Utility asset dispositions are a common recurring aspect of utility regulation. In the normal course, utilities invest in assets necessary for the provision of utility service, then these investments are depreciated or amortized over the life of the assets, and in this way the costs of the assets are gradually recovered in utility rates. At the end of an asset’s useful life, the fully depreciated asset is removed from utility service and any ancillary costs, for example costs of removal or retirement net of salvage, are recovered in rates. But what happens when an asset’s useful life is cut short? In this case, the asset is often referred to as a “stranded asset.”

The “used and useful” standard is a foundational principle in Canadian public utility law that restricts cost recovery in rates to assets that are actively serving customers.^[1] In the Canadian regulatory construct, stranded assets are assets that have not yet been fully depreciated but are no longer “used and useful” for the provision of utility service. When this happens, an asset’s remaining unrecovered cost is no longer included in rate base and recovered from customers in the normal course. This raises the issue of how to dispose of the undepreciated balance of the stranded asset; and whether the balance is to the account of the shareholder, and therefore unrecoverable in rates, or to the account of customers and recoverable in rates.

The effects of climate change are renewing debates about the appropriate disposition of stranded assets because climate change is reshaping the operating environment for electric utilities in two ways. First, historical weather patterns are threatening facilities and making resilience a priority for grid planners. Second, regulatory and legislative directives in response to climate risk are placing new demands on utilities. The effects of climate and the resulting energy transition are increasing stranded asset risks. These risks are compounded by the long depreciation horizons of utility infrastructure, creating uncertainty about whether assets will be stranded in future and who will bear the financial burden if assets are destroyed, become underutilized, or are required to retire early.

Assuming a planning horizon that may encompass thirty to forty years, utilities can expect increased physical risks to their facilities, higher operating costs, and increased demands for resilience and decarbonization.^[2] Frequent and intense storms are already increasing the degree of damage to transmission and distribution assets. Wildfire risks are escalating; threatening utility infrastructure and increasing liability exposure for utilities when utility equipment sparks fires. ^[3] A McKinsey study highlights that investments in long-lived assets in risky locations increase balance-sheet exposure. ^[4] The destruction of utility assets due to volatile weather raises questions with respect to who should pay for the continued recovery of asset costs when they are destroyed by weather events.

Utilities are increasingly required to integrate climate risk into planning, undertake justifiable resilience investments, and demonstrate climate adaptation strategies; all while satisfying decarbonization objectives. Stranded asset risk increases when infrastructure built for historical or emerging climate and GHG norms becomes potentially inadequate or unsafe. Who should pay for the undepreciated costs of assets that are no longer required due to a lack of suitability in response to climate risk?

STRANDED ASSET ISSUES

Stranded assets in this emerging environment may chiefly come about in two ways. First, assets may become stranded when they are prematurely destroyed in climate-related events, such as wildfires and tornadoes. In these cases, the assets no longer exist physically, but the undepreciated and therefore unrecovered capital invested in the destroyed assets remains in the utilities’ accounts. Second, facilities and infrastructure may become underutilized, uneconomic, obsolete, or unrecoverable under policy or legislative requirements to address climate risk. In this case, although the assets still physically exist, unrecovered capital invested in the now un-needed or unsuitable assets may no longer be recoverable in rates because the assets are no longer “used and useful” for the provision of utility service.

As climate and the ensuing energy transition increasingly affect utilities in Canada, regulators will need to grapple with several sometimes inter-related issues with respect to the disposition of assets potentially stranded as a result of climate events and climate policy. How can regulation mitigate the costs of stranded assets? How should the costs of stranded assets be calculated when stranding occurs? Who should bear the costs of stranding as a result of climate events or climate policies when they occur? Should stranded asset costs be equitably shared between utility shareholders and utility customers, and if so, how? How should the risk of stranded asset costs be accounted for in utility revenue requirements and rates?

THE CURRENT TREATMENT OF STRANDED ASSETS IN CANADA

The disposition of stranded asset costs in Canadian utility regulation is inconsistent across jurisdictions and occasionally muddled by the influence of government policy on regulators. Ontario and Alberta approaches to the disposition of stranded assets are, for example, quite different.

