DERTF: Order 2222 Tariff Language (MSC-2019-2) (20220210)

WPPI provided its comments on the proposed tariff language changes directly in the documents posted with the DERTF, 2/10/2022 meeting materials:

• Item 07a Module A Section 12 –Iteration 3 Redlines
• Item 07b Module B – Iteration 2 Redlines
• Item 07c Module C – Iteration 1 Redlines
• Item 07d Module E-1 Iteration 2 Redlines

Hello,

This is ITC's feedback. Thank you.

ITC Comments 2-24-22

During the February 10, 2022, Distributed Energy Resources Task Force (DERTF) meeting, MISO reviewed proposed tariff language changes to Modules A, B, C, E-1, and Attachment TT.  Much of the language had not been discussed prior to the meeting—so for many of the changes, this posting was the “first look.” Also, there was not much actual discussion of the proposed changes at the 2-10-22 meeting. Stakeholder feedback was requested on the proposed language. ITC’s feedback is below. We have also included some of the feedback that we have submitted in the past as it remains relevant (and other feedback that we have also submitted but which is not included herein, also remains relevant and timely).

ITC Order 2222 Tariff Language (Modules B, Module C, Attachment TT) Comments

Global comment: ITC needs to be included everywhere that communications and modeling information are considered/discussed/shared. Not all ITC TO/TOP areas in the MISO RTO fit into the categories of LBA, EDC, or LSE. As written in draft sections of the Tariff, ITC would be excluded from access to the relevant info for DEARs. If it would be helpful, we could arrange a discussion between SMEs at MISO and ITC to further discuss.    

Comments for Module B

None at present.

Comments for Module C

Regarding e. Metering, subsection v. (a), MISO proposes to add:  “A Market Participant on behalf of a Distributed Energy Aggregated Resource shall report only wholesale injections and withdrawals.”

Question/Comments:

• Where will the wholesale injections and withdrawals be metered? Is this the same physical location as the Commercial Pricing Node, and if not, how will MISO be assured of the wholesale delivery at the CP Node? 
• As a CPNode can be an Elemental Pricing Node or an Aggregate Price Node, doesn’t MISO need to know if the DEAR is mapping to an APNode or an EPNode to correctly calculate the LMP?
• If the DEAR maps to an APNode, how will it be included in the “pre-established” normalized weighting factors of the EPNode? 
• Will MISO be relying on retail meters for the information used to determine wholesale injections? 
• Details of metering schema have not been fully discussed. It would be useful to have a discussion of metering requirements and graphics that depict various anticipated metering configurations to support measurement from the injection point of the DEAR to the wholesale pricing point before the proposed Tariff language moves forward.

The Tariff definitions of the relevant Pricing Nodes are included below for reference. The CPNode includes Resources. Question:  As DEARs are to be considered resources are they not required to be metered at the CP Node?  The Tariff definition for CPNode below indicates that Resources are CPNodes.

Commercial Pricing Node (CPNode): An Elemental Pricing Node or an Aggregate Price Node in the Commercial Model used to schedule and settle Market Activities. Commercial Pricing Nodes include Resources, Hubs, Load Zones and/or Interfaces.

Elemental Pricing Node (EPNode): A single Bus where LMP is calculated.

Aggregate Price Node (APNode): An aggregation of Elemental Pricing Nodes whose LMP is calculated as the sum of the products of the LMP at each Elemental Pricing Node defined in the Aggregate Price Node and the associated pre established normalized weighting factors for the Elemental Pricing Node.

Regarding the use of DEARs for System Support Resources, SSRs.

The definition of an SSR is:

System Support Resource (SSR): Generation Resources or Synchronous Condenser Units that

have been identified in Attachment Y – Notification to this Tariff and are required by the

Transmission Provider for reliability purposes, to be operated in accordance with the

procedures described in Section 38.2.7 of this Tariff.

