Bonneville Power Administration
Submitted 05/19/2022, 02:29 pm
1.
Please provide your organization’s overall position on the DAME revised straw proposal: a.) Support b.) Support with caveats c.) Oppose d.) Oppose with caveats e.) Neutral/No position/Need more information
Overall position: Support with caveats
The Bonneville Power Administration (Bonneville)[1] continues to support the development of an imbalance reserves product that is co-optimized with energy and ancillary services and also supports development of a reliability capacity down product. These products are important additions to the CAISO’s day-ahead market that will support reliability by better positioning resources capable of addressing the significant uncertainty that manifests between the day-ahead and fifteen-minute market timeframes. In particular, the imbalance reserve product has an important role in EDAM in that it ensures the EDAM footprint has sufficient flexible reserves to meet ramping and uncertainty needs, and provides a common standard that enables the trading and optimization of day-ahead reserve capacity across the EDAM footprint.
With that said, Bonneville has significant concerns with the proposed market power mitigation (MPM) measures for energy, reliability capacity, and the imbalance reserve product. The new measures create significant risk of over-mitigation, which discourages participation of external supply in the CAISO BAA and introduces significant concerns for any hydro entity considering participation in an EDAM that is built on this construct. In DAME, mitigation measures affecting external supply can and should be managed by allowing external supply to forego awards rather than be mitigated. In EDAM, mitigation measures remain problematic due to more exposure to administrative market outcomes and because the number of arguably uncompetitive paths would dramatically increase. Further, Bonneville is concerned that the proposed mitigation measures undermine the results of the hydro Default Energy Bid (DEB) process.
Bonneville is alarmed by this continued trend in the CAISO markets towards expanded administrative price suppression mechanisms such as additional bid offer caps and more stringent market power mitigation measures. These actions only serve to reduce participation of external supply and competition for the CAISO BAA, which is exactly the opposite outcome required to lessen the likelihood of market power. Rather than continuing to incrementally add layers of price suppression measures such as arbitrary bid caps and market power mitigation measures, the CAISO needs to take a step back and employ a more holistic approach to price formation for its markets with the objective of ensuring prices transparently reflect the needs of the grid and the costs of meeting those needs.
Continued focus on mitigation measures rather than on transparent market price signals drives Bonneville’s strong desire for measures that insulate external suppliers from over-mitigation, like allowing participants to forego awards rather than have bids mitigated or capped. As discussed extensively in the hydro DEB process, Bonneville is concerned about over-mitigation because it represents a reliability risk. If our bids are mitigated, resulting in unintended dispatch at uneconomic prices to other balancing authorities, limited hydro reservoirs can be depleted in situations where that generation is necessary to meet load in future periods. It is critical that Bonneville retain the ability to meet its future load without reliance on market purchases, caused by over-mitigation.
[1] Bonneville is a federal power marketing administration within the U.S. Department of Energy that markets electric power from 31 federal hydroelectric projects and some non-federal projects in the Pacific Northwest with a nameplate capacity of 22,500 MW. Bonneville currently supplies around 30 percent of the power consumed in the Northwest. Bonneville also operates 15,000 miles of high voltage transmission that interconnects most of the other transmission systems in the Northwest with Canada and California. Bonneville is obligated by statute to serve Northwest municipalities, public utility districts, cooperatives and then other regional entities prior to selling power out of the region.
2.
Please provide your organization’s summary comments on the Day Ahead Market Enhancements 3rd Revised Straw Proposal and on the April 29, 2022 stakeholder call.
In summary:
- Bonneville strongly opposes the proposed MPM changes for the IFM and RUC for the following reasons:
- Energy and availability bids should be mitigated based on bid-in demand, rather than imbalance reserve deployment scenarios in the IFM.
- The reliability capacity bid cap ($247) provides sufficient mitigation against market power of reliability capacity.
- The values that imbalance reserves and reliability capacity availability bids are mitigated to, must properly account for the complex and dynamic nature of hydropower opportunity costs, including the value of storing water for days, weeks, or months to meet future higher value energy demands. The competitive LMPs proposed to be used for mitigation of reliability capacity and imbalance reserves do not accomplish this.
- CAISO should proceed cautiously with new market power mitigation measures and draw upon previous FERC determinations of appropriate market power mitigation measures.
- Bonneville requests that, at a minimum, resources must be given an option to forego the award of imbalance reserves or reliability capacity rather than face mitigation forcing the resource to be deployed when it wouldn’t be otherwise, risking future reliability.
- Bonneville requests the CAISO enable market participants to submit imbalance reserve bid curves that allow for different imbalance reserve bids for different quantities.
- RUC needs to be restored to its original purpose, which is to procure reliability capacity to meet any difference between bid-in demand vs. the expected demand forecast and backup any net virtual supply. The CAISO should stop using a high confidence RUC demand forecast once DAME is implemented.
- To be eligible to provide imbalance reserves or reliability capacity, there needs to be a high degree of confidence that a resource’s output will be consistent with its award. This needs to be factored in when considering the eligibility of variable energy resources to provide imbalance reserves up and reliability capacity up.
- If real-time energy bids from imbalance reserves and reliability capacity awards will be capped, then the CAISO should not also mitigate the availability bids.
- Bonneville supports the ability of RA resources to bid non-zero $/MW for imbalance reserves and reliability capacity.
3.
Please provide your organization’s comments on the need for day-ahead market enhancements.
Bonneville strongly agrees with the CAISO on the need for the day-ahead market enhancements. The CAISO has clearly explained the benefits of these new day-ahead capacity products and reasons why they are preferable to out-of-market actions currently employed by CAISO system operators to maintain the reliability of the grid. CAISO operators have relied upon significant amounts of out-of-market actions that create market inefficiencies, fail to properly incentivize flexible capacity, and distort market prices and signals. Bonneville also views the development of the imbalance reserve (IR) product as foundational for EDAM.
Bonneville is troubled by some stakeholder groups’ opposition to the IR product, particularly concerns raised around this product creating higher prices. Price transparency and accurate price formation is a key feature of efficient markets that properly incent both generation and load to reduce the need for out-of-market actions and ultimately reduce long-term costs.
The IR product provides an opportunity for additional clean, flexible resources to meet CAISO’s uncertainty and ramping needs. RUC commits hourly capacity that may not provide the flexibility that is needed in real-time. And the RUC process limits participation of certain resources, namely system resources (such as Bonneville’s hydro system resources) that are not allowed to participate in the RUC process without a resource adequacy (RA) contract. Notwithstanding the RUC requirements, Bonneville has limited excess firm hydro supply to sell as RA given the various uncertainties of hydro operations and obligations in the RA procurement timeframe. But in the day-ahead timeframe, Bonneville may provide additional firm hydro supply given that variables such as stream flows, load forecasts, seasonal operating constraints and targets, etc., are more defined.
4.
Please provide your organization’s comments on changes to the IFM Market Power Mitigation Pass.
The proposed changes to the MPM pass for the IFM are concerning to Bonneville. Energy and availability bids should be mitigated based on bid-in demand, rather than imbalance reserve deployment scenarios in the IFM. The values that imbalance reserves availability bids are mitigated to, must properly account for the complex and dynamic nature of hydropower opportunity costs, including the value of storing water for days, weeks, or months to meet future higher value energy demands. The competitive LMPs proposed to be used for mitigation of imbalance reserves do not accomplish this.
Continued focus on mitigation measures rather than on transparent market price signals drives Bonneville’s strong desire for measures that insulate external suppliers from over-mitigation, like allowing participants to forego awards rather than have bids mitigated or capped. As discussed extensively in the hydro DEB process, Bonneville is concerned about over-mitigation because it represents a reliability risk. If our bids are mitigated, resulting in unintended dispatch at uneconomic prices to other balancing authorities, limited hydro reservoirs can be depleted in situations where that generation is necessary to meet load in future periods. It is critical that Bonneville retain the ability to meet its future load without reliance on market purchases, caused by over-mitigation.
We understand that the CAISO is proposing to evaluate the competitiveness of bids in the IFM for three scenarios: (1) the base scenario (cleared bid-in load), (2) the imbalance reserve up deployment scenario, and (3) the imbalance reserve down deployment scenario. If any of these scenarios are determined to be uncompetitive, energy bids will be mitigated. If either of the imbalance reserve deployment scenarios is determined to be uncompetitive, imbalance reserve bids will also be mitigated.
While the imbalance reserve product is being added to the IFM, day-ahead energy will still clear at the bid-in demand. The imbalance reserve deployment scenarios address the outer ends of the distribution of requirements (97.5 and 2.5 percentiles). To mitigate energy prices based upon uncompetitive conditions in these scenarios would impose mitigation of day-ahead energy bids for the potential of a rare circumstance occurring in real-time. Additionally, resources that receive an imbalance reserve product award or an ancillary service award must economically offer energy into the real-time market. The real-time market has its own MPM pass that mitigates real-time energy bids when conditions are uncompetitive.
FERC has already determined that using bid-in demand is the appropriate basis for market power mitigation in the day-ahead market. In its September 21, 2006 Order, the Commission required the CAISO to use bid-in demand rather than forecasted demand as the basis for market power mitigation in the day-ahead market, agreeing with commenters that using the CAISO forecasted demand would cause the CAISO to over-mitigate suppliers[1]. The imbalance reserve requirements are neither based on bid-in demand, nor the forecast demand, but rather based on bid-in demand plus reliability capacity plus a historical level of uncertainty between the day-ahead and the real-time market. Therefore, mitigating the imbalance reserve deployment scenarios would result in systemic over-mitigation beyond the bid-in demand, which would discourage bids from the very supply that this product is attempting to procure. For all of these reasons, Bonneville strongly opposes mitigation of energy bids based on the deployment scenarios and recommends the CAISO continue using the base scenario (using bid-in demand) as the basis for market power mitigation of energy bids in the day-ahead market, consistent with FERC’s September 21, 2006 Order.
Over-mitigation of bids (energy or capacity) harms the seller and discourages participation in the CAISO markets, particularly from external supply. The CAISO should proceed cautiously with new market power mitigation measures and draw upon previous FERC determinations of appropriate market power mitigation measures.
Regarding the values resources are mitigated to, Bonneville and other participating hydro resource owners have spent significant time and effort working with the CAISO on a workable hydro bid (DEB) as part of the Local Market Power Mitigation Enhancements initiative in 2018. The hydro DEB was intended to account for the complex and dynamic nature of hydropower opportunity costs, including the value of storing water for days, weeks, or months to meet future higher value energy demands. As Bonneville noted in that initiative, Bonneville markets wholesale power from the energy-limited FCRPS to meet preference load, risk-adjusted marketing objectives for surplus power, and reliability obligations in its BAA after meeting non-power constraints. As such, operational considerations are paramount. Bonneville relies on its models and its people to determine how to best meet its hydraulic objectives in light of our obligations. The CAISO’s proposal to mitigate availability bids to a competitive LMP does not allow for any of these important hydro considerations. And the proposed mitigation measures are also combined with a real-time energy bid cap that leaves the hydro owner unable to manage its operations through its bids.
[1] Paragraph 1089 of FERC Order Conditionally Accepting the CAISO’s Electric Tariff Filing to Reflect Market Redesign and Technology Upgrade Issued September 21, 2006. (Sept. 21, 2006 FERC Order)
5.
Please provide your organization’s comments on changes to the Integrated Forward Market.
Bonneville notes that the CAISO has not responded to its previous comments to enable market participants to submit imbalance reserve bid curves that allow for different imbalance reserve bids for different quantities. Bonneville reiterates that the limitation on resources to submit only a single price offer for a single quantity for imbalance reserve capacity does not allow suppliers to offer imbalance reserves based on additional costs, including opportunity costs and/or transmission costs, as the amount of imbalance reserves offered increases. This will likely result in suppliers offering a lower quantity of imbalance reserves than they would otherwise if resources were allowed to price differentiate their quantity offers. To maximize participation for the imbalance reserve products, Bonneville again requests the CAISO enable market participants to submit imbalance reserve bid curves that allow for different imbalance reserve bids for different quantities.
6.
Please provide your organization’s comments on the RUC Market Power Mitigations Pass.
Bonneville believes the reliability capacity bid cap ($247) provides sufficient mitigation against market power. We disagree with the CAISO that prior FERC rulings, which found that a $250/MWh bid cap on RUC availability bids provide sufficient mitigation of any potential for market power, don’t apply to the current market context.
7.
Please provide your organization’s comments on changes to the Residual Unit Commitment.
Bonneville reiterates its request for clarification regarding what net demand forecast will be used in RUC. Specifically, will CAISO continue to use a high confidence forecast in RUC similar to what is being used for summer 2021 or will CAISO revert back to using the expected net demand forecast? Bonneville understands that reducing out of market actions by CAISO operators has been a key driver of this initiative and is anticipating RUC would procure reliability capacity up to an expected demand forecast.
Bonneville also reiterates its request for clarification on which resources can participate in RUC and provide reliability capacity up and down. Section 31.5.1.1 of CAISO’s tariff states that “Capacity from Non-Dynamic System Resources that have not been designated Resource Adequacy Capacity is not eligible to participate in the RUC.” Our understanding then is that imports that are non-dynamic and have not been designated as resource adequacy capacity are not eligible to provide reliability capacity up and reliability capacity down. Will these eligibility requirements remain the same once DAME is implemented or is CAISO proposing to make modifications to the eligibility requirements for participation in the RUC as part of the DAME initiative?
