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Key developments in Alberta’s power industry in 2022

This article originally appeared in our Power Perspectives 2023 publication and provides a look back at some of the key developments and decisions in the Alberta power market occurring in 2022. Power Perspectives 2023 provides an in-depth overview of the most significant developments in the Canadian power and emerging energy sectors from the previous year. Download the full publication here.

Our National Energy Group continues to monitor new developments in Alberta and throughout Canada. Further and more recent insights can be found on our Canadian Energy Perspectives blog

  1. Introduction & Market Update

Following the Government of Alberta's commitment in its June 2020 Recovery Plan to diversify Alberta's energy industry and as noted in the Alberta Electric System Operator's (AESO) 2022 Long-term Transmission Plan, the province of Alberta (the Province, or Alberta) continues its shift away from coal-fired to gas-fired generation in the electricity market, with continued development and advancement of alternative energy sources.

Throughout 2022, Alberta’s electricity market continued its emphasis on energy efficiency and emission reductions.  As plans continue to push for a more decarbonized and decentralized future, Alberta will have to balance such advances with system reliability and affordability for rate payers. To this end and as discussed in detail below, the AESO released its Net-Zero Emissions Pathways Report (Net-Zero Report) on the transition of Alberta’s electricity system to a net-zero carbon emissions scenario by 2035. The Net-Zero Report analyzed different supply and demand factors and their effects on the electricity market, system reliability and the costs associated with electricity supply and transmission on the road to a net-zero future.  The AESO is also engaging stakeholders with respect to its 2023 Reliability Requirements Roadmap, with a purpose of providing stakeholders with an understanding of the AESO’s approach and plans to ensure reliability are sustained as the industry transforms to a more decarbonized and decentralized system. 


Learn more

© Source: AESO, “Installed Capacity by fuel source”, Understanding Alberta’s Electricity Mix (2022), online:

In 2022, Alberta took a number of steps toward its goals of a transformed generation mix, including awarding 25 carbon capture, utilization and storage (CCUS) hub projects, establishing a framework for geothermal resource development and it continued to evaluate the legislative and regulatory regime governing hydrogen. The AESO and the Province are also evaluating and reviewing the legislative scheme governing the electricity market in Alberta, including facilitating self-supply and export of energy and considering the way in which energy storage technologies can be integrated into Alberta's Interconnected Electric System while maintaining a fair, efficient and openly competitive market.

   2. Key Developments in 2022

(a)     Regulatory Updates
  • AESO Net Zero Pathways Report

In June 2022, the AESO released their Net-Zero Report on the transition of Alberta’s electricity system to a net-zero carbon emissions scenario by 2035. The Net-Zero Report analyzed different supply and demand factors and their effects on the electricity market, system reliability and the costs associated with electricity supply and transmission on the road to a net-zero future.

Key Net-Zero Scenarios

The Net-Zero Report focused on three key scenarios studied by the AESO:

  1. Dispatchable Dominant scenario where Alberta’s energy supply continues to include a significant number of thermal units with low carbon emissions (likely resulting from the implementation of carbon capture and sequestration and hydrogen combustion technologies);
  2. First-Mover Advantage scenario, where renewable supply (wind and solar) continues to grow, with the addition of moderate amounts of energy storage, and begins to displace existing thermal units; and
  3. Renewables and Storage Rush scenario, envisioning even faster growth in renewable supply, coupled with high volumes of energy storage to displace an even larger proportion of the low-carbon thermal supply.

Each of these scenarios includes the use of carbon offsets, to varying degrees, as the Net-Zero Report found the total physical elimination of carbon emissions was operationally unrealistic.

        2035 Transition Goal

While the AESO forecasts that a net-zero transition by 2035 is attainable under any of the above three scenarios, these scenarios are still highly uncertain and not without risk. In particular, there is a risk to sufficient electricity supply if legacy unabated gas generation units are retired before sufficient new renewable or low-carbon thermal generation is available to replace them. This becomes a bigger risk in the winter months when Alberta’s demand is typically highest. The Net-Zero Report also concluded that further study is required on other aspects of system reliability (such as ramping capability, inertia and frequency response) and possible impacts and mitigations in a net-zero scenario.