Tariff Section 38.2.7 is titled:  38.2.7 Generation Suspension, Generation Retirement, and System Support Resources

• MISO appears to be contemplating the use of DEARs as solutions for the retirement of other resources, including other DEARs, is this correct? 
• How will MISO ensure that the DEAR (particularly given the ability to change the DEAR composition on a quarterly basis) will conform to the needs of the SSR study? Would these details be in a contract? Would the contract provisions relating to the physical characteristics needed for modeling be available to entities responsible for the security of the BES? 
• How is measurement and verification in Attachment TT sufficient to ensure the reliability of the BES if DEARs are approved as SSRs given that the actual performance may not be known in real-time?
• MISO notes that DEARs can provide alternate solutions. Has MISO contemplated how DEARs will be retired (Generation Suspension) under the Tariff?
• The universe of potential impacts and concerns about using DEARs at the distribution level in place of resources connected at the BES level to ensure system security necessitates reflection and public discussion. This construct, like many others, is not something that should be left to proposed Tariff language that has never been publicly discussed.

Comments pertaining to a section with a title of “Registration”

• MISO references Business Practice Manuals (BPMs) in the proposed Tariff filing. Relevant BPMs have not yet been developed. We cannot comment on things that are not yet developed.  In general it is useful to have requirements in the Tariff and not left to BPMs.  Impacts to the transmission system should not be left to BPMs.

• MISO continues to rely on Attachment TT for measurement and verification. As we have noted in other comments, Attachment TT is wholly inadequate –particularly as we now see above that MISO is proposing to use DEARs as SSRs. All resources performance should be measured in real-time at the resource level and the physical point of injection and this should be the same place that the settlement for the resource is calculated. Calculation and statistical performance (in place of actual measurement) is not sufficient for the reliability of the BES.  DEARs have the potential to displace the output resources connected at the BES level. Thus it is imperative that a “one for one” occur—or in the event that it does not, that MISO, identify, quantify and develop additional ancillary services that make up for whatever capabilities are potentially ‘missing’ such as primary frequency response, voltage ride through, and perhaps inertia. 

General Comment: We ask that MISO recall that not all Transmission Owners in MISO are associated load

MISO States:  The LSE or EDC, and LBA will have access to relevant information used by the Transmission Provider, subject to the appropriate protection of any Confidential Information. 

As noted at the outset, ITC needs access, to the registration information as it is needed for modeling, and potentially communications information as well for situational awareness.

Could MISO please explain the proposed language below—again with blank pages and no section headers, not sure exactly where this is from, but it appears to be new language:

For Distributed Energy Aggregated Resources, Self-Schedules for Energy must be: (i) greater than or equal to the Hourly Economic Minimum Injection Limit and less than or equal to the Hourly Economic Maximum Injection Limit with an Inject or Emergency Inject Commitment Status; (ii) greater than or equal to the Hourly Economic Maximum Withdrawal Limit and less than or equal to the Hourly Economic Minimum Withdrawal Limit with a Withdraw or Emergency Withdraw Commitment Status; (iii) greater than or equal to the Hourly Economic Maximum Withdrawal Limit and less than or equal to the Hourly Economic Maximum Injection Limit with a Continuous Commitment Status.

• The phrasing in yellow is confusing. Could MISO please explain?

CONTINUED

Comments on Attachment TT that MISO has Re-Requested

We are resubmitting the comments we submitted on 11-15-21 regarding Attachment TT both because MISO is asking for comments on Attachment TT and we have the same concerns now as we did in November—in fact our concerns are increasing due to the newly proposed language on SSRs.

During the November 1, 2021 Distributed Energy Resources Task Force (DERTF) meeting, MISO recommended using existing measurement and verifications (M&V) protocols as described in Attachment TT for demand response in a DERa.

ITC Response:

Anticipated increases in Demand Response Resources and Distributed Energy Resources (including aggregations) as well as LMRs and EDRs in the footprint should encourage MISO to consider more stringent measurement and verification protocols to document performance. Specifically, response should be measurable, measured, and verified as are the responses of other Resources with which the Distributed Energy Resource aggregations (DERas) will be competing at the time of their deployment. This requires measurement before, during and after the deployment.  Situational awareness and system security would be enhanced by a more complete understanding of the actual performance of DERas. Attachment TT as it stands appears inadequate to support operator situational awareness and accurate settlement for services.

