Canadian Power – Key Developments in 2019, Trends to Watch for in 2020: Alberta - Overview

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The following is a chapter from our Power Group's fifth annual Canadian power industry retrospective Canadian Power Key Developments in 2019, Trends to Watch for in 2020. A PDF request form is available at the end of the article. 

Introduction

With the newly elected United Conservative Government of Alberta and a new climate strategy, Alberta’s electricity industry continues to be in a state of transition. In the AESO 2019 Long-term Outlook, the Alberta Electric System Operator (“AESO”) predicted that 19% of the province’s electricity supply will be sourced from renewables in 2030. This is a 10% increase but significantly less than the 30% by 2030 projection the AESO made in its 2017 forecast under the former New Democratic Party (“NDP”) government. The 30% renewables by 2030 target remains enshrined in legislation as part of the Renewable Electricity Act (“REA”), but it is unclear how the government of Alberta intends to hit this target.

Key Developments in 2019

Election

The Alberta election was held on April 16, 2019. The Jason Kenney-led United Conservative Party (“UCP”) won 54.88% of the popular vote and 63 seats, reducing then-Premier Notley’s NDP to official opposition with 24 seats.

The newly elected Government of Alberta has been quick to implement its platform. Since its election, the Government of Alberta has drastically changed the landscape of the Alberta electricity market. Among other things, the Government of Alberta has cancelled the NDP’s planned market overhaul, which would have changed Alberta’s energy system from an energy-only market to a capacity market, and cancelled the Alberta Renewable Electricity Program. In addition, after a mere 4 weeks of being sworn-in, the Government of Alberta repealed the Alberta carbon levy and rebate system. It is anticipated that the Government of Alberta will continue to make changes as it continues to implement its platform to balance the provincial budget in 2020.

Cancellation of Capacity Market

On July 24, 2019, the Government of Alberta announced that it would not proceed with the implementation of a capacity electricity market. As highlighted in our 2018 Alberta Regional Overview, Bill 13: An Act to Secure Alberta’s Electricity Future, was passed to provide the legal framework to support Alberta’s transition to a capacity market. The AESO was required to consult with market participants, stakeholders and the Market Surveillance Administrator in the development of proposed changes to the rules to establish a capacity market. The proposed AESO rules would then have required the approval of the Alberta Utilities Commission (“AUC” or the “Commission”) prior to implementation.

However, following a 90-day review period by the new UCP government (a campaign promise to determine which market-based system is best for Alberta), the government determined not to proceed with the implementation of the capacity market and to remain as an energy-only market. The decision to abandon the capacity market came on the eve of a pending AUC decision with respect to the AESO’s application for approval of the first set of provisional market rules essential for the implementation and operation of the capacity market. The key goal in the government’s decision to abandon a capacity market in Alberta was to restore investor confidence in Alberta’s electricity system by returning to a cost-effective, reliable, energy-only market.

In an energy-only market, electricity is generated, sold and bought on the wholesale electricity market. Alberta has been operating an energy-only market for electricity for over 20 years. Coupled with the announcement from the government was direction to the AESO to consider whether changes are needed to the energy-only market, including changes to the price floor/ceiling and shortage pricing, and to provide guidance on market power mitigation. The AESO delivered an initial report to the Government of Alberta on required market changes; however, the report has yet to be made available publicly.

Cancellation of AESO’s Renewable Electricity Program

On June 10, 2019, the Government of Alberta advised the AESO that it will not be continuing with the Renewable Electricity Program (“REP”), as it had deemed the program to be a costly subsidy. REP round 4 was intended to procure up to 400 megawatts of renewable electricity. Although the REP was cancelled, the Government of Alberta directed the AESO to continue to honor the awards issued under REP Rounds 1, 2 and 3. Under the REP, successful bidders entered into a Renewable Electricity Support Agreement (“RESA”) with the AESO, which provides a 20-year indexed renewable energy credit, structured akin to a contract for differences, to cover any difference between the participant’s bid for energy generated from a project and the pool price of energy in the market.

