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Canadian Power – Alberta Regional Overview

Introduction & Market Update 

Over the past year, Alberta’s energy industry has continued to be the central focus for the Province with an emphasis on innovation and diversification. In 2020, Canada faced the largest public health crisis in a century, the worst global economic crisis since the 1930s and a crippling collapse in energy prices. In response to the downturn, the Government of Alberta released a Recovery Plan in June 2020. The Province committed to diversifying Alberta’s energy industry through a number of strategies and regulations which include: (i) Alberta’s Natural Gas Vision and Strategy which lays out a plan for the Province to become a global supplier of clean, responsibly sourced natural gas, which includes the supply of hydrogen; (ii) a new mineral strategy to optimize Alberta’s resource potential, including lithium; and (iii) the introduction of Bill 36, the Geothermal Resource Development Act, to establish a regulatory scheme for the development of geothermal resources. 

Alberta’s generation mix is expected to undergo a major shift as federal and provincial policies drive the retirement of all coal-fired generation by 2030. The Alberta Electric System Operator (“AESO”) forecasts that coal will be replaced with a mix of natural gas generation and renewable energy. Alberta’s merchant power market presents a unique opportunity for innovation and investment in clean energy in the Province through its many features, including the carbon market, power purchase agreements and government incentives targeted at moving toward a greener and diversified economy. 

Throughout 2020, the ongoing effects of COVID-19 and low oil prices caused significant disruption to Alberta’s electricity industry and the economy more broadly. The AESO indicates that load at behind-the-fence (”BTF”) industrial sites, which are primarily oil and gas related facilities, began to decline due to persistently low oil prices, and in August, Alberta Internal Load (“AIL”) hit its lowest levels at 950 MW, 10% below weather adjusted normal. According to the Market Surveillance Administrator (“MSA”), 2020 had the highest amount of supply surplus of any year in the last 20 years. Q3 2020 observed 1,865 minutes of supply surplus; the previous high was 231 minutes in Q3 2012. 


Alberta graph

Key Developments in 2020 


With respect to energy storage, Alberta is a flurry of activity. Alberta’s first transmission connected energy storage project was completed in September 2020, and there are 10 additional energy storage projects within Alberta’s connection queue. 

In August 2019, the AESO released its Energy Storage Roadmap setting out a plan to facilitate the integration of energy storage technologies into the AESO’s Authoritative Documents and the AESO’s grid and electricity market. Highlights of the regulatory initiatives undertaken in 2020 to implement energy storage into Alberta’s grid are discussed in detail in our storage article at page 69 of this publication. 


The Alberta Utilities Commission (“AUC”) launched the Distribution System Inquiry (“DSI”) in December 2018 to provide a forum for Alberta’s electricity industry to consider a regulatory response to mounting economic and technological pressures affecting Alberta’s electric distribution systems. The inquiry was comprised of three modules, collectively focused on understanding three key questions: 

– How will new technologies affect the grid and existing electric distribution facility owners and how quickly?

– How will incumbent electric distribution utilities be expected to respond to alternative approaches to providing electrical services, and which of these services should be subject to regulation? 

– How should electric distribution facility rate structures be modified to incentivize efficient and cost-effective use of the grid? 

The AUC identified certain emerging trends and innovations in Module One, which concluded on November 15, 2019. 

" Notably, the AUC found that there was greater customer choice and control over electricity consumption, and Alberta’s electricity market had become more competitive.  "

Modules Two and Three both concluded on July 15, 2020. Module Two examined the interplay between the trends identified in Module One and certain forces affecting existing distribution utilities: changing consumer preferences, service prices, taxes, subsidies and government incentives aimed at consumer behavior. The resulting discussion included which distribution utility services ought to be regulated, the related implications for the monopoly franchise and the obligations to serve, and to what extent (if any) new entrants should be regulated by the AUC. 

Module Three examined the ability of current rate designs to encourage investment in distribution systems and deter uneconomic bypass of regulated facilities.

The considerations included: 

– What information from regulated utilities should be made available to new entrants for the purposes of interconnection, physical co-location of facilities, and unbundling of or equal access to facilities? 

