RASC: RA Construct Questions (RASC010, 011, 012) (20210920)

See email attachment.

• Would  MISO consider some type of "guard rails" or other mechanism(s) to ensure undue financial harm does not befall ratepayers due to unintended consequences.  For example, what if unforeseen circumstances result in a number of CONE applications even though no improvement in resource adequacy and/or no shortages ultimately exist.  There needs to be language to ensure resource owners have an "off-ramp" to avoid CONE during the first few years of the revised accreditation when appropriate.

MidAmerican appreciates the opportunity to request clarification on MISO’s proposed resource adequacy reforms. MidAmerican fully supports MISO’s assertion that MISO is facing a reliability imperative as the industry transitions to more variable resources. Moving to a seasonal construct is a logical step to respond to that transition. MidAmerican remains concerned that certain parts of the proposal will result in uncertainty and therefore not result in an increase in reliability. MISO should review real time market rules and provide market participants with more information in advance of real time which will address its reliability concerns and allow market participants to stage units for tight margin hours that do occur. Finally, MISO should continue to review real time market incentives to address reliability concerns. For example, requiring the correct amount of flexibility, including a ramp requirement as well as the requirement to have controllable resources and limiting scheduled outages eligible for exemptions to accreditation reductions.

Questions 1 –

Has MISO considered the full range of real time market improvements that will provide reliability improvements? For example, if there is a high probability of tight margin hours, should MISO commit long-lead time units? This incentivizes the longer-term viability of these reliable, non-intermittent units rather than penalizing them through the capacity market. What specifically in MISO’s proposal addresses the unpredictability of tight hours? What specifically in MISO’s proposal addresses the growing variability and uncertainty in the MISO generation portfolio? Will MISO include this variability and uncertainty in the MOM forecasts? If so, how?

Question 2 –

The whole SAC process is setting a unit’s ZRCs for a season based on the prior three years’ performance during the tightest 3% of the hours in that same season.

As communicated by the IMM, “uncertainty will always cause tight hours to occur unpredictably.”   Explain why utilizing a unit’s performance in only 3% of all hours in a season over a three-year period rather than using overall performance over a three-year period is a better reflection of how a unit will perform? Did MISO create any correlation data to prove that assumption? 

Question 3 –

MISO believes that the ZRC levels should be set based on the SAC value times what MISO refers to as the ICAP deliverability percentage which is the firm service (NRIS plus FIRM TSR) divided by the ICAP value which is the minimum of the GVTC test and the total interconnection service. This produces results that seem to indicate NRIS service is not at all firm based on the MWs but rather firmness is based on a ratio of firm service to the ICAP value.

If MidAmerican’s understanding is correct, please explain why MISO not allowing full capacity credits up to the level of firm service?

Question 4 –

MISO has stated in documentation that a resource that is not online and not in an outage and has a cold start lead time greater than 24 hours during an RA hour that the unit will receive no credit for that RA hour. Will MISO modify its proposal to consider hot or warm start times? This will be an important factor to appropriately represent capacity values provided for system support. Will MISO modify its proposal to exempts units that may be offline because temporary transmission conditions would either make the unit uneconomic or may worsen system reliability if the unit was online? Does MISO plan to have some sort of feedback loop that provides exemptions from resource capacity credit penalties when MISO does not properly commit a unit?

Question 5 -

MISO’s proposal will backfill seasons that do not have enough tight hours using a resource’s annual average offered capacity. Will MISO include that season that does not have enough tight hours when calculating the annual number? If so, there may be double counting for that season of capacity credit penalties. Also, if a unit performs poorly in the summer season because, for example, the river water temperature is too warm that is being used to cool your plant requiring a derate, that derate should not extend into non-summer months. How does penalizing a unit in the fall for a summer issue correlate to a seasonal reliability objective?

Question 6 –

MidAmerican’s current understanding is that if a unit has a planned outage longer than 30 days within a season, the unit will be able to participate in that season’s auction but must replace the capacity for any day longer than 30 days with another resource or will face a financial non-compliance charge for failing to replace the ZRCs. Can the replacement occur at anytime meaning if the unit has a 32-day outage could you replace the 2 days in the middle of the outage? Can another unit that has a 14-day outage in the middle of the 32-day outage be used to replace the ZRCs for those 2 days? Can it be during that other unit’s 14-day outage or does it have to be when the unit is not in a planned outage? What if it is a forced outage? Can the unit that has the 32-day outage be used for replacement for any time during it’s 32-day outage except for the 2 days? Where does the money from the financial non-compliance charge go?

Questions 7 –

MISO proposes to convert the PRMR (Planning Reserve Margin Requirement) that is currently being calculated into a PRMR(SAC) by adding the SAC accredited by all the thermal units and adding it to the UCAP accredited non-thermal units and dividing it by the sum of the UCAP accredited MWs and multiplying that ratio times the PRMR that comes out of the LOLE study as shown on the bottom of page 19 of your whitepaper from August 16, 2021.

 Since the LOLE study uses the UCAP values in the study, then a MW of PRMR is a MW of UCAP, but when applying a ratio as per the equation above, (SAC) during tight hours during the last 3 years could be better or worse than average performance over 5 years that only includes forced outages (UCAP) since your SAC hours is a subset of the UCAP hours but would also include planned outages. This equation indicates a SAC higher than the UCAP would result in a higher requirement so all units perform well during tight hours compared to all hours the overall requirement will increase. Conversely, if units have previously performed poorly during tight hours and the SAC is very low than the requirement will go lower. How does setting the requirement (what you need to carry) based on how units have performed based on a different criterion than how the original requirement was calculated correlate to the objective of improved seasonal reliability? In discussions with MISO staff, this is an imperfect short-term solution until the SAC methodology can be inserted into the LOLE study process. Does MISO believe that the SAC process can be inserted into the LOLE study process? If so, how? How long will it take to incorporate the SAC process into the LOLE study process?

Wolverine requests the following information for clarification as well as identification of potential fundamental issues within the current seasonal construct proposal.

