RASC: Sub-Annual Construct Revised Proposal Design Elements (RASC010, 011, 012) (20210707)

The following feedback is offered by the Entergy Operating Companies ("EOCs")[1] in response to the request made during the July 7, 2021 Resource Adequacy Subcommittee meeting concerning the Sub-Annual Construct proposals and refinements.

The EOCs are unable to share meaningful feedback on MISO’s sub-annual construct proposal until MISO provides analysis detailing how the seasonal construct proposal will impact each of the EOCs’ projected seasonal accredited capacity and PRMR. Moreover, the EOCs request that MISO provide this analysis with ample time to review and well before the work of drafting BPM and tariff language begins. For these reasons, the EOCs  believe that a target FERC filing date of September for the sub-annual construct proposal is too aggressive and needs to be delayed to provide more time for MISO stakeholders to receive additional information and understand the impacts of, and provide meaningful feedback on, MISO’s proposed resource adequacy construct changes.

Below the EOCs have provided high-level feedback and clarifying questions related to the material presented in the July RASC.

Revised Accreditation Proposal and Methodology:

• MISO’s stated intent of moving away from the original “tight margin” hours-only proposal to their latest proposal is to add stability to resource accreditation. While the inclusion of both tight (Tier 2) and non-tight (Tier 1) hours attempts to address stability concerns, it does not do so in an effective manner because MISO is suggesting to place 80% of the weighting on only the top 3% of tight margin hours. The EOCs are very concerned that the 20%/80% weighting for the Tier 1 and Tier 2 hours will result in extreme accreditation volatility from one year to the next and strongly urge MISO to revise the tier 1/tier 2 weighting to a more balanced approach, such as a 50%/50% weighting.  
• The EOCs request that MISO provide additional clarification around slide 10 on what is meant by, “If there are no Resource Adequacy hours, Tier 1 is defaulted to 100% weight”. The accreditation proposal utilizes a 3-year historical look to identify the RA hours for a given season, and it is highly unlikely that a season will have zero Resource Adequacy hours for 3 consecutive years. The EOCs suggest that MISO modify this requirement by setting a minimum number of RA hours that must occur in order for Tier 2 hours to be considered in unit accreditation. For example, if any season has less than 30 RA hours (10 per season) in the 3-year period, then Tier 1 hours would default to 100% weighting. This proposed revision, working together with the proposed 50/50 tier weighting, would help add some stability to resource accreditation that stakeholders reasonably are requesting.
• In regard to the 24-hour lead time requirement for offline units, the EOCs are requesting clarification on what is included in the lead time calculation. For example, is lead time inclusive of both notification time and cold startup time?

Impact Analysis with Revised Accreditation and Requirements:

• The EOCs acknowledge and appreciate the work that MISO put into the MISO wide and zonal impact analysis; however, the EOCs are concerned that the calculated results do not capture many of the components of the proposal, as described by MISO on slide 15. Without accurate impact projections it is difficult for stakeholders to evaluate MISO’s proposals. This further highlights the importance of delaying the September tariff filing date for this proposal so that MISO has adequate time to perform and provide to stakeholders more thorough and comprehensive impact analyses.
• The EOCs are alarmed by the forecasted deficit position for LRZ 10 in the winter season and would like to work with MISO to review the ZIA calculations for LRZ 10. Given that MISO’s proposed seasonal construct is projected to have a significant change to the zonal net positions relative to the LCR requirement, the EOCs believe that MISO needs to provide sufficient time for LSEs to transition from the current annual construct to a new seasonal construct. Without providing an appropriate transition period, LSE’s may potentially suffer significant financial penalties in the PRA due to CONE pricing. This result would be extremely unjust, unreasonable, and unforeseeable. The EOCs have been prudently planning and making system investments based on an annual resource adequacy construct. For MISO to make the drastic change of moving to a seasonal construct without providing sufficient runway for LSEs to adapt would be unreasonable. MISO’s current seasonal construct implementation date, the 23/24 PY, would not provide enough time for LSEs to make the necessary investments and system upgrades in order to align with the new seasonal construct. If MISO continues with its current aggressive implementation timeline for the seasonal construct, the EOCs believe that the elevated PRA financial costs driven by moving to a seasonal PRA should be phased in across a reasonable transition period to avoid unreasonably adverse impacts to the EOCs’ customers and to ensure a reasonable opportunity to plan for the new construct.

Non-Thermal Resource Accreditation

• The EOCs are seeking additional detail related to solar resource accreditation. Slide 24 indicates that the seasonal construct solar accreditation will continue to use historic solar availability data based on peak hours. If a seasonal accreditation for solar is adopted, is MISO suggesting that solar output will be accredited based on peak production hours or during net peak load?

Planning Resource Auction

• The EOCs recommend that MISO consider a revision to NRIS/ERIS if the seasonal construct is implemented. Current and past Interconnection Service studies are based on summer peak conditions, and LSEs have obtained Interconnection Service to align with summer GVTC ratings. Under MISO’s seasonal construct proposal, the GVTC ratings for thermal resources will be increased for the non-summer seasons. The EOCs are concerned that thermal resource capacity in the non-summer seasons may be limited by the current Interconnection Service levels that align with a summer peaking system.
• The EOCs would request that MISO provide additional detail/explanation on how the ACP interacts with CONE as the provided chart on slide 30 is difficult to interpret. Additionally, the EOCs are concerned that the total CONE pricing impacts are the same for a zone whether the zone is deficient for 1 season or 4 seasons. 

Coordinated Planned Outages

• The EOCs have clarifying questions regarding the Coordinated Planned Outage three-level exemption process proposal
  • What happens when an outage is granted an exemption because it was scheduled 120+ days in advance, but the outage ends up being extended beyond the originally requested outage duration length? Does the entire outage still receive an exemption? Are extensions tied to NERC GADS event classification?
  • Does the “no outages in previous 120 days” rule apply to the 120 days prior to the time the outage is scheduled? Or 120 days prior to when the outage actually occurs?
    • Does this apply to outages of any type (e.g. Forced or Maintenance outages)?
• Does MISO intend to look at maintenance margin in relation to all of MISO, MISO South and MISO North/Central, Zonal, or on an LSE basis?
• The EOCs request additional information on the “No Harm Test” requirement. Does an LSE have to meet the requirements of every item in the “No Harm Test”?

The EOCs appreciate the opportunity to comment. 

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

ETEC appreciates the opportunity to submit feedback to MISO at this key juncture - the last opportunity before MISO proposes to finalize its RA construct design and start drafting tariff language in August. Given MISO’s proposed schedule, ETEC feels compelled to, once again, urge MISO to take the necessary time to fully vet and discuss its proposal in the stakeholder forum before proceeding to FERC.

Although MISO has been discussing the concept of seasonal RA and capacity accreditation for some time, critical design details are still in flux. For example, several aspects of MISO’s accreditation proposal have been changed and were presented this month, including the introduction of new design elements such as the 30-day seasonal, unavailability offer limitation. Additionally, MISO released new data and analysis, which is helpful for stakeholders to review, but those are still designated as preliminary and MISO has failed to provide a backcast analysis that demonstrates how the proposed changes would impact the PRMR and resource accreditations, as well as improve reliability (i.e. the reliability metrics that MISO is using to gage the merits/benefits of these proposed changes).

