Ontario’s IESO recently announced that it is likely to carve out a special long-term procurement target specifically for battery storage resources. This is another boon for storage resources, following their becoming eligible to compete for the IESO’s “Medium-Term RFP” last year. Historically, the wholesale electricity market has not had regulations amenable to storage resources. The latest long-term (“LT1”) RFPs appear to try to address this.

As previously reported by us, the IESO is rolling out its LT1 RFP to address system reliability needs beginning to arise in 2025-2027. The LT1 RFP aims to procure up to 2,500 MW of new and incremental capacity from both existing and new-build supply and storage resources that can enter service beginning May 1, 2027 for a 20 year term ending April 30, 2047.

Subsequent to the issuance of the LTI RFP, the IESO created an “Expedited LT1 Process” stream to procure an additional 1,000 MW more quickly from advanced new-build resources that are able to enter commercial operation between May 1, 2025 and May 1, 2026.

Successful Expedited LT1 Process proponents that can enter service within the first 12 months, i.e. between May 1, 2025 and April 30, 2026, may be eligible to receive supplemental contract revenues by way of a commercial operation date (COD) “multiplier” of 1.1X to 1.5X. However, those projects unable to meet commercial operation by May 1, 2026 may be subject to financial penalty in the form of liquidated damages.

LT1 contracts are expected to include indexing provisions against material cost increases, etc. to hedge against inflation and commodity price increases during the development period, i.e. between contract acceptance and commercial operation. The IESO is also proposing a fixed price contract structure that pays for capacity based on a “pay-as-bid” approach, but subject to a “capacity payment adjustment mechanism”.

The capacity payment adjustment mechanism is comprised of proponents submitting two additional % bid “modifiers” whereby resources will have their fixed payments adjusted (topped-up or clawed-back) where the quarterly average energy market price exceeds or fails to meet the applicable modifier threshold. Proponents are not required to submit capacity payment adjustment factors, but those that do will be subject to having their modifiers evaluated by the IESO to ensure levelization of all participant bid prices (exact formula still TBD).

The IESO has acknowledged that a different capacity payment adjustment mechanism is appropriate for battery storage resources. This is because battery storage resources primarily operate by leveraging arbitrage opportunities in withdrawing electricity when market prices are low and injecting electricity when market prices are high.

Storage proponents have accordingly asked the IESO to consider basing LT1 contract payments for battery storage proponents on the price spread between on- and off-peak rather than quarterly average energy market prices. Otherwise, as energy storage proponents argue, they could be gratuitously exposed to increased merchant risk, thereby raising financing costs and in turn undermining the ability of battery storage resources to competitively bid for and maximize participation under an LT1 contract.

In response to this feedback, the IESO is currently considering bifurcating the LT1 procurement target for battery storage on the one hand and for all other resources on the other hand. All competing technology resources (storage and non-storage) will still be limited to a maximum project size of 600 MW. The IESO has also proposed that participating storage facilities be reimbursed in the form of a “regulatory charge credit” for all regulatory energy charges, including global adjustment, incurred in respect of electricity withdrawn.

These are significant advances toward greater integration of energy storage participation at the wholesale level in Ontario. It will be interesting to see if the IESO will also respond to the energy storage industry’s feedback to expand the eligibility for the LT1 and Expedited LT1 Process procurements to include storage resources generally rather than limiting eligibility to battery storage. Draft Expedited LT1 RFP documents are to be published on August 25, 2022.

Our team at McCarthy Tétrault continues to closely follow the development of the LT1 RFP and Expedited LT1 Process procurements, as well as the IESO’s Resource Adequacy Framework generally. If you would like more information about electricity regulation in Ontario, we are here to help.

Please contact Stephen Furlan, Reena Goyal, or any other member of the Power Group at McCarthy Tétrault with any questions or for assistance.

On February 8, 2022, Ontario’s Independent Electricity System Operator (“IESO”) presented a webinar on its intent to launch a Request for Proposal (the “LT I RFP”) to procure at least 1,000 MW in fall 2022 to address multiple reliability needs. Based on a directive from the Minister of Energy, the IESO has been instructed to seek resources that can be in service between 2026 and 2028 as part of the IESO’s broader Resource Adequacy Framework.

Background

The LT I RFP forms part of a broader Resource Adequacy Framework under which the IESO aims to address a capacity need in Ontario set to emerge in the mid-2020s. The forecasted capacity gap arises from a combination of factors, most notably the retirement of the Pickering nuclear plant, the refurbishment of other nuclear generating units, and expiring generation contracts for certain existing facilities.

The LT I RFP will aim to procure at least 1,000 MW of new and incremental capacity from both existing and new-build supply and storage resources that can enter service between 2026-2028 for a seven- to ten-year period. To address both global system needs and more localized transmission security needs, the LT RFP I will seek to acquire capacity preferably in the transmission zones east of Toronto and in southwestern Ontario.

Proposed Eligibility Requirements

Each proposal must confirm that:

1.  the subject resource can provide at least 1,000 MW of new capacity with a minimum of 4 hours of consecutive energy duration, based on system needs;
2. the proponent must be a fully dispatchable (i.e., able to dispatch electricity on demand at the request of IESO through generators, hybrid generators, or storage resources that are directly connected to the transmission or distribution system) Market Participant (as defined in the IESO Market Rules); and
3. all permits are in place and all regulatory requirements are met at the commercial operation date.

Proposed Rated Criteria

Each eligible proposal can earn points for desirable resource attributes or technical characteristics, if the subject resource:

1. is able to deliver 8 or more consecutive hours of energy;
2. is located in areas of greatest system need, such as southwestern Ontario or East Toronto;
3. is able to ramp up or down quickly;
4. is a quick-start resource;
5. has a larger operating range; and
6. has the technical capability to provide one or more ancillary services.