1. How often will SAC be lower than UCAP?
2. Please provide justification for adjusting the PRMR and LCR post-LOLE modeling by the SAC/UCAP ratio. Provide evidence that proves reliability will at least be maintained by adjusting the PRMR and LCR post- LOLE analysis using the adjustment ratio.
3. Please explain (including references to Tariff and BPM language) if MISO’s existing and proposed capacity construct allows a LMR to clear the auction and subsequently offer zero availability for the planning year/season. If allowed, will MISO penalize the LMR? If no penalty will be applied, provide justification why it does not exist.
4. MISO’s current planned outage proposal utilizes a three-tier approach that is favorable for Tier 1 hours and restrictive for Tier 2 hours. Please explain why all approved planned outages are not exempt for all hours when maintenance margin is greater than zero. Please explain why MISO does not deny outage requests when maintenance margin is below zero.
5. MISO currently proposes to require legacy resources either request additional NRIS through the interconnection queue or procure a TSR to obtain different capacity credits for each season. Has MISO considered other options and if so, what are they? If not, when does MISO expect to consider other options?
6. Does MISO perform an audit of the CROW data compared to the GADS data? If not, does MISO have any concerns about different outage designations between CROW and GADS?
7. If MISO reduces the setpoint for a resource during any hour, but particularly a Tier 2 RA hour, will the resource’s accreditation be impacted or will it be exempt?
8. MISO has indicated that they will address open issues and/or further changes in the future. Has MISO maintained a log of these issues? If yes, does MISO have a plan/timeline to address and resolve the issues?

Stakeholder Comments – Lignite Energy Council, member of the Affiliate Sector

Questions:

1. What seasonal or annual reliability metric is showing the need for the proposed changes to the reliability construct?
2. What are the measurable metrics or objectives sought in the proposed changes to the Resource Adequacy Construct?
3. What seasonal or annual reliability metric is showing the impacts of the proposed changes to meet the defined objectives?
4. What is the basis for selecting the 80/20 weighting for tier 2 and tier 1 hours that drive the seasonal accreditation capacity(SAC) or each dispatchable generation unit.
5. What is the basis for selecting the 25% operating margin for defining an RA hour?
6. How is the proposed reliability construct envisioned to provide LSEs an indication of either increasing or decreasing levels of system reliability when considering resource additions or retirements?
7. With the observed impacts of having higher levels of wind dispatched and being unexpectedly not available driving the occurrence of RA hours, what is the basis for not including wind and solar resource availability assessment in the proposed construct?
   1. How will an expected subsequence filing including wind and solar be able to properly “merge” into the implementation of the currently proposed approach when the history of RA hours and impacts on individual generation unit SAC values have been created without wind and solar in the methodology? 

                                                               i.      The history of creating RA hours will likely include the wind/solar resources as a driver to the RA occurrence.  This is the time to get it more correct by looking at the availability of all resources during RA hours.

1. Additional comments regarding this question(Presented by Affiliate Sector member at September 21, 2021 Advisory Committee Meeting):
   1. The MISO generation portfolio is expected to continue a transformation into higher penetrations of renewable energy and more retirements of baseload coal generation.  Stakeholders continue to express the need to have an adequate representation of the MISO market when considering individual decisions along this pathway of generation transformation.  The Affiliate sector has a stated the following objectives at the :

•  (1) Resilience — Place more emphasis on ensuring the MISO grid is resilient, especially in light of extreme operating conditions such as those experienced by CAISO (last August) and ERCOT (February), as well as other infrequent but highly disruptive disturbances.
• (2)Coal Retirements — Analyze the potential reliability and resilience impacts of greater-than- announced coal retirements.
• (3) Renewables — Continue evaluating the implications of high penetration levels (30 percent and greater) of renewable energy. This is especially important in light of federal proposals aimed at increasing the penetration of renewables.

1. Additional information regarding resilience:

(1) Regarding resilience, we want to commend MISO for undertaking its Regional Resource Assessment (RRA). The RRA initiative should identify specific attributes that are essential to maintaining both reliability and resilience, which are often conflated but are not the same. Reliability means keeping the lights on during normal challenges; resilience means keeping the lights on (or restoring electricity as quickly as possible) during extreme operating conditions. While there are objective criteria for determining grid reliability (e.g., loss of load expectation), there are no criteria for determining whether the grid is resilient. (It is worth noting that ERCOT asserted to FERC in 2018 that its grid was resilient, when it clearly was not. Resilience criteria might have led to a different outcome during February’s winter storm.) Therefore, we urge MISO to establish criteria (or metrics) to gauge whether the region’s grid is resilient now and in the future, especially as the grid transitions to a lower-carbon resource mix.

1. In short, if we were MISO, we would ask ourselves four objective questions:

• Is the MISO grid resilient now and will it be resilient in the future?
• How do we know?
• What attributes enable the MISO grid to be resilient?
• How should MISO value those attributes?

1. Additional comments on constructing a more robust Resource Adequacy Approach
   1. If the Resource Adequacy Construct is limited to a single dimension of seeking adequate accredited MW to meeting the PRMR, and doesn’t provide an indication of system resiliency, there will be no ability to allow LSEs to consider resource additions that will enhance reliability.  A more robust resource adequacy approach will also allow LSEs and regulators to consider the impact of generation additions and retirements. 
   2. Evaluating the energy mix and the generation dispatched for a wide range of RA hours, including the days previous and subsequent to the larger numbers of sequential RA hours is expected to be a valuable exercise and could be used to gain insights on system resiliency.  Longer periods of subsequent RA hours could be used to identify the types of conditions that resources are evaluated for contribution to system resiliency. 
   3. The current and proposed modifications Resource Adequacy proposal  are both “blind” in identifying the resource mix that provides system reliability.  One of the stated reasons for the proposed Resource Adequacy changes is the higher level of renewable generation and more Max Gen events throughout the year.  This observation provides support for a seasonal approach, but is not adequately evaluating the impact of resource changes that are causing the increased number of Max Gen events. 
   4. Developing a robust understanding of the required resource mix needed to carry the system through periods of limited resources will be crucial to keep the system reliability. 
   5. This would be a reporting function by MISO and not resource type requirement, so the issue of MISO not being a resource planning entity is avoided.