8.
Please provide your organization’s comments on Real-Time Market Ramp Deviation Settlement.
No comments.
9.
Please provide your organization’s comments on Congestion Revenue Rights.
No comments.
10.
Please provide your organization’s comments on Accounting for Energy Offer Cost in Upward Capacity Procurement.
Bonneville supports the ability to distinguish resources with high energy costs from resources with low energy costs when awarding reliability capacity up and imbalance reserves up. The CAISO proposes to implement a real-time energy bid price cap on all resources that receive an imbalance reserve up or reliability capacity up award. Resources with energy costs above the real-time energy bid cap will need to incorporate the financial risk of being subject to the real-time cap into their imbalance reserve up and reliability capacity up bids. Bonneville finds it problematic that these same resources are also subject to having their imbalance reserve up and reliability capacity up availability bids mitigated. If the CAISO moves forward with a real-time energy bid cap on all resources that receive an imbalance reserve up and reliability capacity up award, the CAISO should not also put those same resources at risk of having their availability bids mitigated.
Bonneville will need to better understand the specific methodology of how the P97.5 price that sets the real-time energy bid cap would be determined before we can offer our support to this approach.
11.
Please provide your organization’s comments on the Alignment between RA, DAME and EDAM.
No comments.
12.
Please provide your organization’s comments on the WEIM Governing Body Role.
Given that the DAME is an “essential element” of EDAM, Bonneville believes the EIM Governing Body should have joint authority with the CAISO Board on all aspects of the DAME proposals. This includes the real-time energy bidding rules for resources that received awards in the day-ahead market to provide imbalance reserves up, bidding obligations for resources that have day-ahead schedules for imbalance reserve or reliability capacity, and the remainder of the initiative.
13.
Please provide your organization’s comments on any other additional topics you would like addressed.
Bonneville has no further comments.
California Energy Storage Alliance
Submitted 05/19/2022, 04:48 pm
1.
Please provide your organization’s overall position on the DAME revised straw proposal: a.) Support b.) Support with caveats c.) Oppose d.) Oppose with caveats e.) Neutral/No position/Need more information
b.) Support with caveats
2.
Please provide your organization’s summary comments on the Day Ahead Market Enhancements 3rd Revised Straw Proposal and on the April 29, 2022 stakeholder call.
In these comments, the California Energy Storage Alliance (CESA) recognizes the California Independent System Operator’s (CAISO or ISO) analyses and proposals to improve upon the Day-Ahead Market’s (DAM) current design. Overall, CESA continues to support the creation the Imbalance Reserve (IR) product as a means to address growing uncertainty between the Integrated Forward Market (IFM) and Real-Time Dispatch (RTD)?. CESA agrees that IR is an essential product to minimize the cost and emissions related to uncertainty in RTD. To this end, ?CESA’s comments can be summarized as follows:
- CESA does not believe the 15-minute nature of IR should be reevaluated as the CAISO system is certainly moving towards higher dependence on intermittent and energy-limited assets. ?
- CESA welcomes the CAISO’s proposal to establish IR requirements using a quantile regression methodology.
- CESA supports the establishment of a graduated penalty price structure for IR procurement; nevertheless, the lack of justification behind the illustrative values presented in the third revised Straw Proposal (TRSP) limits stakeholders’ ability to provide significant feedback.
- CESA requests clarity on how the IR product’s penalties for unavailability in the RTD would incorporate the energy limitations of certain assets.
- CESA considers IR is better positioned to address the variance resultant from the increased penetration of VERs and the frequency of extreme weather events and requests additional analysis that demonstrates Reliability Capacity (RC) is needed since IR alone could not mitigate the risks identified by CAISO in Section 2 of TRSP.
- CESA acknowledges and supports the CAISO’s decision to modify the schedule of DAME in order to align with the EDAM initiative, thus removing the need for the contentious “transition period” in which IR-eligible resources would have been required to submit $0 IR bids.
- CESA requests the CAISO expand on this explanation regarding the differences in use and purpose between IR and the Flexible Ramping Product (FRP).
- CESA requests the CAISO revise the TRSP to include examples regarding how NGR assets can bid, how their IR bids would be optimized and translated from the hourly domain to 15-minute instructions, and how IR would interact with the state-of-charge exceptional dispatch (SOC ED).
3.
Please provide your organization’s comments on the need for day-ahead market enhancements.
Overall, CESA agrees with the CAISO’s justification for the creation of the IR product and the modification of the RUC process. As noted in the TRSP, the CAISO’s grid is experiencing a profound transformation. With thousands of MW of intermittent, energy-, and use-limited resources, the CAISO’s system has become increasingly susceptible to forecast deviations that result in energy imbalances between the Day-Ahead Market (DAM) and Real-Time Dispatch (RTD). Data presented in the TRSP demonstrates that these imbalances are frequent and have increased in magnitude in recent years, reaching up to 6 GW in the positive direction and about 7 GW in the negative direction, in a single hour.
To manage these energy imbalances, operators have resorted to out-of-market actions, such as manually adjusting the RUC forecast to ensure sufficient capacity can meet load. While useful, these adjustments inevitably lead to uneconomic and inefficient outcomes. Given the fact that all resources that provide Resource Adequacy (RA) are required to bid RUC at $0 if they have not been fully scheduled or awarded in the IFM, a manual revision of the RUC forecast will not result in the efficient selection of the most economic capacity. Moreover, since the RUC process today is only design to procure capacity in the positive (up) direction, operators are unable to identify the optimal capacity to move downwards, if required. Finally, even if the operators are able to adjust the RUC forecast and schedule the needed capacity, the eligibility requirements for RUC participation do not ensure that selected capacity will be sufficient to meet 15-minute ramping needs. In this context, the efficiency benefits of creating a specific product that can address the bidirectional uncertainty between the DAM and the RTD are significant.
The creation of an IR product will mitigate operational risks associated with load and supply forecast variability. By establishing IR as a product to be co-optimized with energy and ancillary services (AS) in the IFM, and modifying the RUC process to require non-$0 bids, the CAISO will be able to identify economic outcomes that maximize the value of responsive capacity. Furthermore, allowing RA resources to recover RTD availability costs via IR and RC bids could place downward pressure on RA contract prices. As such, CESA considers that the CAISO’s justification for DAME is reasonable and grounded in the multifaceted modernization of California’s grid.
4.
Please provide your organization’s comments on changes to the IFM Market Power Mitigation Pass.
CESA offers no comments at this time.
5.
Please provide your organization’s comments on changes to the Integrated Forward Market.
In the TRSP, the CAISO notes that the DAM will only award IR to resources that are dispatchable in the fifteen-minute market, up to their fifteen-minute ramp capability. CESA considers that this eligibility determination is correct considering the CAISO’s intent to minimize the impact of net load forecast uncertainty, which is largely driven by sudden changes in load (weather events) and supply (VER output). Moreover, retaining the fifteen-minute dispatchability requirement for IR provides a reasonable hedge against intra-hourly variance. In this context, CESA urges the ISO to retain these fifteen-minute eligibility parameters for IR, noting that responsiveness is essential to address uncertainty in the RTD.
In Section 3.3 of the TRSP, the CAISO presents its methodology to estimate the IR requirement within the DAM. CAISO staff notes that they will use a quantile regression methodology to determine IR requirements. CASIO argues that a quantile regression methodology is better equipped than a linear regression methodology because the IR requirements should be based on the outliers (percentiles 2.5 and 97.5) of the net load imbalances, not their averages. CESA supports the use of a quantile regression analysis. This methodology is adequate to estimate magnitude of IR requirements since, compared to an ordinary least squares regression, quantile regression makes no assumptions about the distribution of the target variable. As such, the CAISO should utilize this method to identify IR requirements.
In prior proposals, the CAISO suggested that the procurement of IR should be done based on a single constraint relaxation penalty price. In the TRSP, the CAISO has modified its recommendation, now proposing a graduated penalty price structure that can gradually relax the IR requirement at higher costs. Importantly, the CAISO proposes to retain discretion to set the penalty price and procurement relaxation prices in conjunction with stakeholders that will participate in the Extended DAM (EDAM). In the TRSP, the CAISO included an illustrative table detailing the IR graduated penalty prices, noting that the values presented are not final and could be significantly altered by EDAM stakeholders. While CESA sees merit in the idea of a graduated penalty price framework, the lack of justification behind the illustrative values limits stakeholders’ ability to provide significant feedback. In addition, since these values may change due to feedback in the EDAM initiative, CESA limits its input noting that a graduated structure is desirable and should be further developed and have its parameters justified.
Finally, in the TRSP, the CAISO elaborates on how resources with an IR award in the DAM would be penalized if they are unavailable in RTD. The ISO proposes to have resources that do not support their day-ahead energy and IR award shall be charged with the higher of the RTPD FRU price, the RTD FRU price, or the IR price. CESA requests clarification how this would apply to resources with energy limitations, such as NGR assets that are dependent on their state-of-charge (SOC) or hydroelectric assets that may have daily energy limitations. It is currently unclear if this proposal would assess penalties based exclusively on the bid range, or it if it will consider SOC and daily energy limits. To this end, CESA urges the ISO for clarity on this matter.
6.
Please provide your organization’s comments on the RUC Market Power Mitigations Pass.
CESA offers no comments at this time.
7.
Please provide your organization’s comments on changes to the Residual Unit Commitment.
CESA understands the CAISO’s intent in improving the RUC process is to ensure that RC-eligible resources may economically provide incremental capacity in both the upward and downward directions by submitting non-$0 bids. While CESA agrees with the conclusion that such a modification would result in a more economic and efficient use of RC-eligible capacity, the CAISO has yet to present evidence to indicate that both IR and RC are needed improvements for the DAM. From CESA’s perspective, IR is better positioned to address the variance resultant from the increased penetration of VERs and the frequency of extreme weather events. While the proposed improvements to the RUC process are reasonable prima facie, CESA requests additional analysis that demonstrates IR alone could not mitigate the risks identified by CAISO in Section 2 of TRSP.
8.
Please provide your organization’s comments on Real-Time Market Ramp Deviation Settlement.
See CESA’s answer to question 13.
9.
Please provide your organization’s comments on Congestion Revenue Rights.
CESA offers no comments at this time.
10.
Please provide your organization’s comments on Accounting for Energy Offer Cost in Upward Capacity Procurement.
CESA offers no comments at this time.
11.
Please provide your organization’s comments on the Alignment between RA, DAME and EDAM.
CESA recognizes the CAISO’s leadership in organizing and coordinating several initiatives that are essential to retaining and improving the reliability of its footprint. As stated in the TRSP, the CAISO must ensure alignment and consistency across the RA Enhancements, DAME, and EDAM initiatives to ensure a robust market capable of efficiently serving load while advancing California’s decarbonization goals. To this effect, CESA acknowledges and supports the CAISO’s decision to modify the schedule of DAME in order to align with the EDAM initiative. This modification has obviated the need for the contentious “transition period” in which IR-eligible resources would have been required to submit $0 IR bids. This type of alignment and responsiveness to stakeholder concerns is welcome, as it greatly alleviates potential financeability risks. As such, CESA welcomes the ISO’s labor to align these three initiatives and looks forward to continuing collaborating with the ISO and other stakeholders across these venues.
12.
Please provide your organization’s comments on the WEIM Governing Body Role.
CESA offers no comments at this time.
13.
Please provide your organization’s comments on any other additional topics you would like addressed.
In the TRSP, the CAISO offers a series of clarifications regarding differences between IR and the FRP. CESA requests the CAISO expand on this explanation considering a number of stakeholders have raised questions regarding their use and purpose. This should include examples on price formation and the co-optimization of energy, AS, and IR.
The TRSP also includes additional information regarding the potential for storage resources participating under the Energy Storage Resource (ESR) pathway to provide products outlined in DAME. While CESA welcomes this information, we request that a similar section is created for the NGR pathway, which is currently used by the overwhelming majority of storage assets interconnected to the CAISO’s system. Given potential changes in the schedule of the Energy Storage Enhancements (ESE) initiative, CESA considers that discussion of the ESR pathway in this forum is premature. Instead, the CAISO should revise the TRSP to include examples regarding how NGR assets can bid, how their IR bids would be optimized and translated from the hourly domain to 15-minute instructions, and how IR would interact with the state-of-charge exceptional dispatch (SOC ED).
California Public Utilities Commission - Public Advocates Office
Submitted 05/19/2022, 04:08 pm
1.
Please provide your organization’s overall position on the DAME revised straw proposal: a.) Support b.) Support with caveats c.) Oppose d.) Oppose with caveats e.) Neutral/No position/Need more information
Cal Advocates is opposed to the Day-Ahead Market Enhancements (DAME) revised straw proposal.
2.
Please provide your organization’s summary comments on the Day Ahead Market Enhancements 3rd Revised Straw Proposal and on the April 29, 2022 stakeholder call.
The CAISO’s DAME Third Revised Straw Proposal (Proposal) would alter CAISO Must Offer Obligation (MOO) rules and includes conditions that could allow Resource Adequacy (RA) resources to be paid twice for providing a single service. The absence of a zero-dollar bid requirement and the eligibility for RA resources to receive non-zero market payments for Imbalance Reserves (IR) and Reliability Capacity (RC) for RA resources would effectively pay RA resources twice for the same service. The Proposal does not include an estimation of the value or potential revenues associated with the IR and RC products.[1] To avoid unnecessary costs to ratepayers, existing RA contracts would need to be modified to account for new CAISO market revenues for services already provided and paid for by those contracts. These modifications may not be feasible due to existing contract terms.
