services Group regularly works with its governing authorities to manage
the affairs of the business, employing local, state level, and corporate resources.
Condemnation Expropriation Proceedings
The Regulated Services Group's distribution systems could be subject to condemnation or
other methods of taking by government entities under certain conditions. Any taking by government entities would legally require fair compensation to be paid. Determination of such fair compensation is undertaken pursuant to a legal proceeding
and, therefore, there is no assurance that the value received for assets taken will be in excess of book value.
Inflation Risk
AQN's profitability could be impacted by inflation increases above long-term averages.
The Regulated Services Group’s facilities are subject to rate setting by its regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by regulatory agencies is known as regulatory lag. As
a result of regulatory lag, inflationary effects and timing delays may impact the ability to recover expenses and/or capital costs, and profitability could be impacted. In the event of significant inflation, the impact of regulatory lag on the
Company would be increased. In order to mitigate this exposure, the Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses and capital
costs.
The Renewable Energy Group's assets are subject to long-term PPAs and other offtake
agreements, most of which are not indexed to inflation and could experience declines in profitability if operating costs increase at a rate greater than the offtake price.
Development and construction projects could experience a decrease in expected returns as
a result of increased costs. To mitigate the risk of inflation the Company attempts to enter into fixed price construction agreements and fixed price offtake agreements.
Tariff Risk
Changes in tariffs or duties, such as antidumping and countervailing duty rates related
to the U.S. Department of Commerce's investigation into an antidumping and countervailing duties circumvention claim on solar cells and panels supplied from Malaysia, Vietnam, Thailand and Cambodia, may adversely affect the capital expenditures
required to develop or construct the Corporation’s projects, as well as the timing for completion, or viability, of such projects. In the
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U.S., tariffs have been imposed in recent years on imports of solar panels, solar cells,
aluminum and steel, among other goods and raw materials. These occurrences may have adverse impacts to the Corporation, as the buyer of goods, which could adversely affect the Corporation’s expected returns, results of operations and cash flows.
International Investment Risk
The Company operates in markets, or may pursue growth opportunities in new markets, that
are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or regulations may not provide the same type of legal certainty and rights, in connection with the
Company’s contractual relationships in such countries, as are afforded to the Company in Canada and the U.S., which may adversely affect the Company’s ability to receive revenues or enforce its rights in connection with any operations or projects
in such jurisdictions. In addition, the laws and regulations of some countries may limit the Company’s ability to hold a majority interest in certain projects, thus limiting the Company’s ability to control the operations of such projects. Any
existing or new operations or interests of the Company may also be subject to significant political, economic and financial risks, which vary by country, and may include: (i) changes in government laws, policies or personnel or a country's
constitution; (ii) changes in general economic conditions; (iii) restrictions on currency transfer or convertibility; (iv) changes in labour relations; (v) political instability and civil unrest; (vi) regulatory or other changes adversely
affecting the local utility market; (vii) breach or repudiation of important contractual undertakings and expropriation and confiscation of assets and facilities without compensation or compensation that is less than fair market value; (viii)
less developed or efficient financial markets than in North America; (ix) the absence of uniform accounting, auditing and financial reporting standards, practices and disclosure requirements; (x) less government supervision and regulation; (xi) a
less developed legal or regulatory environment, including uncertainty in outcomes and actions that may be inconsistent with the rule of law; (xii) heightened exposure to bribery and corruption risk; (xiii) political hostility to investments by
foreign investors, including laws affecting foreign ownership; (xiv) less publicly available information in respect of companies; (xv) adversely higher or lower rates of inflation; (xvi) higher transaction costs; and (xvii) fewer investor
protections.
The Company may suffer a significant loss resulting from fraud, bribery, corruption or
other illegal acts, or from inadequate or failed internal processes or systems. The Company operates in multiple jurisdictions and it is possible that its operations and development activities may expand into new jurisdictions. Doing business in
multiple jurisdictions requires the Company to comply with the laws and regulations of such jurisdictions. These laws and regulations may apply to the Company, its subsidiaries, individual directors, officers, employees and third-party agents.
The Company is also subject to anti-bribery and anti-corruption laws, including the Canadian Corruption of Foreign Public Officials Act and the U.S. Foreign Corrupt Practices Act. As the Company makes acquisitions and pursues development
activities internationally, it is exposed to increased corruption-related risks, including potential violations of applicable anti-corruption laws.
The Company relies on its infrastructure, controls, systems and personnel, as well as
central groups focusing on enterprise-wide management of specific operational risks such as fraud, trading, outsourcing, and business disruption, to manage the risk of illegal and corrupt acts or failed systems. The Company also relies on its
employees and certain third parties to comply with its policies and processes as well as applicable laws. The failure to adequately identify or manage these risks, and the acquisition of businesses with weak internal controls to manage the risk
of illegal or corrupt acts, could result in direct or indirect financial loss, regulatory censure and/or harm to the Company’s reputation.
Risks Specific to the Atlantica Investment
The Company’s investment in Atlantica exposes the Company to certain risks that are
particular to Atlantica’s business and the markets in which Atlantica operates.
Atlantica owns, manages and acquires renewable energy, conventional power, electric
transmission lines and water assets in certain jurisdictions where the Company may not operate. The Company, through its investment in Atlantica, is indirectly exposed to certain risks that are particular to the markets in which it operates,
including, but not limited to, risks related to: conditions in the global economy; changes to national and international laws, political, social and macroeconomic risks relating to the jurisdictions in which Atlantica operates, including in
emerging markets, which could be subject to economic, social and political uncertainties; anti-bribery and anti-corruption laws and substantial penalties and reputational damage from any non-compliance therewith; significant currency exchange
rate fluctuations; Atlantica’s ability to identify and/or consummate future acquisitions on favourable terms or at all; Atlantica’s inability to replace, on similar or commercially favourable terms, expiring or terminated offtake agreements;
termination or revocation of Atlantica’s concession agreements or offtake agreements; and various other factors. These risks could affect the profitability and growth of Atlantica’s business, and ultimately the profitability of the Company’s
anticipated investment therein. On February 21, 2023, Atlantica announced that its board of directors had commenced a process to explore and evaluate potential strategic alternatives to maximize shareholder value (the “Atlantica Strategic
Review”). There is a risk that the Atlantica Strategic Review could result in the approval or completion of a transaction or other change in Atlantica's business strategy that is not aligned with the Company’s interests. If any of the foregoing
were to occur, the value of the Company’s investment could decrease and the Company’s financial condition, results of operations and cash flows could be adversely affected.
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The Company’s international activities and operations expose the Company to similar
risks and could likewise affect the profitability, financial condition and growth of the Company.
The Company accounts for its investment in Atlantica using the Fair Value Method (see Note 8(a) in the annual consolidated financial statements). AQN
records in the consolidated statement of operations the fluctuations in the fair value of Atlantica shares and dividend income when it is declared. Dividends declared and paid by Atlantica are made at the discretion of Atlantica’s board of
directors. The Company does not control the board of directors of Atlantica. Therefore, there can be no assurance that dividends will continue to be paid on Atlantica’s ordinary shares, will continue to be paid at the same rate as they are
currently being paid or will be paid at any specified target rate. A loss of Atlantica dividend income, as a result of any reduction or suspension by Atlantica of its dividend or in the event that the Company were to dispose of its equity
interest in Atlantica, could have a material adverse impact on the Company's cash flows and net income.
Joint Venture Investment Risk
The Company has, and may in the future continue to have, an equity interest of less than
100% and/or partners in certain projects and facilities. As a result, the Company may not operate or control all or any decision-making in respect of such projects and facilities and its interest may be subject to the decision-making of third
parties, and the Company may be reliant on a third party’s personnel, good faith, contractual compliance, expertise, historical performance, technical resources and information systems, proprietary information and judgment in providing the
services. This may limit the Company’s flexibility and financial returns with respect to these projects and facilities, and create risks to the Company, including that the joint venture partner may:
•have economic or business interests or goals that are inconsistent with the Company’s economic or business interests
or goals;
•take actions contrary to the Company’s policies or objectives with respect to the Company’s investments;
•contravene applicable anti-bribery laws that carry substantial penalties for non-compliance and could cause
reputational damage and a material adverse effect on the business, financial position and results of operations of the joint venture and the Company;
•have to give its consent with respect to certain transactions and decisions, including among others, the sale of the
Corporation’s renewable energy business and decisions relating to funding and transactions with affiliates;
•become bankrupt, limiting its ability to meet calls for capital contributions and potentially making it more
difficult to refinance or sell projects;
•become engaged in a dispute with the Company that might affect the Company’s ability to develop, construct or
operate a project;
•have competing interests in the Company’s markets that could create conflict of interest issues; or
•have different accounting policies than the Company.
The Company has entered into Equity Capital Contribution Agreements ("ECCA") with
certain of its project development entities it holds an equity interest in. The ECCAs obligate the Company to provide funding upon the realization of certain completion milestones related to the projects under development. The ECCAs have been
pledged as collateral against construction loans obtained by the project entities and may require the Company to fund in amounts in excess of the underlying value of the assets. The Company has also provided guarantees of performance for certain
development projects owned by the equity investees. The Company's maximum exposure to loss (as defined in U.S. GAAP under ASC 810) on these agreements and guarantees is $1,044.5 million as of December 31, 2023.
Please refer to Note 8 in the annual consolidated
financial statements for a description of the Company's Long-Term Investments and Notes Receivable.
Asset Retirement Obligations
AQN and its subsidiaries complete periodic reviews of potential asset retirement
obligations that may require recognition. As part of this process, AQN and its subsidiaries consider the contractual requirements outlined in their operating permits, leases, and other agreements, the probability of the agreements being extended,
the ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.
In conjunction with acquisitions and developed projects, the Company assumed certain
asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal or decommissioning of power generating facilities; (ii) cut (disconnect from the distribution system), purge (clean of natural gas
and PCB contaminants), and cap natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or dispose of sections of natural gas mains when removed from the pipeline system; (iii) clean and
remove storage tanks containing
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waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation
or demolition of structures and facilities.
Cycles and Seasonality
Regulated Services Group
The Regulated Services Group's demand for water is affected by weather conditions and
temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more
frequent than normal the demand for water may decrease, adversely affecting revenues.
The Regulated Services Group's demand for energy from its electric distribution systems
is primarily affected by weather conditions and conservation initiatives. The Regulated Services Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have
short-term adverse impacts on revenues.
The Regulated Services Group's primary demand for natural gas from its natural gas
distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather, the greater the demand for natural gas to heat homes and businesses. As such, the natural gas
distribution systems demand profile typically peaks in the winter months of January and February and declines in the summer months of July and August. Year to year variability also occurs depending on how cold the weather is in any particular
year.
There is a risk that climate change impacts the seasonality and demand for water,
electricity and natural gas.
The Company attempts to mitigate the above noted risks by seeking regulatory mechanisms
during rate review proceedings. While not all regulatory jurisdictions have approved mechanisms to mitigate demand fluctuations, to date, the Regulated Services Group has successfully obtained regulatory approval to implement such decoupling
mechanisms in 7 of 13 states. An example of such a mechanism is seen at the Peach State Gas System in Georgia, where a weather normalization adjustment is applied to customer bills during the months of October through May that adjusts commodity
rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns.
Renewable Energy Group
The Renewable Energy Group's hydroelectric operations are impacted by seasonal
fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower, while during the
spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year, the level of hydrology
varies, impacting the amount of power that can be generated in a year.
The Renewable Energy Group's wind generation facilities are impacted by seasonal
fluctuations and year to year variability of the wind resource. During the fall, winter and spring periods, winds are generally stronger than during the summer period. The ability of these facilities to generate income may be impacted by
naturally occurring changes in wind patterns and wind strength.
The Renewable Energy Group's solar generation facilities are impacted by seasonal
fluctuations and year to year variability in solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher production in the summer months. The ability of these facilities to generate
income may be impacted by naturally occurring changes in solar radiance, such as cloud cover and snow.
The Company attempts to mitigate the above noted natural resource fluctuation risks by
acquiring or developing generating stations in different geographic locations.
Development and Construction Risk
The Company actively engages in the development and construction of new power generation
and water and wastewater facilities, and currently has a pipeline of renewable energy generation and storage projects in development or construction, as well as the development and construction of transmission and distribution assets and other
complementary projects. There can be no assurance that the Corporation will be able to identify attractive acquisition or development candidates or that it will be able to realize growth opportunities that improve the Corporation's financial
results or increase the amount of cash available for distribution There is always a risk that material delays, technical issues with interconnection and the interconnection utility, required upgrades to interconnection facilities, required
curtailments of generation, delays in obtaining interconnection rights, and/or cost overruns or lost revenue could be incurred in any of the projects planned or currently in construction affecting the Company’s overall performance. There are
risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, warranties under contracts may be unfilled or insufficient,
there may be inadequate availability, productivity or increased cost of qualified craft or local labour, start-up activities may take longer than planned, curtailment
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of a facility's output may be required, the scope, actual or expected returns, and
timing of projects may change, and other events beyond the Company's control may occur, in each case that may materially affect the viability, schedule, budget, cost and performance of projects. Regulatory approvals can be challenged by a number
of mechanisms which vary across state and provincial jurisdictions. Such permitting challenges could identify issues that may result in permits being modified or revoked.
Risks Specific to Renewable Generation Projects:
The strength and consistency of the wind resource will vary from the estimate set out in
the initial wind studies that were relied upon to determine the feasibility of the wind facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the actual wind, the assumptions
underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
The amount of solar radiance will vary from the estimate set out in the initial solar
studies that were relied upon to determine the feasibility of the solar facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the solar radiance, the assumptions underlying
the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
For certain of its development projects, the Company relies on financing from third
party tax equity investors or purchasers of tax credits, the participation of which depends upon the qualification of the project for U.S, tax incentives and satisfaction of the investors' investment criteria. These investors typically provide
funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be adversely impacted.
Litigation Risks and Other Contingencies
AQN and certain of its subsidiaries are involved in various litigation, claims and other
legal and regulatory proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial
loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.
Mountain View Fire
On November 17, 2020, a wildfire now known as the Mountain View Fire occurred in the
territory of Liberty Utilities (CalPeco Electric) LLC ("Liberty CalPeco"). The cause of the fire remains under investigation, and CAL FIRE has not yet released its final report. There are currently 21 lawsuits that name certain subsidiaries of
the Company as defendants in connection with the Mountain View Fire, as well as a non-litigation claim brought by the U.S. Department of Agriculture seeking reimbursement for alleged fire suppression costs and a notice from the U.S. Bureau of
Land Management seeking damages for the alleged burning of public lands without authorization. Fourteen lawsuits are brought by groups of individual plaintiffs alleging causes of action including negligence, inverse condemnation, nuisance,
trespass, and violations of Cal. Pub. Util. Code 2106 and Cal. Health and Safety Code 13007 (one of these 14 lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). On March 6,
2024, a trial commenced in Los Angeles County Superior Court on four bellwether cases with respect to inverse condemnation liability only. If the Company’s subsidiaries were found liable in those cases, the damages, if any, would not be
determined at this trial. In another lawsuit, County of Mono, Antelope Valley Fire Protection District, and Bridgeport Indian Colony allege similar causes of action and seek damages for fire suppression costs, law enforcement costs, property and
infrastructure damage, and other costs. In six other lawsuits, insurance companies allege inverse condemnation and negligence and seek recovery of amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits is
uncertain. Liberty CalPeco intends to vigorously defend them. In 2023, Liberty CalPeco accrued estimated losses of $66 million for claims related to the Mountain View Fire, against which Liberty CalPeco has recorded expected recoveries from
insurance of $66 million. The resulting net charge to earnings was $nil. The estimate of losses is subject to change as additional information becomes available. The actual amount of losses may be higher or lower than these estimates. While the
Company may incur a material loss in excess of the amount accrued, the Company cannot estimate the upper end of the range of reasonably possible losses that may be incurred. The Company has wildfire liability insurance that is expected to apply
up to applicable policy limits.
Apple Valley Condemnation Proceedings
On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the
utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp. (“Liberty Apple Valley”). On May 7, 2021, the Court issued a Tentative Statement of Decision denying the Town of Apple Valley’s attempt to take the Apple Valley water system
by eminent domain. The ruling confirmed that Liberty Apple Valley’s continued ownership and operation of the water system is in the best interest of the community. On October 14, 2021, the Court issued the Final Statement of Decision. The Court
signed and entered an Order of Dismissal and Judgment on November 12, 2021. On January 7, 2022, the Town filed a notice of appeal of the judgment entered by the Court. On August 2, 2022, the Court issued a ruling awarding Liberty Apple Valley
approximately
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$13.2 million in attorney’s fees and litigation costs. The Town filed a notice of appeal
of the fee award on August 22, 2022. The Town’s appeal of the condemnation judgment and fee award have been consolidated into one appellate docket, which is proceeding before the Court of Appeals.
Information Security Risk
The Company relies upon its and third-party information and operational technology
networks, systems and devices to process, transmit and store electronic information and to manage and support a variety of business processes and activities and safely operate its assets. The Company also uses its and third-party information
technology systems to record, process and summarize financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal and tax requirements. The Company’s and certain of its third-party
vendors' technology networks, systems and devices collect and store sensitive data, including system operating information and proprietary business information belonging to the Company and third parties, as well as personal information belonging
to the Company’s customers, employees and other stakeholders. As the Company operates critical infrastructure, it may be at an increased risk of cyber-attacks or other security threats by third parties.
The Company’s, its third-party vendors’ or other counterparties' technology systems and
technology networks, devices and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers or breaches due to employee error or malfeasance, disruptions during software or hardware upgrades, telecommunication
failures, theft, politically-driven attacks (including as a result of geopolitical tension, and any associated sanctions imposed or actions taken by the United States, Canada or other countries or retaliatory measures by nation states or other
actors), acts of war or terrorism, natural disasters or other similar events. In addition, certain sensitive information and data may be stored by the Company on physical devices, in physical files and records on its premises or transmitted to
the Company verbally, subjecting such information and data to a risk of loss, theft, release and misuse. Methods used to attack critical assets could include social engineering and general purpose or industry specific malware or ransomware
delivered via network transfer, removable media, viruses, attachments, or links in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and detect. The occurrence of any of these events could negatively
impact the Company’s operations, power generation facilities and utility distribution and transmission systems; could cause services disruptions or system failures; could adversely affect safety; could expose the Company, its customers or its
employees to a risk of loss or misuse of information; could affect the ability to earn or collect revenue or correctly record, process and report financial information; and could result in increased costs, legal claims or proceedings, liability
or regulatory penalties against the Company, damage the Company’s reputation or otherwise harm the Company’s business.
The long-term impact of terrorist attacks and cyber-attacks and the magnitude of the
threat of future terrorist attacks and cyber-attacks on the utility and power generation industries in general, and on the Company in particular, cannot be known. Increased security measures to be taken by the Company as a precaution against
possible terrorist attacks and cyber-attacks may result in increased costs to the Company. The Company must also comply with data privacy laws in each of the jurisdictions in which it operates. Certain data privacy laws and other cybersecurity
regulations have expanded in recent years, leading to increased obligations, and fines for breaches of such laws and regulations have increased. The Company may incur additional costs to maintain compliance, or significant financial penalties, in
the event of a breach.
The Company cannot accurately assess the probability that a security breach may occur or
accurately quantify the potential impact of such an event. The Company provides no assurance that it will be able to identify, protect against and remedy all cybersecurity, physical security or system vulnerabilities or that unauthorized access
or errors will be identified and remedied. Should a breach occur, the Company may suffer costs, losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory, or other processes, and could materially
adversely affect the Company’s business and results of operations including its reputation with customers, regulators, governments and financial markets. Resulting costs could include, among others, response, recovery (including ransom costs) and
remediation costs, increased protection or insurance costs, and costs arising from damages and losses incurred by third parties.
Uncertainty surrounding continued hostilities or sustained military campaigns (including
as a result of the conflict between Russia and Ukraine, and any associated sanctions imposed or actions taken by the United States, Canada or other countries or retaliatory measures by Russia or other geopolitical conflicts) may affect operations
of the Company in unpredictable ways, including disruptions of supplies and markets for products of the Company, and the possibility that the Company’s operations or facilities could be direct targets of, or indirect casualties of, an act of
terror or cyber-security attack. The effects of hostilities, military campaigns or terrorist or cyber-security attacks could include disruption to the Company’s generation, transmission and distribution systems or to the electrical grid in
general, and could result in a decline in the general economy and have a material adverse effect on the Company.
Technology Infrastructure Implementation Risk
The Company relies upon various information and operational technology infrastructure
systems to carry out its business processes and operations. This subjects the Company to inherent costs and risks associated with maintaining, upgrading, replacing and changing information and operational technology systems. This includes
impairment of its technology systems, potential disruption of operations, business process and internal control systems, substantial capital expenditures,
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demands on management time and other risks of delays, and difficulties in upgrading,
transitioning and integrating technology systems.
AQN and certain of its subsidiaries are in the process of updating their technology
infrastructure systems through the implementation of an integrated customer solution platform, which includes customer billing, enterprise resource planning systems and asset management systems. The implementation of these systems is being
managed by a dedicated team. Following pilot implementations, deployment began in 2022 and has occurred in a phased approach that is expected to be completed in 2024. The implementation of such technology systems requires the investment of
significant financial and human resources. Disruptions, delays or deficiencies in the design, implementation, or operation of these technology systems or integration of these systems with other existing information technology or operations
technology could: adversely affect the Company’s operations, including its ability to monitor its business, pay its suppliers, bill its customers, and report financial information accurately and on a timely basis; lead to higher than expected
costs; lead to increased regulatory scrutiny or adverse regulatory consequences; or result in the failure to achieve the expected benefits. As a result, the Company’s operations, financial condition, cash flows and results of operations could be
adversely affected.
Energy Consumption and Advancement in Technologies Risk
The Company’s generation, distribution and transmission assets are affected by energy
and water demand, sales and operating costs, among other things, in the jurisdictions in which they operate. Demand, sales and operating costs may change as a result of, among other things, fluctuations in general economic conditions, energy and
commodity prices, inflation, interest rates, employment levels, personal disposable income, customer preferences, advancements in new technologies, population or demographic changes and housing starts. Significantly reduced energy or water demand
in the Company’s service territories could reduce capital spending forecasts, and specifically capital spending related to new customer growth. A reduction in capital spending could, in turn, affect the Company’s rate base and earnings growth. A
downturn in economic conditions may have an adverse effect on the Company’s results of operations, financial condition and cash flows despite regulatory measures, where applicable, available to compensate for some or all of the reduced demand and
increased costs, which recovery, if any, may lag costs incurred by the Company. In addition, an extended decline in economic conditions could make it more difficult for customers to pay for the utility services they consume, thereby affecting the
aging and collection of the utilities’ trade receivables.
Initiatives designed to reduce greenhouse gas emissions and control or limit the effects
of climate change have resulted in incentives and programs to increase energy efficiency and reduce water and energy consumption, including efforts to reduce the availability and reliance on natural gas. There may also be efforts to move to
deregulation in certain of the markets in which the Regulated Services Group operates, which could adversely affect the Company's business, financial condition and results of operations.
Significant technological advancements are taking place in the generation and utility
industry, including advancements related to self-generation and distributed energy technologies such as fuel cells, micro turbines, battery storage, wind turbines, solar panels and technologies related to lower energy, natural gas and water use.
Adoption of these and other technologies may increase as a result of government subsidies or policies, improving economics and changing customer preferences.
Increased adoption of these practices, requirements and technologies could reduce demand
for utility-scale electricity generation and electric, water, and natural gas distribution, and as a result, the Company’s business, financial condition and results of operations could be adversely affected.
The Company may also invest in and use newly developed, less proven, technologies or
generation methods in its development and construction projects or in maintaining or enhancing its existing operations and assets. There is no guarantee that such new technologies will perform as anticipated. The failure of a new technology or
generation method to perform as anticipated may adversely affect the profitability of a particular development project or existing operations and assets.
The Regulated Services Group seeks to actively engage with regulators, governments and customers, as
appropriate, in an effort to ensure these changes in consumption do not negatively impact the services provided.
Uninsured Risk
The Company maintains insurance coverage for certain exposures, but this coverage is
limited and the Company is generally not fully insured against all potential significant losses. Insurance coverage for the Company is subject to policy conditions and exclusions, coverage limits, and various deductibles, and not all types of
liabilities and losses may be covered by insurance. Further, certain assets and facilities of the Company are not fully insured, as the cost of the coverage may not be economically viable or may not otherwise be available. Insurance may not
continue to be offered on an economically feasible basis, or at all, and may not cover all events that could give rise to a loss or claim involving the Company’s assets or operations. There can also be no assurance that insurers will fulfill
their obligations. The Company’s ability to obtain and maintain insurance and the terms of any available insurance coverage could be materially adversely
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affected by international, national, state or local events and company-specific events,
as well as the financial condition of insurers.
If the Company were to incur a serious uninsured loss or a loss significantly exceeding
the limits of its insurance policies, the results could have a material adverse effect on the Company’s business, results of operations, financial condition and cash flows. In the event of a large uninsured loss, including those caused by severe
weather conditions, wildfires, natural disasters and certain other events beyond the control of the Regulated Services Group, the Company may make an application to an applicable regulatory authority for the recovery of these costs through
customer rates to offset any loss. However, the Company cannot provide assurance that the regulatory authorities would approve any such application in whole or in part. This potential recovery mechanism is not available to the Renewable Energy
Group.