Xcel Energy appreciates the opportunity to provide feedback and questions regarding the SAC proposal: 

1. Please provide the final annual and seasonal RA hour file for Planning Years 2018/19, 2019/20, 2020/21 using the methodology for selection that will be filed.  We believe the last file provided was published prior to any changes made in August such as the use of a 12 hour lead time instead of a 24 hour lead time.
2. What are the default SAC values that will be used for each class of thermal resource types?
3. Is MISO developing a process for MPs to dispute SAC values?
4. MISO has provided estimates of the SAC/UCAP generator variability, but LSEs need the SAC/UCAP system and zonal ratios that will be used for the calculation of the load obligation, based on expected resource mix transitions from the OMS survey or the RRA.  Without guardrails on this ratio, it is impossible to create sensitivities within a resource plan for the next 20 years.
5. MISO is capping the RT offer for each hour at the ICAP value and then applying a ratio to account for the deliverability limit after the fact to the SAC.  It seems to be an easy change and more appropriate to instead cap the RT offer by the deliverability limit within the calculation instead of applying a ratio after the fact. 
6. What data would be used to calculate the capacity accreditation for a historical non-capacity resource on an annual basis to a capacity resource for some seasons and a non-capacity resource for other seasons?  How does this change when only a portion of a unit's capacity cleared the annual construct?
7. MISO appears to be willing to consider transitional mechanisms beyond what is already included in the filing (i.e. phase-out of RAN Phase I planned exemptions).   While a transition of the 80/20 weighting (such as 60/40 the first year, 70/30 the second year, 80/20 the third year) may not resolve the fundamental issues, it may soften the impact of components that may not have been fully vetted and allow time for those components to be adjusted before those few RA hours are weighted at 80%. 

The Environmental Sector appreciates this opportunity to submit questions and comments on the RAN Reliability Requirements and Sub-annual Construct presentations published by MISO on September 1, September 8, and September 20 of 2021.  (Issue Tracking ID#: RASC010, RASC011, RASC012)  As stated in the Environmental Sector’s prior comments in September 2020, October 2020, December 2020, January 2021, March 2021, July 2021, and August 2021, the Environmental Sector appreciates MISO’s extensive work in developing this proposal but also remains concerned that MISO’s approach has not fairly and fully defined the periods of greatest risk against which resource performance should be measured for purposes of accreditation.  We are also concerned that MISO has not shown sufficient analysis of how its proposal will result in increased reliability and lowered risk of loss of load.  Below, the Environmental Sector describes its questions and comments on MISO’s most recent resource adequacy proposals from the month of September.  This feedback focuses in (1) MISO’s proposed changes to Module A of its Tariff; (2) MISO’s “Renewable Impact Analysis” presentation; (3) MISO’s proposed Schedule 53 to its tariff, which memorializes its approach to Seasonal Accredited Capacity; and (4) MISO’s proposed changes to Module E-1 governing its Planning Resource Auction.

 I. Module A (definitions) redline dated Sep. 8, 2021 (https://cdn.misoenergy.org/9.8.21%20Workshop%20Module%20A%20Definitions586307.docx):

The Environmental Sector proposes the following edits (shown in bold italic), largely clarifying and non-substantive, to certain of the proposed definitional changes in Module A. 

Minimum Capacity Requirement Non-Compliance Charge: The charge assessed to a Market Participant that has not demonstrated it has secured 50% of its PRMR before the closing of the PRA window for a given Season.

Seasonal Accredited Capacity (SAC):  The amount of Capacity, for each Season, in MW assigned to a Planning Resource after accounting for its historic availability, consistent with Schedule 53.

Zonal Resource Credit (ZRC): A MW unit of Planning Resource which has been converted from a MW of Seasonal Accredited Capacity to a credit in the MECT, which is eligible to be offered by a Market Participant into the PRA, to be sold bilaterally, and/or to be submitted through a Fixed Resource Adequacy Plan, in all cases for a given Season.

II. “RAN Renewable Impact Analysis” presentation dated Sep. 8, 2021

(https://cdn.misoenergy.org/20210908%20RA%20Construct%20Tariff%20Review%20Workshop%20Item%2002%20Renewable%20Impact%20Analysis587681.pdf)

The Environmental Sector offers the following questions after reviewing information in this presentation.

1. At what point in MISO’s RAN policy development process was the “Proof of Concept evaluation” (as referenced on slide 4) used?  What were the bases of the parameters mentioned here (e.g. 15% credit for wind in spring, summer, fall and 20% in winter) in relation to the Proof of Concept evaluation?

2. Where does MISO intend to memorialize the methodology in written form for calculating wind and solar accreditation as summarized on slide 3 of this presentation?  Is it roughly based on the methodology laid out inhttps://cdn.misoenergy.org/2021%20Wind%20&%20Solar%20Capacity%20Credit%20Report503411.pdf?

3. Please explain why it is optimal from a risk management perspective to use the following hours for evaluating historic availability for solar resources: Hours 15,16,17 ET for Spring-Fall; Hours 8, 9, 19, 20 ET for Winter.  Please provide analysis showing that these hours are the appropriate hours of actual high risk to evaluate the accreditation for solar resources for each season.

4. What analysis has MISO completed to ensure that the high-load hours being evaluated for purposes of accrediting wind resources are aligned with periods of actual high risk on the MISO system?

5. Has MISO conducted a system-level loss of load modeling analysis to assess the periods or hours in which there is greatest risk of not serving load? And if so, is this the same foundation for assessing the accreditation value for all resources, including thermal generators and renewable generators?

