RASC: BPM-011 Annual Review (20230822-23)

Voltus appreciates this opportunity to comment on the proposed redlines to BPM 11, revision 29, and submits the following set of comments:

4.2.5 - LMR Obligations and Penalties

Page 52:

The DSRI is populated with the monthly Demand Reduction Capability Forecast values provided at the time of the LMR registration.  If the LMR partially clears, the value in the DSRI will be adjusted by the % of the total seasonal ZRCs a resource clears times the Demand Reduction Capability Forecast.

Voltus agrees with this change, but notes that adjusting the default LMR availability value in the DSRI by the proportion of each LMR that cleared in the PRA must also account for the possibility that the ZRCs of that LMR may also have been transferred via a ZRC transaction and subsequently used in a FRAP or cleared in the PRA by a different MP. MISO should update the logic that calculates default DSRI values to be equal to % of the total seasonal ZRCs that were converted to a Performance Obligation, regardless of how that obligation came about.

Page 54:

Self Scheduled MWs are not subject to notification times because they are already planned to be performing at those levels, as decided by the MP; however, MWs available for MISO are subject to notification times whenever Scheduling Instructions are created.

Before finalizing any changes to BPM 11 guidance on DSRI data management, MISO must first explain how resources on a Firm Service Level (FSL) baseline are expected to report availability when they are operating above or below the historical average peak on which their registration volume is based. 

As Voltus has stated in previous comments, LMR enrollments are based on capability during system peak conditions. For FSL customers, the enrolled amount is the difference between peak load (calculated as described in Business Practice Manual 11) and the FSL or “drop to” load level that an LMR can achieve when dispatched. Real-time operators need to know not just how much reduction they can expect relative to peak conditions, but also how much load drop they can expect to see when they dispatch LMR. If MISO aims to reflect load drop in the availability reported in the DSRI, then reported availability should be based on a standard baseline that measures near-term curtailable load, specifically the so-called “capacity baseline” or “10-of-10 with symmetric multiplicative adjustment.” LMRs on an FSL baseline should report the delta between their peak curtailable load and current curtailable load in the “self scheduled” field of the DSRI. Crucially, the “self scheduled” quantity should count as “available” for accreditation purposes, reflecting the fact that LMRs are accredited based on their curtailment ability during peak conditions.  BPM 11 should detail how data in the “MW available for MISO” and “Self Schedule MW” fields should be calculated for FSL customers. 

Page 57:

DRs that registered with a Firm Service Level Measurement & Verification methodology that partially clear, will have the uncleared portion of the resource added to their registered FSL when evaluating performance.

Voltus agrees with this new language with the same edit as above; the Performance Obligation is what is relevant and it does not necessarily correspond only to what cleared the Planning Resource Auction. 

4.2.7 - DR Qualification Requirements

Page 64: 

Submitting locational information for each asset in the DR registration. That information can include Account Number, Meter Number, Address, City, State, and Zip Code. The minimum required information is the Zip Code for every physical location of the asset in the DR Registration. ARCs must submit all locational information listed above. 

Voltus’ position is that the locational information requirement should not distinguish between whether a resource is being submitted by an ARC or another MP. The same data requirements should be applied regardless of the submitting party; LBAs and LSEs have this locational information readily on file for each customer account, and MISO has recently emphasized the need for greater locational information, so Voltus sees no value in this discrepancy of requirements.

Page 67:

The assets’ load should be calculated as the average load of the assets up to the last three seasonal MISO system peak hours. One or two years of load data may be used if the full three years is not available, but an explanation must be submitted as to why the full three years are not available, for example a new facility that has only been in operation for two years.

Voltus agrees with this change.

6.5 - LMR Performance Assessment

Page 132-133:

Unless already entered as Self-Scheduled for the event, DRs registered with a firm service level must still show a load reduction. Advanced Reporting should reflect the best estimate of load reduction available during the event. Penalties will still be measured as load above the registered firm service level.

This proposed redline is a step towards the detailed guidance for FSL resources that Voltus has requested, but it remains vague. MISO must specify exactly how “load reduction” should be estimated (i.e. which baseline) and how market participants should reflect when FSL resources are operating below their peak load, and possibly even at or below their FSL.

Until MISO clarifies how Self Scheduled MW should be calculated and entered for FSL resources, Voltus cannot fill in this field for its LMR resources, nor can it comment on proposed redlines related to how the value of this field affects deployments or performance assessment.