The IESO has indicated that as the design of the LT I RFP process continues to be refined through stakeholder feedback, some of these rated criteria may become mandatory requirements.

Stakeholder Engagement

The IESO is inviting stakeholders to participate in the design of the LT I RFP, including providing feedback on whether the revenue mechanisms in the contracts should be structured as energy market “collars”, contracts for difference, or price adders. The IESO also plans to engage with stakeholders to determine how to value and monetize Environmental Attributes (“EAs”), along with other revenue streams.

Stakeholders may provide feedback on the term length of the procurement contracts, the timelines of the LT I RFP process, and the proposed mandatory requirements and rated criteria. Stakeholders are invited to provide comments by February 15, 2022.

 In connection with the LT I RFP, the IESO intends to issue a draft request for qualifications (“RFQ”) by February 28, 2022 and complete community engagement on the RFQ prior to March 31, 2022. A final RFQ will be issued by June 30, 2022.

Our team at McCarthy Tétrault continues to closely follow the development of the LT I RFP, as well as the IESO’s Resource Adequacy Framework generally. If you would like more information about electricity regulation in Ontario, we are here to help.

Please contact Reena Goyal, Mitchell Lui, or any other member of the Power Group at McCarthy Tétrault with any questions or for assistance.

On November 10, 2021, Ontario’s Minister of Energy released a letter (the “Letter”) to the Independent Electricity System Operator (“IESO”) making comments and requests on a number of the IESO’s current and planned measures to meet the province’s anticipated electricity capacity needs emerging in the mid-2020s.

The Letter confirms the provincial government’s overall support for the IESO’s approach to capacity procurement and, in doing so, it appears that the Minister intends to provide greater certainty to sector participants who may be deciding whether to invest in new generation or storage assets, or to reinvest in existing facilities.

The Letter in context

The Letter follows on the heels of the IESO’s draft medium-term RFP, released on November 2, which we commented on in a previous post.

The IESO’s procurement activities are part of the Resource Adequacy Framework under which the IESO aims to address the emerging capacity need in Ontario. The forecasted capacity gap arises from a combination of factors, most notably the retirement of the Pickering nuclear plant, the refurbishment of other nuclear generating units, and expiring generation contracts for certain existing facilities.

What are the highlights?

The Minister asks the IESO to advance the following initiatives and sets out a series of deadlines beginning in December 2021 to report back to the Ministry:

• Future Competitive Procurement Mechanisms;
• Ensuring Short-Term System Reliability;
• Approach for Re-contracting Biomass Generation Facilities;
• Program for Re-contracting Small Hydroelectric Facilities;
• Update to 2016 Study on Energy Storage in Ontario;
• Gate 2 Review for Marmora, Meaford and Schreiber Pumped Storage Projects; and
• Gate 3 Contract Negotiations on the Oneida Energy Storage Project and Lake Erie Connector Transmission Project.

The appendix to the Letter summarizes the Minister’s specific directions with respect the above initiatives.

Support for storage, small hydro, and biomass

The Minister encourages the IESO to be technology-agnostic in its approach to the long-term RFP, while at the same time singling out storage as a potential resource provided these facilities can deliver the required services. The Letter further asks the IESO to update its 2016 report on energy storage, recognizing its potential to advance decarbonization.

Alluding to the expiry of existing small hydro power purchase agreements, the Letter asks the IESO to explore ways to allow these facilities to continue operating. Highlighting the zero-emission electricity offered by hydro, the Minister states that a program for re-contracting small hydro should appropriately tailor the eligibility threshold and term length, but does not make specific suggestions.

The Letter also requests that the IESO re-contract specific biomass facilities whose PPAs are expiring in 2021, stating that it will “take time” to find alternative uses for waste biomass. The Letter states that new contracts should be for a maximum of five years, but the Minister does not say whether these facilities should expect to remain online beyond that.

What about achieving zero emissions?

Although the Letter makes a number of references to decarbonization and zero emissions renewable electricity, it does not state that electricity procurement in Ontario should be consistent with achieving zero emissions, nor does it confirm the continued role of natural gas in the energy transition (apart from mentioning the IESO’s recent Gas Phase-Out Impact Assessment).

The latter is notable given the Minister’s October 7, 2021 letter asking the IESO to evaluate a moratorium on the procurement of natural gas and which, unlike the Letter, calls for a pathway to zero emissions in the electricity sector. This, in turn, raises questions about the link between any such moratorium and procurement strategy more generally.

As a result, while the Letter provides certainty on several specific initiatives, much apparently remains undecided in terms of the overall challenge of procuring for a zero emissions grid. Sector participants might anticipate further procurement direction from the Ministry following the IESO’s response on the gas moratorium, not due until November 2022.

We’re here to help

Our team at McCarthy Tétrault continues to closely follow developments under the IESO’s resource adequacy framework, including emerging opportunities for sector participants. If you would like more information about electricity regulation in Ontario, we are here to help.

Please contact Reena Goyal, Will Horne, or any other member of the Power Group at McCarthy Tétrault with any questions or for assistance.

On November 2, 2021, Ontario’s Independent Electricity System Operator (“IESO”) posted a draft of its Medium-Term RFP (the “Draft RFP”) under its Resource Adequacy Framework.

The Draft RFP sets out the process and criteria by which the IESO proposes to procure up to 750 MW of capacity from existing generating or storage resources via three-year commitments beginning in May 2026 (with optional two-year extensions).

