INTRODUCTION

Climate change policies around the world have had a significant impact on energy regulation. This article considers the first three Canadian cases that have struggled with the impact of the energy transition on stranded assets. It also deals with the impact of the energy transition on energy regulation practice and procedure.

This article also seeks to explore what we now call agile regulation, a new form of regulation that requires real time innovation and flexibility to meet the demands of the energy transition. The cases we consider come from three different regulators in three different provinces — Ontario, British Columbia and Nova Scotia

The three cases involve a fundamental principle in public utility law that provides that utilities can only recover the cost of capital assets that are “used and useful.” Used and useful has a long history in both Canadian^[1] and American^[2] law. The Supreme Court of Canada decision in ATCO^[3] makes it clear that assets that are no longer required to meet public utility service needs cannot be included in regulated assets and considered part of the rate base.

The energy transition runs into the “used and useful” rule every day. There are a number of reasons. First, the energy transition involves major capital expenditures in new technology some of which will not work.^[4] If the technology doesn’t work it will not be used and useful. Second, the new technology may render useless existing technology or reduce its useful life.

THE DECISIONS

Ontario

On December 21, 2023 the Ontario Energy Board (OEB) issued a 145 page decision in a rate application by Enbridge Gas Inc. (Enbridge) following an 18 day hearing.^[5] There was no shortage of participation in this hearing. The Board considered the submissions of 20 intervenors and 385 letters of comment. In a press release the same day the Board pointed out that this is the first OEB proceeding to consider a natural gas rates application in the context of the energy transition.

The first section of the Enbridge decision set out the Board’s major findings related to the energy transition:

1. The energy transition poses a risk that assets used to serve existing and new Enbridge customers will become stranded because of the energy transition. Enbridge has not provided an adequate assessment of this risk to demonstrate that its capital spending plan is prudent. The stranded asset risk affects all aspects of Enbridge’s system and its proposals for capital spending on system expansion and system renewal.
2. The OEB has reduced the overall proposed capital budget for 2024 by $250 million. Enbridge is expected to utilize its project prioritization process to accommodate this envelope reduction. The OEB did not accept the current Asset Management Plan as a basis to support the proposed capital investments.
3. For the proposed system expansion capital spending plan, the OEB has determined that for small volume customer connections, the revenue horizon that Enbridge uses to determine the economic feasibility of new connections is to be reduced from 40 years to zero, thus reducing stranded asset risk for these new connections to zero, effective January 1, 2025.^[6]

Enbridge Gas Inc. is the largest natural gas distribution utility in Canada, serving over 3.5 million customers. The company is the product of a merger in 2018 of Enbridge Gas Distribution Inc. and Union Gas Limited. This application is the first cost of service application since the two companies were joined together.

Essentially the application was a rate case. But the issue that dominated the application and the decision was issue three above.  That was the decision by the OEB to reduce the revenue horizon for small volume customer connections from 40 years to zero. It costs Enbridge just over $4,000 to connect a gas customer. Reducing the number to zero meant that the new customers had to pay the full cost of the connection upfront. This, the OEB concluded, avoided any possibility of stranded assets.

The OEB concluded that the gas utility had completely ignored the impact of the energy transition and assumed it was “business as usual”:

The OEB concludes that Enbridge Gas’ proposal is not responsive to the energy transition and increases the risk of stranded or underutilized assets, a risk that must be mitigated.  In particular, Enbridge Gas has not met the onus to demonstrate that its proposed capital spending plan reflected in its Asset Management Plan is prudent and that it has accounted appropriately for the risk arising from the energy transition.

Two important themes emerged during this proceeding.

• climate change policy is driving an energy transition that gives rise to a stranded asset risk, and
• the usual way of doing business is not sustainable.

…

As OEB staff put it,

Enbridge Gas expects to continue to add new customers and expand its rate base in what appears to be “business as usual.”

…

In the face of the energy transition, Enbridge Gas bears the onus to demonstrate that its proposed capital spending plan reflected in its Asset Management Plan is prudent having accounted appropriately for the risk arising from the energy transition.

