On February 19, 2021, the Alberta Utilities Commission (the “Commission”) released its Final Report reflecting the findings from its Distribution System Inquiry (the “Inquiry”).1 This blog post represents the second in a 2-part series summarizing the Final Report, including the potential tools or solutions for addressing the issues facing the Commission and industry in light of the distribution transformation.  The first blog post summarizing these issues can be found here

Tools and Considerations for Addressing the Issues

The Commission noted that there was widespread consensus among parties that the current regulatory framework governing Alberta's electricity industry appears to be sufficiently robust and flexible to accommodate any such adjustments or modifications that may be required to allow distribution utilities to efficiently integrate distributed energy resources (“DERs”) into the Alberta Interconnected Electric System (“AIES”).2

The following initiatives to make such adjustments were recommended or highlighted by the Commission:

Tariff and Rate Redesign

1. Improving distribution tariffs

Parties recommended the transition to rates that better reflect the costs of providing utility service, both in terms of: (i) the division of cost recovery among customers; and (ii) in how the allocated costs are recovered from customers (i.e., rate design).

With respect to the division of cost recovery among customers, parties suggest that cost causation could be better achieved by: (i) “unbundling distribution costs” (i.e., distribution costs are broken down into components)3; (ii) developing separate class-specific rates for certain DERs4; (iii) developing rate classes based on capacity rather than end-use (i.e., residential, commercial, irrigation)5; and (iv) developing customer-specific rates6.

With respect to rate design, the independent experts in the Inquiry agreed that, based on principles of cost causation and economic efficiency, the design should involve both: (i) non-avoidable charges to recover the embedded costs of the existing infrastructure7; and (ii) variable, avoidable charges to send a forward-looking price signal capable of affecting future system costs by altering current behaviour. 8 These recommendations represent a shift away from the higher weighting of variable rates currently used in Alberta.

2. Improving price signals from the AESO transmission tariff

Parties recognized that uneconomic bypass of transmission costs occurs as more customers install on-site generation. Under the current AESO tariff design, the bulk transmission costs are collected through a 12 Coincident Peak (“12-CP”) demand charge, sending price signals to reduce load at the time of transmission system coincident peak. It was argued that the 12-CP charge no longer reflects the underlying cost drivers of the transmission system, thus avoiding this charge does not reduce the costs of the transmission system and simply allows self-supply customers to avoid paying for a large portion of transmission system costs.9 The Commission recognized that this issue is best left to AESO tariff proceedings and noted that the AESO has launched a tariff modernization initiative and is currently consulting on bulk and regional tariff redesign.10

Additionally, the harmonization of distribution and transmission tariffs was also discussed, including how the AESO tariff is flowed through each distribution tariff11; and the alignment of transmission and distribution tariffs with respect to price signals12. The Commission recognized that these issues are best left to distribution tariff applications.13

3. The importance of passing through energy price signals to customers

Given that the wholesale and retail prices for electricity in Alberta are determined through competitive markets, it was generally agreed by the independent experts that the most efficient price signal would be exposure to a time-varying rate that corresponds to the wholesale price of electricity.14 Once more advanced metering technology is fully deployed, there will be an opportunity to leverage the competitive forces present in the Alberta wholesale electricity market to promote economically efficient outcomes, including enhanced retail competition and customer choice. This could be done by retail settlement occurring on the actual hourly usage of customers, thus creating incentives for retailers and customers to respond to energy market price signals.15

Deployment of Advanced Metering Infrastructure (“AMI”) Systems

The widescale deployment of AMI systems is an essential element and primary enabling technology of grid modernization as it will allow for enhanced rate design and improved access to information.16 AMI consist of metering devices (i.e., smart meters) that are capable of being read remotely at an hourly or more frequent interval for electricity consumption and demand.17

The types of information AMI systems can generate will enable distribution utilities to design rates in ways that are more aligned with cost causation and send more effective price signals.18 Additionally, AMI systems would facilitate the opportunity to leverage the competitive forces present in the Alberta wholesale electricity market through dynamic price signals.19