[1] The lack of estimated prices for proposed products was discussed by stakeholders and CAISO staff in discussions during the DAME Third Revised Straw Proposal Workshop, April 29, 2022.
3.
Please provide your organization’s comments on the need for day-ahead market enhancements.
Cal Advocates has no comment on this topic at this time.
4.
Please provide your organization’s comments on changes to the IFM Market Power Mitigation Pass.
Cal Advocates has no comment on this topic at this time.
5.
Please provide your organization’s comments on changes to the Integrated Forward Market.
The Proposal would implement two new capacity products to enable the CAISO to send market instructions to increase or decrease resource generation. The IR product would be an IFM product that would enable the CAISO to issue market instructions to a generator to dispatch upward or downward (increase or decrease actual generation) based on uncertain load needs that emerge between the day-ahead and real-time markets.[1] The RC product would similarly allow the CAISO to increase or decrease a resource’s generation awarded in the CAISO market but would be procured by the CAISO through the existing Residual Unit Commitment (RUC) process.[2] Both products would provide services that the CAISO already procures from RA resources[3] through out-of-market actions[4] and the RUC process. The CAISO asserts that the IR and RC products would allow it to more effectively procure generation to meet actual load.[5] The CAISO proposes to require RA resources to bid for the IR and RC products at any price. This is a departure from existing rules requiring RA resources to submit zero-dollar RUC bids.[6]
Currently, RA resources must offer zero-dollar bids for their available generation to the RUC. These resources are not eligible to receive RUC availability payments even if the RUC clearing price is other than zero dollars.[7] If needed, the CAISO may procure additional capacity through the RUC to meet CAISO’s forecast of load beyond what clears in the IFM.[8] However, the reliability and flexibility that the new IR and RC products would provide are currently accessible through out-of-market actions and in the existing RUC structure.[9] Adding IR and RC products without a zero-dollar bid requirement and providing associated IR and RC revenue to RA resources would alter the RA program since resources would realize new market revenue streams for services that are currently offered with zero-dollar bids.[10]
Today, fixed rates in RA contracts account for the generator’s costs of having a zero-dollar bid requirement for RUC and the obligation to be available in the real-time market (RTM). The CAISO acknowledges that the existing RA obligations create costs to the generator since resources may lose potential RTM energy sales and bear costs of being available such as fuel scheduling and securing transmission.[11] These obligations also prevent RA resources from exporting energy to non-CAISO grids if not procured in the IFM. As the CAISO notes, because RA resources, “… receive no market compensation for their real-time availability, they must recover the costs and risks through [RA] contract payments.”[12]
A non-zero-dollar bid requirement and access to payments for IR and RC would provide generators with additional revenue for IR and RC awards in addition to their RA contract revenue. Currently, RA contracts are priced assuming RUC and real-time availability services receive zero market revenue other than the price of energy if the resource is dispatched. Load-serving entities (LSEs) would be double-charged for those services through payment of the RA contract, which assumes a zero-dollar RUC payment requirement, and the CAISO market costs of procuring IR and RC at non-zero rates.[13] In other words, providing RA resources payments for IR and RC would result in double-charging by generators whose IR or RC bids are selected until RA contracts could be re-negotiated.
Double payment may be avoided by adopting new RA contracts that recognize the ability for RA resources to receive payment for IR and RC, or by adjusting the price of existing RA contracts with delivery terms lasting through DAME implementation. However, negotiations to adjust all existing RA contracts would create administrative costs for LSEs and generators. Also, negotiations to reduce an RA contract’s rate may not be feasible. Cal Advocates does not have insight into the contract conditions of all LSEs, but RA contracts do not necessarily include provisions that obligate parties to adjust ongoing contract rates if CAISO market structures are altered. For example, recent pro forma RA agreements published by Pacific Gas and Electric Company (PG&E) include provisions to continue delivery of products if the CAISO Tariff changes;[14] however, the pro forma RA agreements lack any provisions that require a party to adjust the contract’s price if the CAISO market or Tariff are altered, except by mutual agreement. It is unlikely that a generator would voluntarily reduce the price of a contract if new market revenue streams emerge.
If double-payments are not addressed through contract modification, the double payments would persist until the contract is terminated early or expires. However, early terminations typically incur costs to the terminating LSE and expirations may be as soon as a month or as long as numerous decades. The California Public Utilities Commission (CPUC) estimates that LSEs perform forward contracting at least three years ahead for about 61% of expected RA needs.[15] This means that roughly 24,627 MW worth of RA contracts are executed for service at least three years out.[16] The CPUC also requires contract lengths of at least ten years for most resources procured to meet Integrated Resource Planning (IRP) targets.[17] The significant volume of long-term RA contracts and the potential inability to alter the contract price creates inefficiencies and unnecessary ratepayer costs.
Additionally, the Proposal does not estimate how much IR and RC the CAISO expects to procure, nor does the Proposal estimate the costs of the new IR and RC products.[18] These factors prevent accurate adjustments to existing RA contracts since generators have no estimate of what market revenue to expect from transacting IR and RC. The CAISO states: “Marginal prices are a more appropriate mechanism to compensate resources for their availability than fixed contract payments and results in compensation that reflects when and where the capacity is most valued.”[19] However, a transition from fixed contract payments to market payments cannot be efficiently accomplished without knowing the expected volume of procurement and the price of IR and RC. At the April 29, 2022 workshop, the CAISO acknowledged challenges of estimating IR and RC prices.[20] In order to accurately adjust existing RA contract payments, an estimation of prices and volumes of IR and RC is necessary.
The CAISO should modify its proposal to retain the zero-dollar bid requirements for IR and RC and to not provide RA resources with payments for IR and RC. A zero-dollar bid requirement for RA resources may prevent Extended Day-Ahead Market (EDAM) participants from competitively bidding for IR and RC since RA resources would be bidding at zero-dollars. However, applying a zero-dollar bid requirement to IR and RC would prevent double-payment for those products and avoid unnecessary ratepayer costs.
Alternatively, if the CAISO moves forward with a non-zero-dollar bid requirement and payments for IR and RC to RA resources, it should “grandfather” existing RA contracts by applying a zero-dollar bid requirement for IR and RC products to existing RA contracts. Any RA contract executed prior to DAME implementation should have a zero-dollar bid requirement and prevent access to IR and RC payments, similar to the treatment of RUC bids and availability payments in CAISO Tariff 40.6. Any contract renewal or extension would end the grandfathered treatment, and any RA contract executed after DAME implementation should utilize the bidding and payment requirements for IR and RC as implemented by DAME. Grandfathering would prevent double-payment for reliability services for existing RA contracts. A grandfathering period would also allow a portion of the RA fleet to maintain existing payment structures while observing how IR and RC perform in the market.
[1] Proposal, p. 30.
[2] Proposal, p. 39.
[3] RA resources are required to provide those services as a part of the RA Must Offer Obligation (MOO). See CAISO Tariff 40.6.1 and 40.6.2.
[4] Out-of-market actions include exceptional dispatches and manual adjustments of load forecast that the RUC utilizes today. Proposal, p. 30.
[5] The CAISO would procure IR and RC products with consideration of other market products such as energy and ancillary services. Proposal, p. 5.
[6] Proposal, pp. 34, 40.
[7] CAISO Tariff 40.6.1.
[8] CAISO Tariff, 40.6.1.
[9] Proposal, p. 5.
[10] The CAISO Tariff includes RA must offer obligations that require zero-dollar bids for RUC awards and make RA resource ineligible to receive RUC availability payments if the RUC price clears at a non-zero rate. CAISO Tariff 40.6.1.
[11] Proposal, pp. 16-17.
[12] Proposal, p. 8.
[13] IR and RC costs would be allocated to LSEs and Scheduling Coordinators based on imbalances of virtual supply or demand, contribution to uncertainty, and metered demand. Proposal, pp. 34-35, 41-42.
[14] “Seller shall comply [with] all applicable CAISO Tariff provisions, CPUC Decisions and all other applicable rules, requirements or Laws, including any Bidding of the Project to meet any Must Offer Obligations….” PG&E Mid-Term Reliability RFO – Phase 1: Appendix E2 – Long Term Resource Adequacy Agreement, Retrieved May 11, 2022 (PG&E MTR RFO Pro Forma Agreement), Article 4.4(b) (Page 12). Available at: https://www.pge.com/en_US/for-our-business-partners/energy-supply/electric-rfo/wholesale-electric-power-procurement/midtermrfo-phaseone.page?WT.mc_id=Vanity_rfo-midtermrfo-phaseone.
[15] CPUC, Addendum to Energy Division Issue Paper and Draft Straw Proposal for Consideration in Track 3B.2 of Proceeding R.19-11-009, December 21, 2020, pp. 7-8.
[16] The 61% amount was for September 2024 RA requirements. The RA requirements for September 2024 were not provided in the CPUC’s document, so assuming the September 2024 RA requirements are equal to the September 2020 system RA requirements of the CPUC, 40,372 MW, then 61% of that requirement is 24,627 MW. See Table 1 “Final Load Forecast Used for Compliance” at: CPUC, 2020 Resource Adequacy Report, April 2022, p. 11.
[17] The procurement of 11,500 MW of resources for IRP requirements must utilize a minimum of ten-year terms. Decision (D.) 21-06-035, Decision Requiring Procurement to Address Mid-Term Reliability, June 24, 2021, p. 70 and Ordering Paragraph 9. Similarly, a previous IRP decision required any new RA resources built to meet a 3,300 MW procurement target must also have contract terms lasting at least ten years. D.19-11-016, Decision Requiring Electric System Reliability Procurement for 2021-2023, November 7, 2019, Ordering Paragraph 10.
[18] The means of price formation for the products is described by the CAISO using arithmetic but actual values are not estimated. See CAISO Day-Ahead Market Enhancements Appendix B Version 9.2, August 6, 2021, pp. 33-34.
[19] Proposal, p. 17.
[20] The CAISO pointed out technical challenges to estimating volumes of procurement of IR and RC in addition to the estimation of their prices. The CAISO did suggest using ancillary service prices or non-RA RUC bids as a reference but did not include any price estimates in the current proposal. DAME Third Revised Straw Proposal Workshop, April 29, 2022. See recording of discussion between the CPUC, PG&E, and CAISO from 12:05 to 18:50 and 27:30 to 31:25 at: https://www.youtube.com/watch?v=58CaKs8FI1g.
6.
Please provide your organization’s comments on the RUC Market Power Mitigations Pass.
Cal Advocates has no comment on this topic at this time.
7.
Please provide your organization’s comments on changes to the Residual Unit Commitment.
Please see Cal Advocates’ response to Question 5.
8.
Please provide your organization’s comments on Real-Time Market Ramp Deviation Settlement.
Cal Advocates has no comment on this topic at this time.
9.
Please provide your organization’s comments on Congestion Revenue Rights.
Cal Advocates has no comment on this topic at this time.
10.
Please provide your organization’s comments on Accounting for Energy Offer Cost in Upward Capacity Procurement.
Cal Advocates has no comment on this topic at this time.
11.
Please provide your organization’s comments on the Alignment between RA, DAME and EDAM.
Apart from our above comments concerning IR and RC bidding requirements, Cal Advocates has no additional comment on this topic at this time.
12.
Please provide your organization’s comments on the WEIM Governing Body Role.
Cal Advocates has no comment on this topic at this time.
13.
Please provide your organization’s comments on any other additional topics you would like addressed.
Cal Advocates has no additional comments at this time.
Middle River Power, LLC
Submitted 05/19/2022, 03:46 pm
1.
Please provide your organization’s overall position on the DAME revised straw proposal: a.) Support b.) Support with caveats c.) Oppose d.) Oppose with caveats e.) Neutral/No position/Need more information
Middle River Power LLC (“MRP”) supports the CAISO’s DAME Third Revised Straw Proposal (3RSP) with caveats, as noted below.
2.
Please provide your organization’s summary comments on the Day Ahead Market Enhancements 3rd Revised Straw Proposal and on the April 29, 2022 stakeholder call.
- MRP supports the proposed need for, and design of, the imbalance reserve and reliability capacity products.
- MRP does not support the proposal to apply local market power mitigation to the non-locational imbalance reserve and reliability capacity products.
- MRP does not understand the proposed decisional classification and the rationale behind that proposed classification.
3.
Please provide your organization’s comments on the need for day-ahead market enhancements.
MRP strongly agrees with the principle that acquiring the operational flexibility needed to address growing uncertainty through a fully biddable and deliverable market product would be far preferable to CAISO operators continuing to secure this necessary operating flexibility through opaquely biasing the Residual Unit Commitment (“RUC”) demand forecast.
4.
Please provide your organization’s comments on changes to the IFM Market Power Mitigation Pass.
MRP remains opposed to the CAISO’s proposal to apply local market power mitigation to imbalance reserve (capacity) offers.