The record is clear that Enbridge Gas has failed to do so.  Enbridge Gas has taken the position that there is no stranded asset risk for the purpose of setting rates for 2024.  This is not logical.^[7]

There was a great deal of controversy as to whether the number should be zero or a larger number. The number estimates became a guessing game. Enbridge was prepared to move from 40 to 30 years on an interim basis if the final number could be determined in a separate hearing.  Board Staff and one Board member agreed on 20 years while others agreed on 15 years. Two intervenors and two Board members remained at zero.  They turned out to be the winners. As Enbridge pointed out numerous times, the numbers were largely argument as opposed to evidence.

Estimating the degree of stranded assets involves a new and difficult forecast. Board Staff, Enbridge, and four intervenors suggested that the stranded asset calculation be deferred to a separate hearing. That was rejected by the Board which ruled:

Enbridge Gas has not demonstrated that the 40-year revenue horizon is appropriate in light of the energy transition underway. Enbridge Gas acknowledges this in its reply argument.  It proposes a 30-year revenue horizon on an interim basis pending a separate proceeding to determine what the revenue horizon should be.  The OEB is of the view that the record before it is more than sufficient to determine this issue and there is no benefit to deferring the issue to a subsequent proceeding.

…

The OEB finds that zero is the optimal revenue horizon because this fully addresses the risk of stranded assets resulting from the energy transition for new connection projects.^[8]

Enbridge responded to the decision with two appeals. The first was an application to the courts indicating that the decision should be set aside because there were no reasons or evidence supporting the findings. This was supported by the Minister of Energy who stated the next day that he would use all of his authority to pause and reverse the Ontario Energy Board’s decision.

The second was a Motion for Review that asked the Board to establish a new panel that would review the decision of the first panel. The grounds were essentially those set out in the application to the Court of Appeal — there was no evidence or reasons. There was however one wildcard.

In the Notice of Motion Enbridge stated:

“The Decision effectively makes a new policy that is directly at odds with Government of Ontario policy. In this way key aspects of the decision are fundamentally flawed. It is appropriately the role of the provincial government to make the overarching policy and for the OEB to implement it. As an economic regulator it is the OEBs role to serve and promote provincial energy policy. Where the OEB creates new policy that conflicts with the government of Ontario policy that is an error of law contrary to the OEBs statutory objectives in respect of natural gas and an overstepping of jurisdiction that must be corrected.”^[9]

At page 5 of its Reply Argument Enbridge states:

“Energy transition policies are appropriately the domain of the government and not the OEB and speculating on a future state in advance of government direction is at best unproductive and at worst results in not meeting the reliability, affordability and energy access needs of Ontario.”^[10]

The Notice of Appeal that Enbridge filed with the Divisional Court comes close to this principle when it states that:

…the OEB erred in law and jurisdiction by:

Acting contrary to the statutory objectives for gas as set out in the OEB Act and in accordance with the policies of Government of Ontario.”^[11]

If upheld, a claim that failing to act in accordance with the policies of the government constitutes an error in law and jurisdiction by an energy regulator could significantly change Canadian energy regulation.

As indicated, the OEB dismissed outright the Enbridge application to spread the cost over 40 years. More importantly the Board ignored a request by Enbridge, the Board Staff, one of the Board members and a number of interveners to hold a separate hearing to make proper determination of what the number should be. Those parties all argued that the evidence was insufficient, and a number of relevant parties affected by the ruling were not present and had not been given notice.

There was no concern about any possible delay caused by the second hearing. Both Enbridge and Board staff agreed that there would be no stranded assets in year one. It looked like 30 or 20 years would work on an interim basis. However, the OEB disagreed and stated:

“The OEB is of the view that the record before it is more than sufficient to determine this issue and there is no benefit to deferring the issue to a subsequent proceeding.”^[12]

The Enbridge decision has faced its fair share of criticism. This includes a response from the Ontario Minister of Energy who proposed new legislation that would give the government authority to reverse the decision. It also includes the right for the government to order generic hearings on certain aspects of a proceeding where the government believes that the evidence is insufficient.