– Should information from new entrants be made available to other market participants, and if yes, on what terms? 

– What process should the AUC follow to consider regulatory changes meant to deal with the issues identified by the DSI?

The DSI was conducted by way of a series of information requests and written submissions. The final DSI report, which has yet to be published, is expected to set out a regulatory framework intending to facilitate efficient outcomes in Alberta’s utilities market. 


DCG reduces strain on the system by displacing power that would otherwise have to be imported by distribution facility owners (“DFOs”) from the transmission system. DCG reduces congestion, lowers line losses and enhances system reliability by having generation located closer to consumers. 

Several DFOs’ tariffs give a transmission-based credit to large-scale DCG providers for the electrical energy they supply to the distribution system. 

The credits are calculated by determining the difference between the AESO system access service charges to a DFO with a distributed generator in operation and the charges that would have been incurred had the distributed generator not been in operation. The idea is to encourage DCG by providing a credit for the reduced amount of electricity a DFO draws from the power pool when a distributed generator interconnects with its wires. 

The future of DCG credits has been uncertain since the AUC’s 2018 ISO Tariff Decision issued on September 22, 2019. In this proceeding, the AUC noted evidence of a cross-subsidy resulting from DFOs being required to provide credits to DCG providers but not receiving any corresponding benefit. DFOs recover the cost of DCG credits by passing transmission costs on to load customers, meaning that, in effect, load customers are forced to subsidize the cost of DCG.

The DSI more recently contemplated the following key submissions regarding DCG credits:

Alberta graph

In early March 2021, the AUC is set to hear AUC Proceeding 26090 which will consider whether DCG credits shall continue to be implemented in a distribution utility’s tariff. Currently, through their respective utility tariffs, each of FortisAlberta Inc., ATCO Electric Ltd. and ENMAX Power Corporation offer DCG credits. The AUC intends to decide this matter for all distribution tariffs and the AUC currently anticipates its determination in this proceeding will affect each of ATCO Electric, ENMAX and FortisAlberta as well as their customers, and the owners and operators of DCG units that receive benefit from DCG credit mechanisms.

DCG credits do not operate in a vacuum - they are intertwined with a number of other tariff, transmission and distribution system planning issues. It is within the context of these broader policy considerations that the fate of DCG credits will be determined. The future of DCG credits will likely be borne through the result of regulatory and distribution tariff proceedings, such as AUC Proceeding 26090, and the industry and market participants can likely expect the final DSI report to provide a regulatory framework which is intended to achieve competitive market outcomes. 


Following the AUC’s Decision 25848-D01-2020 (the “Decision”) in late December 2020 varying Decision 2294-D02-2019, lenders and project developers within Alberta can expect impacts to connection costs for DCG projects. The Decision approved the AESO proposed adjusted metering practice and use of the substation fraction methodology to allocate the costs of interconnection facilities that may have joint use as part of the 2018 independent system operator (“ISO”) tariff. 

Highlights of the material findings and outcomes include: 

– The AUC approved the AESO’s proposed substation fraction methodology of one (“SSF=1”) at all DFO contracted substations on a prospective basis which will attribute all connection costs to Rate Demand Transmission Service (“Rate DTS”) contracts and none to Rate Supply Transmission Service (“Rate STS”) contracts.

– The AUC confirmed that incremental costs which result from the connection of the DCG to the distribution or transmission system or alteration of connection facilities should flow through to DCGs. In order to adequately and accurately allocate incremental connection costs of the transmission system to DCGs that caused those costs, in all future customer contribution decisions (“CCDs”), the AESO was directed to clearly identify the DCG incremental transmission connection costs. 

– Past CCD recalculations may have allocated costs to a DCG which did not reflect the actual incremental costs associated with their connection to DFO-contracted substations. In response, the AESO is directed to (i) reallocate such additional costs from the Rate STS to the Rate DTS, and (ii) recalculate CCDs using the SSF=1 methodology, in each case retroactively back to December 1, 2015, and inform the DFOs of those recalculations. The DFOs are directed to file a report with the AUC by March 31, 2021, with the details of the resolution of any such disputes with such DCGs. In future CCDs, the AESO will be responsible for clearly identifying, to the extent possible, the DCG incremental transmission connection costs. 