The following wind projects were awarded REP Round 1 RESAs and were anticipated to be operational by the end of 2019.

Four wind projects were selected for REP Round 1

© https://www.aeso.ca/market/renewable-electricity-program/rep-results/

Wind projects were awarded REP Round 2 RESAs

© Ibid

Wind projects were awarded REP Round 3 RESAs

© Ibid

Alberta Infrastructure Procures 135,000 MWh of Solar-Generated Electricity

In October 2018, Alberta Infrastructure issued a Request for Proposals for the procurement of 135,000 MWh of solar-generated electricity each year for the next 20 years. Before releasing the RFP, Alberta Infrastructure sought input from industry stakeholders through a Request for Information in August 2018. Successful bid participants will enter into Solar Electricity Support Agreements with Alberta Infrastructure.

In February of 2019, Alberta Infrastructure awarded Canadian Solar Solutions Inc. a 20-year contract at an average price of 4.8 cents per kilowatt-hour. Canadian Solar Solutions Inc. along with Conklin Metis Local 193 (which has a 50% equity stake in the projects) will build three new solar farms near the communities of Hays, Tilly and Jenner in southeast Alberta. These three facilities will have a combined capacity of approximately 100 MW and are expected to be completed in 2021.

Cancellation of Energy Efficiency Alberta Programs

On November 7, 2019, numerous programs offered by Energy Efficiency Alberta (an organization established by the NDP government in 2017) were cancelled by the newly elected UCP government. The following incentive programs were eliminated:

(i) the Residential and Commercial Solar Program, which provided incentives to businesses and homeowners to install solar panels on their rooftops;

(ii) the Community Generation Program, a partnership between Energy Efficiency Alberta and the Municipal Climate Change Action Centre to support the installation of locally generated renewable energy projects;

(iii) the Home Improvement Program, which offered rebates for new windows, insulation, tankless water heaters and more; and

(iv) the Online Rebate Program, through which Albertans could receive rebates for new appliances, smart thermostats and other purchases that improve energy efficiency.

Market Rule Developments

AUC Rule Amendments

The following are new or amended AUC requirements or processes established in 2019:

Rule 012: Noise Control

In December 2017, the AUC initiated a consul­tation process on changes to certain provisions of Rule 012: Noise Control. The AUC stated that a number of issues with respect to predicted sound level and compliance determination have arisen when construction is delayed, and when multiple facilities exist or are proposed in proximity to one another. These issues include the following:

(i) post-construction sound level surveys submitted by facility owners frequently identify challenges in collecting sufficient representative data required to meet the requirements of Rule 012. Many of these post-construction surveys have had to be redone;

(ii) members of the public have filed noise-related complaints regarding constructed facilities;

(iii) delays between approval and construction dates for facilities/power plants can add complexity to adjacent facility proposals or construction of dwellings in proximity to approved facilities; and

(iv) lengthy construction delays after a project has been approved can result in alterations to the selected wind turbine model, thereby potentially affecting noise impact assessments of the proponent, as well as adjacent facilities.

The AUC approved amendments to Rule 012 on April 16, 2019. The final results of the consultation process were a revised Rule 012 and a revised Rule 007, which were issued and published on the AUC website. The amendments to the rules were effective August 1, 2019. The amended Rule 012 includes but is not limited to: (i) a new definition of baseline sound level which now includes noise contribution from existing energy-related facilities, (ii) conditions for when a new noise impact assessment must be filed as part of a time extension request; and (iii) a new definition of ambient sound.

Rule 024: Rules Respecting Micro-Generation

The AUC worked with stakeholders and the AESO to update the AUC’s Micro-Generation Notice Submission Guideline. The revised guideline was published in May 2019, and summarizes the current processes required to obtain approval for micro-generation connection to the grid. As a result, Rule 024: Rules Respecting Micro-Generation also underwent minor amendments.