There is however one feature of the decision that the OEB deserves credit for. This is one aspect of agile regulation called “regulatory guidance.” In the Enbridge decision this is set out in section 10 of the Order as follows:

10. For its next rebasing application, Enbridge Gas shall:

1. File an Asset Management Plan that provides clear linkages between capital spending and energy transition risk. The Asset Management Plan should address scenarios associated with the risk of under-utilized or stranded assets and identify mitigating measures.
2. File a report examining options to ensure its depreciation policy addresses the risk of stranded asset costs appropriately. These options must encompass all reasonable alternative approaches, including the Units of Production approach.
3. Track and study the ten accounts proposed by InterGroup with respect to net salvage and file a report on the results.
4. File a proposal to reduce any remaining capitalized indirect overheads to zero.
5. File an independent third-party expert study that assesses its overhead capitalization methodology.
6. Perform a risk assessment and develop a plan to reduce the stranded asset risk in the context of system renewal.^[13]

This is an important element of practice and procedure in agile energy regulation. It was also used by the Nova Scotia regulator in Annapolis Tidal Generation which is reviewed later in this article.

British Columbia

The Enbridge decision is not the only Canadian decision to deal with rate regulation and the energy transition. The very next day, December 22, 2023, the British Columbia Utilities Commission (BCUC) released a decision that faced the same issue. The BC decision^[14] involved an application by Fortis BC Energy Inc. (FortisBC) to expand a natural gas pipeline in the Okanagan region of British Columbia.

In the British Columbia case the utility, FortisBC, applied to the BCUC to expand a natural gas pipeline in the Okanagan at a cost of $327 million. FortisBC stated that the pipeline expansion was needed to meet it forecast increase in demand for natural gas in the Okanagan region due to population growth.

The BCUC turned down the application stating:

The basis for FEI’s justification for constructing the OCU Project is that the growth of population and development in the Okanagan region is robust, and the growth curve will continue unabated. The three peak demand forecasts all support this although with significant variability between them. Of particular concern to the Panel is FEI’s admission that none of its forecasts have considered the potential for a flattening or even a reversal of the curve due to commitments in the CleanBC Roadmap and the impacts of changes to the BC Energy Step Code, other planning guidelines or zoning bylaws. Despite such potential risks, FEI has maintained a ‘business as usual’ approach to its forecasting with the expectation there will be a continued increase in peak demand over the next 20 years.

…

If the OCU Project were a minor expenditure the Panel might be inclined to move forward with a favorable Decision at this time. But at last estimate, the total Project cost estimate is $327.4 million with a delivery rate impact of 2.37 percent. This is a very significant expenditure and, for it to be approved, there needs to be greater certainty that the proposed scope of the project is fully required.^[15]

The BCUC also asked FortisBC to consider a matter not addressed in the application. That was a short-term solution that could meet additional demand in the early years. The Commission directed the utility to file a new plan by the end of July 2024 to address this issue.

Nova Scotia

Energy regulators today live in a new world. Worldwide energy regulators face a $131 trillion investment in new technologies designed to reduce the amount of carbon in the production, distribution and use of electricity.^[16] Picking winners and losers in new technology is not easy. It is always a challenge.

Approving a technology pilot is just the first problem. The second problem is what do the regulators do when the technology fails. The first decision addressing this problem surfaced in Nova Scotia recently.^[17] There the energy regulator faced an application by Nova Scotia Power to write off significant costs related to a new technology pilot that after many years not to be commercially viable.

The project in question is known as the Annapolis Tidal Generation Station. At the time of its commissioning in the mid-1980s the Station was intended to be a short-term research initiative to test the viability of tidal barrage technology in the Bay of Fundy.^[18] In recent years the utility that was operating the project, Nova Scotia Power, experienced significant operational and maintenance costs with the Generating Station. Capital costs were increasing significantly while at the same time the amount of power generated was declining.

The application by Nova Scotia Power asked the Nova Scotia Utility and Review Board (NSUARB)  to approve the amortization of the undepreciated value and the remaining construction work in progress over a ten-year period. Nova Scotia Power did not apply for decommissioning at the same time.

The Board’s decision and the reasoning shows how complicated these cases can become. Nova Scotia Power asked the Board to find that the project was no longer used and useful. It turns out that is not a simple question to answer.