The CAISO’s argument for not applying local market power mitigation is well-presented on 3RSP page 9: imbalance reserves are a fungible system product that need not be procured locationally. As MRP understands, the deployment scenarios are intended to ensure that energy from imbalance reserves can be successfully deployed without violating a network constraint, regardless of whether that constraint is competitive or non-competitive; the deployment scenarios are not intended to be used to acquire imbalance reserves to provide counterflow to either competitive or non-competitive constraints. Given that managing the flow on non-competitive network constraints remains a function of the nodal energy markets, not the proposed system-wide, non-locational imbalance reserve market, the CAISO’s insistence on applying local market power mitigation to a non-locational reserve product remains unjustified.
The examples the CAISO provided to seek to justify applying local market power mitigation (Appendix C) are unavailing. While the examples show an increase in cost due to the higher IRU bids from Generator G2, in the three-bus examples there are only two possible sources of IRU – Generator G1 and G2. In the CAISO’s market, there will be many potential sources of IRU, and the large pool of competition for IRU – a system-wide product - will make an individual generator’s attempt to exercise market power through its IRU bids ineffective. While MRP does not dispute that the three-bus example showed higher costs due to higher IRU bids, MRP is not yet convinced that the three-bus example conclusively demonstrates or justifies the need for local market power mitigation of a system product.
MRP notes that congestion conditions may differ between the Day-Ahead and Real-Time markets. This difference will exacerbate the application of local market power mitigation when no such mitigation is warranted. While this inefficiency is largely inescapable in the energy markets, adding market power mitigation to imbalance reserve and reliability capacity bids will exacerbate it unnecessarily.
The discussion during the May 13, 2022 Market Surveillance Committee meeting surfaced additional issues and questions about the IRU product, including the issue of CRR revenue insufficiency (from the proposed cost allocation) and the possible effects of not having a “default bid” to which to mitigate IRU bids. The CAISO has proposed to mitigate imbalance reserve bids to “…the marginal price of imbalance reserves minus the non-competitive congestion components in the upward deployment scenario at the location of the mitigated resource.” (3RSP at p. 28) Is it possible that the magnitude of the non-competitive congestion components could exceed the marginal price of imbalance reserves so that the mitigated nodal imbalance reserve price could be negative, or at least below the resource’s cost of providing imbalance reserves? If so, then the lack of a default bid is highly problematic.
5.
Please provide your organization’s comments on changes to the Integrated Forward Market.
Continuing to Procure Ancillary Services Regionally
The CAISO (3RSP at page 30) notes that it will continue to procure its current ancillary service products (regulation up and down, spinning reserve and non-spinning reserve) on a system and regional basis as opposed to a nodal basis. Given this, and further given the complications and challenges of developing the deployment scenario framework and the attendant challenges and concerns regarding local market power mitigation under such a framework, should the CAISO consider implementing the IR and RC products on a regional basis instead of a zonal basis?
Procurement of Imbalance Reserves
The CAISO (3RSP at page 31) indicates that it will implement the quantile regression used to set imbalance reserves targets “…such that percentiles used (2.5 and 97.5) are configurable so that the CAISO can make adjustments after gaining operational experience.” While MRP does not oppose allowing these targets to be configurable, MRP believes the CAISO should also adopt – by codifying in its tariff - a transparent, inclusive, and deliberative process for changing these imbalance reserve targets, should that become necessary. These targets, along with other affecting parameters (e.g.,the proposed stepped relaxation parameters) affect the provision of this service and should not be changed without engaging market participants or outside of the proper regulatory framework.
6.
Please provide your organization’s comments on the RUC Market Power Mitigations Pass.
Please see section 4 above.
7.
Please provide your organization’s comments on changes to the Residual Unit Commitment.
MRP appreciates the discussions on (1) RUC’s ability to transition Multi-Stage Generating Resources to a lower configuration, but not to fully de-commit the resource, and (2) the interaction between MSG resources and how they act as Supporting Resources for Price Taker (PT) export schedules (3RSP pages 39-40). MRP appreciates that the MSG resource will still be deemed to support a PT export schedule if it has submitted bids for at least the amount of the PT export schedule in the day-ahead IFM, even if RUC moves the MSG unit to a lower configuration. MRP also appreciates the CAISO clarifying that the supporting resource need not clear the IFM or RUC to support the PT export (3RSP at page 40).
8.
Please provide your organization’s comments on Real-Time Market Ramp Deviation Settlement.
MRP has no comment on this aspect of the 3RSP.
9.
Please provide your organization’s comments on Congestion Revenue Rights.
MRP notes that the 3RSP includes this discussion on Congestion Revenue Rights (CRRs) on page 47: “Whenever a constraint is binding in the deployment scenario and there is transmission reserved for deployed imbalance reserves on that constraint, there may be a shortfall in paying CRRs on that constraint because the CAISO will not collect congestion revenue on the imbalance reserve flow. This will result in the CRR not being paid its full amount because of existing rules that reduce congestion revenue right payments for a CRR on a particular path to not exceed the congestion revenue collected for that path. Generally, if the imbalance reserve bid prices are much lower than energy bid prices, the CAISO expects the constrained transmission to be mostly consumed [constrained?] by energy. Thus, the CAISO does not expect this to be a major issue.”
MRP notes that the CAISO’s lack of concern about imbalance reserves’ impact on CRR revenue sufficiency (because of an expectation that imbalance reserve prices will be much less than energy prices) does not seem to align with the CAISO’s concern about market participants exercising local market power in their imbalance reserve capacity bids.
10.
Please provide your organization’s comments on Accounting for Energy Offer Cost in Upward Capacity Procurement.
While MRP appreciates that the CAISO intends to apply a real-time energy bid cap to only the amount of the imbalance reserve award (3RSP at pages 48-49), MRP notes that the CAISO does not yet have a proposal for how to set the real-time energy bid cap. How the cap will be set is a critical detail that will inform MRP’s position on this issue, and MRP looks forward to the CAISO’s proposal.
11.
Please provide your organization’s comments on the Alignment between RA, DAME and EDAM.
MRP agrees with the CAISO that the relevant aspects of the RA Enhancements, Day-Ahead Market Enhancements and the Extended Day-Ahead Market initiatives must be coordinated and aligned. MRP looks forward to participating in all three of those initiatives as they move forward.
12.
Please provide your organization’s comments on the WEIM Governing Body Role.
MRP’s understanding is that the CAISO’s imbalance reserve product will be a foundational part of the EDAM structure. To that end, MRP is unsure why the CAISO is proposing that the EIM Governing Body would have joint authority only with regards to the settlement of the flexible ramping product (3RSP at page 53), and not, for example, joint authority over real-time bidding rules for imbalance reserves as those reserves would be acquired in balancing authority areas other than the CAISO’s.
13.
Please provide your organization’s comments on any other additional topics you would like addressed.
The 3RSP sets forth (on page 32): “The CAISO proposes to retain discretion to set the penalty price and procurement relaxation values in a flexible manner to allow reconsideration of appropriate values as more entities join the Extended Day-Ahead Market.” While MRP understands the CAISO’s desire for this discretion and flexibility with regards to these penalty prices and relaxation percentiles, these parameters affect the rates and conditions of providing this service, and, as such, MRP believes these parameters should be in the CAISO Tariff and not changed without a Section 205 filing or within the bounds of a limited and transparent change process as may be approved by FERC.
Six Cities
Submitted 05/19/2022, 05:39 pm
Submitted on behalf of
Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California
1.
Please provide your organization’s overall position on the DAME revised straw proposal: a.) Support b.) Support with caveats c.) Oppose d.) Oppose with caveats e.) Neutral/No position/Need more information
The Six Cities “oppose with caveats” the Third Revised Straw Proposal.
2.
Please provide your organization’s summary comments on the Day Ahead Market Enhancements 3rd Revised Straw Proposal and on the April 29, 2022 stakeholder call.
As noted above, the Six Cities oppose the Third Revised Proposal with caveats, because they do not believe that the perceived benefits from the CAISO's proposals outweigh the added costs in terms of complexity, financial risk to CAISO customers, and potential operational and reliability challeges. The Six Cities also remain concerned with the absence of alignment between this initiative and the Extended Day Ahead Market and Resource Adequacy Enhancements initiatives.
In addition to their generalized objections, the specific elements of the proposal to which the Six Cities object include:
- The proposal to remove the ability to self-schedule within the day-ahead timeframe from resources that are eligible to provide imbalance reserves.
- The proposal to eliminate the real time must-offer obligation for resource adequacy resources that do not receive awards in the integrated forward market or residual unit commitment process.
- The absence of robust protections to ensure that resource adequacy resources within the CAISO remain available to meet the needs of the CAISO.
For these reasons, the Six Cities do not support proceeding with implementation of most elements of the DAME initiative. If and when the Extended Day Ahead Market advances, the CAISO may revisit the DAME initiative for potential implementation at that time.
The Six Cities would not oppose modification of the residual unit commitment process to include procurement of downward flexibility as a standalone modification.
3.
Please provide your organization’s comments on the need for day-ahead market enhancements.
The Six Cities oppose finalization or adoption, at this time, of Day-Ahead Market Enhancements as recommended in the Third Revised Straw Proposal. From discussion at the April 29, 2022 web conference in the DAME initiative and at the May 13, 2022 Market Surveillance Committee web meeting, it is abundantly clear that the revisions to the Integrated Forward Market (“IFM”) and Residual Unit Commitment (“RUC”) processes contemplated in the Third Revised Straw Proposal are likely to give rise to increased complexity, increased costs to customers, and potentially increased operating challenges for resources as compared with the currently effective IFM and RUC designs. What is not at all clear, however, is that the proposed revisions will improve market performance on an overall basis. The anticipated benefits of the proposed DAME revisions at this point are completely theoretical, while complexities associated with new market features create risks of unanticipated consequences or dysfunctions. The Six Cities and other market participants repeatedly have urged the CAISO to undertake some type of simulation or other quantitative analysis to support a conclusion that benefits of the DAME revisions are likely to exceed associated costs. A CAISO representative indicated at the May 13th MSC web meeting that some form of cost/benefit analysis may be available during the coming summer. The Six Cities look forward to reviewing that analysis and will reevaluate the DAME proposal in light of that additional information.
Another concern that contributes to the Six Cities’ discomfort with the DAME proposal is the potential for misalignment among the DAME design revisions and market design changes to be developed in the Resource Adequacy (“RA”) Enhancements initiative and Extended Day-Ahead Market (“EDAM”) initiative. As one example, interactions among (i) the introduction of the Imbalance Reserve (“IR”) product and revisions to the RUC process through the DAME initiative and related day-ahead optimization revisions, (ii) the must-offer requirements applicable to RA resources, and (iii) application of the Resource Sufficiency Evaluation (“RSE”) tests in EDAM will impact the ability of the CAISO balancing authority area (“BAA”) to utilize and rely on RA resources procured and paid for by California load serving entities (“LSEs”). Another example involves potential interactions between IR procurement and the RSE. If, as suggested in the April 29th web conference, the outcome of the IR process could increase the risk of the CAISO BAA failing the RSE test, reliability of the CAISO BAA could be impaired, especially if the consequence of failing the RSE is reduction of transfers from external sources to zero. Although the RA Enhancements initiative, the EDAM initiative, and the DAME initiative all are in progress, there are numerous unresolved issues remaining in all of these initiatives. The Six Cities appreciate that the CAISO intends to align the elements of the final proposals in all three initiatives, but for now all three of the initiatives remain works in progress.
The Six Cities also agree with the comment by a representative from Pacific Gas and Electric Company during the April 29th web conference that there is a need for additional clarity on how storage resources would participate in the revised day-ahead market and how the DAME revisions would compare with the existing Non-Generating Resource (“NGR”) model for storage.[1] The CAISO has recognized that a great number of additional storage resources are expected to become operational in the next several years, and that the increased volume of storage capacity will bring both opportunities in terms of increasing flexibility and operating challenges in terms of managing State of Charge. It is unclear whether the elements of the Third Revised Straw Proposal would provide appropriate support for the development and integration of increasing numbers of storage resources.
In sum, while the current IFM and RUC designs are not necessarily perfect, the imperfections at this point are reasonably well understood, and the CAISO has developed solutions to address them. The Six Cities see no compelling reason to finalize DAME revisions at this time and many risks and unresolved questions that militate against doing so. Based on the current scope of the day-ahead market, the Six Cities are not persuaded that it makes sense to move forward with market design revisions that may increase costs to consumers, will substantially increase complexity, and may reduce reliability of the CAISO BAA. The CAISO should suspend further development of most elements of the Third Revised Straw Proposal unless and until there is a comprehensive EDAM design that appears to have a critical mass of support from CAISO stakeholders and EIM entities such that it is reasonable to reconsider DAME revisions necessary to support implementation of the EDAM.
[1] Similar questions exist for the proposed Energy Storage Resource participation model.
4.
Please provide your organization’s comments on changes to the IFM Market Power Mitigation Pass.
See generally the Six Cities’ response to Item 3 above.
Based on the discussion at the May 13th MSC web meeting, the challenge of developing an appropriate methodology for mitigating potential exercise of market power in bids for IR is one of the complexities that contributes to the Six Cities’ concerns with the proposed DAME revisions. The initial examples presented by the CAISO at the MSC meeting indicated that applying mitigation to the energy component of bids for IR would not fully eliminate ability to exercise market power with respect to the capacity component. Both CAISO representatives and MSC members highlighted that lack of information regarding resources’ costs for providing IR capacity creates risks of undercompensating or overcompensating for IR through a mitigated price. Of course, RA resources already will have been compensated for committing to make their capacity available to the market, suggesting the potential that RA resources may be overcompensated for IR capacity at any price above $0. The Six Cities conclude that mitigation of the potential exercise of market power for the capacity component of IR bids is necessary but take no position on specific elements of a mitigation approach until a proposed methodology has been fully developed, explained, and supported.