III. Schedule 53 proposed tariff language published Sep. 8, 2021 (https://cdn.misoenergy.org/9.8.21%20Workshop%20SCHEDULE%2053_Seasonal%20Accredited%20Capacity%20Calculation586309.docx):

The Environmental Sector offers the following questions after reviewing information in this proposed new tariff schedule, which memorializes MISO’s proposed methodology for calculating Seasonal Accredited Capacity.

1. Regarding the use of Hourly Emergency Maximum Limit, which figures into several accreditation calculations in Section IV here: is this a value that changes hour-by-hour or from season to season or from year to year for a given Resource?  How and when is the Hourly Emergency Maximum Limit for a Resource determined?  (That is not clear from reviewing the definition of Hourly Emergency Maximum Limit in Module A.)  The use of this value to capture a resource’s available capacity in megawatts across a range of tight hours seems meaningful only if this value is, in fact, varying across those hours.  Can MISO provide an example of how some sample resources may have varied in their Hourly Emergency Maximum Limits over time?

2. In Section IV.A, we suggest that, for purposes of the SAC determination for a given Season, any Annual RA Hours already included in Seasonal RA Hours for that Season should be excluded when calculating Annual Average Offered Capacity, as we suggested in our prior comments due on August 25.

3. In Section IV.C, we suggest editing what appears to be a scrivener’s error: “Annual Average Offered Capability” should be changed to “Annual Average Offered Capacity”.

4. In Section VI.A.2.a, we suggest editing this sentence: “Proposed Generator Planned Outage to occur entirely during a period that the subregion 120 days or more in advance of the outage start date and 120 days or more beyond the end date of any previously scheduled outages for the unit.” 

The bolded word (emphasis ours) appears to mark a place where certain phrases are inadvertently missing.

5. Has MISO worked with affected state utility commissions and/or electric utilities to plan for the incorporation of this new seasonal resource adequacy construct in integrated resource planning or other state generation planning processes?  Does MISO believe that LSEs and utility commissions have the tools to successfully model and plan for seasonal capacity requirements? If so, based on what information: which state processes and planning/modeling software packages have been specifically analyzed?

6. Regarding the language “New or existing Resources that do not have at least 60 days of Real-Time offered availability for each Season will have a SAC based on the Class Average SAC to ICAP Ratio for its Resource type” in Section V, we have the following question: Does this mean that if a particular Resource does not clear or is routinely withheld from the Planning Resource Auction and is used for the purpose of providing potential replacement ZRCs later (cf. August 4 RASC presentation at slide 23, final bullet point), then whenever it is ultimately used for capacity replacement in the PRA (cf. Section 69A.3.1.h of proposed Module E-1 language), its accreditation will be based on a Class Average accreditation ratio, even though it was historically functioning to essentially boost the accreditation of another resource?  Isn't that double counting the capability of the replacing Resource and/or artificially boosting the accreditation of the replaced resource (i.e., the cleared resource that underperformed)?

7.  Also, we have a clarifying question: does “60 days” in the quoted language from Section V mean 60 days total for the three instances of that Season across the three historic evaluation years?  Or an average of 60 days per Season (for that given Season) across the three evaluation years?

8. For provisions throughout Section VI, we have the following general question: if a generator notifies MISO of a Generator Planned Outage later than the earliest required date to qualify for a certain type of exemption, then does the entire outage not qualify for the exemption, or just the initial days of the outage that were noticed too late?  As an example, under Section VI.A.1, if a Resource schedules a Generator Planned Outage 117 days before the outage start date, then does the Tier 2 exemption apply starting with the 4th day of the outage and all subsequent days?  Or are all days of the outage disqualified from the Tier 2 exemption, because the outage started less than 120 days after the notice, period?  As a second example, if a generator is forced to take an outage with no notice to MISO, could the generator immediately notify MISO of the outage and make that a Generator Planned Outage beginning on the 15th day of the outage, so that outage days starting with the 15th day would qualify for a Tier 1 exemption under Section VI.B.iii?  The Environmental Sector recognizes the potential for creative interpretation here and recommends adding clarifying language to establish that, in any of these or similar cases, all days of the outage are disqualified from the applicable exemption for accreditation purposes.

IV. Module E-1 redline published Sep. 8, 2021 (https://cdn.misoenergy.org/9.8.21%20Workshop%20Module%20E-1%20Draft%20Redlines586308.docx)

The Environmental Sector offers the following comments and questions on this proposed tariff language.

1. Regarding Section 69A.3.1.h, subsection (a): it appears that a cleared Resource in the Planning Resource Auction may take up to a 30-day planned outage in a Season and still be considered to be performing under the tariff.  How does MISO’s proposal assure there is enough available capacity to meet the Planning Resource Margin requirement in any given season when it allows resources to take a 30 day outage in a season and still receive capacity credit?

2. Related to the above, how are transmission constraints considered when allowing uncleared ZRC to replace cleared ZRCs in the Planning Resource Auction?

3. In Section 69.A.3.1.h(a), we are concerned about the phrasing of this passage:

If a Planning Resource for which a Market Participant converts Unforced Seasonal Accredited Capacity into ZRCs is unable to meet the applicable performance requirements for the cleared ZRCs as described in Sections 69A.3.9 3.1 and 69A.5 for greater than 30 days due to full or partial planned outages any time during the Season of the Planning Year in which the ZRCs cleared, such Market Participant may must replace the cleared ZRCs with uncleared ZRCs to relieve the performance requirements applicable to the Planning Resource.

The language “If a Planning Resource … is unable to meet … performance requirements … for greater than 30 days due to full or partial planned outages…” has some ambiguity and could be construed to mean that the minimum amount of performance in a Season is 31 days (or 30.01 days).  A better phrasing (consistent with the intent stated on Slide 23 of MISO’s August 4 RASC presentation) might be to change “for greater than 30 days” to “for a period of inability that lasts longer than 30 days”.

4. In Section 69A.5(b) and twice in Section 69A.3.1.h(a), is the phrase “planned outage” meant to be “Generator Planned Outage”?