As a result of the evolving proposal, analysis, and data, ETEC has not been able to assess the impact of MISO’s proposal. ETEC strongly believes that it is critical for stakeholders to be able to understand the full scope of MISO’s proposal with clear, established design elements and by completing / finalizing the relevant analysis. Stakeholders should be given the opportunity to provide feedback based on a holistic view and understanding of the impacts prior to MISO drafting tariff language and filing at the FERC. ETEC requests MISO finalize and present a complete proposal across all components and design elements in August, or as soon as feasible, and provide an opportunity for stakeholder feedback before proceeding.

WEC Energy Group submits this response to MISO’s request for feedback on the July 7 RASC presentation on enhancements to the seasonal RA proposal.

Complexity and Proposed September Filing:
At a high-level, we are concerned that the Seasonal Accredited Capacity (SAC) concept is increasingly complex, especially considering each resource will have 4 SAC values. Each SAC value is determined based on hourly Emergency Max RT offers, two Tier levels with different weightings, different amounts of seasonal RA Hours, multipart planned outage “safe harbor" provisions, lead-time cutoffs, and potentially different seasonal deliverability. There are additional rules proposed for the conversion of SAC values into ZRCs for resources with more than 30 days of cumulative unavailability in a season. This complexity will require a phased implementation approach so that LSEs and resource owners are able to make adjustments to their operational strategies and to put those strategies in place. We are also concerned that several issues, such as those outlined below, require much more stakeholder discussion, which doesn’t seem feasible prior to the projected September FERC filing.

WEC Energy Group supports taking the time to get the RA construct proposal “right” rather than vetting substantive issues at FERC. We have time – the transition to more intermittent resources is underway but it will not happen overnight. The seasonal approach to resource adequacy will work under the current UCAP accreditation model. This provides an opportunity to split accreditation into a separate issue and FERC filing. We recommend that MISO and stakeholders consider this phased approach, whereby the seasonal RA construct is implemented with the current UCAP accreditation model and accreditation enhancements are developed and applied later.

Basis for 20%/80% Tier 1/Tier 2 Weighting:
The maximum number of hours for Tier 2 (RA Hours) is limited to 3% of the hours per season, or 65 hours. 97%, or about 2,100 hours is allocated to Tier 1. The proposed 20% weighting of Tier 1 is inconsistent with the Reliability Imperative’s goal of ensuring resources with attributes the system needs are available in all 8,760 hours of the year. Additionally, we note that the LOLE study already includes the impact of forced and planned outages during RA Hours in the PRMR. Weighting a resource’s availability during Tier 2 hours too heavily will introduce “double jeopardy” where-by the PRMR already accounts (and socializes) a certain level of generation unavailability and each resource is also subject to a heavily-weighted SAC derate. We recommend that MISO and stakeholders consider a lower weighting for Tier 2 (and higher for Tier 1), especially considering that the maximum number of Tier 2 hours is 65 hours.

Tier 1 and Tier 2 “Safe Harbor” Provisions:
MISO and stakeholders need to undertake further discussion, both at the RASC and the RSC, on the Maintenance Margin (MM) calculation, the determination of “sufficient” MM, the level of RA Hour risk within the MM, and consideration of partial exemptions based on the lead-time and amount of MM rather than an “all or nothing” exemption. We also note that during the 5/21 RAN workshop, MISO Staff suggested that “opportunity outages” with lead times of less than 14 days could obtain a Tier 1 exemption if adequate margin is forecasted. Further development of this concept is needed.

30-Day Cumulative Unavailability Cutoff for Seasonal ZRCs:
MISO’s proposal to not allow seasonal ZRCs for resources that are unavailable for more 30-days is ripe for gaming and creates perverse incentives. For example, a resource owner can hedge its outage risk of not obtaining seasonal ZRCs by scheduling 29 days of outages at the end of one season and 29 days at the beginning of the next. This “all or nothing” 30-day cutoff is not consistent with MISO’s value proposition that recognizes a large number of resources in a market and the diversity in resource availability. We suggest that MISO and stakeholder consider a weighted ZRC based on the length of the outage. For example, a resource that is unavailable for 75% or more of the season is not eligible to receive ZRCs, unavailable between 50% and 75% of the season is eligible for 50% ZRCs, and so on. Further stakeholder discussion and design is needed on this issue to ensure that diversity in planned outages is not negatively impacted.

Any proposal to limit seasonal PRA offers based on resource unavailability needs to be closely coordinated with the withholding provisions with Module D, both to curb market manipulation and to provide LSEs with the flexibility to mitigate risk with their own resource portfolios and ZRC offers.

Capacity Replacement:
MISO proposes to require capacity replacement for a resource that clears ZRCs in a seasonal PRA but subsequently becomes unavailable prior to the season for more than 30 days in the season. This proposal fails to consider that the seasonal LOLE study and seasonal PRMR already include the impact of forced and planned outage risk. The MISO resource adequacy pool is designed to provide “mutual assistance” when the unexpected occurs – we need to maintain this concept within the RA construct. MISO’s capacity replacement proposal, when combined with the current Module D withholding provisions, severely restricts an LSE’s ability to manage its resources to mitigate the risk of cleared capacity that unexpectedly becomes unavailable prior to a season. For example, an LSE may want to withhold some its capacity resources within its own portfolio to mitigate this risk only to find itself in violation of withholding.

We do support the concept of an option, rather than an obligation, to replace ZRCs if a resource clears the seasonal PRA but is subsequently unavailable.

MISO RASC Feedback

Big Rivers Electric Corporation

Hoosier Energy Rural Electric Cooperative

Southern Illinois Power Cooperative

Southwest Louisiana Electric Membership Corporation 

July 21, 2021

Big Rivers Electric Corporation, Hoosier Energy Rural Electric Cooperative, Southern Illinois Power Cooperative, and Southwest Louisiana Electric Membership Cooperative  (“The Respondents”) thanks MISO for the opportunity to provide feedback on the proposed sub-annual resource adequacy construct elements discussed at the July 7^th, 2021, RASC meeting.

As we’ve stated in past comments, the Respondents still lack the information to have a position either for or against all of MISO’s proposed changes to the PRA and still believe that MISO’s analysis lacks the requisite cost/benefit analysis that would convince us that these changes are necessary. The Respondents are customer-owned member cooperatives, therefore ensuring we provide our members with the reliable capacity and energy at the lowest cost is incredibly important. Thus, the Respondents are concerned that this proposal will only raise capacity prices in the region by reducing the amount of available supply and increasing the Planning Reserve Margin Requirements (“PRMR”) in both individual Local Resource Zones (“LRZ”) and the entire region without a corresponding increase in reliability.

