ATCO Electric Ltd. (ATCO Electric) and ATCO Gas and Pipelines Ltd (ATCO Gas), collectively the ATCO Utilities, were regulated under the Alberta Utilities Commission (AUC) second Performance-Based Regulation (PBR) plan from 2018 to 2022 (PBR2). The plan, which was approved in Decision 20414-D01-2016 (Errata), included the reopener provision initially approved in the AUC’s first PBR plan.^[2] The reopener provision was intended…to identify, assess and potentially address design or operational problems within the plan. Reopener provisions are triggered by positive or negative financial results that were unanticipated at the commencement of the plan, material and which cannot be addressed by other features of the plan.^[3]

Under the reopener provision, an achieved return on equity (ROE) that is 500 basis points above or below the approved ROE in a single year, or 300 basis points above or below the approved ROE for two consecutive years, may result in a reopening of the PBR plan, on application from the regulated company or an interested party, or on the Commission’s own motion.

ATCO Electric’s regulatory filings for 2021 and 2022 included financial results that exceeded its approved ROE by 435 and 635 basis points respectively. The ROE for ATCO Gas in the same years exceeded the approved ROE by 331 and 635 basis points. Given these results, the Commission reopened the PBR plans for the ATCO Utilities for 2021 and 2022. On May 22, 2024 the Commission issued Decision 20414-D01-2016 AUC-Initiated Review Under the Reopener Provision of the 2018-2022 Performance-Based Regulation Plans for ATCO Electric and ATCO Gas.

The proceeding set out to determine the factors that contributed to the ATCO Utilities’ achieved ROEs in excess of the approved ROE.

The Commission determined that for ATCO Electric, the main factors were its capital cost savings in 2021 and 2022. For ATCO Gas, the main factors were its capital cost savings in 2021 and 2022 and its operating and maintenance savings in 2022.

The Commission’s approach in the proceeding was to determine what portion of the total cost savings achieved over the PBR Term, and specifically in 2021 and 2022, were quantifiable and explainable with reference to specific programs or initiatives undertaken by the ATCO Utilities during the PBR2 term. The assumption was that any savings that were not attributable to specific programs or initiatives of the ATCO Utilities were not the result of efficiency gains, and therefore the “spending envelope” provided by the PBR2 formula in 2021 and 2022 exceeded the amount required to provide utility service by the relevant unattributed amounts.^[4]

Over the PBR2 term ATCO Electric had total capital savings of $569.9 million. The Commission determined that approximately $183 million was explained and quantified by ATCO. That left approximately $387 million in unquantified and unexplained capital savings.^[5] The Commission also determined, on the same basis, that approximately $28.5 million of ATCO Gas’s total capital savings of $281 million over the PBR2 term were the result of capital-related efficiencies and measurable cost-savings.^[6] ATCO Gas also had operating and maintenance (O&M) savings of $29.6 million in 2022, of which the Commission determined that ATCO had reasonably supported approximately $8.72 million, leaving about $21.1 million of savings unexplained.^[7] Finally, the ATCO Utilities reported approximately $81.5 million in cost savings resulting from full time equivalent (FTE) labour reductions over the PBR2 term.^[8] ATCO Electric explained that it had a 13 per cent reduction in FTEs resulting in cost savings of approximately $21.2 million annually over the PBR2 term, while ATCO Gas had achieved a seven per cent reduction in FTEs, resulting in cost savings of approximately $16.3 million annually.^[9]

Given these results, the Commission questioned whether there was a problem with the design or operation of the ATCO Utilities’ PBR2 plans.^[10] Although the actual capital spend by the ATCO Utilities was significantly below the amount of capital-related funding provided by the I-X and K-Bar mechanisms, the Commission concluded that there were no problems with the design of the K-Bar mechanism. The Commission recognized that the K-Bar mechanism was “meant to allow the utilities to manage costs on a holistic basis to arrive at the optimal mix of O&M and capital expenditures required to fulfill their obligation to provide safe and reliable distribution service.”^[11] The Commission went on to conclude that there were no problems with the design of the other elements of the PBR2 plans and that the evidence in the proceeding did not support a conclusion that there was a flaw in the design of the ATCO Utilities’ PBR2 plans.^[12]

