In relation to the Alberta Utilities Commission (AUC), the Alberta Court of Appeal issued two decisions of note in 2023; in both cases the AUC’s decision was overturned. The Alberta Government also temporarily paused the AUC’s ability to approve new renewable projects.

2016 FORT MCMURRAY WILDFIRE COSTS

In ATCO Electric Ltd v Alberta Utilities Commission,^[1] the Court considered the Commission’s 2019 decision^[2] to allocate the undepreciated costs of ATCO’s electric distribution system assets destroyed by the 2016 Fort McMurray wildfire to the account of ATCO’s ratepayers, and not its shareholders.

The Commission’s approach was informed by the principles it extracted from the Supreme Court of Canada’s seminal Stores Block^[3] decision, and the Commission’s subsequent Utility Asset Disposition (UAD) policy decision.^[4]

Consideration of the Stores Block case, all subsequent AUC and judicial decisions which applied it, and the UAD decision, is well beyond the scope of this summary. There has been almost twenty years of litigation on various asset disposition fact patterns in Alberta. The cases have not provided a clear picture for investors or ratepayers regarding how stranded assets should be treated. This observation comes from both industry commentators and the AUC itself. The Court’s 2023 decision potentially provides an element of incremental certainty, but only to one class of cases; assets destroyed by a wildfire.

The Commission’s decision applied the UAD principles, particularly the depreciation principles previously adopted by the Commission in the UAD decision, in allocating the losses associated with the premature retirement of utility assets.

Pursuant to those principles, to determine whether the residual value of the destroyed assets was to be allocated to the shareholder or ratepayer, the Commission examined whether the retirement was “extraordinary”^[5] or “ordinary.”^[6] This was important because, according to the depreciation-based principles being applied, an “extraordinary”^[7] retirement resulted in the residual value being allocated to shareholders and an “ordinary”^[8] retirement resulted in the residual value being allocated to ratepayers. Finally, the question of whether an event was “extraordinary”^[9] or “ordinary”^[10] turned on whether the utility’s most recent depreciation study considered the risk of assets being retired in events with similar characteristics. If the study considered that risk, the event was “ordinary”^[11] and, if not, the event was “extraordinary.”^[12]

In the case of the assets destroyed by the Fort McMurray wildfire, the Commission found there was no recognition or incorporation of similar events in ATCO’s depreciation study. As a result, the Commission found that the asset retirements should be characterized as “extraordinary.”^[13] The Commission assigned the residual value of the destroyed asset to ATCO’s shareholders.

Critical to the Commission’s reasoning was the continued application of the Commission’s conclusion in the UAD decision that the effect of the Stores Block decision and subsequent court cases was to limit the Commission’s flexibility in dealing with cost allocation issues. More specifically, the Commission interpreted the seminal finding by the Supreme Court, that utility customers do not acquire any proprietary interest in a utility’s assets^[14], to mean that because assets used for utility service are the property of the utility service provider, any gain or risk of loss with respect to that original investment would be for the account of the owner of the property.

The Court of Appeal made short work of that constraint. The Court found that the Commission erred in law in finding that its options for dealing with assets destroyed by natural disasters were constrained by Stores Block. The Court observed that the Stores Block case dealt with the sale of assets as opposed to assets destroyed by wildfire, and that it did not bind the Commission in setting a just and reasonable tariff in relation to the losses at issue. With that finding, the matter was referred back to the AUC for reconsideration.

In Reconsideration of ATCO Electric Ltd. Z Factor Adjustment for the 2016 Wood Buffalo Fire decision^[15] the Commission reconsidered the matter in light of the Court’s direction. The Commission found that, in the context of the Fort McMurray wildfire, assigning the residual value of the destroyed assets to ATCO’s shareholders removed ATCO’s reasonable opportunity to recover its costs.

This result recognizes the destroyed assets had been in rate base, had been deemed prudent and, although now destroyed for reasons outside of ATCO’s control, the replacement assets continued to be required for utility service.

The Commission was careful to limit this reasoning to the facts before it (being assets destroyed by wildfire). However, having ratepayers bear asset costs that result from natural disaster causes is arguably not consistent with the no acquired rights reasoning in Stores Block, but is more aligned with the pre-Stores Block regulatory approach of having ratepayers and shareholders share both the benefits and burdens of utility service, depending on the circumstances.

