Resource Adequacy FAQ

For coincident peak, is MISO requiring seasonal coincidence factors?
MISO only publishes only one seasonal coincident peak. 

Do you need to look back 5 years to come up with your coincident peak or just the previous year?
You need a minimum of one year, but you can use more than one. 

What are the minimum datapoints needed for seasonal Coincident Factor?
You need a minimum of one year.

Is there an import function to submit Non-Coincident Peak and Energy for Load? 
This is not a current capability, but something we can look into for the future. 
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If the GVTC value is the same for all historic years or should it reflect the prior year. 
Your units current GVTC is valid through all 3 lookback years. 

What happens when Schedule 53 Seasonal Accredited Capacity (SAC) is greater than ICAP?
The linked knowledge article covers this topic. KA-01389 (misoenergy.org)

Are you able to submit an ICAP deferral for a new resource to include only a portion of the 4 seasons if they will not be operational prior to 6/1/23? Submit just offers for Fall, Winter, and Spring for example.
You can choose which seasons you are doing an ICAP deferral for, please refer to BPM-011-r27 for more information.

Is MISO going to post seasonal Interconnection Service for each resource? 
MISO's Generator Interconnection Agreements (GIA) do not grant seasonal interconnection services. Under the Confirm SAC display in the MECT, each resource will have the same Interconnection Service values (NRIS and ERIS) display for each season. Example, if a Generator has a 100MW GIA that grants its 50MW of NRIS, each season will show Total IS= 100MW, 50MW of NRIS, and 50MW of ERIS. 

Is the Interconnection Service limitation prior to conversion of ISAC or do you need enough Interconnection Service to cover the SAC too? 
You must have enough Interconnection Service to be fully deliverable to your ICAP.

How does one convert the excess Energy Resource Interconnection Service (ERIS) SAC when there is no Transmission Service Rights (TSR) beyond the Network Resource Interconnection Service (NRIS) Service. 
You must have enough Interconnection Service to be fully deliverable to your ICAP. Examples below shows three different scenarios.



The ERIS conversion is requiring a TSR# on the conversion page. How do you convert the ERIS SAC?
Converting ERIS SAC requires firm transmission in the form of PTP to NITS. These TSR numbers are entered in the MECT. New features in the MECT automate the TSR approval process, there are currently some technical issues going on that is being researched. In the case of non-automation, MISO staff will manually approve TSRs.

Can an LSE assign NITS from a different zone for ERIS capacity?
Yes, you can participate, if, you have firm transmission service in the form of PTP or NITS. Please refer to BPM-011 for more information.  

How will MISO address the ISAC calculation on jointly owned units where different owners submit separate offers?
Market Participants may request a review with MISO staff to go over calculations with joint owners on how to confirm the computations are handling the proper shares. 

If there are adjustments to ISAC, does MISO plan to update the System UCAP/SAC ratios for any changes? 
MISO will be giving the final ratio on December 15th. 

Can your ISAC calculation be greater than NRIS?
ISAC generally will not be, but SAC can be higher. 

When are the final ISAC ratios posted?
The final ISAC ratio will be posted on 2/15.

For the SAC determination of an LMR, will the value be the same across all four seasons for this upcoming year (23/24)? 
LMRs are not Schedule 53 resources, but they will be seasonal on what they can curtail.

Are there any similar types of adjustments for LMRs, either BTMG or DR for the upcoming auction?
The number of calls is defined five for Summer and Winter. Three for Spring and Fall.

The Multi-Day Operating Margin (MOM) report shows peak hour operating margin for 6 days, for planning purposes don't market participants need hourly granularity? 
The MOM forecast provides estimates of operating margins for the expected peak hour next 6 days. Maintenance Margin is also based on expected peak loads. For planning purposes which should be many weeks or days in advance, that is the appropriate level of hourly granularity. 

What maintenance margin and/or operating margins reports contain hourly data.
The Multi-Day Operating Margin (MOM) forecast estimates the timing of the peak hours for the next 6 days. Typically, the other hours from the dame days would have lower and higher operating margins. 