5. In Section 69A7.1.a, at subsection (a), we suggest inserting “made by the Market Participant” after “ZRC Offers”.

6. In Section 69A7.1.a at subsection (b), we suggest inserting “that” after “threshold” and before “will be applied”.

7. In Section 69A7.1.a at subsection (e), we are unsure what is meant by this proposed new passage:

MCR Transition Period: To respect the limitations on unit deliverability across the Sub-Regional Power Balance Constraint, the MCR will be determined on a Sub-Regional basis commencing with the 2025/2026 Planning Year.  MCR compliance will be determined separately on a Sub-Regional basis, where the Sub-Regions will consist of the First Planning Area and the Second Planning Area.  Commencing with the 2025/2026 Planning Year, MCR Non-Compliance Charges will be calculated on a Sub-Regional basis.

Does this mean that the Minimum Capacity Requirement will be determined on a MISO-wide basis for 2023/2024 and 2024/2025?  Since MCR compliance is determined for each Market Participant based on its Planning Resource Margin Requirement and the resources it controls, what does it mean for MCR compliance to be determined on a Sub-Regional basis, or not determined on a Sub-Regional basis?

Conclusion

We thank MISO once again for the opportunity to submit these questions and comments and look forward to working further with MISO to refine the latest resource adequacy proposals to ensure that they are workable and designed to ensure the highest levels of reliability in the MISO system.

The following feedback is offered by the Entergy Operating Companies ("EOCs")^[1]in response to MISO’s request made during the September 20, 2021 Resource Adequacy Subcommittee meeting.

While the EOCs are pleased that MISO has delayed its target filing date from September 2021 as previously planned, the EOCs do not believe that MISO has established a plan or process going forward that will allow for meaningful stakeholder feedback or necessary changes to the MISO proposal. For this reason, the EOCs have significant doubts that the new target date of December 1, 2021 will allow sufficient time for MISO to address the numerous outstanding stakeholder concerns.

Given that MISO’s proposed seasonal construct is projected to significantly change individual LSEs’ net surplus/deficit positions in the Planning Resource Auction and also LRZs’ net positions relative to the LCR, the EOCs believe that MISO should provide reasonable and appropriate transition mechanisms and time for LSEs to move from the current annual construct to a new seasonal construct. Otherwise, LSE’s may potentially suffer significant financial penalties in the PRA due to CONE pricing with no reasonable opportunity to mitigate those risks due to the long lead time involved in resource procurement. This result would be unjust and unreasonable and would impose an unfair penalty and burden on LSEs. For these reasons, the EOCs suggest that MISO implement the following transition mechanisms:

• During the first three years under the new construct, use UCAP unit ratings measured on a seasonal basis; [2]
• During the first three years under the new construct, constrain the Local Clearing Requirements (LCR) 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 30 days; 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 continue to have the following questions and requests related to MISO’s sub annual resource adequacy construct proposal:

• 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 showing the number of planned outages in recent years that exceeded 30 days across MISO and an estimate for how much replacement capacity would be needed as a result. More specifically, data showing the average length of time for nuclear refueling outages in MISO.
• 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.
• Updated analysis showing the projected LRZ surplus/deficit position relative to the LCR requirement when using the new RA hour selection methodology described by MISO in August 2021.
• RASC discussion and BPM updates on reforms to the seasonal ZIA methodology

The EOCs appreciate the opportunity to comment.

The Coalition of Midwest Power Producers (COMPP) thanks MISO and the Board for providing stakeholders additional time to develop an understanding as to how MISO’s proposed Seasonal and Minimum Capacity reforms will improve resource adequacy.

MISO’s RAN whitepaper highlights the inefficient conversion of capacity to energy as an issue contributing to the high number of maximum generation events, warnings, alerts, conservative operation announcements, and load shed events. MISO’s proposals focus on generator availability as the item that will resolve the issue of having a high number of events requiring operator action and the various emergency declarations. To evaluate the potential effectiveness of the proposed reforms, stakeholders must have an understanding of the current Resource Adequacy Construct’s performance. COMPP is requesting for MISO to perform a short, qualitative performance assessment that (1) articulates the shortfalls of the current construct, and (2) articulate how the proposed reforms address those shortfalls. To provide this detail COMPP submits the following questions that will allow COMPP to better understand the impacts of MISO’s Seasonal and Minimum Capacity reforms.

In addition to the qualitative explanation, COMPP is requesting that MISO response to the following questions. The responses to these questions will provide COMPP with an understanding of the current Resource Adequacy Construct's performance and how the proposed Seasonal and Minimum Capacity Requirement reforms would improve the performance. 

1. 2020/2021 Planning Year Performance
1. How many ZRCs did MISO clear in the 2020/2021 Planning Resource Auction?
2. What was MISO’s peak load on February 15, 2021?
3. What was MISO’s peak load on February 16, 2021?
4. What was MISO’s peak load on February 17, 2021?
5. What was MISO’s peak load on February 18, 2021?
6. How many MWs from resources that cleared in the 2020/2021 Planning Resource Auction were unavailable during the daily peak due to Planned Outages on February 15, 2021?
7. How many MWs from resources that cleared in the 2020/2021 Planning Resource Auction were unavailable during the daily peak due to Planned Outages on February 16, 2021?
8. How many MWs from resources that cleared in the 2020/2021 Planning Resource Auction were unavailable during the daily peak due to Planned Outages on February 17, 2021?
9. How many MWs from resources that cleared in the 2020/2021 Planning Resource Auction were unavailable during the daily peak due to Planned Outages on February 18, 2021?
10. How many MWs from resources that cleared in the 2020/2021 Planning Resource Auction were unavailable during the daily peak due to Unplanned Outages on February 15, 2021?
11. How many MWs from resources that cleared in the 2020/2021 Planning Resource Auction were unavailable during the daily peak due to Unplanned Outages on February 16, 2021?
12. How many MWs from resources that cleared in the 2020/2021 Planning Resource Auction were unavailable during the daily peak due to Unplanned Outages on February 17, 2021?
13. How many MWs from resources that cleared in the 2020/2021 Planning Resource Auction were unavailable during the daily peak due to Unplanned Outages on February 18, 2021?
14. Under MISO’s proposed Seasonal Reforms, how many MWs of Planned Outages from capacity resources that cleared the PRA would MISO have expected to see during each of the above-mentioned days?
15. Under MISO’s proposed Seasonal Reforms, how many MWs of Unplanned Outages from capacity resources that cleared the PRA would MISO have expected to see during each of the above-mentioned days?
16. What were the causes of Unplanned Outages for capacity resources that cleared in the 2020/2021 PRA during the period of February 15-18, 2021?
17. How would MISO’s proposed Seasonal Reforms have reduced the risk of those outages occurring?
18. During the period of February 15-18, 2021, what were the daily peak imports and exports?
19. 2,987 ICAP MWs and 2.331 UCAP MWs of non-firm external support were modeled in the 2020/2021 LOLE Study. MISO saw upwards of 10.3 GWs of non-firm external support during the February 2021 winter weather events. Relying on more non-firm external resources than assumed in the LOLE Study indicates a higher Loss of Load Expectation risk.