The RFP in context

The Draft RFP forms part of a broader Resource Adequacy Framework under which the IESO aims to address a capacity need in Ontario set to emerge in the mid-2020s. The forecasted capacity gap arises from a combination of factors, most notably the retirement of the Pickering nuclear plant, the refurbishment of other nuclear generating units, and expiring generation contracts for certain existing facilities.

In contrast with the pending Long-Term RFP (stakeholdering to begin in 2022) which will aim to procure at least 1,000 MW of new and incremental capacity from both existing and new-build resources that can enter service between 2026-2028 for a seven- to ten-year period, the Draft RFP is geared toward addressing a specific forecasted capacity need limited primarily to already connected resources with or without expiring contracts.

What’s in the Draft RFP?

The full text of the Draft RFP is available here. Key requirements, deadlines, and evaluation criteria include the following (bold terms are defined in the Draft RFP):

Eligibility	Proponents must be “Qualified Applicants” as defined in the Draft RFP, which (among other things) means that Proponents must own an existing and operating generation or storage facility. The facility must be: capable of delivering services in accordance with the “Medium-Term Capacity Contract” (discussed below); connected to the Ontario grid as of the proposal submission deadline; and currently or previously the subject of an IESO contract that has expired or will expire by April 30, 2026, or is otherwise registered with the IESO and not under contract. A “Qualified Facility” may include a connected facility, embedded generation facility, embedded electricity storage facility, or an embedded non-market participant facility (as defined in the Market Rules).
Contract Terms	The Medium-Term Capacity Contract will pay suppliers a fixed monthly capacity payment. Successful Qualified Facilities will enter into contracts containing either: must-offer obligations, which require Qualified Facilities that are non-variable generation to offer into the day-ahead market during qualifying hours at a specified minimum quantity; or facility capacity factor obligations, which require Qualified Facilities to produce a minimum amount of metered generation during qualifying hours.
Process	The Draft RFP includes the following milestones: January 31, 2022: IESO’s deadline for releasing the final RFP and contract; February 21, 2022: Proponents’ deadline for registration; and April 28, 2022: Proposal submission deadline. The Draft RFP includes additional process guidelines and technical submission requirements, including registration, scope of potential addenda, scope of permissible communication, and post-selection processes.
Evaluation	Proposals will be evaluated in four stages: Completeness (pass/fail); Mandatory criteria – the proponent must be a Qualified Applicant, with a Qualified Facility with an accurate nameplate capacity; Rated criteria scoring – proposals will receive a maximum of 11 rated criteria points across the categories of (i) location; (ii) dispatchability; (iii) operating reserve; and (iv) duration; and Proposals that are below the “Reserve Price” will have their “Proposal Price” evaluated using the criteria in step 3 to determine their “Evaluated Proposal Price”, which are then ranked.

 

The bigger picture

As the federal government and industry participants become increasingly focused on achieving net-zero, it is notable that the Draft RFP lacks any mandatory scoring or criteria related to emissions reduction. This reflects a continued need for clear guidance and direction from provincial government to the relevant agencies, including the IESO and Ontario Energy Board, on expectations and timelines for achieving net-zero in the electricity sector.

Although the Ministry of Energy has directed the IESO to, among other things, “develop an achievable pathway to zero emissions in the electricity sector” and to submit a report on same by November 2022, the authors submit that this timeline is too long and that clearer emissions-related procurement targets need to be established sooner.

By explicitly including storage alongside generation in the Draft RFP, the IESO does appear to be recognizing stakeholder input concerning the potential of storage resources to further decarbonize the Ontario grid, while boosting flexibility and maintaining efficiency and cost effectiveness.

Notwithstanding, there is arguably an opportunity to further integrate emissions-related criteria in the Medium-Term (and Long-Term) RFP. This need is particularly imminent given the potential for significant increased electricity demand in Ontario resulting from possible future broad based transport electrification and natural gas phase-out.

We’re here to help

Our team at McCarthy Tétrault continues to closely follow the development of the Medium-Term RFP, as well as the IESO’s Resource Adequacy Framework generally. If you would like more information about electricity regulation in Ontario, we are here to help.

Please contact Reena Goyal, Will Horne, or any other member of the Power Group at McCarthy Tétrault with any questions or for assistance.

On November 6, 2019, the Government of Ontario issued Order in Council 1499/2019 directing the Independent Electricity System Operator (“IESO”) to retain an independent third party consultant for the purpose of identifying ways to reduce costs to Ontario electricity consumers, with a particular focus on wind, solar and natural gas contracts expiring during the next 10 years (the “Directive”). In response to the Directive, the IESO retained a third party consultant and issued a report addressed to the Government on February 28, 2020 (the “Report”).  The IESO also wrote to and solicited ideas for cost reduction opportunities from contracted generators that held larger IESO contracts or portfolios of contracts.  Almost five months later, a copy of the Report, together with the underlying third party consultant report and other related documents, was published last week on the IESO’s public website.  After much speculation, the publication finally allows industry participants to see what the IESO and its consultants concluded in response to the Directive.

It will come as little surprise to industry that the Report has few concrete proposals for cost-lowering opportunities.  The Report concludes that “buyout” and “buydown” options for wind and solar contracts were the most viable. The “blend and extend” option, which had circulated around industry as the most popularly cited potential cost relief measure, was rejected as unlikely to result in long-term savings to ratepayers.