In the presentation made in July, MISO stated that they will provide LSE specific information at a future date but could not give stakeholders a window of when that information will be provided. This information is vital. The Respondents are very concerned that this data will not be provided until well after the filing is made, perhaps until after a decision is made by the FERC, with potentially large impacts to the accreditation of their generating resources and raising costs to serve their members. We urge MISO to provide this information prior to the filing and give adequate time for LSEs to assess the impacts to their resource portfolios.

Accreditation: The Respondents appreciate MISO’s movement in their latest proposal based on previous stakeholder feedback regarding the weighting of outages during high-risk hours and the margin threshold for Tier I and II periods. The Respondents are supportive of the 25% margin threshold in inclusion of hours in Tier II but are still concerned about the 20% weighting for Tier I and 80% weighting for Tier II outages. 80% weighting for Tier II outages which only comprise of 3% of the hours in the year at most, still places a large component of the accreditation penalties on bad timing, especially during the non-summer months. Generator Operators cannot predict when shortages will occur any better than MISO can.  Punishment for not having clear “crystal ball” foreknowledge of tight margin hours is far from an incentive.  MISO should provide more substantive support and analysis behind the 80/20 split in penalties.   The impact of a much heavier weighting in Tier II will create a large amount of volatility in accreditation year to year if an unusual event occurs and increase costs to customers. The Respondents believe that the ability to avoid penalties is left to chance and prudent outage planning could still leave us with large, volatile hits to our accreditation in this latest proposal. Stressing the need to have LSE-specific data on how this proposal would impact us is further emphasized to determine the level of volatility we may see in our accreditation under this proposal.

Impact Analysis Results: The Respondents are concerned about the impact analysis MISO presented in July and the missing impacts to accreditation for LMRs, renewable resources, and understated forced outages in the LOLE modeling. MISO stated that without that information, the footprint remains in a since reductions in seasonal accredited capacity are generally offset by reductions in planning reserve requirements. While this sounds reasonable the Impact Analysis could look completely different without these additional items being factored included. This could have a dramatic impact on the amount of available capacity in each season, for all Local Resource Zones. Additionally, without individual LSE data we can’t determine which group of CPNodes the Respondents fit into on Slide 22 of the presentation.

Capacity Replacement: The Respondents are very concerned around MISO’s capacity replacement rules and the 30-day outage provision. While we recognize that availability within the season is crucial to MISO maintaining reliability, excluding resources for being unavailable for 30+ days due to a planned outage puts undue pressure on prudent outage planning. Currently MISO does not allow units that are on outage 90 out of the first 120 days of the Planning Year (i.e., the Summer Peak season which the annual requirements are based on) to be ineligible for the PRA. This is drastically different than saying a unit can’t participate in a season if an outage is 31 or more days in a 90-day season where conditions may not be as tight as the Summer. Many long-term outages consist of major overhauls of generating equipment which need to be performed, generally every 8 years to ensure that unit is performing at its best during Tier II hours and are taken when load levels are generally at their lowest (Spring/Fall). Limiting the ability to plan these outages which generally takes 4 to 6 weeks puts undue pressure on the maintenance of units which could require additional repairs once the outage is underway. The Respondents would be much more comfortable if the minimum outage time for exclusion was 45 days rather than 30 days to account for the variability in the longer-term overhauls which happen to larger units every couple of years. 30 days is simply too short and might put generator owners in a bind for an outage that was planned a year or more in advance of the PRA and increase the capacity costs to serve their customers. The Respondents are also concerned with unintended consequences of outages clustered around the end/beginning of seasons to hedge Generators against seasonal disqualification of resources as Generator Owners adapt to the new rules in the proposal. This could increase reliability risks during times which historically have not been problematic for MISO as the window for completing planned maintenance without penalties or replacement continues to narrow.

Cost of New Entry: MISO’s change to the CONE pricing has the Respondents concerned given the cost impact that we could be exposed to for one deficient season. While it may be reasonable based on the current Annual CONE values MISO calculates, $1,000/MW-day could be incredibly punitive for a single season depending on their capacity position. This also ties into the 30-day outage exclusion referenced above. An LSE may have a large unit being overhauled that’s excluded from a season with little LOLE risk and have a large amount of load exposed to CONE pricing in a season where the likelihood of a LOLE event is very low. This seems extreme and the Respondents need to more time to analyze the effects of seasonal CONE pricing.  

Planned Outage Exemption: The Respondents appreciate MISO’s clarification around the planned outage exemptions in the July presentation but remain concerned that MISO’s proposal will have a dramatic effect on the availability of units during short-term maintenance outages. Short-term maintenance outages should be exempted from penalty when sufficient margin exists, recognizing that opportunity outages taken during times of sufficient margin improve reliability of the system by keeping that unit from being forced offline during a Tier II hour. Not allowing a Tier I exemption for these outages means that no matter what we do, our capacity accreditation will be penalized for an outage during a time with a glut of capacity. This flies in the face of efficiency, reliability, and prudent outage planning and may cause changes in behavior that are detrimental to the unit’s availability when needed (i.e., more units deferring maintenance and thus increasing the potential for a forced outage later). The Respondents would recommend MISO allow Tier I exemptions for planned outages less than 14 days ahead of the current day so long as MISO forecasts adequate margins.

The Respondents also believe that since the Tariff stipulates that a long-term “Timely” outage is submitted 2 years in advance for non-nuclear and 3 years for nuclear resources, that any outage submitted within those guidelines should be exempt from both Tier I and II penalties. If MISO continues to advocate for Tier II penalties for units submitting Timely outages 2+ years ahead of time, then this portion of the Tariff language should be removed because Timely outages will be exposed to undue risk from a Tier II penalty when MISO had more than adequate time to plan for this outage.

Timing: Respondents continue to have concerns that MISO’s timeline is overly aggressive and the need for a September filing at FERC is exaggerated. While we recognize that MISO has already deferred their filing from June to September, a September filing gives us less than 60 days to complete evaluation of the proposal in which MISO still has not provided many crucial details on the mechanics of how this proposal will operate and the impacts this proposal will have on LSEs. Without this information, Respondents do not believe a September filing is feasible at this juncture and MISO should evaluate a potential phase-in of changes to allow both staff and members to get comfortable with this substantial change to the PRA.

Seasonal LOLE targets: On Slide 25 of the presentation MISO made at the July RASC, MISO intends to apply a 0.025 LOLE target for all seasons, resulting in a cumulative LOLE of 0.1 annually. While this method allows MISO to produce stable ELCC values for wind resources, the Respondents are concerned that this method may over-procure capacity when margins are sufficient and may under-procure when margins are tight. This is exactly the opposite of logic and reliability which this proposal is striving to achieve. The Respondents believe that MISO should make its best effort to capture the actual LOLE for each season and allocate LOLE to the season where the risk actually occurs rather than arbitrarily assigning LOLE risk to seasons without any true risk being calculated in the LOLE study.

