RASC: Proposed Options of Construct Design Elements (RASC010, 011, 012) (20210310)

Item Expired
Topic(s):
Resource Adequacy

In the March 10 meeting of the Resource Adequacy Subcommittee (RASC), stakeholders were invited to submit feedback on Resource Availability and Need (RAN) reliability requirements and sub-annual construct proposed options of construct design elements.  Please reference slide numbers where feedback directly responds to content from the presentation.  

Comments are due by March 24. 


Submitted Feedback

AES Indiana appreciates the opportunity to provide feedback on MISO’s efforts to develop a sub-annual capacity construct.


• Feedback Item: What if the annual LOLE study shows little risk in a season? (Slide 15)
o Response: AES Indiana believes that more detailed examples are necessary to develop an informed opinion. These examples should demonstrate how reserve margin would change due to changes in the seasonal LOLE allotment. 0.01 LOLE is 10% of the total annual LOLE and allocating 10% of the total annual LOLE to the Spring and/or Fall seems like a consequential change without underlying analysis.


• What determines an RA hour? (Slide 17)
o AES Indiana believes that detailed examples and data for each option are necessary to develop an informed opinion. Of the options presented, AES Indiana prefers the option(s) that result in the utilization of the largest number and most diverse set of RA hours (i.e. hours that represent more than one event). However, AES Indiana is concerned that none of these options solve the major problems AES Indiana currently has with MISO’s sub-annual ACAP accreditation construct, namely incentivizing prudent maintenance/outage planning.


• Should there be a lead time threshold for offline resources when calculating ACAP? (Slide 18)
o AES Indiana supports option 2, which is utilizing a 24-hour lead time for offline RT offers to identify RA hours. An unintended consequence of developing a lead time for offline RT offers that is less than 24 hours is that it could incentivize resource owners to must-run baseload units in order to avoid being subject to this provision. Additionally, it seems this places additional risk on a resource owner who is following economic signals provided by MISO.


• Should there be a lead time threshold for offline resources when calculating ACAP? (Slide 19)
o AES Indiana requires more information to clarify how this concern is different than the concern on Slide 18 of the presentation. However, AES Indiana agrees that lead times should be considered in resource accreditation.


• Would RA hours impact ELCC calculations? (Slide 20)
o AES Indiana requires more data and examples for each option to develop an informed opinion. AES Indiana suggests MISO provide data around what accreditation would have looked like with last year’s data for each of the proposals. Option 3 would fail to recognize the value a resource provides in reducing the gross peak, even if the incremental reduction is diminishing.


• Where should months that could have hot weather go? (Slide 21)
o AES Indiana recognizes that May and September can exhibit high peak summer weather. However, including May and September in the summer shortens the outage planning season and could detrimentally focus the periods of time when utilities plan their outages.


• What about Load Serving Entity load forecasts and allocation of transmission losses? (Slide 22)
o AES Indiana requires more information as to how each of these options would produce different results to provide a meaningful response.


• When should a resource not participate in an auction? (Slide 23)
o AES Indiana supports the second option, which is that a resource cannot offer ZRCs if the resource is expected to be unavailable for greater than 45 days. MISO may need to coordinate and stagger outages to prevent excessive overlap. While a specific resource outage of 45 days over the summer could be problematic, MISO could mitigate issues with outage coordination.


• How would GVTC be submitted for seasons? (Slide 35)
o AES Indiana supports the first option: MISO to weather adjust the annual values for use in various seasons. AES Indiana believes that it would be burdensome to submit GVTC values seasonally and weather adjustment is a proven method.


• Should MISO rely on resources known to be unavailable or require them to be replaced to ensure the availability of resources cleared to meet lowered seasonal PRM targets? (Slide 36)
o AES Indiana leans toward supporting the second option, only requiring replacement per Option 1 if prior to the start of the season. AES Indiana requires more clarification regarding whether the proposal refers to the time-period between the auction window and the start of the planning year, or whether this refers to a forced outage that occurs within a season (in which case it should not have to be replaced because MISO pools this risk).


• Should there be rules specific to outages that impact multiple seasons? (Slide 37)
o AES Indiana supports the first option: no specific rules, can create later if need identified. AES Indiana is concerned that more rules around outages effectively constrains outages to occur within a smaller window of time, which could create new problems. AES Indiana suggests that MISO let the previous rule that states outages within a season must be 45 days or less (contained on slide 23) guide the cross-season outage planning construct. Less restrictions lead to a greater ability to distribute risk.


• Should the DA must offer requirement be based on ICAP? LOLE will still be using ICAP when it hasn't selected the resource for an outage in its simulations. (Slide 38)

o AES Indiana supports the decision to continue to require offering ICAP MWs consistent with cleared ZRCs.

TO: MISO RESOURCE ADEQUACY SUBCOMMITTEE
FROM: THE ENTERGY OPERATING COMPANIES
SUBJECT: RASC SUB ANNUAL RESOURCE ADEQUACY CONSTRUCT
DATE: MARCH 24, 2021

The Entergy Operating Companies (EOCs) appreciate the opportunity to provide feedback on the following components of the sub-annual construct proposal.

Resource Accreditation (ACAP)
The EOCs do not support MISO’s proposal of accrediting resources based on a small subset of historical resource adequacy hours. This approach would result in volatile accreditation ratings from year to year, would not be an accurate predictor of future resource availability, and would unfairly penalize resources that take planned outages which happen to occur during tight margin hours even when those outages were planned far in advance. An improvement to MISO’s ACAP proposal would be to measure ACAP accreditation based on all hours in a season; however, the EOCs believe that the ACAP methodology is generally flawed due to its treatment of planned outages. The LOLE study already incorporates planned generation outages directly into the SERVM model, which impacts the calculated MISO Planning Reserve Margin. So further consideration of planned outages in resource accreditation is not appropriate. Therefore, the EOCs believe that MISO should continue to use UCAP accreditation but on a seasonal basis. Lastly, if MISO moves from UCAP to a new accreditation methodology, then it is critical for there to be a transition period to allow a reasonable time for LSEs to adapt their planning practices to accommodate the new methodology; given the long lead times involved in resource planning decisions, to implement a change this significant without adequate notice and a transition period would be unreasonable.

Generation Lead Times
The EOCs do not support including generation lead time as a factor for determining unit accreditation. Establishing a lead time threshold would severely decrease the accreditation of certain generation resources, undervaluing their true reliability contribution to the MISO system. For example, less efficient units with longer lead times provide system reliability benefits by operating during periods when other units are taking planned outages. If a long lead time accreditation criteria were implemented it is possible that these longer lead time reserve units may be given a zero accreditation value – an outcome that would be unreasonable considering the reserve capacity value that they provide. Lastly, generation resources are currently incentivized to be available on short lead times in order to receive energy benefits, making it unnecessary to further incentivize short lead times through unit accreditation.

Seasonal Load Forecast
The EOCs require more detailed information on options 2 and 3 before they can offer meaningful feedback on which load forecast option is more reasonable. In particular, the EOCs would like MISO to perform the proposed option 2 methodology on the most recent historical load forecast year to show the impact of the new methodology. The experience from last year’s stakeholder discussion of changes to the planned outage methodology illustrates the importance of analyzing the impacts of the proposed changes, including at the zonal level, as part of the evaluation of the changes.

DA Performance Obligation
The EOCs support MISO’s policy that performance obligations in the Day Ahead market only apply to generators in cleared seasons.

Minimum Capacity Requirement
The EOCs strongly support the implementation of a minimum capacity requirement, including the adoption of a reasonable locational element to this requirement. The EOCs commented extensively, in their January 20, 2021 comments, on many of the issues related to this proposal that were discussed at the March 10, 2021 RASC meeting – and, rather than repeating those comments here, incorporate them by reference.[1]  The EOCs address several issues and items from the March 10, 2021 RASC slides/materials and discussion below.

- Locational Requirement

The proposal must contain some locational requirement in order to be meaningful and reasonable. Simply put, for MISO to impose a minimum capacity requirement but allow an LSE to meet it with physical resources located potentially over 1,000 miles away from its load (e.g., an electric cooperative in Louisiana entering into a bilateral contract to buy wind from North Dakota) would fail to address either the harm to reliability or the inequitable cost shift that exists under the current Resource Adequacy Construct. Plainly, reliability demands that a significant portion of the capacity used to serve a given load is sited in reasonable proximity to that load. And if an LSE is permitted to use far-flung capacity to meet the proposed requirement, then the burden of maintaining sufficient in-zone capacity to reliably serve the load in the zone is effectively shifted to other LSEs within the zone. That result, on its face, would be unreasonable.

While including a locational element to the proposal is thus imperative, it is equally important that the locational element be designed in a reasonable manner to avoid unintended consequences or harm to LSEs that have engaged in reasonable long-term planning. In particular, it is important that some accommodation be made for resources that historically have been used by an LSE to serve its load, even if those resources happen to be located across a zonal boundary from its loads. Such legacy resources, some of which pre-date the adoption of capacity zones in MISO or even pre-date the formation of MISO or an LSE’s participation in MISO, do not represent an avoidance of responsibility for procuring adequate capacity to serve load reliably -- nor do they reflect any failure to engage in reasonable resource planning.

Given the lack of detail from MISO regarding how the locational aspect of this proposal will work, it is understandable that some stakeholders have initial concerns regarding the overall proposal. The locational element of this proposal is a critical feature, and faced with uncertainty about how that element would work, some stakeholders reasonably may be inclined to think that no requirement would be better than the uncertainty of a requirement that may penalize them despite no failure on their part to engage in reasonable long-term planning to serve their load. For this reason, and while MISO understandably needs time to develop the details of the locational aspect of the proposal, it is very important that MISO at least begin to develop the principles that will guide MISO’s decisions about the locational element of the proposal so that stakeholders can have some visibility into how it may affect them. To the extent that there has been stakeholder apprehension to this overall proposal thus far, much of it reasonably can be attributed to the absence of information thus far about the locational element of the proposal.

On a final note regarding the locational issue, during the March 10, 2021 RASC meeting, there was some confusion regarding whether MISO still intends to include a locational element to the proposal. While the EOCs understood MISO to say that the locational element continues to be part of the concept, for the above reasons, the EOCs view a reasonable locational element as an essential aspect of any solution along these lines to the reliability and cost shifting issues that exist under MISO’s current construct.