Turning to whether there was a problem with the operation of the ATCO Utilities’ PBR2 plans, the Commission focused on “the lack of quantification and explanation of savings by the ATCO Utilities attributable at any level (i.e., specific amounts, ranges, estimates) to specific programs, projects or initiatives such as those enumerated by the ATCO Utilities.” The Commission noted that “[t]he gap between the amount of cost savings realized by each of ATCO Electric and ATCO Gas over the PBR2 term and the amount that the utilities quantified as being attributable to achieved efficiencies throughout the PBR2 term is inordinate.”^[13]

The Commission stated that it:

…does not expect every dollar of cost savings to be perfectly quantified and apportioned precisely to the specific driver of that dollar of savings. However, it does expect distribution utilities to be aware of the factors, both within and outside of their control, that contribute to the cost savings achieved during a PBR term. The Commission also expects that utilities will be able to adequately explain the difference between revenues provided by the PBR formula and the actual costs incurred with reference to the associated quantified cost savings attributable to those factors or, in instances where such quantification and explanation is not feasible, with a reasonably robust description of the utility’s choices and actions (supported by evidence such as business cases or corporate directives) that led to the related reduction in costs.^[14]

The Commission went on to adopt the following basis for its decision:

While the Commission is not bound by the rules of evidence, in this Commission initiated proceeding and considering the information asymmetry that is inherent in the regulation of utilities, it finds that it is appropriate to adopt principles related to negative inferences; in particular, that a decision maker can  draw a negative inference from the  absence of relevant information on  the record and may conclude that the matter that was not recorded did not  occur or exist.^[15]

The Commission concluded that:

The magnitude of the savings that were neither quantified nor attributed to particular projects, programs or initiatives by the ATCO Utilities has led the Commission to conclude that the savings cannot  be attributed to utility-driven  efficiency gains resulting from the  incentives intended under PBR. The Commission’s view is that much of the ATCO Utilities’ unquantified  and unexplained savings were  the result of factors other than  efficiencies, including those asserted by the interveners, such as the ATCO Utilities opting to not pursue certain capital projects (what the UCA and the CCA referred to as “lower workloads”), and realizing cost savings as a result of COVID-related externalities including supply chain disruptions that prevented the ATCO Utilities from executing certain required projects. These decisions are made by each of the ATCO Utilities in response to their PBR2 plans and are therefore operational, rather than structural in nature.

The Commission therefore finds that the PBR2 plans of ATCO Electric and ATCO Gas did not operate as intended in each of 2021 and 2022. The result is rates that  were not just and reasonable in  those years because customers were  required to pay rates (including  the rates of return achieved by the  ATCO Utilities that exceeded the  approved return and the threshold  for the reopener) without receiving  the benefit of more efficient utility  service. In other words, the operation of the plans was inconsistent with the bargain that is inherent in PBR, and customers paid more than what was reasonably required for the provision of safe and reliable utility service. The Commission finds that this constitutes a problem with the operation of each of ATCO Electric’s and ATCO Gas’s PBR2 plans.^[16]

Having determined that there was a problem with the operation of the ATCO Utilities’ PBR2 plans that cannot be resolved without reopening and reviewing the plans, the Commission turned to the matter of a remedy and the applicable time period over which the remedy should be applied. The Commission set out the scope and preliminary process steps for a Phase 2 proceeding to deal with this matter, noting that “[b]ecause the PBR2 plans are complete, an adjustment to the PBR2 plans on a go-forward basis is not a possible remedy.”^[17] The Commission concluded that:

…an appropriate remedy may be in the nature of refunds to the ATCO Utilities’ customers that relate to the quantum of savings that were not supported through evidence of quantified efficiencies and explanations of the drivers and sources of those efficiencies, which resulted in savings.^[18]

Perhaps recognizing the challenges in determining an appropriate remedy, the Commission authorized and encouraged the parties to commence a negotiated settlement process.^[19]

A SHIFT IN FOCUS

The approach undertaken by the Commission in Decision 28300-D01-2024^[20] is very different from the approach adopted by the Commission in a previous re-opener proceeding resulting in Decision 23604-D01-2019^[21], which is discussed below. The Commission’s approach signals a noteworthy shift in the focus and attitude of the Commission between 2019 and 2024. This shift is likely attributable to two significant events.

Affordability

The Alberta Government established a new Affordability and Utilities Ministry. The minister’s mandate letter includes objectives relevant to the AUC.

Reviewing the operations, policies, and mission of your agencies, including the Alberta Utilities Commission and the Alberta Electric System Operator, and recommending ways to improve their operations and align its mission with the government’s goal of a carbon neutral, reliable, and affordable power grid by 2050.