Proposed PRA Design Changes (Slide 27): The Respondents are unclear about what MISO means by “seasonal correction of annual GVTC values”. Does this mean MISO will apply seasonal corrections to annual GVTC values submitted by generator owners or will generator owners have to do their own submittal of seasonal values? If generator owners are required to submit their own seasonal values, will this change require quarterly GVTC tests? The Respondents would also like more information around the seasonal provision for load forecasts and transmission losses and what MISO expects to be a “summer-level of rigor”. If this means that LSEs will have to segregate load forecasts and transmission losses by season that increases the workload on us four-fold which is something we stressed was a concern in prior comments. If this method is required, how will we know the increase in reliability is worth four times the effort to compile the information that MISO already receives in the annual process? It appears MISO’s proposal is trying to minimize its administrative impact to MISO staff while ignoring the added burden of responsibility on LSE staff members.

Thank you in advance for considering this feedback.

WPPI appreciates the opportunity to provide feedback on MISO’s revised sub-annual Resource Adequacy construct design elements.  While we provide our own comments below, we also participated in discussion with the CUOS group on MISO’s current proposal, and we support the CUOS comments

WPPI also appreciates MISO’s effort to incorporate in its revised proposal stakeholder suggestions such as including a margin threshold, using Emergency Max for both Tier 1 and Tier 2, and applying the accreditation penalty to offline resources that have lead times greater than 24-hours during Tier 2 hours only (and not during Tier 1 hours).

However, WPPI remains concerned with MISO’s very aggressive timeline when there are several key design elements that we feel need to be provided at the next RASC.  These include:

1. Indicative seasonal results for each LSE prior to September filing
2. The method will MISO use for calculating Tier 2 accreditation—will Tier 2 be calculated by looking at seasonal availability in each PY, then averaged together or is seasonal availability calculated from the total RA hours over the season over the last three PYs?
3. If resource has higher capacity in non-summer season, how will MISO handle seasonal deliverability if current NRIS or ERIS levels do not cover the extra output capability?
4. How does MISO propose to change the number-of-calls accreditation rules for LMRs in moving from an annual to a seasonal construct?  (We note that requiring 10 calls per season for full accreditation would appear significantly excessive) 
5. Will there be any adjustments to withholding rules in Module D given the increased scope of capacity replacement requirements?
6. Will the MCR have locational element?
7. Finally, as WPPI has maintained consistently throughout the RAN phase 3 discussion, accreditation needs to be aligned with the LOLE analysis that determines the capacity requirement. Accordingly, we ask MISO to explain how their proposed accreditation changes are consistent with the assumptions used in the LOLE analysis. 

Specific feedback comments corresponding to slides in the July RASC presentation are included below.

Slide 10:

It would be beneficial to have a reasoned justification for the 80/20 tiered weighting for Tier 2 and Tier 1 hours.  We understand MISO wanted 100% Tier-2 hours weighting and feels this may be some sort of compromise, however, to reduce volatility in accreditation a more equalized weighting could be beneficial to LSEs for long-term planning.  We do not see any reason why a 60/40, split wouldn’t achieve MISO’s goal of weighting Tier 2 hours heavier than Tier 1 hours.

Slide 11:

It is critical that MISO unambiguously describe how Tier 2 availability will be calculated and incorporated into accreditation prior to filing tariff changes at FERC.  In response to WPPI’s question during the July RASC meeting, MISO proposed two interpretations of the language on slide 11: Seasonal RA hour aggregation over three PY, or seasonal PY accreditation averaged over three years.  Both options have potential issues and we provide some suggestions on both approaches below. 

Interpretation 1:

Seasonal RA hour aggregation over three PY:

-              If calculating accreditation using availability of RA hours in a season over 3 years, then the “Default to 100% weighting for Tier 1” proposal holds no weight, because each season will have at least some RA hours over three years.

-              Also, with seasons that have limited RA hours (Central+North Spring 69 hours, South Winter 77 hours), this reduced amount of RA hours could have drastic impacts on accreditation on a yearly basis.

 Therefore, we view this proposal for calculating Tier II accreditation to be problematic and recommend that it shouldn’t be pursued. 

Interpretation 2:

Calculating Seasonal Accreditation for each PY, then averaging three PYs together:

-              This too brings issues of seasons with very few RA hours.  For example, spring PY2018-19 in the N+C region where there are only 4 RA hours that all occur on one date 3/6/2019 from HE 7-10.  This would end up heavily penalizing the generator unfortunate enough to have been offline during that morning.  If MISO adopts this approach, we would suggest that in instances of less than 15 RA hours in a Planning Year, you adopt the “Default to 100% weighting for Tier 1” as well. 

Alternative proposal:

An alternative approach MISO could adopt for individual seasons that have fewer than 65 RA hours would be to adjust the 80% weighting for Tier II accreditation in those seasons. 

For instance, for the Central + North Spring season in PY2018-19, there are only 4 RA hours.  In this season we would propose using a calculation of Tier 2 weighting of

80% Tier 2 weighting * (# of RA hours / 65 RA hour standard) = 80% * (4/65) = 5% weighting to Tier 2 hours and 95% weighting for Tier 1 in the spring 2018/2019 season. 

A similar calculation can be made if calculating accreditation for specific seasons over three Planning Years.  Using Spring season in Central + North, where only 69 hours have been identified over the last three PYs:

80% Tier 2 weighting * (# of RA hours in all three PY / (65 RA hours per PY * 3 PY))

= 80% * (69 RA hours / 195 Possible RA hours)

= 28% weighting for Tier 2 hours and 72 % weighting for Tier 1 hours.

Slide 12:

Slide 12 provides the formula for calculating the SAC/UCAP ratio.  At slide 19 MISO provides an accreditation example for LRZ 1 in which the SAC/UCAP ratio is specific to LRZ 1.  Does MISO intend to calculate this on a MISO-wide basis or an LRZ-specific basis?

Slide 27:

MISO’s proposal of “cannot offer ZRCs expected to be unavailable for >30 days” raises questions for us.  The current policy focused on the first 90 days of the Planning Year may be reasonable given that virtually all identified LOLE in official MISO annual LOLE studies to date has fallen within the first 90 days of a Planning Year.  In contrast, it appears that MISO’s proposed adaptation of this rule to the seasonal construct will no longer focus on the highest-risk period.  Accordingly, the logic of the current rule does not appear to straightforwardly transfer to the seasonal-construct context.  Moreover, MISO’s proposal appears to run contrary to what we believe are two key principles that should govern design of the resource-adequacy construct.  Firstly, accreditation should be tied to the LOLE analysis.  We suspect that MISO’s LOLE analysis finds capacity value for resources assumed to have planned outages of 30 days or longer, and thus that MISO’s proposed rule will invalidate capacity in a way that is inconsistent with the PRM determination.  Secondly, to the extent possible, the impact on accreditation of future outages known in advance of the PRA should be comparable to the impact of those not known until after the auction, or to forced outages not known in advance.  MISO’s proposed rule provides no assurance of comparable impacts.  We note in particular that the proposed rule may pose difficulty in the case of nuclear re-fueling outages.  At a minimum we would ask MISO to compare the proposed 30-day threshold to standard nuclear refueling outage duration.  Finally, we are concerned that this rule will lead units to focus on scheduling outages on the borderline of seasons so they can take their longer outages and this will lead to more generators competing for these seasonal transitions, which would be counterproductive to the goal of efficient outage scheduling.  This will be especially problematic in any seasonal transition into or out of summer.  Other approaches to dealing with long outages are available and should be considered.