- Exemption for LSEs under 50 MW

The EOCs take no position, at this time, regarding the proposed exemption from the minimum capacity requirement for LSEs with loads at or below 50 MW. At the March 10, 2021 RASC meeting, MISO offered no clear explanation for why any such exemption is needed or how MISO arrived at 50 MW as the appropriate level for such an exemption. Pending hearing MISO’s reasoning and explanation, the EOCs will keep an open mind on this point. Nonetheless, the EOCs would observe that the obligation to ensure sufficient capacity in the MISO market to reliably serve the loads in MISO is an obligation shared by every LSE in MISO, not just large utilities. During the discussion at the March 10, 2021 RASC meeting, one stakeholder went as far as to suggest that rather than impose this new obligation on small utilities, MISO should instead require the large investor-owned utilities to procure a small amount of additional capacity – and that, given their size and business model, he was sure they would be happy to do it. This comment reflects the unreasonable mentality that apparently exists among some MISO LSEs: (i) that they are “too small to matter”; or (ii) that because they are small they are somehow exempt from the obligation to procure sufficient capacity to serve their loads; or even (iii) that they are entitled to rely on capacity provided by others without contributing any meaningful amount to the cost of maintaining that capacity. This comment – and the mentality underlying it – reveal the dire need for a requirement along the lines of what MISO is proposing. And they also reveal the sensitivity arising from adopting any LSE size exemption – whether set at 50 MW or otherwise. That is, adopting such an exemption may unwittingly confirm or validate the unreasonable view of some small LSEs that they are too small to matter or entitled to free ride on investments made by others. Again, the EOCs will await additional explanation before reaching a definitive view on the reasonableness of an LSE size exemption to the proposed requirement, or the size threshold at which such exemption is set.

- Other Issues and Items from the March 10, 2021 Discussion of the Proposal

During the March 10, 2021 RASC discussion, one stakeholder challenged MISO’s suggestion that the current MISO Planning Resource Auction reflects an implicit assumption that LSEs will engage in reasonable long-term planning to serve their loads. This challenge is simply without merit. If there were no such implicit assumption, then the only reasonable conclusion is that almost none of the capacity presently in the market is needed – because that is the signal that the clearing prices in the PRA, which annually hover at or around zero, are sending. If resources in MISO were forced to rely only on PRA revenues, all or almost all would immediately retire. Plainly, the market design assumes that LSEs will be engaging in reasonable planning to meet their needs, and indeed, per the data MISO provided on slide 27 of its March 10, 2021 deck, that is what the overwhelming majority of LSEs in MISO in fact are doing. However, those same data show that there is a relatively small number of LSEs – representing 1.9 GW of load if the proposed 50% requirement is assumed to be a reasonable standard – who are not carrying their weight when it comes to reasonable planning. As the surplus capacity in the market diminishes over time, the risk presented by these LSEs’ failure to plan in a reasonable manner increases and may inflict harm on other LSEs. That is why it is important for MISO to act now.

Some stakeholders have also raised questions about the implications of the proposal with respect to the states’ authority to regulate resource planning. One essential benefit of MISO’s current Resource Adequacy Construct is that it prioritizes and respects the authority of the states to regulate the resource planning of the utilities under their retail jurisdiction. Importantly, however, there are many LSEs in MISO over which the states do not have regulatory jurisdiction. These LSEs tend to be relatively small municipal electric utilities and electric cooperatives. Nonetheless, over a market the size of MISO, the MW of load represented by these types of LSEs is considerable. As such, MISO cannot reasonably ignore the capacity needs of these loads, and importantly, the states have no authority or jurisdiction to address them. MISO’s proposal would fill this gap.

Finally, the EOCs would note that the recent winter storm event in February 2021 illustrates the very high stakes of ensuring resource adequacy in MISO. That event was not unique to MISO; indeed, MISO fared far better than some of its neighbors. While the causes and contributing factors for that event are under investigation, and are no doubt multi-faceted and complex, the event demonstrates the consequences if there are insufficient resources available to serve load when needed. In such an event, when things get tight, the system operator does not undertake an evaluation to assess who did and did not procure sufficient long-term resources to meet their needs – and only shed load to those LSEs who failed to plan reasonably for their needs. Rather, the operator must make split second decisions to preserve the security of the grid, and all LSEs are potentially exposed to the risk of load shed. This type of event underscores the importance, in the planning arena, of ensuring that MISO’s Resource Adequacy Construct is designed to ensure that all LSEs, regardless of size or business model, engage in reasonable long-term resource planning to serve their loads.

The EOCs appreciate the opportunity to comment.

 

 


Need to understand impact (slide 10)

As stated previously, MISO needs to provide details on the impact of the proposal.  Specially, MISO needs to provide stakeholders with the footprint and zonal capacity positions relative to current construct.  Further, MISO needs to factor this magnitude of change impact on implementation schedule, especially considering the lengthy MISO queue process.

 

Minimum capacity demonstration (slide 7)

We support a minimum capacity demonstration as a core concept of a functioning and reliable capacity auction.  Free ridership concerns and risks need to be addressed.

 

ACAP (slide 7)

Consistent with overwhelming concerns shared by other stakeholders, the ACAP component of the RAN construct should be dropped.  Future refinement accommodating ACAP concepts could be appropriate, pending details.

 

RAN strategy (slide 7/10)

MISO should focus on RAN construct rules which tell LSEs how to plan for long-term reliability.  Many of MISO’s RAN concepts focus instead on penalties for operational non-performance.  MISO should break these areas apart.

 

Minimum 0.01 LOLE for seasons with low risk (slide 12/15)

The 0.01 LOLE default is arbitrary and does not address the risk of inefficiently over-stating requirements.  MISO needs to demonstrate how any minimum LOLE requirement would offer significantly flexibility, and MISO needs to demonstrate why is a minimum LOLE requirement is needed at all.  Such demonstrations should show PRMR for a more direct impact to LSE requirements.

 

Seasonal RA hours (slide 16)

When selecting RA hours, MISO needs to keep in mind that LSEs must convert those hours into confidential load levels for reserve capacity calculations.  Potential volatility due to abnormal / infrequent weather events does not accommodate confident resource planning.  MISO needs to focus on more typical challenges and trends.  For exampling, weather normalization calculations may be appropriate.

 

Resource lead time in accreditation (slide 18/19)

MISO should accommodate long lead-time resources in capacity accreditation (6, 12, 24 hours).  A 1 to 2-hour limit is far too short.  MISO should consider that it’s ability to forecast operations risks will become much better in the months and years ahead, despite the portfolio evolution.  Such long lead-time resources can offer a significant benefit to reliability.

CGA Comments on MISO’s Proposed 50% Forward Capacity Requirement

Clean Grid Alliance appreciates the opportunity to provide further input on MISO’s proposed 50% forward capacity requirement as presented again in the March RASC meeting.  First, we note that the comments we submitted on January 20, 2021, all still apply at this point.  In these comments, we specifically reiterate some of those concerns and add to them.

MISO’s proposal still is not responding to a problem that has been clearly defined or that seems to exist.  MISO still has not provided evidence of either an overreliance on the PRA or an issue of free ridership.  Given that there is no problem currently, and MISO has not shown that a problem is imminent, MISO’s proposed 50% forward capacity requirement is likely to be a very large administrative burden to ensure that only 1.6 GW[1] of capacity is procured prior to the PRA.  That amount of capacity procurement is unlikely to have a large impact on the long-term planning procedures already in place.

MISO’s PRA is already a residual or balancing market. MISO’s proposed 50% forward capacity requirement would further minimize the purpose of the PRA as a balancing market. Forward contracting in commodity markets is voluntary and driven primarily by participants’ expectations of the spot market prices. Implementing this new procurement requirement would limit participants’ ability to voluntary contract in the MISO market.  Additionally, the market signal for new capacity may be dulled or muted by requiring 50% procurement, thus hindering reliance on the spot market. Therefore, this could potentially reduce the incentives for the remaining 50% capacity need as a result of weakened market signals. In reducing efficient price signals, MISO’s proposal may ultimately result in higher costs to customers.

If there is a concern with prices, low capacity clearing prices do not reflect a flaw in market fundamentals, and therefore do not encourage “free ridership.” Instead, prices have been appropriately low and reflect the level of installed capacity in the region.  It is inefficient and counterproductive to attempt to solve a pricing problem by imposing new administrative burdens, restrictions, and requirements on market activity. Rather, if pricing is in fact the problem, MISO should seek solutions that would address the pricing problem itself.

We also reiterate our original market power concerns: To the extent that the forward procurement mechanism would include a locational component to the capacity demonstration requirements, the mechanism would potentially create market power concerns that would be difficult to mitigate because large portions of generation are owned by a single entity in many locations in MISO. Not only would this raise costs for a portion of MISO customers, but it would also allow vertically integrated utilities to stifle retail competition. Hence, it would likely undermine competition at both the wholesale and retail levels.

We urge MISO to remove this proposed 50% forward capacity requirement.

Respectfully submitted by Natalie McIntire on behalf of Clean Grid Alliance.


[1] Slide 27 - https://cdn.misoenergy.org/20210310%20RASC%20Item%2004a%20Sub-Annual%20Construct%20(RASC010,%20011,%20012)529458.pdf.

WPPI reiterates it does not support including MISO’s proposal for a Forward Capacity Requirement or MISO’s ACAP proposal in its current proposal regarding a new sub-annual RA construct. Regarding the specific slides from the March RASC presentation, WPPI provides the following more-detailed feedback below of MISO proposed sub-annual resource adequacy construct changes.

Slide 15: For calculating the allocation of LOLE in seasons with little LOLE, WPPI supports the second option “If a season has little LOLE, raise the target to 0.01 without adjusting down elsewhere (annual LOLE >0.1)”. At the RASC we discussed an example with material LOLE risk only identified in summer. Under the first option described, MISO would set a .07 risk target still for summer, dramatically and unnecessarily increasing the PRMR target and associated cost. This would be a flawed outcome, and one that would undermine MISO’s value proposition. For the initial analysis that determines where LOLE risk resides, it appears to us that if there are seasons found to have little to no LOLE risk, such that targets determined for the other seasons set resource adequacy requirements, MISO has effectively established that we can achieve a year-round LOLE risk of .1 days per year without making adjustments to the LOLE targets for the seasons with material risk. Therefore, adding .01 LOLE risk to the seasons with minimal to no risk (without adjusting down elsewhere) would be an appropriate method and there wouldn’t be any worries about excess LOLE risk.