CPower Comments to MISO’s August 22-23 RASC Feedback Request on BPM-011 Redline Edits

September 11, 2023

Ding the August 22-23 RASC meeting, MISO presented draft redline edits to BPM-011 to reflect updates for the upcoming 2023/24 Planning Year. Enerwise Global Technologies, LLC d/b/a CPower (“CPower”) appreciates the opportunity to provide feedback to MISO on the draft redlines and thanks MISO staff for their review and consideration. Should you have any questions, please do not hesitate to contact Peter Dotson-Westphalen.

1. Section 4.2.7. Demand Resource (DR) – Qualification Requirements

In Section 4.2.7. Demand Resource (DR) – Qualification Requirements, CPower supports the addition of the requirement to include additional information regarding the location of every physical location of the asset in a DR Registration, as well as the other ministerial edits throughout this section.

However, CPower does not support, and is confused by, the addition of the requirement that states, “[t]he underlying customer accounts for ARC registrations must be registered under a single DR registration name for the entirety of the Planning Year. The registered capability and tested status can be different for each Season.” It is CPower’s understanding that, while MISO’s tariff does require that only one Market Participant (“MP”) may represent and end customer account to participate in any of MISO’s DR participation mechanisms at a given time,[1] different MPs may register the same end customer to participate in one (or more) MISO DR participation mechanism(s) in different Seasons given that only one MP is representing the account at a time. The redlined language would effectively prohibit a MP’s ability to register customer accounts to participate in only some Seasons while another MP could register those same accounts during other (non-overlapping) Seasons, by requiring that, “the underlying customer accounts…must be registered under a single DR registration name for the entirety of the Planning Year.” (emphasis added)

2. Section 4.2.7.1. – Demand Resource Registration Process

MISO proposed to insert additional language requiring an explanation be provided by the MP when registering a Load Modifying Resource (“LMR”) that does not have three full years of historical data to calculate the average of the assets’ load during the last three years’ worth of seasonal MISO system peak hours. While this is not an unreasonable request, MISO should be aware that utility data sharing practices vary across the MISO territory, and in CPower’s experience, ARCs may only be able to request 12-24 months-worth of historical interval data for customer accounts, and may not be able to access customer data that spans sufficient time covering this full timeframe to be able to calculate the average seasonal load. The lack of access to this data due to current utility data sharing practices should not cause MISO or the other entities involved in reviewing an ARC’s LMR registrations as being deficient or cause it to be unduly rejected.

3. Section 4.2.7.8. – Demand Resource – Testing Requirements

Absent from BPM-011 is a clear statement of how MISO assesses performance of DR LMRs during tests, which happens to be different than how DR LMRs performance may be assessed depending on the selection made for each LMR by the MP during the registration process. CPower recommends including language that outlines the test performance calculation within this section, as it is imperative that all MPs may readily understand how LMRs test performance is different from events.

4. Section 6.5.2. – DR Performance

In Section 6.5.2. – DR Performance, MISO has included language which states, “[u]nless already entered as Self-Scheduled for the event, DRs registered with a firm service level must still show a load reduction. Advanced Reporting should reflect the best estimate of load reduction available during the event. Penalties will still be measured as load above the registered firm service level.” While CPower understands the need for and importance of ensuring MISO operators have the most up to date and accurate information possible regarding the MW available from DR in the DSRI. However, firm service level (“FSL”) baseline measurements afford participating customers the ability to comply with its obligation even if they are already operating at or below the FSL. MPs representing DRs registered with a FSL should not need to enter a Self-Schedule a DR LMR is already operating at or below so long as the availability is appropriately indicated in the DRSI. CPower believes the first additional sentence should be removed or revised to reflect that LMRs registered with an FSL and operating above the FSL would still need to show a load reduction to or below the FSL.

Respectfully,

Peter Dotson-Westphalen

Sr. Director, Regulatory & Government Affairs

CPower

Peter.D.Westphalen@CPowerEnergyManagement.com

781-214-7523

MidAmerican Energy appreciates the opportunity to provide feedback on MISO’s BPM-011 (20230822-23).

4.2.6 BTMG Qualification Requirements

The added bullet states, “Submitting the zip code for the physical location of all generators in the BTMG registration.  Generators located in separate zip codes must be registered separately.”

• Submitting these as separate registrations will be an administrative burden for MidAmerican.
• Currently MidAmerican registers two BTMG groups (which consist of multiple end-use customers); this would increase that task to 62.
• Additionally, updating the daily DSRI would be unmanageable if this would also have to be done by zip code.
• MidAmerican strongly suggests that locational information be handled differently so the administrative burden is less cumbersome.