Reviewing Alberta’s electricity pricing system with the goal of reducing transmission and distribution costs for Albertans.^[22]

The focus of the AUC is now more aligned with issues of affordability than was the predecessor Commission. This is apparent in recent decisions of this Commission. For example, in Decision 26356-D01-2021: Evaluation of Performance-Based Regulation on Alberta,^[23] the Commission concluded that the sharing of benefits among customers and the utilities was not adequate during the two previous PBR terms, noting that:

Although the evidence suggests that customers experienced lower rates under PBR than would be expected under COS regulation and some sharing of savings occurred during rebasing for the 2018-2022 PBR plans, rates continued to increase during an economic downturn in Alberta and utility earnings during this same period were characterized by the interveners as excessive.^[24]

In Decision 27388-D01-2023: 2024-2028 Performance-Based Regulation Plan for Alberta Electric and Gas Distribution Utilities,^[25] the Commission sought to “secure better sharing of total benefits of PBR between utilities and their customers”^[26] by introducing into the PBR3 plans an asymmetric, two-tiered earnings sharing mechanism and an X factor premium of 0.3 per cent.

The focus of the Commission now appears to more sharply consider the goal of reducing transmission and distribution costs for Albertans in alignment with Government of Alberta policy objectives. This is not to say that the prior Commission was blind to issues of affordability, however, the focus of the PBR1 and PBR2 plans was arguably on maximizing efficiency incentives, recognizing that consumers benefited from the caps on rates and revenues in the plans and from the recognition of achieved efficiency gains when rebasing was undertaken at the end of the PBR regimes.

It is not a criticism that the Commission is attuned to Government policy objectives with respect to issues of affordability. Indeed, regulators often adopt public policy objectives related to affordability or decarbonization goals, for example, with or without governing legislation that compels them to do so. For example, PBR plans in Massachusetts and Hawaii include elements such as earnings sharing, consumer dividends, scorecards and metrics, and other performance incentive mechanisms designed to encourage the achievement of public policy objectives. Nor should the Commission be criticized for adopting what it sees as a more equitable sharing of the benefits of PBR in its PBR3 regime. The question is whether its current public policy lens should be applied to the PBR2 outcomes; outcomes that may well align with the objectives of the Commission panel that approved those plans.

A loss of trust

In 2022, ATCO Electric agreed to pay a $31 million administrative penalty after an AUC investigation found it deliberately overpaid a First Nations group for work on a new transmission line, and then failed to disclose it when it applied to include the extra cost in its application for approval of the Jasper Transmission Interconnection Project.^[27] In July 2024, ATCO again agreed to pay $3 million in fines and to refund $4 million to customers for two additional contraventions of the Electric Utilities Act with respect to proceedings before the AUC.^[28] These missteps likely coloured the Commission’s perspectives on ATCO. There is pointed language in Decision 28300-D01-2024 that suggests the Commission simply did not believe the ATCO evidence.

In the oral hearing, D. McHugh stated that the ATCO Utilities do not have the information required to reconcile their cost savings any further than what has already been provided on the record of this proceeding. The Commission finds  this statement to be inconsistent with  other statements the ATCO Utilities made in this proceeding related to  their sophisticated and superior  business management… The ATCO Utilities’ evidence of their ability to set performance targets and to measure performance at such a granular level is not consistent with their professed inability to determine the source of organization-level cost savings.^[29]

Again, there is an inconsistency between the ATCO Utilities’ evidence of their ongoing monthly processes to manage their capital and O&M programs and their evidence that they do not have a record of what programs resulted in a significant majority of capital, and in the case of ATCO Gas, O&M cost savings…

.^[30]

It seems evident that the Commission did not believe that the ATCO Utilities were unable to provide the information the Commission requested to further demonstrate that the achieved cost savings were attributable to achieved efficiencies. There is a maxim in public utility regulation that a regulated company is loathe to lose the trust and unbiased goodwill of the regulator. That maxim may well have been proven in the proceeding leading to Decision 28300-D01-2024.

ISSUES ARISING

Was it reasonable to expect ATCO to demonstrate that its earnings resulted from utility-driven efficiency gains?

