RASC: Resource Adequacy Reforms Q and A (RASC010, 011, 012)

Consumers Energy appreciates the opportunity to ask additional questions and provide feedback regarding the RA Construct's most recent iterations and ongoing concerns as of the November 3 RASC Stakeholder Meeting.

While CE supports performance based accreditation, the current SAC proposal is complicated, continues to evolve, and generates additional questions each time new information is presented and stakeholder questions are addressed or partially addressed. We strongly reiterate the request to delay filing the SAC portion of the current RA Construct until a final proposal is reached, outstanding questions addressed and stakeholders have the opportunity to review the proposal's impacts on their fleets, whether through MECT or other manual calculations that can be reasonably replicated to address necessary changes in operations or planning.

CE asked previously about upgrades to a unit capacity/GVTC and how this would be addressed in the SAC calculation. MISO's response was that accredited values would only be fully reflected the third year after the upgrade occurred. This leads to our current question regarding differences in capacity and accreditation values as well as offer requirements in the Day Ahead and Real Time auctions, especially with regard to what clears in the annual seasonal auction as compared to a unit's entire capability. What happens if a unit has 400 MW but only clears 300 MW in the auction. If we do not offer the other 100 MW capacity in some form or put it into an extended derate to complete maintenance, would we be taking capacity accreditation hits for this uncleared but otherwise available capacity?

The following feedback is offered by the Entergy Operating Companies ("EOCs")^[1]in response to MISO’s request made during the November 2021 Resource Adequacy Subcommittee meeting.

The EOCs believe that MISO’s proposed implementation schedule does not allow enough time for market participants to adapt to the new resource adequacy construct and may unreasonably result in EOC customers being exposed to elevated PRA clearing prices for the initial years that the construct is implemented with no meaningful opportunity to plan for or mitigate exposure to such costs. Regardless of whether sharply increased PRA clearing prices represent an efficient result – and the EOCs believe strongly they do not – it is beyond reasonable dispute that implementing a dramatic change in the market design that causes clearing prices to increase sharply with no opportunity for LSEs to react or mitigate exposure to such prices is unjust and unreasonable.  The EOCs concern of elevated PRA risk is based on MISO’s latest projected impact data presented in the November RASC which shows that the MISO proposal would reduce the current 21/22 LRZ 10 Local Clearing Requirement (LCR) surplus position from ~1,700 MW to ~100 MW for the winter season (“with the stroke of a pen”) and would reduce the LRZ 7 LCR surplus position from ~2,000 MW to ~0 MW for the winter season.  It should be noted that MISO’s projected impact numbers do not take into account the amount of capacity that generation owners may newly withhold from the auction due to planned outages that exceed 31 days (e.g., nuclear units on refueling outages) in response to new rules penalizing resources that incur such outages, which would only worsen the surplus/deficit LCR positions.

EOCs have not objected to moving to seasonal RA planning auctions, but the projections noted above should be cause for significant concern by MISO regarding its design of the sub-annual construct.  The seasonal planning auctions contain an RA hours selection methodology using historic, operational real time events that vary from year to year.  Using tight margin hours across an entire year to establish an average accreditation value can be a poor predictor of a resource’s future performance for a given season.  Stated another way, the link between the cost consequences and the planning behavior MISO wants to incent is marginal at best.  EOCs support MISO’s Minimum Capacity Requirement (now Minimum Capacity Obligation or “MCO”) and believe may afford some modest incremental benefit with respect to the planning resource issues MISO wants to address.  MISO should file the MCO changes separately and consider the EOC’s transition suggestions (see below) allowing for a gradual transition to, and an assessment of, MISO’s proposed Sub-Annual Construct changes.

The time between when FERC would likely approve MISO’s proposal and the first day the proposal would go into effect (June 1, 2023) is roughly ~15 months. Given the length of time it takes to plan and construct new generation and transmission assets, this is not enough time for market participants to take any meaningful actions or make system investments to improve their zone’s LCR position. Additionally, the 23/24 PY will use unit accreditation ratings that are based on historic unit performance from September 2019 through August 2022, meaning that at the time FERC would approve this proposal, the facts and circumstances that drive over 2/3 of the period dictating a unit’s rating will already have occurred, leaving little opportunity for generation owners to take any actions to try to improve unit accreditation ratings before the 23/24 PY. 