                                                               i.      What does MISO expect would have happened if only 2.3 GWs of non-firm external support committed to MISO during the February 15-18, 2021 period? What additional operating actions would MISO have needed to take?

                                                             ii.      Under MISO’s Seasonal Reforms, how will non-firm external UCAP be converted to SAC?

                                                           iii.      Under MISO’s Seasonal Reforms, how many more internal capacity resources would have been available to serve MISO load during the February 15-18, 2021?

2. 2021/2022 Planning Year Performance
1. How many ZRCs did MISO clear in the 2021/2022 Planning Resource Auction?
2. What was MISO’s peak load on June 10, 2021?
3. How many MWs from resources that cleared in the 2021/2022 Planning Resource Auction were unavailable during the daily peak due to Planned Outages on June 10, 2021?
4. How many MWs from resources that cleared in the 2021/2022 Planning Resource Auction were unavailable during the daily peak due to Unplanned Outages on June 10, 2021?
5. What were the causes of the Unplanned Outages for capacity resources that cleared in the 2021/2022 PRA during the operating day of June 10, 2021?
6. How would MISO’s proposed Seasonal Reforms have reduced the risk of those Unplanned Outages occurring?
7. How would MISO’s proposed Minimum Capacity Requirement have reduced the risk of all outages occurring?
8. On June 10, 2021, MISO relied on more than 13 GWs of non-firm external support, far exceeding the amount of non-firm external support modeled in the 2021/2022 LOLE Study. Does MISO view the need to rely on 13 GWs of non-firm external resources during as indicative of higher or lower loss of load risk?

                                                               i.      How would MISO’s Seasonal Reforms and Minimum Capacity Requirement proposals have reduced reliance on non-firm external commitments?

3. MISO’s SAC proposal results in higher supply excess than the current construct. With a vertical demand curve, all resources beyond the required demand are sent a retirement signal. As a result, more capacity resources are sent a retirement signal under MISO’s SAC proposal. How does this result in improved reliability?
4. MISO Staff stated the reason for the Minimum Capacity Requirement is because there is no “regulatory backstop” in retail choice areas.
1. What is the expected supply excess over local clearing requirements in retail choice areas for the 2022/23 Planning Year? How does the MCR proposal result in more or less excess in future years?
2. What is the average XEFORD of thermal units in retail choice areas?
3. What is the average XEFORD of thermal units in regulated areas?

Submitted on behalf of East Texas Electric Cooperative, Inc. (ETEC):

ETEC appreciates the opportunity to submit the following questions and requests to MISO:

1. Per MISO’s suggestion, ETEC has submitted a request through the portal for its resource accreditation information and will be reviewing MISO’s response. Based on that review, ETEC may have additional questions.
2. Please provide historical peak date / times for MISO and each LRZ on a seasonal basis to allow LSEs to forecast seasonal coincident peak demands.
3. Please provide a single point of reference on the MISO website for the latest and greatest information related to MISO’s proposal including but not limited to tariff / BPM draft language, MISO analysis, public data, and design documents.
4. Please develop a historical simulation of MISO’s proposal over one or several recent emergency event (e.g. Feb 2021 extreme winter weather). As a part of this, please quantify and demonstrate the potential impact of MISO’s proposal on the reliability experienced during the event.

Duke Energy appreciates this last opportunity to provide questions to MISO regarding the SAC proposal.  Many of these questions and requests have been submitted previously and we have yet to hear an answer.

• Duke requests that MISO provide unit-level example calculations that demonstrate all features and nuances of the proposal, including
• Addressing integrity issues with the hourly margin data identified by DEI (see Duke Energy Indiana Supplemental Comments 8/25/2021)
• Calculating SAC over the defined 9/1 to 8/31 performance period, rather than over plan years as MISO has done thus far.  This would include re-calculating the annual RA hours to reflect such period
• Calculations reflecting the appropriate treatment of the outage exemption process, not just calculations that assume no outages are exempt as MISO has done thus far
• Calculations for treatment of exempt planned derates, which MISO has not addressed at all to date (see Duke Energy Indiana Comments 7/21/2021 and 8/23/2021), including how exempt planned derates are removed from the annual average offer calculation
• Calculations reflecting the use of the hot-to-warm-to-cold unit state progression, not just the cold unit startup+notification time that MISO as done thus far
• A more appropriate reconciliation of SAC with PRM:  What MISO has provided they portray as conservative because MISO doesn’t include any outage exemptions; this results in the lowest SAC accreditation possible (hence the conservative portrayal).  However, SAC is only one side of the equation, as position is what matters.  MISO is calculating the PRMsac = PRMucap * SAC/UCAP.  So when MISO understates SAC by ignoring outage exemptions in their example calculation, MISO is at the same time then understating the PRM.  So when MISO finally gets around to calculating SAC correctly and the number goes up, the PRMsac will go up too.  The obvious question is then, for any individual utility what goes up faster, SAC or PRM?
• Duke also asks if MISO can respond to DEI comments and include provisions in the calculations to address times when a generator is providing service to the system (on line with positive net generation) but the offer is zero or otherwise less than the unit output, and/or the unit commit state is in outage (see Duke Energy Indiana Comments 7/21/2021)
• Duke asks if MISO can  clarify how it will treat intra-hour changes to unit offers for purposes of accreditation (i.e., use the offer at the start of the hour, the end of the hour, the average across the hour, the highest value within the hour, the lowest value within the hour, etc.) (see Duke Energy Indiana Comments 8/23/2021)
• Duke also wanted to clarify if MISO has answered a question provided early this month regarding the proposed tariff language.   The question revolves around whether this applies to both planned and forced outages.
• Capacity Replacement Non-Compliance Charge: The charge assessed to a Market Participant for failing to replace ZRCs that were designated for RAR and did not fulfill their performance obligations for more than 30 days in a Season. 