4.2.7 Demand Resource (DR) – Qualification Requirements

The added bullet states, “Submitting locational information for each asset in the DR registration. That information can include Account Number, Meter Number, Address, City, State, and Zip Code. The minimum required information is the Zip Code for every physical location of the asset in the DR Registration…”

• MidAmerican currently registers two DRs that consists of multiple end-use customers and one DR for thousands of DLC participants. If these need to be submitted individually it would be hundreds of entries as our DRs are located throughout MidAmerican’s entire service territory. If this requirement is removed for Direct Load Control (DLC), it would be increased to 28 entries.
• Additionally, updating the daily DSRI would be unmanageable if this would also have to be done by zip code.
• MidAmerican strongly suggests that locational information be handled differently so the administrative burden is less cumbersome.

6.4.1 Maximum Outage & Derate Threshold (Greater than 31 day rule)

MidAmerican agrees with Entergy that MISO should reconsider how 31+ days are treated. Simply looking at loads in September vs. the middle October highlights the flaw of treating a 25-day outage in September better than a 35-day outage that runs from early October to early November.

The Entergy Operating Companies ("EOCs")^[1] appreciate the opportunity to provide feedback on MISO’s BPM-011.

 The EOCs believe that the 31+ day outage replacement rule is flawed and believe that this rule should be eliminated, or at the very least reformed in a meaningful way. The major concerns that the EOCs have with this rule are:

• It results in generation owners incurring costs that yield no benefits. For example, it incentivizes units to take more-frequent shorter-duration outages that are less efficient than longer-duration outages. The rule does not result in less annual planned outage days but instead creates higher costs for customers. Further, the rule is at times counterproductive to reliability because it causes owners to schedule outages during higher risk periods in order to keep outage durations less then 31 days in a season.
• The PRMR and LCR requirements determined by the LOLE model already incorporates planned outages, including some outages greater than 31+ days. This being the case, the 31+ day outage replacement rule effectively raises the PRMR and LCR requirement above the target levels. Said differently, the impact of planned outages is being double counted, creating unnecessary costs for customers.
• It causes resources to offer higher PRA bids which translates into higher prices that signal capacity scarcity even if there is not scarcity on the system.
• The financial noncompliance charge of CONE + ACP is arbitrary and particularly unreasonable when there is no expectation of scarcity on the system; it does not correspond to the marginal value of reliability provided by additional capacity.
• It creates volatility in year-to-year PRA clearing prices, which works against the purpose of other ongoing MISO reforms, namely the sloped demand curve effort.

 In the event that some form of the 31+ day outage rule continues to exist, the EOCs believe that the impacts of such rule should be through unit accreditation ratings rather than financial penalties and PRA offer price impacts.

WPPI Energy offers the comments below regarding BPM-011.  Along with this we are providing comments and suggested edits in a red-line version

WPPI would request that MISO specify, in the BPM, the mapping between CROW codes and criteria for Generator Planned Outages that are subject to a replacement requirement (where duration exceeds 31 days in a season). It appears that this should be specified in 6.4.1 of the BPM. We would suggest that Generator Planned Outages are those with an Outage Priority of Planned.

The BPM, as updated for the seasonal resource adequacy process, disallowed retroactive ZRC replacement. There is no obvious reason for this rule, which makes replacement more difficult than necessary.. We suggest that replacement should be allowed, after the fact, within some specified period after the end of the season, after which MISO could proceed to calculate non-compliance charges for that season.

MISO proposes to require provision of zip code information for LMRs. MISO acknowledges that this is a proxy for more precise information on electrical location. The BPM should explicitly note that, as a (superior) alternative to zip code, registrants may provide EPNode or Network Model bus number information.

Finally, we noted a number of section-numbering errors in existing BPM language, particularly between 4.2.5 & 4.2.6 and between 4.2.6 & 4.2.7.  We recommend that MISO check the entire document for proper section numbering.