Referencing Decision 28300-D01-2024^[31], the Commission noted that “the ATCO Utilities themselves were in a similar proceeding previously and were able to quantify and attribute their costs savings.”^[32] However, a review of the record of that proceeding and Decision 23604-D01-2019 would argue that ATCO was unable to fully quantify and attribute their cost savings to utility-driven efficiency gains resulting from the incentives intended under PBR.

In that proceeding, the Commission requested that the ATCO companies provide:

an analysis of items that contributed to the achieved ROEs exceeding the approved ROE in each of 2016 and 2017, for capital and operating and maintenance costs (e.g., productivity improvements implemented by the utility, externally driven factors affecting costs). In addition, identification of any attributes of the PBR features that affect revenues that may have contributed to the achieved ROEs exceeding the allowed ROE in each of 2016 and 2017 (e.g., going-in rates, I-X adjustments, customer growth, Y factors, Z factors, K factors).^[33]

In response, the companies provided financial results showing variances across revenue and cost categories and evidence of a number of factors that contributed to the achieved ROEs, but did not provide a full accounting of the efficiency gains resulting from the incentives intended under PBR. In response to a Commission information request that asked ATCO to complete tables detailing the cost reductions and their associated effect on earned ROE from 2015 to 2016 and 2016 to 2017, the ATCO Utilities argued that they were unable to provide the level of detailed reporting requested by the Commission. ATCO stated:

ATCO is unable to calculate the effect on earned ROE for each productivity improvement as ATCO has not tracked revenue, O&M costs and capital costs associated with every activity. Under PBR, there is no direct link between costs and revenue… It is not possible to re-establish a link between revenue and costs, after the fact, in an attempt to explain the overall results of the utilities. This is exacerbated by the fact that the utilities did not track this kind of information, and in fact took deliberate steps to eliminate all unnecessary reporting and tracking as a key aspect of the culture change required to drive out efficiencies. Had detailed tracking of costs with a linkage to revenues been undertaken over the first term, the incentives would not have been as strong and the effort required to administer such tracking would have resulted in fewer efficiencies found.^[34]

The Commission accepted the evidence of the ATCO utilities with respect to the factors that contributed to the achieved results in 2016 and 2017 as evidence that the companies responded to the incentives intended under the PBR plan. The bulk of the decision, however assessed a number of alleged faults with the PBR plan to determine whether there was sufficient evidence to conclude that the earnings achieved by the ATCO Utilities above the Commission’s generically approved ROE were the result of a problem with the design or operation of the ATCO Utilities’ 2013–2017 PBR plans. The Commission found that there was no evidentiary basis to conclude that the earnings achieved by the ATCO Utilities above the Commission’s generically approved ROE were the result of a problem with the design or operation of the ATCO Utilities’ 2013–2017 PBR plans.

Given this precedent, could the ATCO Utilities have reasonably understood that they would be required to have the information necessary to reconcile all of their cost savings to achieved efficiency gains?

Is it reasonable to require utilities under PBR to demonstrate that their earnings resulted from utility-driven efficiency gains?

Productivity is generally measured as the ratio of total outputs to total inputs in the production process of the firm. Total factor productivity (TFP) growth, which Is the measure of industry productivity used to establish the productivity offset (X Factor) in PBR plans such as those approved by the AUC, is the difference between the growth in outputs and the growth in inputs over time, based on a year-over-year index of output and input growth. The firm’s own input and output data can theoretically be used to derive a company-specific productivity growth estimate and, alternatively, the Kahn Method can be used to calculate a productivity growth estimate based on financial data as opposed to the outputs measured in TFP growth studies. Given how productivity is calculated in a PBR plan, it is difficult to relate achieved productivity growth results to specific activities of the firm.

PBR incentivizes three types of efficiencies:

• Productive efficiency: Taking customer demand as given, the utility satisfies that demand at the least cost possible and operates as close as possible to the frontier of the “production possibility set”, which characterizes a firm operating at the most efficient level possible.

• Allocative efficiency: Considering that customer demand for outputs and services can change based on their price, the utility provides the highest value range of outputs and services, given the least-cost mix of current inputs and future cost structure and technology.

• Dynamic efficiency: The utility finds the optimal rate of innovation and investment to improve production processes, satisfy evolving consumer demand and reduce long-run average cost. To the extent that it provides more flexibility to introduce new services and/ or more attractive rate plans, PBR can increase dynamic efficiencies.

