In the October 12-13 meeting of the Resource Adequacy Subcommittee (RASC), MISO presented an updated Load Modifying Resource (LMR) accreditation proposal and design elements. Stakeholders were asked to provide feedback.
Comments are due by October 27, 2022.
1) AMP supports WPPI's feedback.
2) IMEA’s LMR resources are net capability tested annually and according to the MISO rules. IMEA resources are also well maintained and exercised regularly. IMEA LMR resources are available every hour of every day throughout the year unless one or more units are on a maintenance outage. Some of the LMR resources may be load limited based on the then current load in any given hour of the IMEA Member of which they are Behind the meter. IMEA puts this information in the DSRI tool for every hour of every day.
DSRI tool does not reflect the actual capability for our units. For capacity accreditation purposes, LMR resources should not be reduced based on sporadic Daily load limitations.
IMEA is willing to work with MISO on this issue.
3) MRES prefers to continue to differentiate LMRs by resource type. Some LMRs are similar in nature to Schedule 53 resources and MRES prefers to treat them this way for accreditation, including the use of 3-year rolling averages. For LMRs that are highly available during all hours, Tier 1 and Tier 2, measuring their availability only in Max Gen or Tier 2 hours creates accreditation risk due to the small number of observations.
As far as intermittent BMTG and energy storage, it makes sense to accredit these similar to how MISO accredits comparable market registered resources (with expectations for change in coming years as penetration increases).
I am happy to discuss.
David Sapper
dsapper@ces-ltd.com
The Entergy Operating Companies ("EOCs")[1] appreciate the opportunity to provide feedback on MISO’s evaluation of potential LMR accreditation reforms. See below for the EOCs response to MISO’s identified LMR questions.
[1] The Entergy Operating Companies are Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, Entergy New Orleans, LLC, and Entergy Texas, Inc.
Voltus Comments to RASC on LMR Accreditation Reforms (RASC-2020-4 RASC-2019-2) (20221012)
October 27, 2022
Voltus appreciates the opportunity to comment on proposed changes to LMR accreditation in MISO’s capacity construct. Voltus was the first, and is by far the largest, aggregator of retail customers (ARC) providing capacity, energy, and operating reserves from demand response to the MISO market. We have participated in the LMR program since 2017, and have witnessed constant changes in that time to how LMRs are enrolled, accredited, measured, paid, and dispatched. These changes make it difficult to build and maintain relationships with the underlying commercial and industrial customers whose curtailable loads are enrolled as LMRs. They also make it difficult to build the demand response industry in MISO. Because of the material impacts of the latest proposed changes to the LMR program on the market participants who offer LMR, any changes should happen via updated Tariff language rather than through business practice manuals.
MISO has proposed both near-term and long-term changes to LMR accreditation. Near term, MISO is proposing using the DSRI web portal to calculate average availability during defined hours per season. As Voltus has stated in prior comments, guidance on how to record availability has changed over time. Even today, there is still no clear guidance on if/how to record dual-registered LMR/EDR availability in the DSRI or how to record availability for loads registered with a Firm Service Level M&V method. As a result, there is no reliable historical data that reflects LMR availability across all LMRs. Therefore, historical data should not be used to derate or otherwise accredit LMRs. If and when clear guidance is established for how to report availability for all relevant resource types, it will make sense to use that data to establish capacity payments in line with the new seasonal construct. At such time, measures of resource availability should be based on demonstrated, resource-specific availability for the given season, or–for new resources–on market-participant level demonstrated availability. The availability of one MP should not influence another’s payments or accreditation.
In the longer term, MISO is proposing redefining LMR to require availability outside of emergency conditions and to require greater load flexibility. As Alcoa said in their comments on this matter, there is a role in system planning for emergency-only resources. There is a larger market for commercial and industrial loads that are willing and able to curtail load to prevent a blackout than of customers who can curtail at any time. LMR should continue to be an emergency program, but Voltus would enthusiastically support the introduction of additional programs that pay a premium for more flexible and responsive demand response loads that can participate outside of emergency conditions.
Which hours should be used when considering LMR availability?
LMRs should be judged based on their availability during conditions that best match when they will be needed and could be dispatched. LMRs can only be called during an EEA 2, so LMR availability should be measured only during MaxGen hours or more severe emergency conditions.
How should MISO account for Firm Service Level (FSL) and Emergency Demand Response (EDR)?
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 firm service level 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. To reflect load drop, availability reported in the DSRI 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.
Dual-enrolled LMR/EDR resources are required to show 0 availability in the DSRI when they have active EDR offers. MISO should update its own systems to track which LMRs and EDRs are related to one another, and to reflect the EDR offer volumes for associated LMRs. These offered megawatts are in fact “available” to MISO, just through EDR dispatches rather than LMR. The difference between peak and current curtailable load should be reported as “self scheduled” for FSL loads available as EDR as well as for loads available as LMR.
If the DSRI is modified to cover all forms of availability - LMRs, EDRs, and Self-Scheduled MW for FSLs -then it will be a reliable tool to account for FSL baselines and EDR resources.
Should MISO still consider transmission losses and Planning Reserve Margin (PRM) add back for LMRs?
Yes, MISO should consider transmission losses and PRM when accrediting LMRs for capacity. A megawatt of curtailment at an end customer facility is worth more than a megawatt of generation from a power plant to the MISO system, because of avoided transmission and distribution system losses. FERC has consistently provided guidance that demand response should receive payment for these avoided system losses. For example, in paragraphs 55-57 of FERC’s Order on Proposed Tariff Revisions issued January 14, 2013 in Docket No. ER12-1627-000, FERC forbade ISO New England from removing transmission and distribution loss credits for demand response assets providing capacity. There is a clear consensus from stakeholders commenting on this matter on the record so far that the status quo of adding back transmission losses and PRM is logical and equitable.
How should MISO collect locational information for LMRs?
MISO should make the enrollment processes for LMRs enrolled by load serving entities the same as for LMRs enrolled by Aggregators of Retail Customers (ARCs). ARCs already provide CP Nodes and physical addresses when enrolling LMRs. ARCs are not able to identify EP Nodes, as EP Node data is not public, so ARCs should not be required to provide EP Node data.