“Buyout” would involve early termination of a contract in consideration for a lump-sum payment negotiated to represent all future anticipated contractual net revenues to the supplier.   The Report identifies the principal risk of buyouts for contract holders (and the IESO) is market forecast related since settling a lump-sum payment requires that each party to the contract assume the risk of its forecast.  From the supplier’s perspective, if its actual future market revenues are less than those assumed in the buyout amount, it will have settled for too little and its original anticipated return on investment will be eroded.  “Buydown” would keep the contract in place but, similar to buyout, would entail a lump-sum payment in exchange for a lower contract price for the remaining contract term. It may also be combined with or entail financial arbitrage whereby the IESO would provide replacement financing to the supplier.  Such replacement financing could also permit the lowering of the contract price payable to the supplier on the assumption that the IESO’s low cost of capital will permit it to provide such financing at a lower cost than the supplier’s existing financing.   The Report anticipates that the buyout option will experience less uptake due to the market forecast risk concern, and would not be applicable to gas contracts.

 

Based on the IESO’s base case scenario, the buydown approach is estimated to result in net cost savings in the first year of implementation of $32 million attributed to wind and solar resources and $5 million attributed to gas-fired resources. The IESO estimates the net present value of the net savings from the buydown option to range from $303 million to $443 million over the term of the program and to require over $2.1 billion of new debt. The IESO also estimates it would take more than a year before cost reductions could begin to be realized by consumers.  These estimates do not include the cost to the IESO of the necessary program implementation and contractual changes, and appear to assume that there would be a relatively low approximately 16% take up rate (as a percentage of total contracted megawatts) of the universe of eligible wind, solar and gas contracts.

 

It will undoubtedly come as a relief to industry that the Report points out that the potential cost-reduction opportunities were screened for, among other considerations, the parties’ respective contractual rights and obligations.  Also, vetted opportunities had to be possible under the existing terms of the contracts or achievable through negotiated contract amendments.  The Directive and other developments in the sector, particularly the introduction of the White Pines Wind Project Termination Act and the cancellation of the renewable energy approval for the Nation Rise wind project, have contributed to considerable anxiety among IESO contract holders and spread uncertainty to suppliers other than perennially nervous wind and solar generators.  The Report rightly points out that, in the absence of supplier defaults, the IESO has few opportunities to terminate its contracts unilaterally.   It also rightly – if not understatedly – points out that there are little savings to be had from unilateral terminations by the IESO.  

 

We commend the IESO for the Report on the basis of the reasonableness of its underpinnings for screening opportunities for cost savings, its solicitation and consideration of participant feedback, and the practicality of its analysis and conclusions.  Recognition that beneficial opportunities may only be implemented through the agreement of the parties to the supply contracts is an important message to industry participants.  As an editorial point, it might have been worthwhile to also remind Report readers that any actions related to unilateral termination of contracts, be they initiated by the IESO or the Government, reduce confidence in the Province’s business climate overall and increase sovereign risk premiums factored in by future investors. 

 

We would also suggest that greater weight be placed on industry anxiety that may have had an impact on the conclusions of the Report.  In that regard, we observe that concern about potential unilateral terminations á la White Pines and fears about the IESO actively seeking circumstances to justify contract terminations have continued to dog the industry.  These concerns and fears were significantly exacerbated by the Directive and have embroiled industry participants for months.  While the Report may help quell some of this anxiety, it will not remove it completely, particularly in the context of the many exacerbating factors arising from the Covid 19 pandemic.  (For example, reduction in provincial load and expected increases of provincial debt and deficits.)   As a result (but with no empirical evidence whatsoever), we question the Report’s conclusion that buydown would have a higher take up rate than buyout.  While buydown may help reduce the consequences of future risk of contract termination, it still suffers from the market risks identified with respect to buyout transactions.  Additionally, it contemplates the possibility of the IESO becoming a lender to suppliers.  A rhetorical question worth pondering is whether suppliers in today’s environment would feel more or less secure in having the IESO as their lender as well as their offtaker?  The Report points out that the IESO “strictly enforces the obligations in its contracts” but that a supplier’s obligations following the achievement of commercial are “generally readily achievable”.  We would expect that an IESO financing would increase the supplier’s obligations significantly.  We would also expect that most suppliers would perceive a far greater risk of “strict enforcement” by the IESO than they would with their usual financial institutions under their current financings.  On the other hand, despite the risk of market forecasting related to the buyout option, there may be significant attraction to a supplier to monetize its contract today and thereby materially reduce any sovereign risk.  We would also expect that the transactional costs and the timeframe for implementation of multiple contract buyouts would be substantially less than multiple buydowns combined with financial arbitrage.

 

In addition to the foregoing potential contractual opportunities, the Report identifies other opportunities for potential electricity consumer savings, including considering the use of non-firm imports to meet future capacity needs, and developing market enhancements to increase competition. More information on associated stakeholder engagements for these initiatives can be found here.

 

At this point, the ball is back in the Government’s court.  While industry may be largely in agreement with the Report’s conclusions, trepidation will continue until the Government’s response is known.  We will continue to monitor developments in respect of the Directive and would be pleased to discuss any questions or concerns that arise from it or the Report.

What is MPM?

The IESO recently released the much anticipated Market Power Mitigation (“MPM”) detailed design document for its Market Renewal Program. Market power mitigation is a common feature found in most other North American competitive electricity markets. It is intended to curb potential or actual market power that certain electricity suppliers could wield given their location on the transmission grid. Specifically, suppliers could exercise market power where there is congestion on the transmission line or intertie in the geographical area that the participant supplies electricity.

Who does MPM apply to?