Slide 16-17: In regards to the ACAP proposal portion of the seasonal construct, as noted in WPPI’s support of the motion, we believe this item should not be included in the seasonal filing. There are multiple aspects of the proposal that need further discussion well beyond what appears available in MISO’s seasonal-construct timeline. Most notably, WPPI has major concerns with the RA hour selection proposal as it is currently designed.

Slide 18-19: For lead time for offline RT offers used to identify RA hours and lead time threshold for offline resources when calculating ACAP, WPPI still believes it would be prudent to look at how we can improve operations to be able to successfully utilize long lead time resources before making stringent hour limitations. Also, we reiterate our concern about MISO considering adoption of the 6-hour limit applicable to LMRs given our recollection that MISO argued that the 6-hour LMR limit was justified because LMRs were more awkward than Generation Resources for MISO Operations.

Slide 20: WPPI is comfortable examining ELCC calculations using the top 8 daily gross peak hours for each season. This option is most consistent with the current approach.

Slide 21: There appears to be benefit from having summer month not be restricted to only three calendar months. There doesn’t seem to be any substantial issues with modifying the summer period to expand. Incorporating last week of May and/or first two weeks of September, to account for summer-like conditions that can happen outside of June-August, would be appropriate. Otherwise, PRMR targets for Spring and Fall will mostly be based on summer-like weather that has happened in May or September, setting a standard unnecessarily high for a season where majority of the season, weather is milder. We would suggest that MISO consider defining seasons, which need not have equal length, on the basis of historical and expected load patterns, rather than default seasonal definitions.

Slide 23: WPPI is comfortable with the second option proposed by MISO where a resource “cannot offer ZRCs [if they are] expected to be unavailable > 45 days”. Undoubtedly, there are some concerns that the timing of those days of outage. For instance if they occur in first part of fall or later half of spring; when they’ll be most relied upon for those seasons, this would be problematic. However, as a first effort for the seasonal construct, we would be fine using this standard and reviewing this item in the future for enhancements.

Slides 24-28: WPPI does not support MISO usurping responsibility of resource adequacy from the state regulators. We reiterate our feedback, made the last time this was discussed at RASC, that adoption and design of any forward requirement should be left to the discretion of state regulators for the Load Serving Entities under their purview.

The risk associated with these “free riders” seems quite small and proposed solution will have a de minimis impact. Therefore, we find that this aspect of the seasonal construct isn’t necessary.

DTE Electric appreciates the opportunity to provide feedback on RAN reliability requirements and sub-annual construct design elements. DTE’s feedback on the currently proposed ACAP accreditation methodology can be found in the presentation in the March RASC. Our feedback on other elements of the construct design can be found below.

Risk Calculation & RA Requirements

• What if the annual LOLE study shows little risk in a season? Raise the target to 0.01

Impacts of these options are not well understood by stakeholders. It may be valuable for MISO to test and publish LOLE data for each option to support determination of which methodology results in maintaining annual reliability requirements as well as minimizing the over/understatement of risk in seasons that are adjusted. Are there any options for MISO to make modifications outside of the LOLE for those seasons that require this adjustment?  For example, if raising the LOLE target to 0.01 is required to allow the model to solve but results in an overstatement of risk in a season, are there options to adjust the model back down outside of the LOLE study to account for this overstatement of risk? 

Resource Accreditation

• What determines an RA hour? Declared MaxGen hours + top X% threshold of all hours seasonally (or annually with a minimum # of seasonal hours)       

Multiple options for RA hours should be evaluated to see the impact on PRM/LRR. RA hours chosen retroactively are not an effective solution since the hours will be randomly dispersed throughout the year. This will cause issues for resource planners who want to prudently plan their outages around expected periods of RA hours. A retroactive look at X% of hours must be shown to be representative of unit performance and to accurately reflect future performance expectations of the unit prior to being selected for resource accreditation. Additional options for defining RA hours may exist such as using LOLE to determine seasonal RA hours for each PY in advance of the auction, e.g., peak for all days, 7am – 7pm M-F, etc. Resource Owners should be able to plan for RA hours regardless of selected hours, either by MISO exemptions for outages planned in advance or RA hours determined in advance.

• What RT lead time is needed to be counted as available if offline for RA hour identification? 6 hours (RAN LMR requirement)

6-hour RT lead time alignment with LMRs makes sense on the surface by holding all resources to the same standard.  However, LMRs are not the same as traditional units and require different lead times for MW generation/reduction. Rather than penalize long-lead units, we should focus on more accurately forecasting emergency events so that MISO can better commit these units to alleviate RA hours. By creating these restrictions MPs may feel pressured to must-run long lead resources on high load days to ensure they do not miss RA hours, which can lead to sub-optimal market outcomes and higher cost energy for consumers.


• Should there be a lead time threshold for offline resources when calculating ACAP? Under evaluation, will be discussed at April RASC.

Using different offline resource lead times for RA hour determination and an accreditation methodology could cause inconsistency in the accreditation of those resources. Lead times should align with RA hour identification outlined in above bullet. DTE does not support MISO moving forward with ACAP and other accreditation methodologies should be evaluated for resource adequacy.

• How should RA hours be defined locationally? North/Central combined & South

Defining two groups of RA hours for North/Central combined and South makes sense if MISO is seeing a large divergence in regional vs MISO-wide emergencies and RA hours

• How would seasonal ELCC work? Options need additional evaluation.

All resources should be accredited based on the same RA hours


Planning Resource Auction

• Where should months that could have hot weather go? May in Spring and September in Fall

Generally agree with MISO to keep May in Spring and September in Fall to keep alignment with the FTR market but DTE is open to reviewing more options as recommended by other stakeholders. Shifting the seasons by 2-4 weeks could make sense if it allows those seasons to have more uniform risk and avoid increasing the PRMR of spring/fall just to account for a hot week in May/September. Any shifts from the traditional seasons should be shown to have an appreciable impact on PRMR before moving forward with them as any shifts from traditional seasons would inherently be confusing to MPs.
 

• What about Load Serving Entity load forecasts and allocation of transmission losses? Take status quo approach but do all steps for each season

Agree with MISO to take status quo approach but do all steps for each season

• When should a resource not participate in an auction? Cannot offer ZRCs expected to be unavailable for a significant portion of the season

DTE agrees with MISO that resources which are expected to be unavailable for a significant portion of the season should not participate in the auction. There should be further discussion in the RASC to determine what number of outage days is reasonable for disqualifying resources.

Design decisions not prioritized for discussion at March RASC but feedback was welcomed

Resource Accreditation

• Should there be a transition to ACAP accreditation? Under evaluation- April item

There should be a transition period when any future accreditation methodology is approved by RASC to account for the period where behaviors may change to align with new accreditation.

• Will unit availability matter for future accreditation if the unit did not clear in the corresponding seasonal auction? No, future seasons won’t count past seasons not cleared

DTE agrees with evaluating MISO’s suggestion but would like to understand the impacts on accreditation. If seasons are excluded in the performance period for accreditation will less hours be reviewed for those resources? This may cause issues if units do not clear for multiple years and then will not have representative historical data to determine accreditation. Understanding how these hours will be removed or replaced is critical in ensuring units receive the proper accreditation in the auction.

Planning Resource Auction

• How would GVTC testing work? MISO to weather correct the annual values for use in various seasons

Agree with MISO’s suggestion to weather correct annual values for use in various seasons.

• What if a resource expects a prolonged outage after clearing for a season? If prior to start of the season, require replacement if expected to be unavailable for a significant portion of the season- April item

DTE believes that this issue supports the idea of establishing “true-up” auctions prior to each season where adjustments to resources for the prompt season can occur.

• What about outages that span multiple seasons? No specific rules for now, can create later if need identified- April item

Agree that no specific rules need to be created at this time.

DA Performance Obligation

• When will resources have a must offer obligation? Performance obligations only apply in cleared seasons

Agree with MISO

• Given ACAP accreditation, what are resources required to offer? Continue to require offering ICAP MWs consistent with cleared ZRCs

Regardless of accreditation methodology, it makes sense to continue requiring ICAP MWs consistent with cleared ZRCs.

• Are changes needed to prevent market power? Tweak rules for a seasonal approach and evaluate the exemption from physical withholding for non-RAR resources- April item

On several occasions, MISO has sought to remove the Physical Withholding exemption for Non-Capacity Resources.  While the details of how MISO would evaluate this in the context of the seasonal construct filing are not yet know, DTE is concerned about the prospect of requiring resources to provide a “capacity-like” service with no “capacity-like” compensation that resources can receive from providing this service.  If MISO seeks to compel market participation from non-RA resources because they are nonetheless needed by the market, it should provide additional compensation to those resources for the critical service they are providing.  

Comments

of the

Association of Businesses Advocating Tariff Equity (ABATE),

Illinois Industrial Energy Consumers (IIEC),

Louisiana Energy Users Group (LEUG),

Midwest Industrial Customers (MIC),

Texas Industrial Energy Consumers (TIEC),

Coalition of MISO Transmission Customers (CMTC),

Midwest Industrial Customers (MIC),

Alcoa Power Generating Inc. (APGI)

and

NIPSCO Large Customer Group (NLCG)[1]

Regarding

RASC: RAN Sub-Annual Resource Adequacy and Capacity Demonstration Requirement Proposal

Including

Proposed Options of Construct Design Elements

(RASC010, 011, 012) (20210310)

March 24, 2021

 

ABATE, IIEC, LEUG, NLCG, TIEC, CMTC, MIC and APGI, as representatives of the End-Use Customer (EUC) Sector, and NLCG appreciate this opportunity to provide comments to MISO.