Assets Stranded by Climate Events

As a point of departure, it is worth considering the approach to the disposition of assets stranded by climate events in the two jurisdictions. Both the Ontario Energy Board (“OEB”) and the Alberta Utilities Commission (“AUC”) include Z factors in their regulatory rate setting frameworks to consider the costs of unforeseen events that are outside of management’s control. Both jurisdictions have similar criteria for what constitutes a Z factor event. Qualifying events include climate events, such as tornadoes and wildfires. However, although both jurisdictions generally allow for the recovery of incremental costs arising from a Z factor event, including allowing replacement assets in rate base, the disposition of the costs of assets stranded by the event has been different in the two provinces.

The Ontario Energy Board Act^[5], at Section 36 and Section 78, gives the Board authority to set just and reasonable rates for gas utilities and electricity distributors and transmitters. The OEB’s approach to considering stranded assets is grounded in the prudence test and, when weather events occur, application of a Z factor. Under the prudence test, if an investment was prudent when it was undertaken then the OEB has generally determined that the utility is entitled to recover both the remaining costs of the assets destroyed and the costs of replacement assets from customers. In this way, Ontario has largely assigned stranded asset liability for unforeseen climate events to utility customers.

The West Coast Huron Energy Inc. decision (EB-2011-0335)^[6] is a seminal case in Ontario. West Coast Huron requested approval to recover the costs caused by a tornado that occurred in August 2011, destroying many of its assets in the town of Goderich. The application requested recovery of the remaining net book value of the assets destroyed. The Board found that a Z-factor event had occurred when the F3 tornado destroyed a significant portion of West Coast Huron’s distribution system and other assets and that the event was genuinely “external to the regulatory regime and beyond the control of management.”^[7] The Board concluded that the event satisfied the causation, materiality and prudence conditions for a Z factor adjustment to the company’s rates. Accordingly, the Board directed the company to:

…apply for a Z-factor adjustment in its next rebasing application when actual incremental costs and lost revenues have been clearly identified. The review would be limited to prudence, cost allocation and rate design matters since causation and materiality have been established in this Decision with Reason.^[8]

The company’s subsequent rebasing application was resolved by way of a settlement, set out in Settlement Agreement EB-2011-0335. The settlement approved by the OEB included $162,105 in revenue requirement for the net book value of stranded assets related to storm damages.^[9]

In contrast to Ontario, Alberta’s approach to stranded asset cost recovery is grounded in the Supreme Court’s Stores Block decision^[10] and governed by the AUC’s Utility Asset Disposition (“UAD”) decision.^[11] The AUC strictly interpreted the Stores Block decision in the UAD decision, finding that ratepayers do not have a proprietary interest in the utilities’ assets. Because the utilities own their assets, any gains or losses at disposition are to the account of utility shareholders. Losses from extraordinary retirements including premature obsolescence, policy-driven early retirement, and natural disasters have accordingly been generally borne by shareholders.

The UAD decision distinguishes between ordinary retirement of an asset at the end of its service life, and extraordinary retirement that results in stranded asset costs. An ordinary retirement is one that was reasonably contemplated by depreciation and amortization and for which the costs have been recovered over the asset’s life in customer rates. An extraordinary retirement is one where an asset is removed from rate base before it is fully depreciated because it is obsolete, overdeveloped and surplus to future needs, used for non-utility purposes, removed due to unusual casualty or sudden and complete obsolescence, or unexpectedly shut down completely due to events that were not reasonably anticipated or contemplated in the applicable depreciation and amortization provisions used to set rates. Any under or over recovery of capital investment resulting from an extraordinary retirement is to the account of the utility’s shareholders. Customers do not share in any loss or gain on disposition of an asset.

On June 11, 2018, the Alberta Legislature passed Bill 13, An Act to Secure Alberta’s Electricity Future^[12], which amended several existing statutes. There was an attempt to address the regulatory implications of the Stores Block decision on utility asset dispositions in Alberta in the draft legislation, but the provisions were removed.^[13] The effect of the UAD decision remained unchanged.

