After nearly three decades of stability, Alberta’s electric industry framework is entering an era of radical and unknown change, primarily driven by the need to mitigate climate change.

The Government of Alberta (GOA) directed the Alberta Utilities Commission (AUC) to initiate an open, public proceeding to address four land-related issues with respect to the development of power plants: land use, viewscapes, reclamation costs, and use of Crown lands.^[1] Based on the AUC’s report, the GOA advised the AUC of its intention to advance policy, legislative and regulatory changes that affect future generation development.^[2]

One might ask why land-related issues have not been more directly addressed until now, and why generators were given such an extraordinary degree of freedom.

Having been one of the current market’s designers,^[3] the author was reminded of a line in G.B. Shaw’s “Anthony and Cleopatra”:

“Pardon him, Theodotus: he is a barbarian, and thinks that the customs of his tribe and island are the laws of nature.”^[4]

I freely admit that we designed this system like barbarians, tossing the sophisticated machinery of load forecasting, generation system modelling and rigorous generation reliability standards into the scrap heap, replacing it all with an elegantly clean and simple market design that has lasted nearly three decades.^[5]

The policy “deal” with generators was radical in the extreme. Generators compete to supply electricity to the grid; the lowest priced offers that satisfy the market’s demand will be accepted by the power pool and paid the market price for their output. Generators only get paid for the energy they produce; if you don’t run, you don’t get paid — the “energy-only” model.^[6]

The model worked well in large part due to Alberta’s fortunate circumstances. While other jurisdictions were experiencing little load growth, Alberta was forecast to continue to grow at 2.5 per cent a year for decades to come.^[7] No matter how overbuilt the Alberta system might become, in a few years load growth would catch up with supply. And no matter what the price of oil may be, the massive capital investments in heavy oil extraction ensured that electricity consumption would continue, so the risk of load loss appeared minimal.

To make this ‘deal’ work, Alberta had to adopt certain ‘tribal’ customs that by now have come to seem like the laws of nature.

• First and foremost, there shall be no generation planning, no official assessment of the need for new capacity that could be used to mandate system additions.^[8] Generators can build whatever they want, wherever they want, and whenever it pleases them to do There is to be no customer or government agency input to these commercial decisions.
• Transmission shall be pre-built, so that “actual [transmission] construction must then be staged to mesh with generator start-up and commissioning…”^[9]

The Alberta Electric System Operator (AESO) was given the difficult task of planning and operating a transmission system which can connect unpredictable generation resources — and “the transmission system must be relatively congestion free or the underlying market model will not function effectively.”^[10]

When Alberta’s generation fleet consisted of a dozen large coal units, a congestion free grid was quite feasible; but as the system dissolves into hundreds of small renewable generators, the market model breaks. If many generators choose to concentrate in a resource-rich area, the AESO has no choice but to plan and propose projects to alleviate generator-caused congestion, costing consumers hundreds of millions of dollars.^[11] As the AESO has stated, “the current zero-congestion policy is unsustainable and must change.”^[12]

Land-related issues are just one aspect of the broader industry evolution, which is moving away from a generator-centric, ‘relatively streamlined market design’ and towards a more balanced future design that optimizes the system as a whole and explicitly recognizes that there is more to a power system than just energy generation.

CONSTRAINING GENERATORS’ MARKET FREEDOMS

It may appear to some that legislative changes are happening too rapidly, without extensive consultation and consideration. In fact, the market dynamics changed several years ago, and rapid response is now essential.

A particularly compelling issue is the recent massive increases in the price of power in the power pool. In recent years, average pool prices have more than doubled, creating a serious affordability issues for customers while greatly increasing generator margins. The urgency of electric industry restructuring is pervasive, and Alberta does not have the luxury of leisurely, thorough rumination on each issue.

The need for speed is particularly acute since these high pool prices are not driven by fundamentals like gas price increases but are a product of the ‘generator freedom’ policy combined with the reduction in competition created by the advent of major renewable generation resources which cannot respond to market price signals.

Annual Average Pool Price ($/MWh)^[13]

Economic withholding occurs when a generator prices its output above its Short-Run Marginal Cost (SRMC). A dramatic example of economic withholding is provided in the Market Surveillance Administrator’s quarterly report for Q3 2022. The MSA found that “[h]igh pool prices in Q3 [2022] were primarily driven by the exercise of market power by two generation companies.”^[14]

To illustrate this point, the MSA provided a graph of the supply curve for August 10, 2022, Hour Ending 1500 (3 PM). This curve determines the hourly pool price of power, based on the level of system load.