QUARTERLY FINANCIAL INFORMATION
The following is a summary of unaudited quarterly financial information for the eight quarters ended
December 31, 2023:
| (all dollar amounts in $ millions except per share information) | 1st Quarter 2023 | 2nd Quarter 2023 | 3rd Quarter 2023 | 4th Quarter 2023 | |||||||||||||||||||
| Revenue | $ | 778.6 | $ | 627.9 | $ | 624.6 | $ | 666.9 | |||||||||||||||
| Net earnings (loss) attributable to shareholders | 270.1 | (253.2) | (174.5) | 186.3 | |||||||||||||||||||
| Net earnings (loss) per share | 0.39 | (0.37) | (0.26) | 0.27 | |||||||||||||||||||
| Diluted net earnings (loss) per share | 0.39 | (0.37) | (0.26) | 0.27 | |||||||||||||||||||
|
Adjusted Net Earnings1
|
119.9 | 56.2 | 80.5 | 115.5 | |||||||||||||||||||
|
Adjusted Net Earnings per common share1
|
0.17 | 0.08 | 0.11 | 0.16 | |||||||||||||||||||
|
Adjusted EBITDA1
|
341.0 | 277.7 | 282.5 | 334.3 | |||||||||||||||||||
| Total assets | 17,927.1 | 17,968.7 | 17,982.8 | 18,374.0 | |||||||||||||||||||
|
Long-term debt2
|
7,849.2 | 8,083.4 | 8,367.3 | 8,516.3 | |||||||||||||||||||
| Dividend declared per common share | $ | 0.11 | $ | 0.11 | $ | 0.11 | $ | 0.11 | |||||||||||||||
| 1st Quarter 2022 | 2nd Quarter 2022 | 3rd Quarter 2022 | 4th Quarter 2022 | ||||||||||||||||||||
| Revenue | $ | 733.2 | $ | 619.4 | $ | 664.4 | $ | 748.0 | |||||||||||||||
| Net earnings (loss) attributable to shareholders | 91.0 | (33.4) | (195.2) | (74.4) | |||||||||||||||||||
| Net earnings (loss) per share | 0.13 | (0.05) | (0.29) | (0.11) | |||||||||||||||||||
| Diluted net earnings (loss) per share | 0.13 | (0.05) | (0.29) | (0.11) | |||||||||||||||||||
|
Adjusted Net Earnings1
|
140.0 | 109.6 | 73.5 | 97.6 | |||||||||||||||||||
|
Adjusted Net Earnings per common share1
|
0.20 | 0.16 | 0.11 | 0.14 | |||||||||||||||||||
|
Adjusted EBITDA1
|
329.3 | 289.2 | 276.1 | 295.5 | |||||||||||||||||||
| Total assets | 17,669.9 | 17,737.9 | 17,653.3 | 17,627.6 | |||||||||||||||||||
|
Long-term debt2
|
7,191.6 | 7,455.4 | 7,705.1 | 7,512.3 | |||||||||||||||||||
| Dividend declared per common share | $ | 0.17 | $ | 0.18 | $ | 0.18 | $ | 0.18 | |||||||||||||||
| 1 |
See Caution Concerning Non-GAAP Measures.
|
||||
| 2 | Includes current portion of long-term debt, long-term debt and convertible debentures. | ||||
The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions
of facilities as noted in this MD&A.
Quarterly revenues have fluctuated between $619.4 million and $778.6 million over the
prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the fluctuation in the
strength of the Canadian dollar relative to the U.S. dollar which can result in significant changes in reported revenue from Canadian operations.
Quarterly net earnings attributable to shareholders have fluctuated between a loss of
$253.2 million and earnings of $270.1 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and
mark-to-market gains and losses on financial instruments.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
64
|
||||
SUMMARY FINANCIAL INFORMATION OF ATLANTICA
The Company owns an approximately 42% beneficial interest in Atlantica. AQN accounts for its interest in Atlantica using the fair value method (see Note 8(a) in the annual consolidated
financial statements). The summary financial information of Atlantica in the following table is derived from the consolidated financial statements of Atlantica as of December 31, 2023 and 2022 and for the years then ended which are reported in
U.S. dollars and were prepared using International Financial Reporting Standards, as issued by the International Accounting Standards Board ("IFRS"). The recognition, measurement and disclosure requirements of IFRS differ from U.S. GAAP as
applied by the Company.
| (all dollar amounts in $ millions) | 2023 | 2022 | |||||||||
| Revenue | $ | 1,099.9 | $ | 1,102.0 | |||||||
|
Profit (loss) for the year
|
36.4 | (2.1) | |||||||||
| Total non-current assets | 7,732.2 | 8,069.2 | |||||||||
| Total current assets | 982.2 | 1,031.7 | |||||||||
| Total non-current liabilities | 6,517.7 | 6,792.9 | |||||||||
| Total current liabilities | 607.8 | 519.0 | |||||||||
DISCLOSURE CONTROLS AND PROCEDURES
AQN's management carried out an evaluation as of December 31, 2023, under the
supervision of and with the participation of AQN’s Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), of the effectiveness of the design and operations of AQN’s disclosure controls and procedures (as defined in Rule 13a-15(e)
and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of December 31, 2023, AQN’s disclosure controls and procedures are effective to
provide reasonable assurance that information required to be disclosed by AQN in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in rules and forms of the
U.S. Securities and Exchange Commission, and is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.
Management Report on Internal Controls over Financial Reporting
Management, including the CEO and the CFO, is responsible for establishing and
maintaining internal control over financial reporting to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S.
GAAP.
Management assessed the effectiveness of the Company's internal control over financial
reporting as of December 31, 2023, based on the framework established in Internal Control - Integrated Framework (2013) issued by COSO. This assessment included review of the documentation of controls, evaluation of the design effectiveness of
controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2023
to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with U.S. GAAP. Management reviewed the results of its
assessment with the Audit & Finance Committee of the Board.
Changes in Internal Controls over Financial Reporting
For the twelve months ended December 31, 2023, there has been no change in the Company’s
internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.
Inherent Limitations on Effectiveness of Controls
Due to its inherent limitations, disclosure controls and procedures or internal control
over financial reporting may not prevent or detect all misstatements based on error or fraud. Further, the effectiveness of internal control is subject to the risk that controls may become inadequate because of changes in conditions, or that the
degree of compliance with policies or procedures may change.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
65
|
||||
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
AQN prepared its annual consolidated financial statements in accordance with U.S. GAAP.
The preparation of the annual consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of
contingent assets and liabilities. Significant areas requiring the use of management judgment relate to the scope of consolidated entities, the recoverability of assets, the measurement of deferred taxes and the recoverability of deferred tax
assets, rate-regulation, unbilled revenue, pension and post-employment benefits, fair value of derivatives and fair value of assets and liabilities acquired in a business combination. Actual results may differ from these estimates.
AQN’s significant accounting policies and new accounting standards are discussed in Notes 1 and 2 in the annual consolidated financial statements, respectively. Management believes the following accounting policies involve the
application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit & Finance Committee of the Board.
Consolidation and Variable Interest Entities
The Company uses judgment to assess whether its operations or investments represent
variable interest entities ("VIEs"). In making these evaluations, management considers (a) the sufficiency of the investment's equity at risk, (b) the existence of a controlling financial interest, and (c) the structure of any voting rights. In
addition, management considers the specific facts and circumstances of each investment in a VIE when determining whether the Company is the primary beneficiary. The factors that management takes into consideration include the purpose and design
of the VIE, the key decisions that affect its economic performance, whether the parties to the arrangements are related parties or de facto agents of the Company, and whether the Company has the power to direct the activities that would most
significantly affect the economic performance of the VIE. Management's judgment is also required to determine whether the Company has the right to receive benefits or the obligation to absorb losses of the VIE. Based on the judgments made, the
Company will consolidate the VIE if it determines that it is the primary beneficiary.
Estimated Useful Lives and Recoverability of Long-Lived Assets, Intangibles
Assets, Goodwill and Long-term Investments
The Company makes judgments (a) to determine the recoverability of a development
project, and the period over which the costs are capitalized during the development and construction of the project, (b) to assess the nature of the costs to be capitalized, (c) to distinguish individual components and major overhauls, and (d) to
determine the useful lives or unit-of-production over which assets are depreciated.
Depreciation rates on most utility assets are subject to regulatory review and approval,
and depreciation expense is recovered through rates set by ratemaking authorities. The recovery of those costs is dependent on the ratemaking process.
The carrying value of long-lived assets, intangible assets, goodwill and long-term
investments, is reviewed whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill. Equity method investments are reviewed to determine whether an
other-than-temporary decline in value has occurred and an impairment exists. Some of the factors AQN considers as indicators of impairment include a significant change in operational or financial performance, unexpected outcome from rate orders,
natural disasters, energy pricing and changes in regulation. When such events or circumstances are present, the Company assesses whether the carrying value will be recovered through the expected future cash flows. If the facility includes
goodwill, the fair value of the facility is compared to its carrying value. Both methodologies are sensitive to the forecasted cash flows and in particular energy prices, long-term growth rate and, discount rate for the fair value calculation.
In 2023 and 2022, management assessed qualitative and quantitative factors for each of
the reporting units that were allocated goodwill. No goodwill impairment provision was required. During the fourth quarter of 2022, the Company recorded an impairment charge of $235.5 million to reduce the carrying value of its investment in the
Texas Coastal Wind Facilities and the carrying value of the Senate Wind Facility which began commercial operations in 2012. These impaired assets operate within the ERCOT market, and the 2022 Impairment recorded is primarily due to declining
forecasted energy prices in ERCOT for the Senate Wind Facility and continued challenges with congestion at the Texas Costal Wind Facilities. The Company determined fair value using an income approach. Changes in assumptions of revenue forecasts,
driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis |
66
|
||||
Valuation of Deferred Tax Assets
In assessing the realization of deferred tax assets, management aims to consider all
evidence, both positive and negative, to determine whether it is more likely than not that deferred tax assets will be realized. A piece of objective evidence evaluated is cumulative earnings or losses incurred over the three-year period. Even
with a cumulative loss, management will typically review a forecast of future taxable income and consider tax planning strategies before making its final assessment.
The U.S. entities in the Renewable Energy Group continue to be in an overall
deferred tax asset position as at December 31, 2023. In the course of assessing the U.S. deferred tax assets in the Renewable
Energy Group, management concluded, similar to 2022, that it was not probable that the U.S. business of the Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group (with the exception of certain transferable tax credits). Management’s
conclusion is based on the balance of all available positive and negative evidence applicable to the Renewable Energy Group.
The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income during the
carryforward period are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as management projections for growth.
Management’s assessment of the deferred tax asset in Canada supports that it is probable
that the benefit of such assets will be realized. While the Canadian entities are operationally profitable, the Canadian entities as a whole, are in a cumulative 3-year loss position. Management has evaluated all available positive and negative
evidence applicable to the entities in Canada and has concluded that it is probable that the Canadian businesses will make sufficient taxable profit to allow them to utilize their available tax attributes prior to their expiry.
Accounting for Rate Regulation
Accounting guidance for regulated operations provides that rate-regulated entities
account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it
probable that such rates can be charged and collected. This accounting guidance is applied to the Regulated Services Group's operations, with the exception of Suralis.
Certain expenses and revenues subject to utility regulation or rate determination
normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets
and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration
of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would make the recovery of these assets and liabilities no longer probable, these regulatory
assets and liabilities would be required to be written off or written down.
Unbilled Energy Revenues
Revenues related to natural gas, electricity and water delivery are generally recognized
upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last
meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the
system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
Derivatives
AQN uses derivative instruments to manage exposure to changes in commodity prices,
foreign exchange rates, and interest rates. Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual
transactions qualify for hedge accounting treatment. Management’s judgment is also required to determine the fair value of derivative transactions. AQN determines the fair value of derivative instruments based on forward market prices in active
markets obtained from external parties adjusted for nonperformance risk. A significant change in estimate could affect AQN’s results of operations if the hedging relationship was considered no longer effective.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 67 | ||||
Pension and Post-employment Benefits
The obligations and related costs of defined benefit pension and post-employment benefit
plans are calculated using actuarial concepts, which include critical assumptions related to the discount rate, mortality rate, compensation increase, expected rate of return on plan assets and medical cost trend rates. These assumptions are
important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The mortality assumption for December 31, 2023 uses the Pri-2012 mortality table and the projected
generationally scale MP-2021, adjusted to reflect the ultimate improvement rates in the 2021 Social Security Administration intermediate assumptions for plans in the United States. The mortality assumption for the Bermuda plan as of December 31,
2023 uses the 2014 Canadian Pensioners' Mortality Table combined with mortality improvement scale CPM-B.
The sensitivities of key assumptions used in measuring accrued benefit obligations and
benefit plan cost for 2023 are outlined in the following table. They are calculated independently of each other. Actual experience may result in changes in a number of assumptions simultaneously. The types of assumptions and method used to
prepare the sensitivity analysis has not changed from previous periods and is consistent with the calculation of the retirement benefit obligations and net benefit plan cost recognized in the consolidated financial statements.
|
2023 Pension Plans
|
2023 OPEB Plans
|
||||||||||||||||||||||||||||
| (all dollar amounts in $ millions) | Accrued Benefit Obligation | Net Periodic Pension Cost | Accumulated Postretirement Benefit Obligation | Net Periodic Postretirement Benefit Cost | |||||||||||||||||||||||||
| Discount Rate | |||||||||||||||||||||||||||||
| 1% increase | (56.7) | (1.4) | (22.6) | (1.5) | |||||||||||||||||||||||||
| 1% decrease | 67.9 | 2.5 | 27.7 | 1.7 | |||||||||||||||||||||||||
| Future compensation rate | |||||||||||||||||||||||||||||
| 1% increase | 1.9 | 1.2 | — | — | |||||||||||||||||||||||||
| 1% decrease | (1.7) | (1.1) | — | — | |||||||||||||||||||||||||
| Expected return on plan assets | |||||||||||||||||||||||||||||
| 1% increase | — | (5.5) | — | (1.5) | |||||||||||||||||||||||||
| 1% decrease | — | 5.5 | — | 1.5 | |||||||||||||||||||||||||
| Health care trend | |||||||||||||||||||||||||||||
| 1% increase | — | — | 25.6 | 3.4 | |||||||||||||||||||||||||
| 1% decrease | — | — | (21.2) | (2.8) | |||||||||||||||||||||||||
Business Combinations
The Company has completed a number of business combinations in the past few years.
Management's judgment is required to estimate the purchase price, to identify and to fair value all assets and liabilities acquired. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and
certain assumptions generally included in a present value calculation of the related cash flows.
Acquired assets and liabilities assumed that are subject to critical estimates include
property, plant and equipment, regulatory assets and liabilities, intangible assets, long-term debt and pension and OPEB obligations. The fair value of regulated property, plant and equipment is assessed using an income approach where the
estimated cash flows of the assets are calculated using the approved tariff and discounted at the approved rate of return. The fair value of regulatory assets and liabilities considers the estimated timing of the recovery or refund to customers
through the rate making process. The fair value of intangible assets is assessed using a multi-period excess earnings method. The fair value of long-term debt is determined using a discounted cash flow method and current interest rates. The
pension and OPEB obligations are valued by external actuaries using the guidelines of ASC 805, Business combinations.
| Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 68 | ||||
Consolidated Financial Statements of
Algonquin Power & Utilities Corp.
For the years ended December 31, 2023 and 2022
| Consolidated Financial Statements | 69 |
MANAGEMENT’S REPORT
Financial Reporting
The accompanying consolidated financial statements and management discussion and
analysis (“MD&A”) are the responsibility of management and have been approved by the Board of Directors.
The consolidated financial statements have been prepared by management in accordance
with U.S. generally accepted accounting principles. Financial statements by nature include amounts based upon estimates and judgments. When alternative accounting methods exist, management has chosen those it deems most appropriate in the
circumstances.
The Board of Directors and its committees are responsible for all aspects related to
governance of the Company. The Audit & Finance Committee of the Board of Directors, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfill its responsibilities for
financial reporting and internal controls related thereto. The Committee meets with management and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit
& Finance Committee reports its findings to the Board of Directors for its consideration in approving the consolidated financial statements for issuance to the shareholders.
Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal
control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial
statements for external purposes in accordance with generally accepted accounting principles.
Management assessed the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2023, based on the framework established in Internal Control – Integrated Framework (2013) issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2023. Ernst & Young
LLP, the independent registered public accounting firm that audited the accompanying consolidated financial statements has issued its attestation report on the Company’s internal control over financial reporting,
March 8, 2024
|
/s/ Chris Huskilson
|
/s/ Darren Myers | |||||||
|
Interim Chief Executive Officer
|
Chief Financial Officer | |||||||
| Consolidated Financial Statements | 70 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Algonquin Power & Utilities Corp.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Algonquin Power &
Utilities Corp. (the “Company”), as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the years then ended, and the related notes (collectively referred to as
the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations
and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2023, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework), and our report dated March 8, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company‘s management. Our
responsibility is to express an opinion on the Company‘s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement
of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our
audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our
opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period
audit of the financial statements that is communicated or required to be communicated to the Audit & Finance Committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our
especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the
critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
| Consolidated Financial Statements | 71 |
| Regulatory assets and liabilities—Recovery of costs through rate regulation | ||||||||
| Description of the Matter |
As described in Note 7 to the consolidated financial statements, the Company has
approximately $1.33 billion in regulatory assets and approximately $734.30 million in regulatory liabilities that are subject to regulation by the public utility commissions of the regions in which they operate. Rates are determined
under cost-of-service regulation. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on assets or common shareholder’s equity. Regulatory decisions can have an impact on
the timely recovery of costs and the approved returns. The recoverability of such costs through rate-regulation impacts multiple financial statement line items and disclosures, including property, plant, and equipment, regulatory assets
and liabilities, derivative instruments, pension and other post-employment benefit obligation, regulated electricity, gas and water distribution revenues and the corresponding expenses, income tax expense, and depreciation and
amortization expense.
Although the Company expects to recover its costs from customers through
rates, there is a risk that the respective regulator will not approve full recovery of the costs incurred. Auditing the recoverability of these costs through rates is complex and highly judgmental due to the significant judgments and
probability assessments made by the Company to support its accounting and disclosure for regulatory matters when final regulatory decisions or orders have not yet been obtained or when regulatory formulas are complex. There is also
subjectivity involved in assessing the potential impact of future regulatory decisions on the financial statements. The Company’s judgments include evaluating the probability of recovery of and recovery on costs incurred, or probability
of refund to customers through future rates.
|
|||||||
| How We Addressed the Matter in Our Audit |
We obtained an understanding, evaluated the design and tested the operating effectiveness of
controls over the Company’s evaluation of the likelihood of recovery of regulatory assets and refund of regulatory liabilities, including management’s controls over the initial recognition and the monitoring and evaluation of regulatory
developments that may affect the likelihood of recovering costs in future rates, a refund, or future changes in rates.
We performed audit procedures that included, amongst others, evaluating the
Company’s assessment of the probability of future recovery for regulatory assets and refund of regulatory liabilities, by comparison to the relevant regulatory orders, filings and correspondence, and other publicly available information
including past precedents. For regulatory matters for which regulatory decisions or orders have not yet been obtained, we inspected the Company’s filings for any evidence that might contradict the Company’s assertions, and reviewed
other regulatory orders, filings and correspondence for other entities within the same or similar jurisdictions to assess the likelihood of recovery in future rates based on the respective regulator’s treatment of similar costs under
similar circumstances. We evaluated the Company’s analysis and compared that analysis with letters from legal counsel, when appropriate, regarding cost recoveries or future changes in rates. We assessed the methodology and mathematical
accuracy of the Company’s calculations of regulatory asset and liability balances based on provisions and formulas outlined in rate orders and other correspondence with regulators.
|
|||||||
|
/s/ Ernst & Young LLP
|
||||||||
| Chartered Professional Accountants | ||||||||
| Licensed Public Accountants | ||||||||
| We have served as the Company's auditor since 2013. | ||||||||
| Toronto, Canada | ||||||||
| March 8, 2024 | ||||||||
| Consolidated Financial Statements | 72 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Algonquin Power & Utilities Corp.
Opinion on Internal Control over Financial Reporting
We have audited Algonquin Power & Utilities Corp.’s internal control over financial
reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO criteria”). In our opinion,
Algonquin Power & Utilities Corp. (the “Company”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Accounting
Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2023, and 2022, the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the years then
ended, and the related notes, and our report dated March 8, 2024, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the Management Report on Internal Controls over Financial Reporting section contained in the accompanying Management
Discussion and Analysis. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial
Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on
the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
| /s/ Ernst & Young LLP | ||||||||
| Chartered Professional Accountants | ||||||||
| Licensed Public Accountants | ||||||||
| Toronto, Canada | ||||||||
| March 8, 2024 | ||||||||
| Consolidated Financial Statements | 73 |
Algonquin Power & Utilities Corp.
Consolidated Statements of Operations
|
Years ended
|
|||||||||||
| (thousands of U.S. dollars, except per share amounts) | December 31 | ||||||||||
| 2023 | 2022 | ||||||||||
| Revenue | |||||||||||
| Regulated electricity distribution | $ | 1,295,497 | $ | 1,278,912 | |||||||
| Regulated natural gas distribution | 621,173 | 686,744 | |||||||||
| Regulated water reclamation and distribution | 399,052 | 364,383 | |||||||||
| Non-regulated energy sales | 296,314 | 350,797 | |||||||||
| Other revenue | 85,979 | 84,177 | |||||||||
| 2,698,015 | 2,765,013 | ||||||||||
| Expenses | |||||||||||
| Operating expenses | 906,985 | 851,489 | |||||||||
| Regulated electricity purchased | 429,760 | 465,570 | |||||||||
| Regulated natural gas purchased | 267,122 | 340,792 | |||||||||
| Regulated water purchased | 19,564 | 18,308 | |||||||||
| Non-regulated energy purchased | 19,499 | 41,684 | |||||||||
| Administrative expenses | 90,359 | 80,232 | |||||||||
| Depreciation and amortization | 466,996 | 455,520 | |||||||||
|
Asset impairment charge (notes 5, 8 and 16)
|
23,492 | 159,568 | |||||||||
| Loss on foreign exchange | 8,359 | 13,833 | |||||||||
| 2,232,136 | 2,426,996 | ||||||||||
| Gain on sale of renewable assets | — | 64,028 | |||||||||
| Operating income | 465,879 | 402,045 | |||||||||
|
Interest expense (note 9)
|
(353,656) | (278,574) | |||||||||
|
Loss from long-term investments (note 8)
|
(124,974) | (483,385) | |||||||||
|
Other income (note 7)
|
41,410 | 18,179 | |||||||||
|
Other net losses (note 19)
|
(132,889) | (21,391) | |||||||||
|
Pension and other post-employment non-service costs (note 10)
|
(19,939) | (10,950) | |||||||||
|
Gain on derivative financial instruments (note 24(b)(iv))
|
4,564 | 4,408 | |||||||||
| Loss before income taxes | (119,605) | (369,668) | |||||||||
|
Income tax recovery (expense) (note 18)
|
|||||||||||
| Current | 9,740 | (7,843) | |||||||||
| Deferred | 76,560 | 69,356 | |||||||||
| 86,300 | 61,513 | ||||||||||
| Net loss | (33,305) | (308,155) | |||||||||
|
Net effect of non-controlling interests (note 17)
|
|||||||||||
| Non-controlling interests | 87,901 | 111,323 | |||||||||
| Non-controlling interests held by related party | (25,922) | (15,157) | |||||||||
| $ | 61,979 | $ | 96,166 | ||||||||
| Net earnings (loss) attributable to shareholders of Algonquin Power & Utilities Corp. | $ | 28,674 | $ | (211,989) | |||||||
|
Series A Shares and Series D Shares dividend (note 15)
|
8,356 | 8,720 | |||||||||
| Net earnings (loss) attributable to common shareholders of Algonquin Power & Utilities Corp. | $ | 20,318 | $ | (220,709) | |||||||
|
Basic and diluted net earnings (loss) per share (note 20)
|
$ | 0.03 | $ | (0.33) | |||||||
See accompanying notes to consolidated financial statements
| Consolidated Financial Statements | 74 |
Algonquin Power & Utilities Corp.
Consolidated Statements of Comprehensive Income (Loss)
|
Years ended
|
|||||||||||
| (thousands of U.S. dollars) | December 31 | ||||||||||
| 2023 | 2022 | ||||||||||
| Net loss | $ | (33,305) | $ | (308,155) | |||||||
| Other comprehensive income (loss) (“OCI”): | |||||||||||
|
Foreign currency translation adjustment, net of tax recovery of $6,616 (2022 - tax expense $2,423), (notes 24(b)(iii)
and 24(b)(iv))
|
(5,386) | (23,502) | |||||||||
|
Change in fair value of cash flow hedges, net of tax recovery of $1,885 (2022 - tax expense of
$20,644), (note 24(b)(ii))
|
59,487 | (94,295) | |||||||||
|
Change in pension and other post-employment benefits, net of tax expense of $1,612 (2022 - tax expense of $8,330), (note
10)
|
4,693 | 27,761 | |||||||||
| OCI, net of tax | 58,794 | (90,036) | |||||||||
| Comprehensive income (loss) | 25,489 | (398,191) | |||||||||
| Comprehensive loss attributable to the non-controlling interests | (60,962) | (97,816) | |||||||||
| Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp. | $ | 86,451 | $ | (300,375) | |||||||
See accompanying notes to consolidated financial statements
| Consolidated Financial Statements | 75 |
Algonquin Power & Utilities Corp.
Consolidated Balance Sheets
| (thousands of U.S. dollars) | |||||||||||
| December 31, | December 31, | ||||||||||
| 2023 | 2022 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 56,142 | $ | 57,623 | |||||||
|
Trade and other receivables, net (note 4)
|
524,194 | 528,057 | |||||||||
| Fuel and natural gas in storage | 48,982 | 95,350 | |||||||||
| Supplies and consumables inventory | 178,150 | 129,571 | |||||||||
|
Regulatory assets (note 7)
|
142,970 | 190,393 | |||||||||
| Prepaid expenses | 81,926 | 58,653 | |||||||||
|
Derivative instruments (note 24)
|
10,920 | 12,270 | |||||||||
|
Other assets (note 11)
|
23,061 | 22,564 | |||||||||
| 1,066,345 | 1,094,481 | ||||||||||
|
Property, plant and equipment, net (note 5)
|
12,517,450 | 11,944,885 | |||||||||
|
Intangible assets, net (note 6)
|
93,938 | 96,683 | |||||||||
|
Goodwill (note 6)
|
1,324,062 | 1,320,579 | |||||||||
|
Regulatory assets (note 7)
|
1,184,713 | 1,081,108 | |||||||||
|
Long-term investments (note 8)
|
|||||||||||
| Investments carried at fair value | 1,115,729 | 1,344,207 | |||||||||
| Other long-term investments | 641,920 | 462,325 | |||||||||
|
Derivative instruments (note 24)
|
72,328 | 71,630 | |||||||||
|
Deferred income taxes (note 18)
|
158,483 | 84,416 | |||||||||
|
Other assets (note 11)
|
198,993 | 127,299 | |||||||||
| $ | 18,373,961 | $ | 17,627,613 | ||||||||
See accompanying notes to consolidated financial statements
| Consolidated Financial Statements | 76 |
Algonquin Power & Utilities Corp.