By way of example, in Decision 21609-D01-2019 ATCO Electric Ltd., Z Factor Adjustment for the 2016 Regional Municipality of Wood Buffalo Wildfire^[14], the AUC denied ATCO recovery of the undepreciated value of the assets destroyed in the Wood Buffalo wildfire.^[15] The Commission determined, pursuant to its UAD decision, that the utility and its shareholders were responsible for the remaining net book value of the assets destroyed.

However, a 2023 Alberta Court of Appeal ruling^[16] granted an appeal of Decision 21609-D01-2019, finding that the decision under appeal was based on errors of law, particularly the conclusion that the Commission’s options for treating destroyed assets were constrained by the Stores Block decision. The Court determined that the setting of rates is clearly within the discretion of the Commission, including the determination of what expenses can be included as recoverable costs, how to deal with depreciation, and how to deal with stranded or unpredictably destroyed assets. The court summarized its finding as follows:

In Decision 28320-D01-2023^[18] the AUC reconsidered its ruling in Decision 21609-D01-2019. In its reconsideration the Commission focused its analysis on whether ATCO had been provided with a reasonable opportunity to recover its costs, having accepted that the costs were prudently incurred and that the assets were required for the provision of utility service. On this question, the Commission concluded:

…in the circumstances of the Wood Buffalo fire, isolating and directing the removal of the entirety of the net book value of the destroyed assets had the effect of rescinding the reasonable opportunity previously afforded to ATCO Electric to recover these costs, and did so for reasons beyond ATCO Electric’s control.^[19]

ATCO was subsequently allowed to recover in rates the net book value of the assets destroyed in the wildfire.

Assets Stranded by Government Policy

Thus far, the Alberta Utilities Commission has strictly applied the UAD decision in circumstances where a company is replacing infrastructure in response to government policy. In an early application of the UAD decision, the AUC denied cost recovery to EPCOR for the stranded costs of meters replaced by Advance Metering Infrastructure (“AMI”) meters, despite accepting that the adoption of AMI meters complied with government policy.^[20]

In this case, EPCOR indicated that it had considered two government policy matters in its analysis of the AMI business case. First, EPCOR considered new Measurement Canada specification S-S-06 that introduced more stringent regulations regarding meter compliance sample testing and meter replacements.^[21] Second, the company argued that its decision to acquire an AMI system to automate meter reading and associated meter processes was consistent with government policy in relation to smart meters.^[22] The Commission accepted both policy initiatives as supportive of the company’s decision to adopt AMI.^[23] The Commission then conducted an analysis of whether retirement of the existing meters resulting from their replacement with AMI meters constituted an “ordinary retirement” or an “extraordinary retirement.” The Commission concluded that because it was:

…not reasonable to conclude that the characteristics of the proposed retirement of EDTI’s existing meters over a forecast three-year period were anticipated or contemplated in the determination of the parameters used in the preparation of EDTI’s most recent depreciation review and reflected in EDTI’s rates, the book value of the undepreciated meters is to the account of EDTI’s shareholder.^[24]

Accordingly, EPCOR was prevented from recovering in rates the outstanding net book value of the existing meter assets that would be retired, estimated to be approximately $10 million to $12 million.

It is yet to be seen whether the ruling in Decision 28320-D01-2023 will compel the AUC to revisit and reconsider its approach not only to assets destroyed prematurely by forces of nature but also to assets stranded prematurely by forces of government policy. The Commission was careful to ring fence its finding in Decision 28320-D01-2023, stating that:

In arriving at this decision, the Commission has not adopted a new framework or test for the treatment of assets destroyed by force of nature. Instead, the Commission has based its decision on the relevant provisions of the Electric Utilities Act and the guidance of the Court of Appeal, as applied to the particular circumstances of the Wood Buffalo fire.^[25]

The Challenge of Responding to Government Policy Objectives

Regulators may be inclined to respond to government policy objectives in their approach, recognizing a broad public interest mandate. However, how much weight should be given to government mandate letters or other policy instruments that are not given effect in the regulator’s governing legislation? Responding to government policy objectives when policies are not adequately addressed in legislation can present difficulties for regulators. Where there is a gap between stated policy objectives and governing legislation that would give the regulator clear authority to achieve those policy objectives, regulators risk judicial appeals of their decisions on the one hand, and government rebuke or potential dismissal on the other.