What affect does Market Clearing above CONE in a single season have and what affect does that have on other seasons?
Technically, Cost of New Entry (CONE) itself is an annual figure, an industry-wide term, used to indicate that current, annualized, capital cost of constructing a power plant. There is never a price that if going over [annual] CONE. MISO does apply different denominators to CONE based upon the way it is used. The highest auction price you can have CONE [annual] divided by the number of days in that season, For Auction Clearing Prices, that is the maximum. If we have 2 or more seasons that are in Zonal Resource Credit (ZRC) shortage or near shortage it would be CONE divided by the number of days in those seasons. 

What if my new resource or existing resources does not have at least 60 days of Real-Time offered availability when designated for Resource Adequacy Requirement (RAR) over the last 3 years for each season, what will the SAC be based on? 
The resource will have a SAC based on the Class Average SAC to ICAP Ratio for its resource type. 

When and where are Operating Margins posted?
We have shared this data in the spreadsheets that can be used to calculate unit level SAC values. MISO will explore posting such information shortly after each season or possibly on an ongoing weekly basis via an automated report for future Planning Years. 

What is the report name that shows the daily operating margin for the next 7 days?
The Multi-Day Operating Margin (MOM) forecast estimates the operating margins for the next 6 days.

Where can we see reporting on our historical outages that received exemption flags in CROW?
Market Participants can obtain their own outage data because MISO's CROW system does have report functionality which Market Participants can utilize. MISO will be updating the CROW User's Guide available on the MISO Market and Operations webpage

If there was an outage in the past that was >30 days and we are calculating SAC, should we exclude that season in the SAC Calculation? If yes, do we just divide by 2 years instead of 3?
​​If you don't offer into a season because your outage is more than 31 days, and the unit was coded as exempt you don't need to do anything. It will be removed from the calculations. You will use the seasons it was in use for the calculations. 

Which maintenance margin should we be utilizing to get an exemption? Central or MISO whole maintenance margin?
The margin is where the asset is physically located, not MISO wide. 

The IMM has provided guidance to deduct "otherwise reasonably expected unavailability" from the 31 days of threshold under the 31-Day rule to determine how many actual planned outage days could occur in a season before having to withhold/replace. Does MISO agree with this guidance? If so, what is MISO's recommendation on how to determine such "reasonably expected unavailability" to deduct from the 31-day threshold for each unit?
This was added as a fail-safe at the recommendation of the IMM, so people can't offer in PRA when it is out for the season. Language will be added by the IMM to BPM-009 that clarifies the standard. 

​​​​​​How do we know what Annual Average Offer Capacity (AAOC) hours to use if the unit is in outage and has an exemption during the AAOC hour? 
AAOC hours are used to help ensure sufficient sample size as a proxy. MISO doesn't backfill annual Resource Adequacy (RA) hours, less of an issue since 260 of them per Planning Year instead of 65 per season. It is measured by what you had. So, if you were exempt for 10 then you would not be reflected in the calculations.

The 31-Day rule applies to outages in CROW at the time of the auction, correct? What happens if outages have been submitted in CROW, but have not yet been approved/exempted by MISO by the time of the auction? What is MISO subsequently denies or does not provide an exemption for an outage in CROW after the auction but, for example such unit was withheld assuming the outage would be approved?
Planned outages are counted after the fact based on what actually happened. When submitted or approved doesn't matter for counting days towards the 31-day threshold. Regarding unplanned outages that were known or could be reasonably anticipated the determination whether to count them is determined by the IMM. Combination of planned and unplanned, but IMM counted outage days is compared to 31 days to determine replacement requirement and related non-compliance charges. 

If we shorten an outage in CROW, will we lose our exemption if the maintenance margin is <0 on any day of outage on the date we shorten the outage even if it was >0 when we initially submitted the longer outage?
If an outage is reduced by more than 20% of their duration, the outage will be re-evaluated for exemptions. The Change Request (CR) date will be used to determine exemption eligibilities. BPM-008 Section 4.8.2 Changes by Generator Owner or Generator Operator does address this and gives an example. If reduced by less than 20%, outage is not re-evaluated and all exemptions that were previously granted will remain.