Even though a company may undertake specific programs aimed at achieving identifiable efficiencies, in practice efficiencies are achieved through a myriad of activities throughout an organization at every level. In a given year, there are an almost infinite number of decisions made by utility managers that impact costs. Allocating cost savings into those due to the plan and those that would have happened in any event is a challenge and almost certainly unquantifiable. Is it reasonable to keep track of all of them and then say which are due to efficiency decisions and which would have happened anyway with or without a PBR regime? On an accounting basis, budgets are set to achieve cost and revenue targets under the price or revenue cap. Some targets are achieved, others are not. And, although companies are capable of providing financial results showing variances across revenue and cost categories that align with their system of accounts, relating many of these variances to a measure of productivity growth is a different exercise. Likewise attributing any earnings beyond the allowed ROE to productivity growth resulting from specific utility activities is likely not fully achievable, and likely beyond the objectives of the Commission when it approved the PBR2 plans.

PBR allowed the Commission to set just and reasonable rates and to incentivize the companies to minimize their costs without having to obtain or consider cost information from the companies beyond the initial information required to set going-in rates. The reduced need for the Commission to obtain information on the companies’ costs and avoid the problem of informational asymmetry was one of the objectives of the Commission when it initially adopted PBR. Among the reasons for adopting PBR, the Commission included:

…rate-base rate of return regulation is increasingly cumbersome in an environment where some companies offer both regulated and unregulated services and where operations that were formerly integrated have been separated into operating companies, some of which require their own rate and revenue requirement proceedings… These conditions complicate the task for regulators who must critically analyze in detail management judgments and decisions that, in competitive markets and under other forms of regulation, are made in response to market signals and economic incentives. The role of the regulator in this environment is limited to second guessing.^[35]

When the Commission approved PBR2, it did not contemplate that the companies would, or should, be required to attribute any earnings beyond the allowed ROE to efficiency gains resulting from specific activities. In addition, there is no such requirement in Decision 27388-D01-2023 which approved the PBR3 plans. If the Commission now intends to adopt a PBR regime that requires companies to undertake such an accounting, then perhaps the current PBR regime will need to be reconsidered.

Did the PBR2 plans operate as intended?

The PBR2 plans may have operated as the Commission intended when the plans were approved. It is noteworthy that the Commission, in Decision 28300-D01-2024, determined that that there were no problems with the design of the PBR2 plans, but determined that there was a problem with the operation of the plans in 2021 and 2022. A corollary of the latter determination is that the design of the PBR2 plans was such that it was unworkable under the conditions that prevailed in 2021 and 2022; the COVID and post-COVID era that resulted in lower workloads, delayed capital investments and cost savings resulting from COVID-related externalities. If that is not the case, then arguably the plans worked as designed.

The productivity offset in the PBR2 plans was based on TFP studies that measured long-run industry productivity, recognizing that productivity fluctuates over time. The level of achieved productivity is not uniform, and it may be periodically positive or negative from one year to the next. However, over the long run, an average level of productivity, whether positive or negative, is realized. Had the PBR2 term played out beyond 2022, the gains achieved, and the resulting positive ROEs, may have been negated in subsequent years when the lower workloads and delayed but necessary capital investments experienced in 2021 and 2022 were potentially reversed. On an accounting basis, the increase in retained earnings arising from the ROE results in 2021 and 2022 might have been re-invested in the operations and capital investment requirements beyond 2022 to catch up after the lingering effects of COVID ended.

Alternatively, was there the potential that the effects of COVID on the lower workloads and delayed capital investments experienced in 2021 and 2022 could have been the result of exogenous events that were rightfully dealt with as a Z Factor event under the PBR2 plans? In Decision 20414-D01-2016 (Errata) the following criteria were to be applied when evaluating whether the impact of an exogenous event qualifies for Z factor treatment:

(i) The impact must be attributable to some event outside management’s control.

(ii) The impact of the event must be material. It must have a significant influence on the operation of the distribution utility; otherwise the impact should be expensed or recognized as income, in the normal course of business.

(iii) The impact of the event should not have a significant influence on the inflation factor in the PBR formula.

(iv) All costs claimed as an exogenous adjustment must be prudently incurred.

(v) The impact of the event was ^[36]

Might the cost savings have been considered as exogenous and remedied as a Z Factor adjustment under the plans? However, the criteria for a Z factor adjustment appear to contemplate that only costs can be claimed as an exogenous adjustment. They do not mention savings resulting from exogenous events qualifying for Z Factor treatment.