The Nova Scotia Energy Board Decision 2026 NSEB 8^[26] illustrates the challenges regulators face and the kind of creative workarounds they sometimes adopt to achieve a public interest outcome, when government policy and legislative mandates are not aligned.

The Government of Nova Scotia’s Clean Power Plan^[27] mandates, among other things, the phasing out of coal fired generation by 2030. In its September 18, 2025 general rate application, Nova Scotia Power stated that it intended “to request approval of the securitization of $704 million of the unrecovered net book value of thermal assets within the scope of the Decarbonization Deferral Account.”^[28] As explained and discussed further below, securitization reduces the cost of recovery for the net book value of stranded assets by replacing the utility’s market-based current weighted average cost of capital with lower-cost bond financing to mitigate the effect on utility rates. However, in Nova Scotia securitization required enabling legislation and companion regulations that might not have been enacted in time for the company to implement approved rates on January 1, 2026; rates that would have included payments on the securitization bond had securitization been approved. In the alternative, the company requested that the Nova Scotia Energy Board approve a “securitization deferral” to defer the depreciation expense and financing costs of the unrecovered net book value of the thermal plant assets until the necessary legislation is enacted, at which time securitization would proceed. In its decision, the Board recognized that “securitization cannot currently proceed in Nova Scotia because the enabling statutory provision has not been proclaimed and regulations to implement this mechanism have not been enacted by the Province.” ^[29] The Board approved the requested securitization deferral. A follow-on application would approve the securitization of the unrecovered net book value of the thermal assets and rates would be adjusted accordingly.

Regulators may be increasingly required to consider alternative approaches to deal with the potential for assets to be stranded by climate events or government policy initiatives while balancing competing objectives, such as affordability; particularly when government policy and legislative mandates are potentially at odds.

REGULATORY ALTERNATIVES

A survey of regulatory alternatives to manage both the potential for stranded assets and the disposition of stranded asset costs in jurisdictions throughout North America yields some alternative responses to stranded asset issues that are worthy of consideration and discussion.

Mitigating the residual cost of assets that may be stranded due to climate change

If the likelihood and potential severity of stranded asset costs can be reduced before any assets are stranded, then the effect of stranded assets on utilities and their customers can be constrained over the long run. However, regulators are increasingly challenged to balance the need to mitigate the potential for assets to be stranded while satisfying the need for utilities to provide timely, safe and reliable utility service at the lowest possible cost and allowing the utilities a reasonable opportunity to recover their prudently incurred costs. And all while managing the potential for rate shock and worsening energy poverty for certain utility customers.

The OEB’s direction that the next Enbridge Asset Management Plan address scenarios associated with the risk of under-utilized or stranded assets and propose mitigating measures seeks to reduce the potential cost of stranded gas assets. The OEB considered stranded asset risks related to climate policy in the 2023–24 Enbridge Gas rate case (EB-2022-0200).^[30] The OEB determined that the energy transition poses a stranded asset risk related to assets serving both new and existing customers and that the Enbridge Asset Management Plan did not adequately address these risks. The Board directed that the next Enbridge Asset Management Plan address scenarios associated with the risk of under-utilized or stranded assets and propose mitigating measures. The nature of Enbridge’s mitigating measures and the OEB’s response to those measures will set the stage for further treatment of stranded asset costs related to climate policy and the energy transition in Ontario. This signals a shift in the approach to the regulatory management of stranded asset risks occasioned by climate policy.

Other regulators are requiring utilities to provide Asset Management Plans and Integrated Resource Plans that account for declining gas demand due to electrification. Washington State’s Utilities and Transportation Commission (“UTC”) is requiring utilities serving both gas and electric customers to file Integrated System Plans that include energy transition planning by 2027.^[31] In 2023, the Washington Legislature passed ESHB 1589 (Large Combination Utilities Decarbonization Act) requiring UTC to develop rules to allow utilities providing both gas and electric service to merge their resource planning into a single Integrated System Plan. The plans are intended to restrain the utilities from expanding gas infrastructure that may become obsolete to the extent possible by better aligning infrastructure investments with the effects of climate laws. The plans encourage investment in non-pipeline alternatives like electrification programs, demand response, and adequate alignment of accelerated depreciation.