The Net-Zero Report suggests significant investment of capital and operating costs will be required over the AESO’s 2021 LTO Reference Case baseline to achieve net-zero by 2035, representing an additional $44 to $52 billion, depending on the scenario. These amounts include capital investments for new generation (including a return on investment), operating costs and transmission revenue requirements. Of the three scenarios examined, the Net-Zero Report suggests the First-Mover Advantage Scenario will have the lowest overall costs. 

  • The Net-Zero Report assumes that the regulatory and political environment would continue to encourage a net-zero transition, and that existing programs (including those implemented pursuant to the Technology Innovation and Emissions Regulation (TIER)) would continue along their current trajectories. Changes in energy policy and regulation at the provincial or federal level, developing technologies as well as the changing economics of low carbon power sources (such as renewables, small modular reactors, hydrogen and energy storage) may all have an effect on Alberta’s road to a net-zero electricity system, which the AESO will continue to monitor.   
    • Update on Alberta’s CCUS Hubs

In May 2021, Alberta Energy announced a new competitive bid process for issuing rights for carbon sequestration. The process focuses on the development of strategically located carbon sequestration hubs, allowing for additional volumes and multiple sources of CO2 to be stored and avoiding stand-alone injection operations.

As of the fall of 2022, Alberta approved, through two competitive bid processes, a total of 25 hub proposals. Following a significant amount of interest, the Province closed its first Request for Full Project Proposals for Carbon Sequestration Hubs (RFPP) in Alberta's industrial heartland region on February 1, 2022 and shortly thereafter, selected six projects to develop carbon sequestration hubs. All six have entered evaluation agreements with the Province. On October 4, 2022, following the second RFPP, the Province approved 19 additional projects for carbon sequestration hubs across Alberta.

The selected companies will begin exploring how to safely develop their carbon storage hubs and, following a successful evaluation demonstrating the proposed project can provide permanent storage, companies will have the opportunity to apply for the right to inject captured CO2. The Province also announced it will invest $40 million in 11 CCUS projects through Emissions Reduction Alberta.  Emissions Reduction Alberta re-deploys funds collected under the TIER through investments aimed at reducing greenhouse gas emissions and growing Alberta’s economy by accelerating the development and adoption of innovative technology solutions.

(b)    Alberta Utilities Commission Hydrogen Inquiry Report

The Alberta Utilities Commission (AUC) commenced an inquiry in March 2022 into the viability and impacts of hydrogen blending into natural gas distribution systems in Alberta (Hydrogen Inquiry). The AUC subsequently submitted a report on the Hydrogen Inquiry to the Minister of Energy on June 30, 2022 and on September 6, 2022 released the report to the public (Hydrogen Report).

The Hydrogen Report provides the Province with findings, observations and considerations intended to guide the development of legislation for hydrogen blending in Alberta. The Hydrogen Report also identified areas for future study, including, hydrogen distribution systems, renewable natural gas and pure hydrogen pipelines serving customers. It is expected the Province will move forward with the development of hydrogen related legislation and future studies in the near future.  As outlined in the Hydrogen Report, key findings and challenges facing hydrogen development (based on feedback from stakeholders) include:

  • Reducing legislative barriers: to enable hydrogen blending, the Gas Utilities Act and Gas Distribution Act should be amended to include “up to 20 percent hydrogen by volume blended within a low-pressure natural gas distribution system”.
  • Agency oversight: the current division of responsibilities among the agencies in Alberta is capable of accommodating hydrogen development and integration and a government-initiated review could be considered to reduce ambiguity.
  • Rural community blending: given hydrogen blending is less practical for rural natural gas consumers, there is likely no need for a regulatory requirement for rural communities or any rural gas co-operatives to blend hydrogen.
  • Rates payable by consumers: it is premature to consider how costs associated with hydrogen blending should be allocated among consumers. Currently, only prudently incurred distribution infrastructure costs to enable hydrogen blending should be recovered from customers.
  • Credits and tax rebates: as the cost burden of hydrogen blending may not outweigh benefits of emission reductions and carbon tax savings offered, the Province may want to consider supports for customers in the form of credits, tax rebates or subsidies to reduce the burden on individual customers.


(c)    Recent AUC Decisions
  • AUC Decision (27048-D01-2022) – 2023 Generic Cost of Capital Proceeding – released March 31, 2022

The AUC in its Decision 27084-D01-2022 (the 2023 GCOC Decision) approved a return on equity of 8.5% of a deemed equity ratio of 37% for Alberta utility operators in 2023 (the same as was approved in 2021 and 2022). The parameters established in the 2023 GCOC Decision do not apply to EPCOR Energy Alberta GP Inc., Enmax Energy Corporation and Direct Energy Regulated Services as these entities are regulated separately as rate providers.