If the system load is less than about 9,700 MW, prices will be $100 / MWh or less. But if load is even few per cent over that level, the price will jump up to the $800 range with almost no intermediate steps.

Illustrative Q3 2022 supply curve (August 10, 2022 HE15)^[15]

How can this be? The answer is: market power. Two generation companies own almost all of the generation capacity over 9,700 MW, and they can ask whatever price they wish for their output.

In the original market design this was not a problem. Some level of economic withholding was necessary for Alberta’s market to function: “Generators may choose to invest in the Alberta market if they believe they will be able to recover their capital costs. The Alberta electricity market allows economic withholding to encourage such investment, enabling generators to price their assets above marginal cost.”^[16]

When almost all generation could turn on in response to high prices, economic withholding was constrained by competition — if you price your output too high, someone else will outbid you, you will not be dispatched, and you will sit idle.

But unlike natural gas fired units, renewables cannot increase their output in response to high prices. They are limited by their wind and solar energy inputs, and if it’s calm and cloudy the remaining natural gas generators can often charge whatever they wish.

At the government’s direction, the AESO is now considering long-term solutions to this market problem.^[17] In the interim, two stopgap regulations constraining dispatchable generators were put in place:

• Supply Cushion Regulation [AR 42-2024] sets a target supply cushion of 932 MW, and if this is not met then the regulation directs the Alberta Electric System Operator to issue unit commitment directives to specific generation assets that are offline, telling them when and for how long they are to be online and synchronized with the system. This mechanism can be used to ensure that there is adequate thermal generation in the market to mitigate the impact of economic withholding.
• Market Power Mitigation Regulation [AR 43-2024] imposes a lower price cap of $125/MWh on non-renewable generators, in any month in which their profits equal twice their monthly capital ^[18] This sets a limit on the benefits of economic withholding.

These financial and operating constraints are an example of the necessarily rapid evolution away from the current generator-centric model, to give recognition to other stakeholder interests such as those of landholders.^[19]

THE AUC INQUIRY INTO LAND ISSUES

By Order in Council, the GOA directed the AUC to look in to four matters:

• The development of power plants on specific types or classes of agricultural or environmental land.
• The impact of power plant development on pristine viewscapes.
• The implementation of mandatory reclamation security requirements for power plants.
• The development of power plants on lands held by the Crown in the Right of Alberta.^[20]

Following its long-established processes:

The Commission received hundreds of written submissions from stakeholders, First Nations and Métis communities. Stakeholders include Albertans across the province, municipalities, power plant proponents, and various organizations such as landowner, municipal, environmental and industry associations. Several stakeholders filed expert reports along with their written submissions.^[21]

This is an arguably ideal way to gather broad input on a complex issue — to make use of existing expertise, in an open public forum, and develop fact-based options based on that input.

On February 28, 2024, the GOA issued a letter providing “Policy Guidance to the Alberta Utilities Commission.”^[22] This Policy Guidance will be referred to in discussing the four matters dealt with by the Commission.

1. Agricultural and environmental land

There are currently no specific legislative or regulatory constraints on the classes of agricultural lands dedicated to renewable generation projects. The Minister’s Policy Guidance letter sets out an “Agriculture First” approach, under which “Alberta will no longer permit renewable generation developments on Class 1 and 2 lands, unless a proponent can demonstrate the ability for both crops and/or livestock and renewable generation to co-exist.”^[23]

Land use is already a Commission consideration in transmission siting decisions. The restrictions on generation land use can be seen as part of a necessary movement towards a more balanced policy, compared to the current extreme ‘generation first’ approach. Land is a fundamental non-renewable resource, and there is merit in the position that agricultural use should have a high social priority.

Renewables are forecast to consume only a small fraction of Alberta’s total agricultural land, perhaps 0.4 to 0.6 per cent of the existing class 2 agricultural land.^[24] But in practice, “less than 5 per cent of projects have been installed on class 2 land,” and “high-value crop land can generate revenue that exceeds the current market price of solar land leases.”^[25] These statistics suggest that a land-use restriction would not impose unreasonable new constraints on renewables developers, who are already economically incented to locate on less valuable classes of land.