Currently in Alberta, the decision to deploy AMI rests with the distribution utility, and such decision is typically made on an internal cost-benefit basis unique to each utility, particularly given the age and capability of the utility's existing meters.20 In general, parties did not support the idea of a mandated widespread deployment of AMI systems throughout the province.21 Given that AMI systems are widely expected to be the cornerstone of grid modernization in the future, it is the Commission's expectation that, at a minimum, interval-capable AMI meters will be deployed through the natural evolution and replacement cycle of meters as part of the prudent planning and operation of the Alberta distribution system.22

Access to Data and Information

Parties commented that the lack of access to relevant information creates barriers to entry and otherwise weakens competition and customer choice.23  Access to their real-time (or near-real-time) load information empowers customers to manage their consumption and make decisions between consuming grid-supplied electricity and electricity supplied by DERs. Increasing access to this information in Alberta has a number of necessary prerequisites: (i) the installation of AMI systems24; (ii) the settlement of consumption an hourly basis at the retail level25; and (iii) addressing the problem of load settlement based on load profiles as opposed to actual hourly usage26.

Providing access to relevant data and information to DER proponents can also enhance competition in the electricity market.27 To do this, a third party could compile aggregate consumption patterns or loading patterns on the grid to support competitive outcomes.28

Information and data related to the DER interconnection process is also needed for: (i) customers to assess the difference in prices and costs for grid-supplied electricity versus installing DERs; and (ii) DER proponents to determine optimal siting.29 The Commission found that there is considerable merit in standardizing the interconnection process, to the extent practical and reasonable, as well as   ensuring the transparency of the process for all stakeholders, especially as the rate of DER penetration continues to increase.30 Additionally, the Commission recognized that distribution utilities that have proactively made interactive hosting capacity maps publicly available and that these maps provide an estimate of the DER capacity that may be accommodated without adversely affecting power quality or reliability under current configurations and without requiring infrastructure upgrades.31

Integration of DERs

The Commission identified a number of specific considerations for the integration of DERs, including: 1) distribution-connected generation (“DCG”) credits; 2) ownership of energy storage resources; 3) the role of DERs as non-wires alternatives (“NWAs”); and 4) the integrated planning and operation of the transmission and distribution systems.

1. DCG credits

When a DCG supplies electricity onto the distribution system, the total load consumed on that segment of the distribution system is masked, resulting in the lowering the billing determinants measured at the point of delivery, and thus lowering the AESO charges billed to the distribution utility.32 Since avoiding these charges does not lower the cost of the transmission system, the AESO must collect the missing portion of its transmission revenue requirement from other customers.33 The Commission, prior to the release of its Final Report, established an independent module for the consideration of all DCG credits stemming out of FortisAlberta Inc.'s application for approval of its 2022 Phase II distribution tariff application.34

2. Ownership of energy storage resources

Since energy storage is not expressly defined in existing legislation, there is some uncertainty regarding who may operate and control these assets, as well as how, and in what scenarios.35 During the Inquiry, there was no consensus on ownership, with parties being divided between two scenarios: (i) no regulated utility ownership, but contracts for grid services permissible; and (ii) regulated utility ownership permitted.36 

3. Role of DERs as NWAs

A number of parties argued that DERs have the potential to assist in mitigating system reliability issues and in reducing overall system costs as NWAs.37 However, using DERs as NWAs represents a fundamental shift in how distribution utilities approach planning for system upgrades, development, and growth. As such, a number of practical, engineering and regulatory steps and processes will need to be reconsidered, augmented, modified, replaced and/or discarded to accomplish this.38

Although the Transmission Regulation limits the circumstances where NWAs may be considered in the transmission context, no such limitations exist for the distribution system.39 However, some parties noted that certain aspects of the existing regulatory framework for distribution utilities do not provide the right incentives for adoption of NWAs.40 For example, in Alberta, distribution line losses are paid for by retailers; therefore, distribution utilities have little incentive to use DERs to mitigate these costs.41 Similarly, there is a potential for NWAs to be characterized as operational expenses and not capital expenditures in distribution utility accounting, which is important when considering that distribution utilities earn a return on rate base.42 Changes to the performance-based regulation framework in Alberta or implementation of pilot projects were touted as possible solutions to these incentive issues.43

4. Integrated planning and operation

Parties also argued that to maximize the value of DERs, system planning and operation would need to become more integrated and coordinated as between the AESO and transmission and distribution utilities.44

Proposed Next Steps

Parties recommended that the Commission lead a process for establishing roadmaps for the evolution of Alberta distribution utilities which would include: (i) events that trigger certain steps; and (ii) conditions or actions that need to be met upon the triggering event.45 Parties differed in their views respecting the implementation of the roadmaps, including whether the roadmap(s) should be utility-specific or a common roadmap.