5.
Please provide your organization’s comments on changes to the Integrated Forward Market.
See generally the Six Cities’ response to Item 3 above.
With respect to specific elements of the Third Revised Straw Proposal, the Six Cities strongly oppose the CAISO’s proposal to remove the ability to self-schedule within the day-ahead timeframe from resources that are eligible to provide IR. It appears that the CAISO’s proposal would impose an economic bidding requirement on all resources the CAISO considers capable of providing IR, which would constitute a dramatic expansion of market participation obligations beyond the pool of flexible RA resources that have contracted to take on and are compensated for an economic bidding obligation. As the Six Cities understand the proposal, it effectively would eliminate any differences in availability requirements between flexible RA resources and both system RA resources and non-RA resources that are capable of providing IR. Since the inception of CAISO participation requirements, self-scheduling has been recognized as a permissible method of participating in the market, other than for resources that voluntarily have committed to supply flexibility. The CAISO has not justified its proposal to override operating preferences of resource owners.
In addition to the general concerns with removing flexibility from resource owners as between economic bidding or self-scheduling, certain of the Six Cities face distribution system-related conditions that require internal units to operate. Such conditions may be weather-related, such as during high temperatures, where a City’s load exceeds its import capability to its distribution system, and its units must produce energy in order to avoid load shed within the City, or they may be related to internal maintenance or other operational reasons. At a minimum, revocation of self-scheduling for IR eligible resources would require development of exemptions that would accommodate the Six Cities’ self-scheduling needs for reliability or other appropriate operating reasons.
6.
Please provide your organization’s comments on the RUC Market Power Mitigations Pass.
See generally the Six Cities’ response to Item 3 above.
If the CAISO determines to move forward with the DAME elements set forth in the Third Revised Straw Proposal, the Six Cities agree that it is necessary to include a market power mitigation pass in a revised RUC process if the optimization for RUC/Reliability Capacity (“RC”) takes transmission limitations into account, especially if all resources, including RA resources, are permitted to submit non-zero bids to supply RC.
7.
Please provide your organization’s comments on changes to the Residual Unit Commitment.
Although the Six Cities oppose most elements of the RUC revisions set forth in the Third Revised Straw Proposal for the reasons discussed in their response to Item 3 above, the Cities would not oppose modification of the RUC process to include procurement of downward flexibility. Expanding the current RUC process to include procurement of downward dispatch capability to assist the CAISO in addressing over-generation conditions would appear to involve only modest revisions to the existing RUC design, seems unlikely to result in substantially increased costs to customers, and may assist in the effective integration of storage resources.
8.
Please provide your organization’s comments on Real-Time Market Ramp Deviation Settlement.
This element of the CAISO’s proposal is highly complex. The Six Cities have not, at this time, identified significant concerns, but are not prepared to express support or opposition and continue to evaluate the approach outlined in the Third Revised Straw Proposal.
9.
Please provide your organization’s comments on Congestion Revenue Rights.
The Six Cities agree with the concern that the CAISO has identified regarding the potential for underfunding of congestion revenue rights (“CRRs”) in connection with the proposed implementation of the IR product. The Six Cities understand that the CAISO has concluded the likelihood of such underfunding may be low and that it does not “expect this to be a major issue.” (See Straw Proposal at 47.) The Six Cities are not aware of any analysis supporting this expectation and observe that the impacts of introducing the IR product in the CAISO’s day-ahead market on other elements of the CAISO’s markets are largely unknown at this time. The CAISO should endeavor to continue evaluating the risks to CRR funding that may result from introduction of the IR product so those risks can be considered and addressed as a part of this initiative. Because the scope and risks to CRRs resulting from adoption of the IR product do not appear to be well-understood at this time, it seems premature to select any particular options to address this potential underfunding.
10.
Please provide your organization’s comments on Accounting for Energy Offer Cost in Upward Capacity Procurement.
The Six Cities support the CAISO’s continuing consideration of this issue and urge adoption of measures to ensure that the incremental cost of the IR and RC products within the CAISO BA are minimized to the extent possible. The CAISO does not provide a comprehensive proposal, but instead seeks stakeholder feedback on the concept of a real time energy bid price cap for resources that receive IR up or RC up awards. The Six Cities are not prepared to comment on the CAISO’s conceptual proposal at this time, but will continue to evaluate this issue when more details are available.
11.
Please provide your organization’s comments on the Alignment between RA, DAME and EDAM.
As outlined in their response to Item 3 above, the Six Cities continue to have significant concerns regarding the DAME proposal and the extent to which it is perceived by the CAISO as a necessary prerequisite to the EDAM. The Six Cities have previously stated their position that the proposals in the DAME initiative should provide beneficial improvements to the CAISO markets irrespective of whether EDAM moves forward. However, it is still far from apparent that the potential reliability risks and the costs and complexities of the DAME proposal are worthwhile, especially in the absence of EDAM. As discussed elsewhere, the Six Cities support tabling consideration of the DAME proposals until it is clear that the EDAM will move forward with the support of CAISO stakeholders and EIM entities, and only then considering the elements of DAME that are needed for the EDAM.
12.
Please provide your organization’s comments on the WEIM Governing Body Role.
The Six Cities have not identified concerns with the CAISO’s initial determinations of the issues that would be subject to joint versus advisory authority.
13.
Please provide your organization’s comments on any other additional topics you would like addressed.
The Six Cities remain concerned with ensuring the availability of CAISO RA resources to meet the reliability needs of the CAISO BAA. First, the Six Cities do not support the elimination of the real time must-offer obligation for RA resources that do not receive awards in the IFM or RUC processes. This may lead to a reduction in the reliability of CAISO BAA, as RA resources may elect not to participate in subsequent market processes. There continues to be no clear rationale for this element of the CAISO’s Straw Proposal. The option of permitting individual local regulatory authorities (“LRAs”) to continue to require participation through real time may be superficially appealing, but the inability for individual LRAs or their LSEs to monitor, much less enforce, compliance by RA resources of their contractual commitments within the timeframes of the CAISO markets renders this proposal largely meaningless.
As the Six Cities have explained in their prior comments in this initiative, RA resources procured and paid for by CAISO LSEs to meet their RA obligations—whether local, system, or flexible—must be available to meet the needs of the CAISO BAA, particularly during tight system conditions. At the same time, CAISO LSEs should not be exposed to increased costs by enabling RA resources that are already being paid for adhering to the CAISO’s existing bidding and offer rules to obtain supplemental revenues by bidding for IR products at non-zero rates. The Six Cities continue to urge the CAISO to work with California LSEs to resolve these risks and assure that RA capacity procured for the use of the CAISO footprint remains available to meet CAISO needs.
Western Power Trading Forum
Submitted 05/19/2022, 08:51 pm
1.
Please provide your organization’s overall position on the DAME revised straw proposal: a.) Support b.) Support with caveats c.) Oppose d.) Oppose with caveats e.) Neutral/No position/Need more information
Oppose with caveats. WPTF would like to clarify that our current position is opposed with caveats because the next version is intended to be the draft final proposal. The policy as currently described is too far from a workable market design in terms of price formation and reliability. More work needs to be done before moving to a draft final version. WPTF would support the policy if the design was significantly simplified as discussed throughout our detailed comments. The complexity of the current policy is not justified and introduces too many significant adverse impacts; whereas a more simplified design can strike the appropriate balance between market design complexity and benefits achieved.
2.
Please provide your organization’s summary comments on the Day Ahead Market Enhancements 3rd Revised Straw Proposal and on the April 29, 2022 stakeholder call.
WPTF appreciates the opportunity to comment on the CAISO’s Day-ahead Market Enhancements Third Revised Straw Proposal. This stakeholder effort has been ongoing for several years now and is the joint effort of CAISO staff and the entire stakeholder community. Over this time period, the CAISO resource mix and system conditions have changed in significant ways. Thus, at this juncture, we believe that some aspects of the proposal are responsive to underlying drivers that have changed since this initiative was first conceptualized. Also in light of EDAM, we believe the CAISO must consider two possible futures - one with and one without EDAM - and that there are fundamental design differences based on whether EDAM moves forward.
In summary, our comments reflect the following positions:
- WPTF supports moving out of market actions into a competitive day-ahead product that improves price formation and results in an overall benefit to ratepayers but believes additional justification around the benefits that will be provided is warranted.
- WPTF believes the benefits of this proposal needs to be justified first assuming a non-EDAM paradigm; its concerning if we move forward with a significant market change that hinges on the benefits materializing only if EDAM is implemented.
- WPTF is concerned that the theoretical benefits of the upward imbalance product, which hinges on moving out of market actions (e.g., RUC biasing) into the day-ahead market, may not be realized based on the data provided. Thus, we would like to see additional data analysis to better evaluate the likelihood of reduced RUC biasing and, upon implementation, the use of RUC biasing be limited for declared emergencies.
- WPTF questions the need for the downward products (IRD and RUC Down) given the changes in resource mix and bidding behaviors since the onset of this initiative as well as explicitly linking the RCD product to Net Load.
- WPTF is extremely concerned that the four mitigation elements included in this proposal are overly complex and run the risk of introducing significant adverse market impacts, which need to be seriously considered. The concerns with market power can be addressed by simply (1) retaining the RT MOO, (2) imposing an appropriate IRU/RCU bid cap, (3) procuring regionally rather than nodally, and (4) implementing the graduated demand curve.
- WPTF is concerned that the proposal could be identifying more constraints as uncompetitive if the IRU and IRD offers are not both included in the Residual Supply Index calculation for amount of residual supply. Since both IRU and IRD create flows on the transmission lines, they can be operationalized by the market to provide counterflow and should be included in the residual supply calculation. If not, there is a risk of inaccurately identifying constraints as uncompetitive, where that counterflow is available.
- WPTF questions if procuring IRU/IRD nodally in the day-ahead time frame is the most effective way to ensure its accessible and deliverable in real-time. Congestion patterns change from day-ahead to real-time, thus what may be accessible in day-ahead is not necessarily accessible in real-time. Procuring IRU/IRD regionally in a similar manner to ancillary services will further simplify this proposal and address several of the concerns requiring overly complex features of this proposal.
- WPTF would like more explanation on the 15-minute ramping eligibility to better understand how that aligns with (1) the hourly awards, (2) formulation of the requirement, and (3) ramping capacity constraints on the resource. We also believe additional discussion is warranted regarding whether or not the 15-minute eligibility should be a configurable parameter rather than in the Tariff.
3.
Please provide your organization’s comments on the need for day-ahead market enhancements.
WPTF has long supported the CAISO moving forward with a day-ahead flexibility product to replace the portion of RUC procurement that is due to operator bias for uncertainty and enable decommitments in RUC. At the time this was first proposed, it was in an ISO-only day-ahead construct; LSEs would hedge the majority, but not all of their load costs in a financial day-ahead market and RUC would ensure sufficient long-start resources were committed. For a variety of reasons beginning in 2017/2018 there was a significant change in the day-ahead price relative to the real-time price, and the average prices flipped. Perhaps given the changing resource fleet this was inevitable. Historically you could be more confident in your supply in advance (e.g., gas plants had more time to secure fuel, etc.) but now renewables are less sure of the firmness of their supply the further in advance of dispatch, so much so that a significant portion of wind resources chose not to even offer into day-ahead. Inevitable or not, the absence of this low-cost energy and general renewable variability impacted the day-ahead/real-time price ratio in two ways. First, the lack of wind directly impacted the day-ahead energy price because it was not a low-cost-option for load to secure. Second, the general uncertainty around renewables increased operator out of market actions. Operators began to bias load and commit long-start resources in RUC that were typically uneconomic in real-time. Because they are uneconomic, their pmin energy is included in the real-time supply stack, but their incremental energy offer is not and thus the commitments lower the real-time price.
This was concerning to WPTF from a price formation perspective and thus, it appeared rational to move the operator bias into a formalized market product. At the time we assumed it would be a regional product somewhat similar to AS, have a price cap similar to AS, and be incredibly competitive because all flexible RA resources already have an economic must-offer obligation; it seemed the incremental cost to provide the product would be low or close to $0. The benefit presumably would be more efficient commitment, and by efficient we mean either additional long-starts in day-ahead committed to Pmin or efficient commitment of imports and other resources such that a more economic solution was achieved. If operator bias was moved into a competitive product, while the total costs could end up being the same to load (reduced LMP plus additional IR costs), the price formation of the entire market would be improved. And theoretically anyway, the costs to load should also decrease because the benefit of a lower DA LMP has significantly more impact than any other market by large magnitudes. For example, if you assume only 90% of load is procured in the day-ahead market, at a 30,000 ultimate CAISO forecast, this means 27,000 MWh are cleared at the day-ahead price and 3,000 MWh at the real-time price. A $.25/MWh decrease in LMP in the day-ahead market and $.25/MWh increase in LMP in the real-time market is $6,750 in day-ahead savings and an increase in real-time market cost of only $750, for a clear gain of $6,000 to ratepayers.