MPM is intended to apply to suppliers that participate in either the IESO-administered energy market or the IESO-administered operating reserve market, or both. MPM is not intended to apply to non-dispatchable loads or price-responsive loads, i.e. non-dispatchable loads that elect in the renewed market to participate as price-responsive loads.[1]

The IESO will publish annually the following types of identified constraint areas for the energy market[2], informed by the IESO’s historical data from the previous year and prospective analysis predicting where congestion is expected to continue:

1. Narrow Constrained Areas (“NCA”) – areas where congestion is expected to be relatively frequent over a long duration. The applicable threshold is if the IESO expects the area to be constrained in more than 4% of the hours in the following year in either the day-ahead market (“DAM”) or the real-time market (“RTM”).
2. Dynamic Constrained Areas (“DCA”) – areas where congestion is expected to bind relatively frequently but not for a long enough duration to warrant the designation of NCA. The applicable threshold is 15% of hours, including where caused by an outage or binding import constraint, in a continuous 5-day period in either the DAM or RTM.
3. Broad Constrained Areas (“BCA”) – areas where any time one or more resources outside an NCA or DCA are scheduled with a congestion component greater than $25/MWh. It also exists anytime a non-quick start resource receiving a make-whole payment outside an NCA or DCA is committed where it has a positive congestion component on a binding or active constraint.

Prior to the go-live date of the renewed market (still scheduled for March 2023), the IESO will directly notify any relevant market participants that they are located in any one of the above identified constrained areas. This information will not be made public.

How does MPM work?

For intervals during which congestion creates restricted competition, MPM will be exercised by ex-ante or ex-post analysis of participant dispatch data and offer prices. More specifically, the IESO will perform “conduct and impact” testing of relevant participants to evaluate:

• ex-ante validation of non-financial dispatch data (e.g. ramp rates and minimum generation block run-time);
• ex-ante mitigation for economic withholding affecting energy and operating reserve prices (e.g. a supplier offering in lower than would be expected under unrestricted competition, ostensibly for the purpose of increasing the spread between day-ahead and real-time prices);
• settlement mitigation of out-of-market make-whole payments (e.g. generator cost guarantee payments);
• ex-post mitigation for physical withholding affecting energy and operating reserve prices (e.g. a supplier withholding available supply during the DAM to sell at a higher price during RTM, thereby driving up real-time prices); and
• ex-post mitigation for economic withholding affecting prices or make-whole payments on uncompetitive interties.

Ex-ante validation and ex-ante mitigation

The IESO will determine if MPM has occurred by first applying conduct testing to determine whether a participant’s offers or bids are within the parameters or the “reference levels” and “reference quantities” established beforehand with the participant.

Reference levels will be established at the resource level for both financial and non-financial data, representing the IESO’s estimates of dispatch data in conditions of unrestricted competition. Similarly, reference quantities will be established, representing the IESO’s estimate of the quantity a resource is expected to offer in conditions of unrestricted competition.

Participants that fail conduct testing will then be subject to impact testing to determine if their conduct resulted in economically inefficient price-setting. Where participants fail ex-ante impact testing, the IESO will determine the set of resources that will have dispatch data substituted with reference levels for the purpose of determining schedules, prices and make-whole payments. The IESO will then apply mitigation by substituting participant dispatch data values that failed the conduct test with the corresponding reference level values.[3]

Ex-post mitigation

The ex-post mitigation process will also involve conduct and impact tests for the mitigation of physical withholding (or economic withholding on uneconomic interties). The conduct test will determine if offered quantities were lower than the applicable reference quantities. The impact test will determine if energy or operating reserve prices would be lower had the reference quantity instead been offered. The ex-post application of conduct and impact testing for offers on uncompetitive interties is similar to that applied ex-ante for other energy and operating reserve offers, described above.

Ex-post mitigation will be applied to relevant participants by levying a charge (aka penalty) equal to 1.5x the difference in settlement payments based on as-offered versus applicable reference levels/quantities multiplied by a market-wide MPM “persistence multiplier” of 1, 2 or 3 depending on the number of physical withholding instances by the participant within an 18-month period.

A participant will be found to have exercised market power if its offers are in excess of established thresholds of its pre-established reference levels/quantities. Examples include:

Non-financial (energy market)

• Submitted Minimum Generation Block Run Time is more than the lesser of 100% or 3 hours above the reference level
• Submitted energy ramp rate offered is lower than 50% of the reference level
• Submitted maximum number of starts per day is 50% lower than the reference level or lower than 1

Financial (energy market NCAs and DCAs)

• Offer price is greater then either 50% or $25/MWh above reference level value (note: offers below $25/MWh are excluded from economic withholding tests)
• Start-up offer is greater than 25% above reference level
• Energy local marginal price (“LMP”) in the as-offered pricing pass of the relevant calculation engine is either 50% higher than or $25/MWh above the energy LMP from the reference level pricing pass

Financial (energy market BCAs)

• Offer price is greater than either 200% or $100/MWh above reference level value (note: offers below $25/MWh are excluded from economic withholding tests)
• Start-up offer is greater than 100% above reference level
• Speed no-load offer is greater than 100% above reference level

As competition is more restricted, conduct and impact thresholds become narrower. As such, the thresholds for the operating market are equal to or narrower than that for the energy market.

What’s happening next?

The establishment of reference levels and reference quantities will be the product of a stakeholder engagement process that the IESO intends to commence in late August/September 2020.

Approximately 2 weeks prior to the commencement of that pending stakeholder engagement, the IESO intends to publish “workbooks” setting out the IESO’s proposed cost components to be included in the calculation of reference levels and quantities per fuel type. As part of the stakeholder engagement, the IESO will also be initiating meetings with each fuel type group to discuss the proposed cost components.