There is no question that at the time of the application the generating station was not being used. The question was whether the technology could be useful in the future. The NSUARB pointed to the arguments of the intervenor groups at paragraph 32.

The closing submissions of the Small Business Advocate, the Industrial Group, the Consumer Advocate, and the Town of Annapolis Royal all expressed concerns relating to NS Power’s assertion that the retirement of the Generating Station is the lowest cost option to customers. All four stakeholders noted that they do not agree that NS Power has put forth a sufficiently comprehensive analysis to convince them that there is no viable future use of the assets in question for public utility purposes.^[19]

The analysis by the NSUARB is best set out in the following paragraphs:

In this case, given the significant amount of the undepreciated cost remaining in rate base, NS Power proposed a 10-year amortization period. No party challenged the proposed length of the amortization period. It was supported by both Mr. Reed and Grant Thornton. The Board agrees that, if decommissioning is established as the least cost option, a 10-year amortization period appears to create a reasonable balance between negative impacts to current ratepayers and intergenerational equity considerations.

The substantive issue in dispute in this case is whether NS Power has shown that decommissioning of the Generating Station is the least cost option for ratepayers. The Board recognizes that in preparing its case NS Power took several steps in this application which are appropriate. The use of external consultants to supplement in-house expertise follows Board guidance. The Board acknowledges these consultants support the approach set out in the application. As well, the use of probabilistic modelling was appropriate in this case, given the number of uncertainties which could impact cost estimates. That said, the Board has determined it does not have enough information to find that decommissioning is, in fact, the least cost option. The Board therefore finds NS Power has not met the burden of proof to obtain the accounting treatment relief sought in this matter.

The Board is in general agreement with the Intervenors, based on the evidence filed by Midgard and MS Consulting, that there are too many cost variables which have not been sufficiently addressed, or have been addressed in an inconsistent manner across the various options. The Board acknowledges there is contention between NS Power and MS Consulting as to the actual impact of certain inputs on the modelling results, including certain inputs used by MS Consulting. The Board also recognizes that Midgard’s ultimate recommendation was that the LEM option be kept alive. This could theoretically be done by approving the current application and revisiting the issue, if necessary, when a decommissioning application is filed.

That said, given the magnitude and scope of the unaddressed issues, the Board concludes approval of the accounting treatment at this point is premature. The evidence indicates there are varying levels of class estimates for the different options. In particular, the spread in NPVRR values between the LEM option and the decommissioning option are not that wide. In certain scenarios, the LEM option might actually be more cost-effective, although with greater risk.

It is therefore important that, as far as it is possible, there be an apples-to apples comparison between the LEM option and the decommissioning option. The Board is concerned that if the accounting treatment is approved now, there may be a tendency to focus on having the decommissioning option approved. This may create less incentive to continue robustly assessing the LEM option.^[20]

In the end the NSUARB concluded that it did not have sufficient information to make a decision. The complexity of the issues that face regulators in this type of case is evident in the Commission’s direction to Nova Scotia Power regarding the additional information that is required to properly address the issue:

While it will not direct NS Power to undertake any specific studies, it would seem to the Board that the following information would be of assistance in determining the least cost option in this matter:

1. A more fulsome assessment of LEM costs;
2. A more fulsome assessment of the new technology option, including: a. A more thorough assessment of options and costs to change station capacity under the new technology option; and b. Solicitation of pricing from multiple manufacturers for the new technology option;
3. A more fulsome assessment of sedimentation issues and costs associated with the decommissioning option;
4. Completion of environmental studies needed to assess environmental risks and costs associated with each alternative;
5. A more fulsome assessment of station asset disposal options;
6. A detailed explanation of why capital cost estimates for the decommissioning option have decreased so dramatically from the estimates included in NS Power’s 2018 Hydro Asset Study;
7. Engagement with DFO personnel on if NS Power can satisfactorily present alternative studies or data on fish migratory periods and fish mortality for the site, short of returning the Generating Station into operation, including potentially modifying its operation to reduce or mitigate the potential impacts on fish so as to avoid the requirement for a DFO Authorization;
8. Engagement with DFO personnel on whether it would consider any compliance plan with an accompanying request for authorization. If DFO will entertain such a request, NS Power could estimate the cost of preparing and implementing a compliance plan in its Decision Analysis;
9. Engagement with DFO personnel and the Province on any Fisheries Actor environmental compliance issues under the Decommissioning option with respect to restoring the area to its original condition (i.e., with no water flow through the causeway at the location of the Generating Station and any resulting decommissioning compliance costs related to the sluice gates, causeway, and fish passages). The results of these discussions could be incorporated into the Decommissioning option in the Decision Analysis; and
10. With respect to the above initiatives, engagement with Indigenous communities respecting the various options (including LEM, New Technology and Decommissioning), to better inform the potential costs to be incorporated into the Decision Analysis.^[21]