 

Background

During the March 10, 2021 meeting of the MISO Resource Adequacy Subcommittee, as part of its Resource Availability and Need (RAN) initiative, the MISO Staff provided an extensive presentation on the current status of its work on its proposal to introduce a sub-annual resource adequacy construct and impose a 50% capacity demonstration requirement on all Load Serving Entities (LSEs).  During the presentation, MISO provided initial recommendations for certain details associated with its proposal and presented available options for certain other details associated with its proposal.  It also provided links to the Resource Adequacy (RA) Hours it utilized for its sample RA Hour calculations included in its February 2021 presentation to the MISO RASC.  Additionally, it indicated that it is in the process of conducting seasonal Capacity Import Limit / Capacity Export Limit (CIL/CEL) analysis to support sample RA Hour and Available Capacity (ACAP) calculations at the zonal level.  The MISO Staff also indicated that it continues to be MISO’s plan to file its sub-annual resource adequacy and 50% capacity demonstration proposal with the Federal Energy Regulatory Commission (FERC) by the end of June 2021.  To that end, MISO proposed to add a MISO RASC workshop in April to the already scheduled MISO RASC meetings for April 14th, May 12th and June 9th.  Finally, the MISO Staff invited stakeholders to submit feedback by March 24th on the options available for the design elements of MISO’s proposal.

 

ABATE/IIEC/LEUG/TIEC/CMTC/MIC/APGI/NLCG Comments

We appreciate the opportunity to comment on the latest iteration of MISO’s proposal with respect to sub-annual resource adequacy and capacity demonstration by LSEs.

With respect to our comments, first, we strongly recommend that MISO delay its planned FERC filing of its proposals until at least the end of the 3rd quarter of 2021.  While we appreciate the effort and analysis that the MISO Staff has provided to date, the reality is much more work is needed with respect to the development, analysis and stakeholder vetting of the proposal.  The proposal would make major fundamental changes to MISO’s resource adequacy provisions, and, as such, the proposal will require very careful development and consideration to ensure the proposal will:

  • Reasonably address the identified needs;

 

  • Not introduce unintended consequences;

 

  • Not unduly impact either stakeholders in general or specific stakeholders; and

 

  • Provide a reasonable transition period to mitigate the potential shock to the market by those elements of the proposal that have a significant adverse impact on either stakeholders in general or specific stakeholders.   

Given that MISO has not completed the development and analysis for its proposal, MISO recently received an overwhelming vote of no confidence from the MISO RASC on the ACAP portion of its proposal and there are only three months left to complete the development and analysis of the proposal as well as stakeholder vetting of the proposal, the proposed FERC filing date for the proposal should be pushed back at least three months to the end of the 3rd quarter of 2021.

Second, while we appreciate that MISO has heeded our past September 23, 2020 and January 27, 2021 comments with respect to the serious market power issues that would be introduced by imposing a local forward (i.e., pre-Planning Resource Auction) capacity demonstration requirement on individual LSEs, MISO’s continued pursuit of its forward capacity demonstration requirement proposal, even with the local capacity portion of the proposal discarded, is still problematic and we continue to not support it.

In our September 23, 2020 written comments to MISO on this topic, we expressed our concern that MISO has not demonstrated the need to impose a forward (i.e., pre-Planning Resource Auction) capacity demonstration requirement on individual LSEs to supplement the MISO Planning Resource Auction (PRA).[2]   Furthermore, as we noted in our January 20, 2021 comments, in the intervening period since we filed our September 23, 2020 comments, MISO has not presented any new evidence to demonstrate the need for such a requirement.[3]  In particular, it has not presented evidence that its current resource adequacy construct is unlikely to attract and retain sufficient capacity to meet MISO’s one day in ten year loss of load expectation standard in the long term absent the addition of a forward capacity demonstration requirement.  Nor has MISO shown that a significant capacity shortfall is imminent within MISO without the addition of a forward capacity demonstration requirement to supplement the PRA.  Moreover, MISO has not demonstrated that individual LSEs are excessively relying on the PRA for their capacity requirements to an extent that threatens system reliability or that inappropriately shifts costs to other market participants.  Since our January 20, 2021 comments, MISO has still not shown the foregoing.  Therefore, MISO has not presented a demonstrable need to impose a forward capacity requirement on individual LSEs, even one that does not require the capacity be sourced in the same Local Resource Zone as the LSE’s load.  Given this, MISO should drop the forward capacity requirement portion of its sub-annual resource adequacy proposal.

Third, we offer the comments which follow with respect to the various sub-annual resource adequacy design option questions the MISO Staff presented in its March 10, 2021 presentation to the MISO RASC.

Slide 15: How should Loss of Load Expectation (LOLE) be allocated across four seasons?

MISO notes that with the introduction of four seasons into the resource adequacy construct, some of the seasons may have a de minimis, but greater than zero, LOLE.  As a result, the Astrape SERVM model that MISO uses for its LOLE analysis might not be able to converge if MISO tried to impose a LOLE requirement of zero for those seasons.  To address this issue, MISO proposes to raise the LOLE requirement for such seasons from zero to 1 day in 100 years.  However, in doing so, MISO proposes to lower the LOLE requirement in other seasons such that the sum of LOLE requirements remains 1 day in 10 years for the year as a whole.  Alternatively, MISO indicates it could instead leave the LOLE requirements for the other seasons as is.

We agree with using a LOLE requirement of 1 in 100 days (or less, if possible) rather than a LOLE requirement of zero for those seasons that have a de minimis LOLE in order to ensure the Astrape SERVM model will converge.  However, we disagree with MISO proposal to decrease the allowed LOLE in other seasons to make up for the LOLE that is allowed in the seasons that have a de minimis LOLE.  Decreasing the allowed LOLE in these other seasons would likely have the effect of raising capacity requirements to a higher level than is necessary to achieve an annual LOLE of 1 day in 10 years.  The reason for this is that the LOLE for one or more of the seasons with a de minimis LOLE may be well less than 1 day in 100 years.  As a result, decreasing the allowed LOLE in non-de minimis seasons to compensate for the LOLE that was allowed in the de minimis LOLE seasons could have the effect of requiring an annual LOLE that is less than 1 day in 10 years, which would impose larger capacity requirement than is required by the traditional 1 day in 10 year standard.  Therefore, we recommend that MISO instead adopt the alternative of leaving the LOLE requirements for the non-de minimis LOLE seasons as is.

Slide 17: How should RA hours be defined?

Under its Available Capacity (ACAP) proposal, MISO is proposing to use resource availability during historical defined RA hours as the basis of capacity accreditation for conventional generation resources.  MISO proposes to define RA Hours separately for the MISO North/Central subregion and the MISO South subregion.  MISO proposes to define historical RA Hours as all hours when a Maximum Generation Warning, Alert or Event occurred plus a defined number of the tightest resource adequacy margin hours of the year.

Given the historic non-coincidence of MISO Maximum Generation Events in MISO North/Central and MISO South, we agree that if RA Hours are used, they should be established separately for MISO North/Central and MISO South.

We do not agree with including hours when a Maximum Generation Warning, Alert or Event occurred as RA Hours.  If a defined number of the tightest margin hours for resource adequacy during a year is ultimately utilized as the basis of RA Hours and that defined number is carefully selected, it should generally already encompass those hours when Maximum Generation Warnings, Alerts and Events occur. 

Despite these comments, note that we do not support MISO’s ACAP capacity accreditation proposal as it is currently proposed especially with respect to its treatment of planned generation outages.  Addressing the above comments would not alone be sufficient to address our concerns with MISO’s current ACAP capacity accreditation proposal.

Slide 18: What lead time for offline real-time offers should be used to identify RA hours?

MISO proposes to only count off-line real-time offers with a lead time of 6 hours or less when determining tight resource adequacy margin hours for purposes of determining RA Hours. 

We disagree with MISO’s proposal.  Most tight resource adequacy margin situations are identifiable well in advance of their occurrence such that off-line generation resources with long lead times can be committed online by MISO at their minimum output level well in advance of those tight periods in order to assure their availability if a Maximum Generation Event occurs.  Given this, the maximum allowed lead time for offline real-time offers for determining tight resource adequacy margin hour to determine RA Hours should be no less than 24 hours.

This said, as indicated earlier above, we do not support MISO’s ACAP capacity accreditation proposal as it is currently proposed.  Addressing the above comments would not alone be sufficient to address our concerns with MISO’s current ACAP capacity accreditation proposal.

Slide 19: Should there be a lead time threshold for offline resources when calculating ACAP?

MISO asks whether a minimum lead time, possibly as short as 6 hours, should be required for offline generation resources when determine their ACAP during RA Hours. 

As discussed above, most tight resource adequacy margin situations are identifiable well in advance of their occurrence such that off-line generation resources with long lead times can be committed online by MISO at their minimum output level well in advance of those tight periods in order to assure their availability if a Maximum Generation Event occurs.  Also, we would note that MISO, when filing its current 6 hour notice limit for LMRs with FERC, emphasized that LMRs that could not meet the 6 hour notice requirement for LMRs could instead register as Generation Resources or Demand Response Resources in order to receive a capacity accreditation.  Setting the lead time limit for offline generation resources (and potentially Demand Response Resources) at 6 hours would effectively eliminate this capacity accreditation option for these former LMRs that have long lead times.  Given all of this, the maximum allowed lead time for offline generation resources for evaluating their availability during RA Hours should be no less than 24 hours.

However, as indicated earlier above, we do not support MISO’s ACAP capacity accreditation proposal as it is currently proposed.  Addressing the above comments would not alone be sufficient to address our concerns with MISO’s current ACAP capacity accreditation proposal.

Slide 20: Would RA hours impact ELCC [Electric Load Carry Capability] calculation?

MISO asks whether it should use the same approach for ELCC calculations for renewable generation as it currently uses for its annual resource adequacy construct, but on the seasonal level, or alternatively use RA Hours for all resources.

Given that we do not support MISO’s ACAP capacity accreditation proposal as it is currently proposed, we do not at this time support applying RA hours to conventional generation resource capacity accreditation, never mind applying it to other types of resources such as renewable generation resources.  Preliminarily, a seasonal modification of the current ELCC method may be a more appropriate approach.

 Slide 21: Should a summer season include May or September?

MISO proposes to leave May in Spring and September in Fall under its proposed seasons for its sub-annual resource adequacy proposal.

We do not oppose leaving May in Spring given that the currently boundary line between MISO Planning Years is the end of May and beginning of June and it could be commercially very difficult to change that boundary.

However, we oppose leaving September in Fall if analysis shows that there is a significant LOLE exposure for September.  Note that September is considered a summer month under many state retail tariffs and/or retail rate class cost of service studies within the MISO footprint (e.g., Michigan, Missouri, Indiana, Wisconsin and Illinois).  In addition, if analysis shows there is a significant LOLE exposure for September, placing September in Fall rather than Summer would have the effect of inappropriately elevating MISO capacity requirements for the Fall season.  We recommend that MISO give more consideration to including September in the Summer season rather than in the Fall season.  Similar consideration should be given with respect to whether March should be a Winter or Spring month.