Consolidated Balance Sheets (continued)
| (thousands of U.S. dollars) | |||||||||||
| December 31, | December 31, | ||||||||||
| 2023 | 2022 | ||||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 210,412 | $ | 186,080 | |||||||
| Accrued liabilities | 554,875 | 555,792 | |||||||||
|
Dividends payable (note 15)
|
74,916 | 125,655 | |||||||||
|
Regulatory liabilities (note 7)
|
99,850 | 69,865 | |||||||||
|
Long-term debt (note 9)
|
621,856 | 423,274 | |||||||||
|
Other long-term liabilities (note 12)
|
80,458 | 134,212 | |||||||||
|
Derivative instruments (note 24)
|
34,915 | 32,491 | |||||||||
| Other liabilities | 7,898 | 7,091 | |||||||||
| 1,685,180 | 1,534,460 | ||||||||||
|
Long-term debt (note 9)
|
7,894,174 | 7,088,743 | |||||||||
|
Regulatory liabilities (note 7)
|
634,446 | 558,317 | |||||||||
|
Deferred income taxes (note 18)
|
578,902 | 565,639 | |||||||||
|
Derivative instruments (note 24)
|
75,961 | 137,830 | |||||||||
|
Pension and other post-employment benefits obligation (note 10)
|
96,653 | 125,579 | |||||||||
|
Other long-term liabilities (note 12)
|
465,874 | 461,230 | |||||||||
| 9,746,010 | 8,937,338 | ||||||||||
|
Redeemable non-controlling interests (note 17)
|
|||||||||||
| Redeemable non-controlling interest, held by related party | 308,350 | 307,856 | |||||||||
| Redeemable non-controlling interests | 10,013 | 11,520 | |||||||||
| 318,363 | 319,376 | ||||||||||
| Equity: | |||||||||||
| Preferred shares | 184,299 | 184,299 | |||||||||
|
Common shares (note 13(a))
|
6,229,994 | 6,183,943 | |||||||||
| Additional paid-in capital | 7,254 | 9,413 | |||||||||
| Deficit | (1,279,696) | (997,945) | |||||||||
|
Accumulated other comprehensive loss (“AOCI”) (note 14)
|
(102,286) | (160,063) | |||||||||
| Total equity attributable to shareholders of Algonquin Power & Utilities Corp. | 5,039,565 | 5,219,647 | |||||||||
|
Non-controlling interests (note 17)
|
|||||||||||
| Non-controlling interests - tax equity partnership units | 1,196,720 | 1,225,608 | |||||||||
| Other non-controlling interests | 347,338 | 333,362 | |||||||||
| Non-controlling interest, held by related party | 40,785 | 57,822 | |||||||||
| 1,584,843 | 1,616,792 | ||||||||||
| Total equity | 6,624,408 | 6,836,439 | |||||||||
|
Commitments and contingencies (note 22)
|
|||||||||||
|
Subsequent events (notes 3(c), 7(a), 8(c), 9(c), 9(d), 16(a), 17(c))
|
|||||||||||
| $ | 18,373,961 | $ | 17,627,613 | ||||||||
See accompanying notes to consolidated financial statements
| Consolidated Financial Statements | 77 |
Algonquin Power & Utilities Corp.
Consolidated Statements of Equity
|
(thousands of U.S. dollars)
For the year ended December 31, 2023
|
|||||||||||||||||||||||||||||||||||||||||
| Algonquin Power & Utilities Corp. Shareholders | |||||||||||||||||||||||||||||||||||||||||
| Common shares |
Preferred shares |
Additional paid-in capital |
Retained earnings (deficit) | AOCI | Non- controlling interests |
Total | |||||||||||||||||||||||||||||||||||
| Balance, December 31, 2022 | $ | 6,183,943 | $ | 184,299 | $ | 9,413 | $ | (997,945) | $ | (160,063) | $ | 1,616,792 | $ | 6,836,439 | |||||||||||||||||||||||||||
| Net earnings (loss) | — | — | — | 28,674 | — | (61,979) | (33,305) | ||||||||||||||||||||||||||||||||||
|
Effect of redeemable non-controlling interests not included in equity (note 17)
|
— | — | — | — | — | (24,598) | (24,598) | ||||||||||||||||||||||||||||||||||
| OCI | — | — | — | — | 57,777 | 1,017 | 58,794 | ||||||||||||||||||||||||||||||||||
| Dividends declared and distributions to non-controlling interests | — | — | — | (279,634) | — | (54,322) | (333,956) | ||||||||||||||||||||||||||||||||||
| Dividends and issuance of shares under dividend reinvestment plan | 30,482 | — | — | (30,482) | — | — | — | ||||||||||||||||||||||||||||||||||
| Contributions received from non-controlling interests, net of cost | — | — | — | — | — | 107,933 | 107,933 | ||||||||||||||||||||||||||||||||||
| Common shares issued upon conversion of convertible debentures | 11 | — | — | — | — | — | 11 | ||||||||||||||||||||||||||||||||||
| Common shares issued under employee share purchase plan | 5,229 | — | — | — | — | — | 5,229 | ||||||||||||||||||||||||||||||||||
| Share-based compensation | — | — | 13,162 | — | — | — | 13,162 | ||||||||||||||||||||||||||||||||||
| Common shares issued pursuant to share-based awards | 10,329 | — | (15,321) | (309) | — | — | (5,301) | ||||||||||||||||||||||||||||||||||
| Balance, December 31, 2023 | $ | 6,229,994 | $ | 184,299 | $ | 7,254 | $ | (1,279,696) | $ | (102,286) | $ | 1,584,843 | $ | 6,624,408 | |||||||||||||||||||||||||||
See accompanying notes to consolidated financial statements
| Consolidated Financial Statements | 78 |
Algonquin Power & Utilities Corp.
Consolidated Statements of Equity (continued)
|
(thousands of U.S. dollars)
For the year ended December 31, 2022
|
|||||||||||||||||||||||||||||||||||||||||
| Algonquin Power & Utilities Corp. Shareholders | |||||||||||||||||||||||||||||||||||||||||
| Common shares |
Preferred shares |
Additional paid-in capital |
Deficit | AOCI | Non- controlling interests |
Total | |||||||||||||||||||||||||||||||||||
| Balance, December 31, 2021 | $ | 6,032,792 | $ | 184,299 | $ | 2,007 | $ | (288,424) | $ | (71,677) | $ | 1,523,082 | $ | 7,382,079 | |||||||||||||||||||||||||||
| Net loss | — | — | — | (211,989) | — | (96,166) | (308,155) | ||||||||||||||||||||||||||||||||||
|
Effect of redeemable non-controlling interests not included in equity (note 17)
|
— | — | — | — | — | (8,859) | (8,859) | ||||||||||||||||||||||||||||||||||
| OCI | — | — | — | — | (88,386) | (1,650) | (90,036) | ||||||||||||||||||||||||||||||||||
| Dividends declared and distributions to non-controlling interests | — | — | — | (396,965) | — | (61,063) | (458,028) | ||||||||||||||||||||||||||||||||||
| Dividends and issuance of shares under dividend reinvestment plan | 97,801 | — | — | (97,801) | — | — | — | ||||||||||||||||||||||||||||||||||
| Contributions received from non-controlling interests, net of cost | — | — | — | — | — | 273,697 | 273,697 | ||||||||||||||||||||||||||||||||||
| Common shares issued upon conversion of convertible debentures | 6 | — | — | — | — | — | 6 | ||||||||||||||||||||||||||||||||||
| Common shares issued upon public offering, net of tax effected cost | 38,227 | — | — | — | — | — | 38,227 | ||||||||||||||||||||||||||||||||||
| Common shares issued under employee share purchase plan | 5,319 | — | — | — | — | — | 5,319 | ||||||||||||||||||||||||||||||||||
| Share-based compensation | — | — | 14,849 | — | — | — | 14,849 | ||||||||||||||||||||||||||||||||||
| Common shares issued pursuant to share-based awards |
9,798 | — | (14,743) | (2,766) | — | — | (7,711) | ||||||||||||||||||||||||||||||||||
| Non-controlling interest assumed on asset acquisition | — | — | 7,300 | — | — | (12,249) | (4,949) | ||||||||||||||||||||||||||||||||||
| Balance, December 31, 2022 | $ | 6,183,943 | $ | 184,299 | $ | 9,413 | $ | (997,945) | $ | (160,063) | $ | 1,616,792 | $ | 6,836,439 | |||||||||||||||||||||||||||
See accompanying notes to consolidated financial statements
| Consolidated Financial Statements | 79 |
Algonquin Power & Utilities Corp.
Consolidated Statements of Cash Flows
| (thousands of U.S. dollars) |
Years ended December 31
|
||||||||||
| 2023 | 2022 | ||||||||||
| Cash provided by (used in): | |||||||||||
| Operating activities | |||||||||||
| Net loss | $ | (33,305) | $ | (308,155) | |||||||
| Adjustments and items not affecting cash: | |||||||||||
| Depreciation and amortization | 466,996 | 455,520 | |||||||||
| Deferred taxes | (76,560) | (69,356) | |||||||||
|
Initial value and changes in derivative financial instruments net of amortization
|
(15,502) | 2,462 | |||||||||
| Share-based compensation | 10,397 | 10,920 | |||||||||
| Cost of equity funds used for construction purposes | (3,366) | (1,896) | |||||||||
| Change in value of investments carried at fair value | 229,988 | 499,125 | |||||||||
|
Pension and post-employment expense lower than contributions
|
(7,838) | (15,329) | |||||||||
| Distributions received from equity investments, net of income | 11,730 | 23,829 | |||||||||
|
Impairment of assets (notes 5 and 8(c))
|
23,492 | 235,478 | |||||||||
|
Other (notes 19(c), 19(e) and 19(f))
|
108,338 | 8,116 | |||||||||
|
Net change in non-cash operating items (note 23)
|
(86,336) | (221,618) | |||||||||
| 628,034 | 619,096 | ||||||||||
| Financing activities | |||||||||||
| Increase in long-term debt | 3,033,503 | 4,622,937 | |||||||||
| Repayments of long-term debt | (2,297,346) | (3,326,519) | |||||||||
| Net change in commercial paper | 74,720 | 68,300 | |||||||||
| Issuance of common shares, net of costs | 5,229 | 43,546 | |||||||||
| Cash dividends on common shares | (322,468) | (378,597) | |||||||||
| Dividends on preferred shares | (8,356) | (8,720) | |||||||||
| Contributions from non-controlling interests and redeemable non-controlling interests (note 3) | 98,955 | 272,515 | |||||||||
| Production-based cash contributions from non-controlling interest | 9,084 | 6,182 | |||||||||
|
Distributions to non-controlling interests, related party (note 17)
|
(25,428) | (34,816) | |||||||||
| Distributions to non-controlling interests | (51,164) | (43,919) | |||||||||
| Payments upon settlement of derivatives | — | (28,913) | |||||||||
| Shares surrendered to fund withholding taxes on exercised share options | (2,434) | (4,667) | |||||||||
|
Redemption of Series C preferred shares (note 12(h))
|
(14,515) | — | |||||||||
| Acquisition of non-controlling interest | — | (1,580) | |||||||||
| Increase in other long-term liabilities | 22,666 | 19,324 | |||||||||
| Decrease in other long-term liabilities | (79,638) | (94,837) | |||||||||
| 442,808 | 1,110,236 | ||||||||||
| Investing activities | |||||||||||
| Additions to property, plant and equipment and intangible assets | (1,026,171) | (1,089,024) | |||||||||
| Increase in long-term investments | (243,742) | (221,281) | |||||||||
| Acquisitions of operating entities | — | (632,797) | |||||||||
| Increase in other assets | (12,220) | (26,527) | |||||||||
| Receipt of principal on development loans receivable | 174,763 | 178,300 | |||||||||
| Decrease in long-term investments | 11,749 | 2,920 | |||||||||
| (1,095,621) | (1,788,409) | ||||||||||
| Effect of exchange rate differences on cash and restricted cash | (267) | (1,127) | |||||||||
|
Decrease in cash, cash equivalents and restricted cash
|
(25,046) | (60,204) | |||||||||
| Cash, cash equivalents and restricted cash, beginning of year | 101,185 | 161,389 | |||||||||
| Cash, cash equivalents and restricted cash, end of year | $ | 76,139 | $ | 101,185 | |||||||
| |
|||||||||||
See accompanying notes to consolidated financial statements
| Consolidated Financial Statements | 80 |
|
Algonquin Power & Utilities Corp.
Consolidated Statements of Cash Flows (continued)
|
|||||||||||
| (thousands of U.S. dollars) |
Years ended December 31
|
||||||||||
| 2023 | 2022 | ||||||||||
| Supplemental disclosure of cash flow information: | |||||||||||
|
Cash paid during the year for interest expense
|
$ | 368,511 | $ | 272,734 | |||||||
|
Cash paid during the year for income taxes
|
$ | 7,171 | $ | 10,962 | |||||||
|
Cash received during the year for distributions from equity investments
|
$ | 112,716 | $ | 112,951 | |||||||
| Non-cash financing and investing activities: | |||||||||||
| Property, plant and equipment acquisitions in accruals | $ | 172,165 | $ | 120,819 | |||||||
| Issuance of common shares under dividend reinvestment plan and share-based compensation plans | $ | 46,040 | $ | 112,918 | |||||||
| Property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable | $ | 23,938 | $ | 90,700 | |||||||
See accompanying notes to consolidated financial statements
| Consolidated Financial Statements | 81 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
Algonquin Power & Utilities Corp. (“AQN” or the “Company”) is an incorporated entity
under the Canada Business Corporations Act. AQN’s operations are organized across two primary business units consisting of the Regulated Services Group and the Renewable Energy
Group. The Regulated Services Group primarily owns and operates a portfolio of regulated electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and
Chile; the Renewable Energy Group primarily owns and operates, or has investments in, a diversified portfolio of non-regulated renewable and thermal energy generation assets.
1.Significant accounting policies
(a)Basis of preparation
The accompanying consolidated financial statements and notes have been
prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.
(b)Basis of consolidation
The accompanying consolidated financial statements of AQN include the
accounts of AQN and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in
non-controlling interests (note 1(s)).
(c)Business combinations, intangible assets and goodwill
The Company accounts for acquisitions of entities or assets that meet
the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred
income taxes, which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and
includes acquisition costs.
Intangible assets acquired are recognized separately at fair value if
they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection
agreements are amortized on a straight-line basis over their estimated life of 40 years. The majority of the Company’s customer relationships are amortized on a straight-line basis over their estimated lives of 25 to 40 years. Certain customer
relationships and water rights in Chile as well as brand names are considered indefinite-lived intangibles and are not amortized, but assessed annually for indicators of impairment. Miscellaneous intangibles include renewable energy credits that
are purchased by the Company’s electric utilities to satisfy renewable portfolio standard obligations. These intangibles are not amortized but are derecognized when remitted to the respective state authority to satisfy the compliance obligation.
Goodwill represents the excess of the purchase price of an acquired
business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized.
As at September 30 of each year, the Company assesses qualitative and
quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is
less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. If the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value, an impairment
charge is recorded in an amount of that excess, limited to the total amount of goodwill allocated to that reporting unit. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely
than not reduce the fair value of a reporting unit below its carrying amount.
| Notes to the Consolidated Financial Statements | 82 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(d)Accounting for rate-regulated operations
The operating companies within the Regulated Services Group are
subject to rate regulation generally overseen by the regulatory authorities of the jurisdictions in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. AQN’s regulated operating
companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”)
except for AQN’s Chilean operating company, Suralis (Chile) Water System (“Suralis”) (formerly known as Empresa de Servicios Sanitarios de Los Lagos (ESSAL). The rates that are approved under the Chilean regulatory framework are designed to
recover the costs of service of a model water utility. Because the rates are not designed to recover Suralis’s specific costs of service, the utility does not meet the criteria to follow the accounting guidance under ASC 980.
Under ASC 980, regulatory assets and liabilities are recorded to the
extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate-making process. Included in note 7, “Regulatory matters”, are details
of regulatory assets and liabilities, and their current regulatory treatment.
In the event the Company determines that its net regulatory assets are
not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate-regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining
regulatory assets or liabilities. The impact could be material to the Company’s reported consolidated financial condition and consolidated results of operations.
The U.S. electric, gas and water utilities’ accounts are maintained in
accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the applicable Regulator(s) and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas
accounts are maintained in accordance with the Gas Distribution Uniform Accounting Regulation - Gas
Distribution Act, 1999 (New Brunswick).
(e)Cash and cash equivalents
Cash and cash equivalents include all highly liquid instruments with
an original maturity of three months or less.
(f)Restricted cash
Restricted cash represents reserves and amounts set aside pursuant to
requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from AQN’s cash balances are maintained in accounts
administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. AQN cannot access restricted cash without the prior authorization of parties not related to AQN.
(g)Accounts receivable
Trade accounts receivable are recorded at the invoiced amount and do
not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into
account current market conditions and customers’ financial condition, the amount of receivables in dispute, future economic conditions and outlook, and the receivables aging and current payment patterns. Account balances are charged against the
allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.
| Notes to the Consolidated Financial Statements | 83 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(h)Fuel and natural gas in storage
Fuel and natural gas in storage is reflected at weighted average cost
or first-in-first-out as required by regulators and represents fuel, natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders and
other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments (note 7(a)). Accordingly, the net realizable value of fuel and gas in
storage does not fall below the cost to the Company.
(i)Supplies and consumables inventory
Supplies and consumables inventory (other than capital spares and
rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or upon becoming obsolete. These items are stated at
the lower of cost and net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base, and repair and maintenance expenses are recovered through a cost of service
calculation. Accordingly, the cost usually reflects the net realizable value.
(j)Property, plant and equipment
Property, plant and equipment are recorded at cost. Capitalization of
development projects begins when it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate-regulated entities, including expenditures for
preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as regulatory assets or
property, plant and equipment when it is determined that recovery of such costs through regulated revenue of the completed project is probable.
The costs of acquiring or constructing property, plant and equipment
include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during
construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost
determined as the present value of lease payments to be made over the lease term.
AFUDC represents the cost of borrowed funds and a return on other
funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property
subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized
that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated
statements of operations.
Improvements that increase or prolong the service life or capacity of
an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as
incurred. Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance
and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility
capital assets. They also include amounts initially recorded as advances in aid of construction (note 12(c)) once the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are
amortized at the rate of the related asset as a reduction to depreciation expense.
| Notes to the Consolidated Financial Statements | 84 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(j)Property, plant and equipment (continued)
The Company’s depreciation is based on the estimated useful lives
of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized
below:
| Range of useful lives | Weighted average useful lives | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Generation |
3-60
|
3-60
|
33 | 33 | |||||||||||||||||||
| Distribution |
1-100
|
1-100
|
40 | 39 | |||||||||||||||||||
| Equipment |
5-54
|
5-54
|
15 | 11 | |||||||||||||||||||
The Company uses the unit-of-production method for certain components of its
wind-generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the
unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component.
In accordance with regulator-approved accounting policies, when
depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in
results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property,
plant and equipment are charged to earnings as incurred.
(k)Commonly owned facilities
The Regulated Services Group owns undivided interests in three
electric-generating facilities with ownership interest ranging from 7.52% to 60%, with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company’s investment in the undivided
interest is recorded as plant in service and recovered through rate base. Commonly owned facilities represent cost of $552,701 (2022 - $559,630) and accumulated depreciation of $83,283 (2022 - $75,820). The Company’s share of operating costs are
recognized in operating expenses. Total expenditures incurred on these facilities for the year ended December 31, 2023 were $72,584 (2022 - $110,268).
(l)Impairment of long-lived assets
AQN reviews property, plant and equipment and finite-life intangible
assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.
As at September 30 of each year, the Company assesses qualitative
factors to determine whether it is more likely than not that the indefinite-lived intangible is impaired. If it is more likely than not that the indefinite-lived intangible asset is impaired, the Company calculates the fair value of the
intangible asset. If the carrying value of the intangible asset exceeds its fair value, the Company recognizes an impairment loss in an amount equal to that excess. Indefinite-life intangibles are tested for impairment between annual tests if an
event occurs or circumstances change that would more likely than not reduces the fair value below its carrying amount.
Recoverability of assets expected to be held and used is measured by
comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value.
| Notes to the Consolidated Financial Statements | 85 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(m)Variable interest entities
The Company performs analyses to assess whether its operations and
investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In
circumstances where AQN is not deemed the primary beneficiary, the VIE is not consolidated (note 8).
The Company has equity and notes receivable interests in two
power-generating facilities. AQN has determined that these entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial
support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As AQN has both the power to direct the activities of the
entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entities, the Company is considered the primary
beneficiary.
Total net book values of assets and long-term debt of these facilities
amount to $57,740 (2022 - $57,241) and $12,738 (2022 - $15,024), respectively. The financial performance of these entities reflected on the consolidated statements of operations includes non-regulated energy sales of $17,317 (2022 - $19,752),
operating expenses and amortization of $5,986 (2022 - $5,834) and interest expense of $1,384 (2022 - $1,723).
(n)Long-term investments and development loans
Investments in which AQN has significant influence but not control are
either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. AQN records its share in the income or loss of its equity-method
investees in income from long-term investments in the consolidated statements of operations. AQN records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when
it is declared by the investee.
Notes receivable are financial assets with fixed or determined
payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method.
The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and
principal are reasonably assured.
If a loss in value of a long-term investment is considered other than
temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance on notes receivable is recorded in order to present the net amount expected to be collected on the receivable. This allowance reflects
the risk of loss over the remaining contractual life of the asset, taking into consideration historical experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The impairment is measured based on
the present value of expected future cash flows discounted at the note’s effective interest rate.
| Notes to the Consolidated Financial Statements | 86 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(o)Pension and other post-employment plans
The Company has established defined contribution pension plans,
defined benefit pension plans, other post-employment benefit (“OPEB”) plans and supplemental retirement program (“SERP”) plans for its various employee groups. Employer contributions to the defined contribution pension plans are expensed as
employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using
assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and
modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (loss) (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the
Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan
for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement.
The costs of the Company’s pension for employees are expensed over the
periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations. The components of net periodic benefit cost other than the service cost component
are included in Pension and other post-employment non-service costs in the consolidated statements of operations.
(p)Asset retirement obligations
The Company recognizes a liability for asset retirement obligations
based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the
estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and
amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of
operations. Actual expenditures incurred are charged against the obligation.
(q)Leases
The Company accounts for leases in accordance with ASC Topic 842, Leases. The Company leases land, buildings, vehicles, rail cars and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of
its lease agreements, with renewal periods ranging from one to five years.
The Renewable Energy Group enters into land easement agreements for
the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has
full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive
access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842.
The right-of-use assets are included in property, plant and equipment
while lease liabilities are included in other liabilities on the consolidated balance sheets. The discount rates used in the measurement of the Company’s right-of-use assets and liabilities are the discount rates at the date of lease inception.
The Company’s lease balances as of December 31, 2023 and its expected lease payments for the next five years and thereafter are not significant.
| Notes to the Consolidated Financial Statements | 87 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(r)Share-based compensation
The Company has several share-based compensation plans: a share option
plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a restricted share unit (“RSU”) and performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The
Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as
administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is
credited to common shares.
(s)Non-controlling interests
Non-controlling interests represent the portion of equity ownership in
subsidiaries that is not attributable to the equity holders of AQN. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings (loss) and other comprehensive income (loss)
(“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.
If a transaction results in the acquisition of all, or part, of a
non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings (loss) or comprehensive income (loss) as a result of
changes in the non-controlling interest, unless a change results in the loss of control by the Company.
Certain of the Company’s U.S.-based wind and solar businesses are
organized as limited liability corporations (“LLCs”) and partnerships, and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes
and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the
percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share
of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17).
The HLBV method uses a balance sheet approach. A calculation is
prepared as at each balance sheet date to
determine the amount that Tax Equity Investors would receive if an equity investment
entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of
the reporting period is the Tax Equity Investors’ share of the earnings or losses from the investment for that period.
Equity instruments subject to redemption upon the occurrence of
uncertain events not solely within AQN’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received
less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the
instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as
temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.
(t)Recognition of revenue
Revenue is recognized when control of the promised goods or services
is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. Refer to note 21, “Segmented information” for details of revenue disaggregation
by business units.
| Notes to the Consolidated Financial Statements | 88 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(t)Recognition of revenue (continued)
Regulated Services Group revenue
Regulated Services Group revenue derives primarily from the
distribution and generation of electricity, water distribution, wastewater collection and distribution of natural gas.
Revenue related to utility electricity and natural gas sales and
distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the
corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class
usage patterns, weather, line loss, unaccounted-for natural gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan.
As a result, in some months cash is received in advance of the
delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant.
Water reclamation and distribution revenue is recognized over time
when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding
unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current
tariffs. Unbilled receivables are typically billed within the next month.
On occasion, a utility is permitted to implement new rates that have
not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the
jurisdiction in which the rates were implemented.
Revenue for certain of the Company’s regulated utilities is subject to
alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue
calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, “Segmented information” and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively,
from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset.
Renewable Energy Group revenue
Renewable Energy Group’s revenue derives primarily from the sale of
electricity, capacity and renewable energy credits.
Revenue related to the sale of electricity is recognized over time as
the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer
to the customer.
Revenue related to the sale of capacity is recognized over time as the
capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a
promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer.
| Notes to the Consolidated Financial Statements | 89 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(t)Recognition of revenue (continued)
Renewable Energy Group revenue (continued)
Qualifying renewable energy projects receive renewable energy credits
(“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The
RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon
generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses.
The Company applies the invoicing expedient to the electricity and
capacity in the Renewable Energy Group contracts. As such, revenue is recognized at the amount to which the Company has the right to invoice for services performed. Revenue is recorded net of sales taxes.
(u)Foreign currency translation
AQN’s reporting currency is the U.S. dollar. Within these consolidated
financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$”, in Chilean pesos with “CLP” and in Chilean Unidad de Fomento with “CLF” immediately prior to the stated amounts.
The Company’s Canadian operations have the Canadian dollar as their
functional currency since the preponderance of operating, financing and investing transactions are denominated in Canadian dollars. Similarly, the Company’s Chilean and Bermudian operations’ functional currency is the Chilean peso and the
Bermudian dollar, respectively. The financial statements of these operations are translated into U.S. dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing as at the balance sheet date, and
revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a
component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.
(v)Income taxes
Income taxes are accounted for using the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax
assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the
date of enactment. Investment tax credits for the rate-regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Investment tax credits along with other income tax
credits in the non-regulated operations are treated as a reduction to income tax expense in the year the credit arises.
The organizational structure of AQN and its subsidiaries is complex
and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect
of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or
measurement are reflected in the period in which the change in judgment occurs.
| Notes to the Consolidated Financial Statements | 90 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(w)Financial instruments and derivatives
Accounts receivable and notes receivable are measured at amortized
cost. Long-term debt and preferred shares, Series C (redeemed during the year) are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.
Transaction costs that are directly attributable to the acquisition of
financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of
that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities, Green equity units (note 11(a)) and intercompany loans are recorded in other assets. Deferred financing costs,
premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of
the respective instrument.
The Company uses derivative financial instruments as one method to
manage exposures to fluctuations in exchange rates, interest rates and commodity prices. AQN recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value
recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company
applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity.
For derivatives designated in a cash flow hedge relationship, the
change in fair value is recognized in OCI.
The amount recognized in AOCI is reclassified to earnings (loss) in
the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold,
terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects
earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings (loss).
Foreign currency gain or loss on derivative or financial instruments
designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge is reported in the same manner as the translation adjustment (in OCI) related to the net investment.
The Company’s electric distribution and thermal generation facilities
enter into power and natural gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and, as such, are not required to be recorded at fair value as derivatives
and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.
(x)Fair value measurements
The Company utilizes valuation techniques that maximize the use of
observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous
market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:
•Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.