The Board concluded that until it received this information in a new application it was unable to make a decision stating:

The Board has determined that it has insufficient evidence at this time to find that decommissioning of the Generating Station is the least cost option for ratepayers. It therefore is not able to find that the asset is not used and not useful in accordance with Accounting Policy 6350. Therefore, the Board will not approve the application at this time. The Board believes the best way of proceeding is to reconsider the application for accounting treatment approval along with a decommissioning application. That said, NS Power is at liberty to reopen the matter if it is in a position to address the Board’s concerns.^[22]

The introduction of new technology creates two problems for energy regulators. The first is defining the terms and conditions on which regulators accept and approve investment in new technology. The second as outlined in this Nova Scotia case is the terms and conditions on which regulators remove the technology from rate base when it turns out not to be useful.

AGILE REGULATION

Recently three economists from the University of Ottawa released a study on energy regulation during the energy transition, prepared for the Canadian government. It started with the following premise:

Achieving the government of Canada’s ambitious emissions reduction strategy will require an unprecedented scale and pace of innovation. Against this backdrop shifting to a more agile regulatory system has never been more pressing… Shifting towards a more agile regulatory system has two dimensions. It involves changing the policy instruments and the regulatory institutions. ^[23]

The authors then added: “Regulatory excellence means using the best available evidence and being transparent and inclusive.”^[24]

More recently the Ontario Minister of Energy sent to a new Letter of Direction to the Acting Chair of the Ontario Energy Board stating:

“as electrification and energy transition progresses the OEB should continually explore how to maximize its flexibility to facilitate innovation within the existing regulatory framework The OEB should continue to collaborate with the IESO, Ministry officials and sector stakeholders in this regard. Innovation in both gas electric sectors is critical to meeting our goals of meeting future energy demand in reducing emissions.”^[25]

The three decisions reviewed in this article were the first decisions in Canada where energy regulators faced the full force of the energy transition head on in terms of its impact on stranded assets. This is an important issue today. It will become more important tomorrow.

Regulatory practice and procedure in this area will require some refinement. Energy regulators will have to become more flexible and innovative, something the Ontario Minister of Energy has endorsed. The Ottawa economists suggested that agile regulation is regulation that is not only transparent but seeks the best possible evidence.

The decisions reviewed in this article indicate that energy regulation involving the energy transition and stranded assets require consideration of six factors: better evidence, different solutions, new regulatory guidance, cost allocation, risk adjustment, and policy alignment.

BETTER EVIDENCE

An interesting question is why did the OEB not ask for better evidence in the Enbridge case? A number of parties in that proceeding including Board Staff asked the OEB to defer the matter to a generic hearing in order to obtain better evidence. This is not a new procedure in energy regulation. Recently when Nova Scotia Power asked the Nova Scotia Utility and Review Board (NSUARB) to approve the amortization of the undepreciated value of the Annapolis Tidal Generation Station,^[26] the NSUARB indicated it could not make its decision until additional information that properly addressed certain issues was provided.

The OEB treated the Enbridge case as a garden-variety rate case. In those cases, if the applicant does not meet its burden of proof the application is dismissed. The treatment of stranded assets in the energy transition requires a different approach.

The Canadian energy regulators will have to revise their practices and procedures to meet the new challenge.  The starting point is the procedure used by the NSUARB in Annapolis Tidal Generation. Where the stranded asset evidence is not satisfactory, regulators must take steps to get better evidence. The regulator should also provide better guidance and be specific about the information required as the NSUARB did in Annapolis Tidal Generation.