Other users such as pipelines, industrial sites, urban and residential development consume far more land than renewables.^[26] In the interests of a fair, level playing field, one would hope that the restrictions imposed on renewable projects will not be more onerous than the restrictions imposed on other types of projects.

From an implementation perspective, the Commission noted: “Currently there is no single multi-criteria evaluation tool that integrates environmental, vegetation, soils and agricultural information on a province-wide basis that can be used to inform the siting of renewable projects in Alberta.”^[27]

To bridge this gap, the AUC committed to “explore requirements for proponents to provide soil field verification earlier in the application process,” and noted the option to “assess the value of creating a province-wide integrated multi-criteria evaluation tool to identify and evaluate agricultural land.”^[28]

After reviewing the numerous existing controls on “high value environmental land such as native prairie, mountains and wetlands,”^[29] the Commission observed: “The existing regulatory framework is generally sufficient for the protection of environmental land.”^[30]

2. Pristine Viewscapes

The effect of power plant development on viewscapes is a socially important issue that cannot be readily quantified or assessed.

“ The Commission received substantial feedback that the personal value of a viewscape would vary depending on an individual viewer’s perception, and that attempting to define or delineate commonly held criteria of a pristine viewscape would be challenging.”^[31]

In response to this concern, the Commission committed to “enhance the existing visual impact assessment requirements within Rule 007 to include a more structured visual impact assessment methodology within the AUC application review process.”^[32]

As to ‘No-Go’ zones where power plant development would be completely restricted, the Commission indicated that “the identification and delineation of these areas, if any, should be by the government.”^[33] These are not narrowly technical decisions, but rather represent a balancing of considerations at the general public level, the community level and the individual level.

The Minister’s Policy Guidance indicated that “Government of Alberta will develop and implement the necessary policy and legislative tools to establish buffer zones, of a minimum of 35 km, around protected areas or other “pristine viewscapes” designated by the province where new wind projects will no longer be permitted.”^[34]

Other developments within that zone could trigger the need for a visual impact assessment. This policy implicitly recognizes that wind turbines are the most visible industrial structures, while other developments are less imposing, and can be managed by the local regulating party (preferably on an industry-agnostic basis as suggested by the AUC).^[35]

3.  Crown Land

Crown land use has historically been authorized for a range of energy developments such as transmission lines and oil and gas facilities. Historically, renewable power plants have seldom been developed on Crown land. On this issue there is a void: “There is currently no government policy specifically authorizing or setting parameters for the development of wind and solar projects on provincial Crown land, and there is no form of Crown land disposition specifically intended to facilitate this type of development.”^[36]

There are a broad range of existing users of Crown land, including “disposition holders (e.g., those holding grazing leases or timber permits), as well as recreational users of Crown land and First Nations and Métis communities exercising their constitutionally protected rights.” ^[37]

The Minister’s Guidance Letter recognized that an immediate policy decision would be inappropriate.

Given the many competing interests surround our Crown Land resource, meaningful engagement is required before any changes to Crown Land access, which will result in future legislative changes coming into force in late 2025.^[38]

This leaves the use of crown land for power plant development in an explicitly undetermined state, but with a stated deadline for resolution in late 2025.

4. Reclamation

As the Alberta Energy Regulator has observed with respect to abandoned oil and gas wells: “Historically, liability management has been largely reactive and not focused on the full life cycle of energy development.”^[39]

As the Commission stated, “there is no reclamation security regime that applies to all power plants,” and:

There is currently no mandatory financial security requirement for a proponent to guarantee its reclamation obligations. Most power plants are located on privately owned land and are hosted voluntarily by landowners who can negotiate the terms of entry and as such, may negotiate some form of financial security for future reclamation obligations.^[40]

Accordingly, it is gratifying to see this issue positively addressed in the Minister’s Policy Guidance: “Government of Alberta will develop and implement the necessary policy and legislative tools to ensure developers are responsible for reclamation costs via bond or security, with appropriate security amounts and timing to be determined by Environment and Protected Areas in consultation with Affordability and Utilities.”^[41]

The Commission observed that

The process of defining a reclamation security regime will presumably proceed in due course.

CONCLUDING OBSERVATIONS

For over a quarter of a century, Alberta’s electric industry has been broken up into generation, transmission, distribution, retail segments. The boundaries between these segments are quite artificial, being creations of historical accident and administrative convenience.