Note on BPM 11 Updates
MISO’s October 12 response to stakeholder comments on the latest BPM 11 redline, here: https://cdn.misoenergy.org/MISO%20Response%20to%20RASC%20BPM-011%20RAN%20Seasonal%20Implementation%20Draft%20Language%20(RASC-2019-2,%202020-2,%202020-3)%20(20220824)626552.pdf, included the following:
Stakeholder feedback: Request clarity regarding a new statement placed in the first paragraph of section 6.4.2. The statement notes “DRs that registered with a firm service level Measurement and Verification methodology must still show a [load] reduction to their firm service level in response to scheduling instructions or be subjected to the penalties described above.” Duke notes that LMRs which are self scheduled or otherwise already below their contracted firm service level will not show any additional reduction. Clarification would be appreciated that in such a scenario MISO would not penalize such an LMR.
MISO response: This statement has been removed and changes to section 4.2.7 addresses the concern more intently.
The most recent BPM 11 posted on the RASC subcommittee page here, https://www.misoenergy.org/events/2022/resource-adequacy-subcommittee-rasc---october-12-2022/, however, still includes the sentence in 6.5.2 reading: “DRs that registered with a firm service level Measurement and Verification methodology must still show a load [sic] reduction to their firm service level in response to scheduling instructions or be subjected to the penalties described above.”
MISO should immediately remove this sentence, per its commitment during prior stakeholder engagement. This language is problematic and unreasonable, and conflates the foundational concepts of a capacity market with that of an energy market. For purposes of capacity planning, so long as a resource is operating at or below its committed Firm Service Level during a dispatch, it is meeting its capacity obligation. MISO cannot “have its cake and eat it too” by both limiting LMRs to their peak load contribution as part of resource adequacy planning and accreditation, while also requiring them to demonstrate performance in response to in-day scheduling instructions. Such a change would severely harm the demand response market in MISO. As capacity resources, LMRs are accredited based on their capabilities during system peak conditions. The LMR enrollment process restricts LMR enrollments to a level no higher than projected load during the MISO seasonal peak hour (calculated based on an average of historical load during seasonal peaks). The value that firm service level resources provide to the system is the delta between their peak load and actual load during an emergency. They provide the same system benefit (i.e., a reduction from projected to actual demand) regardless of why their load is reduced. Other ISO demand response programs in the US, including PJM’s Emergency Load Response program, NYISO’s Special Case Resources program, and ERCOT’s Emergency Response Service program, recognize the benefit of curtailment relative to peak load as decoupled from a resource’s ability to deliver against an energy baseline (i.e., demonstrate load drop in response to scheduling instructions).
Energy is an entirely different product from capacity. For example, for DRR1s participating in the energy market, energy is measured as the ability to curtail load either compared to load just before the dispatch, or during the days prior to the dispatch as defined by the “10-of-10 with symmetric multiplicative adjustment” baseline. LMR resources can receive payments for energy, calculated based on energy baselines, if they dual-enroll in the EDR program and are dispatched as EDRs. Voltus agrees with MISO that in order to receive energy payments, DR resources need to deliver energy against such a baseline. That is not and should not become the case for LMRs.
For both the reasons above and based on its prior stakeholder comments, MISO should strike the proposed language requiring demonstrated load drop to achieve a firm service level. Finally, this new language rises to the level of a material change that would need to happen via a Tariff update, rather than through business practice manuals.[1]
Voltus looks forward to continued dialogue with the Resource Adequacy team at MISO as the LMR program adapts to fit the new seasonal construct.
Respectfully submitted,
Allison Bates Wannop
Senior Director of Legal and Regulatory Affairs
Voltus, Inc.
awannop@voltus.co
[1] City of Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985); see also Demand Response Coal. v. PJM Interconnection, L.L.C., 143 FERC ¶ 61,061, at P 17 (2013) (“The FPA requires all practices that significantly affect rates, terms and conditions of service to be on file with the Commission, and these practices must be included in a Commission-accepted tariff rather than other documents”).
Generally, Wolverine supports thermal/dispatchable BTMG, intermittent BTMG, and BTM storage be treated comparable to their respective in-front-of-the-meter market resources where “availability” is the focus to derive their SAC/ELCC accreditation. Further, because availability is the focus for accreditation, Wolverine supports MISO establishing DR rules based on their historical availability (not the minimum dispatch requirements currently being used) reported to MISO (e.g., in the DSRI).
1. Which hours should be used when considering LMR availability?
WEC Energy Group supports the use of the same Schedule 53 Tier 1 and Tier 2 hours (MaxGen hours + tight hours up to 65 hrs/season) that are applied to other resources to determine the availability of LMRs. Since LMRs cannot be used without first declaring an EEA 2, MISO and stakeholders should consider whether Tier 1 hour availability provides any accreditation value. If there is no value, we don’t see the need to determine LMR availability during Tier 1 hours.
2. How should MISO account for Firm Service Level (FSL) and Emergency Demand Response (EDR)?
The Demand Side Resource Interface (DSRI) needs to provide operators the ability to report Available LMR MW with a qualifier for the difference between Available MW and the amount cleared in the PRA such as “not consuming” (in addition to “self-scheduled”, “maintenance”, or “outage”). For example, a 40 MW interruptible load (Demand Resource) with a 20 MW FSL that is consuming 30 MW in real time will only have 10 MW available to curtail because 10 MW is already “not consuming”. Operators are hesitant to use “self-scheduled” to represent the 10 MW that is not consuming because they have not implemented a self-schedule (nor is the 10 MW of DR on forced or planned outage – it just isn’t consuming). Similar to a Schedule 53 resource that has an hourly Emergency Max offer and availability of x MW but is currently dispatched at x-y MW, DR availability should reflect its Available MW plus the amount that is either “not consuming” or “self-scheduled”.
3. Should MISO still consider transmission losses and Planning Reserve Margin (PRM) add back for LMRs?
For a Demand Resource, yes. When LSEs account for a registered DR of x MW on the supply side, they include that same amount of load (x MW) on the demand side (in other words, the load is not net of the registered DR). Since load on the demand side is adjusted for transmission losses and included when the PRM is applied, the DR will offset an equal amount of load plus losses plus PRMR on the demand side.