If a planned outage begins, and the work is completed quicker than anticipated, can the planned outage duration be shortened? If so, are there any associated exemption status or other types of impacts?
"Implemented" tickets in CROW can be "Completed" earlier than the end date/time with no impact to the exemptions on ticket. Completing a ticket in CROW is not considered a Change Request. 

Where can I find more details regarding outages and exemptions.
For additional details, please see in the Outage Exemption Chart. See Schedule 53.II Tier 1 and Tier 2 Planned Outage Exemption Requirements.

For a unit with a planned outage greater than 31 days, my understanding is that you could either seek an exemption from the IMM to not participate in that season's PRA or you could participate and be subject to a penalty for days greater than 31. If you use the second option, and you replace the capacity for the days above 31 you would avoid the penalty. Is this correct? Also, in addition to all this, the outage would not hurt future accreditation as long as it was submitted with sufficient notice, etc.?
Penalties would not apply if the capacity on an outage greater than 31 days was replaced. There are other variables that factor into capacity accreditation in addition to the outage notice timeline. 

Do some forced outages get exemptions? 
No, only planned outages receive exemptions. 

Do gas outages Code 124 get exemptions?
Inability to get gas does not get an exemption. 

If there is a change to the outage start or end dates occurring for an outage that was previously exempt, do the unchanged days (in the original outage window) still have an exemption while the newly added days do not?
Please refer to the Maintenance Margin before extending an outage. If the maintenance margin is good and it is still timely you can do a change request. If you are extending and the maintenance margin is not great, submit a ticket so you can retain your exemptions on your original ticket.
Change requests that shorten an outage by no more than 20% or reduce capacity of the outage will not lose exemption(s). All other change requests will reset the queue position and be cause for re-evaluation of exemptions using the date of change as the evaluation date. BPM-008 Section 4.8.2 discusses this further. If extending an outage would cause you to lose exemptions MISO suggests submitting a new ticket so you do not lose the exemption on your 1st ticket. New requests are required to extend an outage already in progress.  

Where in CROW Reporting is the Exemption Submittal box?
MISO is working with the vendor to fix this bug and putting instructions on how to do this will be added to the Appendix in CROW. It will be coming soon. 

Does MISO have an outage cause code reference that corresponds to NERC/GADS or PSC outage codes?
The CROW user guide has an attachment of all cause coded for MISO. 

What is the impact if you have Time Requirement Exemption (TRE) but not a Maintenance Margin Exemption (MME)​?
If only ONE of these boxes is checked, you will have a Tier 1 exemption. If BOTH are checked it is a Tier 2 exemption. If no boxes are checked then you do not have an exemption. 

What outage codes count and do not count toward accreditation impacts?
The TRE and MME exemption boxes are checked or not based on the rules laid out in Section II of Schedule 53. MISO has discretion to provide an exemption in some circumstance, for example there is a code 126 Transmission System Limitations which can result in the granting of an exemption upon consultation with the Planning Operations Team. 

Do you loose accreditation if you make scheduled outage changes?
Change requests that shorten an outage by no more than 20% or reduce capacity of the outage will not lose exemption(s). All other change requests will reset the queue position and be cause for re-evaluation of exemptions using the date of changes as the evaluation date. BPM-008 Section 4.8.2 discusses this further. If extending an outage would cause you to lose exemptions MISO suggests submitting a new ticket so you do not lose the exemption on your first ticket. New requests are required to extend an outage already in progress.

A planned derate is not eligible for exemption currently, but will it be looked at in the future?
Yes, exemptions for derates will be looked at in the future.

Does MISO let market participants know in CROW that outage has received a Time Exemption Requirement (TRE) or Maintenance Margin Exemption (MME)?
This is in the works. They are hoping to get it into CCE by the end of November.