We are now questioning whether this basic rational for the Imbalance product exists under EDAM and the CAISO’s specific imbalance reserve formulation. It is hard for WPTF to see a need for a downward day-ahead product in a high renewable, high storage grid. It seems like if the CAISO is concerned by the lack of downward flexibility, simply obligating wind to offer into the day-ahead market and allowing RUC decommitment will resolve the issues. As we discuss below, wind resources MAPE has significantly decreased over the last few years and there seems no harm to requiring they offer in at least a portion of their supply – perhaps 90% of their RA offered. RUC decommitment likewise seems like an easy feature to add to the existing RUC process and wouldn’t require an explicit RUC downward requirement. Simply if physical supply cleared above the CAISO forecast of CAISO demand then a resource could be decommited.
Second, according to data provided, it seems like most resources (aside from a fixed set of imports) do economically offer into the real-time market and can be curtailed in real-time, so it’s hard to understand the rational for a downward product during solar hours. The product will not have any impact on import self-scheduling and already thermal is off or backed down as low as possible. It is really unclear what the downward product gains in terms of reliability or efficiency. The product does not prevent self-scheduling, merely pays resources for economic offers that are in the real-time market anyway.
Third, while the upward products still seem theoretically beneficial, the formulation using net load, multiple layers of mitigation, and radically changing the RA rules all add complexities that potentially strip the product of much of its benefits. We discuss these in detail throughout our comments.
Finally, the theoretical benefits entirely hinge on operators stopping their RUC load bias and that this bias is actually needed. It is unclear whether these two things are possible or true. WPTF asks the CAISO to show whether operator bias that is being proposed to move into a day-ahead product is actually needed. Based on data presented in the MPPF it looks like load forecast error and VER forecast error is trending downward and economic offers and ramping capability in real-time are trending upward. Therefore, why exactly are operators concerned about ramping and uncertainty in real-time? This is important because if operators keep biasing even after the new products are implemented, then there will be reduced rather than improved day-ahead efficiency. WPTF appreciates the CAISO providing data on the historical net load imbalance and historic RUC adjustments but is confused by the conclusions drawn from the data and by the data itself. The historical net load imbalance and RUC adjustments do not seem possible given data presented in the MPPF and available on Oasis. We ask that the CAISO double check or perhaps better describe what is being presented.
4.
Please provide your organization’s comments on changes to the IFM Market Power Mitigation Pass.
WPTF is strongly opposed to the CAISO’s proposal to mitigate imbalance reserves in the IFM with the local market power mitigation (LMPM) framework. The proposal as currently described, includes several flawed elements that introduce adverse market impacts, increasing the risk and cost of implementing a market power mitigation mechanism for imbalance reserves. To be clear, WPTF supports competitive markets and believes in market power mitigation when the ability to exercise market power actually exists in a market. Not mitigating for market power runs the risk of Type II errors in a market. Specifically Type II errors occur when market power is not detected and thus left unmitigated. Obviously, this has the impact of resulting in energy prices that reflect market power, which is detrimental to a competitive wholesale energy market. On the other hand, mitigating for market power when the conditions do not exist also comes with its own costs and risks that need to be considered. Specifically, this results in Type I errors – or mitigating offers to prices that no longer reflect the willingness to supply when the ability to exert market power does not exist. This in turn deters participants from forward contracting, voluntary import supply offers, and dilutes the appropriate price signals, all of which provide benefits to a competitive market. Thus, it’s imperative that the costs/benefits of both Type I and Type II errors be considered and weighed against one another before moving forward with any market power mitigation mechanism.
The risk/cost of both error types hinges on (1) whether or not there is the ability to exert market power, (2) accuracy of the mitigation mechanism being implemented in terms of identifying resources that meet the conditions to exert market power, and (3) determining a mitigated offer price that reflects the competitive willingness to supply the product. First, WPTF believes the conditions to exert market power through IRU bids does not exist given that the market already mitigates energy offers via Local Market Power Mitigation (LMPM) and will now mitigate energy offers based on deployment scenarios. For a resource to exert market power, the conditions have to be predictable, persistent, and profitable. Even the CAISO has acknowledged those criteria do not hold true in this case. Second, the CAISO’s current LMPM design is not formulated to fully capture the supply and demand for counter-flow during the deployment scenarios; it runs the risk of underestimating the amount of available counter-flow thus resulting in more Type I errors (i.e., over mitigation). Lastly, the CAISO has noted that its challenging to come up with a way to estimate a competitive offer price for the products (e.g., akin to a Default Energy Bid for the products), thus has resorted to simply relying on a nodal price generated by the market absent congestion costs from uncompetitive constraints. Relying on the competitive price for mitigation purposes results in the mitigated offers not even reflecting the opportunity cost of not providing energy in the day-ahead market or the risk of not being scheduled in real-time. In any market power mitigation design, it’s imperative that the mitigated price at least covers the cost of the resource, including opportunity costs. The current proposal fails in this regard, introducing the risk of prices not providing accurate market signals and weakening price formation.
WPTF would like to take this opportunity to highlight that during the March 2, 2022 stakeholder call, the CAISO very clearly articulated several reasons for no longer proposing IRU mitigation; these reasons are reiterated in this proposal on page 9. We agreed with the CAISO’s position articulated on March 2, 2022 and are baffled as to why the sudden change in mind given that none of the prior justifications have changed in any way. And furthermore, those justifications are further supported by the CAISO’s own mitigation examples presented in Appendix C.
Specifically, the CAISO notes on pg. 9 of the proposal that there are two reasons why the CAISO, in March 2022, was no longer proposing to mitigate IRU bids. First, by mitigating energy offers, the opportunity cost portion of the IRU price will also be mitigated, effectively addressing any potential to exercise market power in IRU prices. Additionally, because the market is able to make a trade off decision between energy and IRU, the market can simply opt to procure energy rather than IRU from a resource that tries to exert market power through high IRU offers. The CAISO even goes on to acknowledge that “a resource may find it challenging to profitably withhold imbalance reserve capacity” but justifies the sudden change in direction to mitigate IRU because it may result in “a less economic solution through higher-cost energy dispatch”. However, WPTF would like to point out that in the event the market procures higher-cost energy from a resource instead of its IRU capacity at an unmitigated capacity price, the energy procured would be at a mitigated offer price since its still subject to mitigation. Thus, the “higher-cost energy” is still only reflecting the mitigated marginal cost of that resource to provide energy.
The CAISO did provide some examples to illustrate the impact of (1) no mitigation, (2) mitigating only energy offers, and (3) mitigating energy and IRU offers. A few interesting observations can be made that further support the CAISO’s direction in March of not mitigating IRU offers. First, the mitigation examples provided by the CAISO shows that the cost of IRU allocated to load is highest when both energy and IRU bids are mitigated; mitigating the energy bids alone resulted in the lowest cost of IRU allocated to load. Second, the examples highlight that when energy offers are mitigated, the market will instead schedule a resource for energy and procure the IRU from another location at a lower price.
It seems as though the CAISO believes the need for mitigating IRU bids comes from the fact that the market will be procuring the products nodally to ensure deliverability. WPTF sees the benefit of nodal procurement from the perspective that its appropriately testing and ensuring the energy is actually deliverable to where its needed in real-time. However, we question if the most effective way of doing that assessment is in the day-ahead market. Conditions and congestion patterns change from day-ahead to real-time; what may be deliverable in day-ahead can easily become not deliverable in real-time. It would be useful to evaluate or analyze changes in congestion patterns that would defeat the purpose of nodal procurement of IRU/IRD in day-ahead. It could be the case that the benefit of day-ahead nodal procurement is not significant; as such, by procuring regionally (similar to A/S) the driver for why the CAISO believes there is a need to implement a complex market power mitigation mechanism is no longer. This then allows the CAISO to significantly simplify the market design and implementation of IRU/IRD.
Again, this all goes back to weighing the cost and benefits of implementing market power mitigation. One needs to not only weigh the pros and cons of Type I and Type II errors but also the complexity of the solution to the size of the concern. It could easily be the case that there is a less complex solution to address the potential issue of market power mitigation in IRU. The CAISO’s discussion to date and examples highlights that there is minimal ability for participants to exert market power through IRU bids – it’s not predictable, persistent, or profitable. Thus, the risk of applying mitigation and introducing Type I errors into the market far outweigh the risks type II errors occurring with IRU. The market already has in place several mitigation measures to address the potential of Type II errors occurring.
In addition, WPTF offers below several additional reasons why mitigating IRU is unwarranted and introduces adverse market impacts.
- IRU is a system wide product that’s being procured nodally, not a product being procured in a local area that should be assessed for local market power mitigation. The IRU requirement is a system wide requirement meaning that the market will procure the minimum amount of IRU and can do so from resources anywhere across the system. WPTF understands, the desire to ensure its deliverable based on transmission congestion, which introduces the nodal/deliverable element of this product. Simply ensuring that wherever the product is procured is deliverable is different than having to dispatch the energy from certain resources in a locally constrained area to manage congestion; the market can simply go procure the product from another resource on the system that’s also deliverable. This is in contrast to mitigating energy offers from resources within a locally constrained area. In this case, the market has to procure energy from resource in that area to manage congestion on the system. The latter has the ability to exercise market power whereas the former does not.
- Mitigating IRU when there is also a graduating demand curve for IRU introduces significant complexity that is unwarranted. It is WPTF’s understanding that the imbalance reserve graduated demand curve will start relaxing the IRU/IRD requirement as prices increase above $247/MW. Thus, once prices start reaching $247/MW, no one has the ability to impact IRU prices; the market will simply stop procuring additional capacity and set the prices based on the graduated demand curve prices, not IRU offer prices. It then follows that the IRU mitigation will only be effective in mitigating market power that is exercised at a price less than $247/MW, which goes back to the profitability point. If the maximum price a participant could possibly influence by exerting market power is $247/MW, then its not a profitable practice. Thus, with the graduated demand curve in place, another MPM IRU mechanism is not needed and simply adds unwarranted complexity to the market.
- Mitigating IRU offers to a “competitive LMP” removes the ability for resources to manage the risk of being exposed to the real-time energy bid cap and reflect costs of providing that product. In another section of the proposal, the CAISO describes the need for a real-time energy bid cap to be imposed on resources awarded IRU. The CAISO goes on to note that for the policy to achieve the intended outcome of being able to distinguish between lower and higher cost resources when awarding IRU, the higher cost resources will simply reflect the risk of being exposed to a bid cap that is lower than their costs in the IRU offers. However, if a higher cost resource reflects that risk in the IRU offer, but the IRU offer is then mitigated to a “competitive LMP” that no longer reflects that risk, then the CAISO’s own mitigation proposal unwinds its solution for another element of this proposal. The market design cannot rely on resources reflecting risk in the IRU offer price but then have the cost of that risk removed from the offer by the same market design. Additionally, the concern of only having “high priced energy” in real-time from resources awarded IRU becomes less of a concern if the CAISO retains the RT MOO. The RT MOO will ensure there is sufficient energy offered into the real-time market, thus driving down the offers to more competitive levels.
- The CAISO’s justification for needing to consider a local market power mitigation design for IRU/IRD procurement is based on a flawed deliverability assumption. A key element of the CAISO’s proposal is nodal procurement of IRU/IRD. While WPTF understands the desire to ensure that the energy, if needed from IRU/IRD procured capacity, is deliverable to where it’s needed, we are concerned that there is a major flaw to the CAISO’s approach. Nodal procurement in day-ahead does not equate to the energy from that capacity being deliverable in real-time. Congestion patterns change between the two markets; what may be deliverable in the day-ahead can easily become stranded behind a constraint in real-time. Thus, the nodal procurement is (1) not a realistic way to ensure the energy would be available in real-time, (2) unnecessarily creates the CAISO’s need to consider local market power mitigation, (3) increases complexity in the market from both an implementation and price formation perspective, and (4) creates the potential for CRR shortfalls. Rather, WPTF believes that regional procurement in the day-ahead coupled with an IRU/IRD bid cap strikes the appropriate balance between design/implementation complexity and size of the issue.
WPTF also requests that the CAISO hold another workshop to discuss the mitigation process in more detail. While we appreciate the examples provided in Appendix C, there is no supporting document that allows stakeholders to follow the examples or discuss the takeaways and observations. Additionally, none of the documentation to date provides any transparency into the formulation of the competitive path assessment and if/how it will be adjusted to account for the new products. Below is a list of elements for which WPTF believes warrants further discussion and clarification by the CAISO via the workshop such that stakeholders can provide more meaningful feedback.
- In the IFM MPM run today, the market clears bid in load against bid in supply using unmitigated supply offers. Its our understanding that the MPM IRU run will use the same inputs but also model realized upward and downward uncertainty distributed across the system at certain load and VER locations. Given that the objective function is still to clear bid in load against bid in supply, what price (if any) will the uncertainty levels be modeled at in the market?
- Will the dynamic competitive path assessment be modified to account for the counter-flow that can be provided from the new imbalance products? Today, the DCPA only considers the counterflow that can be provided from energy offers. However, with the new products, counterflow on a constraint can now be provided from additional IRU as well as IRD that is from resources on the other side of the constraint. This information has yet to be discussed anywhere in the stakeholder process and WPTF believes some changes to the DCPA formulation are warranted.