Vistra Corp. (“Vistra”) appreciates the opportunity to submit feedback on the proposed updates to the Resource Adequacy (RA) Business Practices Manual (BPM-11) that MISO shared during the August 23^rd RASC meeting; we look forward to future discussions on this topic. Vistra is submitting feedback on several sections of the BPM, with a particular focus on “Appendix K” which includes the 2024/2025 “Resource Adequacy Timeline.” In light of the recent confusion and uncertainty regarding the calculation of the systemwide UCAP/ISAC ratio- which resulted in FERC Commissioners’ March 17, 2023, Show Cause Order and MISO’s subsequent 11^th hour revisions to the ratio, and disputes that have occurred in other RTOs regarding auction timelines, Vistra believes it’s critical for MISO to incorporate the most impactful RA and Planning Resource Auction (PRA) dates and activities into the MISO Tariff to offer certainty to market participants.  Including those dates in the tariff would provide much needed certainty to market participants, including ratepayers, as future changes could only be made after approval by the Federal Energy Regulatory Commission.

Feedback on Appendix K- Resource Adequacy Timeline

With the implementation of MISO’s revised RA process-- from an annual summer-based RA construct to a seasonal construct-- it’s important that the new and revised processes and procedures that are included in Appendix K, and critical to the success of the RA process, are also reflected in the MISO Tariff. This provides both MISO stakeholders and FERC with an opportunity to review and comment on any changes and ensures that any proposed adjustments to Appendix K don’t violate the Filed Rate Doctrine. As was well documented during the UCAP/ISAC systemwide ratio incident earlier this year, there was significant confusion on whether to recalculate the UCAP/ISAC systemwide ratio because the MISO Tariff fails to address the timing of the calculation of the ratio or the need for, or frequency of, any updates to the ratio. We should not allow that level of uncertainty to persist for other requirements included in the RA Timeline. Vistra appreciates the recent updates MISO has proposed to include in Appendix K, and recommends that at a minimum, the below RA and PRA dates and activities that MISO includes in Appendix K, but does not include in the MISO Tariff, be reflected in the Tariff. Vistra acknowledges that language on the timing of the auction is already contained in the Tariff.

These Resource Adequacy dates may need to be slightly adjusted for future planning years:

1)      October 2, 2023- MISO opens the new Planning Year in the MECT for all 4 Seasons.

2)      November 1, 2023-- Loss of Load Expectation study results published by MISO.

3)      December 15, 2023-- Seasonal Accreditation values are published by MISO; Initial UCAP to ISAC Ratio is published by MISO.

4)      December 15, 2023-- to February 1, 2024-- Market Participants can submit resolution requests for ISAC data published by MISO.

5)      February 1, 2024-- February 1 is the last day for market participants to submit resolution requests on previously posted ISAC data for Schedule 53 resources.

6)      February 15, 2024-- Final UCAP/ISAC ratio and SAC values for Schedule 53 resources will be posted on MECT. Schedule 53 resource owners can start to confirm/convert SAC into ZRCs.

7)      March 26, 2024-- Planning Resource Auction offer window for all Seasons is opened.

8)      March 29, 2024-- Planning Resource Auction offer window for all Seasons is closed.

Question Regarding Appendix K- GVTC Extension

As part of the proposed RA Timeline, MISO included language stating that January 15, 2024, is when “Generation Verification Test Capacity (GVTC (is) due for generators that requested (an) extension.”

Vistra’s question is whether this extension request allows generators to re-test? Or if that extension is simply just an extension for submitting data with no-retesting taking place? Vistra reviewed section 69A of the Tariff but was unable to determine which scenario was correct.

Question Regarding Appendix X- Existing Hybrid Resource Accreditation

Under Appendix X, MISO has inserted language stating “For the Electric Storage Resource component of the Hybrid Resource, availability will be measured by the ESR’s output on each seasonal peak hour in combination with its state of charge on that hour. MISO is evaluating incorporating a depth of discharge in the future that would either be provided by the Market Participant or measured from past operational history, as the longevity of lithium-ion batteries are negatively impacted when continually fully discharged at or near depletion.”

Vistra is seeking clarity on the portion language stating  “…availability will be measured by the ESR’s output on each seasonal peak hour in combination with its state of charge on that hour.” It’s not intuitive to Vistra how you would combine “output” with the “state of charge.”

Manitoba Hydro would like to bring to MISO's attention the following items in the draft BPM-011-r29:

Section 4.2.3 - External Resource

In the first paragraph it states that "External Resources that are also Use Limited Resources must meet all requirements in section 4.2.4 DRR Type I and Type II - Qualification Requirements and be approved by MISO". ------ The reference should likely be 4.2.2.1. Use Limited Resources - Qualification Requirements.