Recognizing the lingering market uncertainty and continued volatility caused by COVID-19, the AUC indicated its intent to extend the generic cost of capital parameters for 2023. The second stage of the 2023 GCOC Decision will determine the parameters for 2024 and future years.

  • AUC Decision (27047-D01-2022) – Application for Adjusted Metering Practice - released May 31, 2022

In this decision, the AUC denied an application for the approval of the adjusted metering practice (AMP) implementation plan and related amendments to the independent system operator (ISO) tariff and to Section 502.10 of the ISO Rules from the AESO.

The AUC found that the AESO had not provided sufficient information to determine whether the approval was in the public interest or supported the fair, efficient, and openly competitive operation of the electricity market. Specifically, the AESO failed to provide accurate information on cost estimates and information justifying timing differences between substation categories.

The AUC found the ability of the AMP to reduce significant billing determinant erosion was no longer clear and questioned the value of implementing AMP, due to the phase-out of distribution-connected generation credits, which eliminates one of the major causes of billing determinant erosion. As a result, the AUC determined that the AESO was not required to submit a further application to propose an implementation plan for the AMP but provided direction regarding what information would be required, should they wish to do so. 

  • AUC Decision (27013-D01-2022) - ATCO Electric Ltd. Administrative Penalty Decision – Released June 29, 2022

The AUC issued an administrative penalty to ATCO Electric Ltd. (ATCO) with respect to the Jasper Interconnection Project (Jasper Project) and the Trans Mountain Pipeline Expansion Project (Trans Mountain Pipeline). The issue in question involved a joint venture between ATCO Structure & Logistics Ltd. (ASL) and Simpcw Resources LLP (Simpcw), a commercial entity wholly owned and operated by the Simpcw First Nation, created with a purpose of obtaining contracts for the operation of workforce camps for workers constructing the Trans Mountain Pipeline.

The penalty arose from the award by ATCO of access and matting as well as clearing work around the transmission corridor of the Jasper Project (Matting Work), directly to Blackwoods Contracting Ltd. (Blackwoods), an affiliated entity of Simpcw, after a third party had been selected through an open request for proposal process. The decision to award the Matting Work to Blackwoods was based on the threatened termination of ASL’s Joint Venture Agreement with Simpcw, resulting in the potential loss of camp work contracts should Blackwoods not receive the Matting Work.

The AUC held that ATCO improperly took ASL's interests into account when assessing whether to award the Matting Work contract to Blackwoods, knowing Blackwoods rates were above fair-market value, resulting in approximately $10.8 million of overage costs. Knowing that recovering above fair-market value costs from ratepayers was in contravention of the Inter-affiliate Code of Conduct and the ISO Rules, ATCO asked the AUC to approve an addition of $119.1 million to its rate base for recovery of costs in relation to the Jasper Project, which included the full costs incurred under the Blackwoods contract. It was found that no attempts were made by ATCO to transfer the difference between the fair-market value and the Blackwoods rates to a non-regulated account.

In its Decision, the AUC issued an administrative penalty in the amount of $31 million to ATCO, having regard for the seriousness of the contravention and the harm caused, being financial harm to rate-payers and the breach of trust and erosion to the public's confidence in the AUC's regulatory process. ATCO has also committed to amend its deferral account application to exclude from its claim all costs above fair-market value for the Matting Work contract.

(d)    AUC Decision (26911-D01-2022) – Alberta Electric System Operator Bulk, Regional and Modernized Demand Opportunity Service Rate Design Application – Released November 10, 2022

In this decision, the AUC denied a rate design application from the AESO. The bulk and regional rate design relates to the recovery of wires costs for both the bulk and regional portions of the Alberta transmission system.  The AESO’s current bulk and regional rate was approved over 15 years ago.

In its application, the AESO deviated from past applications and sought to modernize its demand opportunity service (DOS) rate design, a non-firm rate that allows additional use of available transmission capacity that would not otherwise be used. The AESO argued that the current rate design is no longer valid because it does not recognize that an increasing amount of transmission investment is being driven by investments to accommodate the flow of in-merit energy. Additionally, the AESO raised concerns that some customers are able to avoid charges that were previously thought to be unavoidable, reducing the amount of  money recovered from these customers to pay for transmission system costs.