– A new adjusted metering practice changing the point of totalization from the high side of a substation to the feeder level and impacting DCG credits and Rate STS contract capacities was approved by the AUC. The AUC determined this adjusted metering practice proposed by the AESO should be implemented without grandfathering and directed the AESO to submit revised tariff language as part of its compliance filing and implementation details in its next phase 2 tariff application.

– The AUC acknowledged that the adjusted metering practice will affect the availability of metering information currently used for the calculation of DCG credits. However, the AUC determined the issue with respect to the continuation of DCG credits is a distribution tariff matter and will be dealt with in AUC Proceeding 26090. AUC Proceeding 26090 will consider whether DCG credits should continue to be included in a DFO’s tariff. AUC Proceeding 26090 is currently expected to be heard by the AUC during the second week of March 2021. 

Noteworthy, and what will likely be carried forward to future decisions considering cost allocations, is the AUC’s confirmation of the principle (established in AUC Proceeding 25101) that following energization, costs should not be allocated to a DCG if the DCG has not directly caused those costs. In other words, costs should be borne by the party benefitting from the connection project.The full effects and impacts of the Decision will be understood in the coming months. 

The AESO’s required compliance filing to effect the Decision was filed on January 11, 2021. DFOs must file reports by March 31, 2021, setting out the details of all resolutions and outstanding disputes pertaining to DCG flow-through matters.


In fall 2019, on behalf of the Alberta Department of Energy, the AUC issued Bulletin 2019-16 launching consultation on the issue of power plant self-supply and export. In the first round, the AUC sought stakeholder input on the following options for addressing the selfsupply and export issue in the future: 

Option 1: Status quo
Option 2: Limited self-supply and export
Option 3: Unlimited self-supply and export

In the second round of engagement, the AUC asked stakeholders to provide comments on the market and tariff implications of unlimited power plant self-supply and export. 

On June 5, 2020 the AUC provided the Department of Energy with a discussion paper which summarized the views of market participants on how best to address the issue of power plant self-supply and export going forward. 

The feedback received by the AUC was that most stakeholders do not oppose unlimited self-supply and export and generally agree that accommodating unlimited self-supply and export while preserving a fair, efficient and openly competitive market requires appropriate, tariff-based incentives. However, stakeholders disagreed on whether existing transmission and distribution tariffs provide the correct incentives to accommodate unlimited self-supply and export. A majority of stakeholders recognized that these issues will be more fully canvassed in the AUC’s DSI and the upcoming AESO tariff proceeding. 

The discussion paper recommends that regardless of which option the Province decides to implement, the statutory scheme should be amended to clarify the circumstances in which self-supply and export is expressly permitted to ensure regulatory certainty for stakeholders. Before the AUC can effectively address the tariff issue, the Department of Energy must decide, from a policy perspective, whether it wishes to allow self-supplying generators that do not otherwise qualify as an industrial system designation (“ISD”) to self-supply and export.

Until the Department of Energy provides further direction, uncertainty remains for co-generation and industrial systems across the Province. It is anticipated that relief in the form of statutory amendments or new AUC rules may be on the horizon in 2021. 


ISO Rule Amendments 

The following are material or substantial new or amended ISO rules established in 2020: 

ISO Rule 505.2 Performance Criteria for Refund of Generating Unit Owner’s Contribution 

Rule 505.2 was amended to clarify “generating facility” as a “generating unit or aggregated generating facility”; and its applicability to a solar aggregated generating facility. 

ISO Rule 306.7 Mothball Outage Rule (the “ Mothball Rule ”) 

" The AESO’s Mothball Rule allows generators to take mothball outages. The Mothball Rule sets out how and when generators report temporary closures of generating facilities (5 MW or greater) for periods of up to two years. "

On March 16, 2018, the MSA filed a complaint about the AESO’s Mothball Rule, which was withdrawn following an amendment to the rule by the AESO. 

