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 Commenced in December 2018, the Inquiry received broad stakeholder participation from approximately 90 parties who provided submissions on: (i) emerging energy resource technologies; (ii) impacts of these emerging technologies on grid reliability, existing business models, rate structures, and the ability to provide appropriate price signals; and (iii) potential areas of innovation for the Alberta.2 The Commission's lens of review stemmed from the exogenous forces of decentralization of energy resources, digitalization and decarbonization (the "mega-trends") that will continue to intensify in the years ahead.3

This blog post represents the first in a two-part series summarizing the Final Report and identifies the significant issues facing the Commission and industry in light of the distribution transformation.  The second blog post will consider the potential tools or solutions for addressing the issues. 

Need for the Inquiry

The goal of the Inquiry was primarily fact-finding to map out the key issues affecting the future of the electric distribution grid, and to assist in planning and developing a regulatory framework to accommodate the evolution of the electricity system.4 To fulfill its mandate, the Commission sought awareness and understanding of the evolving economic and competitive market forces affecting the electricity grid.5

The central driving force in the distribution transformation is changing customer needs, including increasing electricity needs for various technologies (electric vehicles and heat pumps), desire for new sources of supply (solar and combined heat/power systems), and the adoption of technologies to manage consumption (energy storage, energy efficiency, and smart technologies to manage use), technologies collectively referred to as Distributed Energy Resources ("DERs").6 DERs make it possible to avoid or bypass certain changes in the electricity value chain, shifting the fixed costs of the grid to other customers – those not employing DERs ("uneconomic bypass" ).7 With high rates of DER adoption, this causes uncertainty whether distribution utilities can continue to meet their obligations to provide service and still recover their revenue requirement. 8

For distribution utilities, other forces or challenges include: (i) potentially increased loads partly driven by the electrification of transportation and heating9; (ii) increased adoption of DERs causing dynamic energy flows on the distribution system10; (iii) weakened provincial economic growth and a need to keep grid-supplied electricity affordable  and growing pressure to align rates with costs11; (iv) increased customer choice12; (v) growing competitive pressure to more closely align rates with costs13; and (vi) the development of new technologies to help respond to these issues, particularly as they address growing electricity demands and shifting consumption patterns.14

The Commission articulated three questions to guide the Inquiry and to assist in understanding how these forces may affect the grid: 15

  • How will emerging technology affect the grid and incumbent electric distribution utilities, and how quickly?
  • Where alternative approaches to providing electrical service develop, how will the incumbent electric distribution utilities be expected to respond, and what factors should be considered in determining whether affected services and/or service providers should be subject to a greater or lesser degree of regulation as circumstances change?
  • What factors should be considered in determining whether the rate structures of the distribution utilities should be modified to ensure that price signals encourage electric distribution utilities, consumers, producers, prosumers and alternative technology providers to use the grid and related resources in an efficient, cost-effective way?

Identification of Issues

The Commission identified a number of discrete issues, reflections or topics within the Final Report, including: 1) level of DER adoption; 2) DER tariff avoidance; 3) level-playing field considerations; 4) market implications; 5) benefits of microgrids; 6) electric vehicles; and 7) energy storage resources. The Final Report addresses many of these issues within the context of specific connection-configurations, which will not be addressed here.

1. Level of DER Adoption

Although the Commission found that Alberta has not yet experienced DERs adoption rates at sufficiently high levels to significantly strain the distribution systems beyond manageable levels, it is widely expected that DERs adoption will continue to increase in Alberta due to declining technology costs (e.g., DER solar, energy storage16), embedded price signals, government policies, and shifts in consumer preferences.17 However, there remains uncertainty with respect to the scale and timing of DERs adoption in Alberta.18

2. DER Tariff Avoidance

Traditional rate designs for transmission and distribution tariffs have primary been to recover total revenue requirements rather than to send accurate, cost-based price signals to consumers.19 Additionally, traditional rate design is constrained by simple metering arrangements that limit what can actually be billed and how frequently. These factors create strong incentives to install DERs to avoid tariff charges perceived to be excessive, shifting costs among distribution customers and leading to uneconomic bypass of the grid.20

To date, efforts to prevent uneconomic bypass have focused on either technical measures (such as the AESO's adjusted metering practice on the transmission system to limit the amount of local load offset by DCG) or administrative measures (such as limiting permissible generation and load configurations in recognition of their potential to bypass system costs).21

However, the most effective means of discouraging uneconomic bypass is to design rates based on costs to deliver the service.22 It was observed that distribution tariff structures generally recover a significant portion of fixed system costs through either volumetric (on a $/kWh basis) or peak demand ($/kW) charges that can be avoided through the installation of DERs, which exceeds the marginal costs of distribution service. This over-incents the installation of DERs. Further, installing DERs likely requires grid upgrades and the costs for such upgrades will be disproportionately borne by non-DER customers.23 With sufficient penetration of DERs under the current rate structure, there is a risk that a distribution utility would experience billing determinants erosion and would incent more and more customers to install DERs to bypass those charges.24