As noted by the AUC in its decision, many stakeholders, representing a range of interests, participated in this proceeding and none supported the AESO’s proposed rate design. The primary concerns highlighted by stakeholders were the AESO’s approach to the rate design, the relevance of the monthly coincident peak billing determinant, and modernized DOS’ application to energy storage resources.

In support of its rejection of the AESO’s application, the AUC cited the potential of sending inappropriate price signals to consumers in its decision. The decision highlighted that the focus of cost recovery must shift to a more narrow focus on the efficient use of surplus off-peak transmission capacity as well as fairness in sunk cost recovery. Additionally, the AUC found there to be significant risk that the increased Rate DOS under the proposed modernized approach could “cannibalize” Rate DTS use. While the AUC denied the AESO’s rate application, it noted that the proceeding provided a solid foundation to reassess core rate design elements moving forward.

(e)    MSA Investigations

The Market Surveillance Administrator (MSA) is a public agency created to protect and promote the fair, efficient and openly competitive operation of the electric and retail natural gas markets in Alberta.

On September 2, 2020, the MSA issued a public notice outlining its decision to initiate an investigation in accordance with the Alberta Utilities Commission Act. The investigation was intended to focus on the Balancing Pool's conduct in relation to potential breaches of the Electric Utilities Act, the Fair, Efficient and Open Competition Regulation and the Settlement Agreement between the MSA and Balancing Pool that was approved by the AUC in January of 2020.

In its Q4 2021 Quarterly Report issued in February of 2022, the MSA announced that its investigation has been discontinued. The MSA determined that it was not in the public interest to continue the investigation further or proceed with enforcement action because: (i) it has no current or future physical or financial interest in the Alberta electricity market; (ii) the Balancing Pool has no access to funds other than charges levied on electricity consumers through the Balancing Pool Allocation; and (iii) there is limited specific or general deterrence that would result from proceeding with this matter, since the Balancing Pool was a unique market participant that is no longer in the market.

(f)    Legislative Amendments – Bill 22 – Electricity Statutes (Modernizing Alberta's Electricity Grid) Amendment Act, 2022

On April 27, 2022 the Government of Alberta introduced Bill 22, the Electricity Statutes (Modernizing Alberta’s Electricity Grid) Amendment Act, 2022 (Bill 22). If this sounds familiar, it could be because Bill 22 is a revision of Bill 86 Electricity Statutes Amendment Act (Bill 86), introduced in the previous legislative session but never passed.  Like its predecessor, Bill 22 seeks to modernize Alberta’s electricity system by amending several of its governing statutes and regulations including the Alberta Utilities Commission Act (AUC Act), the Electric Utilities Act (EUA), and the Hydro and Electric Energy Act (HEEA).

Bill 22 introduces some key modernizing changes to Alberta’s electricity market, including:

  • a formal definition for energy storage in Alberta’s legislative and regulatory framework;
  • allowing distribution and transmission utilities (DFOs and TFOs, respectively) to own and/or operate energy storage assets under specific conditions set out in HEEA and the EUA;
  • allowing competitive models to be used to procure distribution and transmission services from market participants;
  • adding a definition of self-supply with export and including exemptions to broadly enable market participants to choose self-supply and export and ensures such facilities pay their fair share of system costs through the AESO’s tariff; and
  • re-assigning many of the current responsibilities of the Balancing Pool to other entities, allowing the agency to begin to wind down.
Incorporation of Energy Storage

Bill 22 implements formal definitions of an “energy storage facility” and an “energy storage resource” into the existing regulatory framework. Generally, the construction and operation of energy storage facilities will be subject to an AUC approvals process under HEEA, like that currently required for hydro developments and power plants.  Bill 22 also contains an exception to requirements for an AUC approval for energy storage facilities where a proponent is storing for their own use (unless and until the AUC otherwise directs or sets out in its rules). 


Bill 22 introduces a formal definition of “self-supply”, being the production of electric energy on a property such that any of that energy is consumed on that property by the owner or tenant. The EUA will not apply to that portion of self-supply which is consumed by the owner or tenant (except in respect of rate setting and tariffs), meaning parties can produce an unlimited amount of energy for self-supply and may also export excess electric energy to the grid. Previously, the AUC’s interpretation of section 2 of the EUA meant that owners who wished to self-supply had to consume the entirety of the energy produced on their property and could not export to the grid, unless they qualified for specific exemptions set out under the EUA or the AUC’s rules.