In summary, WPTF believes the CAISO’s current mitigation proposal is overly complex and runs a significant risk of resulting in Type I errors as well as unintended market impacts from implementing an extremely complex design intended to address an issue that has a much simpler solution. There is a less complex approach that addresses the concerns of market power mitigation without introducing these risks that WPTF believes is a more optimal design. Taking a similar approach to how the CAISO procures Ancillary Services and applies a bid cap to protect against market power is a more desirable design for the new products. Specifically, the CAISO could (1) procure IRU/IRD regionally, (2) apply an IRU/IRD bid cap, (3) retain the RT MOO to ensure sufficient competitive energy is available in real-time, and (4) no longer need the real-time energy bid cap. WPTF does not believe that under regional procurement, the deployment scenarios are still needed. This in turn further simplifies the CAISO’s market design not only from an implementation perspective but also price formation perspective while also making it more transparent for market participants to engage with the CAISO market. WPTF would also like to note that under a regional procurement design, the CRR issue that arises with nodal procurement is no longer an issue. These four changes to the current proposal will result in a simple streamlined market design that addresses the potential issue of market power via IRU offers; additionally, it will allow for a more transparent way for market participants to interact with the market. Any time an overly complex policy is implemented, it makes it more challenging for participants to fully understand how to interact with the market, which creates its own set of risks and costs.
5.
Please provide your organization’s comments on changes to the Integrated Forward Market.
Please see response to #3.
WPTF would also like additional explanation with regards to the alignment between the 15-minute ramping capability vs hourly granularity of the IRU/IRD awards. We understand that a resource will only be awarded IRU/IRD up to its 15-minute ramping capability, and that the justification for this is due to the granularity difference between the day-ahead and 15-minute market. First, we would like to better understand if the IRU/IRD requirement for a given hour is set at the maximum 15-minute uncertainty level of all 15-minute intervals within the hour or is it the summation of the four 15-minute uncertainty levels within the hour. Could it be the case that if all the uncertainty is realized in the first 30mins of a trading hour in real-time that there is no remaining ramping capability for the latter half of the hour?
WPTF would also like to understand the capacity vs ramping capability constraints included in Appendix B. On page 22 of the appendix, the CAISO includes a constraint that ensure there is enough capacity above an energy schedule for all upward ancillary service products and IRU. However, on 23 of Appendix B the CAISO appears to also be limiting the resource to ensure it has enough ramping capability but for four times the amount of awarded IRU. It is unclear to WPTF is through these constraints the CAISO is holding back enough ramping capability for an hour but only awarding and compensating the resource for 15-minute capability.
6.
Please provide your organization’s comments on the RUC Market Power Mitigations Pass.
As described throughout these comments and in response to question #2 and #4, WPTF is opposed to market power mitigation when the ability to exert market power does not exist. Having a mitigation mechanism in place simply as a “fail safe” that can result in Type I errors undermines a wholesale competitive market and introduces adverse impacts. The cost of the adverse impacts need to be seriously considered and weighed against the potential benefit of having such a mechanism in place when the ability to exercise market power is nonexistent. Our more specific concerns with the RUC MPM pass are detailed below.
The CAISO’s proposed RUC MPM process will result in over mitigation triggered by tight supply conditions (not the ability to exert market power) and suppress market prices. The CAISO and stakeholders have all acknowledged through the discussions around system market power mitigation that its inappropriate to mitigate resource offers simply because the market is facing tight supply conditions. Prices should be able to reflect tight supply conditions and mitigating in such conditions that result in suppressed prices is detrimental to price formation and the overall efficiency of the market. However, the CAISO is proposing a mitigation approach that will do just that. The methodology being proposed by the CAISO for use in the RUC MPM run inherently has the flaw of identifying a path as uncompetitive due to tight supply conditions. This is a known flaw of the DCPA/LMPM approach being proposed. Furthermore, due to the sequential nature of IFM and RUC, and the fact that RUC “sees” all IFM energy schedules, A/S awards, and IRU/IRD awards as fixed, WPTF is concerned that the RUC MPM process will be extremely susceptible to this significant flaw.
By the time the RUC MPM process runs, the IFM market has already set aside capacity from resources for energy, A/S, and now IRU/IRD. Given that the capacity will be protected in RUC, WPTF is concerned it cannot be used to dispatch and help manage RUC congestion. The only capacity still available in the RUC process to manage congestion would be the remaining capacity, not the total amount of RUC/RCD capacity that was initially offered into the market. For example, a 100 MW resource offers in 100 MWh for energy, 100 MWs RCU, 50 MWs IRU, 25 MWs Reg up, and 20 MWs spin. The IFM awards it a 50 MWh energy schedule, 25 MWs reg up, and 15 MWs IRU. This leaves the resource with only 10 MWs of remaining capacity. WPTF is concerned that the RUC MPM process will only see the 10 MWs of RCU supply available even though the resource originally offered in 100 MWs. This is not due to the resource trying to exert market power or withhold capacity, but rather because the IFM market is run prior to RUC, leaving significantly less supply available in RUC compared to what was originally offered. This creates a condition of having tight supply in the RUC process, not a condition that allows market power to be exerted, and thus should not have mitigation applied.
If a resource is awarded RCU/RCD in RUC MPM pass and adds any flows to a constraint already binding, RUC will have to procure another MW of capacity to provide counterflow. Now that constraint will have to be tested for competitiveness in a market with inherently less supply than was originally offered in at the onset of the day-ahead market (i.e., prior to IFM). Thus, the pivotal supplier test may find insufficient supply to meet counterflow, but not because there wasn’t enough capacity offered in initially, but because the IFM first awards energy, A/S, and IRU/IRD and removed that capacity from being available. This in turn leads to the CAISO mitigating due to tight supply conditions created by the CAISO’s own market processes, not from resources trying to exert market power.
It should also be noted that the occurrence of congestion (and thus the probability of testing constraints in the RUC MPM pass) is unlikely to be minimal. Given that the RUC MPM pass sees the IFM schedules and awards as fixed, it then follows that any constraint binding in the IFM run will also be binding in RUC. Thus, even a 1 MW RCU award that adds any amount of flow on a constraint that was binding in the IFM will automatically be tested for competitiveness in the RUC MPM process. Additionally, WPTF would like the CAISO to confirm that in the RUC MPM pass, it is proposing to only test constraints where there is incremental flows in the prevailing direction. In other words, the CAISO will not be testing constraints that are binding in RUC simply due to the IFM schedules and awards.
The application of a local market power mitigation test for the system wide product is fundamentally flawed. Similar to IRU mitigation, WPTF is concerned with the CAISO’s proposal to mitigate a product that is a system wide product simply because it is doing a check to ensure the capacity can be deliverable if dispatched in real-time. We understand that in the RUC MPM process, the market software will convert the capacity offers to energy flows on constraints. And while it may seem easy to justify mitigation because the bids are converted into energy and create flows and counterflows on constraints, we need to keep in mind that the market can simply go and procure that capacity from a resource somewhere else on the system. Having the requirement set at a system wide level inherently introduces a natural form of local market power mitigation – having a larger pool of supply from which the market can award the capacity.
Additional details are needed to better assess the application of the Dynamic Competitive Path Assessment (DCPA) formulation in RUC. WPTF is concerned that the DCPA in RUC will not capture all the available supply of counterflow and thus over-mitigate resources. WPTF understands that the CAISO is planning to leverage the current Dynamic Competitive Path Assessment (DCPA) formulation and apply it to the RUC process in the RUC MPM pass. However, there is little information provided on the formula’s application in RUC with the two new products. For example, we would like to better understand what will be considered counterflow supply. Today, this is done by summing up the counterflow that can be provided from resources where an additional MW of dispatch will result in flows on the binding transmission constraint that go against the prevailing flow.
Absent any additional details, WPTF is concerned that the current formulation will inherently underestimate the available supply of counterflow and thus lead to over-mitigation and increased Type I errors. RUC today manages for congestion. This means that when RUC capacity adds congestion to a binding constraint, RUC will need to procure additional RUC capacity (not because the capacity is needed for reliability reasons, but rather for congestion management) to provide counterflow on a binding constraint in the RUC run. With the new proposed products there are now two ways to manage congestion in RUC. First, increase dispatch (award RCU) from a resource that can provide counterflow, and second decrease generation (award RCD) from a resource contributing to the congestion. WPTF would like to confirm if the DCPA will capture supply available from awarding resources RCD as available counterflow supply. If the DCPA does not capture that available supply that can be used to manage the congestion, then the RUC MPM process will over-mitigate.
7.
Please provide your organization’s comments on changes to the Residual Unit Commitment.
Similar to the Imbalance Reserves products, the RUC imbalance requirement is based on Net Load (load forecast minus solar forecast minus wind forecast). On page 22 of the Third Revised Straw proposal, the CAISO states the drivers for reliability capacity down are:
- Bid-in load clears the IFM greater than the CAISO load forecast
- Virtual demand clears the IFM in excess of virtual supply forecast
- VERs clear IFM less than the CAISO VER forecast
The reasons stated do not seem to inherently support a RUC downward product based on a net load forecast.
Reason 1: Bid-in load clears the IFM greater than the CAISO load forecast. This rarely (never?) happens and would have to happen at significant levels for there to be a reliability or market issue. Most resources already economically offer into real-time and can simply be backed down from their day-ahead schedule.
Reason 2: Virtual demand clears the IFM in excess of virtual supply forecast. Virtual demand clearing in excess of virtual supply is not in and of itself an issue; in fact, in the event bid-in load is less than the CAISO forecast of CAISO demand, this is helpful for IFM price formation. Only if bid-in load plus net virtual demand exceeds the forecast would there be a reliability issue, but again resources already economically offer into real-time and can simply be backed down from their day-ahead schedule. It is unclear why they need an additional RUC payment to do so. If Reason 1 and 2 combined mean that RUC must decommit a resource, it should do so, but WPTF is struggling to understand why this requires an explicit additional requirement using net load. These reasons are if all scheduled supply exceed the CAISO load forecast.
Reason 3: VERs clear IFM less than the CAISO VER forecast. VERs systematically under schedule in the day-ahead, perhaps in part because there is an RA exemption for EIRs to offer into the day-ahead market. However, for years the CAISO has adjusted the CAISO forecast of CAISO demand for additional expected VERs and virtual supply has addressed some of the price formation issues. Again, it is unclear why there should be a product in RUC in the event non-VER capacity is cleared above the net load forecast. There is no reliability issue – VERs can be curtailed in real-time. And if they don’t want to be curtailed, they can bid into the day-ahead market so that less thermal is committed, which leads to better price formation in the day-ahead market anyway. The original reason for wind not wanting to bid into the IFM was due to the high MAPE. However, this has been trending downward. On average, the monthly day-ahead wind forecast MAPE was above 5% in 2019 for 5 months, in 2020 for 3 months, in 2021 for 2 months, and this year has been under 3.25% for January and February.
WPTF remains supportive of modifying RUC to allow decommitment but is still unclear on the purpose of the RUC down product given the net load formulation. CAISO routinely experiences significant over-generation because of solar, but the majority of solar already economically offers into the market and the CAISO only extremely rarely has had to curtail solar self-schedules. We are struggling therefore to identify the reliability need for a downward RUC product and asks for further explanation.
8.
Please provide your organization’s comments on Real-Time Market Ramp Deviation Settlement.
WPTF generally agrees with the need to apply some form of no pay provisions when a resource awarded the IRU/IRD products in IFM do not make that ramping capability available in real-time. The CAISO is currently proposing to charge the resource at the higher of IRU/IRD price, FMM FRP price, and RTD FRP price. The CAISO further notes that they want to implement something that has a stronger incentive to make the ramping capability available in real-time than just a reversal of the IRU/IRD payments; thus the current proposal includes the higher of the product prices and FRP prices. However, WPTF notes that the FRP prices tend to be near zero the majority of the time and thus questions how strong of an incentive that will generate in practice.
WPTF is still evaluating the reasonableness of applying the proposing ramping deviation settlement on resources awarded IRU/IRD in the IFM and then subsequently FRP in real-time. At a high level, the idea of clawing back opportunity costs from providing IRU/IRD in the IFM when the resource is then awarded FRP seems to be addressing an issue that is not warranted. When a resource receives an opportunity cost in IRU/IRD prices, it’s because it was held out of merit from providing energy in IFM to provide the IRU/IRD products. That being said, WPTF is still evaluating this element. The CAISO indicated an excel file was made available to help stakeholders evaluate the aspect of the proposal. However, its unclear to WPTF where that excel file was posted, thus we have been unable to fully evaluate this element of the proposal at this time.
9.
Please provide your organization’s comments on Congestion Revenue Rights.
WPTF urges the CAISO to be proactive and consider implementing some form of a solution rather than take a “wait and see” approach in this case. The CAISO should not be proposing a market design element that will knowingly have adverse impacts on another aspect of the market – in this case CRRs – especially since there is an easily implementable solution from the onset.
The latest round of CRR market changes created significant uncertainty for CRR holders in such a way that its challenging for them to appropriately value CRRs in the auction processes today. The CAISO’s proposal to not collect congestion rents due to imbalance reserve flows is just adding to the risk and uncertainty of holding CRRs. This proposal essentially harms CRR holders in a way that they cannot mitigate through changing their own market behavior. The proposal also creates inappropriate cost shifting; it takes costs (congestion costs from imbalance reserve flows) that should be borne by one set of market participants engaging in the energy market but puts those costs on another set of participants are not necessarily participating in the energy market to begin with.