Slide 28:

Generally, the concerns we have regarding pre-auction capacity disqualification, discussed in the context of slide 27, also apply to the post-auction capacity disqualification proposal on slide 28.  In addition, we have significant concerns about the availability, price and ease of procurement of uncleared ZRCs in case of a 30-day urgent outage.  Due to uncertainty around potential lengthy forced outages, we could see some LSEs choosing to withhold some capacity as a precaution, a situation that would both limit the available surplus capacity to be available for replacement and require us to review Module D withholding rules.

Slide 30:

MISO’s proposal appears likely to have the effect that, for a 4-season deficiency, generators that clear for the entire year will be paid the annual CONE value, whereas for a 1-season deficiency, they will be paid this value plus the auction clearing prices for the other three seasons.  Is this correct?  If so, was this MISO’s intent? 

Slide 38:

We have concerns about MISO’s proposed three-level exemption process.  In particular, we are concerned about the “no outage in previous 120 days” language.  As written, this appears arbitrary and unreasonable.  If a generator chooses to have two one-week outages in a given period vs one two-week outage, we do not feel that these should be treated differently and receive different exemptions.  Also, this provision fails to distinguish long from short prior outages.  In instances where a generator has experienced a short outage in previous 120 days, this should not impact it from receiving an exemption for a future outage.  

Also, MISO’s proposal is unclear as to whether the “no outage in previous 120 days” applies to when the outage request was made or when outage begins.  

-        If the “no outage in previous 120 days” applies to when outage request was made, then is the generator permitted to have an outage in the next 120 days and still retain their exemption as long as they did not have an outage 120 days prior to the making the original outage request?

-        If “no outage in previous 120 days” applies to beginning of the outage, then generators will not be guaranteed exemption until the outage begins and it is known that they did not have to take an outage in last 120 days.  That level of uncertainty is problematic.

Therefore, we suggest that the language of “no outage in previous 120 days” be removed for simplicity and to provide generators some certainty of being able to actually obtain exemptions for their outages.

Alliant Energy appreciates MISO’s preliminary results analysis.  MISO needs to provide additional analysis and data to understand the full impacts and risks of the proposed construct.  As a high-level summary in response to the seasonal construct slides:

• Volatility - Tight margin hour accreditation calculations are extremely limited, and the 80/20 weighting is arbitrary and does not suitably mitigate volatility.
• Projections - Analysis based on the current Planning Year does not uncover the challenges for the near-future.  MISO needs to identify such future challenges to understand the speed at which LSEs will need to react to cover their obligations.  MISO should perform impact analysis with 5- and 10-year models.
  • This is critical as MISO identifies that Zone 1 (MN) and Zone 3 (IA), which have high renewable penetration, are the most affected.  Due to the pace and direction of evolution in the generation industry, many other zones will be soon be in a similar position and MISO needs to provide transparency for these zones and the footprint.
• Outage exemptions - We are concerned that MISO’s lack of exemption from Tier 2 impacts for outages <120 days and/or maintenance margin <0 sets an unrealistic expectation on operations and unit performance.  This concern is further magnified by an 80% weight on a limited number of hours which greatly impacts unit accredited capacity, without necessary providing a good measure of future performance.  The end effect may be to drive out the dispatchable resources that MISO desperately needs.
• Data requests - Specific data requests related to the presentation:
  • Provide slide 21 (zonal LCR capacity for all seasons) at the PRMR level, which is also an obligation for LSEs. 
  • Provide, confidentially to each party, the individual unit data UCAP and SAC for all seasons.  In essence this is a granular reveal of the data presented in slide 22 for all resources and in all seasons (not just winter).
• Resource Planning guidance - MISO needs to provide a template of forward-looking resource planning information so LSEs can economically and reliably develop plans for the short-term and long-term future.  MISO needs to provide this information now, even if indicative, to fully unveil the seasonal construct.  LSEs need 5-year and 10-year projections of seasonal values at the footprint and zonal level for the following:
  • PRM and PRMR for footprint and individual zones,
  • LRR and LCR,
  • CIL and CEL, with noteworthy step changes,
  • Wind and solar ELCC,
  • 4-hour battery storage ELCC,
  • Long-duration storage ELCC (8-hour, 12-hour, 24-hour, 72-hour),
  • Theoretical dates and times of projected seasonal peaks and tight margin hours correlating with footprint and zonal LCR and PRMR (especially if this is projected to be night/day to understand solar performance).

Additional detailed concerns not addressed above are noted below:

• Slide 15 – It is a significant concern that MISO has not captured all impacts in its preliminary analysis, in particular wind and solar (and presumably storage for varying duration) ELCC.
  • MISO states that the largest impact to zones is heavy renewable penetration (such as Zone 1 and Zone 3) – which drives the need for further caution as it flags these inputs as a sensitivity.
  • We understand that some of this information (wind and solar but not storage) will be presented in September.  Stakeholders; however, need to understand potential impacts from proposed changes prior to a FERC filing being made.

Southern Minnesota Municipal Power Agency, (LBA designation SMP) appreciates the opportunity to provide feedback to the RAN RA Construct Proposal presented at the July 7, 2021 RASC meeting.  SMP has several concerns with this proposal that are addressed in the CUOS organization’s feedback document.  However, there is one specific item we would like to elaborate on since it will have a significant impact on our organization.  On slides 27 and 28 of the presentation, MISO discusses a proposal which would restrict a generator’s eligibility to participate in the seasonal capacity auction or otherwise require them to replace ZRCs (the exact details are still a little unclear) if they have an outage which is “known prior to the start of the season and is expected to exceed 30 days”. SMP believes that this proposal creates an expectation that is technically impossible to achieve and is punitive to specific classes of generators.  SMP also believes that this proposal will ultimately result in other unintended consequences that will harm reliability rather than enhance it. 

All base load steam powered generating plants (coal, nuclear, and combine cycle) require long lead time planned outages on an annual or biennial basis to perform overhauls and other major maintenance on their boilers, steam turbines, and balance of plant systems. These long lead time outages/overhauls are usually scheduled at least a year in advance due to the longer lead times required to procure and manufacture parts and materials, schedule contractors, and coordinate the timing of other long lead time outages with other generators in a company’s portfolio. 

Since base load generating units are normally on-line, these annual or biennial long lead time planned outages/overhauls are the only time these units can perform the major maintenance activities needed to keep the plant operational and reliable.  These outages are generally scheduled during the spring and fall seasons to minimize any impact to the system and are fairly lengthy in duration due to the nature of the work.  A typical coal boiler or steam turbine overhaul requires anywhere from 4 to 10 weeks of downtime depending on the scope of work.  In most all cases, it is technically impossible to complete this work in under 30 days.