It should be undisputed that sweeping changes to the design of the resource adequacy construct in MISO should include reasonable safeguards to protect LSEs and their customers from unreasonable harm.  Even if it were accepted that MISO’s sweeping changes are necessary to ensure reliability, to implement those changes with no opportunity for LSEs to react and adapt their behavior to mitigate risk would be unreasonable.  The occurrence of clearing prices at or near CONE may or may not be an efficient outcome, but to force customers in MISO to bear those costs on day 1, based solely on MISO’s decision to change the market rules, and with no opportunity to react, amounts to an unreasonable penalty and a wealth transfer – and it does nothing to improve or ensure reliability or resource adequacy in MISO.  Despite the elevated risk of CONE pricing and the short implementation timeline, MISO has not proposed any meaningful transition mechanisms to safeguard customers from the risk of exorbitant PRA clearing prices during the transition period from the old construct to MISO’s proposed construct. The one transition mechanism that MISO has proposed, phasing in the tier 1 and 2 accreditation weightings, will likely not result in a significant increase in supply across MISO, and could possibly result in a loss of capacity for some zones and seasons.[2] For this reason, the EOCs are not confident that this transition mechanism is sufficient to mitigate CONE pricing during the transition period. In past feedback requests, the EOCs have proposed the following transition mechanisms, all of which MISO has not only failed to incorporate into its proposal but also failed to respond to in any meaningful way or to explain why such transition mechanism is unacceptable or unworkable in whole or in part:

• During the first three years under the new construct, use UCAP unit ratings measured on a seasonal basis; [3]
• During the first three years under the new construct, constrain the LCRs for the non-summer seasons so the non-summer LCRs do not exceed the summer LCR value;
• During the first four years, do not implement the capacity replacement requirement for planned outages that exceed 31 days[4]; and
• During the first four years under the new construct, do not adjust the daily CONE value based on the number of seasons an LRZ is deficient relative to the LCR requirement. To explain further, during this four-year period, the daily CONE value should always be equal to the annual CONE value divided by the number of days in the planning year.

The EOCs again request that MISO include all, or at least some, of these mechanisms in the proposal in order to lower the risk of large PRA price increases during the transition period with no reasonable opportunity for LSEs to react or mitigate their exposure.

The EOCs request that MISO answer the following questions:

• Given that (1) the amount of time between FERC approving MISO’s tariff and the day the proposal would be implemented is roughly ~15 months, and (2) 2/3 of a unit’s historical performance hours for the 23/24 PY will already have occurred by the time FERC would accept MISO’s proposal, what actions does MISO believe market participants reasonably can take over 15 months to improve their zone’s LCR surplus/deficit position?
• What impact will MISO’s proposed transition mechanism (change to the tier weightings) have on the projected zonal LCR positions?
• If MISO’s proposed construct causes customers to pay CONE pricing in the PRA in the first year the construct is implemented (~15 months after FERC approves the construct) with no opportunity to mitigate their risk of such pricing, does MISO believe this is an acceptable outcome?
• An explanation of how exposing an LSE to CONE pricing based solely on sweeping market design changes is consistent with MISO’s value proposition for membership.
• A calculation of how the net benefits of MISO participation would be affected if a substantial number of MISO LSEs incur CONE pricing in the initial year the RAN proposal is implemented with no opportunity to mitigate their exposure to such pricing.
• Please provide analysis showing the correlation between system reliability events and planned outages that exceed 31 days.
• Please provide the following data for all system reliability events over the prior 5 years:
  • The amount of nuclear capacity offline in a refueling outage that ended up being greater than 31 days.
  • The amount of nuclear capacity offline in a refueling outage that was less than 31 days.
  • In recent years, how many of the 31+ day nuclear refueling outages were planned during times with a positive maintenance margin?

The EOCs do not find MISO’s responses to the following questions/requests submitted in prior feedback requests to be satisfactory and would ask that MISO provide additional explanation/analysis to resolve these questions and requests.

• More information/explanation regarding MISO’s analysis showing that most of the Entergy Operating Companies would have their highest Planning Reserve Margin Requirements in the Spring season, which is traditionally considered an off peak season in the South region during which significant maintenance outages are taken. Additionally, an explanation of when is the best time for MISO South generation owners to be scheduling planned maintenance outages according to the insight provided by MISO’s proposed resource adequacy construct – recognizing that reasonable planned maintenance outages are essential to maintaining generation resources in good working order and thus to meeting customer demand at times of peak demand.
• Analysis comparing the level of volatility associated with UCAP unit ratings vs Seasonal Accredited Capacity (SAC) unit ratings.
• Analysis showing how MISO determined the 20/80 tier 1 to tier 2 weighting and data showing the impact of using a 50/50 tier 1 to tier 2 weighting
• Analysis demonstrating how the LSE PRMR requirements and surplus/deficit positions would change if MISO calculated the SAC to UCAP ratio on a regional basis (in alignment with how RA hours are selected), as opposed to on a MISO wide basis as currently proposed.

The EOCs appreciate the opportunity to comment.

See attachment sent via email.

• Is it likely that each season will have very divergent Planning Reserve Margins? 
• When attempting to recreate our capacity position, is it reasonable at this time to assume that the Planning Reserve Margin will be close to 8.9%? 
• If generators with >31 days are excluded from participation in the PRA, will these outages also being used in the LOLE study result in an effective double counting of outages during those times? 