The Court also clarified that pre-Vavilov^[16] cases continue to be presumptively binding precedent, notwithstanding the change in standard of review analysis. The ATCO argument in this regard was aimed at the Court’s imprimatur of the Commission’s UAD decision in FortisAlberta Inc v Alberta (Utilities Commission).^[17]

AESO CUSTOMER CONTRIBUTIONS

A second decision of note is the Court of Appeal’s decision in Alta Link Management Ltd v Alberta Utilities Commission.^[18]

The case involves the question of who should pay for new transmission facilities and whether or not customer contributions should be used to finance the required investment.

Customer contributions are a longstanding financing and regulatory tool used to balance the obligation to serve customers against the risk of building facilities to serve one or a few customers, that will be paid for by other customers in general rates. The contribution policy is normally based on collecting the excess of project connection costs over forecast customer supporting revenue.

In the old vertically integrated world, customer contributions were not an issue. The regulator would approve the utility’s investment policy and that policy would dictate when a contribution was required to provide service. When a contribution was required and paid by a ratepayer to a utility, for regulatory accounting purposes, that contributed capital was excluded from rate base. These customer payments (variously called customer contributions or contributions in aid of construction) tend to be temporary in nature and are re-paid by the utility over the useful life of the related facility.

When Alberta restructured the electricity market 25 years ago to support competitive generation supply and retail services, these changes introduced a new commercial interface between the transmission and distribution systems that did not exist in the old vertically integrated world. In addition, to facilitate a competitive wholesale market, the administration of access to transmission lines was placed in the hands of an independent third party, called the Transmission Administrator (TA). Today the TA has become the Independent System Operator, which operates under the business name of the Alberta Electric System Operator (AESO).

In its new terms and conditions for transmission system access, the AESO developed a contribution policy that introduced price signals to the transmission/distribution interface to ensure the efficient and economic development of transmission facilities.

What this meant is that distribution companies would be required, in certain circumstances, to pay a customer contribution when requesting service from the AESO.

It is fair to say that the AESO’s contribution policy, when first approved in 2000 by the Commission’s predecessor, was highly contentious. It was widely recognized, even by the regulator, that the policy, once implemented, might present difficulties over time. As it turns out, the decision to send a price signal to distribution companies in the contribution policy created incentives and results that the Commission attempted to address in its decision that is the subject of this appeal.

The incentives and outcomes tackled by the Commission are best explained through an example.

A distribution utility is receiving requests for service in a frontier area of Alberta. The utility evaluates the request to determine whether the best economic solution for serving the load is a distribution or transmission addition. If the distribution solution is chosen, the utility’s contribution policy requires it to determine if the costs of the facility should be allocated to all customers on the distribution system (no risk the revenues will not match the project costs) or to one or more of the customers requesting service (a risk of revenue shortfall).

If a contribution is required, the utility collects it from the customers and that contributed capital is an offset to its rate base.

If the distribution utility concludes that a transmission system extension or expansion is the best solution, the utility approaches the AESO to request service.

At this point, the AESO determines whether a transmission solution is indeed the most economical solution to provide the requested service and, if so, whether a customer contribution is required to be paid by the distribution utility. In making that determination, the distribution utility provides the AESO with all the information required to support the decision to plan, design and build a transmission facility, including forecasted load growth, the type of load and the number of customers. This information is critical in making the determination whether the anticipated revenue will meet the required investment. If so, the load is classified as system and the investment costs are rolled in and paid by all transmission ratepayers. If there is a forecast revenue shortfall, a customer contribution will be required.

If a customer contribution is assessed against the distribution utility, it has the discretion to allocate these costs to one or more customers behind the transmission/distribution interface (called the “POD” or point of delivery), to all customers behind the POD or to all ratepayers on the distribution system.

If the utility passes through the customer contribution to its customers, whether one or more, the money collected by the utility is paid to the transmission company selected by the AESO to build the new transmission capacity and the payment is expensed for accounting and regulatory purposes.

If the distribution utility makes the determination that the contribution cost should be allocated to all ratepayers on the distribution system, the distribution company pays the contribution itself. However, for accounting and regulatory purposes, the customer contribution ultimately paid by the distribution utility to the transmission utility is added to the distribution utility’s rate base and that capital earns a return until the related assets are fully depreciated.

The customer contribution received by the transmission utility is an offset to its rate base and reduces its asset base for revenue requirement purposes.

This potential outcome creates an incentive for the distribution utility to cherry pick between the distribution company and AESO’s customer contribution policies. The choice of a transmission solution, with a customer contribution paid by the distribution utility (a system allocation) provides an opportunity to augment its capital basis and earnings.

On the other hand, the contributed capital received by the transmission utility is treated as an offset to its asset base, diminishing the capital basis and its earnings even though it built and operated the related transmission facility.