Section 4.2.3.2. External Resources - Qualification Requirements

A new bullet has been added which states "External Resource registration needs to point to a Load CP Node. This ensures the firm transmission PRA requirements." ----- Is this not a duplicate of the second bullet "Firm Transmission Service has been obtained within MISO to deliver the Capacity Resource MWs seeking to be qualified from the External Resource(s) to the CP Node within MISO"?

Typos:

Please correct the subsections under 4.2.6.5 BTMG Deliverability. The 3 subsections below it are not numbered correctly (pages 63-64)

Concerns below pertain to content of Section 4.2.6 and 4.2.7:

Near-Term: DSRI Enhancements and LMR Accreditation (New EP Node/Zipcode identification requirement)

MISO introduced new qualification requirements for Load Modifying Resources in the BPM-011-r29 Redline document posted on August 23, 2023. In section 4.2.6, BTMG’s are now proposed to be required to submit the zip code of the physical location of all generators in the BTMG registration. In Section 4.2.7, Demand Resources (DR’s) are now proposed to be required to submit the zip code for every physical location of the asset in the DR registration.

This new requirement for BTMG and DR seems illogical and unsupported by MISO presentation materials and stakeholder discussions. I understand that MISO wants visibility into the electrical location of the LMR’s to improve operator ability to manage localized transmission emergencies. But requiring the zip code does not lead BA operators to the correct mapping or knowledge of electrical location in the system for reliability operators to effectively manage Transmission System Emergencies or Local Transmission Emergencies. If local connection knowledge is what MISO seeks, require the EP node rather than the US Postal Service mail delivery area. For rural electric cooperatives, in many cases the zip code doesn’t clearly distinguish whether the load is served by the local cooperative’s distribution substation EP Node, or if the load is served by a nearby municipality or township with the same zipcode using a different EP Node.

Near-Term: DSRI Enhancements and LMR Accreditation (New Zip Code Aggregation Boundary)

In Section 4.2.6 of the BPM-011-r29, it's also surprising to see MISO suggesting that BTMG's cannot be aggregated from within a single CP Node (as is today), but instead can only be aggregated from within a zip code. This new requirement would break up potentially large aggregations of dozens of smaller assets into smaller LMR-BTMG's, some of which now may not meet the 100kW threshold.

This also contradicts the discussion and posted Meeting Minutes of the January 17-18, 2023 meeting item 10, which states that "MISO intends to collect the EP Node for all LMRs within a group but will not require groups to be registered for each EPNode".

The new zipcode boundary limit also violates the existing requirement of 4.2.6 which state's that in meeting the 100kW minimum size "an aggregation of smaller resources [...] may qualify [...] if located in the same LRZ."

GRE objects to this new proposed draft BPM language which introduces a requirement to limit registration groups according to each zip code (sic EP Node). MISO hasn't demonstrated why this new boundary restriction for aggregation candidates is necessary or warranted.

Back in March of 2023, WEC Energy Group proposed changes to BPM-011 to clarify responsibilities for ARC LMR reporting.  At the time, we were informed that Eric Thom's team will include this item in the annual BPM review.  However, our proposed clarification is not included in the redline posted for the August 22 and 23 RASC meeting.  The following is our original request from this past March and we request inclusion of this change for RASC review and approval.

WEC Energy Group would like to propose the following changes to BPM-011 to clarify responsibilities for ARC LMR reporting. There are often several LSEs within each LBA that are not affiliated with the LBA operator. The LBA operator cannot supply LSE/ARC specific LMR information and we propose language to clarify the responsibility of the LSE.

To clarify the BPM, we suggest the following change:

BPM-011, page 65 of 231, currently states the following:

Submission of ARC LMR Registrations

The LBA and LSE will verify the following:

• LBA name
• LSE name
• RERRA name
• CPNode name
• End use customer account number
• Meter identification number(s)
• Maximum level of participation (MWs)
• Address of the assets in the ARC registration.

The LSE is the source for retail customer data, confirming the load and meter related information. LBAs have no direct relationship with retail customers.  We request revision to the manual as follows:

Submission of ARC LMR Registrations

The LBA and LSE will verify the following:

• LBA name
• LSE name
• RERRA name
• CPNode name

The LSE will verify the following:

• End use customer account number
• Meter identification number(s)
• Maximum level of participation (MWs)
• Address of the assets in the ARC registration.

Xcel Energy has provided a marked-up version of the BPM redlines to stakeholder relations.  The recommendations are highlighted by a comment bubble so you can easily move from one revision to the next.