We do not believe that an LMR explicitly registered as a BTMG should have its capacity credit grossed up for transmission losses and the PRM because a BTMG does not remove load from the demand side; it adds generation to the supply side.
4. How should MISO collect locational information for LMRs?
We continue to believe that MISO should not require locational information on a scale less than the LBA (or CPNode) level because in many cases, locational information at a more granular level will not have any impact on its deployment; some LSEs simply can’t deploy LMRs on a scale less than the LBA. If an LSE has the ability to deploy LMRs on a more granular scale, such as EPNode or physical address, those LSEs should have the option, but not the obligation, to report on that level.
Comments
of the
Association of Businesses Advocating Tariff Equity (ABATE),
Illinois Industrial Energy Consumers (IIEC),
Louisiana Energy Users Group (LEUG),
Texas Industrial Energy Consumers (TIEC),
Coalition of MISO Transmission Customers (CMTC),
Midwest Industrial Customers (MIC),
and
NIPSCO Large Customer Group (NLCG)[1]
Regarding
RASC: LMR Accreditation Reforms
(RASC-2020-4 RASC-2019-2) (20221012)
October 27, 2022
ABATE, IIEC, LEUG, TIEC, CMTC and MIC, as representatives of the End-Use Customers (EUC) Sector, and NLCG appreciate this opportunity to provide comments to MISO.
At the October 12-13 meeting of the Resource Adequacy Subcommittee (RASC), MISO presented an updated Load Modifying Resource (LMR) accreditation proposal and design elements for the same. Stakeholders were asked to provide feedback.
MISO in its October 12-13 presentation to the MISO RASC indicated that its specific near-term proposal that it intends to file with the Federal Energy Regulatory Commission (FERC) in early 2023 is to use reported average availability during defined hours for each season from the MISO Demand Side Resource Interface (DSRI) of the MISO Market Portal as a basis for capacity accreditation for LMRs. In addition, MISO indicates that as part of that proposal it also intends to require locational information on LMRs be submitted during the annual LMR registration/qualification process. MISO has requested feedback on this near-term proposal as well as four specific design elements of that proposal.
We have previously provided comments to MISO on its various LMR capacity accreditation proposals on March 23, 2022, August 3, 2022 and September 7, 2022. They can be accessed at:
The following key points from those comments apply to MISO’s specific October 12-13, 2022 near-term LMR Capacity Accreditation proposal:
MISO’s current proposal to use the sum of DSRI-reported self-scheduled MW and Available MW as the basis of LMR availability, and not DSRI-report Available MW alone, is in line with our previous comments. In addition, also consistent with our previous comments, MISO has recognized the MISO DSRI does not currently properly account for the availability of LMRs using the Firm Service Level (FSL) Option or LMRs that are also registered as Emergency Demand Response (EDR). We appreciate MISO recognizing and proposing to address these concerns. As we have detailed in our past comments, it is imperative that the sum of DSRI-reported self-scheduled MW and Available MW be used, if DSRI information is going to be used for LMR capacity accreditation, in order to properly reflect the total availability of a LMR to provide energy in a given hour, not just the incremental energy that is available from the LMR above the self-scheduled energy of that LMR in that hour. In addition, it is imperative to recognize that the proper measure of availability for LMRs that use the FSL Option is their availability to reduce their demand down to their firm service level (i.e., curtail all of their non-firm demand) in a given hour, not their availability to curtail down by a specified amount of MW.
While we appreciate MISO recognizing and proposing to address the foregoing concerns, we would caution there are also timing concerns with respect to the foregoing concerns. Specifically, it is very important that DSRI information not be used for the capacity accreditation of a specific LMR until there is at least four consecutive seasons of accurate information available in the DSRI for that LMR.
As MISO has recognized, the DSRI does not currently properly reflect the availability of LMRs using the FSL option or the availability of LMRs that are also registered as EDR. Regardless of the fix MISO may choose to rectify this issue with the current MISO DSRI, once the fix is in place, sufficient time will need to be allowed such that four consecutive seasons of information can be accumulated from the affected LMRs prior to applying that information toward determining the capacity accreditation for those LMRs.
There can also be timing issues for LMRs that do not use the FSL and are not registered as an EDR. For example, LMRs that are registered with MISO and converted to UCAP for a given planning year, but ultimately are not used in a Fixed Resource Adequacy Plan (FRAP) and not cleared in the Planning Resource Auction (PRA) for that planning year, are under no obligation to MISO to curtail or generate during MISO Generation Events. However, these LMRs are not necessarily unregistered from MISO and, as a result, are included in the DSRI for the planning year in which they did not clear in the PRA despite the fact they have no obligation to MISO to curtail or generate energy during Maximum Generation Events during that planning year. Because of their inclusion in the DSRI despite not being cleared in the PRA, the Available MW from such LMRs have to be forced to zero in the DSRI. If this is not done, MISO will generate Scheduling Instructions for those LMRs during LMR Drills and Maximum Generation Events despite those LMRs during that planning year having no obligation to curtail or generate energy during MISO Maximum Generation Events due to their presence in the DSRI. Such zero entries in the DSRI do not reflect the availability of those LMRs in future MISO planning years and should not be the basis of capacity accreditation for those LMRs for those future planning years.
To address the above timing issues, MISO’s near-term proposal should not apply DSRI information to the capacity accreditation of any given LMR until there is four consecutive seasons of accurate information in the DSRI regarding the availability of that LMR. This means the use of DSRI information for capacity accreditation should not apply to LMRs using the FSL option, or LMRs that are also registered as EDR, until MISO has implemented a fix to the DSRI to properly account for the availability of these LMRs and there has been sufficient time to accumulate four consecutive seasons of information in the DSRI from these LMRs with the fix in place. It also means that the use of DSRI information for capacity accreditation should not apply to LMRs with respect to their DSRI entries during a planning year in which they were not used in a FRAP and not cleared in the PRA since that information will not reflect their availability in future planning years since the entered values may have had to be forced to zero to avoid receiving Scheduling Instructions from MISO.