The boundaries of these industry segments are not helpful in rethinking Alberta’s electric industry structure. Both at a policy and at a physical level, changes in one area often have unexpected impacts in far distant areas, as this article has demonstrated.

The advent of large amounts of renewable generation can profoundly modify market operations. In addition to the heightened impacts of economic withholding discussed above, the level of system strength, stability and flexibility is profoundly impacted by generation resources which cannot be directed to increase output when the system needs it.

The ever-increasing cost of transmission is another outcome of the out-going policies.^[43] This too would impact land use if more inefficiently used transmission lines were built solely to cater to generators’ location preferences.

Land use should be seen as but one single component of this entire integrated whole. Under the generator-centric model, landowners had no seat at the table; this is now changing, and a more balanced regime will doubtless emerge over time. In the interim:

• Though its impact on all parties will be small, it is reassuring to know that there will be restrictions on the development of renewables on agricultural land.
• It is also reassuring to know that there will be constraints on the visual impacts that wind turbines and other generation facilities can have on the viewscape — even though precisely defining this requirement will be challenging.
• Although Crown land locations for generators have not been particularly attractive, the opportunity for meaningful engagement across stakeholder groups will be valuable in defining the rules for all users to
• Although wind and solar projects do not present large reclamation costs compared to oil and gas operations,^[44] now is the time to set the rules of future engagement for all power plants.

The overall industry trend is towards a more centrally managed and controlled power system, in keeping with the inflexible laws of physics.

One of the learnings from the last round of electric industry restructuring in the late 1990’s was that no one is wise enough to be able to foresee all of a major decision’s consequences. As well, many of the concerns and customs inherited from the past structure will prove to be irrelevant in the future structure.

The present process of broad public inquiry followed by public release of policy guidance provides clarity for all stakeholders, and allows a policy’s consequences to be more fully considered by the industry as a whole. But time is of the essence — Alberta’s electric industry is like an airplane in flight, and we do not have the option of taking it out of service while we restructure it.^[45] Changes have to be made quickly on the fly, which will surely be uncomfortable and poses unavoidable risks.

In dealing with these land issues, the Commission has been given a positive and constructive role in receiving, analyzing and summarizing broad industry perspectives, based on open public submissions. As new legislation is developed, it will doubtless be found appropriate to provide the AUC with new powers and clearer guidance in these and other mandate areas, taking advantage of its respected expertise in assessing social, economic and environmental issues in its decisions.

For the last three decades, Alberta’s fortunate circumstances almost inadvertently provided the resources needed to maintain the system’s adequacy, stability, and strength.^[46] It is to be hoped that the many benefits of competition can be harnessed in a new industry structure; but above all, the lights must stay on and the rates must be reasonable. The current land issue resolutions take a useful step in what appears to be the right direction.

* Rick Cowburn is a 40-year veteran of Alberta’s electric industry. He served for 25 years at EPCOR companies and their predecessors, with responsibilities including rate design and approval, forecasting, metering, load settlement and wholesale billing. Since his retirement in 2007 he has worked with a broad range of clients, from REAs to major industrials. In 2012 he served on the Retail Market Review Committee by Ministerial appointment (See www.open.alberta.ca/publications/6001347).