In New York State, utilities are required to file proposed long-term plans every three years. The filings must include at least one scenario with no new traditional gas infrastructure, and the filings must quantify greenhouse gas emissions. The New York Public Service Commission has engaged in gas planning proceedings requiring utilities to demonstrate least-cost, non-pipeline alternatives before approving the expansion of gas networks. The proceedings also consider asset life revisions, targeted retirements and the resulting acceleration of depreciation.^[32]

It is becoming increasingly incumbent on utilities with assets that potentially face obsolescence or early retirement to comply with climate policies to seek approval for accelerated depreciation for any assets at risk (pipelines, meters, and infrastructure). Shortening the lifespan of gas infrastructure, so costs are recovered sooner while customers are still using the system, avoids leaving large unrecovered balances when demand drops. To reduce long-run stranded asset exposure, the Colorado Public Utilities Commission (“CPUC”) is requiring Public Service Company of Colorado (“PSCC”) to revise its depreciation rates for gas assets and to begin pre‑funding future gas system retirements.^[33] The CPUC ordered PSCC to establish a trust account to fund future decommissioning costs for gas assets and to contribute $15M annually to the trust.^[34] These measures are intended to align with heating sector decarbonization objectives.

Accelerated depreciation for assets at risk to avoid or reduce stranded asset costs results in accelerated cost recovery, increasing annual revenue requirements and ultimately customer rates. This has two obvious consequences. As rates increase for natural gas customers, electrification (e.g. the adoption of heat pumps for home heating, replacement of gas stoves) may become more economically attractive. This result is advantageous for the parallel objective to achieve decarbonization targets. However, as rates increase, low income customers may be adversely and disproportionately affected, worsening energy poverty in the absence of countervailing initiatives. Some of the countervailing initiatives adopted by regulators are discussed below.

Some jurisdictions are taking a more overarching approach by considering performance-based regulation (“PBR”) to incentivize utilities to find efficiencies that will offset the effects of the additional costs associated with climate, among other influences on burgeoning utility costs, while mitigating rate increases through caps and rate setting formulas. Transitioning from single-year cost-of-service regulation to multi-year frameworks with metrics for efficiency and affordability can blunt the effect of climate-related utility costs on customer rates.

Although only two jurisdictions in Canada (Alberta and Ontario) have adopted PBR, regulators in the US are increasingly adopting or actively considering multiyear frameworks with metrics for efficiency, affordability, and decarbonization. Massachusetts, New Hampshire, Connecticut and Hawaii all have PBR plans, and Oregon has announced that it will adopt PBR. Other states are also considering PBR or other incentive measures. Washington State, North Carolina, New York, Nevada, Colorado, New Mexico, Ohio, Minnesota, Michigan, Pennsylvania, Maryland, Virginia, and the District of Columbia have initiated stakeholder engagements to consider the adoption of PBR and the form it may take. Only two states have not considered adopting some form of incentive regulation, Texas and Oklahoma.

Calculating the costs of stranded assets

The appropriate calculation of stranded asset costs is not always easily determined, and the calculation has consequences for both utility shareholders and customers. Determining the costs of stranded assets when they are considered underused, outdated, unprofitable, or cannot be recovered begins by looking at the asset’s remaining net book value. The net book value refers to the portion of the original asset investment that has not yet been recovered in utility rates through depreciation or amortization. If a stranded asset retains any fair market value, that value should be subtracted from the asset’s net book value in the stranded asset cost calculation. The fair market value of an asset can be determined by its net salvage value or its resale value in the market. Negative net salvage values that increase stranded asset costs are also possible.

For instance, when coal-fired power generation is phased out, some plants may be suitable for conversion to gas-fired electricity generation. Under these conditions, the fair market value of the phased-out coal-fired plant before conversion should be subtracted from its remaining net book value to determine the stranded asset costs. After conversion, only the arm’s length fair market value of the closed plant plus any conversion costs should be included in the capital cost of the gas-fired conversion and allowed in rate base.^[35] The stranded costs of the coal plant (net of the fair market value) are excluded from the capital cost of the converted gas fired plant and recovered separately through other mechanisms (e.g. securitization).