In addition the above comments, we offer the following comments to MISO on MISO’s four specific design element questions from Slides 22 through 25 of MISO’s October 12-13, 2022 presentation to the MISO RASC:
Which hours should be used when considering LMR availability?
LMRs are only called during Maximum Generation Events that reach, or are expected to reach, Step 2a or higher. Given this, what is critical is their ability to perform during those hours, not others. Therefore, if DSRI information is used as the basis of LMR capacity accreditation, only information from Seasonal MaxGen hours should be used.
This said, it is very important that MISO not double count forced outages in the capacity accreditation of LMR BTMG. The capacity accreditation for LMR BTMG already reflects the historical XEFORd of that LMR BTMG. As a result, lack of availability during Seasonal MaxGen hours due to forced outages should not count a second time against the capacity accreditation of LMR BTMG since those forced outages are already included in the XEFORd value that is already being used for the capacity accreditation for LMR BTMG. Alternatively, the use of XEFORd values for the capacity accreditation of LMR BTMG could be dropped to avoid the double counting of forced outages against capacity accreditation for LMR BTMG. This issue does not apply to LMR DRs since the capacity accreditation for LMR DRs does not involve generating units with forced outage data.
How should MISO account for Firm Service Level (FSL) and Emergency Demand Response (EDR)?
With respect to LMR DR using the FSL Option, MISO needs to first understand what is being reported in the DSRI for LMR DR using the FSL option. Specifically, what is currently being reported in the DSRI for LMR DRs using the FSL Option as “Available MW” is simply the LMR DR’s forecasted hourly non-firm demand that will be curtailed if the LMR DR is called upon. That value provides absolutely no information with respect to how much of its non-firm load it already expects to have down in that hour or whether that LMR DR is able to fully curtail down to its firm service level. It just indicates how many MW of non-firm demand is expected to be curtailed if MISO calls curtailments.
MISO’s preliminary proposed fix for the DSRI with respect to LMR DR using the FSL Option has been to have LMR DRs using the FSL Option submit under the label of “Self-Scheduled MW” the amount of non-firm demand the LMR DR already expects to have down in each hour. While we applaud MISO trying to develop a solution for FSL LMR DRs, we do not believe this specific proposed solution would work well. Specifically, we would caution that the sum of Self-Scheduled MW and Available MW in the DSRI for a given hour under MISO’s preliminary proposed solution may still not indicate whether the FSL LMR DR in that hour is in fact able to fully curtail down to its firm service level. The reason for this is that the forecasted hourly non-firm demand of a FSL LMR DR can be greater than the amount of demand reduction that was registered with MISO for the FSL LMR DR. As a result, while the sum of reported Self-Scheduled MW and Available MW for a FSL LMR DR under MISO’s preliminary proposed solution would identify the non-firm load that is already expected to be not present and the amount of non-firm load that is expected to be curtailed if MISO calls on the LMR, it would not identify whether the FSL LMR DR will be able to fully curtail down to its firm service level in that hour. This is a byproduct of MISO in the DSRI (and in the MISO MCS before it) trying to force FSL LMR DRs to fit into reporting that was designed for LMR DRs that do not use the FSL Option.
Our recommendation for FSL LMR DRs is that MISO eliminate hourly Available MW and Self-Scheduled MW reporting for FSL LMR DRs and instead collect the following through the DSRI from FSL LMR DRs for each hour: (i) the forecasted total demand of the FSL LMR DR for the hour; (ii) whether the FSL LMR DR is available in that hour to fully curtail its demand down to its firm service level (the registered firm service level of the FSL LMR DR would be shown on the DSRI screen to provide a reference point); and (iii) if not available to fully curtail its demand down to its firm service level, the demand level in MW the FSL LMR DR expects to be available to curtail down to instead of its firm service level. Note that the second item in the foregoing list would simply be a check box that would be prepopulated as checked in the DSRI for those hours in those months the FSL LMR DR is available as indicated at the time of the registration of the FSL LMR DR with MISO. If later the FSL LMR DR is not available to fully curtail down to its firm service level in a given hour, the FSL LMR DR would override the prepopulated check mark by unchecking it and entering a MW amount for the demand level to which it expects to be able to curtail down to instead.
From this collected information, MISO would in its systems be able to calculate the expected additional MW curtailment that would occur for each FSL LMR DR by subtracting: (i) the FSL LMR DR’s firm service level from the FSL LMR DR’s forecasted total demand (if the FSL LMR DR is available to fully curtail its demand down to its firm service level) or (ii) the demand to which the FSL LMR DR expects to be able to curtail down to (instead of its firm service level) from the FSL LMR DR’s forecasted total demand (if the FSL LMR DR is not available to fully curtail its demand down to its firm service level). In addition, MISO would now of course know in each hour whether a FSL LMR DR expects to be available to curtail down to its firm service level and, if not, the demand level to which the FSL LMR DR is expected to be able to curtail down if it is not available to fully curtail down to its firm service level. We believe this approach would be a better solution for fixing the current problem of the MISO DSRI not properly accounting for the availability of FSL LMR DRs.
With respect to LMRs that are also registered as EDR, at this time we think the best solution would be to require these LMRs to use the DSRI just like all other LMRs, but to add a check box in the DSRI for each hour indicating whether the LMR also has an EDR offer for that hour. The prepopulation of the check box as checked or unchecked in the MISO DSRI would be selectable by the FSL LMR DR and be adjusted by the FSL LMR DR for specific hours as necessary. We expect there would also likely need to be a link in MISO’s systems that ties the LMR with the registered EDR that is associated with it.
Should MISO still consider transmission losses and Planning Reserve Margin (PRM) add back for LMRs?
The status quo of grossing up LMR DR registered curtailment MW for transmission losses and PRM should be continued. As was explained in detail in our comments to MISO of March 23, 2022[2], prior to the MISO 2014/2015 Planning Year, this LMR type was generally captured, when addressing resource adequacy, by excluding, or subtracting off, the end-use customer’s forecasted non-firm demand at the time of the system peak from the forecasted system peak demand of the end-use customer’s Load Serving Entity (LSE). Under that practice, the LSE of the end-use customer was appropriately not required to carry capacity (including that for planning reserve margin and transmission losses) for the end-use customer’s non-firm load since the non-firm load would be sufficiently available to be completely shut down as necessary during MISO Maximum Generation Events.