The Commission sought to remove the distribution utility’s incentive to favour a transmission solution by eliminating the practice of adding the customer contribution it pays to its rate base when it allocates the contribution to all distribution ratepayers. It also held that the transmission utility should not be able to add the customer contribution received to its rate base.

The Court found that the Commission had not provided sufficient notice that the opportunity to earn a return on customer contributions might be eliminated for both transmission utilities and distribution utilities and returned the matter to the Commission for reconsideration. The Commission has not issued its reconsideration decision.

RENEWABLE GENERATION PAUSE AND INQUIRY

On August 3, 2023, the Minister of Affordability and Utilities directed the Alberta Utilities Commission to pause approvals for new renewable electricity generation projects until February 29, 2024.^[19] The same day, the Minister directed the Commission to inquire and report on specific land use issues regarding renewable power plants, and the impact increasing growth of renewables has to both generation supply mix and electricity system reliability. The Commission was directed to file a report making findings or providing observations to the Minister no later than March 29, 2024.^[20]

The Commission separated the inquiry into two modules: Module A to address the land use issues; and Module B to explore the supply mix and system reliability issues.^[21]

In Module A, the Commission retained experts to prepare reports on the various issues being considered. These included: examining the impacts of renewable power plants on agricultural lands and pristine viewscapes; whether to implement mandatory reclamation security requirements to address renewable power plant abandonments costs; and the potential for developing renewable power plants on Crown lands.

The Commission, in its Module A Report^[22], provided observations, commitments relating to changes to AUC practices and procedures, as well as options for the government to consider in relation to potential legislative or policy changes. In addition, the Commission considered the role of municipal governments in the development and review of renewable projects.

The Minister has reviewed the Module A Report and signaled the policy changes the Alberta Government will be pursuing through legislation before the end of 2024.^[23]

While the pause of renewable project approvals may have come as a surprise to the sector, prior to it, the Commission had been scrutinizing renewable projects more closely, including denying applications or increasing the use of conditions and mitigation measures to address stakeholder concerns.

Four decisions in 2023 are notable in this vein.

On April 20, 2023, the Commission denied an application for the Foothills Solar Project^[24]. The denial was based in part on the potential for the project to result in high bird mortalities and the project siting on the Frank Lake International Bird Area (IBA). Approximately 80 per cent of the project was sited within the Frank Lake IBA setback.

On July 20, 2023, the Commission denied an application for the construction and operation of the Burdett Solar Project.^[25] Again, the denial was based on project siting resulting in unacceptable risks to migratory birds and water birds.

On July 19, 2023, the Commission also denied an application to connect the Nova Solar Power Plant^[26] to the grid in response to a deficient route siting and stakeholder consultation process.

Lastly on November 8, 2023, the Commission in the AECG Forty Mile Wind GP Corp decision,^[27] denied the location of two turbines for the Halkirk 2 Wind Power Project due to unacceptable aviation safety risk associated with flight operations at a nearby aerodrome.

The Alberta government’s comprehensive policy review and resulting policy direction will provide clarity for proponents in considering projects and their design, and will assist the Commission in its assessment of projects in light of recent precedents.

With respect to Module B, the Commission was charged with considering the impacts of the increasing growth of renewables to both generation supply mix and electricity system reliability.

The Commission used three analytical approaches, including a quantitative market and financial modelling of the Alberta power market, a forecast of future consumer electricity bills, and a qualitative assessment of the attractiveness of the Alberta power market.

The Module B Report was provided to the Minister of Affordability and Utilities on March 28, 2024.

While the Module B Report has not been made public, the Minister has already directed^[28] the AESO^[29] and MSA^[30] to pursue changes to the Alberta power market. Those changes include introduction of a mandatory day ahead market, centralized unit commitment and mechanisms to encourage investment in generation that value dispatchability and reliability attributes. The Government of Alberta has also announced it is evaluating proposed changes to the Transmission Regulation.^[31] That Regulation enshrines the somewhat unusual regulatory framework of a fully uncongested grid paid for by load through postage stamp rates. Potential changes to that framework, could result in renewable generators paying an increased share of transmission costs, and potentially facing higher amounts of congestion.

* Bob Heggie is the Chief Executive for the Alberta Utilities Commission.