If you have multiple units on single CROW ticket, if you remove a unit from the ticket, does this trigger a re-evaluation of the exemption status?
This would be considered reduction of capacity of outage. Change requests that shorten an outage by no more than 20% or reduce capacity of the outage will not lose exemption(s). All other change requests will reset the queue position and be cause for re-evaluation of exemptions using the date of change as the evaluation date. BPM-008 Section 4.8.2 discusses this further. If extending an outage would cause you to lose exemptions MISO suggests submitting a new ticket so you do not lose the exemption on your first ticket. New requests are required to extend an outage already in progress. 

Is MISO open to retroactive exemptions prior to 9/1/2022?
You either have an exemption or not prior to 9/1/2022.
If the planned outage is occurring PY 23/24 does the 31-day limit apply or not?
Yes, the capacity replacement provisions are effective for the 2023/2024 Planning Year. 

Will exemptions be granted for outages for the upcoming planning year that are in excess of 31 days in a season, if planned prior to FERC filing?
Exemptions remove the applicable hours from the Schedule 53 calculations. Any day with planned outages in a season whether exempt or not counts towards the 31-day threshold after which replacement is required by the Tariff regardless of when planned. 

What data point triggers the end of an outage to determine the duration between outages?
The planned end date of previous outage for the unit in CROW.

If an outage starts 10 hours earlier than planned for a planned outage that was given an exemption, does it affect the exemption outage? 
Implementing early by a few hours on the same day does not affect your exemption status. If it is a day early, then it would be looked at. 

If an outage lasts 10 hours after the exemption, will it affect the exemption outage?
If you are going to be into the next day you will need to put in another ticket, so you don't lose your exemption on the current ticket.
Should we expect prior CROW tickets that had no exemptions marked, but submitted >120 days in advance to show a Time Requirement Exemption (TRE)?
These Time Requirement Exemptions should show as flagged in CROW. 

What is the status of BPM-008 for Outage Coordination for RAN?
Subsection 4.1.1 should be able to see in revision 21.

If an outage starts in the middle of the hour, is that hour coded as being in outage for SAC Calculation, if it is not in exemption?
MISO compares the Real-Time Offer market time stamp with the CROW outage start time. Real-Time Offer market time stamps are reflected on an hour interval basis, whereas CROW outages are reflected on a minute internal basis. Let's use an example to help explain the process:
- An outage starts in the middle of the hour and is reflected in CROW as starting at 9:15 a.m.
- MISO would flag the outage in the SAC process as hour beginning 10:00 a.m., unless the Real-Time Offer Status already indicates this unit is in outage starting from 9:00 a.m. If this is true, MISO will flag outage as hour beginning at 9:00 a.m. 

How should I submit and outage exemption dispute?
​Submit a case in the MISO Help Center. 

What has been done to resolve combined cycle and exemptions for each individual steam/gas turbine?
Not all combined cycle units offer into the market the same. SAC templates have been posted to the market portal accounting for different circumstances. The general rules are if outages are submitted based on individual turbines, the combine cycle unit will be exempt if all individual units are outaged and exempt. Otherwise, it is based on outage submitted on parent unit.
 

Is the Planning Reserve Margin (PRM) final and official? 
The Planning Reserve Margin (PRM) and the Local Reliability Requirement % (LRR) are official and should not change from the 23/24 LOLE Report.

Is the Planning Reserve Margin % (PRM) and the Local Reliability Requirement % (LRR) are official and should not change from the 23/24 LOLE Report?
The Planning Reserve Margin Requirement MW(PRMR) will be updated with the new load forecasts, transmission losses, and the Local Clearing Requirement (MW (LCR) will be posted in Q1 2023, as MISO starts to publish preliminary PRA data. 
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In comparing RA hours for 9/19-8/21 to what was used during development, it appears there may be numerous changes in the identification of the Tier 2 hours. Could you please discuss what drove the changes in the Tier 2 hours from what was previously provided. 
The underlying data changes when MISO put it into production. MISO's data team went through all the data to get the margin MW accordingly. That is why MISO made the data in late September preliminary. MISO wanted to make sure that we had your MW correct. There should be no changes in the data for that time period when the new one comes out. 