Rule 030: Compliance with the Code of Conduct Regulation

The AUC approved an amended Rule 030: Compliance with the Code of Conduct Regulation, effective April 1, 2019. Section 40(4) of the Code of Conduct Regulation permits the Commission to make exemptions from audits for a period not exceeding 36 months. The table in Section 6 of Rule 030 has been amended to reflect audits completed in 2018­2019, the revised timing due to updated compliance plans, and has been reorganized for ease of reference. The amendments were considered to be minor and were made without stakeholder consultation.

Rule 033: Post-Approval Monitoring Requirements for Wind and Solar Power Plants

On June 12, 2019, the Commission approved Rule 033: Standardized Post-approval Monitoring Requirements for Wind and Solar Power Plants. This Rule was effective July 1, 2019. The intent of post-construction monitor­ing standards is to ensure that approved wind and solar power plant owners and operators implement effective, consistent operational mitigation measures to minimize the potential for negative effects on Alberta’s wildlife and wildlife habitat. The Commission believes that the establishment of standardized post-approval monitoring requirements will improve the consistency of monitoring obligations for owners and operators of approved wind and solar power plants, and will add certainty to the regulatory process.

ISO Rule Amendments

Minimal amendments to the ISO Rules occurred in 2019. The only substantive amendment was to Section 501.10 (Transmission Loss Factors). The amendments were made for the following reasons: (i) to ensure that loss factors reasonably recover the cost of losses on the transmission system; and (ii) to provide transparency to market participants on how loss factors are calculated.

Market Surveillance Administrator

MSA Consultation on Offer Behaviour Enforcement Guidelines

As previously discussed, on July 24, 2019, the Government of Alberta announced that a capacity market will not be implemented in Alberta and the energy-only market will be maintained. Following such announcement, the Alberta Department of Energy was directed to examine whether any changes to the existing energy-only market are needed for it to remain successful, including a policy review related to market power and market power mitigation. The subject matter of this examination, according to the Market Surveillance Administrator (“MSA”), is indistinguishable from participant offer behaviour. As a result, the MSA is not continuing its own consultation related to the Offer Behaviour Enforcement Guidelines.

Section 5 of the Fair, Efficient and Open Competition Regulation (“FEOC”) 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.

 

2019-01-31

© Source: Market Surveillance Administrator, 2019 Market Share Offer Control Report (September 24, 2019)

Alberta’s total capacity decreased 318 MW since the last market share offer control assessment on April 22, 2018. This was primarily due to the retirement of TransAlta’s Sundance Unit 2.

Advisory Opinion Program

Following requests received from market parti­cipants in October 2018, the MSA initiated a stakeholder consultation to consider whether a voluntary advisory opinion program would be helpful to market participants. On October 23, 2019, the MSA created an Advisory Opinion Program (“AOP”) that will provide advisory opinions with respect to whether proposed business conduct and practices of Alberta electricity market participants comply with their obligations under the Electric Utilities Act, including regulations created thereunder.

Alberta electricity market participants who wish to obtain a non-binding Advisory Opinion from the MSA (the “Applicant”) must submit a written request that contains all of the following information:

  • details of the Applicant’s proposed business practice;
  • relevant data and analysis available to the Applicant;
  • relevant third-party data and analysis; and
  • the Applicant’s contact information.

There is no fee to be paid by an Applicant who requests an advisory opinion. In the interest of facilitating greater understanding and transparency of the MSA’s views to the broader market, the MSA will publish a version of any advisory opinion it issues that maintains the confidentiality of the Applicant and any commercially sensitive information.

The Future of Distribution Connected Generator Credits

AUC Decision 22942-D02-2019 issued on September 22, 2019 approved the AESO’s 2018-2020 tariff. One of the key changes proposed in this application concerned the metering of flows used to calculate demand transmission services and which may affect distribution connected generators (“DCG”). Generation technologies used in DCG include photovoltaics, micro-turbines, internal combustion reciprocating engines, combustion turbines, wind generators and fuel cells that may be situated at residential, commercial and industrial sites. DCG can be used to generate a customer’s entire electrical energy supply, to reduce peak demand (commonly referred to as “peak shaving”) for standby or emergency generation, as a green power source or for increased reliability of the distribution system.