The plans came to an end, and the going-in rates were rebased, which accounted for at least a portion of the gains in 2021 and 2022 being recognized in the subsequent PBR term, as the revenue requirements of ATCO Gas and ATCO Electric decreased by $51 million and $41 million, respectively.^[37] All of which may be as intended in the decision approving the PBR2 plans. In any event, it would seem that the revenue requirement reductions at rebasing should be considered when calculating the Commission’s remedy to avoid double counting.

What constitutes just and reasonable rates in a PBR plan?

The upshot of Decision 28300-D01-2024^[38] is that rates are just and reasonable under PBR only when any earnings beyond the allowed ROE can be attributed to utility-driven efficiency gains resulting from the incentives intended under PBR. This may prove to be problematic. The earnings sharing mechanism adopted in PBR3 requires that achieved earnings in excess of 100 basis points be shared with consumers. There is now the potential that parties will argue that any portion of the shared earnings accruing to the utility should rightfully accrue to consumers, unless the utility can demonstrate that the earnings resulted from utility-driven efficiency gains.

Under Cost of Service Regulation (COSR) if the approved rates allowed the company to recover its prudently incurred costs including a reasonable opportunity to earn a fair return, as determined by the regulator, then the rates are just and reasonable. Until they aren’t at which time the company would apply for, or the regulator would initiate, a proceeding to reset rates on a going forward basis.

PBR, by contrast, results in just and reasonable rates by directly regulating the rates the utility can charge by setting of rates and then governing them over the PBR term through the I-X formula and other mechanism of the PBR plan, irrespective of the utility’s actual costs or the profits the utility earns. Revenues and costs are de-linked for the duration of the plan. Under PBR, rates are considered just and reasonable if the going-in rates at the outset of the PBR term are just and reasonable, on the same basis as under COSR. They are assumed to remain just and reasonable until the PBR term ends and going-in rates are re-set for the next PBR term.

Decision 28300-D01-2024^[39] appears to have redefined what constitutes just and reasonable rates under PBR.

Does Decision 28300-D01-2024 constitute retroactive ratemaking?

One of the issues in this decision is whether it constitutes retroactive rate making. It is not clear in the wording of the Commission’s PBR decisions going back to Decision 2009-035 that the Commission intended that any necessary remedy resulting from a re-opening of a PBR plan should be applied retroactively. And the question now is whether it can be.

Under COSR, rates were set on a going forward basis and remained unchanged until the company returned with an application to update its revenue requirement and set new rates, or the Commission commenced a proceeding to do so. If the company was able to provide service at costs that were less than forecasted, or if billing units were greater than forecasted, the company was permitted to keep any ROE above the allowed ROE established when rates were set. The Commission was prohibited from adjusting rates to claw back the earnings achieved by the company in excess of the allowed ROE because doing so constituted retroactive ratemaking. And likewise, if the company was unable to earn its allowed return in the prior period, the rates in the subsequent period would not include recovery of the prior period shortall. Any earnings attrition remained to the account of the company.

Under PBR, rates and costs are de-linked. The going-in rates are set in a fashion similar to COSR, but rates are adjusted annually according to the PBR formula so that the company is afforded an opportunity to stay out longer between rate setting proceedings. At rebasing, as with COSR, the revenue requirement to set going-in rates for the next PBR period considers the actual results from the previous period so that customers receive the benefit of the company‘s improved productivity (lower costs and/or higher billing units) in the rates for the next period. And, as with COSR, the earnings of the company in the prior period are not clawed back, largely because doing so would blunt the intended efficiency incentives of PBR, and because doing so would likely be deemed retroactive ratemaking. Likewise, if the utility experiences earnings attrition under the PBR plan, the company does not recoup its losses in the subsequent PBR term. However, Decision 28300-D01-2024 has modified the landscape.

More importantly, it raises the issue of whether the Commission can retroactively remedy a finding that there is a problem with a PBR plan. Or can the remedy only be applied on a going forward basis, by adjusting the parameters of the next PBR plan. As with COSR, is the Commission prohibited from applying its remedy in such a way that any over-earning or under-earning in a prior period is paid to or recovered from customers in a subsequent period? And it is certainly not clear that the re-opener provision was intended to retroactively remedy any design or operational problems in a PBR plan. Does doing so constitute retractive ratemaking?^[40]

CONCLUDING REMARKS

This decision will likely have implications into the future for the Commission, the companies it regulates and consumers, some of which may not yet have come to light. Among others, it may serve to blunt the intended management efficiency incentives of PBR and sour utilities on continuing PBR regulation. Some of the issues this decision raises may result in changes to the design of PBR plans in Alberta, and potentially in other jurisdictions. In addition, some issues will certainly find their way into the Alberta Court of Appeal. Some may manifest themselves in the responses of the regulated utilities to PBR, while others may affect consumers in the years ahead. It will be insightful to follow the aftermath of this decision.