The original purpose of the current business rule (which excludes generators from the auction if they have a planned outage the extends beyond the first 90 days of the planning year) was to discourage generators from scheduling a planned outage during the entire summer season primarily because the LOLE study did not contemplate and was never designed to account for summertime planned outages.  SMP feels that shortening this rule from 90 days to 30 days and applying it to all seasons is extreme and unnecessary.  These long lead time planned outages, which have historically been schedule in the spring of fall, have always been included in the LOLE process and have always been taken into in consideration when calculating the PRM requirements.  As a result, there is no need to create an additional restriction on base load steam units for these types of planned outages. 

The primary goal of any policy or business practice is to discourage or incent certain behaviors, however there is no action which a steam powered generating plant can take to prevent the need for these longer duration planned outages and therefore no way in which these plants can achieve this intended goal.  These outages cannot be split up into multiple smaller outages due to the scope and nature of the work.  These long lead time schedule outages are an essential business function, and this proposed rule will penalize plants for something that is a normal and necessary part of their business. 

This proposal will have an adverse impact on every base load thermal generating plant in the MISO footprint and some intermediate and peak load facilities as well.  Utilities with multiple generating units will be especially hard hit since they typically schedule multiple long lead time planned outages during any given spring or fall. Since each of these outages will be greater than 30 days, it would require them to withhold or replace multiple generators ZRC’s during the same season.    For some utilities, these base load generators can represent a large portion of the utility’s capacity supply.  If they are forced to replace this capacity due to this rule, it will place a significant burden on these utilities. In SMP’s case, our largest base load steam plant represents 56% of our capacity supply.   If the PRM were 8%, this would require SMP to carry 64% planning reserves for the applicable season.  This would essentially nullify any benefits of belonging to the reserve sharing pool by requiring a SMP to cover their own single worst contingency. SMP believes that it is inappropriate and unrealistic to expect any utility to carry such extreme planning reserve margins. 

It is unclear to SMP if the intent of this proposed policy is to apply only to planned outages or also forced outages.  If the intention is to apply it to forced outages as well, this would also be an unnecessary and punitive since forced outages are already accounted for in the resource accreditation process.

If this new policy moves forward as proposed, SMP fears that it will cause unintended consequences that will overshadow any perceived benefit.  Since these long lead time planned outages cannot be shortened or prevented, utilities will be forced to schedule these outages across seasonal boundaries in order to avoid this penalty. Since this proposed rule will impact all base load steam facilities in MISO, this would result in multiple utilities scheduling multiple outages across the same seasonal boundaries. This could create a significant resource shortfall during critical summer and winter months.   

There have also been some suggestions that this 30-day requirement be made even shorter, possibly 9 or 10 days.  This change would not only impact all long lead time planned outages, but it would also impact almost every near-term “opportunity” planned outage.  This would result in even more generating facilities attempting to schedule more planned outages condensed across a smaller seasonal boundary window.  

In conclusion, SMP feels that this proposed rule 1) is unrealistic since it creates a goal which is technically impossible to achieve, 2) unfairly targets base load steam facilities, 3) is unreasonable since it creates excessive planning reserve requirements for utilities with large base load generation, 4) is unnecessary since these outages are already accounted for in the LOLO and resource accreditation process, and 5) will result in unintended consequences that decrease overall reliability.

July RASC Feedback

DTE appreciates the opportunity to provide feedback on MISO’s revised sub-annual Resource Adequacy construct design elements. While DTE appreciates that MISO has attempted to incorporate elements of stakeholder feedback and adjusted the initial accreditation proposal, DTE is still concerned with the aggressive filing timeline and believes that the accreditation elements of the proposal need to be reviewed more thoroughly before it is ready for filing with FERC. Therefore, DTE strongly recommends that MISO delay any such filing pending further stakeholder discussion on key issues.

Hour selection/Stability in RA Planning –

Tier weighting is unjustifiable in its current 80/20 state with MISO offering no explanation on how it arrived at this weighting. The Tier 2 weighting still introduces the potential for significant volatility in accreditation with 80% of a resource’s capacity being determined by 3% of tight margin hours in the season (~65 hours). These 3% tight margin hours occur randomly and cannot be predicted in advance by stakeholders. Further, past performance during a small sample of randomized tight margin hours would have little to no correlation with performance in future years. Due to this, we believe the currently proposed 80% weighting for Tier 2 hours to be too high and the 20% weighting for Tier 1 hours is not high enough in order to meaningfully reduce volatility in accreditation or to accurately capture expected resource performance in a season. DTE requests that MISO provides analysis of accreditation with differing tiered weightings to help stakeholders understand what levels make sense for each tier and how large of an impact this weighting determination has on the amount of accredited resources in each zone.

The new SAC method also shows a large % change in the accreditation in winter resources with ~25% of resources having a >50% change. Such dramatic changes in accreditation are quite concerning and highlights the potential volatility of the proposed tiered weighting structure. MISO should release unit-specific changes to resource owners so that they can evaluate the impact on their own portfolios.

A proposed change of this magnitude should also be accompanied by unit-specific examples, recalculating prior Planning Resource Auction metrics and clearing results, and a candid comparison between those results and MISO’s expected change in market participant behavior. DTE does not feel that MISO has presented enough data to justify these broad accreditation changes and recommends delaying filing any accreditation changes until the impacts can be better evaluated and are understood by all stakeholders.

Wind and Non-wind intermittent resource accreditation –

If MISO moves forward with the current traditional resource accreditation changes, then MISO should ensure that all resources are aligned in how they are accredited. For example, it does not make sense that wind resources would be accredited on seasonal ELCC while other traditional generators are accredited on their performance of the tightest 3% hours in a season. This could be viewed as preferential treatment to specific resources if they are receiving higher accreditation due to differences in accreditation standards.

LMR accreditation –

During the July RASC, MISO mentioned that the current 10+ call limit requirement for full annual accreditation would be adapted for each season (i.e. 10 calls per season for accreditation). This would be a large increase in the requirements for LMRs which may disincentivize LMRs from participating in the PRA when they would otherwise be able to support reliability under the current annual rules. Can MISO clarify the requirements for LMRs in the seasonal construct?

Seasonal DR accreditation –

Temperature sensitive DR could have very different capability depending on where in the season it is required for accreditation. Currently all demand reduction is at the assumed peak load in the summer. In a seasonal construct, would we assume the seasonal peak load occurs at a certain date in order to determine the volume of DR available and would the DR be subject to the same 30-day eligibility rule? For example, an interruptible air conditioning DR program would have some capability in early September for the fall peak but would likely have no capability in October & November. Would this type of resource receive 0 ZRCs because for most of the fall it is not available, or would it receive the expected amount at peak (typically in September where it would be available)?

Proposed PRA design changes for seasonal construct implementation –

DTE agrees with the current proposal for GVTC, load forecasts, and transmission losses.