The Commission also recognized that industry-led processes to modernize the grid were already occurring, including:

  • The AESO's DERs and energy storage roadmaps; transmission and distribution coordinated planning framework; and tariff modernization and market initiatives.
  • DER hosting capacity maps published by ATCO, ENMAX and Fortis.
  • ATCO's AMI pilot project and pilot EV charging station rate class.
  • ENMAX's EV charging pilot program.
  • EPCOR's joint research with the University of Alberta on potential impacts of DERs to urban utilities.
  • Fortis's several internal and external initiatives, studies and pilots to cost-effectively integrate DERs.
  • Alberta Innovates-led Smart Grid Consortium customer survey.
  • EQUS's installation of Canada's first extra-urban and rural-adapted wireless AMI system.
  • The City of Medicine Hat's deployment of electric, natural gas, and water utility meters conversion to AMI as part of an interconnected metering and billing system.46

The Commission indicated its support for the AESO initiatives which overlap or address many of the recommendations and findings of the Final Report. The Commission indicated its intention to participate in the AESO initiatives and become directly involved through the Commission's decision-making process, as necessary. However, the Commission noted that the AESO's primary focus relates to the transmission system, and a holistic view of the electric grid may not be fully canvassed in the AESO initiatives. As such, the Commission intends to await the outcome of the AESO's initiatives and following on those outcomes will consider the need for further processes.47


While some of the issues outlined in the Final Report may be addressed in part by the AESO and each utility, on an individual basis, it appears that the Commission is more likely to lead or become involved in DER related distribution issues that it considers require coordinated action or if it perceives there is a regulatory efficiency that can be addressed in an industry-wide manner (such as DCG credits).

Although the Commission recognized that on-going initiatives address many of the issues identified in the Final Report, any future efforts to address distribution tariff pricing signals remain unclear. While we note that the Commission very recently announced it will evaluate its current form of performance-based regulation48, it remains to be seen whether rate design changes to address distribution transformation will be considered. Re-imagining the regulatory compact in the context of DERs is a difficult challenge given the diverse group of affected stakeholders and it appears likely that distribution tariff pricing is an issue that will require Commission initiative, oversight and adjudication.


1 Alberta Utilities Commission, Distribution System Inquiry: Final Report (February 19, 2021) (“Final Report”).

2 Ibid at 260.

3 Ibid at 292.

4 Ibid at 293.

5 Ibid at 294.

6 Ibid at 298.

7 Ibid at 309.

8 Ibid at 311.

9 Ibid at 325.

10 Ibid at 328.

11 Ibid at 329.

12 Ibid at 330.

13 Ibid at 334.

14 Ibid at 339.

15 Ibid at 264.

16 Ibid at 265 and 342.

17 Ibid at 343.

18 Ibid at 347.

19 Ibid at 340.

20 Ibid at 352.

21 Ibid at 360.

22 Ibid at 364.

23 Ibid at 365.

24 Ibid at 367.

25 Ibid at 371.

26 Ibid at 372.

27 Ibid at 379.

28 Ibid at 379.

29 Ibid at 385.

30 Ibid at 392.

31 Ibid at 383.

32 Ibid at 435.

33 Ibid at 440.

34 Exhibit 26090-X0005, Alberta Utilities Commission, Letter re. Distribution-connected generation credits and initial process schedule.

35 Final Report, supra note 1 at 446.

36 Ibid at 448.

37 Ibid at 267.

38 Ibid at 400.

39 Ibid at 418 and 421.

40 Ibid at 267.

41 Ibid at 400.

42 Ibid at 423.

43 Ibid at 423-426.

44 Ibid at 405.

45 Ibid at 479.

46 Ibid at 18.

47 Ibid at 512-513.

48 AUC Bulletin 2021-04.

Originally Published by Stikeman Elliott, March 2021

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