Interveners in the MSA’s complaint in support of the Mothball Rule submitted that: (i) generators must be able to rely on stable market rules permitting them to manage the operation of their assets; and (ii) generators should, in the context of a deregulated market, have the right to manage their assets in an economic, businesslike and commercially effective way. Many generators rely on the Mothball Rule to operate their business efficiently. Generally, the position of these interveners was that the Mothball Rule supports the principles of fairness, efficiency and open competition that underpins the Alberta electricity market.

Interveners not in support of the Mothball Rule raised concerns about the addition of renewable generation and the early retirement of coal-fired generating units being the result of regulatory actions rather than market signals. These actions will impact supply/demand balances, and the investment price signal for retirements and generator additions. A high fidelity price signal is necessary to ensure that rational business decisions can be made and that sufficient power generation can be constructed in Alberta to meet future demand. This signal is necessary to ensure an efficient mix of technology and individual capacity is added to the generation fleet to support the growth of intermittent renewables and the replacement of Alberta’s retiring baseload coal capacity. 

In Q3 2020 the AESO reinitiated its review of the Mothball Rule to address stakeholder concerns raised in past consultations and to determine whether revisions to the Mothball Rule are required. The AESO intends to complete its regulatory review by Q4 2021. 

AUC Rule Amendments 

The following are material, substantial, new or amended AUC requirements or processes established in 2020: 

Rule 027: Specified Penalties for Contravention of Reliability Standards 

The AUC amended Rule 027, with an effective date of June 1, 2020. The changes incorporate all currently applicable Alberta reliability standards under classifications listed in the Rule 027 penalty table. 

On October 21, 2020, the AUC subsequently amended Rule 027. The previous version of Rule 027 required the MSA to publish all notices of specified penalties issued for contraventions of reliability standards, including those related to CIP. It also required the MSA to post whether penalties had been paid or whether a notice of specified penalty is disputed, and in the latter circumstances, to post a link to the resulting AUC decision relating to such dispute. This amendment to Rule 027 exempts the MSA from making public any notice of specified penalties related to contraventions of CIP reliability standards including any related documentation.

Amendments to AUC Rules to Reduce Regulatory Burdens and Improve Efficiency

In June 2020, the Province introduced the Red Tape Reduction Implementation Act to reduce regulatory burdens and improve regulatory efficiency. The AUC forms part of this commitment to review its rules in order to reduce regulatory requirements. In November 2020, the AUC initiated a rule-review process which sought feedback from stakeholders on changes to Rule 002: Service Quality and Reliability Performance Monitoring and Reporting for Owners of Electric Distribution Systems and for Gas Distributors, Rule 003: Service Quality Reporting for Energy Service Providers, Rule 021: Settlement System Code Rules and Rule 028: Natural Gas System Settlement Code Rules. The proposed changes focused on the removal of unnecessary requirements, streamlining and updating filing requirements, and the improvement of administrative efficiency. The AUC approved the amendments to Rule 002, Rule 003, Rule 021 and Rule 028 with an effective date of December 17, 2020. 

AUC Rule 007: Applications for Power Plants, Substations, Transmission Lines, Industrial System Designations and Hydro Developments 

Following stakeholder consultation, on August 7, 2020, the AUC released a revised draft version of Rule 007: Applications for Power Plants, Substations, Transmission Lines, Industrial System Designations and Hydro Developments. Feedback was sought to address emerging technologies and to eliminate duplication, clarify existing requirements and to make the rule easier to understand and to use. The Commission conducted a separate consultation process for developing Indigenous consultation processes and procedures. This is outlined further below. 

The draft Rule 007 has been reorganized and includes separate categories for wind power plants, solar power plants and thermal power plants, hydroelectric power plants, “other” power plants greater than 10 MW, and community generation.

The draft version of Rule 007 includes new requirements
to address the following:

End-of-life management for renewable energy operations – the draft Rule 007 requires applicants to: (i) submit a copy of the renewable energy operations conservation and reclamation plan prepared in accordance with the Conservation and Reclamation Directive for Renewable Energy Operations; and (ii) a plan for how the operator intends to ensure sufficient funds will be available at the end of the project to cover the costs of decommissioning and reclamation activities.