Some regulators require utilities to show they have mitigated stranded asset costs before allowing full cost recovery. Some of the statutory requirements in the US related to the recovery of stranded asset costs include a provision that utilities must demonstrate efforts have been made to mitigate stranded costs. Where there is inadequate evidence of mitigation measures, the full amount of the stranded asset costs may not be approved for recovery, given that the utility can be considered imprudent in managing its stranded asset costs. For example, New York and Pennsylvania require utilities to prove mitigation efforts as a pre-condition of full recovery.

Accounting for stranded asset costs in utility rates

Measures to reduce the severity of stranded asset costs resulting from climate initiatives by accounting for potential stranded asset costs in advance will almost certainly result in higher customer rates. When assets are then stranded, the regulator will again be faced with mitigating the effect on customer rates. Regulators are generally loath to increase rates, but when rate increases are necessary, they are then faced with the question of how to equitably share the additional cost recovery among customer classes, particularly when low income customers may be adversely affected.

There is a maxim in rate setting that the individual who causes a cost should bear that cost in their rates. A corollary to that maxim is that the individual who benefits should bear the related costs. However, costs and benefits arising from measures adopted to adhere to climate policies are not easily assigned to any one rate class. Theoretically, everyone in society benefits from climate policies and the associated costs should be borne widely. The additional costs arising from climate policy are the responsibility of the government that institutes the policies and arguably government should defray the costs through tax credits, direct investment, or other measures. However, governments generally leave it to regulators to manage the utility cost consequences of climate policy. Consequently, regulators are faced with the challenge of equitably sharing the costs among rate classes based on considerations such as relative effect or ability to pay.

Equitably sharing the cost of stranding when it occurs

Cost risk sharing between utilities and customers has long been an element of public utility regulation. Traditionally, customers have borne some utility cost risks including fuel cost fluctuations, prudent cost over-runs, load or volume risk (in the absence of revenue decoupling), among others. The challenge for regulators when considering how best to equitably share stranded asset costs is to do so while avoiding appeals on the grounds that any sharing is confiscatory and contrary to the utilities’ entitlement to a reasonable opportunity to recover their prudently incurred costs, as demonstrated in the Alberta case. Regulators, the courts, and legislators are wrestling with finding the appropriate cost sharing balance.

In Washington State, the Climate Commitment Act^[36] is designed to lower greenhouse gas emissions in Washington State by setting a limit on emissions over time. Under the legislation, utilities must either cut their emissions or buy offsets. The Washington Utilities and Transportation Commission (“UTC”) has ordered risk-sharing for Climate Commitment Act compliance costs which requires the utilities to absorb some of the stranded cost risk, rather than passing all of it on to customers.^[37] In its order, the UTC found that it has the authority to impose a risk sharing mechanism on Puget Sound Energy specifically, and determined that the risk sharing mechanism will be addressed in a future rulemaking proceeding that will apply to all utilities it regulates. Interestingly, the Washington State legislation contemplates utilities that provide both gas and electricity service combining their gas and electricity rate bases into a single rate base to better manage sharing of decarbonization costs.^[38] Thus far, the UTC has not adopted this measure, nor have the utilities requested it.

Mitigating the effect of stranded asset costs on utility rates

Regulators are mitigating the effect of stranded asset costs on customers by adjusting revenue to cost ratios across rate classes, expanding discounts for low-income customers, and implementing billing caps for the remaining gas customers most exposed to stranded cost recovery. In addition to these more targeted approaches, securitization has become a widespread tool to reduce the recovery cost of stranded assets and smooth potential customer rate impacts.

Securitization has emerged as a useful approach to provide for both financial efficiency and customer protection. Securitization replaces the utility’s market-based current weighted average cost of capital with lower-cost bond financing to fund the recovery of stranded asset costs over time. Bond financing is treated as a regulatory asset, with its expenses recovered from customers through their rates. Securitization is often used to recover costs associated with stranded assets when facilities are retired early due to climate or other policy and/or regulatory requirements, such as the early closure of coal-fired or nuclear plants. Currently, more than twenty-five states in the US have passed securitization legislation to manage the financial risks of the clean energy transition.