3. Level-Playing Field Considerations

Level playing field considerations between transmission-connected generation ("TCG") and distribution-connected generation ("DCG") were raised throughout the Inquiry.  Parties submitted that the most efficient generation investment will result if all resources, both on the transmission system and distribution system, respond to the same price signals.25 Concerns were raised with respect to: (i) the allocation of transmission system costs26, (ii) DCG credits27, and (iii) differences in how the costs of transmission system line losses are attributed to TCG and DCG as contributing to inconsistencies between transmission and distribution tariff design.28 With respect to the later two concerns, the Commission found that the AESO's approved adjusted metering practice would lessen the impacts of those concerns.29

Another level playing field concern raised was the differences in the regulatory treatment afforded to various DERs despite appearing to be functionally very similar in their impact on the grid.30 One example provided was the payments to small micro-generators for electricity supplied to the grid using the retail rate for electricity consumed from the grid as a proxy, shifting costs from small micro-generators to all other AESO tariff customers.31

4. Market Implications

There were a number of market concerns related to DERs raised in the Inquiry. First, parties were concerned that to the degree that DERs self-dispatch, are intermittent in nature or are not adequately visible, their presence may impede the formation of robust prices.  In particular, allowing DERs to offer net-to-grid (i.e., offers generation into the wholesale electricity market after on-site load has been offset), reduces available information on total demand and total supply and thus, affects market participants' offer strategies, and negatively affects price formation.32 In this regard, the AESO was relatively unconcerned with the current penetration levels of DERs with respect to the market impacts.33 Given the AESO's mandate for the operation of the market, the Commission declined to address any further concerns relating to the potential impact of DER on price discovery.34

Concerns were also raised regarding the degree that DERs investment is motivated by tariff avoidance and securing non-level playing field advantages over other generators, exacerbating the impacts on the wholesale electricity market.35

5. Benefits of Microgrids

With the exception of remote customers off-grid, the Commission found there to be limited public interest benefits for microgrids in Alberta. This is because microgrids essentially create another form of self-supply with export, raising the possibility of cost shifting and uneconomic bypass.36

6. Electric Vehicles

The adoption of EVs represents the potential for substantially greater loads to be placed on distribution systems. This could drive distribution utilities to make significant investments in new infrastructure resulting in a significant increase in costs to serve these new loads.37

However, time-of-use rates or rebates to incent charging during off-peak hours or demand-side management technologies could help minimize the new generation and grid investment that will be needed, potentially resulting in lower system costs. 38 Ongoing regulatory challenges remain because EV charging stations are not clearly defined in legislation and their regulatory status within the evolving electricity system is unclear.39

7. Energy Storage Resources

Parties expressed the following concerns about how the current regulatory framework impedes the deployment of energy storage resources:

  • The absence of a statutory or regulatory definition of energy storage resources within the current legislative and regulatory framework results in a lack of clarity and certainty in how, when, where and for what purpose such resources can be deployed. Many parties argued legislative clarity is required.40
  • Limitations on the ability of customers to self-supply and export electricity to the grid.41
  • The current treatment of energy storage in the AESO and distribution utilities' tariffs, and whether specific rates for energy storage resources are required.42
  • Lack of a process for considering energy storage resources as non-wires alternatives.43
  • Lack of clarity on how energy storage assets would be treated with respect to a utility's rate base, whether the utility owns the asset or obtains the services under contract with a third-party-owned asset.44


The complexity of the distribution transformation in Alberta will continue to engage the Commission and industry for years to come. While the Final Report provides a helpful first step in acknowledging the issues at play, it also recognizes the uncertainty in the rate of DER adoption, which is central to understanding the timing implications and scope of any distribution transformation. Many parties acknowledged in the Inquiry that inefficient pricing in other jurisdictions led to the rapid adoption – within a single decade - of DERs in those jurisdictions.45 Consequently,  efforts by the Commission and industry to address  distribution tariff pricing signals is fundamental in order to leverage DERs to the advantage of Alberta, which will be more fully canvased in Part 2 of our blog post.


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

2 Ibid at 24.

3 Ibid at 27, 39.

4 Ibid at 5.

5 Ibid at 23.

6 Ibid  at 12.

7 Ibid  at 96-97.

8 Ibid at 14.

9 Ibid at 39.

10 Ibid at 40.

11 Ibid at 42.

12 Ibid at 42-45.

13 Ibid at 45.

14 Ibid at 46.

15 Ibid at 8.

16 Ibid  at 35-36.

17 Ibid at 4, 31

18 Ibid at 31.

19 Ibid at 4.

20 Ibid at 5 and 96.

21 Ibid at 112.

22 Ibid at 112.

23 Ibid at 100.

24 Ibid at 102.

25 Ibid at 121.

26 Ibid at 123.

27 Ibid at 124-125.

28 Ibid at 126.

29 Ibid at 127 citing Decision 25848-D01-2020.

30 Ibid at 6.

31 Ibid at 165-166.

32 Ibid at 160.

33 Ibid at 161.

34 Ibid at 161.

35 Ibid at 163.

36 Ibid at 182 and 187.

37 Ibid at 188.

38 Ibid at 188 and 198.

39 Ibid at 217.

40 Ibid at 234-238.

41 Ibid at 242.

42 Ibid at 248-251.

43 Ibid  at section 5.5.2

44 Ibid at section 5.5.4.

45 Ibid at 20.

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