 – Emergency response plan – applicants must provide an emergency response plan that identifies any site specific risks, mitigation measures that may be implemented and appropriate site monitoring and communication protocols that may be put into place.

Time extension applications for power plants – the draft Rule 007 now requires applicants to: (i) explain why the construction or alteration completion date will not be met, why the time extension is required and provide an updated project schedule; (ii) submit a new noise assessment (Rule 012: Noise Control); and (iii) provide a list of contact information for all persons contacted for the Participant Involvement Program (“PIP”).

Solar glint and glare assessment – solar power plants must complete a solar glare impact assessment when receptors are located within 800 metres from the boundary of the project.

Shadow flicker – wind power plants must complete a shadow flicker impact assessment that predicts the shadow flicker at any dwellings within 1.5 kilometres from the centre point of the tower of the closest wind turbine. 

Battery storage – the draft Rule 007 includes 9 new information requirements for battery storage projects. If the battery storage project is intended to operate as a transmission facility, a needs identification document application by the AESO is required.

Maximum impact scenario – the draft Rule 007 acknowledges that technology continues to advance rapidly, often in less time than it takes for a project to progress through the development, permitting and pre-construction cycle. To provide applicants with flexibility to accommodate technology selection after a project is approved, the Commission allows applicants for wind, solar, thermal or “other” power plants to submit applications wherein the site-layout and/ or equipment may change after the approval is obtained. For such applications, an applicant must submit a final project update to the Commission at least 90 days prior to the start of construction, provided that applicants may not change the project site boundary for wind and solar power plants. 

The Commission held the final stakeholder consultation session for feedback on the draft Rule 007 on November 12, 2020. It is anticipated that the revised final Rule 007 will be released in early 2021. 

Rule 007: AUC PIP/Consultation 

As part of the application process for a new power plant, substation, transmission line or industrial system, the AUC requires applicants to submit an application pursuant to AUC Rule 007. As part of the application process, proponents are required to develop and implement a PIP prior to submission of an application to the AUC. PIPs include: (i) distribution of a projectspecific program; (ii) responding to questions and concerns from stakeholders; and (iii) discussion options, alternatives, and mitigation measures. 

In meeting the PIP requirements under AUC Rule 007, applicants are to ensure that all parties, including First Nations and Métis, whose rights may be directly and adversely affected by a proposed development, are informed of the application and have had an opportunity to voice their concerns. 

As currently drafted, AUC Rules 007 and 020 do not specify how Indigenous consultation should occur in the context of a PIP. In December 2019, the AUC released a bulletin for the Interim Direction on Indigenous Consultation for proponents while the AUC reviews its application requirements for consultation with Indigenous communities. The AUC first sought engagement and advice on its Indigenous consultation framework in July 2020. The AUC’s goal was to have clear requirements for Indigenous consultation by the fall of 2020. In November 2020, the AUC sought feedback from stakeholders on a revised draft of AUC Rule 007. As of the date of this publication, no publication had been finalized. 

Market Surveillance Administrator 

2020 Market Share Offer Control 

Section 5 of the Fair, Efficient and Open Competition Regulation requires that the MSA publish the percentage of offer control held by electricity market participants at least annually. An electricity market participant’s total offer control is measured as the ratio of megawatts under its control to the sum of maximum capability of generating units in Alberta. 

Alberta graph

Alberta’s total capacity increased 281 MW since the last market share offer control assessment on January 31, 2019. The increase in total capacity was primarily due to the addition of several wind assets.

Expiry of Historical Government-Backed Power Purchase Arrangements  

As the historical government-backed PPAs held by the Balancing Pool were set to expire on December 31, 2020, the MSA calculated the estimated market share offer control for 2021 and 2022. In its calculation, the MSA assumed that the offer control of the PPA units will be transferred from the Balancing Pool to TransAlta Corporation, Capital Power Corporation and Heartland Generation Ltd. at the end of 2020 and the units will remain in operation.