Along with the new definition of self-supply, Bill 22 introduces new cost recovery mechanisms, allowing the AUC to approve tariffs which recover a share of transmission costs from market participants that self-supply or DFOs providing distribution to market participants that self-supply.

Distribution and Transmission Owners

TFOs and DFOs may incorporate energy storage resources into their systems if approved by the AUC as part of a needs assessment document under Section 34(3) of the EUA. However, Bill 22’s amendments to the EUA provide that a TFO may not offer electric energy or ancillary services associated with such energy storage resource to any electricity market, an exception to the general rule that energy entering or leaving the interconnected system be exchanged through the power pool.

The AUC may approve such energy storage facilities where the DFO is not otherwise able to competitively procure non-wires services or under public interest and economic considerations where: (i) there is only 1 non-wires provider available, (ii) competitively securing non-wires services is not economic; or (iii) the proposed use of an energy storage facility would provide superior safety and reliability to the distribution system. Similar to the restrictions on energy resources for TFOs, new Section 105(1.1) of the EUA provides that DFOs may not offer electric energy or ancillary services from approved energy storage resources to any electricity market.

Bill 22 received Royal Assent on May 31, 2022 and the amendments will go into force on proclamation, presumably with some additional regulations to follow.


  3. Noteworthy AUC and ISO Rule Changes

A summary of the noteworthy AUC and ISO Rule changes are outlined below.





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

Bulletin 2014-11 providing application exemptions for power plants capable of generating 1 megawatt (MW) or greater but less than 10 MW solely for the owner’s own use has been replaced by Bulletin 2022-04. Bulletin 2022-04, issued on March 24, 2022 provides that the proposed development of all power plants in the capability range of 1-10 MWs, regardless of intended use, will proceed via a checklist application. Applicants applying for power plants 10 MW or greater must submit a full application meeting the requirements of Rule 007.


Rule 023: Rules Respecting Payment of Interest

The eligibility for interest payment requirements have been simplified and interest is now calculated using simple interest at the Bank of Canada Policy Interest Rate, plus 1 ¾ percent, unless otherwise directed.


Rule 034: Utility Payment Deferral Program Billing

Rule 034 expired on June 18, 2022 and is no longer in effect. Rule 034 came into effect on June 30, 2021 and provides that for customers who deferred their utility bill payments under the Utility Payment Deferral Program Act service providers must indicate such deferral as separate line items on customer bills. Gas and electric payments not repaid will be recovered in separate gas and electric rate riders.


Section 103.5, Net Settlement Instruction

Subsections 4(1) and 4(2) of Section 103.5 were updated to require the delivery of financial security before cancelling a net settlement instruction and the condition that the ISO must be satisfied of no adverse effects.


Section 501.3, Abbreviated Needs Approval Process

Amendments to Section 501.3 simplified eligibility criteria under Section 3. The amendments removed criteria related to facility size, configurations, etc. and instead requires: (i) that a need consistent with the criteria of subsection 34(1) of the EUA be identified; (ii) the transmission facility project is identified as an appropriate option to meet that need; and (iii) the ISO reasonably expects the costs of the transmission facility to be less than $25,000,000 with system costs not to exceed $15,000,000. 

Updates were made to the conditions for approval under Section 4 and confirmation that the transmission facility project is not anticipated to result in significant environmental defects was added. Requirements related to how the ISO conducts assessments of needs and options were also removed.

The approval process set out under Section 5 was also updated, removing the requirement to provide an approval letter to the market participant.


Section 103.3, Financial Security Requirements

Section 103.3 was revised to include a minimum level of financial security, increase unsecured credit limits, remove the process for assigning proxy credit ratings, clarify the forms of financial security, include rights to request financial information and clarify the rights of the ISO in the event of a material adverse change, including the right for ISO to extend deadlines for the delivery of additional or replacement security.