When will we know the Tier 2 hours for the previous season? Are these going to be provided quarterly?
MISO has not announced the date the Tier 2 hours will be available and has not yet identified the process for providing updated values to stakeholders. 

What is the best way to predict Resource Adequacy Hours?
Consult the daily Multi Day Operating Margin Forecast which gives information for the next 6 days. This is located on the MISO website within Market Reports. 

Does RBDC effect SAC?
No. 

What is the difference between the Initial RBDC Opt Out and final RBDC Out Out?
The Initial RBDC Opt Out is your initial plan prior to going to your RERRA. After the RERRA has approved the final step is to Confirm your Opt Out in MECT. 

If I choose the RBDC Opt Out, is this for three planning years?
Correct, if the RBDC Opt Out is for 3 planning years.

If the RERRA denies your RBDC Opt Out, can I elect to do an RBDC Opt out for the next planning year?
Yes, if the RERRA denies your RBDC Opt Out, you can request for an RBDC Opt Out for the next planning year. 

What is the RBDC plan?
It is not a physical plan; it is just selecting in the MECT your intent to Opt Out. 

How do I schedule time to discuss my RBDC with MISO?
You will submit a ticket through the MISO Help Center. On your ticket be sure to select the category Resource Adequacy and sub-category Planning Resource Auction (PRA). In the Title mention you need to schedule RBDC office hours.

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Will there be a recording of the RBDC Workshop available?
Yes, there will be a recording of the RBDC Workshop available on the MISO website.

If an LSE has load in multiple LBAs and would like to opt-out of RBDC, do they need to individually select the Opt Out check box for all of those?
No. Users only need to select RBDC Opt Out checkbox on the "MISO Coincident Peak" screen for one LBA. The MECT will automatically mark the Opt Out for all other LBAs associated with the LSE. 

Will MISO summarize details regarding how much RBDC Opt Out MWs are in the market?
Yes, MISO will publish information about RBDC Opt Out along with the PRA results while ensuring not to share any confidential or market sensitive information.  

Can an LSE utilize RBDC Opt Out for just one Season or must they Opt Out for all four (4) seasons in a Planning Year? 
Planning Year. Further, any first-time decisions to utilize RBDC Opt Out will require the LSE to continue to utilize RBDC Opt Out for all Seasons for a Lock-In Period of 3 consecutive Planning Years. 

Will MISO be forecasting RBDC related information for future Planning Years? 
No. MISO will not be forecasting any prospective data related to RBDC beyond that provided for the prompt Planning Year. 

If an LSE utilizes a FRAP in the PRA to meet their Initial PRMR obligation and the Final PRMR is higher, how will the LSE satisfy this additional obligation? 
A FRAP may only be used to meet an LSE's Initial PRMR obligation. Should Final PRMR be higher than Initial PRMR, the remaining balance will be sourced from the PRA.

If an LSE utilizes RBDC Opt Out and they have capacity (ZRCs) in excess of their Final PRMR and LCR obligation, does that excess capacity go into the PRA?
Yes. For LSEs utilizing RBDC Opt Out, any ZRCs in excess of the LSE's Finala PRMR and LCR obligations will be sold in the PRA. 

If and LSE utilizes a FRAP in the PRA to meet their Initial PRMR obligation and after the PRA it is found the Final PRMR is lower than Initial PRMR, what will happen to the portion of ZRCs in the FRAP no longer needed to meet Final PRMR obligation? 
In such a scenario, LSEs that FRAP will still clear the PRA at the same MW as their Initial PRMR and will not receive a balance of ZRCs back following the PRA. 

How will LSE with state requirements placing limits on PRA procurement maintain compliance with these requirements given Final PRMR will not be known until after the PRA?
LSEs with such requirements should work with their state regulatory authority on any potential implications on state-specific requirements.  