Slide 22: Seasonal load forecast and transmission losses

MISO indicates that currently LSEs provide load forecasts and are assigned transmission losses for a specific day and hour corresponding to an annual coincident peak load.  MISO also indicates under the proposed sub-annual resource adequacy proposal, it will now need seasonal load forecasts.  MISO proposes to continue to obtain load forecasts from LSE and adjust them for transmission losses, but do this for each season’s MISO peak rather than just for the annual MISO peak.  Other alternatives that MISO offers include: (i) MISO just collecting annual numbers from LSEs and make adjustments for each season or (ii) MISO replacing the LSE load forecasts with MISO or vendor forecasts.

We preliminary support having LSEs providing seasonal load forecasts as they have better information available to them on their own load than MISO.  However, we would note that the issue of loss factors needs to be explored.  Loss factors vary as loading on the transmission system varies since losses in MW roughly vary in proportion to the square of the MW loading on the transmission facilities that make up the transmission system.  Therefore, it should not be assumed that the loss factors at the time of MISO’s seasonal peaks are the same as at the time of MISO’s annual peak.  Separate loss factor should be determined for each seasonal MISO peak.

 

Thank you again for providing us an opportunity for providing these comments.  If you have any questions concerning our comments, please do not hesitate to contact:

 

 

Jim Dauphinais

Brubaker & Associates, Inc.

(Consultants to ABATE, IIEC, LEUG, NLCG and TIEC)

(636) 898-6725

jdauphinais@consultbai.com

 

Ali Al-Jabir

Brubaker & Associates, Inc.

(Consultants to ABATE, IIEC, LEUG, NLCG and TIEC)

(361) 994-1767

aaljabir@consultbai.com

 

Kevin Murray

McNees Wallace & Nurick LLC (for CMTC)

(614) 719-2844

murraykm@mcneeslaw.com

 

Kavita Maini

KM Energy Consulting, LLC (Consultants to MIC)

(262) 646-3981

kmaini@wi.rr.com

 

Steve Dowell

Alcoa Power Generating Inc.

(812) 842-3377

Steve.Dowell@alcoa.com  

 



[1] ABATE, IIEC, LEUG, TIEC, CMTC, MIC and APGI are all MISO Members in the End-Use Customer Sector.  NLCG is a non-MISO Member stakeholder whose members include large end-use customers within Indiana that are interruptible and/or have cogeneration facilities and that take service under NIPSCO Rate Schedule 831, which allows limited market purchases through Northern Indiana Public Service Company (NIPSCO).

 

 

[3] Our January 20, 2021 comments to the RASC on this topic can be viewed by clicking the following link:

 

https://cdn.misoenergy.org/20210203%20RASC%20Stakeholder%20Feedback%20on%20RAN%20Sub-Annual%20Resource%20Adequacy%20Construct%20Proposal515368.zip

 

Big Rivers Electric Corporation

Hoosier Energy Rural Electric Cooperative

Southern Illinois Power Cooperative

Dairyland Power Cooperative 

March 24, 2021

Big Rivers Electric Corporation, Hoosier Energy Rural Electric Cooperative, Southern Illinois Power Cooperative, and Dairyland Power Cooperative (“The Respondents”) thanks MISO for the opportunity to provide feedback on the proposed sub-annual resource adequacy construct elements discussed at the March 10th, 2021 RASC meeting.

As we’ve stated in past comments, the Respondents still do not have the enough 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 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 an increase in reliability.

LOLE Allocation: Respondents understand the dilemma MISO has when determining the risk and associated PRMR in seasons where there is little to no risk of a loss of load event within the LOLE study. With that said, this issue begs the question of why are we moving to a four season construct if the study which determines risk shows little risk of a loss of load event? It seems the premise of MISO’s justification for proposing the seasonal changes is that the risk profile of the region is shifting and therefore changes are need to the capacity construct, but if the LOLE study shows no risk then perhaps this premise is flawed. With that said, Respondents are also concerned that lowering allocation of LOLE risk in seasons where there is risk will yield a less reliable system and result in over-procurement of firm capacity within those seasons.  At this point, Respondents take no position on the options put forth by MISO on this issue presented at the March RASC and would encourage MISO to bring back data to better understand the impacts of different ways to allocate LOLE.

Seasonal makeup of the Summer season: Respondents currently have no preference on the makeup of the Summer season. From a load perspective, including the last 15 days of May and the first 15 days of September as a part of Summer is reasonable given that those days often times include a summer-like peak load, but many LSEs forecast their loads monthly for submittal to MISO which would make including certain days of the month difficult. Therefore, any administrative impact to LSEs would need to be weighed before significantly changing the structure of the seasons within the PRA proposal and the benefits of making these changes should outweigh the burdens imposed on LSEs.

Accreditation: Respondents continue to stress the importance of more information before supporting the Availability-based accreditation at this time. While it seems reasonable to base accreditation of resources on their availability during MISO’s most critical RA hours, the Respondents await information that shows how their individual portfolio of resources will be impacted by this change and the impact on the entire footprint’s reliability.  MISO has the ability to approve or deny outages, so Market Participants should not be held solely accountable for MISO-approved actions in the ACAP accreditation structure.  Without more analysis, it is impossible to determine the cost impact this may have on the Respondent’s customers and whether this change will either raise or lower reliability and/or their capacity costs. MISO should provide both individual LSEs with their UCAP to ACAP conversion for the RA hours MISO chooses to determine the impact on their own accredited values, the ACAP in each LRZ, and the ACAP of the entire MISO footprint. Respondents also have concerns similar to those expressed by DTE that a retroactive look at ACAP accreditation will not properly accredit resources for future performance in times of need. At this time, we continue to seek additional information from MISO on the impact of ACAP to our resource portfolio and the impact on the entire footprint before making a decision to support this change.

Timing: Respondents also share concerns expressed by other stakeholders that MISO’s timeline is overly aggressive and the need for a June filing at FERC is exaggerated. A June filing gives us less than 90 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 impact it will have on LSEs. Without this information, Respondents don’t believe a June 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.

Thank you in advance for considering this feedback.

Comments of the Coalition of Midwest Power Producers

 

The Coalition of Midwest Power Producers (COMPP) submits these comments to the Resource Adequacy Subcommittee on (1) elements of the existing Resource Availability and Need, and (2) Loss of Load Expectation outage modeling changes.

 

(1)    RAN Design Elements (Item 4a)

After the March 10, 2021 RASC meeting, stakeholders were asked to provide comments on specific design elements of the proposed RAN reforms. Generally, COMPP encourages MISO to set an expected FERC filing date that is later than June 1, 2021. Given the volume of issues, the lack of detail on the existing proposals, and the significant implications of the Seasonal, Reliability Requirements, and Available Capacity proposals, COMPP would like to see MISO take additional time to have these proposals address the foundational elements of the RAN initiative.

COMPP is supportive of the RAN initiative generally, but MISO should not be in such a hurry to make a filing at FERC. MISO must take additional time to better articulate the proposed revisions, conduct the associated supporting analysis to ensure any revisions address the regional supply issues set forth in the RAN formation documents. Additionally, COMPP expresses concern that these RAN proposals are not sufficiently related to the objective of abating the increasing amount of capacity emergencies and load shed events.

COMPP’s feedback below first identifies the slide from the March 10, 2021 RASC presentation then jumps to the substantive comments.

Slide 12 – MISO should plan each season to at least a 0.01 loss of load expectation (LOLE). However, MISO should consider increasing the LOLE target to a higher level, like 0.005, during high-risk seasons or periods. Relatedly, MISO should determine RA Hours using historical MaxGen event hours, and hours with the lowest margin of available committed capacity compared to load. Regarding lead time, only resources with 2 hours or less of lead time should be considered when counting available capacity supply.

RA hours should be calculated for the entire region, for the north and south separately, and for each zone. This will allow MISO to increase the LRR% for each zone as needed to ensure adequate local resources will be available.

Seasonal ELCC should be integrated in a later filing. This chunk of work is too complex and should consider North and South region resource penetration levels.

Slide 13 – The seasonal proposal should not be arbitrary. MISO should establish planning metrics that capture weather volatility risk. As such, September should be in the “fall season” and May should be in the “spring season.” If MISO identifies high risks of hot weather, the planning reserve margin and reliability requirements for each season should reflect this risk by increasing the amount of generation needed to maintain reliability.

Under today’s rules, resources that are unavailable for 90 of the first 120 days of the Planning Year are ineligible to participate in the PRA. Put differently, resources need to be available for approximately 25% of the peak period in order to commit capacity in the PRA. MISO’s proposal is that resource could be on outage for 30 or 45 days of a 90-day season. MISO has stated transitioning to a seasonal structure may allow for resources to better schedule outages and highlight availability. Under the current proposal, requiring resources to be available for 50% - 67% of a 90-day season does not necessarily translate to improved reliability. This should be to the current FERC accepted tariff provisions where a resource only needs to be available for 30 days out the first 120 days of the planning year (i.e. largely the summer season) in order to participate in the PRA.

MISO’s current proposal is arbitrary and unsupported.  If MISO is to require a minimal performance standard, the high level of potential unavailability should be reflected in the LRR% and PRM% metrics. COMPP recommends that MISO limit seasonal eligibility 10 days of outage or escalate the LRR% or PRM% to reflect this risk. This would require resources to commit to seasons in which they are expected to be available for nearly 90% of all hours in the season or require MISO to procure enough resources to maintain reliability.

Moreover, MISO should efficiently model demand in the seasonal construct. This could be done through a properly designed downward sloping demand curve for all or a portion of the region, consistent with the recommendations COMPP has submitted via the Integrated Roadmap.

Slide 14 – At this point, MISO should delay filing the ACAP proposal until it has been more fully developed, analyzed, and refined. Furthermore, it is not clear how ACAP will impact planning metrics or unit-specific capacity values. For GVTC testing, MISO should not require generators to test four times per Planning Year. An annual test with seasonal adjustments should be sufficient.

Lastly, MISO should not seek to require non-capacity resources to commit in the Day Ahead market. FERC expressly rejected MISO’s last attempt to assign a Day Ahead commitment requirement to generators that do not have a capacity commitment during that same period. Rather MISO should ensure PRA price signals align with system needs, which would ensure that needed resources offer, commit, and remain in the MISO market footprint. This could also encourage resources that have pseudo-tied out of the region to return to serving MISO customers.