Starting with the 2014/2015 Planning Year, MISO’s resource adequacy provisions were modified to remove this physical load netting option. Specifically, MISO replaced the physical net load netting option with an option to virtually net load. Under this virtual netting option, an LSE’s peak system demand forecast could no longer directly exclude the end-use customer’s non-firm load. However, instead, MISO would grant capacity in the form of Zonal Resource Credits (ZRCs), for the forecasted non-firm demand of the end-use customer at the time of the system peak, that are grossed up for planning reserve margin and transmission losses. To the extent the LSE then chose to apply those ZRCs to its total capacity responsibility (Planning Reserve Margin Requirement), it would leave the LSE with a net capacity responsibility that is identical to what it would have been if physical load netting were still permitted. Like under the former physical load netting option, under the virtual load netting option, the LSE is appropriately not required to carry capacity (including that for planning reserve margin and transmission losses) for the end-use customer’s non-firm load. This virtual load netting option remains available under the current MISO Tariff and continues to be used by many LSEs for their interruptible end-use customer load that is registered as an LMR Demand Resource. Elimination of the current gross up for transmission losses and PRM for LMR DR would inappropriately eliminate the virtual load netting option and not be consistent with the fact that capacity need for transmission losses and PRM is not incurred for this non-firm demand.
How should MISO collect locational information for LMRs?
As we noted at the outset of our comments, MISO should collect, upon registration, the CPNode of each LMR in order to get accurate electrical location information. It should not try to obtain electric location information on a more granular basis for LMRs than the CPNode level because LMRs can consist of the aggregation of load curtailment spread out over a wide geographic area within a given Local Balancing Authority (LBA) Area through utility or Aggregator of Retail Customer load management systems. We would also note that MISO Type 1 Demand Response Resources (DRRs) are only required to be identified down to the CPNode level with respect to location. What is sufficient for Type 1 DRRs should be sufficient for LMRs given Type 1 DRRs are much more likely to be utilized before LMRs when addressing transmission constraints given LMRs can only be used in emergency situations.
Thank you for providing us an opportunity to provide these comments. If it would be of help, we would be glad to discuss any of the above comments further with MISO. We would also be glad to make a presentation at the RASC with respect to any of the above to help both MISO and its stakeholders better understand our comments. With respect to either, please do not hesitate to contact any of the following representatives:
Jim Dauphinais
Brubaker & Associates, Inc.
(Consultants to ABATE, IIEC, LEUG, NLCG and TIEC)
(636) 898-6725
Ali Al-Jabir
Brubaker & Associates, Inc.
(Consultants to ABATE, IIEC, LEUG, NLCG and TIEC)
(361) 994-1767
Kevin Murray
McNees Wallace & Nurick LLC (for CMTC)
(614) 719-2844
Kavita Maini
KM Energy Consulting, LLC (Consultants to MIC)
(262) 646-3981
[1] ABATE, IIEC, LEUG, TIEC, CMTC and MIC 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).
How should MISO account for Firm Service Level (FSL) and Emergency Demand Response (EDR)?
4. Add additional fields to report EDR offers
Should MISO still consider transmission losses and Planning Reserve Margin (PRM) add back for LMRs?
1. Status quo
Transmission Losses:
LMR's ZRC value should continue to get grossed up for transmission losses because they are offsetting the need for traditional generation that is connected to the transmission system. In order for generation to serve load, that generator's MW power at the point of interconnection needs to travel through transmission network losses to serve network load. LMR's provide that equivalent service locally without carrying electrons through lossy transmission lines, therefore their the LMR's MW reduction service is equivalent to the generators MW power + Transmission Losses.
To reiterate, consider a 100 MW Generator that delivers electricity through a 1 MW transmission loss, so it only delivers 99 MW of load at the point of consumption. Alternatively, if that load was able to be curtailed by a 99MW LMR, it provides the equivalent capacity value to the Bulk Electric System as a 100 MW generator would have otherwise provided.
Planning Reserve Margin (PRM):
LMR's ZRC value should continue to get grossed up for PRM because the load reduction measures help to lower the additional risk margin of a MP's load requirements + risk margin (aka PRM).
If an un-registered 100 MW load management measure "LMM" is dispatched over peak conditions and contributes to the reduction of an LSE's coincident peak forecast requirements and PRMR, the load reductions value is providing 100 MW + PRM% value to the overall need to procure PRMR. Suppose PRM% = 8%, then an unregistered 100MW load management measure provides 108MW of PRMR value to the utility.
Including the PRM % add back puts the LMR capacity value on an even playing field with unregistered LMM assets. LMR's are providing capacity value equivalent to their load reduction as well as the avoidance of carrying the extra PRM% risk margin.
How should MISO collect locational information for LMRs?
1. CPNode
MISO uses LMR's as tools for capacity emergencies, which are rarely (if ever) localized or declared in a region below the North/Central/South regions, and sometimes directed at the LBA level. MISO has not demonstrated how breaking up LMR's into EP Nodes or lower would provide tools to better serve capacity emergencies.
LMR's were not intended to be instruments to resolve transmission congestion. Locational Marginal Price is the prevailing tool to manage one side of a transmission constraint, which leads to the scheduling of assets in the Energy and Operating Reserve markets. LMR's don't participate in E&OR markets, but Demand Response Resources (DRR's) do.
I think MISO's reasoning for wanting to manage transmission constraints is sound, but LMR's are not the tool to use. DRR's are the tools to use for managing localized transmission constraints.