Different Solutions

The British Columbia decision in FortisBC is a good example of another feature in the world of agile regulation. Rather than simply dismissing the application the BCUC decided that while it could not approve the $327 million pipeline it was important to address a short-term problem. The BCUC was concerned that based on the evidence there could be a lack of capacity in the short term if not in the long-term and that should be addressed. The BCUC then ordered the utility to prepare a different application dealing with the problems by the end of July 2024. This is another example of the importance of agile regulation.

New Regulatory Guidance

Another new area of practice and procedure in energy regulation that assists the parties in difficult cases like those involved in the energy transition and stranded assets is “new guidance.” The leading examples in the three decisions considered in this article are the Enbridge decision by the OEB, the Annapolis Tidal Generation decision by the NSUARB.

Section 10 of the Order in Enbridge Gas, set out above, lists six different calculations and submissions that the Board required Enbridge to undertake in its next rebasing application.

The NSUARB in Annapolis Tidal Generation listed in detail the information it would be looking for in a revised application with respect to that project. The Board had ruled that it did not have enough information to make proper decisions in the first application. The Board put that application on the shelf and asked the applicant to make a revised application. In difficult cases this is a more productive approach than simply dismissing the original application.

Cost Allocation

An important element of stranded assets cases is an understanding by all parties as to who bears the cost. And in what proportion. To quote the leading American energy regulation scholar, Scott Hempling, wide discretion is granted to regulators. In a well-known article Hempling states:

Stranded cost situations always combine two key facts: prudent investments, and post-investment circumstances not anticipated at the time of the investment. Those factual developments can be reductions in demand, increase in input costs, obsolescence, and changes in regulatory policy. The question is always: When prudent actions produce uneconomic outcomes, who bears the unrecovered costs: shareholders or customers? Readers hoping for clear “dos” and “don’ts” will be disappointed; those hoping for broad regulatory discretion will be pleased. The consistent principle is this: Regulators have a range of options, from full recovery plus profit, to no recovery and no profit, and all points in between.^[27]

The Canadian decisions with respect to who bears the cost of stranded assets also vary widely. The Enbridge decision by the OEB is just one example. There Enbridge claimed that all of the costs relating to stranded assets should be borne by the customers. A number of parties disputed that but the Board for some reason made no decision on that issue. However, the decision in the case that the customer should pay all of the connection costs upfront suggests that the Board believed that the customers were on the hook for all the stranded assets.

It may be that if regulators make a clear statement on how stranded costs will be allocated between the utility and the customer applicants may make a more careful estimate of the extent to which the project will produce stranded costs. We should remember that in these three early cases two of them rested on a conclusion by the regulator that there had been no serious attempt to estimate the stranded cost potential of the project.

Risk Adjustment

Another important instrument regulators face in stranded asset cases is the risk adjustment factor. This was a live issue in the Enbridge case where the capital structure for the purpose of ratemaking was a ratio of 64 per cent debt to 36 per cent equity. Enbridge proposed an increase in the equity thickness from 36 to 42 per cent. Board Staff and four interveners recommended an increase to 38 per cent while eight interveners recommended that it remain at 36 per cent.  In the end the OEB approved an increase in the Enbridge equity thickness from 36 to 38 per cent.

This is an important adjustment factor available to regulators although it is generally restricted to rate cases. It does however require a very reliable estimate regarding the degree to which the applicant faces stranded asset risk.

Policy Alignment

Stranded asset cases have been around for a long time. However stranded assets caused by the energy transition raise unique problems. That is regulatory decisions that run counter to government policy.

The energy transition by definition is a product of government policy and in many cases serious government investment. This factor proved to be the main feature of the Enbridge case which led the Ontario government to introduce new legislation that would allow the government to overrule certain aspects of the OEB decision. Those that believe strongly in the importance of an independent energy regulator found this to be a troubling development.

A better approach would be to give relevant government agencies adequate notice of any aspect of a proposed hearing that raised the possibility of conflict with government policy. There is no reason why government agencies cannot intervene in regulatory hearings.