Alberta graph

The MSA estimates that the market share of electricity market participants with greater than 5% market share offer control will decrease in 2021 to 69% and will decrease in 2022 to 67%. This is largely due to the increase in renewable generation assets being built under the Renewable Electricity Program, which offsets the increase in offer control for TransAlta Corporation, Capital Power Corporation, and Heartland Generation Ltd. due to the expiry of the PPAs.

Revised MSA Compliance Process 

Since the last MSA Compliance Process revisions in October 2016, new Alberta Reliability Standards and sections of the ISO Rules have been adopted (including CIP reliability standards). The MSA has indicated that there may be opportunities to clarify its Compliance Process in order to reduce regulatory burdens for market participants and help achieve Alberta’s red tape reduction targets. 

On December 4, 2020, the MSA released the final revised MSA Compliance Process and associated forms which came into effect on the same date. The changes include clarifications of communication protocols, self-reporting requirements, the enforcement process and outcomes (including forbearance), compliance forms, and opportunities to provide information. 


On November 26, 2019, the Alberta Indigenous Opportunities Act received royal assent and established the Alberta Indigenous Opportunities Corporation (“AIOC”). The AIOC’s mandate is to facilitate investment by Indigenous groups in natural resource projects and related infrastructure in the Province. The AIOC is able to provide up to $1 billion in loan guarantees which supports Indigenous groups to raise capital and invest in natural resource projects. 

On September 9, 2020, the AIOC announced that its first commitment would be a loan guarantee to a consortium of six Alberta First Nations to participate in the Cascade Power Project. Cascade is a 900 MW combined cycle natural gas fired power plant being constructed near Edson, Alberta and is currently expected to be completed in 2023. 


To encourage investment in the Province, the Alberta government is reducing regulatory burdens. Their efforts are reflected by the passing of Bill 22 which introduced the Red Tape Reduction Implementation Act (the “Bill 22”). Bill 22 is omnibus legislation amending 14 pieces of legislation administered by six different ministers. These amendments are intended to increase efficiency, speed up regulatory approval processes and attract investment. For example, Bill 22 will remove the requirement for the Alberta Energy Regulator (“AER”) to obtain Cabinet approval prior to issuing final approval for new Alberta oil sands projects. In its assessment of a proposed project, the AER must consider, among other things, whether the project is in the public interest. In doing so, the AER follows a pre-determined process and generally uses evidence-based measures to minimize environmental, stakeholder and Indigenous impacts. The requirement for Cabinet approval frequently subjected projects to significant public and political debate causing delay, which in turn politicized the project and increased the regulatory uncertainty. By removing the requirement for Cabinet authorization for soil sands projects, Alberta is attempting to increase transparency and centralizing decision-making authority with the AER, as an expert tribunal. However, pursuant to the AER’s governing legislation, it does not have jurisdiction to consider or assess the adequacy of Aboriginal consultation. As a result, the uncertainty arising from Cabinet approval may simply be replaced by additional scrutiny to ensure the duty to consult has been discharged and the honour of the Crown upheld.

AUC Report

In support of the Alberta government’s goal of reducing regulatory burden, in addition to the rule changes discussed above, the AUC made the same commitment to improve the efficiency of its processes and procedures. The AUC Procedures and Process Review Committee (the “Committee”), an expert committee, was established to look into and prepare a report on the processes and procedures of rate proceedings to make them more productive and efficient. The Committee made 30 recommendations to improve AUC adjudicative efficiency, the most fundamental one being that the Commission implement a comprehensive assertive case management approach to its procedures and processes.

The AUC accepted 29 of the 30 report recommendations. These recommendations are to be adopted immediately. The AUC concluded that a legislated tightening of the AUC’s decision-making timeframes was unnecessary.

The Committee concluded that efficiency and productivity of the AUC’s processes and procedures would be improved if the AUC were to adopt an “assertive case management approach that is more reflective of the Commission’s own needs and responsibilities, while respecting the principles of procedural fairness.” The recommendations set out by the Committee and being implemented by the Commission pertain to the following procedures and processes: 

– Assertive Case Management 

– Confidentiality 

– Cross- Examination 

– Scoping of Issues 

– Hearings 

– Argument 

– Scheduling 

– Interrogatories 

– Decisions

What’s Next? 