1. At the time of writing, the decision has not been appealed.

* 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.

As a former Chair of the Alberta Utilities Commission, I read Decision 28300-D01-2024 with great interest. My objective in this article is to point out issues that, from my perspective as a former regulator, arise in this decision. I do not offer any legal opinions on the decision as I am not a lawyer.

2. AUC-Initiated Review Under the Reopener Provision of the 2018-2022 Performance-Based Regulation Plans for ATCO Electric and ATCO Gas (22 May 2024), AUC 28300-2024, online (pdf ): Alberta Utilities Commission <efiling-webapi.auc.ab.ca/Document/Get/806783>.
3. 2018-2022 Performance-Based Regulation Plans for Alberta Electric and Gas Distribution Utilities (6 February 2017), AUC 20414-2016, at para 261.
4. The term “spending envelope” does not appear in the decision.
5. Supra note 2 at para 73.
6. Ibid at para 76.
7. Ibid.
8. Ibid at para 74.
9. Ibid at para 69.
10. Ibid at para 78.
11. Ibid at para 87.
12. Ibid at para 90.
13. Ibid at para 95.
14. Ibid at para 96.
15. Ibid at para 110 [emphasis added].
16. Ibid at paras 111–12 [emphasis added].
17. Ibid at para 177.
18. Ibid.
19. Ibid at para 178.
20. Ibid.
21. AUC-Initiated Review Under the Reopener Provision of the 2013-2017 Performance-Based Regulation Plan for the ATCO Utilities, AUC 23604-D01-2019.
22. Letter from Premier of Alberta Danielle Smith to the Minister of Affordability and Utilities Nathan Neudorf (19 July 2023), online (pdf ): <open.alberta.ca/dataset/bf7f9a42-a807-49b3-8ba3-451ae3bc2d2f/resource/9ebd0656-8e60-45f4-ad06-41f06a3177eb/download/au-mandate-letter-affordability-and-utilities-2023.pdf>.
23. Evaluation of Performance-Based Regulation in Alberta (30 June 2021), AUC 26356-D01-2021, online (pdf ): <efiling-webapi.auc.ab.ca/Document/Get/701629>.
24. Supra note 2 at para 79.
25. 2024–2028 Performance-Based Regulation Plan for Alberta Electric and Gas Distribution Utilities (4 October 2023), AUC 27388-D01-2023, online (pdf ): Alberta Utilities Commission <efiling-webapi.auc.ab.ca/Document/Get/794425>.
26. Ibid at para 327.
27. Rob Drinkwater, “ATCO Electric agrees to $31 million penalty following regulator’s investigation” (18 April 2022), online: <www.cbc.ca/news/canada/edmonton/atco-electric-penalty-investigator-transmission-line-1.6422427>.
28. Bob Weber, “ATCO Electric fined $3 million for unearned rate increases, overstating its costs” (9 July 2024), online: <calgary.citynews.ca/2024/07/09/atco-contraventions-fines>.
29. Supra note 22 at para 107 [emphasis added].
30. Ibid at para 108 [emphasis added].
31. The author was on the AUC panel that issued Decision 23604-D01-2019.
32. AUC-Initiated Review Under the Reopener Provision of the 2018-2022 Performance-Based Regulation Plans for ATCO Electric and ATCO Gas, (22 May 2024), AUC 28300-D01-2024, at para 100, online (pdf ): <efiling-webapi.auc.ab.ca/Document/Get/806783>.
33. Supra note 21 at para 16.
34. Ibid, exhibit 33.
35. Rate Regulation Initiative, Distribution Performance-Based Regulation, (12 September 2012), AUC 2012-237, at para 14.
36. Supra note 2 at 91.
37. Supra note 32 at para 114.
38. Ibid.
39. Ibid.
40. The Commission previously allowed a company to recover a significant shortfall resulting from a formula based regulation plan that was approved for a transmission company; however, the decision was unchallenged and settled by way of a negotiated settlement.