1. ATCO Electric Ltd v Alberta Utilities Commission, 2023 ABCA 129.
2. ATCO Electric Ltd, Z Factor Adjustment for the 2016 Regional Municipality of Wood Buffalo Wildfire (2 October 2019), 21609-D01-2019, online (pdf): Alberta Utilities Commission <efiling-webapi.auc.ab.ca/Document/Get/799233>.
3. ATCO Gas & Pipelines Ltd v Alberta (Energy & Utilities Board), 2006 SCC 4 [Stores Block].
4. Decision 2013-417 (26 November 2013), Alberta Utilities Commission [UAD decision].
5. Supra note 2 at para 88.
6. Ibid.
7. Ibid.
8. Ibid.
9. Ibid, at para 89.
10. Ibid.
11. Ibid.
12. Ibid.
13. Ibid, at para 128.
14. Stores Block, supra note 3 at para 83.
15. Reconsideration of ATCO Electric Ltd Z Factor Adjustment for the 2016 Wood Buffalo Fire (10 December 2023), 28320-D01-2023, online (pdf): Alberta Utilities Commissions <efiling-webapi.auc.ab.ca/Document/Get/799233>.
16. Canada (Minister of Citizenship and Immigration) v Vavilov, 2019 SCC 65 [Vavilov].
17. FortisAlberta Inc v Alberta Utilities Commission, 2024 ABCA 110 (CanLII).
18. Alta Link Management Ltd v Alberta Utilities Commission, 2023 ABCA 325 (CanLII).
19. Generation Approvals Pause Regulation, Alta Reg 108/2023 (Alberta Utilities Commission Act).
20. Terms of Reference for the Inquiry into the ongoing economic, orderly and efficient development of electricity generation in Alberta, Alta Reg 171/2023 (Alberta Utilities Commission Act).
21. Inquiry into the ongoing economic, orderly and efficient development of electricity generation in Alberta (11 September 2023), AUC 2023-06.
22. AUC inquiry into the ongoing economic, orderly and efficient development of electricity generation in Alberta, Module A Report, (31 January 2024).
23. Policy Guidance to the Alberta Utilities Commission (Minister of Affordability), (28 February 2024), (letter to the AUC).
24. Foothills Solar GP Inc, (20 April 2023), 27486-D01-2023 [Foothills Solar Project], online (pdf): Alberta Utilities Commission <efiling-webapi.auc.ab.ca/Document/Get/786809>.
25. Aura Power Renewables Ltd, (20 July 2023), 27488-D01-2023, [Burdett Solar Project], online (pdf): Alberta Utilities Commission <efiling-webapi.auc.ab.ca/Document/Get/791273>.
26. Nova Solar GP Inc & AltaLink Management Ltd: Nova Solar Power Plant and Transmission Connection, (19 July 2023), 27589-D01-2023, [Nova Solar Power Plant], online (pdf): Alberta Utilities Commission <efiling-webapi.auc.ab.ca/Document/Get/791225>.
27. AECG Forty Mile Wind GP Corp: Forty Mile Wind Power Project Amendments, (8 November 2023), 27561-D05-2023, [AECG Forty Mile Wind GP Corp], online (pdf): Alberta Utilities Commission <efiling-webapi.auc.ab.ca/Document/Get/796413>.
28. See the letter from the Minister of Affordability and Utilities to Chief Executive Officer of the Market Surveillance Administrator (11 March 2024), online (pdf): <www.albertamsa.ca/assets/Documents/Letter-from-Minister-Neudorf-to-the-MSA.pdf>; See also the letter Minister of Affordability and Utilities to President and Chief Executive Officer of the Alberta Electric System Operator (11 March 2024), online (pdf): <ehq-production-canada.s3.ca-central-1.amazonaws.com/7fa2c98bd3f6d937ebce1b9700fe25f999b07129/original/1710193426/d439ab6c3817d3b5b0404cca1a7148ec_Direction_Letter_from_Minister_11March2024.pdf>.
29. Alberta Electric System Operator, Alberta’s Restructured Energy Market: AESO Recommendation to the Minister of Affordability and Utilities, (31 January 2024), online (pdf): <ehq-production-canada.s3.ca-central-1.amazonaws.com/530bdb99b5d359617971a5afbfb7c6ce102c948d/original/1710186949/d9df2d63906c31e963da4d8b6a51f3a8_AESO_REM_Recommendation_Report_31Jan2024.pdf>.
30. Market Surveillance Administrator, Advice to support more effective competition on the electricity market: Interim action and an Enhanced Energy Market for Alberta, (21 December 2023), online (pdf): <www.albertamsa.ca/assets/Documents/MSA-Advice-to-Minister.pdf>.
31. Transmission Regulation, Alta Reg 86/2007.