Against the backdrop of Alberta’s Recovery Plan and the federal government’s Healthy Environment and a Healthy Economy Plan (the “Federal Climate Plan”), there are a number of opportunities in Alberta for power generation and new energy development and diversification. The Federal Climate Plan is the cornerstone of the federal government’s commitment in the 2020 Speech from the Throne to create over one million jobs, and includes 64 new measures and $15 billion in investments. This is in addition to the Canada Infrastructure Bank’s (“CIB”) $6 billion for clean infrastructure announced in October 2020 as part of the CIB’s Growth Plan, intended to target investments in clean power ($2.5 billion), the digital economy ($2 billion), energy efficiency ($2 billion), agricultural irrigation projects ($1.5 billion), and zeroemissions transportation ($1.5 billion). 


" These initiatives coupled with the retirement of Alberta’s coal-fired electricity generation fleet and its merchant market, make Alberta a prime jurisdiction for investment and growth in natural gas, renewables, advanced biofuels and other new energy sources and technologies including geothermal, hydrogen and lithium. "



On October 6, 2020, Alberta released the Natural Gas Vision and Strategy which lays out a plan for Alberta to become a global supplier of clean, responsibly sourced natural gas and related products, including hydrogen and petrochemicals. The strategy is a key part of the government’s plan to recover from a period of unprecedented economic adversity. 

The report identified hydrogen as a key growth area for Alberta. Alberta’s strategy includes large-scale hydrogen production with carbon capture, utilization and storage (“CCUS”) and deployment in various commercial applications across the provincial economy by 2030. The intention is to have exports of hydrogen and hydrogenderived products to jurisdictions across Canada, North America, and globally in place by 2040. 

Alberta has several advantages in the production of “blue” hydrogen, which is made with ultra-low emissions by upgrading natural gas. The carbon by-product generated from this process can then be captured and permanently sequestered underground or used for another purpose. 

" The hydrogen economy remains in its infancy, however Alberta is well positioned to be a major contributor given Alberta has the technology and pre-existing infrastructure to produce blue hydrogen.  "

Further commentary on the future of hydrogen in Canada can be found in the Unlocking the Potential of Hydrogen: What lies ahead for Canada? chapter of the Canadian Power – Key Developments in 2020, Trends to Watch for in 2021 publication (download full publication below).


Global demand for lithium is trending upwards as electric vehicles are becoming increasingly common. As they continue to get cheaper, battery capabilities improve, and concerns about climate change increase, demand for electric vehicles and their lithium components is expected to accelerate. On a global scale, it is expected that by 2025, electric vehicles will account for 10% of passenger vehicle sales, rising to 28% in 2030 and 58% by 2040.

This growth presents a major opportunity for Alberta. Alberta’s oil fields hold large deposits of lithium in subsurface brine. While this subsurface lithium-brine has long been overlooked as industrial waste from oil field operations, technologies known as direct lithium extraction (“DLE”) are being developed to access Alberta’s lithiumbrine potential. Considering the recent developments of DLE technologies and that Alberta’s lithium originates from many of the same reservoirs as Alberta’s existing oil and gas resources, Alberta is well-positioned to become a major lithium producer. 

On September 23, 2020, the Province announced the establishment of the Mineral Advisory Council to provide strategic advice, guidance, and recommendations on a Minerals Strategy and Action Plan for Alberta. 

Alberta’s current regulatory regime does not contemplate the production and development of lithium. One function of the Mineral Advisory Council is to explore regulatory options and the regulatory changes required to implement a lithium strategy as part of Alberta’s metallic and industrial minerals sector through stakeholder engagement. Some of the necessary changes required to facilitate development and production of Alberta’s lithium include the following: 

– Changes to the tenure permitting regulatory scheme pursuant to the Metallic and Industrial Minerals Tenure Regulation to better accommodate lithium. Specifically, extending the first two-year assessment period under the current 14-year term to give lithium producers more time to scale up their exploration. In addition, changes to permit inclusion of expenses related to the development of mineral extraction technologies as qualified expenditures to meet minimum spending requirements are required to facilitate extension of the regime to lithium. 