There is anticipated to be much debate between the IESO and participants as to what are appropriate cost components that should be taken into account in establishing static and non-static reference levels/quantities.

Our team at McCarthy Tétrault continues to closely follow the development of the IESO’s new MPM framework. If you would like more information about the IESO’s new MPM framework, we are here to help. Please contact Reena Goyal or any other member of the Power Group at McCarthy Tétrault with any questions or for assistance.

 

Recent experiences in the northeastern US regional transmission organization, PJM Interconnection (PJM) and New York Independent System Operator (NYISO) indicate that the integration of energy storage into competitive wholesale electricity markets can have serious consequences for new and existing capacity resources in Ontario.

The U.S. Federal Energy Regulatory Commission (FERC) recently issued a series of orders denying certain challenges to buyer-side mitigation (BSM) rules in the NYISO’s capacity zones, resulting in the continued broad application of the BSM rules. Among other things, this means that most capacity market participants will be required to offer into the NYISO capacity zones at or above specified offer floors set out in the applicable market rules, including energy storage resources. This is not dissimilar to the December 2019 FERC-ordered expansion of PJM’s minimum-offer price rule (MOPR) to most capacity auction participants, including new energy storage participants (but exempting existing storage resources).

In relation to NYISO, the complainants sought a blanket exemption from the BSM rules for all storage resources, arguing that the BSM rules counteract state efforts to meet certain objectives related to renewable generation, storage uptake and carbon emissions reductions. In the FERC order, the majority took the view that the BSM rules appropriately protect the capacity markets from price suppressive effects of storage resources receiving out-of-market payments and that other policy instruments are available to achieve these objectives. While FERC agreed with the complainant’s assertion that a single storage provider would be unlikely to exercise market power, the order concluded that the cumulative effect of all such resources participating in the capacity market could significantly impact market prices, and therefore, the application of the BSM rules was appropriate.

The rationale for these decisions, in part, is to create a more even-level playing field for capacity market participants by facilitating competition of new entrants against existing resources that receive out-of-market payments under government sponsored supply contracts and to ensure that all resource types, whether existing or new, having the ability to exercise market power are subject to the same mitigation rules. These types of administrative ‘corrections’, however, must be measured against the system costs of implementation as well as potential loss of investor confidence and market participation. Many long-standing participants, for instance, are considering departing from the PJM-administered markets altogether following the issuance of the abovementioned FERC order.

These are some of the issues the Independent Electricity System Operator (the IESO) may need to grapple with in its contemporaneous development of a capacity auction on the one hand and energy storage participation on the other hand.

The creation of new IESO market rules and amendments for the introduction of local and system-backed imports energy storage participation in the upcoming June 2020 capacity auction and beyond was recently stakeholdered and is being recommended for approval by the IESO Board of Directors later this month. Yet many questions continue to remain including whether mandatory offer floors similar to those instituted in PJM and NYISO – whether based on a proportion of Net Cost of New Entry (Net CONE) or otherwise - should be introduced so as to allow energy storage to meaningfully compete in IESO’s capacity markets going forward. Although an administrative default offer cap of $350/MWh is being proposed as part of the now March 2021 capacity auction design, no other market power mitigation mechanisms publicly appear to be under serious consideration.

Whether additional administrative mechanisms are required to enable energy storage to efficiently compete in the pending capacity auctions will turn in part on the pace of storage technology development in Ontario and the physical and financial characteristics of competing capacity market participants. According to the IESO’s recent Annual Planning Outlook, capacity markets are being introduced in Ontario in part to retain existing generation resources after their applicable long-term supply contracts expire to manage the expected capacity shortfall beginning in 2023. This then may lend itself to the adoption of a capacity offer model in the interim akin to that now mandated in PJM. Depending on the rate of energy storage development in Ontario and the characteristics of participating storage resources, a case may be made for the potential exercise of market power in the long term and therefore the equal application of a uniform minimum offer price akin to that now required in NYISO.

Whether such questions will form part of the scope of the IESO’s Capacity Market stakeholder engagement, Energy Storage Design Project or another initiative remains uncertain. Although some elements of Ontario electricity market design differ significantly from its U.S. counterparts, we can be reasonably assured from the recent experiences in PJM and NYISO that the IESO’s contemporaneous development of capacity markets and energy storage participation raise significant questions for new and existing capacity market participants and therefore needs to be closely coordinated. Broader considerations include the extent to which these issues will interface with the Ontario Energy Board’s current consideration of distributed energy resources integration at the distribution level.

If you would like more information about these orders or more information about energy storage in Ontario generally, we are here to help. Please contact Reena Goyal or Christopher Zawadzki or any other member of the Power Group at McCarthy Tétrault with any questions or for assistance

We recently reported in Canadian Power on the Ontario Court of Appeal’s decision in National Steel Car Limited v. Independent Electricity System Operator[1]. In that case, the Court of Appeal found that National Steel Car’s constitutional challenge to “Global Adjustment” charges deserved a full hearing on its merits. Relevant excerpts of our case comment on the Court of Appeal decision are reproduced below.

On January 27, 2020, the Attorney General of Ontario applied for leave to appeal to the Supreme Court of Canada. This may come as a surprise to some, given that counsel for Ontario previously suggested that the solution to this issue does not lie with the courts.

National Steel Car is now expected to file a response to Ontario’s application for leave, following which the Supreme Court will decide whether to hear the case. It should be noted that, even if the Supreme Court does hear the case, it will not be deciding the issue on the merits, but instead will look at whether the Court of Appeal was right to send the case back to the lower court for a full hearing. Nevertheless, if the case is accepted for hearing, the Supreme Court may still provide some instructive comments that touch on the core issue of whether the Global Adjustment is a regulatory charge or an impermissible tax.