As at the end of 2017, ATCO Electric, EN MAX and FortisAlberta tariffs all included a provision that provides transmission-based credit to large-scale DCG providers. Micro-generators (less than 5 MW) are not eligible to receive transmission tariff-based credits. FortisAlberta’s credit is referred to as Option M, ATCO Electrics’s credit is D32 and ENMAX’s credit is known as rate D600. The credits are calculated based on the electrical energy delivered by the DCG to the distribution system, and are the difference between the AESO system access service charges to the distribution wire owner (with the generator in operation), and the charges that would have been incurred if the generator had not been in operation. The amounts are calculated manually for each DCG using actual hourly metering data.

In a prior report, the AUC observed that because the AESO does not provide a credit to the distribution wire owners for reduced transmission system costs due to DCG, the distribution wire owners that must provide this credit must recover the cost of the credit from all of its distribution customers. In this decision, the AUC formally considered the continuation of this practice.

The AESO’s position was that no economic advantage should be provided to a generator that connects via the distribution system over the transmission system and DCGs should not receive distribution derived transmission credits. In response, the AUC held that the continuation of DCG credits was a matter to be determined in distribution tariff-setting processes, and not the present AESO tariff matter. Therefore, the fate of the DCG credits remains uncertain pending the outcome of future distribution tariff-setting processes.

AUC Decisions re Cogen and Self-Supply

On February 20, 2019, the AUC released AUC Decision 23418-D01-2019, El Smith Solar Power Plant (the “Smith Decision”) contemplating the issue of co-generation and self-supply. Additional commentary regarding the Smith Decision can be found in our litigation review in the Canadian Power - Key Developments in 2019, Trends to Watch for in 2020 publication.

The Smith Decision raises important issues regarding self-generation where a generator seeks to export surplus generation not used for self-supply to the grid. The AUC concluded that a self-generator could only avoid the general must-offer, and must-exchange obligations as set out in the Electric Utilities Act (“EUA”) and the Hydro and Electric Energy Act (“HEEA”), if it fell within one of the prescribed exceptions in the legislative scheme.

 

Exemptions

© Source: Nigel Bankes, ‘Opening a Can of Worms: What are the applicable market rules for generation where the generator fails to use the entire output?’, Ablawg.ca, March 5, 2019.

The AUC concluded that the broad exemption offered under section 2(1) of the EUA is only available to a self-generator who does not export any surplus generation to the grid. If any surplus generation is exported, no matter how small, this exemption is forfeited and the generator must then comply with the must-offer, must-exchange rules for the entire output of the facility unless another exemption can be applied. The Smith Decision has been subsequently affirmed by AUC Decision 23756-D01-2019 and AUC Decision 24393-D01-2019. Read together, the AUC concluded that a project would not be approved for self-supply and export unless it fell within the 5 MW limit of the Microgeneration Regulation or the project had an industrial system designation (“ISD”) under section 4 of the Hydro and Electric Energy Act.

Prior to the Smith Decision, many co-generation facilities were relying on prior AUC decisions which contemplated such facilities supplying both to the grid and for their own use without reference to the must-offer, must-exchange obligations under the Fair, Efficient and Open Competition Regulation (“FEOC Regulation”) enacted pursuant to the EUA. On September 13, 2019, the Commission issued Bulletin 2019-16 launching consultation on the issue of power plant self-supply and export and sought stakeholder input on the following options for addressing the self-supply and export issue in the future:

Option 1: Status quo – no change to the statutory scheme is required.

Option 2: Allow limited self-supply and export – this requires a change to the statutory scheme. This exemp­tion could be similar to the micro-generation exemption where operators are required to size their plant to meet internal need on an annual basis, but will be allowed to export excess energy to the grid to a certain percentage of annual production. Comments on the concept and an appropriate export threshold will be helpful.