The Enbridge case raised a serious legal question. That is, the argument that to the extent an energy regulator issues the decision that conflicts with government policy that regulator is acting beyond its lawful jurisdiction. In the world of energy transition and stranded assets this will be an ongoing problem.  It will be difficult to resolve it by issuing policy directives from the government to the regulators. More dynamic real-time solutions are required.

Agile regulation requires greater transparency. This means notice to all relevant parties including the Minister of Energy. The government is by definition involved in every energy transition case.

This article and these three cases are just the start of what could easily become a very significant reform of Canadian energy regulation. We will keep you posted.

 

* Gordon Kaiser a partner at Energy Law Chambers in Toronto and Calgary.  He is a former Vice-Chair of the Ontario Energy Board and former Market Surveillance Administrator in Alberta.

1. See Re London Hydro Inc. (20 March 2009), EB-2008-0235; Re PowerStream Inc. (27 July 2009), EB-2008-0244; Re Toronto Hydro Electric System (2 April 2013).
2. See James Hoecker, “Used and Useful, Autopsy of a Ratemaking Policy” (1987) 8:303 Energy Law Journal, online (pdf): <www.eba-net.org/wp-content/uploads/2023/02/25_8EnergyLJ3031987.pdf>.
3. ATCO Gas & Pipelines Ltd. v Alberta (Energy & Utilities Board), 2006 SCC 4.
4. Nova Scotia Power Incorporated (Re), 2022 NSUARB 2; Gordon Kaiser, “Canadian Energy Regulators and New Technology: The Transition to a Low Carbon Economy” (July 2021) 9:2 Energy Regulation Q, online: ERQ <energyregulationquarterly.ca/articles/canadian-energy-regulators-and-new-technology-the-transition-to-a-low-carbon-economy>.
5. OEB EB-2022-0200, December 21, 2023, Decision and Order, Enbridge Gas Inc.
6. Ibid at 2.
7. Ibid at 19–21.
8. Ibid at 39.
9. OEB EB-2022-0200/EB-2024-0078, January 29, 2024, Enbridge Gas Motion for Review and Variance, at para 14.
10. OEB EB-2022-0200, October 11, 2023, Reply Argument, at para 11.
11. OEB EB-2022-0200, January 22, 2024, Notice of Appeal, at 5.
12. Supra note 5 at 39.
13. Ibid at 140–141.
14. BCUC Order G-361-23, Fortis BC Energy Inc.
15. BCUC Order G-361-23, December 22, 2023, Decision and Order, at 24.
16. International Renewable Energy Agency, “World Energy Transition Outlook” (2021) at 28, online (pdf): IREA <www.irena.org/-/media/Files/IRENA/Agency/Publication/2021/Jun/IRENA_World_Energy_Transitions_Outlook_2021.pdf?rev=71105a4b8682418297cd220c007da1b9 >.
17. Nova Scotia Power Incorporated (Re), 2022 NSUARB 2.
18. For a detailed background on the project, see William Lahey, “Regulation and Development of a New Energy Industry: Tidal Energy in Nova Scotia” (September 2015) 3:3 Energy Regulation Q, online: ERQ <energyregulationquarterly.ca/articles/regulation-and-development-of-a-new-energy-industry-tidal-energy-in-nova-scotia>.
19. Supra note 17 at para 32.
20. Ibid at paras 89–93.
21. Ibid at para 99.
22. Ibid at para 118.
23. Colleen Kaiser, Geoff McCarney, and Stewart Elgie, “Agile Regulation for Clean Energy Innovation”, (July 2021), at 1, online (pdf): Smart Prosperity Institute <institute.smartprosperity.ca/sites/default/files/WP_Agile_regulation.pdf>.
24. Ibid at 4.
25. Letter of Direction from the Minister of Energy to the Acting Chair of the Ontario Energy Board, (29 November 2023), at 3, online (pdf): <www.oeb.ca/sites/default/files/letter-of-direction-from-the-Minister-of-Energy-20231129.pdf>.
26. Supra note 17.
27. Scott Hempling, “From Streetcars to Solar Panels: Stranded Cost Policy in the United States” (September 2015) 3:3 Energy Regulation Q, online: ERQ <energyregulationquarterly.ca/articles/from-streetcars-to-solar-panels-stranded-cost-policy-in-the-united-states>.