•Level 2 Inputs: Other than quoted prices included in Level 1, inputs that are observable for the asset or liability, either directly or indirectly, for
substantially the full term of the asset or liability.
•Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby
allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.
| Notes to the Consolidated Financial Statements | 91 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
1.Significant accounting policies (continued)
(y)Commitments and contingencies
Liabilities for loss contingencies arising from environmental
remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss
contingencies are expensed as incurred.
(z)Use of estimates
The preparation of financial statements requires
management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of these consolidated financial statements and the reported amounts of
revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property,
plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of
regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and the fair value of financial instruments. These estimates and valuation assumptions
are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change
by a material amount.
2. Recently issued accounting pronouncements
(a)Recently adopted accounting pronouncements
The FASB issued Accounting Standards Update (“ASU”) 2022-04, Liabilities — Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations, which require that a buyer in a supplier finance program disclose sufficient information about the program to allow a user of financial
statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. See note 24(c) for details.
(b)Recently issued accounting guidance not yet adopted
The FASB issued ASU 2023-02, Accounting for Investments in Tax Credit Structures Using the Proportional Amortization Method — A Consensus of the
Emerging Issues Task Force, which permits a reporting entity, if certain conditions are met, to elect to account for its
tax equity investments by using the proportional amortization method regardless of the program from which it receives income tax credits. The amendments in this update are effective for fiscal years beginning after December 15, 2023, including
interim periods within those fiscal years. Early adoption is permitted. The Company is currently assessing the applicability and potential impact of the new guidance.
The FASB issued ASU 2023-05, Joint Venture Formations: Recognition and Initial Measurement, which requires a joint venture to recognize and initially measure its assets and liabilities at fair value as at the joint venture formation date. The amendments in this update
are effective prospectively for all joint venture formations with a formation date on or after January 1, 2025. Additionally, a joint venture formed before January 1, 2025 may elect to apply the amendments retrospectively if it has sufficient
information. Early adoption is permitted. The Company is currently assessing the applicability and potential impact of the new guidance.
The FASB issued ASU 2023-07, Segment Reporting: Improvement to Reportable Segments Disclosures, which requires enhanced disclosures about significant segment expenses. The amendments in this update are effective for annual periods beginning on December 15, 2023 and
interim periods within annual periods beginning on December 15, 2024. Early adoption is permitted. The Company is currently assessing the relevant disclosure.
The FASB issued ASU 2023-09, Income Taxes: Improvement to Income Tax Disclosures, which requires a reporting entity to disclose additional income tax information primarily related to the rate reconciliation and income taxes paid information. The amendments
in this update are effective prospectively for annual periods beginning on December 15, 2024. Early adoption is permitted. The Company is currently assessing the relevant disclosure.
| Notes to the Consolidated Financial Statements | 92 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
3.Business acquisitions, development projects and disposition transactions
(a)Kentucky Power Company and AEP Kentucky Transmission Company, Inc.
On October 26, 2021, Liberty Utilities Co., an indirect subsidiary of
AQN, entered into an agreement (the “Kentucky Acquisition Agreement”) with American Electric Power Company, Inc. (“AEP”) and AEP Transmission Company, LLC to acquire Kentucky Power Company and AEP Kentucky Transmission Company, Inc. (the
“Kentucky Power Transaction”). On April 17, 2023, Liberty Utilities Co. mutually agreed with AEP and AEP Transmission Company, LLC to terminate the Kentucky Acquisition Agreement. The Company recognized $46,527 in other net losses for the year
ended December 31, 2023 related to a write-off of costs incurred in preparation for the Kentucky Power Transaction and the termination of the Kentucky Acquisition Agreement. See note 19 for details.
(b)Acquisition of the Deerfield II Wind Facility
On June 15, 2023, the Company, acquired the remaining 50% ownership in
the Deerfield II Wind Facility for consideration of $23,142. The transaction has been accounted for as an asset acquisition. Subsequent to acquisition, the tax equity investors provided additional funding of $98,955, and a third-party
construction loan of $158,550 was repaid.
The following table summarizes the allocation of the aggregate
purchase price to the assets acquired and liabilities assumed at the acquisition dates.
| Deerfield II | |||||
| Working capital | $ | (10,709) | |||
| Property, plant and equipment | 194,419 | ||||
| Long-term debt | (157,935) | ||||
| Asset retirement obligation | (1,030) | ||||
| Deferred tax liability | (1,603) | ||||
| Total net assets acquired | 23,142 | ||||
| Cash and cash equivalents | 1,662 | ||||
| Net assets acquired, net of cash and cash equivalents | $ | 21,480 | |||
(c)Acquisition of the Sandy Ridge II Wind Facility
Subsequent to year end, on February 15, 2024, the Company acquired the
remaining 50% ownership in the Sandy Ridge II Wind Facility for consideration of $8,456. Subsequent to acquisition, the tax equity investors provided additional funding of $60,545, and a third-party construction loan of $162,805 was repaid. Due
to the timing of the acquisition, the Company has not completed the fair value measurements. The Company will continue to review information and perform further analysis prior to finalizing the allocation of the consideration paid to the fair
value of the assets acquired and liabilities assumed.
(d)Partial disposition of renewable assets
On December 29, 2022, the Company closed the sale of ownership
interests in a portfolio of operating wind facilities in the United States and Canada. The transaction consisted of the sale of (1) a 49% ownership interest in three operating wind facilities in the United States totalling 551 MW of installed
capacity: the Odell Wind Facility in Minnesota, the Deerfield I Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois; and (2) an 80% ownership interest in the operating 175 MW Blue Hill Wind Facility in Saskatchewan. The
Company retains control over the U.S. facilities. The Company oversees day-to-day operations and provides management services to each of the facilities.
The cash proceeds of $277,500 for the U.S. facilities, which continue
to be consolidated, were recorded as non-controlling interest (subject to certain post-closing adjustments). The investment in the Blue Hill Wind Facility continues to be recorded as an equity-method investee. Cash proceeds of C$108,610 were
received for the Blue Hill Wind Facility (subject to certain post-closing adjustments). A gain on disposition of $62,828 was recognized and included in gain on sale of renewable assets on the consolidated statements of operations.
| Notes to the Consolidated Financial Statements | 93 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
3.Business acquisitions, development projects and disposition transactions (continued)
(e)Acquisition of New York American Water Company, Inc.
Effective January 1, 2022, the Company completed the acquisition of
New York American Water Company, Inc (subsequently renamed Liberty Utilities (New York Water) Corp. (“Liberty NY Water”)). Liberty NY Water is a regulated water and wastewater utility, serving customers in eight counties in southeastern New York.
A purchase price of $609,000 was paid for this acquisition. The
acquisition related costs were expensed through the consolidated statement of operations (note 19). The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed when control was
obtained.
| Working capital | $ | 4,820 | |||
| Property, plant and equipment (i) | 499,252 | ||||
| Goodwill (ii) | 116,254 | ||||
| Regulatory assets (iii) | 65,621 | ||||
| Other assets | 4,507 | ||||
| Pension and other post-employment benefits | (13,402) | ||||
| Regulatory liabilities (iii) | (59,727) | ||||
| Other liabilities | (8,028) | ||||
| Total net assets acquired | $ | 609,297 | |||
| Cash and cash equivalents acquired | 49 | ||||
| Total net assets acquired, net of cash and cash equivalents | $ | 609,248 | |||
The determination of the fair value of assets acquired and liabilities
assumed is based upon management’s estimates and certain assumptions.
i.Property, plant and equipment consist of regulated water distribution infrastructure and wastewater collection and
treatment facilities. They are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of Liberty NY Water’s assets is 64.74 years.
ii.Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The
contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost of savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Regulated Services Group.
iii.The Company is subject to regulation by the New York State Public Service Commission (“NYPSC”), which has jurisdiction with respect to rates, service,
accounting procedures, acquisitions and other matters. Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be
recovered from or refunded to customers through the rate making process (note 7). As part of the approval of the acquisition of Liberty NY Water, a settlement agreement was approved which requires a full year of ownership prior to the filing of a
new rate case. As a result, new rates would not come into effect until 2024.
Liberty NY Water was consolidated upon acquisition. In 2022, Liberty
NY Water generated approximately $125,370 in revenue and $21,776 operating income.
4.Accounts receivable
Accounts receivable as of December 31, 2023 include unbilled revenue
of $107,001 (2022 - $149,015) from the Company’s regulated utilities. Accounts receivable as of December 31, 2023 are presented net of allowance for doubtful accounts of $30,244 (2022 - $24,857).
| Notes to the Consolidated Financial Statements | 94 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
5.Property, plant and equipment
Property, plant and equipment consist of the following:
| 2023 | |||||||||||||||||
| Cost | Accumulated depreciation | Net book value | |||||||||||||||
| Renewable generation facilities | $ | 4,200,559 | $ | 1,139,137 | $ | 3,061,422 | |||||||||||
| Utility plant | 9,332,092 | 1,191,013 | 8,141,079 | ||||||||||||||
| Land | 133,483 | — | 133,483 | ||||||||||||||
| Equipment | 122,929 | 53,181 | 69,748 | ||||||||||||||
|
Construction-in-progress
|
|||||||||||||||||
| Generation | 378,043 | — | 378,043 | ||||||||||||||
| Distribution and transmission | 733,675 | — | 733,675 | ||||||||||||||
| $ | 14,900,781 | $ | 2,383,331 | $ | 12,517,450 | ||||||||||||
| 2022 | |||||||||||||||||
| Cost | Accumulated depreciation | Net book value | |||||||||||||||
| Renewable generation facilities | $ | 4,119,514 | $ | 1,016,784 | $ | 3,102,730 | |||||||||||
| Utility plant | 8,640,224 | 990,975 | 7,649,249 | ||||||||||||||
| Land | 113,153 | — | 113,153 | ||||||||||||||
| Equipment | 111,707 | 50,904 | 60,803 | ||||||||||||||
|
Construction-in-progress
|
|||||||||||||||||
| Generation | 196,287 | — | 196,287 | ||||||||||||||
| Distribution and transmission | 822,663 | — | 822,663 | ||||||||||||||
| $ | 14,003,548 | $ | 2,058,663 | $ | 11,944,885 | ||||||||||||
During the fourth quarter of 2022, the Company concluded that some
assets in the Renewable Energy Group may not be recoverable due to declining forecasted energy prices in the Electric Reliability Council of Texas (“ERCOT”) market, mainly affecting the results of the Senate Wind Facility (which began commercial
operations in 2012). Accordingly, the Company performed fair value analysis based on the income approach and recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942
to $100,374.
Renewable generation facilities include cost of $117,556 (2022 -
$111,192) and accumulated depreciation of $52,506 (2022 - $46,666) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $537 (2022 - $1,489). Utility plant includes
cost of $3,270 (2022 - $3,076) and accumulated depreciation of $2,455 (2022 - $2,041) related to assets under finance lease.
Utility plant includes cost of $1,922,844 (2022 - $2,033,391) and
accumulated depreciation of $141,466 (2022 - $133,644) related to regulated generation assets.
For the year ended December 31, 2023,
contributions received in aid of construction of $238 (2022 - $1,299) have been credited to the cost of the assets.
| Notes to the Consolidated Financial Statements | 95 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
5.Property, plant and equipment (continued)
Interest and AFUDC capitalized to the cost of the assets in 2023 and 2022 are as follows:
| 2023 | 2022 | ||||||||||
| Interest capitalized on non-regulated property | $ | 6,374 | $ | 4,762 | |||||||
| AFUDC capitalized on regulated property: | |||||||||||
| Allowance for borrowed funds | 8,305 | 6,040 | |||||||||
| Allowance for equity funds | 3,372 | 1,901 | |||||||||
| $ | 18,051 | $ | 12,703 | ||||||||
6.Intangible assets and goodwill
Intangible assets consist of the following:
| 2023 | Cost | Accumulated amortization | Net book value | ||||||||||||||
| Power sales contracts | $ | 58,200 | $ | 43,938 | $ | 14,262 | |||||||||||
| Customer relationships | 77,104 | 14,625 | 62,479 | ||||||||||||||
| Interconnection agreements | 10,329 | 1,977 | 8,352 | ||||||||||||||
|
Other (a)
|
10,352 | 1,507 | 8,845 | ||||||||||||||
| $ | 155,985 | $ | 62,047 | $ | 93,938 | ||||||||||||
| 2022 | Cost | Accumulated amortization | Net book value | ||||||||||||||
| Power sales contracts | $ | 56,926 | $ | 42,818 | $ | 14,108 | |||||||||||
| Customer relationships | 77,850 | 13,709 | 64,141 | ||||||||||||||
| Interconnection agreements | 10,098 | 1,851 | 8,247 | ||||||||||||||
|
Other (a)
|
10,338 | 151 | 10,187 | ||||||||||||||
| $ | 155,212 | $ | 58,529 | $ | 96,683 | ||||||||||||
(a) Other includes brand names, water rights and miscellaneous intangibles
Estimated amortization expense for intangible assets for each of the
next five years is $2,674.
All goodwill pertains to the Regulated Services Group.
| 2023 | 2022 | ||||||||||
| Opening balance | $ | 1,320,579 | $ | 1,201,244 | |||||||
| Business acquisitions | 4,195 | 123,751 | |||||||||
| Foreign exchange | (712) | (4,416) | |||||||||
| Closing balance | $ | 1,324,062 | $ | 1,320,579 | |||||||
7. Regulatory matters
The operating companies within the Regulated Services Group are
subject to regulation by the respective Regulators of the jurisdictions in which they operate. The respective Regulators have jurisdiction with respect to rate, service, issuance of securities, acquisitions and other matters. Except for Suralis,
these utilities operate under cost-of-service regulation as administered by these authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980. Under ASC 980, regulatory assets and liabilities
that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to
customers through the rate-setting process.
| Notes to the Consolidated Financial Statements | 96 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
7.Regulatory matters (continued)
At any given time, the Company can have several regulatory proceedings
underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following
regulatory proceedings were recently completed:
| Utility | State, Province or Country | Regulatory Proceeding Type | Details | ||||||||
| Apple Valley Water System | California | General rate review |
On February 3, 2023, the California Public Utilities Commission (“CPUC”) issued a final order
authorizing an annual revenue increase of $1,494. New rates became effective on April 7, 2023 retroactive to July 1, 2022. The retroactive impact of this final order was recorded in the first quarter of 2023.
|
||||||||
| Park Water System | California | General rate review |
On February 3, 2023, the CPUC issued a final order authorizing an annual revenue increase of
$1,105. New rates became effective on April 7, 2023 retroactive to July 1, 2022. The retroactive impact of this final order was recorded in the first quarter of 2023.
|
||||||||
| CalPeco Electric System | California | General rate review |
On April 27, 2023, the California Public Utilities Commission (“CPUC”) issued a final order approving a revenue increase of $26,979. New rates became effective on July 1, 2023 retroactive to January 2022. The retroactive impact of this final order was recorded in the second quarter of 2023.
|
||||||||
| St. Lawrence Gas | New York | General rate review |
On June 22, 2023, the New York State Department
of Public Services issued an Order authorizing a revenue increase of $5,249 to be implemented over the course of 2023-2025. New rates became effective July 1, 2023.
|
||||||||
| Pine Bluff Water | Arkansas | General rate review |
On August 4, 2023, the Arkansas Public Service Commission issued an Order approving a
unanimous settlement agreement filed by the parties authorizing an annual revenue increase of $3,400. New rates became effective August 15, 2023.
|
||||||||
| Gas New Brunswick | New Brunswick | General rate review |
On September 21, 2023 the Energy & Utilities Board issued a decision authorizing a
revenue decrease of $700.
|
||||||||
| Empire Electric | Arkansas | General rate review |
On December 7, 2023, the Arkansas Public Service Commission issued an Order approving the
settlement agreement authorizing a revenue increase of $5,300. New rates became effective January 1, 2024.
|
||||||||
| Empire Electric | Missouri | Securitization |
On August 1, 2023, the Missouri Western District Court of Appeals affirmed the amount eligible for securitization in line with the Missouri
Public Service Commission’s (“MPSC”) order of $290,383. Subsequent to year-end, on January 30, 2024. the Company completed the securitization to recover the costs associated with the extreme winter storm conditions experienced in
Texas and parts of central U.S in February 2021 (“Midwest Extreme Weather Event”) and the remaining book value of the Asbury generating plant. The MPSC’s order excludes a portion of carrying costs and taxes associated with the
retirement of the Asbury plant. Thus. the Company has incurred a one-time net loss of
$63,495 ($48,452 net of tax) in the third quarter of 2023.
|
||||||||
| Notes to the Consolidated Financial Statements | 97 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
7.Regulatory matters (continued)
Regulatory assets and liabilities consist of the following:
| December 31, 2023 | December 31, 2022 | ||||||||||
| Regulatory assets | |||||||||||
| Fuel and commodity cost adjustments (a) | $ | 326,418 | $ | 388,294 | |||||||
| Retired generating plant (b) | 183,732 | 174,609 | |||||||||
| Rate adjustment mechanism (c) | 192,880 | 136,198 | |||||||||
| Income taxes (d) | 101,939 | 97,414 | |||||||||
| Deferred capitalized costs (e) | 124,517 | 90,121 | |||||||||
| Pension and post-employment benefits (f) | 68,822 | 80,736 | |||||||||
| Environmental remediation (g) | 66,779 | 70,529 | |||||||||
| Wildfire mitigation and vegetation management (h) | 64,146 | 66,156 | |||||||||
| Clean energy and other customer programs (i) | 37,214 | 28,145 | |||||||||
| Asset retirement obligation (j) | 26,620 | 27,172 | |||||||||
| Debt premium (k) | 18,995 | 24,888 | |||||||||
| Cost of removal (l) | 11,084 | 11,084 | |||||||||
| Rate review costs (m) | 8,815 | 9,481 | |||||||||
| Long-term maintenance contract (n) | 4,932 | 6,504 | |||||||||
| Other regulatory assets (o) | 90,790 | 60,170 | |||||||||
| Total regulatory assets | $ | 1,327,683 | $ | 1,271,501 | |||||||
| Less: current regulatory assets | (142,970) | (190,393) | |||||||||
| Non-current regulatory assets | $ | 1,184,713 | $ | 1,081,108 | |||||||
| Regulatory liabilities | |||||||||||
| Income taxes (d) | $ | 290,121 | $ | 312,671 | |||||||
| Cost of removal (l) | 185,786 | 191,173 | |||||||||
| Pension and post-employment benefits (f) | 104,636 | 68,085 | |||||||||
| Fuel and commodity cost adjustments (a) | 42,850 | 24,991 | |||||||||
| Clean energy and other customer programs (i) | 12,730 | 11,572 | |||||||||
| Rate adjustment mechanism (c) | 2,078 | 343 | |||||||||
|
Other regulatory liabilities (p)
|
96,095 | 19,347 | |||||||||
| Total regulatory liabilities | $ | 734,296 | $ | 628,182 | |||||||
| Less: current regulatory liabilities | (99,850) | (69,865) | |||||||||
| Non-current regulatory liabilities | $ | 634,446 | $ | 558,317 | |||||||
As recovery of regulatory assets is subject to regulatory approval, if there were any
changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally does not earn a return on the regulatory balances except for carrying
charges on fuel and commodity cost adjustments (a), rate adjustment mechanism (c), clean energy and other customer programs (i), and rate review costs of some jurisdictions (m). During 2023, the Company recognized $41,410 (2022 - $18,179) of
carrying charges on regulatory balances on the consolidated statements of operations under other income and was computed using only the debt component of the allowed returned.
| Notes to the Consolidated Financial Statements | 98 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
7.Regulatory matters (continued)
(a)Fuel and commodity cost adjustments
The revenue from the utilities includes a component
that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or fuel purchased differ from power or fuel costs recoverable through current rates, that difference is
deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and fuel in future periods ranging mostly
from 6 to 24 months, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated
with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment.
In February 2021, the Company’s operations were impacted by the
Midwest Extreme Weather Event. As a result of the Midwest Extreme Weather Event, the Company incurred incremental commodity costs during the period of record high pricing and elevated consumption. The Company has commodity cost mechanisms that
allow for the recovery of prudently incurred expenses.
In early 2022, pursuant to the securitization statute, Empire Electric
sought authorization for the issuance of $221,646 in securitized utility tariff bonds associated with the Midwest Extreme Weather Event and $140,774, in securitized utility tariff bonds for its Asbury costs, which included $21,283 in asset
retirement obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred. On August 1, 2023, the Missouri Western District Court of Appeals affirmed the amount eligible
for securitization in line with the MPSC’s order of $290,383. The MPSC’s order excludes a portion of carrying costs and taxes associated with the retirement of the Asbury plant. Thus, the Company has incurred a one-time net loss of $63,495
($48,452 net of tax) in the third quarter of 2023.
Subsequent to year-end, on January 30, 2024, Empire District Bondco,
LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180.5 million of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and
$125 million aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy
transition costs related to the retirement of the Asbury generating plant.
(b)Retired generating plant
On March 1, 2020, the Company’s 200 MW coal generation facility located in Asbury,
Missouri, ceased operations. The Company transferred the remaining net book value of Asbury’s plant retired from plant in-service to a regulatory asset. The net book value that may be retained as an asset on the consolidated balance sheets for
the retired plant is dependent upon amounts that may be recovered through regulated rates, including any return. An impairment charge, if any, would equal the difference between the remaining net book value of the asset and the present value of
the future revenues expected from the asset. The Company is also assessing the decommissioning requirements associated with the retirement of the facility.
Per commission orders in its jurisdictions, the Company is required to
track the impact of Asbury's retirement on operating and capital expenses in Missouri for consideration in the next rate case. The Company recorded a regulatory liability for the estimated amount of revenues collected from customers for Asbury
from March 1, 2020 to May 1, 2022 that AQN determined was probable of refund. This regulatory liability did not include revenues collected related to the return on investment in Asbury as AQN determined that they were not probable of refund to
customers based on the relevant facts and circumstances. The Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, the regulatory liability is netted against its retired
generation facilities regulatory asset.
| Notes to the Consolidated Financial Statements | 99 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
7.Regulatory matters (continued)
(b)Retired generating plant (continued)
On April 27, 2022, the MPSC issued an order
consolidating, for purposes of hearing, the cases regarding the quantum financeable through securitization for Asbury and the Midwest Extreme Weather Event. As noted above under (a) Fuel and commodity cost adjustments,
subsequent to year-end, on January 30, 2024, the Company completed the securitization of the costs associated with the retirement of the Asbury plant in accordance with the MPSC’s order.
(c)Rate adjustment mechanism
Revenue for CalPeco Electric System, New England Gas System, Midstates
Gas system, EnergyNorth Gas System, Granite State Electric System, Peach State Gas System and BELCO is subject to a revenue decoupling mechanism approved by their respective regulator, which allows revenue decoupling from sales. As a result, the
difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers over periods ranging from
one to five years. The revenue from BELCO includes a component that is designed to recover budgeted capital and operating expenses for the current year. To the extent actual capital and operating
expenditures are lower than the budgeted amounts, 80% of the shortfall is refundable to customers and is recorded as a regulatory liability. Retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24
months are accrued upon approval of the final order. The difference between New Brunswick Gas’ regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis
over 26 years. The Liberty NY Water System has similar trackers, which are recovered over periods ranging from one to two years.
(d)Income taxes
The income taxes regulatory assets and liabilities represent income
taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities over the life of the plants and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates.
(e)Deferred capitalized costs
Deferred capitalized costs reflect deferred construction costs and
fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and
these amounts are being recovered at a rate of 2.43% annually.
In 2020, the Empire Electric System made an election under Missouri
law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits the Empire Electric System to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable weighted
average cost of capital (“WACC”) on certain property, plant and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall
include carrying costs at the WACC, plus applicable federal, state and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new
rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates.
| Notes to the Consolidated Financial Statements | 100 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
7.Regulatory matters (continued)
(f)Pension and post-employment benefits
To the extent pension and OPEB costs incurred differ
from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability as approved by the applicable Regulators and is recovered through rates over a period of three to eight years. In addition, the annual movements in AOCI for pension and OPEB for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System (note 10(a)) are
reclassified to regulatory accounts in accordance with ASC 980. The balance is recovered through rates consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement
Benefits. As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that had not yet been recognized in net periodic cost and were
presented as AOCI prior to the acquisition. These balances are recovered through rates over the future service years of the employees (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement
Benefits before the transfer to regulatory asset occurred.
(g)Environmental remediation
Actual expenditures incurred for the clean-up of
certain former natural gas manufacturing facilities (note 12(d)) are recovered through rates over a period of seven years and are subject to an annual cap.
(h)Wildfire mitigation and vegetation management
The regulatory asset includes incremental wildfire liability insurance
premium costs approved for tracking in the Company’s California operations as well as the difference between actual and adopted spending related to dead trees program, to prevent future forest fires and general vegetation management. The assets
are recovered over two years.
(i)Clean energy and other customer programs
The regulatory asset for clean energy and customer programs includes
initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. The assets are generally included in rate base and recovered over periods of six to ten years.
(j)Asset retirement obligation
Asset retirement obligations are recorded for legally required removal
costs of property, plant and equipment. The costs of retirement of assets as well as the on-going liability accretion and asset depreciation expense are expected to be recovered through rates once expenditures are made.
(k)Debt premium
Debt premium on acquired debt is recovered as a component of the
weighted average cost of debt.
(l)Cost of removal
Rates charged to customers cover for costs that are expected to be
incurred in the future to retire the utility plant. A regulatory liability (or asset) tracks the amounts that have been collected from customers net of costs incurred to date.
(m)Rate review costs
The cost to file, prosecute and defend rate review applications is
referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the Regulator ranging from one to five years
(n)Long-term maintenance contract
To the extent actual costs of long-term maintenance incurred for one
of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is generally included in rate base and recovered over five years.
(o)Other regulatory assets
The Company’s regulated utilities incur other miscellaneous costs such
as storm costs, property taxes, financing costs and equipment costs, which are probable of recovery under existing mechanisms.
| Notes to the Consolidated Financial Statements | 101 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
7.Regulatory matters (continued)
(p)Other regulatory liabilities
During the year, the Company recognized a regulatory liability of
$63,495 relating to the portion of additional securitization costs of Empire Electric that were not allowed as per the Securitization Statute.