Advanced Energy Management Alliance (“AEMA”) [1] respectfully submits the following comments to the MISO Resource Adequacy Sub-Committee (“RASC”) on the feedback request made by MISO at the October 13, 2022, meeting of the RASC.[2] AEMA is a trade association under Section 501(c)(6) of the Federal tax code whose members include national distributed energy resource companies and advanced energy management service and technology providers, including demand response (“DR”) providers, as well as some of the nation’s largest demand response and distributed energy resources. AEMA members support the beneficial incorporation of distributed energy resources (“DER” or “DERs”), including advanced energy management solutions, into wholesale markets as a means to achieving electricity cost savings for consumers, contributing to system reliability, and ensuring balanced price formation. These comments represent the collective consensus of AEMA as an organization, although they do not necessarily represent the individual positions of the full diversity of AEMA member companies.
At the October 13th meeting of the RASC, MISO presented their proposal for near and long-term actions on LMR accreditation. In the near-term, MISO proposes to “utilize Demand Side Resource Interface (DSRI) to average availability during defined hours per season” and to “require locational information through the registration/qualification process.” In the long-term, MISO proposes to “redefine LMR and Demand Response to be available and visible both in and out of emergency conditions” and states that “resources behind emergencies will need to be highly flexible and reliable.”[3]
MISO requested feedback on the updated LMR accreditation proposal and certain design elements. AEMA offers the following comments:
Additionally, MISO should not utilize historical data, from before implementation of any new process as part of the LMR accreditation because rules have changed regarding reporting of resource availability, Emergency Demand Response (EDR) availability, and self-schedule MWs. MISO must establish criteria for accreditation, then modify the systems to capture the relevant data and then begin tracking for future accreditation.
Additionally, MISO has stated that resources “will need to be highly flexible and reliable.” AEMA encourages MISO to consider the incentives that will motivate consumers to be more flexible and reliable. Imposing increased performance requirements may drive some emergency only resources that can support the grid for reliability out of MISO’s control. This would be detrimental to both reliability and operational efficiency of the MISO market.
An LMR that clears in the capacity auction has an obligation to perform in an emergency. Whether self-scheduled or only reported as “available” in the DSRI, the resource has clearly met its performance obligation if an emergency occurs, and it is operating at or below its FSL. Therefore, the resource should certainly receive credit for the self-scheduled MWs in the accreditation process.
In the consideration of this design element, MISO has identified other potential fields for reporting information about resources. AEMA reiterates the point that MISO should be cautious about creating increasing levels of reporting requirements that may provide little to no value. As reporting requirements increase, the complexity increases and LMRs will have less and less incentive to make themselves available to MISO operations. Should MISO continue to pursue additional requirements to provide further locational or other information, MISO should clearly define the issues facing MISO operators, as well as provide more detail how this information will be utilized to increase reliability.
AEMA appreciates MISO’s consideration of these comments as part of the examination of resource accreditation issues within MISO. We welcome any questions, and encourage you to contact either Katherine Hamilton, Executive Director of AEMA, or DeWayne Todd, representative of AEMA, should you wish to discuss this with AEMA members.
Respectfully Submitted,
Katherine Hamilton
Executive Director, Advanced Energy Management Alliance
Katherine@aem-alliance.org
202-524-8832
or
DeWayne Todd
DDT LLC
dewaynetodd1297@gmail.com
812-573-8052
WPPI offers the following initial thoughts on MISO's discussion of potential future changes to LMR accreditation included in the Item 12.a.iii presentation to the October RASC (https://cdn.misoenergy.org/20221012%20RASC%20Item%2012a%20iii%20Non-Thermal%20Accreditation%20MISO%20Presentation626584.pdf). We expect that stakeholders—including WPPI—may refine their thoughts as the discussion proceeds, so we recommend that MISO use this round of responses only to prepare for further stakeholder discussion and that MISO seek feedback on these questions again at the end of that discussion.
MISO’s feedback request refers to “an updated [LMR] accreditation proposal.” MISO’s proposal appears to be to “[move] forward with an availability-based accreditation approach for LMRs” as noted on slide 2 of the Presentation. WPPI is generally comfortable with this direction. MISO also requests input regarding four sets of design options, to which we respond below.
Which hours should be used when considering LMR availability?
How should MISO account for Firm Service Level (FSL) and Emergency Demand Response (EDR)?
Should MISO still consider transmission losses and Planning Reserve Margin (PRM) add back for LMRs?
How should MISO collect locational information for LMRs?
MISO’s presentation indicates an interest in finding a mechanism for longer-lead LMRs to participate in MISO DA & RT Markets. We note also that the posted comments of Alcoa Power Generating, Inc., on this feedback item, call for exploration of “an alternative registration option that could motivate existing LMRs to transition to a status in between DA/RT participation and emergency only.” We think this idea merits some consideration. It occurs to us that allowing long-lead LMRs to be considered in the Reliability Assessment Commitment might permit MISO to consider and accredit these in a manner similar to that of market Capacity Resources with similar notification lead times. This could potentially be extended to the Look-Ahead Commitment as well. W
Finally, we note that MISO’s presentation says, at slide 21/29, that emergency resources “will need to be highly flexible and reliable.” WPPI does not agree with this. Various Planning Resources have varying degrees of flexibility and reliability, and there is nothing wrong with this. Lower levels of flexibility or reliability relevant to resource adequacy should be managed by appropriately reduced accreditation, not by prohibition or disqualification.
Duke Energy's feedback is as follows:
LMR Accreditation Based on Reported LMR Availability (slide 22):
While utilization of a single seasonal peak coincident hour would likely be the least burdensome, if historical availability were to impact LMR accreditation, Option 1 of using a mix of Max Gen hours (Tier 1 / Tier 2) would appear to be most in-line with thermal generation accreditation reforms as well as address accreditation of LMRs in a manner consistent with the times (hours) of potentially highest risk.
Duke would like to point out a potential unintended consequence of this approach, however. Historically, MISO has allowed LMRs be to registered such that individual resources represent an aggregation of common/like end use customers typically participating in retail DR programs. In this way, a relatively low number of LMR registrations represent a much higher number of individual end use customers. However, the criteria by which individual participants are aggregated into common resources are oftentimes voluntary. Criteria such as notification time, testing compliance, EM&V methodology, etc. may readily change year-over-year. This can result in individual end use customers shifting between resources each Planning Year. Due to this, an end use customer’s availability in one Planning Year may not impact the availability/accreditation for that same end use customer in the next Planning Year. Such an result may not be intended and given the consequences, should be carefully considered.