THE FUTURE OF STRANDED ASSET COSTS

Clearly there are regulatory alternatives that offer solutions to the problems of equitable treatment of stranded asset costs. To the extent that utility shareholders or their customers bear the brunt of climate-related utility costs, and in particular the costs of stranded assets that may result, regulators who are charged with the public interest task of finding an equitable sharing of the costs and benefits of climate policies should be given broad legislative authority to consider creative regulatory alternatives. Adopting specific and workable alternatives for the treatment of assets potentially stranded by climate events, climate policies, and the energy transition in general will require regulators to have the legislative authority, latitude, and determination to do so.

Legislation also needs to recognize that climate policies are intended to achieve a universal public good. Responding to climate change benefits everyone and the burden of paying for the implementation of climate policies should not be disproportionately borne by either utility shareholders or their customers. In the emerging utility market, where electricity consumers are increasingly no longer reliant only on utility delivered energy, those who are not reliant on utility delivered energy should not be absolved from supporting the cost of climate initiatives. To do so exacerbates the problem of cost recovery from a shrinking customer base. This may require a broader approach to managing the costs of climate policy through non-regulatory measures such as tax credits or direct government subsidies to defray the risks and potential costs of policy implementation. Alternatively, significant rate restructuring to better align the recovery of utility costs, including climate-related costs, may be required.^[39]

• * Mark Kolesar is a researcher, author and consultant in utility regulation and policy development, and a frequent participant in webinars and conferences in Canada and the U.S. He was a member of the Alberta Utilities Commission for twelve years, including six years as Vice Chair and two years as Chair. Mark is now managing principal at Kolesar Buchanan & Associates Ltd., where he advises on utility regulation matters. Mark does not offer any legal opinions on the matters discussed in this article, as he is not a lawyer.

  ¹ There are limited exceptions to the strict application of the “used and useful” standard in Canadian utility regulation. Plant Held for Future Use (“PHFFU”) is sometimes permitted to attract a regulated return until it is put into service, and Construction Work in Progress (“CWIP”) is sometime included in Rate Base and permitted to earn a regulated return prior to completion and subsequent use in the provision of utility service.

• ² Canadian Electricity Association, Adapting to Climate Change: State of Play and Recommendations for the Electricity Sector in Canada (2016), online (pdf): <natural-resources.canada.ca/sites/www.nrcan.gc.ca/files/energy/energy-resources/Adapting_to_Climate_Change_State_of_Play_and_Recommendations_for_the_Electricity_Sector_in_Canada.pdf>.

• ³ Notable examples in Hawaii, Alberta and California have led to the adoption of increased measures to reduce the potential for utilities to spark wildfires.

• ⁴ Sarah Brody, Matt Rogers & Giulia Siccardo, “Why, and How, Utilities Should Start to Manage Climate-Change Risk” (2013), McKinsey & Company, online (pdf): <mckinsey.com/~/media/McKinsey/Industries/Electric%20Power%20and%20Natural%20Gas/Our%20Insights/Why%20and%20how%20utilities%20should%20start%20to%20manage%20climate%20change%20risk/Why-and-how-utilities-should-start-to-manage-climate-change-risk-vF.pdf>.

• ⁵ Ontario Energy Board Act, 1998, SO 1998, c 15, Sch B.

• ⁶ Ontario Energy Board, Notice of Application and Hearing for an Electricity Distribution Rate Change — West Coast Huron Energy Inc, Decision and Order, EB-2011-0335.

• ⁷ Ibid at 8.

• ⁸ Ibid at 9.

• ⁹ Ibid, Appendix O at 13.

• ¹⁰ ATCO Gas & Pipelines Ltd v Alberta (Energy & Utilities Board), 2006 SCC 4.

• ¹¹ Alberta Utilities Commission, Utility Asset Disposition, Decision 2013-417 (26 November 2013), online: AUC <auc.ab.ca/applications/decisions/Decisions/2013/2013-417.pdf>.