8.Long-term investments
Long-term investments consist of the following:
| December 31, 2023 | December 31, 2022 | ||||||||||
| Long-term investments
carried at fair value |
|||||||||||
| Atlantica (a) | $ | 1,052,703 | $ | 1,268,140 | |||||||
| Atlantica Yield Energy Solutions Canada Inc. (b) | 61,064 | 74,083 | |||||||||
| Other | 1,962 | 1,984 | |||||||||
| $ | 1,115,729 | $ | 1,344,207 | ||||||||
| Other long-term investments | |||||||||||
| Equity-method investees (c) | $ | 456,393 | $ | 381,802 | |||||||
| Development loans receivable from equity-method investees (d) | 158,110 | 52,923 | |||||||||
|
San Antonio Water System and other (e)
|
27,417 | 27,600 | |||||||||
| $ | 641,920 | $ | 462,325 | ||||||||
Fair value change, income (loss) and impairment expense related to long-term investments
from the years ended December 31 is as follows:
| Year ended December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
|
Fair value loss on investments carried at fair value
|
||||||||||||||
| Atlantica | $ | (215,437) | $ | (482,774) | ||||||||||
| Atlantica Yield Energy Solutions Canada Inc. | (14,684) | (16,018) | ||||||||||||
| Other | 133 | (333) | ||||||||||||
| $ | (229,988) | $ | (499,125) | |||||||||||
| Dividend and interest income from investments carried at fair value | ||||||||||||||
| Atlantica | $ | 87,154 | $ | 86,664 | ||||||||||
| Atlantica Yield Energy Solutions Canada Inc. | 16,604 | 20,443 | ||||||||||||
| Other | 49 | 36 | ||||||||||||
| $ | 103,807 | $ | 107,143 | |||||||||||
| Other long-term investments | ||||||||||||||
| Equity method loss (c) | $ | (5,936) | $ | (21,416) | ||||||||||
| Impairment of equity-method investee (c) | — | (75,910) | ||||||||||||
| Interest and other income | 7,143 | 5,923 | ||||||||||||
| $ | 1,207 | $ | (91,403) | |||||||||||
| Fair value change, income (loss) and impairment expense related to long-term investments | $ | (124,974) | $ | (483,385) | ||||||||||
| Notes to the Consolidated Financial Statements | 102 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
8.Long-term investments (continued)
(a)Investment in Atlantica
Liberty (AY Holdings) B.V. (“AY Holdings”),
an entity controlled and consolidated by AQN, has a share ownership in Atlantica Sustainable Infrastructure PLC (“Atlantica”) of approximately 42% (2022 - 42%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The total cost for the Atlantica shares as of December 31, 2023 is $1,167,444 (2022 - $1,167,444).
The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment
in Atlantica, with changes in fair value reflected in the consolidated statements of operations.
(b)Investment in Atlantica Yield Energy Solutions Canada Inc.
AQN and Atlantica own Atlantica Yield Energy Solutions Canada Inc.
(“AYES Canada”), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. AYES Canada invested in Windlectric Inc. (“Windlectric”). The investment by AYES Canada in Windlectric is presented as a non-controlling interest held by a related party.
AYES Canada is considered to be a VIE based on the disproportionate
voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, AQN's investment in AYES Canada is considered an equity-method investment. Under the AYES Canada shareholders
agreement, AQN has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the
treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial
Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated
statements of operations.
As of December 31, 2023, the Company's maximum exposure to loss is $61,064 (2022 - $74,083), which represents the fair value of the investment.
(c)Equity-method investees
The Renewable Energy Group has non-controlling interests in operating
renewable energy facilities and projects under construction with a total carrying value of $343,712 (2022 - $310,103). The Regulated Services Group has non-controlling interest of $112,180 (2022 - $56,199) in a power transmission line project
under construction and other non-regulated operating entities owned by its utilities. The Liberty Development JV Inc. platform for non-regulated renewable energy, water and other sectors has a carrying value of $501 and
(2022 - $15,500) is reported under Corporate.
Operating entities: The Company has interests in the operating
entities listed below. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.
| Economic interest | Capacity | ||||||||||
| Texas Coastal Wind Facilities | 51 | % | 861 MW | ||||||||
| Blue Hill Wind Facility | 20 | % | 175 MW | ||||||||
| Red Lily Wind Facility | 75 | % | 26.4 MW | ||||||||
| Val-Eo Wind Facility | 50 | % | 24 MW | ||||||||
During 2021, the Company acquired a 51% interest in four wind facilities located in
Texas (“Texas Coastal Wind Facilities”) for $344,883. All facilities achieved commercial operations in 2021. During the fourth quarter of 2022, the Company concluded that primarily as a result of continued challenges with congestion at the
facilities, the carrying value of the interest in the Texas Coastal Wind Facilities was other-than-temporarily impaired. Accordingly, the Company performed a fair value analysis based on the income approach and recorded an impairment charge of
$75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities from $282,726 to $206,816. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices,
projected operating and capital expenditures would affect the estimated fair value.
| Notes to the Consolidated Financial Statements | 103 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
8.Long-term investments (continued)
(c)Equity-method investees (continued)
As at December 31, 2023, the Company has issued $113,630 (2022 -
$113,630) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities.
Development: Pursuant to an agreement between AQN and funds managed by
the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021 Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors as both parties contributed cash or
assets of $19,688 to Liberty Development JV Inc. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.
On July 5, 2023, the Company provided a $35,000 non-interest-bearing
loan to Liberty Development JV Inc. The joint venture used these funds to return equity to its shareholders through which the Company received $17,500. Further, the Company recognized an impairment loss on its note receivable of $18,911 as it no
longer expects to pursue development under this joint venture arrangement and the development fees are no longer expected to be realized. The impairment is recorded within asset impairment charge in the consolidated statements of operations.
Subsequent to year-end, on January 4, 2024, the Company purchased Ares’ 50% interest in Liberty Development JV Inc. and Liberty Development Energy Solutions B.V.
Construction: The Renewable Energy Group has 50% equity interests in several wind and solar power electric construction projects. AQN and Ares have formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly
construct projects under the Renewable Energy Group. During the year, the Company contributed several projects to joint entities. The Company holds an option to acquire the remaining interest in most construction projects at a pre-agreed price.
The Company is not considered the primary beneficiary as the partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity
method.
Changes in the carrying value of equity method investees were as
follows:
| 2023 | 2022 | ||||||||||
| Carrying value, January 1 | $ | 381,802 | $ | 433,850 | |||||||
|
Additional investments
|
91,205 | 110,441 | |||||||||
| Net loss attributable to AQN | (5,936) | (21,416) | |||||||||
| OCI attributable to AQN (a) | 7,693 | (67,110) | |||||||||
| Dividend received | (4,600) | (1,183) | |||||||||
| Impairment | — | (75,910) | |||||||||
| Other | (13,771) | 3,130 | |||||||||
| Carrying value, December 31 | $ | 456,393 | $ | 381,802 | |||||||
(a) OCI represents
the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge
| Notes to the Consolidated Financial Statements | 104 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
8.Long-term investments (continued)
(c)Equity-method investees (continued)
Summarized combined information for AQN's equity method investees as
of December 31 is as follows:
| 2023 | 2022 | ||||||||||
| Total assets | $ | 3,235,474 | $ | 2,740,132 | |||||||
| Total liabilities | 1,962,115 | 1,507,079 | |||||||||
| Net assets | 1,273,359 | 1,233,053 | |||||||||
| AQN's ownership interest in the entities | 388,993 | 332,663 | |||||||||
|
Difference between investment carrying amount and underlying equity in net assets(a)
|
67,400 | 49,139 | |||||||||
| Total carrying value | $ | 456,393 | $ | 381,802 | |||||||
(a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction,
the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs.
Summarized combined information for AQN's equity method investees for
the year ended December 31 (presented at 100%) is as follows:
| 2023 | 2022 | ||||||||||
| Revenue | $ | 111,446 | $ | 65,025 | |||||||
| Net loss | $ | (3,633) | $ | (31,070) | |||||||
|
OCI (a)
|
$ | 12,026 | $ | (130,729) | |||||||
| Net loss attributable to AQN | $ | (5,936) | $ | (21,416) | |||||||
|
OCI attributable to AQN (a)
|
$ | 7,693 | $ | (67,110) | |||||||
(a) OCI represents
the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge
Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global
Energy Solutions B.V.) (“Liberty Global Energy Solutions”), Liberty Development JV Inc. and all construction projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the
shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support for the continued development and construction
of the equity investees' projects. As of December 31, 2023, the Company has issued letters of credit and guarantees of performance obligations: under a security of performance for a development opportunity; wind turbine or solar panel supply
agreements; engineering, procurement, and construction agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; and construction loan agreements. The fair value of the support provided recorded as of
December 31, 2023 amounts to $12,666 (2022 - $8,824).
| Notes to the Consolidated Financial Statements | 105 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
8.Long-term investments (continued)
(c)Equity-method investees (continued)
Summarized combined information for AQN's VIEs as of December 31 is as follows:
| 2023 | 2022 | ||||||||||
| AQN's maximum exposure in regards to VIEs | |||||||||||
| Carrying amount | $ | 179,728 | $ | 122,752 | |||||||
| Development loans receivable (d) | 158,110 | 52,923 | |||||||||
|
Indirect guarantees of debt on behalf of VIEs
|
740,866 | 436,790 | |||||||||
|
Other indirect guarantees and commitments on behalf of VIEs
|
303,641 | 221,433 | |||||||||
| $ | 1,382,345 | $ | 833,898 | ||||||||
The commitments are presented on a gross basis assuming no recoverable value in the
assets of the VIEs. The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements.
(d)Development loans receivable from equity investees
The Renewable Energy Group has committed loan and credit support
facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support (in the form of letters of credit, escrowed cash, guarantees or indemnities) in amounts necessary for the
continued development and construction of the equity investees' projects. The loans generally mature on the twelfth anniversary of the development agreement or commercial operation date.
(e)San Antonio Water System and other
The Company does not have significant influence over San Antonio Water
System investments. It is accounted for using the cost method and as at December 31, 2023, it is recorded at the cost of $25,634 (2022 - $25,634).
| Notes to the Consolidated Financial Statements | 106 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
9.Long-term debt
Long-term debt consists of the following:
| Borrowing type | Weighted average coupon | Maturity | Par value | December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||
| Senior unsecured revolving credit facilities (a) | — | 2024-2028 | N/A | $ | 1,624,186 | $ | 351,786 | |||||||||||||||||||||||||
| Senior unsecured bank credit facilities and delayed draw term facility (b) | — | 2024-2031 | N/A | 786,962 | 773,643 | |||||||||||||||||||||||||||
| Commercial paper | — | 2024 | N/A | 481,720 | 407,000 | |||||||||||||||||||||||||||
| U.S. dollar borrowings | ||||||||||||||||||||||||||||||||
| Senior unsecured notes (Green Equity Units) | 1.18 | % | 2026 | $ | 1,150,000 | 1,144,897 | 1,142,814 | |||||||||||||||||||||||||
| Senior unsecured notes (c) | 3.36 | % | 2024-2047 | $ | 1,415,000 | 1,406,278 | 1,496,101 | |||||||||||||||||||||||||
| Senior unsecured utility notes | 6.30 | % | 2025-2035 | $ | 137,000 | 147,589 | 154,271 | |||||||||||||||||||||||||
| Senior secured utility bonds (d) | 4.71 | % | 2026-2044 | $ | 556,199 | 551,166 | 554,822 | |||||||||||||||||||||||||
| Canadian dollar borrowings | ||||||||||||||||||||||||||||||||
| Senior unsecured notes (e) | 3.68 | % | 2027-2050 | C$ | 1,200,000 | 904,604 | 882,899 | |||||||||||||||||||||||||
| Senior secured project notes | 10.21 | % | 2027 | C$ | 16,848 | 12,738 | 15,024 | |||||||||||||||||||||||||
| Chilean Unidad de Fomento borrowings | ||||||||||||||||||||||||||||||||
| Senior unsecured utility bonds | 3.90 | % | 2028-2040 | CLF | 1,521 | 70,967 | 77,206 | |||||||||||||||||||||||||
| $ | 7,131,107 | $ | 5,855,566 | |||||||||||||||||||||||||||||
| Subordinated borrowings | ||||||||||||||||||||||||||||||||
| Subordinated unsecured notes (f) | 5.25 | % | 2082 | C$ | 400,000 | 298,382 | 291,238 | |||||||||||||||||||||||||
| Subordinated unsecured notes (f) | 5.21 | % | 2079-2082 | $ | 1,100,000 | 1,086,541 | 1,365,213 | |||||||||||||||||||||||||
| $ | 8,516,030 | $ | 7,512,017 | |||||||||||||||||||||||||||||
| Less: current portion | (621,856) | (423,274) | ||||||||||||||||||||||||||||||
| $ | 7,894,174 | $ | 7,088,743 | |||||||||||||||||||||||||||||
Short-term obligations of $766,886 that are expected to be refinanced using the
long-term credit facilities are presented as long-term debt.
Long-term debt issued at a subsidiary level (project notes or utility
bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain
financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.
| Notes to the Consolidated Financial Statements | 107 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
9.Long-term debt (continued)
The following table sets out the bank credit facilities available to
AQN and its operating groups as of December 31, 2023:
| December 31, 2023 | December 31, 2022 | |||||||||||||
| Revolving and term credit facilities | $ | 4,562,000 | $ | 4,513,300 | ||||||||||
|
Funds drawn on facilities/commercial paper issued
|
(2,892,900) | (1,532,500) | ||||||||||||
| Letters of credit issued | (469,100) | (465,200) | ||||||||||||
| Liquidity available under the facilities | 1,200,000 | 2,515,600 | ||||||||||||
| Undrawn portion of uncommitted letter of credit facilities | (254,100) | (226,900) | ||||||||||||
| Cash on hand | 56,142 | 57,623 | ||||||||||||
| Total liquidity and capital reserves | $ | 1,002,042 | $ | 2,346,323 | ||||||||||
Recent financing activities:
(a)Senior unsecured revolving credit facilities
Corporate
On March 31, 2023, the Company's senior unsecured revolving credit
facility was amended and restated to increase the borrowing capacity from $500,000 to $1,000,000 with a new maturity date of March 31, 2028.
On March 31, 2023, the Company entered into a new $75,000 uncommitted
bi-lateral credit facility.
On June 1, 2023, the Company terminated its former $50,000 uncommitted
bi-lateral credit facility.
Regulated Services Group
On October 27, 2023, the Company extended the
maturity date of the senior unsecured revolving credit facility of $500,000 from February 28, 2024 to October 25, 2024.
(b)Senior unsecured bank credit facilities and delayed draw term facilities
On April 25, 2023, the Regulated Services
Group elected to terminate the undrawn amount of $489,600 of its $1,100,000 senior unsecured syndicated delayed draw term facility (the “Regulated Services Delayed Draw Term Facility”), which was intended to be used to partially fund the Kentucky Power Transaction. On October 27, 2023, the Company extended the maturity of the Regulated Services Delayed Draw Term Facility of $610,400 from November 29, 2023 to October 25, 2024.
(c)Senior unsecured notes
On March 13, 2023, the Company repaid a
$15,000 senior unsecured note on its maturity.
On July 31, 2023, the Company repaid a
$75,000 senior unsecured note on its maturity.
Subsequent to year-end, on January 12, 2024,
Liberty Utilities Co., completed an offering of $500,000 aggregate principal amount of 5.577% senior notes due January 31,
2029 (the “2029 Notes”); and $350,000 aggregate principal amount of 5.869% senior notes due January 31, 2034 (the “2034 Notes” and together with the 2029 Notes, the “Senior Notes”). The Senior Notes are unsecured and unsubordinated obligations of
Liberty Utilities Co. and rank equally with all of Liberty Utilities Co.’s existing and future unsecured
and unsubordinated indebtedness and senior in right of payment to any existing and future Liberty Utilities Co.’s subordinated indebtedness. The 2029 Notes were priced at an issue price of 99.996% of their face value and the 2034
Notes were priced at an issue price of 99.995% of their face value. Liberty Utilities Co. used the net proceeds from the sale of the Senior Notes to repay indebtedness.
| Notes to the Consolidated Financial Statements | 108 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
9.Long-term debt (continued)
(d)Senior unsecured utility bonds
Subsequent to the year-end, on January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180,500 of aggregate principal amount
of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125,000 aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred
qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy transition costs related to the retirement of the Asbury generating plant described in note 7.
(e)Senior unsecured utility notes
On November 1, 2023, the Company repaid a
$5,000 senior unsecured utility note on its maturity.
(f)Subordinated unsecured notes
On November 6, 2023, the Company redeemed all
$287,500 of its 6.875% fixed-to-floating subordinated notes - series 2018 - at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.
As of December 31, 2023, the Company has
accrued $74,493 in interest expense (2022 - $70,274). Interest expense for the year ended December 31 consists of the following:
| 2023 | 2022 | ||||||||||
| Long-term debt | $ | 251,539 | $ | 258,084 | |||||||
| Commercial paper, credit facility draws and related fees | 134,678 | 46,466 | |||||||||
| Accretion of fair value adjustments | (23,834) | (16,547) | |||||||||
| Capitalized interest and AFUDC capitalized on regulated property | (14,679) | (10,802) | |||||||||
| Other | 5,952 | 1,373 | |||||||||
| $ | 353,656 | $ | 278,574 | ||||||||
Principal payments due in the next five years
and thereafter are as follows:
| 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total | ||||||||||||||||||||||||||||||||
| $ | 621,856 | $ | 140,241 | $ | 1,193,531 | $ | 1,280,846 | $ | 819,122 | $ | 4,481,961 | $ | 8,537,557 | |||||||||||||||||||||||||
10.Pension and other post-employment benefits
The Company provides defined contribution pension plans to
substantially all of its employees. The Company’s contributions for 2023 were $14,521 (2022 - $12,126).
The Company provides a defined benefit cash balance pension plan under
which employees are credited with a percentage of base pay plus a prescribed interest rate credit. In conjunction with the utility acquisitions, the Company also assumes defined benefit pension, SERP and OPEB plans for qualifying employees in the
related acquired businesses. The legacy plans are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company
permanently freezes the accrual of benefits for participants in legacy plans. Thereafter, employees accrue benefits under the Company’s cash balance plan. The OPEB plans provide health care and life insurance coverage to eligible retired
employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage.
| Notes to the Consolidated Financial Statements | 109 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
10.Pension and other post-employment benefits (continued)
(a)Net pension and OPEB obligation
The following table sets forth the projected benefit obligations, fair value of plan
assets, and funded status of the Company’s plans as of December 31:
| Pension benefits | OPEB | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Change in projected benefit obligation | |||||||||||||||||||||||
| Projected benefit obligation, beginning of year | $ | 628,135 | $ | 765,618 | $ | 217,330 | $ | 292,646 | |||||||||||||||
| Projected benefit obligation assumed from business combination | — | 87,933 | — | 5,195 | |||||||||||||||||||
|
Plan settlements
|
(3,226) | (112) | — | — | |||||||||||||||||||
| Service cost | 11,954 | 16,309 | 3,253 | 6,277 | |||||||||||||||||||
| Interest cost | 33,687 | 24,787 | 11,510 | 9,146 | |||||||||||||||||||
| Actuarial loss (gain) | 20,172 | (198,074) | (10,913) | (82,991) | |||||||||||||||||||
| Contributions from retirees | — | — | 2,189 | 2,220 | |||||||||||||||||||
| Plan amendments | — | — | — | (2,452) | |||||||||||||||||||
| Medicare Part D | — | — | 355 | 367 | |||||||||||||||||||
| Benefits paid | (42,801) | (68,197) | (14,226) | (13,078) | |||||||||||||||||||
| Foreign exchange | (53) | (129) | — | — | |||||||||||||||||||
| Projected benefit obligation, end of year | $ | 647,868 | $ | 628,135 | $ | 209,498 | $ | 217,330 | |||||||||||||||
| Change in plan assets | |||||||||||||||||||||||
| Fair value of plan assets, beginning of year | 569,255 | 648,864 | 172,167 | 192,375 | |||||||||||||||||||
| Plan assets acquired in business combination | — | 74,532 | — | 8,577 | |||||||||||||||||||
| Actual return on plan assets | 65,272 | (109,118) | 22,620 | (30,105) | |||||||||||||||||||
| Employer contributions | 22,326 | 23,296 | 10,677 | 11,811 | |||||||||||||||||||
|
Plan settlements
|
(3,226) | (112) | — | — | |||||||||||||||||||
| Contributions from retirees | — | — | 2,189 | 2,220 | |||||||||||||||||||
| Medicare Part D subsidy receipts | — | — | 355 | 367 | |||||||||||||||||||
| Benefits paid | (42,801) | (68,197) | (14,226) | (13,078) | |||||||||||||||||||
| Foreign exchange | 2 | (10) | — | — | |||||||||||||||||||
| Fair value of plan assets, end of year | $ | 610,828 | $ | 569,255 | $ | 193,782 | $ | 172,167 | |||||||||||||||
| Unfunded status | $ | (37,040) | $ | (58,880) | $ | (15,716) | $ | (45,163) | |||||||||||||||
| Amounts recognized in the consolidated balance sheets consist of: | |||||||||||||||||||||||
| Non-current assets (note 11) | 12,598 | 12,264 | 35,879 | 14,218 | |||||||||||||||||||
| Current liabilities | (1,416) | (1,907) | (3,164) | (3,039) | |||||||||||||||||||
| Non-current liabilities | (48,222) | (69,237) | (48,431) | (56,342) | |||||||||||||||||||
|
Net amount recognized
|
$ | (37,040) | $ | (58,880) | $ | (15,716) | $ | (45,163) | |||||||||||||||
The accumulated benefit obligations for the pension and OPEB plans are $827,559 and
$815,589 as of December 31, 2023 and 2022, respectively.
| Notes to the Consolidated Financial Statements | 110 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
10.Pension and other post-employment benefits (continued)
(a)Net pension and OPEB obligation (continued)
Information for pension and OPEB plans with an accumulated benefit
obligation in excess of plan assets:
| Pension | OPEB | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Accumulated benefit obligation | $ | 425,842 | $ | 413,041 | $ | 71,089 | $ | 198,463 | |||||||||||||||
| Fair value of plan assets | $ | 393,857 | $ | 364,229 | $ | 18,793 | $ | 139,368 | |||||||||||||||
Information for pension and OPEB plans with a projected benefit
obligation in excess of plan assets:
| Pension | OPEB | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Projected benefit obligation | $ | 507,612 | $ | 489,140 | $ | 71,089 | $ | 198,463 | |||||||||||||||
| Fair value of plan assets | $ | 458,497 | $ | 417,994 | $ | 18,793 | $ | 139,368 | |||||||||||||||
(b)Pension and post-employment actuarial changes
| Change in AOCI, before tax | Pension | OPEB | |||||||||||||||||||||
| Actuarial losses (gains) | Past service losses (gains) | Actuarial losses (gains) | Past service losses (gains) | ||||||||||||||||||||
| Balance, January 1, 2022 | $ | 15,807 | $ | (4,195) | $ | (15,630) | $ | 310 | |||||||||||||||
| Additions to AOCI | (47,473) | — | (41,527) | (24) | |||||||||||||||||||
| Amortization in current period | (3,429) | 1,584 | 56 | (2,476) | |||||||||||||||||||
| Amortization due to plan settlements | 15 | — | — | — | |||||||||||||||||||
| Reclassification to regulatory accounts | 34,409 | (752) | 23,551 | — | |||||||||||||||||||
| Balance, December 31, 2022 | $ | (671) | $ | (3,363) | $ | (33,550) | $ | (2,190) | |||||||||||||||
| Additions to AOCI | (12,600) | — | (23,797) | 853 | |||||||||||||||||||
| Amortization in current period | 617 | 1,491 | 2,554 | — | |||||||||||||||||||
| Recognition of settlement gain | 235 | — | — | — | |||||||||||||||||||
| Reclassification to regulatory accounts | 5,517 | (755) | 19,518 | — | |||||||||||||||||||
| Balance, December 31, 2023 | $ | (6,902) | $ | (2,627) | $ | (35,275) | $ | (1,337) | |||||||||||||||
The movements related to pension and OPEB in AOCI for Empire Electric
System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(f)).
| Notes to the Consolidated Financial Statements | 111 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
10.Pension and other post-employment benefits (continued)
(c)Assumptions
Weighted average assumptions used to determine net benefit obligation for 2023 and 2022
were as follows:
| Pension benefits | OPEB | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Discount rate | 5.19 | % | 5.48 | % | 5.22 | % | 5.49 | % | |||||||||||||||
| Interest crediting rate (for cash balance plans) | 4.48 | % | 4.50 | % | N/A | N/A | |||||||||||||||||
| Rate of compensation increase | 3.60 | % | 3.70 | % | N/A | N/A | |||||||||||||||||
| Health care cost trend rate | |||||||||||||||||||||||
| Before age 65 | 7.00 | % | 6.00 | % | |||||||||||||||||||
| Age 65 and after | 6.00 | % | 6.00 | % | |||||||||||||||||||
| Assumed ultimate medical inflation rate | 4.50 | % | 4.75 | % | |||||||||||||||||||
| Year in which ultimate rate is reached | 2034 | 2033 | |||||||||||||||||||||
The mortality assumption for December 31, 2023 uses the Pri-2012 mortality table and
the projected generationally scale MP-2021, adjusted to reflect the ultimate improvement rates in the 2021 Social Security Administration intermediate assumptions for plans in the United States. The mortality assumption for the Bermuda plan as of
December 31, 2023 uses the 2014 Canadian Pensioners' Mortality Table combined with mortality improvement scale CPM-B.
In selecting an assumed discount rate, the Company uses a modelling
process that involves selecting a portfolio of high-quality corporate debt issuances (AA or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers
the results of this modelling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate.
The rate of return assumptions are based on projected long-term market
returns for the various asset classes in which the plans are invested, weighted by the target asset allocations.
Weighted average assumptions used to determine net benefit cost for 2023 and 2022 were as
follows:
| Pension benefits | OPEB | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Discount rate | 5.35 | % | 2.94 | % | 5.49 | % | 3.00 | % | |||||||||||||||
| Expected return on assets | 6.38 | % | 6.19 | % | 6.45 | % | 6.48 | % | |||||||||||||||
| Rate of compensation increase | 3.99 | % | 3.91 | % | n/a | n/a | |||||||||||||||||
| Health care cost trend rate | |||||||||||||||||||||||
| Before Age 65 | 6.00 | % | 5.88 | % | |||||||||||||||||||
| Age 65 and after | 6.00 | % | 5.88 | % | |||||||||||||||||||
| Assumed ultimate medical inflation rate | 4.75 | % | 4.75 | % | |||||||||||||||||||
| Year in which ultimate rate is reached | 2033 | 2031 | |||||||||||||||||||||
| Notes to the Consolidated Financial Statements | 112 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
10.Pension and other post-employment benefits (continued)
(d)Benefit costs
The following table lists the components of net benefit cost for the
pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of Pension and other post-employment non-service costs in the consolidated statements of operations. The employee benefit
costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition.
| Pension benefits | OPEB | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Service cost | $ | 11,954 | $ | 16,309 | $ | 3,253 | $ | 6,277 | |||||||||||||||
| Non-service costs | |||||||||||||||||||||||
| Interest cost | 33,687 | 24,787 | 11,510 | 9,146 | |||||||||||||||||||
| Expected return on plan assets | (31,990) | (41,226) | (9,736) | (11,359) | |||||||||||||||||||
| Amortization of net actuarial loss | (852) | 3,452 | (3,559) | (56) | |||||||||||||||||||
| Amortization of prior service credits | (1,491) | (1,584) | (853) | 24 | |||||||||||||||||||
| Amortization due to plan settlements | — | (15) | — | — | |||||||||||||||||||
| Amortization of regulatory accounts | 16,258 | 22,952 | 6,965 | 4,829 | |||||||||||||||||||
| $ | 15,612 | $ | 8,366 | $ | 4,327 | $ | 2,584 | ||||||||||||||||
| Net benefit cost | $ | 27,566 | $ | 24,675 | $ | 7,580 | $ | 8,861 | |||||||||||||||
(e)Plan assets
The Company’s investment strategy for its pension and post-employment
plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due.