Slide 22 – MISO should rely on an independent third-party to develop load forecasts for the Planning Year. It is MISO’s role as the market administrator to establish reliability metrics. As such, MISO should embrace this in working with a third-party expert to establish peak load forecasts by season to guarantee peak loads consider all verifiable information.   

Slide 28 – The 50% “Reliability Requirement” imposed on LSEs prior to the Planning Resource Auction could be an improvement over the conditions in the capacity market today. While the PRA fails to send appropriate economic signals, the creation of a more robust bilateral market in MISO through the Reliability Requirements proposal could provide market participants with better insight into regional and local supply needs. COMPP encourages MISO to provide more information on how this proposal can improve reliability in the region and why the 50% level is justifiable.

AMES and MGE generally support WPPI Energy's feedback.

CFU supports WPPI Energy's feedback for slide 23.

MPPA and SMMPA generally support WPPI Energy's feedback except with regard to slide 23.  MPPA and SMMPA do not believe there should be any restrictions for participating in the capacity auction for generators with lengthy planned outages.  (The “season” in which the planned outage occurs is a moot point.)  Many generating plants conduct their planned outages on a 3-year cycle.  As a result, these outages tend to be lengthy in nature.   It would be unjust to restrict such a plant from the auction during the year in which the outage occurs since the market gets the advantage of no planned outages during the other 2 years.   Such a policy would unfairly force such generators  to purchase capacity for their planned outage once every 3 years whereas generators that take  multiple, shorter, planned outages do not have to replace their capacity. This would be especially painful in a 2-season market since the generator would be forced to replace its capacity for 6 months even though the outage is only scheduled for 46 days.    In addition, if MISO implements the proposed ACAP accreditation policy there would be no need nor justification to restrict generators from participating in the auction for lengthy planned outages since the ACAP already accounts for the generator’s planned outages.  To do otherwise would be double penalizing the generator.

Other LSE Coalition members do not necessarily support WPPI Energy's comments at this time and will submit feedback separately or after the next RASC meeting.

I'd be happy to discuss.

David Sapper

dsapper@ces-ltd.com

Conceptual Design
PSCW staff supports in principal the concept of rewarding resources credit for flexibility and availability during times of need and supports the seasonal construct conceptually. Additionally, PSCW staff supports any efforts that will help with improved outage coordination to reduce risk during tight margin hours throughout the planning year.

ACAP (some points also reflected on the ballot response submitted to RASC on March 17, 2021 as part of the DTE Motion)
PSCW staff supports in principal the idea of rewarding resources credit for flexibility and availability during time of need, presented in the available capacity accreditation (ACAP) metric. Due to the fast pace of change in the resource mix in the MISO footprint as well as greater reliance on LMRs and intermittent resources, unit response time, and the amount of flexibility a resource can provide are becoming increasingly important in the consideration of resource accreditation. Staff believe that an appropriate change in accreditation methodology is required to address the gap between planning and operation time resource availability. Having said that, here are our general areas of concern regarding MISO’s ACAP proposal:

  1. It is unclear how much the total ACAP accreditation of units will vary year-to-year. We would like more information to understand if under ACAP we would have the visibility required for long-term resource planning.

      2. MISO should generally provide and facilitate a more comprehensive analysis of the ACAP metric and provide learning opportunities for all stakeholders to fully understand the impacts adopting this this change, even if this includes delaying the filing(s). Areas in particular include:

1)    More information about how MISO will or could assign Resource Adequacy hours, including a clear analysis using past data and identifying system peaks

2)    How units will be treated and/or de-rated should there be no “tight” hours in a season

3)    How will any de-rate of units align with de-rate of planning reserve margins

        3. We recommend that MISO and stakeholders keep refining the ACAP metric to address the concerns raised by all stakeholders on an extended, yet defined timeline. We would like MISO to explain the possibility, including any ramifications, of separating ACAP from the Resource Adequacy construct filing.

        4. If MISO does not separate the ACAP filing from the sub-annual construct filing at FERC, we would recommend delaying the combined filing past the June 2021 timeline to address stakeholder concerns regarding the ACAP metric.

The OMS Resources Work Group (RWG) appreciates this opportunity to provide feedback to MISO on its current work on the RAN initiative. This feedback does not constitute a position of the OMS Board of Directors.

ACAP Proposal

As a general opening comment, the OMS RWG is supportive of the principle of accrediting resources based on their expected ability to perform when they are needed most.

Several members of the OMS Resources Work Group have significant concerns with the proposed ACAP accreditation. This proposal represents a significant shift from current practice and given that the proposal was just released for stakeholder review, there is concern that rushing this through will not give stakeholders enough time to process, become educated on, or fully understand the ramifications of the proposal. As more education is needed, MISO should provide a workshop on resource accreditation, including a 101-level discussion on its ACAP proposal and also explain issues and deficiencies with the existing UCAP method.

There are concerns related to potential unintended consequences on planned outages. As planned outages would be subject to the same accreditation penalty as forced outages, MISO needs to explore whether or not ACAP will impact, or be a substitute for, continued efforts to improve planned outage coordination. One of the most important benefits of the shift to a sub-annual construct is the ability to take cost-saving economic outages during seasons when a resource will not be needed to meet resource adequacy requirements, and MISO must ensure that this benefit is fully realized. Some members believe that means MISO should not subsequently file a physical withholding-like proposal that would require these units that are not offered into the PRA for any season to nonetheless be obligated to offer into the market for dispatch, which would eliminate the value of the seasonal construct.

Some OMS RWG members support continued work on the ACAP proposal and encourage MISO to add additional time for work through outstanding issues with interested stakeholders. These members believe that as of today, no one identified potential negative consequences which can outweigh the potential benefit of proposed ACAP.

Other members request that MISO delay the ACAP accreditation change, and once MISO addresses the concerns voiced by stakeholders, file it separately from the sub-annual construct. These members believe that MISO's ACAP proposal is not ready for prime time, has not been used in any other RTO/ISO, and MISO has offered no modeling to explain how this will affect LSEs ability to meet RA requirements.

Other Considerations

On the proposed options for the sub-annual construct, the OMS RWG shares the following comments and clarifying questions:

  • How should Resource Adequacy Hours be defined?

The OMS RWG has asked for the inclusion of a minimum number of hours to be included in each season previously. A resource that clears in a given season should be expected to be available for the tightest margin hours of that given season. We continue to encourage MISO to consider a minimum number of hours in each season.

  • Would Resource Adequacy hours impact the ELCC calculation? (Slide 20 of presentation)

The OMS RWG wants clarification on whether this proposed change would impact how the system-wide ELCC is calculated or if it would change how the accreditation for individual renewable resources works. We see value in discussing and comparing the resource accreditation treatment.

  • Should a summer season include May or September? (Slide 21 of presentation)

As other stakeholders requested during the RASC discussion, the OMS RWG supports additional data on the relevant information for May and September, as the months should be placed in the season with which they are most aligned. This could also include splitting a month between seasons, if appropriate (i.e. first half of May in Spring, latter half in summer). Additionally, the ARR/FTR seasons should be changed to align with whatever set of seasons is ultimately decided upon for the sub-annual construct.

Xcel Energy provides the following comments regarding the RAN reliability requirements and sub-annual construct proposed options of construct design elements.

 

Risk Calculation and RA Requirements

If there is not a NERC requirement that the annual LOLE totals 0.1, Xcel Energy requests more details as to why MISO believes capping the annual LOLE at 0.1 would be the best approach since it would artificially inflate the PRM requirements for the summer and winter seasons.   We would also like to see examples of the impact of setting a threshold for the seasonal LOLE and reducing the LOLE for the summer and winter seasons so that the total LOLE across the year equals 0.1. 

 

Resource Accreditation

Xcel Energy does not support the ACAP methodology as currently proposed  However, we believe the approach is a reasonable concept and would like to see MISO and stakeholders continue their discussions to improve of the current proposal.  Our preference would be to continue the seasonal construct path to a FERC filing in June as that design has broad stakeholder support and has been discussed for nearly two years now, but allow for additional time for stakeholder discussion and proposals regarding the ACAP concept and file in a separate docket.

One of our main concerns with the current ACAP proposal is the lack of integration with the current outage coordination process.   The modifications to the outage coordination process (RAN phase 1, effective 4/1/19) were designed to balance the need to schedule outages in advance with the capability to schedule shorter-term outages when sufficient capacity margin exists to increase the number of resources available when they are most needed.  This process already incorporates a penalty for outages that were taken when sufficient capacity margin did not exist and could be leveraged to provide a framework for capacity accreditation based on availability during tight margins.   Current outage coordination and penalties regarding planned outages could easily be extended to include Max Gen Warnings and Alerts which would eliminate the need to define RA hours.  We also believe that continued improvements to the Maintenance Margin forecasts  will help MISO and MPs identify when capacity margin exists for outages and additional improvements to the process and application of penalties should be reviewed. 

MISO has stated that the principle of ACAP is to ensure more resources are available during times of need.   If this is indeed the case, we recommend that the best place to start would be to improve the current outage coordination process instead of applying penalties retroactively.

In addition to the impacts to the outage coordination process,  we have additional concerns with the ACAP proposal regarding impacts to resource planning as well as a multitude of details underlying the calculations.  Without these details, it is impossible to thoroughly assess the proposal.

Regarding the lead time threshold for offline resources, we believe this issue is best addressed through improvements to market commitment processes which are currently being addressed in the MSC.

Regarding the hours to use for resource accreditation of wind (and eventually solar) in the ELCC calculations, Xcel Energy would support using the net peak load hours for this purpose. 

 

PRA

Xcel Energy recommends that the initial seasonal construct start with a three month season, as defined in the FTR process.  However, we do recommend that this is evaluated on an ongoing basis once the seasonal construct is implemented.

 

DA Performance Obligation

Xcel Energy agrees with MISO that must-offer requirements would only apply in the seasons in which the resource has been cleared for capacity.  Current Tariff requirements regarding physical withholding exemptions for non-RAR resources should be applied on a seasonal basis.