• ¹² An Act to Secure Alberta’s Electricity Future, SA 2018, c A-14.5 (assented to 11 June 2018).

• ¹³ The failed amendments to Bill 13 would have guaranteed that utilities would recover the full cost of any stranded assets in customer rates providing the original investment was determined to have been prudent. However, the amendments would also have modified the prudence test ostensibly in favour of utility shareholders. These amendments were eventually excluded from the legislation.

• ¹⁴ ATCO Electric Ltd, Z Factor Adjustment for the 2016 Regional Municipality of Wood Buffalo Wildfire, Decision 21609-D01-2019.

• ¹⁵ The author was a member of the panel of the AUC that issued ATCO Electric Ltd, Z Factor Adjustment for the 2016 Regional Municipality of Wood Buffalo Wildfire, Decision 21609-D01-2019.

• ¹⁶ ATCO Electric Ltd v Alberta Utilities Commission, 2023 CanLII 129 (ABCA).

• ¹⁷ Ibid at para 60.

• ¹⁸ Alberta Utilities Commission, Reconsideration of ATCO Electric Ltd, Z Factor Adjustment for the 2016 Wood Buffalo Fire, Decision 28320-D01-2023 (19 December 2023).

• ¹⁹ Ibid at para 36.

• ²⁰ Alberta Utilities Commission, 2013 PBR Capital Tracker True-Up and 2014–2015 PBR Capital Tracker Forecast, Decision 3100-D01-2015 at paras 639–91. The author was the chair of the AUC panel that issued Decision 3100-D01-2015.

• ²¹ Ibid at para 645.

• ²² Ibid at para 643.

• ²³ Ibid at paras 657–58.

• ²⁴ Ibid at para 691.

• ²⁵ Supra note 18 at para 24.

• ²⁶ Nova Scotia Energy Board, General Rate Application by Nova Scotia Power Incorporated for Approval of Certain Revisions to its Rates, Charges and Regulations, Decision 2026 NSEB 8, M12451.

• ²⁷ Government of Nova Scotia, Clean Power Plan, online: <novascotia.ca/clean-power-plan>.

• ²⁸ Supra note 26 at para 285.

• ²⁹ Ibid at para 314.

• ³⁰ Ontario Energy Board, Enbridge Gas Inc — Application to Change its Natural Gas Rates and Other Charges Beginning January 1, 2024, Decision on Settlement Proposal, EB-2022-0200.

• ³¹ Washington Utilities and Transportation Commission, State Regulators Adopt Rules for Integrated System Plans, Docket U-240281 (26 September 2025), online: WUTC <publicnow.com/view/A9CA8167E4A875654138C0752D4966C10B997728?1758930484>.

• ³² New York State Department of Public Service, PSC Accepts Plan to Advance Gas System Reliability (18 September 2025), online: NY DPS <publicnow.com/view/D0B5B3EF399A45232225C6465D25F44A42F92B4C>.

• ³³ Colorado Department of Regulatory Agencies, Proceeding No 25A-0165G.

• ³⁴ “UCA Staff Flag Stranded-Asset Risk in PSCo Depreciation and Gas Infrastructure Filings” (13 July 2025), online: Citizen Portal <citizenportal.ai/articles/6173324/UCA-staff-flag-stranded-asset-risk-in-PSCo-depreciation-and-gas-infrastructure-filings>.

• ³⁵ This assumes a vertically integrated utility without deregulated (competitive) generation.

• ³⁶ Climate Commitment Act, Wash Rev Code § 70A.65 (2021).

• ³⁷ Washington Utilities and Transportation Commission, Final Order, Docket U-230968 (21 February 2025).

• ³⁸ Amanda Zhou, “State’s New Law Involving PSE Aspires to Set a Course for the Future”, The Seattle Times (22 April 2024), online: <seattletimes.com/seattle-news/climate-lab/states-new-law-involving-pse-aspires-to-set-a-course-for-the-future>.

• ³⁹ See Mark Kolesar, “Repricing the Grid: Should It Be Regulated as a Common Carrier?” (2025) 13:2 Energy Regulation Q.