Additionally, it should be recognized that the CAISO and stakeholders recently kicked of an initiative to address a similar issue. A certain market feature today also creates a scenario where the CAISO is not collecting congestion costs from all the flows in the CAISO market, thus contributing to CRR underfunding. Initially the thought was this impact would be minimal - which is the same justification the CAISO is providing in this initiative. However, recent experience has shown that the impact is not minimal and has had detrimental impacts on CRR holders. The CAISO is now proposing to implement a solution after participants have been unduly harmed. WPTF thus questions why the CAISO isn’t taking a “better safe than sorry” approach here and implement the solution now rather than waiting for the issue arise and further harm participants.
WPTF would like to further explore the pros and cons of both solutions identified by the CAISO in additional to a potential “backstop” solution. For example, the CAISO could consider putting a floor on the CRR underfunding such that if the concern with CRR arises, the impact to CRR holds will at least ensure it will only result in reduced payments rather than flip to charging CRR holders, as was the case with the 2% shift factor threshold. Additionally, in the event the CAISO opts for the backstop approach, WPTF would request that the CAISO establish a transparent metric such that if the CRR shortfall impact reaches a pre-defined level, the CAISO will immediately act and implement a more robust solution.
10.
Please provide your organization’s comments on Accounting for Energy Offer Cost in Upward Capacity Procurement.
While WPTF understands what the CAISO is trying to achieve by proposing a real-time energy offer cap on resources that have been awarded IRU/RCU, we are strongly opposed to this element of the proposal for several reasons as discussed below.
The energy bid cap will force resources to offer in at energy prices that do not cover their costs. As been discussed for several years, there are a lot of changes that occur between the day-ahead and real-time markets. Several of those changes, such as gas price volatility, is out of the control of resource owners and can cause drastic increases in the cost of a resource generating in real-time overnight. It may easily be the case that in real-time a resource awarded IRU will be forced to submit an energy bid that does not cover its marginal energy costs. Take the gas price volatility scenario as an example. Per the CAISO’s proposal, the real-time energy bid cap will be published prior to the close of the day-ahead market such that resources can price the risk of being exposed to the cap in their IRU offers (which as discussed below has its own faults). Thus, any changes in gas prices that occur from the time the real-time energy bid cap is set and when the resources are dispatched for energy in real time will not be accounted for. Additionally, because the resource will not be able to even offer in energy prices above the cap to reflect its marginal energy costs, those costs will not be included in bid cost recovery. Thus the only way a resource providing IRU capacity that is exposed to a real-time energy bid cap actually recover its full costs is to file at FERC – a tedious, costly, and time consuming process. Additionally, the resulting energy market prices in real-time will be suppressed and not truly reflect the marginal cost of energy. This proposal not only forces resources to operate at prices below costs, but the price signals from the real-time market will be jeopardized.
The CAISO’s “solution” to address the prior concern is not feasible and encourages resources to submit offers that no longer reflect their willingness to provide the product. The CAISO has acknowledged that placing a real-time energy bid cap on resources may run the risk noted above. The solution offered in the proposal is for resources that risk not being able to reflect their costs in real-time is to price that risk into the IRU capacity offers. This is a flawed approach for a few reasons. First, the CAISO’s proposal encourages resources to offer in IRU capacity at prices that diverge from their true willingness to provide. Secondly, the CAISO is also proposing to mitigate the IRU capacity offers. Thus a resource may price the risk into the IRU capacity offer only to have it mitigated to a level that no longer reflects that risk; the mitigation of the IRU offers essentially makes the CAISO’s solution to the real-time energy bid cap ineffective.
The energy bid cap proposal may indirectly mitigate the resource’s energy bid curve absent any market power mitigation. WPTF would like to better understand how the real-time energy bid cap will work with energy offers to maintain a monotonically increasing bid curve. In real-time, is the CAISO planning to just check that a certain MWh amount equal to the IRU/RCU award is offered in at a price at or under the real-time energy bid cap? Or is the CAISO going to check that the same operating range associated with the IRU/RCU capacity is offered in at or below the real-time bid price cap? If the latter, then WPTF is concerned that this is indirectly mitigating the entire bid curve underneath the upper limit of where the IRU/RCU capacity range ends without any market power. For example, if a 100 MW resource receives a 25 MWh day-ahead energy schedule and 10 MW of IRU/RCU but now has to ensure that the bid segment from 25MW to 35MW is at or below the real-time energy bid cap, it then follows that everything under 35 MWs has to be bid in less than the bid cap to ensure a monotonically increasing bid curve. If the former, then it could be the case that resources will essentially be forced to generate at prices lower than actual costs and/or buy back day-ahead schedules at higher real-time prices. Using the same example as above, the resource has two options. One it can self-schedule its day-ahead award and then offer in the IRU below the bid cap. If actual costs in real-time are greater than the bid cap, then the resource is now forced to generate at prices less than it can reflect in bids. Alternatively, the resource can offer in the first 10 MWh segment below the real-time energy bid cap (and take a loss if actual costs are higher than that) and then submit a bid for the remaining 25MWh energy schedule at the higher actual real-time cost of, for example, $45/MWh. But due to the increase in energy that is offered in at bids less than $30/MWh, energy prices may not reach $45/MWh and the resource then has to buy back a portion of its day-ahead schedule at potentially a higher real-time price. WPTF believes these nuances of how the bid cap will be applied and the implications of each approach need to be further discussed.
This proposal element unnecessarily diverges from the treatment of all other ancillary service products. Throughout discussions on this element of the proposal, there is always the question as to why this ancillary service like product requires different treatment (e.g., LMPM vs capacity bid cap, and real-time energy bid cap). The response is always that there is a higher likelihood of this product being dispatched for energy in real-time than the other ancillary service products. WPTF would like to take this opportunity to remind the CAISO that at the beginning of MRTU, the spinning reserve capacity that was flagged as non-contingent (roughly 50% of total procurement) was consistently dispatched for energy in real-time at the underlying real-time energy bid price. There was no real-time energy bid cap in place nor mitigation of the capacity offers to begin with. Additionally, the CAISO continues to note that we need to ensure that the real-time energy market is then left with high priced energy offers from the IRU capacity to schedule imbalance energy. Here again, if the CAISO were simply to maintain the RT MOO then this would be a non-issue; the real-time market would still have sufficient energy offers from resources that would naturally drive down the energy offers to marginal costs (e.g., the natural forces of a competitive market and real-time LMPM on energy offers would mitigate all concerns). With this in mind, WPTF again asks why the different treatment is necessary?
To recap. WPTF does not believe the real-time energy bid cap is warranted and in fact the only response the CAISO has provided for needing it in place is as a result of other flawed elements of this proposal. A simple solution would be to trust the natural forces of a competitive market coupled with maintaining the RT MOO.
11.
Please provide your organization’s comments on the Alignment between RA, DAME and EDAM.
The CAISO must separate DAME/EDAM policy from DAME/no-EDAM policy.
While WPTF appreciates the CAISO’s enthusiasm and optimism about extending their day-ahead market, we do not accept it as a foregone conclusion. The CAISO has justified DAME and the introduction of a new imbalance product in the IFM as a more reliable and economic way of committing and scheduling resources in the day-ahead market. Thus, it is WPTF’s understanding that regardless of whether EDAM moves forward, the CAISO believes DAME is a worthwhile day-ahead market improvement. Since this is the case and EDAM is not a certainty, we believe the CAISO must clearly articulate what is being proposed solely in the event EDAM goes forward. One of the main impacts of a no-EDAM reality is on the RA rules.
No-EDAM policy
Absent EDAM, WPTF does not see a justification or need to change the real-time RA must offer or RUC rules because of a new imbalance product. The sole justification for changing these rules is due to potential leaning and concerns about equities between Balancing Areas. The main consideration therefore in a no-EDAM world, is whether it is appropriate to require all RA capacity to bid for the IR products and whether this could be construed as a double payment for a real-time must-offer (similar to RUC).
WPTF believes the answer to this requires an understanding of the existing RA program rules, which have not been summarized nor described well thus far within this initiative. Tariff section 40.6 clearly and extensively describes both scheduling coordinators for RA resources and the CAISO’s obligation to RA resources. Key tariff sections are summarized and commented on below.
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- Day-Ahead Availability rules and 40.6.4.1 Exceptions
All RA capacity physically capable of operating must submit either an economic bid or self-schedule into the day-ahead market AND submit economic bids or self-schedule to provide any ancillary services they are certified to provide. The CAISO will honor these self-schedules until the CAISO is unable to satisfy 100% of their AS requirements and only then will they curtail an RA self-schedule. The only exceptions to this are listed in 40.6.4.1 and that is to specify certain conditionally available resources only need to submit self-schedules or economics bids up to their expected availability and not the full RA capacity value. Finally, there is an exemption the CAISO should consider removing and that is for Eligible Intermittent Resources – this is the only resource type that does not have a tariff day-ahead must-offer to self-schedule or economically bid their physical availability in the day-ahead market.
40.6.2. Real-time Availability rules
All RA capacity that receives a day-ahead schedule for energy or AS must submit Bids into the real-time market for the at trading hour. Short and medium starts, regardless of day-ahead awards, must submit bids all hours they are physically available. Long start resources cannot be committed by the optimization in real-time so are released from their must-offer; however, are still allowed to self-commit or wheel-out in real-time. Finally, the CAISO will continue to honor energy self-schedules of RA capacity until the CAISO is unable to satisfy 100% of their AS requirements.
For the avoidance of doubt, here is the tariff definition of Bid, “Either (1) an offer for the Supply or Demand of Energy or Ancillary Services, including Self-Schedules, submitted by the Scheduling Coordinators for specific resources…” so RA capacity is still allowed to self-schedule in real-time and the CAISO must honor this self-schedule.
Finally, tariff section 40.10.6.1 is key because this is where the flexible must-offer obligation is articulated. Only flexible RA capacity must submit economic offers. Unlike the general system obligation to bid when physically available, flexible RA only requires economic offers from 5 am to 10 pm each day or if a lower flexible category, for 5 hours on certain days.
Take aways:
- The imbalance reserve product requires economic offers in real-time. Already the CAISO and CPUC have determined the requirement to provide economic offers is a separate RA product that needs a requirement and potentially premium over system RA, which is why the flexible RA product was created.
- The impact of the flexible RA product on the RA market and energy market is tenuous at best; however, it is the flexible RA product that has an overlap with the imbalance product because it is the only RA product that requires real-time economic offers.
- Ancillary services are not a requirement to provide RA capacity because there is no obligation by the CAISO nor CPUC that RA resource must be certified to provide AS products. If they are certified for them, only then must they offer them into the market if physically available.
Thus, WPTF agrees with the CAISO’s conclusion that this product may be able to replace the current flexible RA paradigm; and sees a few possible paths forward. One path; however, that is not an option is to require all RA resources to offer in their non-self-scheduled capacity into the product. This is not an option because the RA program explicitly allows real-time self-schedules for non-flexible RA resources. This is an important feature of the real-time must-offer obligation because many resource types need the ability to fix their schedules in advance due to fuel or availability limitations. That said, some small changes are possible:
- Flexible RA capacity can have an IR MOO and flexible RA program retained as is
- Flexible RA program can be modified to incorporate the IR products and RUC needs
- RA resources can have the option to certify for the IR product by the CAISO (and have their MOO determined contractually) and if they certify (like AS) they have to offer it in
- RA resources can have the option to certify and allow pre-certification participation so resources can test whether they are able to comply with the must-offer obligation and requirements
- A combination of these
Initially WPTF believes option 4 or something similar will be incredibly important for storage. It is unclear whether storage will be able to manage their energy, AS, and now IR product obligations without using end-of-hour SOC parameters or self-scheduling. Certainly, a sandbox environment will be needed for storage resources, including hybrid and co-located to test the new IR obligations.
EDAM policy
If EDAM moves forward, WPTF agrees this adds a layer of complication, but that also the conclusions and positions above still are important.
In the event EDAM moves forward, WPTF believes that the changes to the day-ahead market should be considered holistically and does not support removing the RA real-time must offer obligation nor leaving it up to the individual LRAs. Instead, WPTF supports the creation of an EDAM price formation and RA must-offer obligation stakeholder working group that addresses key issues that need to be resolved under EDAM. Including, but not limited to:
- Maintaining IFM as a financial (not physical) market. IFM currently is a financial hedge for load serving entities where bid-in load is used to clear supply. There is no obligation for load to bid in up to their forecast because it is a financial market. RUC is a reliability check to do needed long-start commitments but is not intended (as designed) to impact the IFM energy price. One LSE may bid in less of their load into real-time but can be confident because of the RA must-offer obligation and requirement for RA to bid $0 into RUC that they aren’t paying for RA that someone else is leaning on. This construct of a financial IFM appears diluted under an EDAM paradigm and WPTF would like additional discussion on this element.
- The purpose of BAAs versus LSEs. If the CAISO forces all BAAs to fully bid their load into the IFM to pass an RA test it fundamentally changes the structure and function of the IFM. The need for RUC is less clear and an integrated RUC/IFM seems to be something worthwhile to consider.
- Resource adequacy rules versus RS rules. Removing the RA real-time must-offer transforms the RA program into a forward resource sufficiency program. This needs significantly more discussion than it has been given within DAME thus far.
12.
Please provide your organization’s comments on the WEIM Governing Body Role.
We support joint authority.
13.
Please provide your organization’s comments on any other additional topics you would like addressed.
WPTF has no additional comments at this time.