Fields Available in DSRI for Capability Reporting and Use in Future LMR Accreditation (slide 23):
Duke agrees LMRs utilizing a Firm Service Level (FSL) M&V Methodology would benefit from having an additional field created in the DSRI to track “maintenance MW”. FSL-type curtailment tends to be the most readily adopted by end use customers. While a CBL must be created to estimate future capability (10 of 10), DSRI in its current form is not able to track capability which is not available during a given time period, but is known – such as planned maintenance at a manufacturing facility, or other recent reductions in consumption not accounted for in the rolling 10 of 10 baseline. While the capability value “Available” to MISO can be modified on an hourly basis in DSRI to account for such periods, the reduction in capability in such a scenario is not due to local (Self-Scheduled) dispatch, but rather a reduction in load at the end use customer impacting the overall capability of the resources for that period of time. If MISO wishes to have this level of insight for FSL-type LMRs, adding an additional field in the DSRI for “Maintenance” should provide it.
LMR Add-Back for Transmission and PRM (slide 24):
Duke strongly supports the status quo of increasing LMR capability as reported at an end-use customer level back up to the level of relief it provides to the transmission system. Curtailment of end-use load directly impacts the need of generated capacity inclusive of transmission losses. Additionally, so long as PRM is first applied to the entire load forecast (not considering any LMR capability), LMR capability should also be increased by the same PRM.
Locational Information for LMRs (slide 25):
Duke would suggest collecting locational information only for the largest LMRs representing singular end-use customer sites (options 4 and 5). Additional discussion would be helpful on this topic, but to the extent registration processes are not significantly impeded (ie: previously mentioned ability to aggregate like end-use customers into common resources), providing granular location information in a separate form or submission should not be significantly burdensome, particularly if it were to utilize CP Node or Physical Address (Options 1 or 2). However, if the MECT would be updated in a manner requiring individual registrations for each end-use customer inclusive of locational information, such an approach would more significantly increase the burden of participating and registering LMRs.
LMRs are currently designed to help in emergency capacity situations. Seasonal MaxGen hours should therefore be considered. If a different approach is developed, an additional type of LMR category should be created to allow for continued participation of emergency only capacity resources.
Yes. The current process is reasonable.
Otter Tail would appreciate more insight as to how each of the proposed options would be beneficial for MISO. Otter Tail would be supportive of enhancing MISOs operations to the best of our ability to what MISO deems to be most useful. However, Otter Tail would like to note the technological limitations that would be present for aggregated resources.
As a MISO Member representing numerous Municipal utilities with LMRs in MISO, Michigan Public Power Agency (MPPA) has a critical stake in LMR accreditation and continues to work with MISO and other Stakeholders to refine LMR contributions to reliability and properly recognize them through accreditation. In that spirit, MPPA offers the following feedback on MISO’s proposal and design elements:
Among the potentially competing objectives of Resource Adequacy (RA) reform, two valid objectives require more emphasis: simplicity and consistency.
ST proposal:
In accrediting LMR BTMG, MISO should use 3 years of historical data and the same Tier 2 hours as Schedule 53. The marginal value of a different approach is outweighed by increasing the already confusing level of complexity of the Schedule 53 approach and missing an easy opportunity for consistency across resource classes.
Any locational information should not require the LMR registrant to know MISO’s network and commercial models, but provide MISO with sufficiently specific information known to the registrant for MISO to determine where within its models the LMR belongs.
MISO should retain the status quo approach with respect to the treatment of transmission losses and Planning Reserve Margin (PRM) in LMR accreditation, given LMR’s interconnection at voltages below transmission and the option for the registrant to reduce their peak load forecast rather than register the LMR, respectively. MISO has provided no rationale for modifying these logical adjustments, making them appear to be an arbitrary and unjustified reduction in accreditation.
LT proposal:
MPPA understands and supports MISO’s goal of incentivizing development—and disincentivizing retirement—of resources with attributes required for system reliability. However, MISO is attempting to use RA accreditation in the planning horizon to solve reliability concerns better managed in the operating horizon. Strong, positive economic signals in MISO’s markets must work in concert with RA accreditation requirements.
Q: Which hours should be used when considering LMR availability?
A: Using Tier 1 and Tier 2 hours would be the most equitable with the approved Schedule 53 concepts. Doing so would also provide incentive for LMRs and EDRs to be available in all “tight” hours that could potentially become Tier 2 hours, which would thereby provide greater reliability benefit to MISO.
Q: How should MISO account for Firm Service Level and Emergency Demand Response?
A: EDRs are currently required to enter zero MW in DSRI when they have EDR offers. This prevents double counting. If MISO wants to use DSRI for accreditation, then any of the proposed rework options for the interaction between DSRI and EDR offers could allow for proper accounting of EDRs.
Q: Should MISO still consider transmission losses and PRM add back for LMRs?
A: A gross up for BTMG-positioned resources and DR for transmission losses and PRM is equitable.
Q: How should MISO collect locational information for LMRs?
A: We would be willing to provide better locational information as long as it is used as a tool for MISO Operations and there is no after-the-fact assessment and associated penalty that is charged for attempting to help inform MISO’s decisions.
ITC supports MISO’s efforts to review LMR accreditation. The fact that LMRs are only available to MISO for dispatch during EEA2 makes it imperative that they be available and ready to perform during EEA events. Thus, LMRs with a long start time (greater than 2 hours) do not seem suitable for EEA performance which might reasonably require near real-time action to reduce load.
ITC supports exploring requirements to identify the locations of LMRs through the use of telemetry to enhance MISO’s situational awareness which could help MISO operators to understand where load might be dropped (thus potentially changing congestion patterns).
LMR accreditation should reflect the emphasis placed on their availability in EEA conditions. As it is reasonable to expect Max Gen events during the Tier 1 and Tier 2 hours, this seems like a reasonable place to evaluate availability.
For Firm Service Level and Emergency Demand Response –if the load is not consuming at the time it is called, interrupting it ‘down to’ FSL or deploying EDR may not have the intended consequence of freeing up energy to the system. Thus, FSL and EDR resources should include self-Scheduled MW as well as report hourly loads. Maintenance reporting would also be valuable because it can help to expand understanding of the actual availability of the resources, similar to how other resources track availability.