To which entity is the RBDC Opt Out Adder applied and does it change?
The RBDC Opt Out Adder is only applied to those LSEs which elect to pursue RBDC Opt Out. The adder value (by season) will not change for the duration of the 3-year mandated Opt Out commitment period, but other values impacting Final PRMR (such as PRM and coincident peak forecast) will continue to be updated each year

How does the capacity market clear when utilizing RBDCs?
Historically, MISO has utilized a "vertical" demand curve in the capacity auctions. Regardless of offer price or volume, the PRA needed to satisfy the same PRMR requirement in terms of capacity. With the implementation of RBDC, this demand curve is now sloped such that when ACP is low, more capacity is needed to satisfy PRMR and when CAP is high, relatively less capacity is needed to satisfy PRMR. Should there be sufficient capacity offers available in the PRA, the point at which the offer curve and the (sloped) demand curve intersect will set both the ACP and the Final PRMR values. The RBDC itself will not move, only the point at which the curve(s) intersect given the nature of the offer curve, accounting for regional/zonal import and export limits. 

What is the process for an LSE to utilize RBDC Opt Out?
The process was reviewed at a high level during the RASC meeting on 11/6/24 and again in detail during the RBDC Workshop on 11/15/24. Presentation materials, including a video of the Workshop are available on the MISO website. 

How will the future implementation of DLOL impact RBDC?
The recently approved Direct Loss of Load (DLOL) accreditation reform will directly impact the methodology by which capacity resources, will participate in the PRA, are accredited. However, as the DLOL methodology will impact Initial PRMR calculation due to its impact on resource UCAP values, DLOL will have a secondary impact on how MRI curves are established and accordingly RBDC's themselves. 
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What happens if an LSE initially electing RBDC Opt Out does not ultimately procure sufficient ZRCs to cover their Final PRMR obligation?
An LSE electing RBDC Opt Out that does not meet their Final PRMR shall pay the RBDC Opt Out Deficiency Change (2.748 * CONE for applicable LRZ) for the insufficient ZRCs in each Season as per Section 69A.9.1(k) in Module E-1 of the MISO Tariff. 

What's the maximum cost exposure under both Opt In and Opt Out decision?
The maximum cost exposure for an LSE that elects RBDC Opt Out is 2.748*CONE+ZRC shortage amount for each Season in which the LSE is not able to meet its Final PRMR. Please note the CONE value is an annual number calculated by MISO pursuant to Tariff Section 69A.8 and submitted to and approved by FERC each year. The CONE value for Planning Year 2025/2026 for each LRZ was recently approved by FERC Docket No. ER25-111. For LSEs that are relying on the PRA to procure ZRCs (or in other words opting in) it is important to note that under the RBDC construct (unlike the vertical demand curve construct), the extreme price volatility when going from 1MW long to 1MW short (or 100 MW short to 100 MW long) is no longer a possibility. A significant amount of capacity shortage, with respect to the Initial PRMR (i.e. capacity to meet the target LOLE criterion), needs to exist to have a CONE as an ACP the season under the RBDC construct. Thus, in totality, on seasonal basis, the maximum cost exposure for an LSE that is relying entirely (no partial FRAPS) on the PRA to procure ZRCs is equal to annual CONE*Final PRMR. 

If an LSE Opts Out and within the following three years, its RERRA sets its own PRMR, what is the procedure from there?
(i) Is the Opt Out nullified and the LSE can now participate in the auction?
(ii) If the Opt Out is not nullified, when MISO does the PRM + Adder calculation will it use the state's PRM or the MISO value?
(i) If an LSE Opts Out and its RERRA sets its own PRM in year 2 or 3 of the RBDC Lock-in period, the Opt Out is nullified and the LSE will now be subject to State-set PRM and other related provisions in the Tariff and BPM. 
(ii) LSE's election of RBDC Opt Out will be nullified if the corresponding RERRA sets its own PRM.  

Is it correct that if an LSE operated in multiple states and wishes to opt out, it would have to be approved by the Commission of each state? 
Yes, MISO has included clarifying language in the BPM Section 5.3.2.2. If an LSE that is electing to use RBDC Opt Out has load obligation that is under the jurisdiction of more than one RERRA, MISO will deny request for RBDC Opt Out if one of the RERRAs indicate that the LSE is not authorized to use RBDC Opt Out. If the MP with the load obligation under several RERRA jurisdictions, however, has designated multiple LSEs under its direction aligned with commensurate RERRA jurisdictions, then each LSE will singly be evaluated for eligibility to select the RBDC Opt Out. 