The Company’s target asset allocation is as follows:
| Asset class | Target (%) | Range (%) | ||||||||||||
| Equity securities | 41.6 | % |
30% - 100%
|
|||||||||||
| Debt securities | 48.6 | % |
20% - 60%
|
|||||||||||
| Other | 9.8 | % |
0% - 20%
|
|||||||||||
| 100 | % | |||||||||||||
The fair values of investments as of December 31, 2023, by asset category, are as follows:
| Asset class | 2023 | Percentage | ||||||||||||||||||
| Equity securities | $ | 376,158 | 47 | % | ||||||||||||||||
| Debt securities | 377,272 | 47 | % | |||||||||||||||||
| Other | 51,180 | 6 | % | |||||||||||||||||
| $ | 804,610 | 100 | % | |||||||||||||||||
As of December 31, 2023, the plan assets do not include any material investments in AQN.
| Notes to the Consolidated Financial Statements | 113 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
10.Pension and other post-employment benefits (continued)
(e)Plan assets (continued)
All investments as of December 31, 2023 are valued using Level 1
inputs except for $26,381 of institutional private equity investments using Level 3 fair value measurement. These private equity funds invest in the private equity secondary market and in the credit markets. These funds are not traded in the open
market, and are valued based on the underlying securities within the funds. The underlying securities are valued at fair value by the fund managers by using securities exchange quotations, pricing services, obtaining broker-dealer quotations,
reflecting valuations provided in the most recent financial reports, or at a good faith estimate using fair market value principles.
The following table summarizes the changes fair value of these Level 3 assets as of
December 31:
| Level 3 | ||||||||||||||
| Balance, January 1, 2023 | $ | 21,904 | ||||||||||||
| Contributions into funds | 4,603 | |||||||||||||
| Return on assets | 2,205 | |||||||||||||
| Distributions | (2,331) | |||||||||||||
| Balance, December 31, 2023 | $ | 26,381 | ||||||||||||
(f)Cash flows
The Company expects to contribute $23,248 to its pension plans and
$3,583 to its post-employment benefit plans in 2024.
The expected benefit payments over the next ten years are as follows:
| 2024 | 2025 | 2026 | 2027 | 2028 | 2029-2033 | ||||||||||||||||||||||||||||||
| Pension plan | $ | 48,271 | $ | 49,652 | $ | 49,389 | $ | 50,443 | $ | 50,751 | $ | 255,465 | |||||||||||||||||||||||
| OPEB | $ | 11,718 | $ | 12,303 | $ | 12,623 | $ | 13,105 | $ | 13,487 | $ | 71,230 | |||||||||||||||||||||||
11.Other assets
Other assets consist of the following:
| 2023 | 2022 | ||||||||||
| Restricted cash | $ | 19,997 | $ | 43,562 | |||||||
| Pension and OPEB plan assets (note 10(a)) | 48,477 | 26,482 | |||||||||
| Long-term deposits and cash collateral | 19,336 | 22,537 | |||||||||
| Income taxes recoverable | 9,988 | 7,100 | |||||||||
| Deferred financing costs (a) | 27,176 | 28,586 | |||||||||
|
Insurance recoveries (note 22(a))
|
66,000 | — | |||||||||
| Other (b) | 31,080 | 21,596 | |||||||||
| $ | 222,054 | $ | 149,863 | ||||||||
| Less: current portion | (23,061) | (22,564) | |||||||||
| $ | 198,993 | $ | 127,299 | ||||||||
(a)Deferred financing costs
Deferred financing costs represent costs of arranging the Company’s
revolving credit facilities and intercompany loans as well as the portion of transactions costs related to the Green Equity Units that will be recorded against the common shares when issued.
| Notes to the Consolidated Financial Statements | 114 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
11.Other assets (continued)
(b)Other
Other includes various deferred charges that are expected to be
transferred to utility plant upon reaching certain milestones as well as prepaid long-term service contracts.
12.Other long-term liabilities
Other long-term liabilities consist of the following:
| 2023 | 2022 | ||||||||||
| Contract adjustment payments (a) | $ | 39,590 | $ | 113,876 | |||||||
| Asset retirement obligations (b) | 115,611 | 116,584 | |||||||||
| Advances in aid of construction (c) | 88,135 | 88,546 | |||||||||
| Environmental remediation obligation (d) | 40,772 | 42,457 | |||||||||
| Customer deposits (e) | 36,294 | 34,675 | |||||||||
| Unamortized investment tax credits (f) | 17,255 | 17,649 | |||||||||
| Deferred credits and contingent consideration (g) | 40,945 | 39,498 | |||||||||
| Preferred shares, Series C (h) | — | 12,072 | |||||||||
|
Hook-up fees (i)
|
7,425 | 32,463 | |||||||||
|
Lease liabilities
|
20,493 | 21,834 | |||||||||
| Contingent development support obligations (j) | 12,666 | 8,824 | |||||||||
| Note payable to related party (k) | 25,808 | 25,808 | |||||||||
|
Contingent liability (note 22(a))
|
66,000 | — | |||||||||
| Other | 35,338 | 41,156 | |||||||||
| $ | 546,332 | $ | 595,442 | ||||||||
| Less: current portion | (80,458) | (134,212) | |||||||||
| $ | 465,874 | $ | 461,230 | ||||||||
(a)Contract adjustment payment
In June 2021, the Company sold 23,000,000 Green Equity Units for total
gross proceeds of $1,150,000. Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The present value of
the contract adjustment payments was estimated at $222,378 and recorded in other liabilities. The contract adjustment payments amount is accreted over the three-year period.
(b)Asset retirement obligations
Asset retirement obligations mainly relate to
legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and polychlorinated biphenyls (“PCB”) contaminants) and cap natural gas
mains within the natural gas distribution and transmission system when mains are retired in place, or sections of natural gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste
contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants; (vi) remove asbestos upon major renovation or demolition of structures and facilities; and (vii)
decommission and restore power generation engines and related facilities.
| Notes to the Consolidated Financial Statements | 115 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
12.Other long-term liabilities (continued)
(b)Asset retirement obligations (continued)
Changes in the asset retirement obligations are as follows:
| 2023 | 2022 | ||||||||||
| Opening balance | $ | 116,584 | $ | 142,147 | |||||||
| Obligation assumed | 1,077 | 793 | |||||||||
| Retirement activities | (6,902) | (27,980) | |||||||||
| Accretion | 4,440 | 4,589 | |||||||||
| Change in cash flow estimates | 412 | (2,965) | |||||||||
| Closing balance | $ | 115,611 | $ | 116,584 | |||||||
As the cost of retirement of utility assets in the United States is
expected to be recovered through rates, a corresponding regulatory asset is recorded for liability accretion and asset depreciation expense (note 7(j)).
(c)Advances in aid of construction
The Company’s regulated utilities have various agreements with real
estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.
In many instances, developer advances can be subject to refund, but
the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the
prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property,
plant and equipment. In 2023, $238 (2022 - $1,299) was transferred from advances in aid of construction to contributions in aid of construction.
(d)Environmental remediation obligation
A number of the Company’s regulated utilities were named as
potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of manufactured natural gas plants (“MGP”) and related facilities. The Company is
currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites.
The Company estimates the remaining undiscounted, unescalated cost of
the environmental cleanup activities will be $46,187 (2022 - $48,346), which at discount rates ranging from 3.4% to 4.3% represents the recorded accrual of $40,772 as of December 31, 2023 (2022 - $42,457). Approximately
$25,713 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 27 years.
Changes in the environmental remediation obligation are as follows:
| 2023 | 2022 | ||||||||||
| Opening balance | $ | 42,457 | $ | 55,224 | |||||||
| Remediation activities | (3,687) | (5,243) | |||||||||
| Accretion | 1,616 | 2,167 | |||||||||
| Changes in cash flow estimates | 1,395 | 1,344 | |||||||||
| Revision in assumptions | (1,009) | (11,035) | |||||||||
| Closing balance | $ | 40,772 | $ | 42,457 | |||||||
The Regulators for the New England Gas System and Energy North Gas
System provide for the recovery of actual expenditures for site investigation and remediation over a period of seven years and, accordingly, as of December 31,
2023, the Company has reflected a regulatory asset of $66,779 (2022 - $70,529) for the MGP and related sites (note 7(g)).
| Notes to the Consolidated Financial Statements | 116 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
12.Other long-term liabilities (continued)
(e)Customer deposits
Customer deposits result from the Company’s obligation by Regulators
to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.
(f)Unamortized investment tax credits
The unamortized investment tax credits were assumed in connection with
the acquisition of the Empire Electric System. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station.
(g)Deferred credits and contingent consideration
Deferred credits and contingent consideration include unresolved
contingent consideration related to prior acquisitions which is expected to be paid.
(h)Preferred shares, Series C
During the year ended December 31, 2023, 100 Series
C preferred shares of AQN that had previously been issued in exchange for 100 Class B limited partnership units of St. Leon Wind Energy LP, were redeemed for $14,515, and a loss on settlement of $2,377 was recorded in other net losses (note
19(f)) in the consolidated statements of operations. As a result of the redemption, no Series C preferred shares of AQN remain outstanding.
(i)Hook-up fees
Hook-up fees result from the collection from customers of funds for
installation and connection to the utility’s infrastructure. The fees are refundable as allowed under the facilities’ regulatory agreement.
(j)Contingent development support obligations
The Company provides credit support necessary for the continued
development and construction of its equity investees’ wind and solar power electric development projects and infrastructure development projects. The contingent development support obligations represent the fair value of the support provided
(note 8(c)).
(k)Note payable to related party
In 2021, a subsidiary of the Company made a tax equity investment into
New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project. Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were
distributed to the Company and in return the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC. The promissory note bears an interest rate of 4% annually and has a maturity date of December 16, 2031.
13.Shareholders’ capital
(a)Common shares
Number of common shares
| 2023 | 2022 | |||||||||||||
| Common shares, beginning of year | 683,614,803 | 671,960,276 | ||||||||||||
| Public offering | — | 2,861,709 | ||||||||||||
| Dividend reinvestment plan | 4,370,289 | 7,676,666 | ||||||||||||
| Exercise of share-based awards (c) | 1,284,532 | 1,115,398 | ||||||||||||
| Conversion of convertible debentures | 1,415 | 754 | ||||||||||||
| Common shares, end of year | 689,271,039 | 683,614,803 | ||||||||||||
| Notes to the Consolidated Financial Statements | 117 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
13.Shareholders’ capital (continued)
(a) Common shares (continued)
Authorized
AQN is authorized to issue an unlimited number of common shares. The
holders of the common shares are entitled to dividends if, as and when declared by the board of directors of AQN (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of
AQN to receive pro rata the remaining property and assets of AQN, subject to the rights of any shares having priority over the common shares.
The Company has a shareholders’ rights plan (the “Rights Plan”), which
expires in 2025. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or
group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50
percent discount from the then-current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan.
(i)At-the-market equity program
On August 15, 2022, AQN re-established its at-the-market equity
program (“ATM Program”) that allowed the Company to issue up to $500,000 (or the equivalent in Canadian dollars) of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price when
issued on the Toronto Stock Exchange (“TSX”), the New York Stock Exchange (“NYSE”) or any other existing trading market for the common shares of the Company in Canada or the United States.
During the year ended December 31, 2023, the Company did not issue any
common shares under its ATM Program. The ATM Program terminated in accordance with its terms on December 19, 2023.
The Company has issued, since the inception of its initial ATM Program
in 2019, a cumulative total of 36,814,536 common shares at an average price of $15.00 per share for gross proceeds of $551,086 ($544,295 net of commissions). Other related costs, primarily related to the establishment and subsequent
re-establishments of the ATM program, were $4,843.
(ii)Dividend reinvestment plan
The Company has a common shareholder dividend reinvestment plan,
which, when the plan is active, provides an opportunity for holders of AQN’s common shares who reside in Canada, the United States, or, subject to AQN’s consent, other jurisdictions, to reinvest the cash dividends paid on their common shares in
additional common shares which, at AQN’s election, are either purchased on the open market or newly issued from treasury. Effective March 3, 2022, common shares purchased under the plan were issued at a 3% discount (previously at 5%) to the
prevailing market price (as determined in accordance with the terms of the plan). Effective March 16, 2023, AQN suspended the dividend reinvestment plan. Effective for the first quarter 2023 dividend (paid on April 14, 2023 to shareholders of
record on March 31, 2023), shareholders participating in the dividend reinvestment plan began receiving cash dividends. If the Company elects to reinstate the dividend reinvestment plan in the future, shareholders who were enrolled in the
dividend reinvestment plan at its suspension and remain enrolled at reinstatement will automatically resume participation in the dividend reinvestment plan.
(b)Preferred shares
AQN is authorized to issue an unlimited number of preferred shares,
issuable in one or more series, containing terms and conditions as approved by the Board.
| Notes to the Consolidated Financial Statements | 118 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
13.Shareholders’ capital (continued)
The Company has the following Cumulative Rate Reset Preferred Shares,
Series A (the “Series A Shares”) and Cumulative Rate Reset Preferred Shares, Series D (the “Series D Shares”) issued and outstanding as of December 31, 2023 and 2022:
|
|
Number of shares | Price per share | Carrying amount C$ | Carrying amount $ | |||||||||||||||||||
|
Series A Shares
|
4,800,000 | C$25.00 | C$ | 116,546 | $ | 100,463 | |||||||||||||||||
|
Series D Shares
|
4,000,000 | C$25.00 | C$ | 97,259 | $ | 83,836 | |||||||||||||||||
| $ | 184,299 | ||||||||||||||||||||||
The holders of Series A Shares are entitled to receive quarterly fixed cumulative
preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2023 was an annual amount of C$1.2905 per share. The dividend rate for the five-year period from, and including
December 31, 2023 but excluding December 31, 2028 will be an annual amount of C$1.6440 per share. The Series A Shares dividend rate will
reset on December 31, 2028 and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The Series A Shares were redeemable at C$25 per share at the option of the Company on December 31, 2023
and are redeemable every fifth year thereafter. The holders of Series A Shares have the right to convert their shares into cumulative floating rate preferred shares, Series B, subject to certain conditions, on December 31, 2028 (or the next
business day, if such day is not a business day), and every fifth year thereafter.
The holders of Series D Shares are entitled to receive fixed
cumulative preferential dividends as and when declared by the Board at an annual amount of C$1.2728 per share for each year up to, but excluding, March 31, 2024. The Series D Share dividend will reset on March 31, 2024 and every five years
thereafter at a rate equal to the then five-year Government of Canada bond plus 3.28%. The Series D Shares are redeemable at C$25 per share at the option of the Company on March 31, 2024 (or the next business day, if such day is not a business
day) and every fifth year thereafter. Accordingly, the Series D Shares are redeemable by the Company on April 1, 2024, but the Company has elected not to exercise its redemption right. The holders of Series D Shares have the right to convert
their shares into cumulative floating rate preferred shares, Series E, subject to certain conditions, on March 31, 2024 (or the next business day, if such day is not a business day), and every fifth year thereafter.
(c)Share-based compensation
For the year ended December 31, 2023, AQN recorded $11,293 (2022 -
$10,920) in total share-based compensation expense as follows:
| 2023 | 2022 | ||||||||||
| Share options | $ | 1,325 | $ | 980 | |||||||
| Director deferred share units | 949 | 960 | |||||||||
| Employee share purchase | 897 | 562 | |||||||||
| Performance and restricted share units | 8,122 | 8,418 | |||||||||
| Total share-based compensation | $ | 11,293 | $ | 10,920 | |||||||
The compensation expense is recorded within operating expenses in the
consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As of December 31, 2023, total unrecognized compensation costs related
to non-vested share-based awards are $23,883 and are expected to be recognized over a period of 1.8 years.
(i)Share option plan
The Company’s share option plan (the “Plan”) permits the grant of
share options to officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are
granted.
| Notes to the Consolidated Financial Statements | 119 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
13.Shareholders’ capital (continued)
(c)Share-based compensation (continued)
(i)Share option plan (continued)
The number of shares subject to each option, the option price, the
expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board (or the compensation committee of the Board (“Compensation Committee”)) from time to time. Dividends on the underlying shares do
not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options that is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount”
represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or common shares at the election of the Company. As the Company does
not expect to settle these instruments in cash, these options are accounted for as equity awards.
The Compensation Committee may accelerate the vesting of the unvested
options then held by the optionee at the Compensation Committee's discretion. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Compensation Committee in
accordance with the terms of the Company’s clawback policy.
The estimated fair value of options, including the effect of estimated
forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date.
The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the
grant date. Expected volatility was estimated based on the historical volatility of the Company’s common shares. The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on AQN
common shares.
The following assumptions were used in determining the fair value of share options
granted:
| 2023 | 2022 | ||||||||||
| Risk-free interest rate | 3.4 | % | 1.9 | % | |||||||
| Expected volatility | 27 | % | 23 | % | |||||||
| Expected dividend yield | 8.6 | % | 4.3 | % | |||||||
| Expected life | 5.50 years | 5.50 years | |||||||||
| Weighted average grant date fair value per option | $ | 1.04 | $ | 2.44 | |||||||
Share option activity during the years is as follows:
| Number of awards |
Weighted average exercise price |
Weighted average remaining contractual term (years) |
Aggregate intrinsic value |
||||||||||||||||||||
| Balance, January 1, 2022 | 2,040,528 | C$ | 15.45 | 6.11 | C$ | 3,145 | |||||||||||||||||
| Granted | 646,090 | 19.11 | 7.22 | — | |||||||||||||||||||
| Exercised | (40,074) | 13.92 | 5.95 | 103 | |||||||||||||||||||
| Forfeited | (19,764) | 19.11 | — | — | |||||||||||||||||||
| Balance, December 31, 2022 | 2,626,780 | C$ | 16.02 | 5.63 | C$ | — | |||||||||||||||||
| Granted | 1,368,744 | 10.76 | 7.24 | — | |||||||||||||||||||
| Exercised | — | — | — | — | |||||||||||||||||||
| Forfeited | (1,327,799) | 16.55 | — | — | |||||||||||||||||||
| Balance, December 31, 2023 | 2,667,725 | C$ | 14.71 | 5.18 | C$ | — | |||||||||||||||||
| Exercisable, December 31, 2023 | 2,621,420 | C$ | 17.11 | 4.50 | C$ | — | |||||||||||||||||
| Notes to the Consolidated Financial Statements | 120 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
13.Shareholders’ capital (continued)
(c)Share-based compensation (continued)
(ii)Employee share purchase plan
Under the Company’s ESPP, eligible employees may have a portion of
their earnings withheld to be used to purchase the Company’s common shares. The Company will match 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution
amount for contributions over five thousand dollars up to ten thousand dollars annually. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the purchase
date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the
TSX or NYSE by an independent broker. The aggregate number of common shares reserved for issuance from treasury by AQN under the ESPP shall not exceed 4,000,000 common shares.
The Company uses the fair value based method to measure the
compensation expense related to the Company’s contribution. For the year ended December 31, 2023, a total of 752,582 common shares (2022 - 414,338) were issued to employees under the ESPP.
(iii)Director’s deferred share units
Under the Company’s DSU plan, non-employee directors of the Company
may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU
has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or
otherwise leaves the Board. The DSUs provide for settlement in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. For the
year ended December 31, 2023, a total of 181,328 DSUs (2022 - 120,513) were issued and 102,460 DSUs (2022 - 5,176) were settled in exchange for 50,677 common shares issued from treasury, and 51,783 DSUs were settled at their cash value as payment
for tax withholding related to the settlement of the awards. As of December 31, 2023, 724,583 (2022 - 645,714) DSUs are outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The
aggregate number of common shares reserved for issuance from treasury by AQN under the DSU plan shall not exceed 1,000,000 common shares.
(iv)Performance and restricted share units
The Company offers a PSU and RSU plan to its employees as part of the
Company’s long-term incentive program. PSUs have been granted annually for three-year overlapping performance cycles. The PSUs vest at the end of the three-year cycle and are calculated based on established performance criteria. At the end of the
three-year performance periods, the number of common shares issued can range from 2.5% to 237% of the number of PSUs granted. RSU vesting conditions and dates vary by grant and are outlined in each award letter. RSUs are not subject to
performance criteria. Dividends accumulating during the vesting period are converted to PSUs and RSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of the PSUs or RSUs have
voting rights. Any PSUs or RSUs not vested at the end of a performance period will expire. The PSUs and RSUs provide for settlement in cash or common shares at the election of the Company. As the Company does not expect to settle these
instruments in cash, these units are accounted for as equity awards. The aggregate number of common shares reserved for issuance from treasury by AQN under the PSU and RSU plan shall not exceed 7,000,000 common shares.
Compensation expense associated with PSUs is recognized ratably over
the performance period. Achievement of the performance criteria is estimated as at the consolidated balance sheet dates. Compensation cost recognized is adjusted to reflect the performance conditions estimated to date.
| Notes to the Consolidated Financial Statements | 121 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
13.Shareholders’ capital (continued)
(c)Share-based compensation (continued)
(iv)Performance and restricted share units (continued)
A summary of the PSUs and RSUs follows:
| Number of awards | Weighted average grant-date fair value |
Weighted average remaining contractual term (years) |
Aggregate intrinsic value |
||||||||||||||||||||
| Balance, January 1, 2022 | 2,443,672 | C$ | 18.07 | 1.72 | C$ | 44,646 | |||||||||||||||||
| Granted, including dividends | 1,090,457 | 17.99 | 2.00 | 17,524 | |||||||||||||||||||
| Exercised | (1,221,620) | 12.62 | — | 23,636 | |||||||||||||||||||
| Forfeited | (202,799) | 18.94 | — | 418 | |||||||||||||||||||
| Balance, December 31, 2022 | 2,109,710 | C$ | 18.38 | 1.76 | C$ | 18,608 | |||||||||||||||||
| Granted, including dividends | 2,841,967 | 10.98 | 2.02 | 25,329 | |||||||||||||||||||
| Exercised | (922,883) | 18.73 | — | 10,125 | |||||||||||||||||||
| Forfeited | (451,047) | 15.07 | — | 3,771 | |||||||||||||||||||
| Balance, December 31, 2023 | 3,577,747 | C$ | 18.38 | 1.76 | C$ | 29,910 | |||||||||||||||||
| Exercisable, December 31, 2023 | 597,363 | C$ | 19.98 | 0.22 | C$ | 4,994 | |||||||||||||||||
(v)Bonus deferral RSUs
Eligible employees have the option to receive a portion or all of
their annual bonus payment in RSUs in lieu of cash. These RSUs provide for settlement in shares, and therefore these RSUs are accounted for as equity awards. The RSUs granted are 100% vested and, therefore, compensation expense associated with
these RSUs is recognized immediately upon issuance.
During the year ended December, 31, 2023, 77,981 (2022 - 55,445) bonus
deferral RSUs were granted to employees of the Company. In addition, the Company settled 69,115 (2022 - 178,368) bonus deferral RSUs in exchange for 31,455 (2022 - 82,886) common shares issued from treasury, and 37,660 (2022- 95,482) RSUs were
settled at their cash value as payment for tax withholdings related to the settlement of the RSUs. As of December 31, 2023, 167,352 (2022 - 158,486) bonus deferral RSUs are outstanding.
| Notes to the Consolidated Financial Statements | 122 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
14.Accumulated other comprehensive income (loss)
AOCI consists of the following balances, net of tax:
| Foreign currency cumulative translation | Unrealized gain on cash flow hedges | Pension and post-employment actuarial changes | Total | ||||||||||||||||||||
| Balance, January 1, 2022 | $ | (76,615) | $ | (3,514) | $ | 8,452 | $ | (71,677) | |||||||||||||||
| Other comprehensive income (loss) | (18,013) | (128,838) | 23,722 | (123,129) | |||||||||||||||||||
| Amounts reclassified from AOCI to the consolidated statement of operations | (5,489) | 34,543 | 4,039 | 33,093 | |||||||||||||||||||
| Net current period OCI | $ | (23,502) | $ | (94,295) | $ | 27,761 | $ | (90,036) | |||||||||||||||
| OCI attributable to the non-controlling interests | 1,650 | — | — | 1,650 | |||||||||||||||||||
| Net current period OCI attributable to shareholders of AQN | $ | (21,852) | $ | (94,295) | $ | 27,761 | $ | (88,386) | |||||||||||||||
| Balance, December 31, 2022 | $ | (98,467) | $ | (97,809) | $ | 36,213 | $ | (160,063) | |||||||||||||||
| Other comprehensive income (loss) | (3,788) | 57,351 | 8,395 | 61,958 | |||||||||||||||||||
| Amounts reclassified from AOCI to the consolidated statement of operations | (1,598) | 2,136 | (3,702) | (3,164) | |||||||||||||||||||
| Net current period OCI | $ | (5,386) | $ | 59,487 | $ | 4,693 | $ | 58,794 | |||||||||||||||
| OCI attributable to the non-controlling interests | (1,017) | — | — | (1,017) | |||||||||||||||||||
| Net current period OCI attributable to shareholders of AQN | $ | (6,403) | $ | 59,487 | $ | 4,693 | $ | 57,777 | |||||||||||||||
| Balance, December 31, 2023 | $ | (104,870) | $ | (38,322) | $ | 40,906 | $ | (102,286) | |||||||||||||||
Amounts reclassified from AOCI for foreign currency cumulative translation affected
interest expense and derivative gain (loss); those for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales, interest expense and derivative gain (loss) while those for pension and post-employment actuarial
changes affected pension and post-employment non-service costs.
15.Dividends
All dividends of the Company are made on a discretionary basis as
determined by the Board. The Company declares and pays the dividends on its common shares in U.S. dollars. Dividends declared were as follows:
| 2023 | 2022 | ||||||||||||||||||||||
| Dividend | Dividend per share | Dividend | Dividend per share | ||||||||||||||||||||
| Common shares | $ | 301,771 | $ | 0.4340 | $ | 486,043 | $ | 0.7130 | |||||||||||||||
|
Series A Shares
|
C$ | 6,194 | C$ | 1.2905 | C$ | 6,194 | C$ | 1.2905 | |||||||||||||||
|
Series D Shares
|
C$ | 5,091 | C$ | 1.2728 | C$ | 5,091 | C$ | 1.2728 | |||||||||||||||
| Notes to the Consolidated Financial Statements | 123 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
16.Related party transactions
(a)Equity-method investments
The Company provides administrative and development services to its
equity-method investees and is reimbursed for incurred costs. To that effect, during 2023, the Company charged its equity-method investees $34,733 (2022 - $38,215) for administrative services and $37,802 (2022 - $25,645) for development services.