Resource Auction Eligibility/Enhanced Capacity Replacement –

Resource owners face increased risk in their ability to procure replacement capacity, which may prove difficult to obtain

• Stakeholders unequivocally recognize the importance of market power mitigation and proper prohibitions on economic or physical withholding.  However, MISO’s latest proposal for capacity replacement requirements combined with current must-offer requirements from Module D provide market participants with few other options to manage their risk of having to procure replacement capacity

• Under the construct that is currently in place, the risk associated with being able to procure replacement capacity is relatively low
  • Resource owners are not obligated to procure replacement capacity for most outages
    • Forced outages are already accounted for in setting the PRMR, so with the exception of catastrophic outages, there are currently no provisions for replacement capacity arising from a forced outage
    • Replacement capacity is not required for planned outages
    • Resources with outages (planned or forced) that encompass 90 of the first 120 days of the planning year will be precluded from PRA or FRAP participation
• As a result, resource owners can freely offer their full portfolio into the PRA without the concern that replacement capacity may become necessary

• The construct being proposed introduces significantly more risk into market participant capacity positions
  • Seasonal auctions are cleared annually, but in the intervening time period between auction clearing and the start of the planning season, which could be as long as 12 months, a market participant’s capacity position could change significantly due to forced or planned outages
  • However, the resource adequacy obligations for these resources would remain unless the market participant can obtain replacement capacity
  • Since market participants are more or less required to offer all of their resources into the PRA, market participants are unlikely to have uncleared ZRCs in their own portfolios to cover potential shortfalls, leaving them dependent on the availability of replacement capacity, which can be challenging to procure

The inability to offer ZRCs into a seasonal PRA when a resource is unavailable for more than 30 days may lead to gaming in outage planning, but modifications could be made to address this

• For example, resource owners seeking to fit extended outages into a planning year may seek to schedule a 29 day outage at the end of one season and a subsequent 29 day outage at the beginning of the next season, stressing maintenance margins at the beginning and end of seasons
• An alternative approach may be some level of ZRC weighting based on the length of the outages (e.g., 0% credit for outages greater than 68 days, 50% credit for 45-68 day outages, 75% credit for 30-44 day outages)

• Extending the unavailability window may be another option which may reduce the incentive for gaming, particularly for resources which may struggle to fit a typical planned outage into the 30-day window
  • Stakeholders observe that the requirement for the current construct is that resources must be available for 90 of the first 120 days (or 75%)
  • Applying this threshold to a 90-day season would suggest a requirement of 68 days

This set of requirements will likely have far-reaching and costly implications for customers but has only been introduced to stakeholders two months prior to filing.  Given the potentially substantial and harmful impacts to customers, these provisions merit much more than a month’s worth of consideration. 

Coordinated outage planning –

Feedback from stakeholders on the ACAP proposal supported bringing in the RAN Phase 1 improvements into the current accreditation methodology. In response to this, MISO has brought in a limited version of the current rules. Under the existing rules, market participants can take near-term outages from 14 to 120 days out when there is adequate margin with no penalty. These “opportunity outages” should help improve overall system reliability for periods when the margin is tighter. Under the current proposal, there would only be exemptions to penalties for the tier 2 hours when the outage was submitted >120 days in advance. This reduces the ability for resource owners to take advantage of periods of high margin due to increased risk of penalty to the tier 2 hours (80% of accreditation). If MISO is not confident in their maintenance margin forecasts, more work needs to be done on their end to improve forecast reliability so that resource owners can plan outages prudently. If planned outages are an issue, then MISO should consider modifying the outage exemption process and not create a new problem where one does not exist (potential penalization and avoidance of planned maintenance outages).

DTE also requests that MISO clarifies the interaction of planned outage exemptions and the tier 2 hours that will be evaluated for accreditation. Will planned outage exemptions reduce the number of hours evaluated in a season or will the exempt hours give the unit 100% credit. For example, if a season has 65 RA hours, a resource has an HRE for 45 RA hours, and is available for 50% of the remaining hours (10 RA hours) how would the tier 2 accreditation end up?

• Option 1: Exempt hours reduce number of hours in season
  Tier 2 % = 10 RA hours available / (65 RA hours in season – 45 RA hours exempt) = 50%
• Option 2: Exempt hours provide 100% credit
  Tier 2 % = (10 RA hours available + 45 RA hours exempt)/ 65 RA Hours = 85%

MEAN, MJMEUC, MPPA, MRES, SMMPA, and WPPI generally support the feedback submitted by SMMPA and WPPI.

I'd be happy to discuss.

David Sapper

dsapper@ces-ltd.com

Environmental Sector Comments on

MISO Resource Adequacy Reforms presentation dated July 7, 2021

The Environmental Sector appreciates this opportunity to submit comments on the RAN Reliability Requirements and Sub-annual Construct proposal published by MISO on July 7, 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, and March 2021, the Environmental Sector appreciates MISO’s extensive work in developing this proposal but also remains concerned that MISO has not clearly supported many elements of its proposal with factual and theoretical development to justify each point.  Below, the Environmental Sector will describe some of its chief concerns in more depth.

Planning Reserve Margin calculations

MISO’s February 3, 2021 presentation at slide 12 stated that Planning Reserve Margin (PRM) requirements would be calculated on a seasonal basis using 2-4 sub-annual periods.  Slides 13 and 31 stated that seasonal PRM requirements would be calculated by multiplying seasonal requirements in terms of UCAP by corresponding ACAP/UCAP conversion ratios.  Subsequent monthly presentations, including Slide 28 of the June 9 presentation, indicated that Loss of Load Expectation (LOLE) requirements would be “refine[d]” in the July-August period, but did not presage a significant change in the methodology.

However, MISO’s July 7 presentation introduces for the first time, at Slides 12-13 and 48-50, the concept that the PRM Requirement (PRMR) in the new construct will be based on a “Seasonal Accredited Capacity” (SAC) concept.  MISO has not made clear how the new SAC concept would differ from the previously proposed ACAP methodology.  Additionally, it would be helpful to know MISO’s projections of the actual seasonal PRMR figures that are likely to manifest under the first delivery year using the most recently proposed construct.  Will these be close to the seasonal PRMR figures shown on Slide 31 of the February 3 presentation?  If not, what PRMR figures are expected by season?  Additionally, it would be very helpful to know MISO’s projection for how accreditation will change for each major resource type as the system transitions from UCAP to SAC accreditation.  Utilities, resource owners, and developers will need to understand how accreditation for their resource types will be changing under this proposal and in the future – which relates to our comments below on the Effective Load Carrying Capability (ELCC) methodologies for wind, and in the future solar.

ELCC methodologies

At Slide 25 of the July 7 presentation, MISO introduces a new methodology for assigning seasonal ELCC to wind resources.  Crucially, the methodology for thermal resources’ seasonal accreditation will apparently be based on real-time offers during the tightest hours (Slides 10, 51-53) while wind resources’ seasonal ELCC will be determined with a planning-based methodology using assumptions of 0.025 LOLE in each of the four seasons.  MISO has not explained why a different accreditation approach should be used for thermal vs. wind generating resources.  Moreover, MISO has not adequately explained to stakeholders why each season, including the two shoulder seasons, should be assumed to have an artificial 0.025 LOLE value for the wind analysis, when the true loss-of-load risk in the shoulder seasons may be approaching zero.  Under this approach, wind resources may be penalized for relatively poorer performance in the shoulder seasons, even though such poorer performance would not actually be contributing to any appreciable loss-of-load risk.  And if such a methodology is used for solar in the future, solar resource accreditation would likely be reduced in the summer season due to an artificially low LOLE value.  In general, MISO has not adequately illustrated how the new approach at Slide 25 (allocating LOLE of 0.025 to each of the four seasons) would affect the accreditation of wind or other resources, versus the former approach of using an annual 0.1 LOLE and maintaining the risk profile from the original LOLE calculations.. 