1. See Albert Utilities Commission, AUC inquiry into the ongoing economic, orderly and efficient development of electricity generation in Alberta, Module A Report, Proceeding 28501, (Calgary: Alberta Utilities Commission, 2024), AUC 28501, online (pdf): Alberta Utilities Commission <media.auc.ab.ca/prd-wp-uploads/regulatory_documents/Reference/28501_Inquiry-ModuleA-Report.pdf> [Alberta Utilities Commission].
2. Letter from Minister Nathan Neudorf to Chief executive officer of Alberta Utilities Commission Bob Heggie (28 February 2024) regarding Policy Guidance to the Alberta Utilities Commission, online (pdf): <www.alberta.ca/system/files/au-minister-neudorf-letter-to-auc-20240228.pdf> [Letter from Minister Nathan Neudorf].
3. See Alberta Department of Energy, Enhancing the Alberta Advantage: A Comprehensive Approach to the Electric Industry, (Edmonton: Steering Committee, 1994), at 26, online (pdf): <open.alberta.ca/dataset/f8024ee2-e18e-405d-89da-83f55c335e05/resource/a6667b6a-ba01-436f-9b2b-e698ab974dca/download/energy-enhancing-the-alberta-advantage-a-comprehensive-approach-to-the-electric-industry.pdf>.
4. George Bernard Shaw, “Caesar and Cleopatra”, (last modified 10 December 2012), at Act II, online: <www.gutenberg.org/files/3329/3329-h/3329-h.htm>.
5. In practice, the Alberta Electric System Operator (AESO) has maintained technical strength in these areas of planning and operations, but their ability to truly optimize the system is limited by existing policies and legislation.
6. Texas is the only other North American jurisdiction which is said to use this model; Alberta has largely gone its own unique way in structuring the electricity market.
7. Alberta Electric System Operator, AESO 2014: Long-Term Outlook, (Calgary: Alberta Electric System Operator, 2024). “Over the next 20 years, Alberta Internal Load (AIL) is expected to grow at an average annual rate of 2.5 per cent” at 3.
8. The AESO carries out diligent system capacity assessments, which would only trigger mandatory additions in exceptional circumstances (which have never occurred); see AESO, Appendix A: Overview of AESO Supply Adequacy Measures, online (pdf): <www.aeso.ca/assets/LARA-Rules-and-ARS/Appendix-A-Overview-of-AESO-Supply-Adequacy-Measuress.pdf>.
9. Alberta Energy: Electricity Business Unit “Transmission Development: The Right Path for Alberta: A Policy Paper” (November 2003), at 7, online (pdf): <www.open.alberta.ca/publications/3103222>.
10. Ibid at 8.
11. See for example Central East Transfer-out Transmission Development Project (10 August 2021), 25469-D01-2021, at paras 7, 43, online: Alberta Utilities Commission <electric.atco.com/content/dam/web/projects/projects-overview/electricity-ceto-decision25469-d01-2021.pdf>.
12. Ministry of Affordability and Utilities, Transmission Policy Review: Delivering the Electricity of Tomorrow, (Government of Alberta, 2023), online (pdf): <www.ablawg.ca/wp-content/uploads/2023/11/Transmission-Policy-Green-Paper-2023.pdf>. “To verify that the benefits of maintaining the zero-congestion policy still outweigh the costs, the Ministry of Affordability and Utilities is examining alternative transmission planning frameworks…” at 14.
13. See Alberta Electric System Operator, AESO 2023: Annual Market Statistics, (2024) “TABLE 1: Annual market price statistics” (table) at 2, online (pdf ): <www.aeso.ca/assets/Uploads/market-and-system-reporting/Annual-Market-Stats-2023_Final.pdf>.
14. Market Surveillance Administrator, Quarterly Report for Q3 2022, (2022) at 15, online (pdf): <www.albertamsa.ca/assets/Documents/Q3-2022-Quarterly-Report.pdf>. See also Market Surveillance Administrator, Quarterly Report for Q2 2022, (2022) at s 1(6)(3), online (pdf): <www.albertamsa.ca/assets/Documents/Q2-2022-Quarterly-Report.pdf>.
15. Market Surveillance Administrator, Quarterly Report for Q3 2022, (2022) « Illustrative Q3 2022 supply curve » (graph) at 29, online (pdf ): <www.albertamsa.ca/assets/Documents/Q3-2022-Quarterly-Report.pdf>.
16. Market Surveillance Administrator, Quarterly Report for Q2 2022, (2022) at 33, online (pdf): <www.albertamsa.ca/assets/Documents/Q2-2022-Quarterly-Report.pdf>.
17. See Alberta Electric System Operator, “Market Pathways” (last modified 15 July 2024), online: <www.aesoengage.aeso.ca/market-pathways>.
18. The Regulation (4) does not apply to smaller entities (<5% of total Alberta capacity), renewables or certain energy storage resources. The daily cap also makes provision for changes in natural gas prices, that being the default generator energy input.