Additionally, Liberty Development JV Inc. (note 8(c)), an equity-method investee of the Company that is the Company’s joint venture with funds managed by the Infrastructure and Power strategy of Ares Management, LLC for its non-regulated
development platform, provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones. During the year, the development fees charged to the Company were $27,933 (2022 -
$12,628).
Subsequent to year-end, on January 4, 2024, the Company purchased
Ares’ 50% interest in Liberty Development JV Inc. and Liberty Development Energy Solutions B.V.
Investments in and acquisitions of equity-method investments are
described in note 8(c).
(b)Non-controlling interest and redeemable non-controlling interest held by related party
Non-controlling interest and redeemable non-controlling interest held
by related party are described in note 17(c).
(c) Transactions with Atlantica
On December 28, 2023, Liberty Development Spain, S.A., a wholly owned
subsidiary of the Company entered into an agreement to sell its 100% equity interests in Liberty Jimena, S.L. and Liberty Caparacena, S.L., and its 80% equity interest in Liberty Infrastructuras, S.L. to Atlantica for a nominal amount. As a
result, the Company recorded an impairment loss of $1,481, included in asset impairment charge in the consolidated statements of operations. The transaction closed on January 23, 2024.
The above related party transactions have been recorded at the
exchange amounts agreed to by the parties to the transactions.
17.Non-controlling interests and redeemable non-controlling interests
Net effect attributable to non-controlling interests for the years ended December 31
consists of the following:
| 2023 | 2022 | |||||||||||||
| HLBV and other adjustments attributable to: | ||||||||||||||
| Non-controlling interests - tax equity partnership units | $ | 114,141 | $ | 108,695 | ||||||||||
| Non-controlling interests - redeemable tax equity partnership units | 1,324 | 6,298 | ||||||||||||
| Other net earnings attributable to: | ||||||||||||||
| Non-controlling interests | (27,564) | (3,670) | ||||||||||||
| $ | 87,901 | $ | 111,323 | |||||||||||
| Redeemable non-controlling interest, held by related party | (25,922) | (15,157) | ||||||||||||
|
Net effect of non-controlling interests
|
$ | 61,979 | $ | 96,166 | ||||||||||
The non-controlling tax equity investors (“tax equity partnership units”) in the
Company's U.S. wind power and solar power-generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings (loss) attributable to the non-controlling
interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(s).
| Notes to the Consolidated Financial Statements | 124 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
17.Non-controlling interests and redeemable non-controlling interests (continued)
Non-controlling interests
| Non-controlling interests - tax equity partnership units (a) | Other non-controlling interests (b) | Non-controlling interests held by related parties (c) | |||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||
| Opening balance | $ | 1,225,608 | $ | 1,377,117 | $ | 333,362 | $ | 64,807 | $ | 57,822 | $ | 81,158 | |||||||||||||||||||||||
|
Net earnings (loss) attributable to NCI
|
(114,141) | (108,695) | 27,564 | 3,670 | — | — | |||||||||||||||||||||||||||||
| Contributions received, net | 107,933 | 6,182 | — | 267,515 | — | — | |||||||||||||||||||||||||||||
| Dividends and distributions declared | (22,743) | (36,736) | (14,497) | (3,350) | (17,082) | (20,978) | |||||||||||||||||||||||||||||
| Repurchase of non-controlling interest | — | (12,249) | — | — | — | — | |||||||||||||||||||||||||||||
| OCI | 63 | (11) | 909 | 720 | 45 | (2,358) | |||||||||||||||||||||||||||||
| Closing balance | $ | 1,196,720 | $ | 1,225,608 | $ | 347,338 | $ | 333,362 | $ | 40,785 | $ | 57,822 | |||||||||||||||||||||||
(a) Non-controlling interests -
tax equity partnership units
The Company obtained control of the Deerfield II
Wind Facility during the year (note 3). Post-acquisition, third-party tax equity investors funded $98,955 in exchange for Class A partnership units in the entity. In addition, the Company received $9,084 (2022 - $6,182) of production based cash
contributions during the year relating to other projects.
(b) Other non-controlling
interests
On December 29, 2022, the
Company sold a 49% non-controlling interest in three operating wind facilities in the United States totalling 551 MW of
installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois. The consideration of $277,500 was recorded as an increase to non-controlling interest, except for a portion of $5,000, which is
subject to refund if some conditions are met and as such was recorded as redeemable non-controlling interest.
(c) Non-controlling interest
held by related parties
In November 2021, Liberty Development JV Inc. invested $39,376 in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company. In May 2019, AYES Canada acquired an interest in a consolidated subsidiary of the Company for $96,752
(C$130,103) (note 8(b)). The investment by AYES Canada and Liberty Development JV Inc. are presented as a non-controlling interest held by related parties.
| Notes to the Consolidated Financial Statements | 125 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
17.Non-controlling interests and redeemable non-controlling interests (continued)
Redeemable non-controlling
interests
Non-controlling interests in subsidiaries that are redeemable upon the
occurrence of uncertain events not solely within AQN’s control are classified as temporary equity on the consolidated balance sheets. If the redemption is probable or currently redeemable, the Company records the instruments at their redemption
value. Redemption is not considered probable as of December 31, 2023.
Liberty Global Energy Solutions (note 8(c)), an equity investee of the
Company, has a secured credit facility in the amount of $306,500 with a previous maturity date of January 26, 2024. Subsequent to year-end, on January 8, 2024, the secured credit facility was renewed with a maturity date of September 30, 2024. It
is collateralized through a pledge of Atlantica ordinary shares held by AY Holdings. A collateral shortfall would occur if the net obligation (as defined in the credit agreement) would equal or exceed 50% of the market value of such Atlantica
shares, in which case the lenders would have the right to sell Atlantica shares to eliminate the collateral shortfall. The Liberty Global Energy Solutions secured credit facility is repayable on demand if Atlantica ceases to be a public company
or if certain other events are announced or completed that could restrict AY Holdings’ ability to sell or transfer its Atlantica ordinary shares. Liberty Global Energy Solutions has a preference share ownership in AY Holdings which AQN reflects
as redeemable non-controlling interest held by related party.
As a result of the subsequent event described in note 8(c), the
redeemable non-controlling interest held by related party will be reclassified to long-term debt in 2024.
Changes in redeemable non-controlling interests are as follows:
| Redeemable non-controlling interests held by related party | Redeemable non-controlling interests | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Opening balance | $ | 307,856 | $ | 306,537 | $ | 11,520 | $ | 12,989 | |||||||||||||||
|
Net earnings (loss) attributable to NCI
|
25,922 | 15,157 | (1,324) | (6,298) | |||||||||||||||||||
| Contributions, net of costs | — | — | — | 5,000 | |||||||||||||||||||
| Dividends and distributions declared | (25,428) | (13,838) | (183) | (171) | |||||||||||||||||||
| Closing balance | $ | 308,350 | $ | 307,856 | $ | 10,013 | $ | 11,520 | |||||||||||||||
18.Income taxes
The provision for income taxes in the consolidated statements of
operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2022 - 26.5%). The differences are as follows:
| 2023 | 2022 | ||||||||||
|
Expected income tax recovery at Canadian statutory rate
|
$ | (31,696) | $ | (97,962) | |||||||
| Increase (decrease) resulting from: | |||||||||||
| Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates | (46,628) | (55,315) | |||||||||
| Adjustments from investments carried at fair value | 16,128 | 51,314 | |||||||||
| Non-controlling interests share of income | 24,677 | 30,025 | |||||||||
| Change in valuation allowance | 10,786 | 41,702 | |||||||||
| Acquisition related state deferred tax adjustments | — | 5,998 | |||||||||
| Capital gain rate differential on disposal of renewable assets | — | (7,340) | |||||||||
| Tax credits | (54,788) | (18,440) | |||||||||
| Amortization and settlement of excess deferred income tax | (12,785) | (14,855) | |||||||||
| Deferred income taxes on regulated income recorded as regulatory assets | (878) | (1,986) | |||||||||
| Other permanent differences | 5,341 | 4,591 | |||||||||
| Other | 3,543 | 755 | |||||||||
| Income tax recovery | $ | (86,300) | $ | (61,513) | |||||||
| Notes to the Consolidated Financial Statements | 126 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
18.Income taxes (continued)
On December 27, 2023, the government of Bermuda enacted the Bermuda
Corporate Income Tax Act 2023, setting a 15% corporate income tax rate effective for fiscal years commencing January 1, 2025. The Bermuda Corporate Income Tax Act 2023 includes various transition adjustments that may affect the recognition of
deferred taxes and as such were considered as part of the initial measurement in the period that includes the December 2023 enactment date. No deferred taxes were required to be recognized as at December 31, 2023.
For the years ended December 31, 2023 and 2022, earnings (loss) before
income taxes consist of the following:
| 2023 | 2022 | ||||||||||
|
Canada (1)
|
$ | (259,141) | $ | (363,050) | |||||||
| U.S. | 102,469 | (37,322) | |||||||||
| Other regions | 37,067 | 30,704 | |||||||||
| $ | (119,605) | $ | (369,668) | ||||||||
(1) Inclusive of
fair value gain (loss) on investments carried at fair value (note 8)
Income tax expense (recovery) attributable to income (loss) consists of:
| Current | Deferred | Total | |||||||||||||||
|
Year ended December 31, 2023
|
|||||||||||||||||
| Canada | $ | 4,352 | $ | (59,488) | $ | (55,136) | |||||||||||
| United States | (14,820) | (23,099) | (37,919) | ||||||||||||||
| Other regions | 728 | 6,027 | 6,755 | ||||||||||||||
| $ | (9,740) | $ | (76,560) | $ | (86,300) | ||||||||||||
|
Year ended December 31, 2022
|
|||||||||||||||||
| Canada | $ | 4,184 | $ | (74,595) | $ | (70,411) | |||||||||||
| United States | 1,579 | 6,183 | 7,762 | ||||||||||||||
| Other regions | 2,080 | (944) | 1,136 | ||||||||||||||
| $ | 7,843 | $ | (69,356) | $ | (61,513) | ||||||||||||
| Notes to the Consolidated Financial Statements | 127 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
18.Income taxes (continued)
The tax effect of temporary differences between the consolidated
financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2023 and 2022 are presented below:
| 2023 | 2022 | ||||||||||
| Deferred tax assets: | |||||||||||
| Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs | $ | 1,030,801 | $ | 878,000 | |||||||
| Pension and OPEB | 7,370 | 16,845 | |||||||||
| Environmental obligation | 11,692 | 12,118 | |||||||||
| Regulatory liabilities | 180,371 | 156,285 | |||||||||
| Other | 72,109 | 61,917 | |||||||||
| Total deferred income tax assets | $ | 1,302,343 | $ | 1,125,165 | |||||||
| Less: valuation allowance | (97,344) | (107,583) | |||||||||
| Total deferred tax assets | $ | 1,204,999 | $ | 1,017,582 | |||||||
| Deferred tax liabilities: | |||||||||||
| Property, plant and equipment | $ | 883,447 | $ | 846,331 | |||||||
| Outside basis differentials | 364,511 | 315,581 | |||||||||
| Regulatory accounts | 317,820 | 303,059 | |||||||||
| Other | 59,640 | 33,834 | |||||||||
| Total deferred tax liabilities | $ | 1,625,418 | $ | 1,498,805 | |||||||
| Net deferred tax liabilities | $ | (420,419) | $ | (481,223) | |||||||
| Consolidated balance sheets classification: | |||||||||||
| Deferred tax assets | $ | 158,483 | $ | 84,416 | |||||||
| Deferred tax liabilities | (578,902) | (565,639) | |||||||||
| Net deferred tax liabilities | $ | (420,419) | $ | (481,223) | |||||||
The valuation allowance for deferred tax assets as of December 31,
2023 was $97,344 (2022 - $107,583). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized for the Renewable Energy Group.
The U.S. entities in the Renewable Energy Group continue to be in an
overall deferred tax asset position as at December 31, 2023. In the course of assessing the U.S. deferred tax assets in the Renewable Energy Group, management concluded, similar to 2022, that it was not probable that the U.S. business of the
Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group (with the exception of certain transferable tax credits). Management’s conclusion is based on the balance of all
available positive and negative evidence applicable to the Renewable Energy Group. The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income during the
carryforward period are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as management projections for growth.
The Company’s overall deferred tax asset position related to Canadian
attributes increased from $83,434 to $151,759 for the year ended December 31, 2023, primarily due to ongoing interest and financing expenses attributable to the Canadian entities and the decrease in the value of the Company’s investment in
Atlantica. As at December 31, 2023, it is considered more likely than not that there will be sufficient taxable income in the future that will allow realization of these deferred tax assets. The Company considered all evidence, both positive and
negative, including the announcement of the sale of the renewable energy business, the availability of tax planning strategies, and the carryforward period of its Canadian net operating losses in making this assessment. The Company will continue
to monitor this position at each balance sheet date.
| Notes to the Consolidated Financial Statements | 128 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
18.Income taxes (continued)
The following table illustrates the annual movement in the deferred
tax valuation allowance:
| 2023 | 2022 | ||||||||||
| Beginning balance | $ | 107,583 | $ | 27,471 | |||||||
|
Charged to income tax expense
|
10,786 | 41,702 | |||||||||
| Charged (reduction) to OCI | (16,696) | 40,613 | |||||||||
| Reductions to other accounts | (4,329) | (2,203) | |||||||||
| Ending balance | $ | 97,344 | $ | 107,583 | |||||||
As of December 31, 2023, the Company had non-capital losses carried
forward and tax credits available to reduce future years' taxable income, which expire as follows:
| Non-capital loss carryforward and credits | 2024—2028 | 2029+ | Total | ||||||||
| Canada | $ | 3,339 | $ | 913,781 | $ | 917,120 | |||||
| US | 8,441 | 1,897,609 | 1,906,050 | ||||||||
| Total non-capital loss carryforward | $ | 11,780 | $ | 2,811,390 | $ | 2,823,170 | |||||
| Tax credits | $ | 3,359 | $ | 200,772 | $ | 204,131 | |||||
The Company has provided for deferred income taxes for the estimated tax cost of
distributed earnings of certain of its subsidiaries. Deferred income taxes have not been provided on approximately $908,449 of undistributed earnings of certain
foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance
of such undistributed earnings is not practicable.
19.Other net losses
Other net losses consist of the following:
| 2023 | 2022 | |||||||||||||
| Acquisition and transition-related costs | $ | — | $ | 6,834 | ||||||||||
|
Kentucky termination costs (a)
|
46,527 | 10,608 | ||||||||||||
|
Acquisition-related settlement payment (b)
|
(11,983) | — | ||||||||||||
|
Securitization write-off (c)
|
63,495 | — | ||||||||||||
| Renewable energy business sale costs (d) | 12,506 | — | ||||||||||||
|
Loss on redemption of long-term note (e)
|
8,532 | — | ||||||||||||
|
Other (f)
|
13,812 | 3,949 | ||||||||||||
| $ | 132,889 | $ | 21,391 | |||||||||||
(a)Kentucky termination costs
The loss related to the termination of the Kentucky Power Transaction
includes $38,795 for the write-off of capitalized costs, which are primarily related to the implementation of an enterprise software solution. The remaining amount relates to the transaction costs, severance costs and other termination costs. In
2022, the Company incurred $10,608 in anticipation of the Kentucky Power Transaction.
(b)Acquisition-related settlement payment
During the year, the Company received $12,814 as an
acquisition-related settlement payment in connection with the Suralis acquisition. The Company also incurred legal fees of $831 in relation to this settlement.
| Notes to the Consolidated Financial Statements | 129 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
19.Other net losses (continued)
(c)Securitization write-off
During the year, the Company has written off $63,495 relating to the
portion of additional securitization costs of Empire Electric that were not allowed as per the Securitization Statute (note 7(a)).
(d)Renewable energy business sale costs
The Company announced that it is pursuing a sale of its renewable
energy business. The Company incurred costs of $12,506 related to this process in 2023.
(e)Loss on redemption of long-term note
During Q4, 2023, the Company redeemed subordinated unsecured long-term
note (note 9(f)) and incurred loss on redemption of $8,532.
(f)Other
Other losses for the year consist primarily of provisions on
litigation matters, executive severance costs, the Series C preferred share redemption loss and other miscellaneous write-offs.
20.Basic and diluted net earnings (loss) per share
Basic and diluted earnings (loss) per share have
been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and bonus deferral restricted share units outstanding. Diluted net earnings per share is computed
using the weighted average number of common shares, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs, RSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares
related to the convertible debentures or resulting from the application of the treasury stock method to outstanding share options and Green Equity Units (note 9(c)).
The reconciliation of the net earnings (loss) and the weighted average
shares used in the computation of basic and diluted earnings (loss) per share are as follows:
| 2023 | 2022 | |||||||||||||
| Net earnings (loss) attributable to shareholders of AQN | $ | 28,674 | $ | (211,989) | ||||||||||
| Preferred shares, Series A dividend | 4,586 | 4,786 | ||||||||||||
| Preferred shares, Series D dividend | 3,770 | 3,934 | ||||||||||||
| Net earnings (loss) attributable to common shareholders of AQN – basic and diluted | $ | 20,318 | $ | (220,709) | ||||||||||
| Weighted average number of shares | ||||||||||||||
| Basic | 688,738,717 | 677,862,207 | ||||||||||||
| Effect of dilutive securities | 2,024,509 | — | ||||||||||||
| Diluted | 690,763,226 | 677,862,207 | ||||||||||||
This calculation of diluted shares excludes the potential impact of
the Green Equity Units and 5,699,593 potential incremental shares that may become issuable pursuant to outstanding securities of the Company for the year ended December 31, 2023, as they are anti-dilutive. This calculation of diluted shares for
the year ended December 31, 2022 excludes all potential incremental shares that may become issuable pursuant to outstanding securities of the Company as they are anti-dilutive.
| Notes to the Consolidated Financial Statements | 130 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
21.Segmented information
The Company is managed under two primary business units consisting of
the Regulated Services Group and the Renewable Energy Group. The two business units are the two segments of the Company.
The Regulated Services Group, the Company’s regulated operating unit,
owns and operates a portfolio of electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; the Renewable Energy Group, the Company’s
non-regulated operating unit, owns and operates, or has investments in, a diversified portfolio of renewable and thermal energy generation assets.
For purposes of evaluating the performance of the business units, the
Company allocates the realized portion of any gains or losses on financial instruments to the specific business units. Dividend income from Atlantica and AYES Canada are included in the operations of the Renewable Energy Group, while interest
income from SAWS is included in the operations of the Regulated Services Group. Equity method gains and losses are included in the operations of the Regulated Services Group or Renewable Energy Group based on the nature of the activities of the
investees. The change in value of investments carried at fair value and unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship are not considered in management’s evaluation of divisional
performance and are therefore allocated and reported under corporate.
|
Year ended December 31, 2023
|
|||||||||||||||||||||||
| Regulated Services Group | Renewable Energy Group | Corporate | Total | ||||||||||||||||||||
|
Revenue (1)(2)
|
$ | 2,315,722 | $ | 296,314 | $ | — | $ | 2,612,036 | |||||||||||||||
| Other revenue | 51,137 | 33,395 | 1,447 | 85,979 | |||||||||||||||||||
| Fuel, power and water purchased | 716,446 | 19,499 | — | 735,945 | |||||||||||||||||||
| Net revenue | 1,650,413 | 310,210 | 1,447 | 1,962,070 | |||||||||||||||||||
| Operating expenses | 786,608 | 119,013 | 1,364 | 906,985 | |||||||||||||||||||
| Administrative expenses | 46,386 | 36,554 | 7,419 | 90,359 | |||||||||||||||||||
| Depreciation and amortization | 346,188 | 119,576 | 1,232 | 466,996 | |||||||||||||||||||
|
Asset impairment charge
|
— | 23,492 | — | 23,492 | |||||||||||||||||||
| Loss on foreign exchange | — | — | 8,359 | 8,359 | |||||||||||||||||||
| Operating income (loss) | 471,231 | 11,575 | (16,927) | 465,879 | |||||||||||||||||||
| Interest expense | (160,998) | (61,261) | (131,397) | (353,656) | |||||||||||||||||||
| Income (loss) from long-term investments | 44,953 | 102,188 | (230,705) | (83,564) | |||||||||||||||||||
| Other expenses | (121,146) | (4,002) | (23,116) | (148,264) | |||||||||||||||||||
| Earnings (loss) before income taxes | $ | 234,040 | $ | 48,500 | $ | (402,145) | $ | (119,605) | |||||||||||||||
| Property, plant and equipment | $ | 8,945,637 | $ | 3,539,069 | $ | 32,744 | $ | 12,517,450 | |||||||||||||||
| Investments carried at fair value | 1,962 | 1,113,767 | — | 1,115,729 | |||||||||||||||||||
| Equity-method investees | 112,180 | 343,712 | 501 | 456,393 | |||||||||||||||||||
| Total assets | 12,658,955 | 5,367,011 | 347,995 | 18,373,961 | |||||||||||||||||||
| Capital expenditures | $ | 816,788 | $ | 209,383 | $ | — | $ | 1,026,171 | |||||||||||||||
(1) Renewable
Energy Group revenue includes $5,695 related to net hedging gain from energy derivative contracts and availability credits for the year ended December 31, 2023 that do not represent revenue recognized from contracts with customers.
(2) Regulated Services Group revenue includes $32,839 related to alternative revenue programs for the year ended December 31, 2023 that do not
represent revenue recognized from contracts with customers.
| Notes to the Consolidated Financial Statements | 131 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
21.Segmented information (continued)
|
Year ended December 31, 2022
|
|||||||||||||||||||||||
| Regulated Services Group | Renewable Energy Group | Corporate | Total | ||||||||||||||||||||
|
Revenue (1)(2)
|
$ | 2,330,039 | $ | 350,797 | $ | — | $ | 2,680,836 | |||||||||||||||
| Other revenue | 54,229 | 28,447 | 1,501 | 84,177 | |||||||||||||||||||
| Fuel and power purchased | 824,670 | 41,684 | — | 866,354 | |||||||||||||||||||
| Net revenue | 1,559,598 | 337,560 | 1,501 | 1,898,659 | |||||||||||||||||||
| Operating expenses | 736,515 | 114,463 | 511 | 851,489 | |||||||||||||||||||
| Administrative expenses | 46,484 | 26,424 | 7,324 | 80,232 | |||||||||||||||||||
| Depreciation and amortization | 317,300 | 137,203 | 1,017 | 455,520 | |||||||||||||||||||
|
Asset impairment charge
|
— | 159,568 | — | 159,568 | |||||||||||||||||||
| Loss on foreign exchange | — | — | 13,833 | 13,833 | |||||||||||||||||||
| 459,299 | (100,098) | (21,184) | 338,017 | ||||||||||||||||||||
| Gain on sale of renewable assets | — | 64,028 | — | 64,028 | |||||||||||||||||||
| Operating income (loss) | 459,299 | (36,070) | (21,184) | 402,045 | |||||||||||||||||||
| Interest expense | (113,482) | (64,285) | (100,807) | (278,574) | |||||||||||||||||||
| Income (loss) from long-term investments | 21,884 | 15,254 | (502,344) | (465,206) | |||||||||||||||||||
| Other expenses | (14,765) | (570) | (12,598) | (27,933) | |||||||||||||||||||
| Earnings (loss) before income taxes | $ | 352,936 | $ | (85,671) | $ | (636,933) | $ | (369,668) | |||||||||||||||
| Property, plant and equipment | $ | 8,554,938 | $ | 3,360,687 | $ | 29,260 | $ | 11,944,885 | |||||||||||||||
| Investments carried at fair value | 1,984 | 1,342,223 | — | 1,344,207 | |||||||||||||||||||
| Equity-method investees | 56,199 | 310,103 | 15,500 | 381,802 | |||||||||||||||||||
| Total assets | 12,109,575 | 5,251,933 | 266,105 | 17,627,613 | |||||||||||||||||||
| Capital expenditures | $ | 908,676 | $ | 180,348 | $ | — | $ | 1,089,024 | |||||||||||||||
(1) Renewable
Energy Group revenue includes $63,717 related to net hedging loss from energy derivative contracts for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.
(2) Regulated Services Group revenue includes $21,640 related to alternative revenue programs for the year ended December 31, 2022 that do not
represent revenue recognized from contracts with customers.
The majority of non-regulated energy sales are earned from contracts
with large public utilities. The Company has sought to mitigate its credit risk by selling energy to large utilities in various North American locations. None of the utilities contribute more than 10% of total revenue.
| Notes to the Consolidated Financial Statements | 132 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
21.Segmented information (continued)
AQN operates in the independent power and utility industries in the
United States, Canada and other regions. Information on operations by geographic area is as follows:
| 2023 | 2022 | |||||||||||||
| Revenue | ||||||||||||||
| United States | $ | 2,169,239 | $ | 2,232,817 | ||||||||||
| Canada | 162,740 | 175,005 | ||||||||||||
| Other regions | 366,036 | 357,191 | ||||||||||||
| $ | 2,698,015 | $ | 2,765,013 | |||||||||||
| Property, plant and equipment | ||||||||||||||
| United States | $ | 10,826,738 | $ | 10,351,736 | ||||||||||
| Canada | 924,389 | 848,560 | ||||||||||||
| Other regions | 766,323 | 744,589 | ||||||||||||
| $ | 12,517,450 | $ | 11,944,885 | |||||||||||
| Intangible assets | ||||||||||||||
| United States | $ | 18,666 | $ | 18,818 | ||||||||||
| Canada | 18,111 | 19,038 | ||||||||||||
| Other regions | 57,161 | 58,827 | ||||||||||||
| $ | 93,938 | $ | 96,683 | |||||||||||
Revenue is attributed to the regions based on the location of the underlying generating and utility
facilities.
22.Commitments and contingencies
(a)Contingencies
AQN and its subsidiaries are involved in various claims and litigation
arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider AQN’s exposure to such litigation to be material to these consolidated financial statements.
Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.