Excerpt from our recent commentary in Canadian Power

National Steel Car Limited v. Independent Electricity System Operator

The Ontario Court of Appeal has decided that the ongoing constitutional challenge to the “Global Adjustment” brought by National Steel Car Limited deserves a full hearing.

The Global Adjustment is a charge paid by all Ontario electricity consumers to cover the difference between the hourly electricity price and the price guaranteed to generators pursuant to their IESO procurement contracts. It is also intended to cover various infrastructure improvements and conservation programs. The amount paid by consumers, including National Steel Car (a heavy industrial user), has increased substantially since 2008, due to a number of factors including the Green Energy Act.

National Steel Car is challenging the Global Adjustment by arguing that it is actually a tax in disguise, and is therefore unconstitutional because Ontario cannot levy indirect taxes.

Last year we reported on the decision of the lower court, in which the motions judge struck National Steel Car’s applications on the basis that it was “plain and obvious” that the applications had no chance of success because the Global Adjustment was a regulatory charge and not a tax.

National Steel Car successfully appealed that decision this year. The company’s argument focuses particularly on the existing FIT contracts, which it states are not actually part of a closed regulatory system designed to promote cleaner energy sources, but instead are being used to accomplish broader policy goals unrelated to electricity generation, such as rural development.

The Court of Appeal ruled on November 29, 2019, that National Steel Car’s claim is sufficiently plausible that the lower court should not have dismissed it without a full hearing on all of the evidence. The Court of Appeal did not make any findings on the merits of National Steel Car’s arguments. The matter has been sent back to the lower court to be considered on a full evidentiary record.

On January 23, 2020, the Ontario Energy Board (the “OEB”) denied an application by the Association of Major Power Consumers in Ontario (“AMPCO”) for an order under section 33 of the Electricity Act, 1998 (the “Act”) to revoke the market rule amendments identified as MR-00439-R00 to –R05: “Transitional Capacity Auction” (the “Amendments”) and refer such amendments back to the Independent Electricity System Operator (“IESO”) for further consideration and lifted a stay of the operation of the Amendment as ordered by the Decision and Order of the OEB dated November 25, 2019.

The Amendments at issue relate to the IESO’s new capacity market. The Amendments allowed for the IESO’s Demand Response Auction (“DRA”) which was launched in 2015 and only procured capacity from DR Resources to evolve into a Transitional Capacity Auction (“TCA”) which would also allow participation by generators that are neither under contract nor rate-regulated to compete for capacity commitments. The main issue raised by AMPCO in its application for the OEB to revoke the Amendments was that the Amendments were unjustly discriminatory to DR Resources. AMPCO claimed that their capacity offers in the TCA would not be able to compete with those of generation resources due to the out-of-market energy payments available to generation resources but not DR Resources.

The Statutory Test

This is only the OEB’s second hearing of a market rule review application since market opening in 2002. The OEB’s elucidation of the statutory test is therefore particularly valuable.

The statutory test that applies when reviewing market rule amendments is set out in Section 33(9) of the Act. The statutory test must determine whether the amendments (i) are inconsistent with the purposes of the Act; or (ii) unjustly discriminate against or in favour of a market participant or class of market participants. The central issue in this case was whether the Amendments, by enabling generation resources to compete in an expanded capacity auction, had the effect of being unjustly discriminatory to DR Resources. In order to determine whether the Amendments are unjustly discriminatory, the OEB found that three elements are required:

1. There must be economic discrimination. The OEB recognized that in the context of electricity markets, discrimination could arise from differences in treatment, including differences in treatment for different classes of market participants.
2. The applicant must show that the difference in treatment is not justified by a difference in circumstances. The OEB noted that “[i]t is only different treatment in the absence of material and relevant differences in the situation or characteristics among the affected market participants that raises the prospect of unjust discrimination.”
3. The claim of discrimination and the economic impact of the difference in treatment must have some quantitative aspect to it and cannot be solely qualitative.

The OEB’s Findings

On the question of economic discrimination, the OEB found that generators and DR Resources were treated differently in the forms of differences in eligibility for payments. For example, some generators are eligible for out-of-market activation payments and start-up costs under the real-time generation cost guarantee (GCG) program. These payments are not made available to DR Resources.

On the question of differential treatment and differences in circumstances, the OEB notably found that both generators and DR Resources incurred activations costs and both are functionally equivalent in balancing supply and demand in the energy market. As such, the OEB found that there was no relevant differences in circumstances. This finding reflects the considerable strides load-side resources have made into the IESO-administered markets in recent years.

On the question of whether AMPCO had demonstrated the quantification of the economic impact, the OEB found that there was no evidence presented by any party on the range of costs by any of these market participants and that the absence of quantitative evidence of costs that different parties incur did not allow the OEB to determine whether the different treatment of generators and DR Resources constituted unjust discrimination. The OEB stated that the experience under the DRA thus far demonstrated limited activation of DR Resources which would suggest that there would have been limited economic impact on DR Resources.

Considerations for the IESO

The OEB provided certain observations relating to market changes. As the capacity market continues to expand by adding additional capacity resources and retaining additional resource commitments, the OEB noted that the IESO “should examine the total costs and compensation available to capacity market participants, whether that compensation is in the capacity market or the energy market, and whether that compensation is an out-of-market payment or some form of energy payment”. Though the OEB did not find that there was unjust discrimination between DR Resources and generators under the TCA, as the capacity market continues to evolve, ensuring that there is no unjust discrimination as between different classes of market participants should be considered a priority.