Thank you again for this opportunity.

These questions can be published to the public.  Please let us know if there are any questions.

Bryan

DTE appreciates the opportunity to ask questions on elements of the current RA construct proposal.

MISO states the desired outcome of the current accreditation proposal is to “Increase confidence in capacity that MISO can count on” as well as that, “Utilizing offered availability, including actual performance during RA Hours provides an improved measure of expected availability.” Has MISO done any analysis to show that the current proposal will meet this objective or improve overall system reliability? If not, DTE recommends that MISO review historic planning years using this new methodology to see if the capacity position expectation going into the planning year for SAC provides an improved picture of capacity MISO could count on during the tightest 3% of hours and MISO emergencies for that historic planning year.

Has MISO considered how to transition into a seasonal construct to account for changing requirements in seasons with traditionally high planned outages? Five-year average planned outage rates from GADS will be used in the LOLE model to set seasonal requirements. Using 5-years of historic planned outage rates may be inappropriate for the first couple years of the seasonal construct due to changing market participant behaviors. For example, MISO’s February 3rd presentation slide 31 indicates summer reserve margin requirements of 7.1%, while spring is at 22.3%. The large deviation between seasons was likely partially driven by the traditionally high planned outage volumes in Spring and market participants may now plan to move these outages to meet this extremely high PRM which could lower future years’ Spring PRMs. Has MISO performed any analyses on the impact of the volume of planned outages in the LOLE to the final seasonal requirements? That analysis could provide insight on how best to transition the outage modeling in the LOLE into a seasonal PRA understanding that market participant behavior may change based on the seasonal requirements they have to meet.

For Hourly Margin calculation, which is utilized to determine RA hours, MISO states that “Load Modifying Resource (LMR), and Emergency Demand Response (EDR) are excluded in the Online margin (MW) and Offline margin (MW) calculations.” Can MISO clarify why it makes sense to ignore resources that were accredited in the PRA when determining the tightest 3% of hours in a season? LMR and EDR resources have accounted for approximately 5.5% of cleared capacity in the PRA for the past 3 planning years and should be considered when determining tight margin hours.

In the September 1^st RASC, MISO presented a slide on page 6 showcasing the volatility in Seasonal Accredited Capacity at footprint and MP levels. Can MISO clarify exactly what inputs went into these graphs and how these STD calculations were done? DTE’s interpretation of the three-year average SAC STD graph for the spring season is that 50% of market participants will experience SAC volatility between 4% - 16% every year. Is this understanding of the graph correct and, if so, can MISO state if they believe this level of volatility in accredited capacity is reasonable for market participants to plan to? Can MISO also provide a volatility analysis of the current UCAP method as a comparison against MISO’s SAC volatility graph so that stakeholders can better understand the impact of this change?

Can MISO explain the logic behind class average SAC? SAC is heavily dependent on market participant behavior during the 3% tightest margin hours and is less dependent on generator type when compared to UCAP. If possible, DTE requests that MISO publishes graphs or data that supports the assertion that class average SAC can be reasonably applied to new resources and a comparison to the current class averages used for UCAP.

Consumers Energy appreciates the opportunity to provide questions regarding elements of the current Resource Adequacy construct proposal.

1. Please confirm that planned derates would qualify for the same exemptions as planned outages. Will a derate be eligible for Tier 1 and 2 exemption?

2. If a single CP Node consists of multiple units (i.e. combined cycle unit with multiple CT and ST) how will accreditation be handled if each of the units has relatively short outages, but the overall period of time that one of the units is out exceeds 30 days?

3. How will MISO prevent over-conservative actions (i.e. submitting planned outages for longer duration and/or greater frequency that truly required in order to achieve exemption)?

4. What recourse does a resource owner have if a resource needs an outage lasting over 30 days and no capacity is available to buy for replacement?

AMP, CMPA, MGE, MPPA, MRES, SMMPA, and WPPI submit the attached questions.

(I couldn't get the numbering to work in this window.)

Thanks,

David Sapper

dsapper@ces-ltd.com

Big Rivers requests MISO provide individual LSE’s with seasonal calculations of Load Forecasts and PRMR, to allow individual evaluation of their own portfolios.

Big Rivers also requests some guidance from MISO and/or the IMM on the expected impact to already-contracted annual ZRC transactions.

Questions regarding Minimum Clearing Requirements and timing:

Assume a small LSE which currently meets its’ 430 MW annual PRM requirements with a 400 MW UCAP thermal resource and a 100 MW UCAP thermal resource.  For simplicity, assume UCAP=SAC for the upcoming Planning Year.