19. See Alberta Electric System Operator, AESO 2023: Reliability Requirements Roadmap, (2023), (renewable resources also impact a range of operating requirements, which the AESO has summarized under the headings of frequency stability “the ability of the electric system to maintain an acceptable frequency level and to recover from supply-demand imbalance due to contingencies in a timely manner.” at 14); system strength (“a measure of the power system’s ability to preserve its stability under all reasonably credible and possible operating conditions” at 34); and flexibility capability (“the ability of the electric system to adapt to dynamic and changing conditions while maintaining balance between supply and demand.”at 46). Alberta’s policy of radical generator freedom is being modified in response to these challenges, see also Alberta Electric System Operator, Alberta’s Restructured Energy Market: AESO Recommendation to the Minister of Affordability and Utilities (Calgary: Alberta Electric System Operator, 2024), online (pdf): <https://www.aesoengage.aeso.ca/37884/widgets/156642/documents/125518>.
20. Alberta Utilities Commission, supra note 1 at 52.
21. Ibid at 5.
22. Alberta Public Agencies Governance Act, SA 2009, c A-31.5 (“Subject to subsection (2), a Minister who is responsible for a public agency may set policies that must be followed by the public agency in carrying out its powers, duties and functions.” at s 10(1)). This legislation is not known to have been used in the past in electric industry matters. See also Letter from Minister Nathan Nuedorf, supra note 2.
23. Letter from Minister Nathan Nuedorf, supra note 2 at 3.
24. Alberta Utilities Commission, supra note 1 at para 93.
25. Ibid at paras 84, 91.
26. Ibid at para 82.
27. Ibid at para 103.
28. Ibid at paras 75, 102. Soil field verification was strongly supported in the Minister’s Guidance Letter.
29. OC 2023/171, online (pdf): <kings-printer.alberta.ca/documents/Orders/Orders_in_Council/2023/2023_171.pdf>.
30. Alberta Utilities Commission, supra note 1 at para 68.
31. Ibid at para 195.
32. Ibid at 49. See Letter from Minister Nathan Nuedorf, supra note 2. See also Alberta Utilities Commission, “Rule 007: Applications for Power Plants, Substations, Transmission Lines, Industrial System Designations, Hydro Developments and Gas Utility Pipelines” (last visited 21 August 2024), online: <www.auc.ab.ca/Rule-007>.
33. Alberta Utilities Commission, supra note 1 at para 212.
34. Letter from Minister Nathan Nuedorf, supra note 2 at 3.
35. Alberta Utilities Commission, supra note 1 at para 212.
36. Ibid at para 127.
37. Ibid at para 129.
38. Letter from Minister Nathan Nuedorf, supra note 2 at 4.
39. Alberta Energy Regulator, “Liability Management: Moving away from the liability management rating (LMR)” (last visited 21 August 2024), online: <www.aer.ca/providing-information/by-topic/liability-management>. See Auditor General of Alberta, Liability Management of (Non-Oil Sands) Oil and Gas Infrastructure: Alberta Energy Regulator (Alberta: Auditor General of Alberta, 2023), online (pdf ): <www.oag.ab.ca/wp-content/uploads/2023/03/Liability-management-oil-gas-mar2023.pdf>.
40. Alberta Utilities Commission, supra note 1 at para 152.
41. Letter from Minister Nathan Nuedorf, supra note 2 at 3.
42. Alberta Utilities Commission, supra note 1 at para 184.
43. In 1996 at the time of competitive generation market opening, transmission costs were $557M; in 2023, costs were $2,729M, an increase of 390%. During that period of time, peak load grew from 7,818 MW to 12,384 MW, an increase of 58%. See Alberta Electric System Operator, 2023 Year in Review: Management’s Discussion and Analysis, (2024), online (pdf): <www.aeso.ca/assets/2023-AESO-Financial-Results_WEB.pdf>. See also Alberta Electric System Operator, 2023 Year in Review: Acting now to create the power system of the future, (2024), online (pdf): <www.aeso.ca/assets/2023-AESO-Year-in-Review_WEB.pdf>. See also Re Gridco, (1990), Proceeding 7051, Disposition ED95124, Applications 162369-1-6, at 85, online: Alberta Utilities Commission <www2.auc.ab.ca/Proceeding26911/ProceedingDocuments/26911_X0583_26911%20VIDYA%20Evidence%20-%20Transmission%20in%20Context_000806.pdf#search=162369>.
44. Alberta Utilities Commission, supra note 1. “The reclamation risk profile for renewable power plants is relatively lower than other industries’ reclamation risks as there is no fuel depletion risk and a lower contamination risk” at 37.
45. Recall that in the five years between open generation competition (1996) and open retail competition (2001) no major generation was built, and in 2000-2001 market prices grew so high that deferral accounts were imposed by the government to mitigate the rate shock.
46. See Alberta Electric System Operator, AESO 2023: Reliability Requirements Roadmap, (2023), online (pdf): <www.aeso.ca/assets/Uploads/future-of-electricity/AESO-2023-Reliability-Requirements-Roadmap.pdf>.