Option 3: Unlimited self-supply and export – this requires a change to the statutory scheme and may require changes to existing transmission and distribution tariff structures.

The outcome of these consultations, future AUC decisions and any resulting legislative changes could have impacts on co-generation and industrial systems across the province. The change in the AUC’s interpretation of its governing legislation has created significant regulatory uncertainty. It is anticipated that relief in the form of statutory amendments or new AUC rules may be on the horizon in 2020.

Energy Storage in Alberta

Alberta is in the process of phasing out coal-fired power and has a legislated target of 30% renewable electricity generation by 2030. In late 2017 and early 2018, as part of its plan to achieve these goals, the AESO assessed the potential need for dispatchable renewables and energy storage to maintain system reliability, flexibility and ramping capability. The AESO concluded that there was no emerging need to specifically procure additional flexibility on the system. This conclusion was based upon the Energy+ Environmental Economics Inc. (E3) study commissioned by the AESO. E3 assessed two common types of energy storage to determine its cost effectiveness: (1) lithium-ion batteries (short-term duration); and (2) pumped hydro storage (long-term duration).

E3’s key findings regarding the potential cost effectiveness of energy storage on the Alberta system included:

  • Alberta’s current transmission tariff makes it difficult for storage to be cost-effective;
  • large-scale storage projects (> 50 MW) are un-likely to be cost effective in Alberta due to: (1) early reserve market saturation (AESO’s operating reserve market may provide high revenues per MW but the market is small); and (2) insufficient daily pool price spreads (even with 12 hours of daily “energy arbitrage” (charging 12 hours at low prices and discharging 12 hours at high prices), storage would need more than a $60/MWh daily price spread to cover a $2500/kW capital cost. AESO projected daily spreads instead range from $15-30/MWh); and
  • smaller storage projects (< 50 MW) may provide market positive revenues in Alberta from operating reserve and the future capacity market if: (1) Alberta’s transmission tariff is revised for charging costs; and (2) price saturation in the operating reserve markets can be avoided.

Although the AESO concluded that there was no requirement to procure storage capacity, it nonetheless developed an Energy Storage Roadmap for Alberta’s system. In August 2019, the AESO released its Energy Storage Roadmap. The AESO solicited stakeholder input on the roadmap and a summary of the feedback can be found on the AESO’s website6. A key theme arising from the stakeholder feedback includes the need to clarify tariff design for energy storage and whether it will be considered generation, load, both, or an ancillary service.

https://www.aeso.ca/assets/Uploads/Ener-gy-Storage-Roadmap-update-to-stakeholders-fi-nal.pdf

What to Expect in 2020

Alberta continues with its energy-only market and a legislatively enshrined target of 30% renewable electricity by 2030. As of March 2019, the installed generation capacity still relies heavily on coal-fired power plants, co-generation and combined and simple cycle natural gas generation.

Electricity in Alberta7

Notwithstanding the federal government’s grant of equivalency to Alberta’s greenhouse gas emissions policy (the “Technology Innovation and Emissions Reduction System” or “TIER”), the federal consumer carbon levy will take effect in Alberta effective January 1, 2020. With the cancellation of most, if not all, of the NDP’s program incentives for renewable generation, it remains uncertain how Alberta will meet its legislative “30 by 30” target. Whether the Government of Alberta will create its own regime and policies to achieve this target or seek legislative amendment, will have a direct impact on the generation supply mix and investment in Alberta. This, combined with the rapid pace of technological advancements, will no doubt spur change in Alberta’s electricity market.

Alberta's electricity market

© 7. Source: https://www.aeso.ca/aeso/electricity-in-alberta/

We expect that Alberta will continue to see growth in the number of smaller market participants as more industrial facilities and consumers install their own generation (e.g. co-generation or even small-scale roof-top solar) and more distribution system-connected renewable energy is developed. Interest in private or non-government backed power purchase agreements will continue to be a focus for future investment in the province.

Click here to request a PDF copy of the publication: McCarthy Tétrault’s fifth edition of Canadian Power

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