 4. Alberta Energy Regulator Bulletin Updates

  • Alberta Energy Regulator Directive 089: Requirements for Geothermal Resource Development

The geothermal industry is growing in Alberta and is anticipated to be a key player in the push to achieve federal and provincial net-zero goals. In June 2022, the Alberta Energy Regulator (AER) released the Geothermal Resource Development Rules (GRDR) and subsequently on August 15, 2022, released Directive 089: Geothermal Resource Development (Directive 089). The GRDR provides the regulatory framework for geothermal development in Alberta, and Directive 089 sets out the requirements for several issues related to geothermal developments from inception to closure. Some of the regulatory requirements applicable to geothermal projects overlap with those of oil and gas projects, including the Licensee Management Program. Under the new Licensee Management Program, geothermal developers will be subject to a holistic licensee assessment, security deposit requirements and estimates of liability.

A notable difference from the oil and gas regime is with respect to surface rights. Directive 089 states that the Surface Rights Act does not apply to geothermal developments. An applicant for a geothermal development will therefore be required to obtain written consent granting surface access from the appropriate landowner. Additionally, Directive 089 states an applicant must have a geothermal resource tenure lease from the Province or documented authorization from the freehold mineral owners.

Directive 089 specifies the different licenses required for geothermal development, which can include a well license, a facility license and a pipeline license. Depending on the type of development, an applicant may require further authorizations under applicable legislation, including the Environmental Protection and Enhancement Act, the Public Lands Act or the Water Act. Finally, Directive 089 also lays out the steps required by applicants who wish to convert an oil and gas well to a geothermal well. Given the interest in conversions of this nature due to potential cost savings and reduction of orphan wells, the process for conversion within Directive 089 is particularly noteworthy.

The release of the GRDR and Directive 089 settled many outstanding questions surrounding Alberta’s geothermal development future, and further investment in the industry within Alberta is expected to follow.

  • Alberta Energy Regulator invitation for Feedback on Proposed New Requirements for Brine - Hosted Mineral Resource Development and Directive 056

The introduction of Bill 82: Mineral Resource Development Act (Bill 82) by the Government of Alberta in December of 2021, once proclaimed, will provide the AER with the authority to regulate the development of Alberta’s mineral resources. To align with the introduction of Bill 82, the AER made changes to Directive 056: Energy Development Applications and Schedules (Directive 056) in order to include geothermal and brine-hosted mineral development requirements.

The revisions to Directive 056 now provide for well, pipeline and facility licensing requirements for both geothermal and brine-hosted mineral developments. The proposed amendments to Directive 056 introduce processes and requirements unique to brine-hosted minerals development and incorporates applicable oil and gas regulatory instruments, where appropriate.

In light of the revisions to Directive 056, the AER sought feedback on the amendments by October 31, 2022, and despite the revisions related to geothermal development, the AER specifically sought feedback on the brine-hosted mineral aspects of the revisions during that period. Following stakeholder feedback, the revised Directive 056 is expected to be released in 2023.

  5. What’s Next?

In 2023, Alberta’s final 1200 MW of coal-fired generation capacity is anticipated to be converted to natural gas.  In less than 9 years, Alberta transformed its generation mix from over 50% coal-fired generation to none.  Alberta’s next provincial election is scheduled for May 29, 2023.  Regardless of the outcome of that election, in the near-term, we expect Alberta will continue its transformation, which is likely to pair renewables, energy storage and new technologies with natural gas generation for system reliability.  This transformation will require a balancing of decarbonisation, reliability and affordability. According to the MSA’s Quarterly Report for Q3 2022, the average pool price in Q3 was $221.41/MWh (an increase of 121% over the Q3 2021 pool price) which is also highest quarterly average pool price on record (using data back to Q1 2001).  With such high prices and a provincial election on the horizon, we expect considerable debate about the affordability for rate payers and whether market design changes or government back-stops will be required to facilitate the transformation.

The beginning of 2023 is expected to set the foundation for much of the work needed to continue to strive toward net-zero.  We hope to see Bill 22 come into force helping to facilitate the incorporation of more energy storage and self-supply to the system.  In addition, it is expected that development of the CCUS hubs will continue which will facilitate both the development of hydrogen infrastructure and emission reductions from large emitters across a range of industries. We also anticipate continued progress toward the implementation of Bill 82 in Alberta with two new regulations approved in December, 2022. The Metallic and Industrial Minerals Tenure Regulation includes new tenure provisions for brine-hosted minerals and came into force on January 1, 2023, while the Mineral Resource Development Regulation will come into force upon proclamation of the Mineral Resource Development Act. Following the election, we expect policy announcements influencing the electricity market and will continue to monitor new developments.



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