– Amendments to the Metallic and Industrial Minerals Royalty Regulation to create royalty rate specific to lithium. 

– Alberta Energy Regulator directives, legislation, and regulations that could apply or be adapted for lithium production. Clearly defined provisions in the Responsible Energy Development Act, the energy resource enactments, and the applicable specified enactments addressing Alberta’s emerging lithium industry will be important in order for Alberta’s lithium industry’s growth.


The global geothermal power market has been projected to grow at a compound annual growth rate of 2.6% between 2019 to 2026 and reach a value of $6.8 billion. A growing interest in geothermal development can be attributed to factors such as advances in technology, improvements in the data available, the ability for geothermal to complement other industrial and commercial practices, and the potential for geothermal to serve as a relatively clean source of heat and electricity. 

In Alberta, research has illustrated a potential to develop geothermal on a commercial scale with excess of 6,100 MW of thermal power capacity potential and 1,150 MW of technically recoverable electrical power capacity potential for a 30 year production period. The factors which contribute to Alberta’s ability to benefit from the potential of geothermal development include natural geological advantages, the expertise of the established oil and gas sector and the opportunity to repurpose inactive oil and gas wells, well sites and existing infrastructure.

On December 9, 2020, Bill 36: Geothermal Resource Development Act (“Bill 36”) received royal assent. Bill 36 is dedicated to the establishment of a regulatory framework for the development of geothermal resources in Alberta. In particular, Bill 36 establishes a framework to regulate geothermal development below the base of groundwater protection, which is the depth groundwater transitions from non-saline to saline. Bill 36 will apply retroactively to any geothermal resource development in Alberta. 

Bill 36 will provide the government and industry with clarity on rules and processes, establish an approach to land use and liability management, protect landowners and mineral rights owners, and establish the government’s authority to receive revenues (i.e. royalties and fees). As Bill 36 awaits proclamation, the Government of Alberta intends to engage with key industry partners and stakeholders in its efforts to implement clear and necessary geothermal regulations that will contribute to further geothermal development in Alberta.

Small Modular Reactors (SMR) 

On August 10, 2020, Alberta joined New Brunswick, Ontario, and Saskatchewan in signing a Memorandum of Understanding (“MOU”) supporting the development of small modular reactors (“SMRs”). This commits Alberta to work to promote the expanded use of nuclear power, a commitment that the other three provinces had made when they first signed the MOU in December of 2019. 

SMRs are expected to be considerably smaller and more versatile than traditional nuclear reactors. They are smaller in both output and physical size. SMRs typically generate between 200 to 300 MW of electricity and are modular, or small enough to be readily built in a factory and shipped easily. SMR technology has particular potential for Alberta’s energy sector, as it could help power oil sands facilities and further reduce the emissions intensity of Alberta oil. 

On December 18, 2020, the Province endorsed the newly released Canada’s SMR Action Plan. Further commentary on small modular reactors in Canada can be found in the SMRs: Canada Places a Bet that its Future Could be Nuclear chapter of the Canadian Power – Key Developments in 2020, Trends to Watch for in 2021 publication (download full publication below). 

What To Expect In 2021 

It is anticipated that 2021 will be a growth year for Albertan energy. With the release of the Alberta Recovery Plan, the phasing out of coal, increased energy storage projects, focus on innovation and push towards clean technology, it is anticipated that Alberta’s electricity industry will undergo a transition in 2021. 

The electricity industry can also expect to see significant regulatory change that will have sweeping effects for project developers and lenders as the AUC implements the red tape reduction initiative. It is anticipated that several outstanding issues will be resolved in 2021 providing increasing certainty for project developers and lenders. The AUC is set to release several reports and rule updates as well as hearings on significant issues. These include the release of the AUC’s updated PIP guidelines and the final DSI report, which is expected to set out a regulatory framework intending to facilitate efficient outcomes in Alberta’s utilities market. In addition, following the outcome of AUC Proceeding 26090 and the AUC’s DSI, industry will get some clarity on the use of DCG credits and charges going forward through the distribution facility owner tariff proceeding.



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