Resource Adequacy Objectives

Minnesota Power is looking to the MISO Resource Adequacy construct to provide equitable treatment of capacity resources across all generation types that ensures a reliable power supply mix for the planning year. An effective resource adequacy construct will also deliver a reliable means of assessing long-term portfolio alternatives in Minnesota Power’s Integrated Resource Planning (IRP) process and provide a structure that incentivizes the generation resources needed to support reliability are maintained or built.  It’s important to Minnesota Power that resource adequacy construct changes do not unduly cause financial harm or additional uncertainty to customers. All changes to the construct must be measurable and financial impacts should also be predictable.    The following comments describe Minnesota Power’s concerns with the proposed ACAP and Seasonal proposals – most notably with the:

  • Equitable Treatment of Capacity Resources
  • Timeline and Process for Stakeholders to Review and Assess Proposed Changes

Equitable Treatment of Capacity Resources

Minnesota Power does not support the concept that the accreditation value will be reduced if a MISO approved planned outage occurs during a period of tight margin hours from Real Time operations data.  Generation owners must be allowed to schedule maintenance outages required to maintain reliable operations without the fear that negative impacts to their accredited capacity value and their financial compensation. These long lead time outages must be given safe harbor in the accreditation process to ensure reliable operations in the future and proper valuation of resource capacity. As proposed, the ACAP construct would create uncertainty as to how much capacity an LSE would need to procure from season to season, which could result in higher costs for customers without any gain in a more reliable energy supply. 

The ACAP construct must provide the incentive for adding all types of resources that support Resource Adequacy, and not just the resource types that can quickly react to a change in system resource needs.  All energy resources that are capable of being reliably dispatched within their typical operational parameters should receive similar capacity values.  All generation resources in MISO’s dispatch stack are necessary to provide energy adequacy, not just the generator at the top of the resource stack that can be quickly brought online to support the intermittency in the system from near term fluctuations in demand or renewables.   Minnesota Power does not support implementing a “lead time threshold for offline resources” when determining the ACAP value.

MISO and Stakeholder Evaluation of Resource Adequacy Proposal

MISO has asked stakeholders for input on several items included in their March 10th presentation, but they have provided little to no analysis that could help stakeholders conduct their analysis.  Prior to filing any changes at FERC, MISO should continue to inform and work with stakeholders on the potential impacts from changes to the Resource Adequacy construct.  It is not reasonable to ask for expedited feedback on how these complex and technical design decisions impact market participants without providing context on the long-term impacts to capacity portfolios, reliability of the system, customer costs, and long-term planning of the power supply.

Furthermore, the decision options create hundreds of potential combinations of possible outcomes, and it is simply not possible to provide any meaningful input as to the impact on any one question, without having the capability to see how these input assumptions interact with each other in the ACAP and Seasonal approaches.  As stated earlier, MISO must provide adequate analysis to show a defined combination of these key factors so that stakeholders can have a meaningful discussion and confidence in their recommendations.  The realm of decision making on these questions is bound by the historic data and the current resource portfolio and MISO must demonstrate how a future portfolio will be able to maintain similar levels of reliability.

The overall design of the ACAP construct and the analysis provided to date does not provide any metrics that demonstrate how ACAP will “send out the right capacity requirement signal” to incent the types of capacity that will create a reliable portfolio.   MISO has an obligation to show how this method can accomplish its stated objectives through robust analysis and a full range of outputs.  MISO must also demonstrate how the anticipated changes in the portfolio will continue to result in the correct capacity requirement signal. 

To ensure stakeholder support, a period of 45 days must be provided between the draft final design and the FERC filing to allow time for stakeholders to evaluate impacts.  MISO should remain open to the possibility of changes being needed after the 45 day review by stakeholders.  Prior to this 45 day review period, and as soon as possible, MISO should make the data available that is needed to adequately evaluate the proposed changes.

Conclusion

Minnesota Power appreciates the opportunity to provide feedback on changes to MISO’s Resource Adequacy construct.  For clarity, Minnesota Power is supportive of the RAN initiative and believes that changes to the resource adequacy construct are needed to support reliability as individual utilities and states move toward a carbon free power supply.  As a principle, Minnesota Power believes that it’s important that a generator’s contribution to reliability be properly valued and predictable in a new resource adequacy construct. Minnesota Power has concerns that ACAP does not achieve these principles.  Changes to the resource adequacy construct need to be supported by sound analysis and stakeholder input. In order to develop consensus among stakeholders a reasonable amount of time and construct information must be given for MISO market participants to evaluate the impacts to their generation portfolio. 

  1. The “capacity price signal” that ACAP provides is for capacity that is dispatched or quickly available during the difficult to predict Real Time market condition of tight margins. 
  2. The need for dispatchable resources (that can be committed ahead of time and considered properly in the planning studies as having unique attributes of being dispatchable) is not considered in the ACAP accreditation methodology.
  3. It is only logical to conclude that over time the expected resource transformation would value adding more peaking capacity fueled by natural gas, and the baseload dispatchable coal and nuclear generation would continue to be retired from the system. 
  4. Greater and greater usage of peaking resources result in an overall resource portfolio where larger blocks of energy would be met with peaking generation that is not typically economic at higher capacity factors, and would also result in an increasing level of lost fuel diversity with coal generation retirements. 
  5. ACAP doesn’t provides a signal to the market that there is a need for these blocks of energy at the bottom of the stack to avoid the hours of tight margin.
    1. Energy adequacy resources that are out for planned outages aren’t given as high of accreditation
    2. After not being committed in the SCED, energy adequacy resources not considered available in a 6 hour timeframe are not accredited with as high

Recommendations

  1. Attributes used in the SCED process for the types of generation be used in the resource accreditation process
    1. Dispatchable – longer startup time
    2. Dispatchable – shorter startup time
    3. Intermittent
    4. Resources by fuel type
    5. Other ?
  2. Energy Adequacy be defined by taking the types of resources defined in the SCED into a modeling effort showing the optimum mix of resources by type.
  3. Fuel Diversity must be included in a comprehensive resource adequacy analysis to show the impacts of fuel contracts and firmness of price and pipeline capacity to avoid the price excursions recently experienced in SPP. 

 

The Environmental Sector appreciates this opportunity to submit comments on the RAN Reliability Requirements and Sub-annual Construct proposal published by MISO on March 10, 2021.  (Issue Tracking ID#: RASC010, RASC011, RASC012)  As stated in the Environmental Sector’s comments in September 2020, October 2020, December 2020, and January 2021, the Environmental Sector appreciates MISO’s extensive work in developing this iterated proposal over the past several months.  The Environmental Sector remains concerned that dating back to MISO’s initial development of the Sub-annual Construct in the fall of 2020, MISO has failed to articulate a clear problem statement, to lay out set of objectives that MISO is seeking to fulfill with the new proposal, or to substantiate its proposal with data, all of which has led to a lack of clarity in the subsequent discussions and specific solutions offered.

ACAP Accreditation Methodology

Regarding the proposed ACAP capacity accreditation scheme mentioned at slide 14 of the March presentation (and slides 13 and 30 of MISO’s February presentation on the proposed Sub-annual Construct), the Environmental Sector objects to the proposal to determine seasonal PRMR values solely based on historical availability of only thermal resources to the extent that is, indeed, what MISO is proposing.  The Environmental Sector reiterates its comments on the UCAP/ACAP issue stated in its January 2021 comments on this topic, namely:

 We’re not clear why MISO would not just change the determination of UCAP for thermal resources to account for the availability factors that ACAP is trying to capture (e.g., planned outages).  Otherwise, one would seemingly end up with IRP modeling that uses UCAP values for renewables and LMRs and ACAP values for thermal generators, which would not be consistent metrics, and would create unnecessary confusion, in addition to not being currently feasible.

An additional concern is that the use of both ACAP and UCAP would imply the need for both a Planning Resource Margin percentage using UCAP and another Planning Resource Margin using ACAP, which could lead to additional confusion in the planning process.  Additionally, while this methodology, to the extent that it is used to accredit the available capacity of all resources, would apparently provide ex post rewards for those resources that were available during peak hours, it apparently would not provide ex ante incentives for all generators to take planned outages during low-risk periods. 

To be more specific on that point, as the Environmental Sector stated in our January 2021 comments:

It is still useful to look at the impact of maintenance on LOLE so that LOLE is not compromised, but that seems that MISO could calculate the maximum amount of capacity (UCAP or adjusted ICAP) that could be out of service in each hour or day, and make plans accordingly. Any maintenance schedule that causes LOLE to increase from its “base” level (base level calculated in the annual optimized 0.1d/y case) is a schedule that should be rejected or penalized in accordance with MISO’s scheduling authority.”

LOLE Calculations

On Slide 15, MISO proposes to raise a Loss of Load Expectation (LOLE) for a particular season with little-to-no risk from a calculated 0 to a deemed 0.01, while adjusting the LOLE down in other seasons.  The Environmental Sector disagrees that it is necessary to deem a nonzero LOLE if there is actually no expected loss of load in a particular season.  If modeling methodologies require a nonzero LOLE, MISO should be more transparent about explaining this aspect, including the data and modeling approaches used for LOLE calculations.  As stated during the meeting, we are also concerned that reducing the LOLE value in the summer season in order to retain an overall 0.1 LOLE annually would result in an overly conservative planning resource margin in the summer months.

The Environmental Sector has significant concerns with the Sub-annual LOLE Modeling methodology employed by MISO’s consultant in the development of this proposal.  At a high level, the Environmental Sector believes that the modeling has not properly accounted for inter-regional or inter-zonal variations in wind shape and solar irradiance on each given day.  However, the Sector will reserve further comment on this topic for future stakeholder feedback opportunities.

ELCC Calculations

The Effective Load Carrying Capability (ELCC) for wind resources is presently poorly defined.  On Slide 20, MISO describes how it calculates ELCC for wind by taking an average across years of the top 8 daily peak hours within a year.  A sub-annual resource adequacy construct will need sub-annual ELCC methodologies so that the procurement in each time period can procure accurately measured products.  The Environmental Sector concurs with the proposal to use some measure of top peak hours for each season, but feels it is unclear why 8 hours is an appropriate number of peak hours to measure to determine the greatest times of resource adequacy risk.  Regarding the question of whether net load vs. gross load should be used in the calculation of daily peaks, the Environmental Sector is unable to make a firm recommendation at this time and instead respectfully requests that MISO provide more data and insight on the calculation of net load vs. gross load.  Additionally, any ELCC methodology should consider the synergistic effect of storage paired with wind or solar.