• The 400 MW resource generally performs an annual outage of 49 days, typically planned in spring or fall.  For the upcoming Planning Year, the 400 MW resource’s planned outage is in the fall
• 50% Minimum Clearing = 215 MW each season (for simplicity the seasonal volume = annual volume)

1. Please clarify whether the 400 MW resource in this example is available to offer and meet the fall season Minimum Clearing Requirement of 215 MW
2. Please confirm or clarify whether this LSE must bilaterally purchase 115 ZRC’s for the fall to meet the fall seasonal Minimum Clearing Requirement (215MW minimum clearing – 100MW thermal resource SAC= 115MW to be purchased). If so, when must proof of that transaction be provided?
3. Please clarify that the minimum clearing requirement is evaluated at the time of the PRA.  If not then, when?
4. What is the impact on minimum clearing requirement of subsequently delaying the 400 MW resource’s outage from the fall to the following spring?

1. Will the delay in filing the Seasonal Resource Adequacy proposal further delay work on Solar Seasonal ELCC discussions (which were meant to begin in Q4 2021) or will the Solar Seasonal ELCC methodology be incorporated into this proposal due to the later filing date? Relatedly, will this impact expected implementation of Solar ELCC, and when does MISO anticipate Solar ELCC implementation to take place?
2. Will the delay in filing the Seasonal Resource Adequacy proposal delay work on Seasonal Accreditation rules for energy storage resources (which were meant to begin Q4 2021), or will seasonal accreditation for energy storage resources be incorporated into this proposal?

Alliant Energy (AE) would appreciate MISO responses to the following questions and comments.  This information will help us understand the elements of the proposed filing and its impacts.  We have prioritized this list to assist with MISO’s workload.

1. Provide July 7 presentation slide 21 (LCR capacity position for all individual zones and seasons) at the PRMR level, which is an obligation for LSEs.
2. Related to the “Seasonal and SAC Update for Alliant.pdf” Surplus / Deficient data sent to AE from MISO Staff on August 2^nd:
   • Provide the data broken up by utility and zone (e.g., ALTW Zone 2 & 3, ALTE Zone 1 & 2) as opposed to rolled up into ALTM.
   • Provide the individual seasonal accreditation values assumed by resource for non-thermal units (wind, solar, hydro, etc.).
3. AE expects that MISO’s proposed RAN construct will require an incremental ramp-up of capacity to satisfy the evolving obligations.  This expectation is based on MISO’s July 7 presentation slide 20 showing a decrease of 2.1-2.2 MW in capacity position for zones 1 and 3, which have higher renewable penetration relative to other zones.  Further, AE expects that other zones will soon be in a similar position due to increased retirements and renewable build-out.  When considering incremental capacity needs under the proposed RAN construct:
   • What information is MISO providing to communicate the incremental capacity need under the RAN construct relative to the current annual construct?  Is this mainly the July 7 presentation slides 17-22?
   • In light of the process time for the MISO queue, does MISO believe that there is adequate time for LSEs to increase capacity for the 2023 Planning Year?
   • What specific actions does MISO believe LSEs can reasonably take to satisfy incremental obligations by the 2023 Planning Year?
   • Does MISO believe that FERC should consider the amount of time LSEs need to react to, and implement, portfolio changes to satisfy the RAN implementation schedule?
4. AE recommends MISO enact RAN through a gradual 3-year ramp-in.  This could apply to many simultaneous concepts such as the 80/20 Tier weighting, penalties, winter reserve margin, etc.
   • To further emphasize on the need for a winter reserve margin ramp-in:  MISO’s February 3^rd presentation slide 31 indicates summer reserve margin requirements of 7.1%, while spring and winter are at 22.3% and 18.5%.  AE questions whether these high reserve margins are reasonable and necessary.  It seems that extreme LOLE control is driving these targets. 
5. Provide estimated LCR and PRMR position for 2023 and 2026 by individual zones and seasons.  Use MISO-OMS Survey data if needed.  If MISO cannot provide this data before the filing date, when would MISO be willing to provide this information?
6. Is MISO proposing any specific processes or measures to review an implemented RAN initiation.  For example, will MISO assess unacceptable volatility issues for values like SAC, PRM, CIL/CEL, etc.?  Volatility risk continues to be a primary concern for AE and other stakeholders. Such volatility issues have the potential to impact perceived accreditation fairness and reliability confidence / overbuild perception.
7. MISO’s proposed SAC calculations are complex and not reasonable to independently produce by MPs.  The SAC calculations are much more in-depth than the relatively straightforward UCAP, XEFORd calculations.  Is MISO proposing any tools for MPs to tackle this transparency issue?  Please explain and elaborate.  AE recommends MISO commit to providing an online tool with actual data on all applicable resources to support SAC calculations.
8. Provide a volatility analysis of the existing UCAP method as a comparison against MISO’s SAC volatility illustration.

WPPI reiterates a question previously posed to MISO, to which MISO has not responded.  Specifically we ask MISO to consider the option described below for generator owners with planned outages that may exceed 30 days in a season, in order to avoid a replacement obligation while addressing MISO's stated concerns.  If MISO remains unwilling to entertain this proposal, we ask MISO to explain why.

Proposed option for generator owners:

1. A resource owner aware of a >30-day planned outage could, at the time of ZRC conversion, voluntarily specify a portion of the season for which the resource would not be considered for capacity.  For example, the resource owner might specify the first 20 days of a planned 40-day outage in a 90-day season.
2. The ZRC conversion would take this into account and allow conversion of a ZRC quantity equal to—in the case just described—only 70/90 of the ZRC quantity that would otherwise be eligible.
3. The converted ZRCs could be offered into the auction and cleared in the normal fashion
4. The specified 20 days would be excluded from MISO’s after-the-fact check for planned outage exceeding 30 days in a season.
5. The specified 20 days would also not be considered as unavailable for the purpose of future capacity accreditation.
6. The resource owner would have some flexibility to change the date of the 20 days in question to accommodate outage rescheduling within the season.
7. This would satisfy MISO’s stated objective of ensuring that MISO is not in the position of relying on capacity disproportionate to what the resource is able to provide.
8. It would also address the objection Potomac Economics articulated recently that full accreditation would permit inappropriate price depression in the PRA.