I would like to thank MISO for allowing us to feedback on this important issue.

QUESTIONS FOR FEEDBACK

• Is the limitation to NRIS + Firm TSR calculation applied before or after the SAC is grossed back up to UCAP equivalent?  It seems that using the gross-up method could further penalize generators without sufficient NRIS, especially when UCAP can be greater than ICAP by design of the calculation.  So well-performing generators may not get all the benefit of converting UCAP>ICAP to ZRCs, which could defeat the purpose of using the gross-up method.
• Considering that MISO seems OK with well-performing generators having UCAP>ICAP under the gross-up method, MISO should reconsider and eliminate its unnecessary provision in the hourly SAC calculation that limits any hourly offer to ICAP.  If it is OK for UCAP to be greater than ICAP, then why can’t any hourly offer value be greater than ICAP?
• Reference MISO’s response to Duke Energy’s question regarding times when a generator is on line, but registering no offer or an outage commit state (10/06 Question 1 in the document “20211103 RASC Item 04a Resource Adequacy Reforms Q and A Document”).  MISO’s response does not seem to address the issue.  Yet, in MISO’s latest example calculation file (“20211103 RASC Item 04a Step by Step SAC Calculation Example”), data is provided in column J, the outage state, and column K, the on-line state, that appears to prove Duke Energy’s point.  Filtering the columns to show 1-1 groupings, indicating the unit is in a state of outage but in-service, reveals 156 hours in that condition.  That, despite MISO’s claims that such condition “should not be a frequent mode of operation and is inconsistent with MISO’s Operating Procedures”.  MISO should reassess its position on this issue by looking at this data, which clearly shows such operating condition is more prevalent.  MISO should alter the hourly SAC calculation per Duke Energy’s recommendation to use, at a minimum, the actual net generation output of the generator for the hour, in such conditions that the offer is zero and/or the unit is in an outage commit state, even though the unit is on line.  This will provide proper credit due for actual service to the system in such conditions when an offer may not have been available, for whatever reason.
• MISO is providing for three transition years for phase-in of the outage exemptions, consistent with the three year lookback for XEFORd, but has only proposed to provide two transition years for phase-in of the Tier 1 weighting.  MISO should align the transitional aspects and provide for three transition years of the Tier 1 weighting as well.  Duke Energy recommends 50/50 in 23-24, 40/60 in 24-25, 30/70 in 25-26, and finally 20/80 in 26-27.
• Please provide an updated hourly RA hours file, calculated as per the specified performance period (9/1 – 8/31), for 9/1/2017 through 8/31/2021.  The latest example calculation file appears to only contains data for MISO South.
• Please provide the seasonal planning reserve margin percentages that are consistent with the seasonal UCAP/SAC gross-up factors presented in MISO’s latest example calculation file.

Thanks,

Bryan

• WPPI would like to thank MISO for the response to Request 13 in the Additional Analysis Requests in the Q&A document providing an analysis showing the number of planned outages in recent years that exceeded 31 days across MISO.  We found this very informative.  We would ask that MISO expand upon this information and provide some additional details to help stakeholders understand the amount of potential capacity that may be unavailable in each season by providing additional analysis mentioned below.
  • Could MISO expand upon this table by breaking down the number of outages >31 days by season?
  • Also, the average size of the generators that were in outage by season.
• At the last RASC, MISO mentioned they are proposing to limit generator RT Emergency Max offers to GVTC, could MISO provide the rationale for this requirement in an accreditation scheme based on historic availability?
  • Also, how does this new limit help operationally?
  • Limiting a resource to its performance at MISO peaks is not a good representation of how the resource could perform throughout the season in non-peak conditions such as periods with lower ambient conditions.  This will ultimately limit the amount of energy a unit could provide for MISO.
• In instances where a generator has been granted permission to not participate in the capacity market for a specific season, MISO suggested that this information may not be available to all MPs.  In regions that are tighter and lack surplus capacity, this could create instances where a MP may have insider knowledge that a specific zone may clear close to CONE, while the other MPs in the zone would be unaware.  Does MISO see any issues with this uneven distribution of market knowledge and how it may impact MPs in that specific zone?
• With MISO deciding to adopt IMM’s proposal for resource accreditation, we just want to confirm that as long as a resource’s offer does not exceed its deliverability (sum of NRIS and incremental ERIS accompanied by firm transmission service) it will not have its total ZRCs be impacted for deliverability.  Even in instances where the adjustment from SAC to UCAP may result in more ZRCs than their ICAP?
• Could MISO and the IMM provide examples of when they will allow a resource with >31 days of planned outage to not offer into the seasonal auction?  What “documentation of such circumstances” would be sufficient to satisfy the IMM that the resource may forego participation in the auction?

MGE generally supports WPPI's feedback.  

Thanks,

David Sapper

dsapper@ces-ltd.com