Would MISO allow multi-state LSEs to have different PRMRs from different states?
Yes, provided they are registered as different Asset Owners (LSEs) corresponding to their loads in different states.

 How is the Local Clearing Requirement (LCR) calculated when a state sets its own PRM?
(i) Will LSEs have a pro-rata share based on coincident with zonal peak, even if it opts out?
(ii) Would LCR need to be met regardless of state PRM override? 
There are no changes to the current calculation for LCR and related Tariff provisions for LSESs when a state sets its own PRM. 
(i) Yes
(ii) Yes

What are the RBDC Opt Out effects on the final shape of the RBDC?
MISO will not make any changes to the RBDC's based on RBDC Opt Out MWs. All curves stay the same. 
 

When is the registrations page unlocked in MECT to submit entries?
December 15th is when registrations can be submitted. 

Is the intent to submit the same "supporting documentation" for each season?
We assume this question pertains to the "Registrations" for Load Modifying Resources (LMR) which can be Demand Response (DR) or Behind-the-Meter Generation (BTMG). The Module-E Capacity Tracking (MECT) tool is currently designed to allow for one (1) 'registration' for the Planning Year. Within the one registration, the 'seasonality' is broken out. All supporting documentation can be uploaded for the specific LMR in one 'registration.' So, the Market Participant can upload one file with the supporting documentation on the seasonality of the LMR of the MP can upload specific files for each season. It is up to the Market Participant at this time.

When will MECT be open to register LMRs?
New LMR Registrations is open now.

What is the Deadline to register New CPNode Resources?
You will need to have GVTC, be in the Commercial Model, and be operatable. March 1st should show this as available in MECT. 

If a replacement capacity goes into a forced outage does the unit still count as replacement capacity? 
If it goes into forced outage after the replacement goes into effect, then yes but it can't be replaced with capacity already on a forced outage. 

Is there a way for generation owners to state they have excess capacity which is available to be contracted for replacement capacity?
Yes, MISO provides via the Market Portal, a bulletin board for the purpose of communicating both a need to buy or sell capacity. 
The following article discusses it in further detail. The bulletin board is called the Non-MISO Transaction Bulletin Board. 

Does replacement capacity have to be available during the same days that the original resource is offline (do the days have to overlap)?
Capacity replacement works by shifting the "designated as Resource Adequacy Requirements (RAR)" and related performance requirements from one resource to another resource that have uncleared Zonal Resource Credits (ZRC) in sufficient quantity. They can't both be designated as RAR at the same time since the tariff requires replacement from "uncleared ZRCs". Whenever a resource is designated for RAR and is on a full or partial outage the count toward the 31-day threshold in a season will continue. Note, if unit A accrues 31 days of planned outages and then replaces with uncleared ZRCs from unit B then has any planned outages in that season then the MP that converted the ZRCs for unit A will be subject to the capacity replacement obligation and related non-compliance obligations since the tariff states that "ZRC replacement shall have no impact on settlements". All of this is covered in Module E-1 Section 69A.3.a.h.a.​​

Is it possible for SAC to be larger than ICAP? 
Under the RAN Seasonal construct, Schedule 53 resources can have a SAC that is higher than the units effective ICAP (lesser of Interconnection Service or GVTC). All of this SAC can be converted and offered into the PRA. The Must Offer obligation would still be capped at your units effective ICAP. For example, if you convert and offer 100% of your SAC, your Must Offer obligation would be 100%*ICAP. If you only convert and offer 90% of your SAC, your Must Offer obligation would be 90%*ICAP.

Where does the data come from for SAC Calculations? 
From MECT: GVTC Data
From DART: Resource Real-Time hourly offered EmerMax and CommitStatus, Resource Lead-Time (calculated by DART engine based on resource offer and status), 5-minute UDS state estimate and control status; for creating online indicator
From CROW: Completed of Implemented Out-of-Service outage for creating outage indicator, RAN Phase I exemption flag for creating exemption indicator
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Will MISO use the last complete planning year for calculation of SAC or the most recent 3 seasons ending with the most recent Summer? 
The lookback period is Sept 1- Aug 31. This is so the latest summer will be used in calculation. 