Shoulder Month Allocation

On slide 21, MISO presents the question of whether each of May and September should be allocated to the Summer season.  MISO correctly notes that “sub-regional and footprint-wide temperatures and load can approach summer highs during these months.”  The Environmental Sector offers that climatic conditions in May and September will differ by region (for example, May could quintessentially represent spring in one region of MISO but summer in another part of MISO), and which season the two months are assigned to should depend on the transmission constraints between regions, which have not been included in the proposed analytical framework.  Weather-based analysis for May and September has also not been included in the stated decisional process.

Holistic Issue Consideration

The Environmental Sector believes that MISO should not separate the Sub-annual Resource Adequacy Construct proposal from other renewables issues currently under discussion, including (but not limited to) capacity accreditation, since weather patterns will affect both demand and resource availability, meaning that consideration by FERC will be most efficient if all relevant issues are considered together.

Forward Capacity Requirement

Finally, MISO has not shown that there is a need to implement the 50% Forward Capacity Requirement that it has included in both the January and March presentations on the Sub-annual Capacity Construct.  MISO has not substantiated that there is an overreliance on the PRA or that there is a real free-rider issue.  Given that the impact of this proposal is minimal (1.6 GW of capacity), and the PRA is only a residual market, the additional administrative burden is not justified.  

Thank you for your consideration of the Environmental Sector's comments on this important matter.

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

ETEC appreciates the continued conversation on the potential need for a sub-annual construct and modifications to resource accreditation. ETEC also looks forward to continuing to participate including in the upcoming April workshop. With that in mind, ETEC makes the following general comments about MISO’s proposals:

  • ETEC agrees with the general sentiment in the meeting that MISO’s proposed filing timeline is too tight. Given the status of analysis and discussions, there is not enough remaining time for MISO to file a holistic proposal by mid-year. ETEC believes that the results of the ACAP vote demonstrates that stakeholders are uncomfortable with proceeding with significant overhauls without fully vetting them.
  • Very much in alignment with the previous, the scope of what MISO is trying to accomplish needs to be well defined and narrowed. ETEC heard new concepts being tossed out for consideration like buyer-side mitigation. Rather than adding to the scope, MISO should focus on the original scope (possible transition to sub-annual construct and resource accreditation) and delineate any other issues to a separate, later forum.
  • Again building off the previous, MISO should separate the forward capacity demonstration concept out of these deliberations and shelf that for a later, separate discussion. At this point, ETEC, as well as other stakeholders, has participated in the RAN-related discussions at the RASC for several years. All along the discussion was regarding a possible seasonal construct plus changes to resource accreditation. Much further along the process and without stakeholder input, MISO added the forward capacity demonstration concept. To stay true to its original intent and the process thus far, MISO should focus on the original scope.
  • ETEC continues to look forward to the data items MISO said would be delivered in April. ETEC has a strong desire to be able to understand the impact of MISO’s proposals on its own resource adequacy position and plans along with broader market effects.
  • ETEC has stated a desire for MISO to do a backcast simulation of its proposals. The February 2021 winter event provides a driver for doing so. Such a backcast simulation would provide a tangible lens for MISO and its stakeholders to understand the possible impact and benefits of MISO’s proposals. ETEC understands that assumptions and simplifications would be necessary to such a simulation and supports MISO making those and discussing them with stakeholders.

Southwest Louisiana Electric Membership Corporation (SLEMCO) and Concordia Electric Cooperative Inc. (Concordia) submit the following comments on the RAN Reliability Requirements and Sub-Annual Construct (RASC010, RASC011, RASC012).

SLEMCO and Concordia are transmission-dependent rural electric cooperatives in Louisiana and Load Serving Entities located in Zone 9. We continue to have concerns about several portions of the proposal as well as MISO recommendations as presented in the March 10, 2021 presentation to the Resource Adequacy Subcommittee.  MISO requested formal stakeholder feedback on their proposed options of construct design elements by March 24, 2021.  Below are the comments of SLEMCO and Concordia.

  1. ACAP Resource Accreditation:  The move to use Available Capacity (ACAP) for resource accreditation may have merit but the complexity and embedded details of moving to this should not be underestimated and a decision to make such a change should not be pursued until all modeling assumptions have been fully vetted and the results compared, reviewed and commented on by stakeholders.  MISO has not yet provided this level of detail and, at this late date, full evaluation and discussion would not be possible before a Q2’21 FERC filing. 
  2. Seasonal Construct: While the logic of a seasonal capacity construct may be intuitive, the impact on embedded calculations such as LOLE and CONE are not as intuitive.  These impacts should be fully understood before moving toward a seasonal capacity construct and determining what months should make up those seasons. While a four season construct with three months in each season may be balanced, the analysis of having a longer summer season should be completed and reviewed and commented on by stakeholders before moving forward.  Once again, MISO has not yet provided the level of detail for an entity to evaluate the impact to its system and, at this late date, full evaluation and discussion would not be possible before a Q2’21 FERC filing.
  3. Minimum Capacity Requirement:  We recognize and appreciate MISO’s elimination of the zonal requirement since the January comment period. While this makes the proposal to require LSEs to procure at least 50% of their PRMR prior to the auction less restrictive, once again, this aspect of the proposed reliability construct changes has to-date not received sufficient analysis. Questions not fully addressed include:
    • A 50% level still appears arbitrary. What is the evidence supporting a rationale for setting the requirement at 50%?
    • We support the exemption of small entities. The 50 MW level, however, seems arbitrary. Has this evaluation been done at other levels, and if so, what is the differential impact? Would a 75MW or 100MW level achieve a similar result?
    • Has there been an analysis of the cost impact of such a requirement on LSEs?
    • Layering regulatory requirements on top of a functioning market could distort market prices in ways that yield unintended consequences. Have potential unintended consequences been fully  considered?
    • In order to allow time for proper review and consideration, we would urge this component be broken out and considered separately from the other proposed RAN construct changes.

As cooperative utilities dedicated to providing least cost service to our customers, we believe this proposal requires much more analysis and consideration to make sure it, in fact, improves resource adequacy, assures reliability and meets the needs of all customers.  Once a more detailed analysis is presented for all components of this proposal, it will be important to allow time for review and comment prior to filing. We encourage MISO not to rush a Q2’21 filing date and allow time for more definitive analysis and comment before making these important changes.

Please see attached document for Energy Michigan's feedback on the RASC March 10, 2021 meeting.

Risk Calculation & RA Requirements:
WEC Energy Group does not support MISO’s proposal to reduce the LOLE in certain seasons to accommodate the use of a 0.01 days/yr in those seasons with no (or little) LOLE risk. MISO’s proposal will inappropriately increase the Planning Reserve Margin Requirement in certain seasons by reducing the LOLE risk to accommodate an administratively assigned LOLE risk in seasons with no risk. The administratively assigned LOLE risk is used for nothing more than to facilitate a solution in those seasons with no (or less than 0.01 days/yr) risk. The risk and reserve margin requirements in those seasons with risk should not increase to account for an administratively prescribed LOLE in seasons with risk less than 0.01 days/yr.

For example, if the annual LOLE simulation determines a risk distribution of 0.07 in the summer and 0.03 in the winter. Assigning a risk of 0.01 in the spring and fall to facilitate a solution should not increase the risk (by reducing the LOLE) in the summer and winter months. In all likelihood, LSEs will have more than sufficient reserves in the spring and fall to cover a 0.01 LOLE risk. However, reducing the LOLE and increasing the risk in the summer to 0.06 or 0.05 will likely require LSEs to obtain more capacity.

Resource Accreditation:
WEC Energy Group does not support the ACAP methodology and the use of RA Hours to accredit resources. As noted by the presentation by DTE at the March 10 RASC meeting, there are simply too many issues and challenges associated with a retroactive ACAP to warrant its use in the new seasonal construct. We recommend that MISO and stakeholders continue their discussion of ACAP and improvements needed to address the issues while moving forward with a seasonal RA construct with the existing accreditation methodologies.

MISO seeks feedback on a number of items associated with RA Hours and ACAP. We are strictly opposed to the use of RA Hours as currently defined and will not opine on those items at this time. However, we note that the proposed definition of RA Hours demonstrates a fundamental deficiency of the concept. Defining RA Hours (either fully or partially) as the top x% of tight hours during a season may not actually represent when available generation is exhausted and the use of operating reserves is imminent. We anticipate seasons without any truly “tight” hours and creating a RA Hour when there is no loss of load risk makes little sense. This is especially pronounced if a generation resource receives an ACAP penalty because it scheduled planned maintenance during a period of no risk but that period is administratively defined as a RA Hour.

The proposed seasonal RA construct will function properly with the existing resource accreditation methodologies. MISO’s desire to send a signal to resource owners by reducing their accreditation when they are needed but not available is easily accomplished with enhancements to the RAN Phase 1 initiatives and additional rules on the application of GADS data. For example, the capacity value of a resource should reflect its unavailability because of lack of fuel.

We do not support the use of RA Hours for seasonal ELCC calculations. We do support the proposal to use the top 8 daily gross peak hours for each season (similar to current annual method).

PRA:
On several occasions, WEC Energy Group has acknowledged MISO’s desire to improve reliability by requiring a minimum amount of capacity prior to the PRA. We have also recommended that the RERRA is ultimately responsible for resource adequacy and should establish and enforce rules regarding capacity. Our position on this issue has not changed.

WEC Energy Group is comfortable assigning May to spring and September to the fall season. However, we recommend continuous review of that assignment to determine if moving May or September to the summer season would provide value to resource owners and LSEs.

If a resource is unavailable for a full season, it should not qualify to participate in the PRA for that season. We recommend that if a resource is partially available for a season, it should qualify for the PRA only if the cumulative outage time is less than 33% of the season. A resource that does not qualify for a seasonal PRA because of a planned outage should be permitted to provide replacement ZRCs when it is not on planned outage. This recommendation is an attempt to balance the benefits of belonging to the reserve sharing pool, the planned outage assumptions within the LOLE study, and the burden on the reserve sharing pool of extended outages. The requirement to obtain replacement ZRCs for suspension and retirement should continue.

DA Performance Obligation (must-offer):
WEC Energy Group agrees with MISO’s proposal to apply must-offer requirements to resources cleared in a particular season, require ICAP MW offers for non-intermittent resources, and to evaluate exemptions options for non-capacity resources from physical withholding.