Moreover, hours with the actual tightest margins, as defined on Slide 10 (declared MaxGen hours plus the top 3% of tightest margin hours in a season), are not necessarily the same as the hours that are most important from a LOLE perspective, which are determined ex ante.  It is not clear why accreditation should look at the contribution to one set of risky hours for one resource type, but the contribution to a potentially different set of risky hours for another resource type.  MISO has not explained the different hour sets chosen, or how an alternate choice of hour sets would change accreditation results for different resource types.

These asymmetric treatments, taken together, mean that MISO’s approach is not accomplishing the objective stated at Slide 5 of the July 7 presentation: “Align resource accreditation with availability in the highest risk periods.”  MISO must justify and ensure stakeholders understand the differing treatment of different types of resources.  In addition, MISO must do more in-depth analyses to determine how the two risk metrics, LOLE and tight margin hours, are related, and perform a root-cause analysis to determine the best metric, or combination of metrics, to use in a consistent manner.

Tariff considerations

If MISO is to file a Federal Power Act Section 205 tariff revision proposal at FERC in September or any future time, MISO must establish that the new regime is just and reasonable, so as to give FERC good cause to approve it.  16 U.S.C. § 824d(a).  One principle of just and reasonable rate structures is that they not be unduly discriminatory.  Morgan Stanley Capital Grp. Inc. v. Pub. Util. Dist. No. 1, 554 U.S. 527, 533 (2008) (quoting FPC v. Sierra Pacific Power Co., 350 U.S. 348, 355 (1956)).  Another principle of just and reasonable rates is that they must “appropriately compensate” market actors.  FERC v. EPSA, 577 U.S. ___, slip op. at 10, 30, 33 (2016) (holding that FERC engaged in “reasoned decision making” when it approved a proposal setting certain wholesale compensation rates for demand response based on “the [] value [provided] to a wholesale market”).  To be fair, courts have deferred to FERC’s judgment in approving a resource adequacy structure, if well supported.  In the PJM context, the D.C. Circuit Court of Appeals upheld a FERC ruling, holding that “[t]he Commission’s policy decision [on capacity market structure] is the type of policy judgment to which we afford deference, and that deference is justified by the record” (emphasis added).  Advanced Energy Mgmt. Alliance v. FERC, Case No. 16-1234, slip op. at 23-24 (D.C. Cir. 2017).

With these points in mind, the Environmental Sector urges in the strongest terms possible that MISO establish a complete record, backed by solid analysis, justifying its choices and projections for each and every element of the proposed seasonal resource adequacy structure, including why different resource types are treated differently, as well as how the proposal is intended, at the highest level, to adequately compensate resources for their ability to avoid loss of load events in what are likely to be the system’s tightest hours.

We thank MISO for the opportunity to submit these comments and look forward to continued close engagement on this important topic.

AMES generally supports SMMPA's and WPPI's feedback (as do MEAN, MJMEUC, MPPA, MRES, SMMPA, and WPPI).

David Sapper

dsapper@ces-ltd.com

See attached PDF

The OMS Resources Work Group (OMS RWG) appreciates this opportunity to provide feedback to MISO on its latest proposed Resource Adequacy reforms that are part of the RAN initiative. These topics on Resource Adequacy are extremely important to the state regulators, and we look forward to continued work with MISO to address any outstanding concerns. This feedback does not represent the views and positions of the OMS Board of Directors.

The OMS RWG provides comments and questions on the following topics (with slide numbers included, as requested):

• Inclusion of a 25% Margin Threshold in determining Tier 2 hours (Slide 11)

The OMS RWG supports MISO’s decision to include the 25% Margin Threshold as part of the qualification for an hour to be considered a Tier 2 hour. This will help ensure that the hours captured in Tier 2 truly reflect some level of tightness on the system and that resources won’t unjustly face significant accreditation penalties for being unavailable during hours that aren’t truly “tight”.

• Tiered Weighting in the Accreditation Calculation (Slide 10)

The OMS RWG requests that MISO provide additional information on its decision to split the weighting between Tier 1 and Tier 2 at 20/80. While the OMS RWG understands the importance of being available during the tightest hours of a given season, some work group members believe that this weighting does not value the performance during Tier 1 hours enough. Given that Tier 2 will only consist of ~3% of the hours in a given season, performance during those hours will always have a significant impact on the accreditation of resources, even if Tier 2 is given a slightly lower weighting than 80%. The OMS RWG would be interested in seeing the accreditation impacts from different weighting percentages between the two tiers.

• Accreditation of LMRs in a Seasonal Construct (Slide 24)

After the discussion on LMRs during the July RASC, there is still uncertainty as to how these resources will be treated in a seasonal construct. While the OMS RWG does not have a specific recommendation at this time, we ask that MISO not significantly deviate from the approved accreditation changes and availability requirements that will go into effect starting with Planning Year 2022/2023. If MISO believes significant changes will be necessary to allow for LMR participation as part of the initial implementation of the seasonal construct, the OMS RWG notes that states will need sufficient time to make and approve the necessary changes to retail tariffs and contracts on file with the retail regulator to accommodate those changes.

In addition, the OMS RWG requests information on the amount of LMRs that will be impacted by the change to seasonal based on MISO’s knowledge of existing resource availability throughout the year.

• Decision to move September back into the Fall season (This is not reflected on a slide)

After the explanation at the July RASC, the OMS RWG understands MISO’s decision to move September back into the Fall season for the initial implementation of the seasonal construct. For purposes of the upcoming Resource Adequacy RAN filing at FERC, we support the decision. However, because of the significant impact that including September in the Fall season has on the capacity requirement for that season, we ask that MISO continue to work on the makeup of the seasons within the new resource adequacy construct and determine what changes would be necessary to accommodate asymmetrical seasons within the construct.

• Offline resource 24-hour lead-time for accreditation calculation (Slide 10)

While we do not necessarily disagree with the decision, the OMS RWG requests information from MISO on the justification for allowing offline units with a lead-time of up to 24 hours to receive full accreditation. Specifically, we seek justification for why these resources are allowed more lead-time relative to the expectations for LMRs in the recently-approved LMR accreditation changes.

• Resource Auction Eligibility (Slide 27)

The OMS RWG asks for clarification on planned outages that overlap two seasons. Part of the new eligibility requirement is that a resource expected to be unavailable for more than 30 cumulative days within a season would not be allowed to participate in that season’s auction. Our question in regard to this is: would a resource that takes a planned outage of greater than 30 days over the course of two seasons (ex. last 30 days of summer and first 30 days of fall) be eligible to participate in both of those seasons, assuming no other known outages during those seasons?