How do we measure the impact on SAC of moving an outage?
Moving an outage can lead to the loss of one or both exemptions in which case the Real-Time offers of 0 during the OOS outage could be used in the Schedule 53 calculations. Limited impact for non-RA Hours but more impactful for RA Hours that have a higher weighting. 

What values are the weighted percentages applied to in SAC?
Planning Year 2025/26 it will be 20% and 80% where it will stay.

​​​​Will MISO be providing an unlocked SAC template? 
MISO has posted both the original locked version and an unlocked version of the Schedule 53 SAC Calculation tool. Both can be found on the Resource Adequacy webpage.

​​​​Where are historical class averages posted by MISO?
Historical class averages (ISAC/ICAP) will be available when SAC accreditation is made available. 

In the SAC Template, step 2-2 limits availability based on the GVTC or the Real-Time Offer EmerMax?
Real-Time offered Hourly Emergency Maximum Limit is the "availability" used in Schedule 53, it is capped by the most recently submitted seasonal corrected GVTC to account for changes in the maximum output of a resource.

What fields in CROW does MISO look at exemptions for the SAC Calculations?
They look at actual outage tickets in CROW, then the actual start and end time in CROW.

How will Combined Cycle be calculated with SAC?
MISO is working to develop the process to match Real-Time Offers to MECT registrations. This process is still under development and may result in the need to raise issues to be addressed during the SAC confirmation process. 

Is it possible that the SAC result could be greater than the GVTC quantity? 
Yes, that is likely to happen for well performing resources given use of the conversion ratio. 

What is the recommended timing for selecting the "Reject SAC" for current cases that are being reviewed?
February 1st. If a resource that has a late GVTC, ICAP Deferral, New Resources or any other that needs time. March 1st. 

Can the SAC only exceed ICAP due to the ICAP/SAC ratio or is there more that goes into that calculation for example ancillary services or generators that are more available during tight hours? 
SAC would only be higher than ICAP for Schedule 53 Resources due to the UCAP/ISAC Ratio.

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Is a non-run of river, non-pumped storage hydro unit considered Schedule 53 resource? 
A non-pumped storage hydro unit that is NOT enrolled as an Electric Storage Resource (ESR) may be considered a Schedule 53 resource, However, hydro resources defined as a Run of River or Use Limited Resources are not considered as Schedule 53 resources. 

If a Market Participant is in a FRAP and converts capacity to ZRCs and transfers those ZRCs to another Market Participant will all four seasons ZRCs have to be transferred at the same time?​​​​​
No. Each season will essentially be a different auction. You will have to transfer the ZRCs in each season individually and just needs to occur before the auction.

Is there more than one opportunity to transfer ZRCs in MECT if circumstances change?
After the auction clears if a Market Participant needs to get replacement ZRC's they go through the non-MISO bilateral market. 

If an MP offers a capacity resource into the PRA and it clears, then the MP status is changed from one entity to another entity who holds the ZRC replacement responsibility if that resource has a catastrophic event?  Will it be the new MP entity or the entity that submitted the resources to the PRA prior to changing MP status?
The ZRC replacement obligation is with the MP that Converts the SAC to ZRCs. In this specific situation of catastrophic outages, the Tariff uses the term "may replace" not "must replace". If they do replace, they will be designated non-Resource Adequacy Requirement (RAR) and would not affect accreditation in the future. The "must offer" obligation for the cleared ZRCs remains with the original owner of the resource (operating company), the responsibility for the resource replacement should go to the operating company. 
 

How does MISO verify gas transmission system limitations, restrictions, supply chain?​​​​​
MISO does not look at the ability to get coal or gas as a planned outage that should be exempt if sufficiently coordinated. Rather this is a risk that should contribute to the accreditation of a resource.