DTE Electric appreciates the opportunity to provide feedback on the accreditation proposal and design elements for LMR accreditation.
If MISO moves forward with the near-term proposal to utilize DSRI availability as a measure of accredited capacity, DTE would strongly encourage MISO to create a new baseline evaluation method for measurement and verification of demand response. With the current 10 in 10 method, there are incentives to be conservative to account for weather impacts to avoid penalties due to a volatile 10-day lookback period. The temperature normalization available for this method is extremely complicated and often inaccurate. Using a regression analysis with load forecast could lead to much more accurate measurements, or allowing us to exclude outlier data, such as a “Best 3 of 5 days” method like other ISOs use.
Which hours should be used when considering LMR availability?
Out of the available options, DTE prefers option #2 of Seasonal MaxGen Hours only.
In the case of no MaxGen hours, demand response availability could be measured by the peak hour for each season. This would align with the current requirements to demonstrate their performance during at least one peak hour of the year with seasonal applicability.
DTE is opposed to accrediting LMRs based on any hour in which they were not called to perform, as the specific program requirements contained within customer retail tariffs could limit performance in other hours which would incorrectly and inappropriately decrement accreditation.
Should MISO still consider transmission losses and Planning Reserve Margin (PRM) add back for LMRs?
Yes, DTE strongly encourages MISO to continue adding transmission losses and PRM back in for LMRs. Since LMRs are a direct reduction of load, we should continue to receive the same benefits. DTE sees no logical reason to change the PRM/transmission loss method.
How should MISO collect locational information for LMRs?
MISO should decide how specific the need is, based on their modeling, although DTE would recommend keeping the location at the CP nodal level. It is not realistic to provide the expected demand reduction at the EP node level due to the nature of customer-driven demand response programs, as they are naturally geographically disparate.
Xcel Energy appreciates the opportunity to provide feedback regarding the Load Modifying Resource (LMR) accreditation proposal MISO presented in the October 2022 RASC.
Which hours should be used for LMR availability?
Since LMRs are not currently accessed unless there is an emergency event, Xcel Energy believes that only the Seasonal MaxGen hours should be used for accreditation. However, many seasons don't have emergency events, so performance during monthly peak hours across several years could be used. It is important to allow for adjustments to historical data for aggregated LMRs, however, as customers are added and dropped from these programs.
How should MISO account for FSL and EDRs?
To increase transparency of the reasons that LMRs are not available, MISO should add two fields to the DSRI that will allow MPs to provide adjustments to hourly firm service levels and availability due to maintenance.
Should MISO still consider transmission losses and PRM add back for LMRs?
Xcel Energy believes there should be no changes to the current process that adds transmission losses and PRM back for accreditation purposes.
How should MISO collect locational information for LMRs?
Xcel Energy reiterates our support to incorporate location information for LMRs to identify the load resources that will be impactful during an emergency event when there is a binding constraint that splits an LBA. MISO needs this information to provide accurate scheduling instructions immediately instead of through a manual process between the MISO RC and the LBA. It is likely that this manual process will also have another layer of communication as the LBA will need to coordinate with the LSE. Time and accuracy is of the essence during emergency events and a manual process for LMR instructions takes operators away from other critical activities required for managing reliability. Providing the locational information for LMRs within an LBA is also a necessary step for MISO to move towards a declaration area for an emergency event that is more granular than today's LBA restriction.
Our preferred solution would be to provide the EP node (distribution/transmission substation) that each LMR is connected to. This would still allow MISO to determine the amount of load relief within a particular area based on substations which MISO has included in their models. We can currently control our interruptible programs using a dynamically selected boundary of physical addresses but do not have this capability with our direct load control programs. Since the substation would be a fairly static location for each LMR and identified at one point in time, the control sub-groups would be readily available within the normal notification times.
MISO needs to allow time for LSEs to identify and incorporate the substation assignment into the registration and MCS processes. In addition, upgrades to both the MECT and the MCS will need to be developed before this information can be submitted and processed efficiently.
Alcoa Power Generating, Inc. (APGI)
Feedback on
“LMR Accreditation Reforms (RASC-2020-4 RASC-2019-2) (20221012)”
October 27, 2022
During the October 13, 2022, Resource Adequacy Subcommittee (RASC) meeting, MISO requested feedback on their updated Load Modifying Resource (LMR) Accreditation proposal and certain design elements of the proposal.[1]
As a MISO Market Participant and Load Serving Entity with LMRs in the MISO MECT, Alcoa Power Generating Inc (APGI) has specific interests in the accreditation process for LMRs.
APGI offers the following feedback and suggestions:
Because of the size of the APGI BTMG, these resources are also reported in the MISO CROW and have GADS reporting requirements. Because of the limited existing MISO options for registration of resources, APGI has no mechanism to signal the status of these generators in the DA and RT markets. It is APGI’s perspective that more efficient processes should be explored that give MISO RT operations better insight into these resources and allow them to schedule into the DA/RT markets.
Widespread, uncontrolled outages can be much more disruptive than controlled shutdowns, especially to the operational processes of many large industrial consumers like APGI. Many industrial consumers like APGI would prefer taking a planned interruption to an unscheduled interruption, but only in the event of extreme system emergency, just prior to system blackout. APGI has a long history of supporting grid reliability, through the occasional interruption of loads and the option should remain available to consumers like APGI.
An example of a bridge resource might be a non-emergency LMR that can be price sensitive and activated at an earlier stage of capacity shortages. These resources would receive energy compensation if deployed.
A self-scheduled LMR that meets its capacity credit performance obligations has fully met any obligation to perform during an emergency. There should be no changes to that aspect.
APGI appreciates the opportunity to provide feedback on this issue.
If there are any questions or comments, please feel free to reach out to:
Sherry Rhodes
Alcoa-APGI
(812) 853-1033
Steve Dowell
ESS LLC, Alcoa Power Generating Inc.
(812) 853-1135
DeWayne Todd
DDT LLC
(812) 573-8052