Mountain View fire
On November 17, 2020, a wildfire now known as the Mountain View Fire
occurred in the territory of Liberty Utilities (CalPeco Electric) LLC (“Liberty CalPeco”). The cause of the fire remains under investigation, and CAL FIRE has not yet released its final report. There are currently 21 active lawsuits that name
certain subsidiaries of the Company as defendants in connection with the Mountain View Fire, as well as one non-litigation claim brought by the U.S. Department of Agriculture seeking reimbursement for alleged fire suppression costs. Fourteen
lawsuits are brought by groups of individual plaintiffs alleging causes of action including negligence, inverse condemnation, nuisance, trespass, and violations of Cal. Pub. Util. Code 2106 and Cal. Health and Safety Code 13007 (one of these 14
lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). On March 6, 2024, a trial commenced in Los Angeles County Superior Court on four bellwether cases with respect to inverse
condemnation liability only. If the Company’s subsidiaries were found liable in those cases, the damages, if any, would not be determined at this trial. In another lawsuit, County of Mono, Antelope Valley Fire Protection District and Bridgeport
Indian Colony allege similar causes of action and seek damages for fire suppression costs, law enforcement costs, property and infrastructure damage, and other costs. In six other lawsuits, insurance companies allege inverse condemnation and
negligence and seek recovery of amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits is uncertain.
| Notes to the Consolidated Financial Statements | 133 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
22.Commitments and contingencies (continued)
(a)Contingencies (continued)
In 2023, Liberty CalPeco accrued estimated losses of $66,000 for
claims related to the Mountain View Fire, against which Liberty CalPeco has recorded expected recoveries from insurance of $66,000. The resulting net charge to earnings was $nil. The estimate of losses is subject to change as additional
information becomes available. The actual amount of losses may be higher or lower than these estimates. While the Company may incur a material loss in excess of the amount accrued, the Company cannot estimate the upper end of the range of
reasonably possible losses that may be incurred. The Company has wildfire liability insurance that is expected to apply up to applicable policy limits.
(b)Commitments
In addition to the commitments related to the development projects
disclosed in note 8, the following significant commitments exist as of December 31, 2023.
AQN has outstanding purchase commitments for power purchases, natural
gas supply and service agreements, service agreements, capital project commitments, land easements and other commitments.
Detailed below are estimates of future commitments under these
arrangements:
| Year 1 | Year 2 | Year 3 | Year 4 | Year 5 | Thereafter | Total | |||||||||||||||||
| Power purchase (1) | $ | 55,312 | $ | 33,869 | $ | 12,274 | $ | 12,520 | $ | 12,768 | $ | 129,818 | $ | 256,561 | |||||||||
| Natural gas supply and service agreements (2) | 121,188 | 71,949 | 42,643 | 33,215 | 30,803 | 154,757 | 454,555 | ||||||||||||||||
| Service agreements | 73,687 | 61,889 | 56,591 | 53,140 | 52,898 | 259,510 | 557,715 | ||||||||||||||||
| Capital projects | 5,598 | — | — | — | — | — | 5,598 | ||||||||||||||||
| Land easements and other | 16,437 | 15,057 | 15,269 | 15,425 | 15,639 | 536,129 | 613,956 | ||||||||||||||||
| Total | $ | 272,222 | $ | 182,764 | $ | 126,777 | $ | 114,300 | $ | 112,108 | $ | 1,080,214 | $ | 1,888,385 | |||||||||
(1) Power purchase: AQN’s electric distribution facilities have
commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2023. However, the effects of purchased power unit cost
adjustments are mitigated through a purchased power rate-adjustment mechanism.
(2) Natural gas supply and service agreements: AQN’s natural gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of
natural gas under contracts for purposes of load serving requirements and of generating power.
| Notes to the Consolidated Financial Statements | 134 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
23.Non-cash operating items
The changes in non-cash operating items consist of the following:
| 2023 | 2022 | |||||||||||||
| Accounts receivable | $ | 3,863 | $ | (124,631) | ||||||||||
| Fuel and natural gas in storage | 46,368 | (21,140) | ||||||||||||
| Supplies and consumables inventory | (48,539) | (24,088) | ||||||||||||
| Income taxes recoverable | (2,889) | 549 | ||||||||||||
| Prepaid expenses | (13,218) | (4,269) | ||||||||||||
| Accounts payable | 23,847 | 24,395 | ||||||||||||
| Accrued liabilities | (488) | 127,076 | ||||||||||||
| Current income tax liability | 1,096 | (2,741) | ||||||||||||
| Asset retirements and environmental obligations | (1,015) | (22,342) | ||||||||||||
| Net regulatory assets and liabilities | (95,361) | (174,427) | ||||||||||||
| $ | (86,336) | $ | (221,618) | |||||||||||
| Notes to the Consolidated Financial Statements | 135 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments
(a)Fair value of financial instruments
| December 31, 2023 | Carrying amount |
Fair value |
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||
| Long-term investments carried at fair value | $ | 1,115,729 | $ | 1,115,729 | $ | 1,054,665 | $ | — | $ | 61,064 | |||||||||||||||||||
| Development loans and other receivables | 158,110 | 155,735 | — | 155,735 | — | ||||||||||||||||||||||||
| Derivative instruments: | |||||||||||||||||||||||||||||
| Interest rate swap designated as a hedge | 72,936 | 72,936 | — | 72,936 | — | ||||||||||||||||||||||||
| Interest rate cap not designated as a hedge | 1,854 | 1,854 | — | 1,854 | — | ||||||||||||||||||||||||
| Congestion revenue rights not designated as a cash flow hedge | 8,458 | 8,458 | — | — | 8,458 | ||||||||||||||||||||||||
| Total derivative instruments | 83,248 | 83,248 | — | 74,790 | 8,458 | ||||||||||||||||||||||||
| Total financial assets | $ | 1,357,087 | $ | 1,354,712 | $ | 1,054,665 | $ | 230,525 | $ | 69,522 | |||||||||||||||||||
| Long-term debt | $ | 8,516,030 | $ | 7,423,318 | $ | 2,532,608 | $ | 4,890,710 | $ | — | |||||||||||||||||||
| Notes payable to related party | 25,808 | 15,320 | — | 15,320 | — | ||||||||||||||||||||||||
| Convertible debentures | 230 | 276 | 276 | — | — | ||||||||||||||||||||||||
| Derivative instruments: | |||||||||||||||||||||||||||||
| Energy contracts designated as a cash flow hedge | 68,070 | 68,070 | — | — | 68,070 | ||||||||||||||||||||||||
| Energy contracts not designated as a cash flow hedge | 5,593 | 5,593 | — | — | 5,593 | ||||||||||||||||||||||||
| Cross-currency swap designated as a net investment hedge | 10,533 | 10,533 | — | 10,533 | — | ||||||||||||||||||||||||
| Currency forward contract designated as hedge | 6,779 | 6,779 | — | 6,779 | — | ||||||||||||||||||||||||
| Interest rate swaps designated as a hedge | 11,790 | 11,790 | — | 11,790 | — | ||||||||||||||||||||||||
| Cross currency swap designated as a cash flow hedge | 5,547 | 5,547 | — | 5,547 | — | ||||||||||||||||||||||||
| Commodity contracts for regulated operations | 2,564 | 2,564 | — | 2,564 | — | ||||||||||||||||||||||||
| Total derivative instruments | 110,876 | 110,876 | — | 37,213 | 73,663 | ||||||||||||||||||||||||
| Total financial liabilities | $ | 8,652,944 | $ | 7,549,790 | $ | 2,532,884 | $ | 4,943,243 | $ | 73,663 | |||||||||||||||||||
| Notes to the Consolidated Financial Statements | 136 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments (continued)
(a)Fair value of financial instruments (continued)
| December 31, 2022 | Carrying amount |
Fair value |
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||
| Long-term investment carried at fair value | $ | 1,344,207 | $ | 1,344,221 | $ | 1,270,138 | $ | — | $ | 74,083 | |||||||||||||||||||
| Development loans and other receivables | 53,680 | 50,300 | — | 50,300 | — | ||||||||||||||||||||||||
| Derivative instruments: | |||||||||||||||||||||||||||||
| Energy contracts not designated as a cash flow hedge | 393 | 393 | — | — | 393 | ||||||||||||||||||||||||
| Interest rate swap designated as a hedge | 69,188 | 69,188 | — | 69,188 | — | ||||||||||||||||||||||||
| Currency forward contract not designated as a hedge | 2,659 | 2,659 | — | 2,659 | — | ||||||||||||||||||||||||
|
Congestion revenue
rights not designated as
a cash flow hedge
|
10,110 | 10,110 | — | — | 10,110 | ||||||||||||||||||||||||
| Cross-currency swap designated as a net investment hedge | 1,267 | 1,267 | — | 1,267 | — | ||||||||||||||||||||||||
| Commodity contracts for regulated operations | 283 | 283 | — | 283 | — | ||||||||||||||||||||||||
| Total derivative instruments | 83,900 | 83,900 | — | 73,397 | 10,503 | ||||||||||||||||||||||||
| Total financial assets | $ | 1,481,787 | $ | 1,478,421 | $ | 1,270,138 | $ | 123,697 | $ | 84,586 | |||||||||||||||||||
| Long-term debt | $ | 7,512,017 | $ | 6,699,031 | $ | 2,623,628 | $ | 4,075,403 | $ | — | |||||||||||||||||||
| Notes payable to related party | 25,808 | 15,180 | — | 15,180 | — | ||||||||||||||||||||||||
| Convertible debentures | 245 | 276 | 276 | — | — | ||||||||||||||||||||||||
| Preferred shares, Series C | 12,072 | 11,675 | — | 11,675 | — | ||||||||||||||||||||||||
| Derivative instruments: | |||||||||||||||||||||||||||||
| Energy contracts designated as a cash flow hedge | 120,284 | 120,284 | — | — | 120,284 | ||||||||||||||||||||||||
| Energy contracts not designated as a cash flow hedge | 8,617 | 8,617 | — | — | 8,617 | ||||||||||||||||||||||||
| Cross-currency swap designated as a net investment hedge | 24,371 | 24,371 | — | 24,371 | — | ||||||||||||||||||||||||
| Cross-currency swap designated as a cash flow hedge | 15,435 | 15,435 | — | 15,435 | — | ||||||||||||||||||||||||
| Commodity contracts for regulated operations | 1,614 | 1,614 | — | 1,614 | — | ||||||||||||||||||||||||
| Total derivative instruments | 170,321 | 170,321 | — | 41,420 | 128,901 | ||||||||||||||||||||||||
| Total financial liabilities | $ | 7,720,463 | $ | 6,896,483 | $ | 2,623,904 | $ | 4,143,678 | $ | 128,901 | |||||||||||||||||||
The Company has determined that the carrying value of its short-term
financial assets and liabilities approximates fair value as of December 31, 2023 and 2022 due to the short-term maturity of these
instruments.
| Notes to the Consolidated Financial Statements | 137 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments (continued)
(a)Fair value of financial instruments (continued)
The fair value of the investment in Atlantica (Level 1) is measured at
the closing price on the NASDAQ stock exchange.
The fair value of development loans and other receivables (Level 2) is
determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management.
The Company’s Level 1 fair value of long-term debt is measured at the
closing price on the NYSE and the Canadian over-the-counter closing price. The Company’s Level 2 fair value of long-term debt at fixed interest rates and notes payable to related party have been determined using a discounted cash flow method and
current interest rates. The Company’s Level 2 fair value of convertible debentures has been determined as the greater of their face value and the quoted value of AQN’s common shares on a converted basis.
The Company’s Level
2 fair value derivative instruments primarily consist of swaps, options, rights, caps, subscription agreements and forward physical derivatives where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various
market indices and utilize discounting based on quoted interest rate curves, which are observable in the marketplace.
The Company’s Level 3 instruments consist of energy contracts for
electricity sales, congestion revenue rights (“CRRs”) and the fair value of the Company’s
investment in AYES Canada. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $26.32 to $144.02 with a weighted average of $38.44 as of December 31, 2023. The weighted average forward market
prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of CRRs are recent CRR auction prices ranging from $nil to $$52.02 with a weighted
average of $5.69 as of December 31, 2023. The fair value of the investment in AYES Canada is determined using a discounted cash flow approach combined with a binomial tree approach. The significant unobservable inputs used in the fair value
measurement of the Company’s AYES Canada investment are the expected cash flows, the discount rates
applied to these cash flows ranging from 8.00% to 8.50% with a weighted average of 8.27%, and the expected volatility of Atlantica’s share price ranging from 27.47% to 33.19% as of December 31, 2023. Significant increases
(decreases) in expected cash flows or increases (decreases) in discount rate in isolation would have resulted in a significantly lower (higher) fair value measurement.
(b)Derivative instruments
Derivative instruments are recognized on the consolidated balance
sheets as either assets or liabilities and measured at fair value at each reporting period.
(i)Commodity derivatives – regulated accounting
The Company uses derivative financial instruments to reduce the cash
flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated natural gas and electric service territories. The Company’s strategy is to minimize fluctuations in natural gas sale
prices to regulated customers. As at December 31, 2023, the commodity volume, in dekatherms, associated with the above derivative contracts is 2,117,039.
| Notes to the Consolidated Financial Statements | 138 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments (continued)
(b)Derivative instruments (continued)
(i)Commodity derivatives – regulated accounting (continued)
The accounting for these derivative instruments is subject to guidance for
rate-regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance
sheets. Most of the gains or losses on the settlement of these contracts are included in the calculation of the fuel and commodity costs adjustments (note 7(a)). As a result, the changes in fair value
of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact.
(ii)Cash flow hedges
The Company reduces the price risk on the expected future sale of
power generation by entering into the following long-term energy derivative contracts.
| Notional quantity (MW-hrs) |
Expiry | Receive average prices (per MW-hr) |
Pay floating price (per MW-hr) |
|||||||||||||||||
| 353,597 | December 2028 | $29.19 | PJM Western HUB | |||||||||||||||||
| 1,492,926 | December 2027 | $21.34 | NI HUB | |||||||||||||||||
| 1,332,645 | December 2027 | $36.46 | ERCOT North HUB | |||||||||||||||||
| 3,534,802 | September 2030 | $24.54 | Illinois Hub | |||||||||||||||||
The Company mitigates the risk that interest rates will
increase over the life of certain term loan facilities by entering into the following interest rate swap contracts. For an
interest rate swap or cross-currency interest rate swap designated as hedging the exposure to variable cash flows of a future transaction, the effective portion of this derivative's gain or loss is initially reported as a component of other
comprehensive income (loss) and subsequently reclassified into earnings once the future transaction impacts earnings. Amounts for interest rate contracts are reclassified to earnings as interest expense over the term of the related debt.
| Derivative |
Notional quantity
|
Expiry
|
Hedged item
|
||||||||
|
Forward-starting interest rate swap
|
$ | 350,000 |
July 2029
|
$350,000 subordinated unsecured notes
|
|||||||
|
Cross-currency interest rate swap
|
C$ | 400,000 |
January 2032
|
C$400,000 subordinated unsecured notes
|
|||||||
|
Forward-starting interest rate swap
|
$ | 750,000 |
April 2032
|
$750,000 subordinated unsecured notes
|
|||||||
| Forward-starting interest rate swap | $ | 575,000 | June 2026 |
First $575,000 of the expected $1,150,000 senior unsecured notes issuance
|
|||||||
| Notes to the Consolidated Financial Statements | 139 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments (continued)
(b)Derivative instruments (continued)
(ii)Cash flow hedges (continued)
The following table summarizes OCI attributable to derivative
financial instruments designated as a cash flow hedge:
| 2023 | 2022 | |||||||||||||
| Effective portion of cash flow hedge | $ | 57,351 | $ | (128,838) | ||||||||||
| Amortization of cash flow hedge | (6,173) | (12,180) | ||||||||||||
| Amounts reclassified from AOCI | 8,309 | 46,723 | ||||||||||||
| OCI attributable to shareholders of AQN | $ | 59,487 | $ | (94,295) | ||||||||||
The Company expects $25,895 of unrealized losses currently in AOCI to be
reclassified, net of taxes into non-regulated energy sales, investment loss, interest expense and derivative gains, respectively, within the next 12 months, as the underlying hedged transactions settle.
(iii)Foreign exchange hedge of net investment in foreign operation
The functional currency of most of AQN's operations is the U.S.
dollar. The Company designates obligations denominated in Canadian dollars as a hedge of the foreign currency exposure of its net investment in its Canadian investments and subsidiaries. The related foreign currency transaction gain or loss
designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of$12,330 for the year ended
December 31, 2023 (2022 - gain of $2,262) was recorded in OCI.
On May 23, 2019, the Company entered into a cross-currency swap,
coterminous with the subordinated unsecured notes issued on such date, to effectively convert the $350,000 U.S. dollar-denominated offering into Canadian dollars. The change in the carrying amount of the notes due to changes in spot exchange
rates is recognized each period in the consolidated statements of operations as gain (loss) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign
currency exposure related to cash flows for the interest and principal repayments on the notes. Upon the change in functional currency of AQN to the U.S. dollar on January 1, 2020, this hedge was dedesignated. The OCI related to this hedge will
be amortized into earnings in the period that future interest payments affect earnings over the remaining life of the original hedge. The Company redesignated this swap as a hedge of AQN's net investment in its Canadian subsidiaries.
The related foreign currency transaction gain or loss designated as a
hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. The fair value of the derivative on the redesignation date will be amortized over the
remaining life of the original hedge. A foreign currency gain of $6,976 for the year ended December 31, 2023 (2022 - gain of $22,091) was recorded in OCI.
Canadian operations
The Company is exposed to currency fluctuations from its
Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using Canadian long-term debt to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases.
The Company’s Canadian operations are determined to have the Canadian
dollar as their functional currency and are exposed to currency fluctuations from their U.S. dollar transactions. The Company designates obligations denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in
its U.S. investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in
OCI) related to the net investment. A foreign currency gain of $606 for the year ended December 31, 2023 (2022 - loss of $18,561) was recorded in OCI.
| Notes to the Consolidated Financial Statements | 140 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments (continued)
(b)Derivative instruments (continued)
(iii)Foreign exchange hedge of net investment in foreign operation (continued)
Canadian operations (continued)
The Company is party to C$300,000 (2022 - C$300,000) fixed-for-fixed
cross-currency swaps to effectively convert Canadian dollar debentures into U.S. dollars. In February 2022, the Company settled the cross-currency swap related to its C$200,000 (2021 - C$150,000) debenture that was repaid. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap and related short-term U.S. dollar
payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and
the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI)
related to the net investment. A gain of $5,959 for the year ended December 31, 2023 (2022 - loss of $11,082) was recorded in OCI.
On April 9, 2021, the Renewable Energy Group entered into a
fixed-for-fixed cross-currency interest rate swap, coterminous with the senior unsecured debentures
issued on such date, to effectively convert the C$400,000 Canadian-dollar-denominated offering into U.S. dollars. The Renewable Energy Group designated the entire
notional amount of the fixed-for-fixed cross-currency interest rate swap and related short-term U.S. dollar payables
created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure
of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation
are reported in the same manner as the translation adjustment (in OCI) related to the net investment.
A gain of $8,420 for the year ended December 31, 2023 (2022 - loss of $13,374) was
recorded in OCI.
Chilean operations
The Company is exposed to currency fluctuations from its Chilean-based
operations. The Company's Chilean operations are determined to have the Chilean peso as their functional currency. Chilean long-term debt used to finance the operations is denominated in Chilean Unidad de Fomento.
(iv)Other derivatives and risk management
In the normal course of business, the Company is exposed to financial
risks that potentially impact its operating results. The Company employs risk management strategies with a view to mitigating these risks to the extent possible on a cost-effective basis. Derivative financial instruments are used to manage
certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes. For derivatives that are not designated as hedges, the changes in
the fair value are immediately recognized in earnings (loss).
The Company was party to an interest rate cap agreement in the amount
of $390,000 for the period between January 15, 2023 and January 15, 2024. On September 29, 2023, the Company entered into a new interest rate cap agreement in the amount of $390,000 million for the period between January 15, 2024 and June 17,
2024.
The Company was party to interest rate swaps with a notional quantity
of C$489,506 to mitigate the interest rate risk related to debt at its Blue Hill Wind Facility. The contract was novated upon the sale of the Blue Hill Wind Facility in 2022. A recognized loss of C$9,732 on the derivative was recorded as a
reduction of the gain on sale of renewable assets on the audited consolidated statements of operations.
The Company mitigates the volatility of energy congestion charges at the ERCOT
transmission grid by entering into CRRs, which as of December 31, 2023 had notional quantity of 5,486,961 MW-hours at prices ranging from $0.55 per MW-hr to $24.88 per MW-hr with a weighted average of $5.16 per MW-hr for January 2024 to June
2026. These CRRs are not designated as an accounting hedge.
| Notes to the Consolidated Financial Statements | 141 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments (continued)
(b)Derivative instruments (continued)
(iv)Other derivatives and risk management (continued)
The Company mitigates the price risk on the expected future sale of
power generation of one of its solar facilities through a long-term energy derivative contract with a notional quantity of 516,202 MW-hours, a price of $25.15 per MW-hr and expiring in August 2030 as an economic hedge to the price of energy
sales. The derivative contract is not designated as an accounting hedge.
The effects on the consolidated statements of operations of derivative
financial instruments not designated as hedges consist of the following:
| 2023 | 2022 | |||||||||||||
| Unrealized gain (loss) on derivative financial instruments: | ||||||||||||||
| Energy derivative contracts | $ | (372) | $ | (945) | ||||||||||
| Commodity contracts | 411 | 185 | ||||||||||||
| Total unrealized gain (loss) on derivative financial instruments | $ | 39 | $ | (760) | ||||||||||
| Realized gain (loss) on derivative financial instruments: | ||||||||||||||
| Energy derivative contracts | $ | (4,896) | $ | 6,939 | ||||||||||
| Interest rate swaps | — | (7,185) | ||||||||||||
| Total realized loss on derivative financial instruments | $ | (4,896) | $ | (246) | ||||||||||
| Loss on derivative financial instruments not accounted for as hedges | (4,857) | (1,006) | ||||||||||||
| Amortization of AOCI gains frozen as a result of hedge dedesignation | 3,989 | 3,465 | ||||||||||||
| $ | (868) | $ | 2,459 | |||||||||||
| Consolidated statements of operations classification: | ||||||||||||||
| Gain on derivative financial instruments | $ | 4,564 | $ | 4,408 | ||||||||||
| Renewable energy sales | (5,432) | 5,236 | ||||||||||||
| Reduction to gain on sale of renewable assets | — | (7,185) | ||||||||||||
| $ | (868) | $ | 2,459 | |||||||||||
(c)Supplier financing programs
In the normal course of business, the Company enters into supplier
financing programs under which the suppliers can voluntarily elect to sell their receivables. The Company agrees to pay, on the invoice maturity date, the stated amount of the invoices that the Company has confirmed through the execution of bills
of exchange. The terms of the trade payable arrangement are consistent with customary industry practice and are not impacted by the supplier’s decision to sell amounts under these arrangements.
The roll forwards of the Company's outstanding obligations
confirmed as valid under its supplier finance programs for years ended December 31, 2023 and 2022, are as follows:
| 2023 | 2022 | |||||||||||||
|
Confirmed obligations outstanding at the beginning of the year
|
$ | 16,785 | $ | 49,910 | ||||||||||
| Invoices confirmed during the year | 90,780 | 16,785 | ||||||||||||
| Confirmed invoices paid during the year | (45,392) | (49,910) | ||||||||||||
| Confirmed obligations outstanding at the end of the year | $ | 62,173 | $ | 16,785 | ||||||||||
| Notes to the Consolidated Financial Statements | 142 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments (continued)
(d)Risk management
In addition to the risk management strategies described above, the
Company manages exposure to risks arising from financial instruments, including credit risk and liquidity risk.
Credit risk
Credit risk is the risk of an unexpected loss if a customer or
counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable
and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders, all of which have a credit rating of A or better. The Company does not
consider the risk associated with the accounts receivable to be significant as the majority of revenue from power generation is earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P,
or BBB or higher by DBRS. Revenue is generally invoiced and collected within 45 days.
The remaining revenue is primarily earned by the Regulated Services
Group, which consists of electric, water distribution and wastewater, and natural gas utilities in the United States, Canada, Bermuda and Chile. In this regard, the credit risk related to Regulated Services Group accounts receivable balances of $364,084 is spread over hundreds of thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks
and security deposits from new customers. In addition, most of the Regulators of the Regulated Services Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers.
As of December 31, 2023, the Company’s maximum exposure to credit risk
for these financial instruments is as follows:
| 2023 | |||||||||||||||||
| Cash and cash equivalents and restricted cash | $ | 76,145 | |||||||||||||||
| Accounts receivable | 554,438 | ||||||||||||||||
| Allowance for doubtful accounts | (30,244) | ||||||||||||||||
| Notes receivable | 158,836 | ||||||||||||||||
| $ | 759,175 | ||||||||||||||||
In addition, the Company monitors the creditworthiness of the counterparties to its
foreign exchange, interest rate, and energy derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This
concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counties may be similarly affected by changes in economic, regulatory or other conditions.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet
its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to take steps to ensure, to the extent possible, that it will have sufficient liquidity to meet liabilities when due. As of December 31, 2023, in
addition to cash on hand of $56,147, the Company has $945,853 available to be drawn on its revolving and term credit facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn.
| Notes to the Consolidated Financial Statements | 143 |
| Algonquin Power & Utilities Corp. | ||
| Notes to the Consolidated Financial Statements | ||
|
December 31, 2023 and 2022
|
||
| (in thousands of U.S. dollars, except as noted and per share amounts) | ||
24.Financial instruments (continued)
(d)Risk management (continued)
Liquidity risk (continued)
The Company’s liabilities mature as follows:
| Due less than 1 year |
Due 2 to 3 years |
Due 4 to 5 years |
Due after 5 years |
Total | |||||||||||||||||||||||||
| Long-term debt obligations | $ | 621,856 | $ | 1,333,772 | $ | 2,099,968 | $ | 4,481,961 | $ | 8,537,557 | |||||||||||||||||||
| Interest on long-term debt | 391,493 | 602,761 | 419,950 | 3,496,032 | 4,910,236 | ||||||||||||||||||||||||
| Purchase obligations | 767,287 | — | — | — | 767,287 | ||||||||||||||||||||||||
| Environmental obligation | 3,136 | 22,577 | 1,820 | 18,654 | 46,187 | ||||||||||||||||||||||||
| Advances in aid of construction | 3,640 | — | — | 84,495 | 88,135 | ||||||||||||||||||||||||
| Derivative financial instruments: | |||||||||||||||||||||||||||||
| Cross-currency swap | 2,419 | 4,243 | 144 | 9,623 | 16,429 | ||||||||||||||||||||||||
| Interest rate forwards | 11,790 | — | — | — | 11,790 | ||||||||||||||||||||||||
| Energy derivative and commodity contracts | 14,276 | 29,273 | 20,550 | 12,127 | 76,226 | ||||||||||||||||||||||||
| Contract adjustment payments on Green Equity Units | 39,590 | — | — | — | 39,590 | ||||||||||||||||||||||||
| Other obligations | 27,796 | 2,901 | 2,304 | 247,480 | 280,481 | ||||||||||||||||||||||||
| Total obligations | $ | 1,883,283 | $ | 1,995,527 | $ | 2,544,736 | $ | 8,350,372 | $ | 14,773,918 | |||||||||||||||||||
25.Comparative figures
Certain of the comparative figures have been reclassified to conform
to the consolidated financial statement presentation adopted in the current year.
| Notes to the Consolidated Financial Statements | 144 |