In so doing, the IESO will need to pay heed to the OEB’s finding that both supply and demand-side resources are “functionally equivalent”. The OEB made this finding despite evidence tendered to suggest that the absence of consumption or ‘negawatt’ of electricity does not necessarily provide the same societal and economic value as the supply or ‘megawatt’ of electricity. If both supply and load are indeed to be treated as functionally equivalent resources for the purposes of participation in the IESO-administered markets, then this would appear to support the case for providing some form of make whole payments for non-generator capacity market participants.

Possible energy payments for economic activation of DR resources is the subject of a current IESO stakeholder engagement. It will be interesting to see if and how that stakeholder engagement will inform the IESO’s pending resource adequacy stakeholder engagement. On the one hand, the OEB’s decision permits the IESO to proceed with broadening competition in the June 2020 capacity auction consistent with its efforts to meet the projected capacity need starting in 2023 as described in the recently released IESO Annual Planning Outlook. On the other hand, the introduction of energy or other form of out-of-market make-whole payments for non-generator capacity market participants could dampen economic efficiency and reduce intended cost savings to ratepayers.

Our team at McCarthy Tétrault continues to closely follow the development of the IESO’s capacity auction, as well as the market renewal program generally. If you would like more information about this decision or more information about the market renewal program generally, we are here to help. Please contact Reena Goyal or Zachary Masoud or any other member of the Power Group at McCarthy Tétrault with any questions or for assistance.

One of the themes of Ontario’s revised 2017 Long-Term Energy Plan, Delivering Fairness and Choice (the “LTEP”), was that “innovative technologies have the potential to transform Ontario’s energy system”[1]. A key example of innovation includes storage solutions. The LTEP noted that “energy storage is a game-changing technology” and highlighted a report published by the IESO on energy storage in March 2016 which found that “energy storage facilities could provide many of the services needed to ensure the electricity system in Ontario operates reliably”.[2] The LTEP called for the IESO and the Ontario Energy Board (“OEB”) to take appropriate steps to identify market and regulatory barriers that disadvantage energy storage, specific rules and codes that “prevent the cost-effective development of energy storage where it can provide value to customers and the electricity system”[3].

Since 2016, energy storage and storage solutions have gained momentum in Canada. As the price of storage technology lessens and growing markets further drive down costs, low costs energy storage should materially expand in Canada.

Solar + Storage: A New Opportunity?

One recent trend in the United States has been the adoption of storage-plus-renewable energy projects, particularly in the solar space. Many major developers in the United States have made significant investments in large-scale solar-plus-storage projects. For example, Florida Power & Light announced plans to power its 409 megawatt Manatee Energy Storage Center by utility-scale solar, “the largest battery project unveiled so far in the U.S. on a megawatt basis”[4] and Hawaiian Electric sent seven solar-plus-storage power purchase agreement (“PPA”) contracts to state regulators which “would add 262 megawatts of solar and 1,048 megawatt-hours of storage distributed over three islands”[5] and which are all at a price of $0.10/kWh or below. What is significant in both of these examples and others in the United States is the low PPA price for projects which combine energy storage technologies and renewable resources.

In a report by Navigant Research (“Navigant”) entitled “How Utilities Can Look Beyond Natural Gas with Cost-Effective Solar Plus Storage Strategies” (the “Navigant Report”), Navigant highlighted that lithium-ion batteries, which “account[ed] for 29.4% of the non-pumped storage capacity installed and 70% of the advanced battery capacity deployed since 2011” was driving market growth and decreasing technology risk and costs associated with energy storage solutions.[6] Highlighting the trend of energy storage solutions being developed together with renewable resources at competitive prices, Navigant predicts “storage-plus Power Purchase Agreement (PPA) prices to fall as adoption of this technology expands”.[7] The Navigant Report urged utilities and regulators both in the United States and abroad to adopt storage-plus renewable energy projects.

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 Alberta Electric System Operator (“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 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 (greater than 50 MW) are unlikely 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).
• Smaller storage projects (below 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; (2) and price saturation in the operating reserve markets can be avoided.

Although the AESO concluded that there was no requirement to procure storage capacity, it is nonetheless developing an Energy Storage Roadmap for Alberta’s system. Alberta’s recent election and pending energy policies change could result in opportunities. If Alberta proceeds with its capacity market transition, partnering with energy storage could provide a mechanism for renewables to participate. We will continue to monitor and provide updates on the AESO’s development of the Alberta Energy Storage Roadmap.

Energy Storage in Ontario

While the presence and buzz surrounding energy storage technologies has been developing rapidly in Ontario, the regulatory landscape has not developed at a corresponding pace. In recent months, electricity regulators in Ontario have taken significant steps to close the gap and prepare for future investment and integration of energy storage technologies in the electricity grid. Advisory bodies have been formed such as the Independent Electricity System Operator’s (“IESO”) Energy Storage Advisory Group to engage feedback and involve industry stakeholders in the development of procurement processes, technical standards, metering and permitting for energy storage. Similarly, the OEB has developed a special license and related exemption for energy storage projects in the province.

In December 2018, the IESO published a report entitled Removing Obstacles for Storage Resources in Ontario (the “IESO Report”). The IESO Report set out a number of recommendations towards removing the regulatory barriers facing energy storage technologies and sector participants in Ontario in order to encourage investment and realize on the benefits available from energy storage. The IESO Report looked primarily at changes within the IESO’s regulatory jurisdiction, but also advocated a collaborative approach with other regulatory bodies recommending that the OEB review and update relevant codes and that the Ontario government consider energy storage more directly in amendments to existing legislation and future legislation.