Details:

The response of Resources defined in MISO Tariff Module 1 is straightforward and the epitome of measurement and verification: 

"Actual Resource Response: The actual movement, in MWs, relative to Setpoint Instructions for a Resource within a Dispatch Interval."

Note how this definition requires measurement “the actual movement, in MW” and performance--the movement that is measured “relative to Setpoint Instructions” by Dispatch Interval. 

Contrast this with the entire Attachment TT that is a torturous description of various statistical analyses based on historical performance that presume to represent real-time performance of DERa components.

From Attachment TT

“Because it is impossible to directly measure the energy that a non-BTMG DRR, LMR, or EDR would have consumed in the absence of the Setpoint Instruction, Scheduling Instruction, or EDR Dispatch Instruction to reduce load, Measurement and Verification criteria are used to determine the performance of DRRs LMRs, or EDRs. Performance will be imputed through comparisons between the DRR’s, LMR’s, or EDR’s consumption baseline (as described below) and the DRR’s, LMR’s, or EDR’s actual hourly Metered energy.” [Attachment TT at 2, Performance Assessment]

From this it appears that MISO is proposing to use “actual hourly Metered energy” rather than a Dispatch Interval-based measurement.

Question: Does MISO intend to modify Attachment TT to recognize 5-minute dispatch instructions and the corresponding 5-minute response verification?

If MISO does not envision changes to TT for DERa to make the measurement and verification more granular, and in real-time, it seems like the Bulk Electric System is being increasingly positioned up imprecise operation which could potentially impact, but may not be limited to, such things as frequency management, Area Control Error, and system Regulation needs and deployment.

The current Attachment TT defines different types of Consumption Baselines against which imputed response is compared to evaluate performance. The Metered Generation Baseline definition appears to allow technologies such as aggregations of rooftop solar, or vehicle chargers to be calculated against a baseline instead of metered.  Note that Attachment TT requires that “all behind the meter generation must use this measurement and verification methodology.”  This statement precludes entities that may want to employ more granular measurement from using same. If MISO intends to rely on Attachment TT, perhaps this should be a minimum standard rather than precluding more granular and potentially better, measurement.  

Attachment TT

3. (i) Consumption Baselines for Energy and Calculated Output

(a) Metered Generation Baseline

This type of consumption baseline only applies to behind-the-meter-generation. All behind-the-meter-generation must use this measurement and verification methodology. For a DRR, LMR, or EDR that combines behind-the-meter-generation and non-behind-the-meter-generation, this consumption baseline applies only to the BTMG components. [Attachment TT, emphasis added]

With increases of technologies such as rooftop solar, and electric vehicle chargers that could be aggregated to form resources that inject to the system, it seems like requiring such resources to use calculated baselines rather than measuring actual performance is missing an opportunity to increase the precision and understanding of system operations.  We encourage MISO to explore and require more granular measurement of such resources.

Attachment TT

3. (i) Consumption Baselines for Energy and Calculated Output

(b) Calculated Baseline

For a DRR, LMR, or EDR not supported by behind-the-meter-generation, the consumption baseline is a profile of hourly demand based on an averaged sample of historical data, which may be adjusted for factors that reflect specific, on-the-day-dispatched conditions, such as weather. Unless the Market Participant registering the resource submits an alternative consumption baseline for the Transmission Provider’s approval, the Calculated Baseline will be determined as follows:

• Separate hourly demand profiles will be determined for (1) non-holiday weekdays and (2) for weekends/holidays.
• The weekday hourly profile will be based on the average of the ten (10), but not less than five (5), most recent weekdays that are not holidays or other non-standard “event” days. The weekend/holiday hourly profile will be based on the average of the four (4), but not less than two (2), most recent weekend days or holidays that are not “event” days.
• An “event” day is one during which there was, for the Resource in question, a real-time energy or ancillary services dispatch, an emergency deployment, or a reported Outage.

 .....

This requirement appears problematic in several respects. First, it appears to require MISO to be able to adjust multiple parameters for performance of multiple DERas and multiple components of DERas ---potentially on a daily basis--as presumably such resources would be offering daily and thus 'event days' could be every day. Has MISO considered the staffing demand that this definition might impose?  Second, as noted above, with increasing volumes of entities aggregating and providing response using sophisticated controls, it seems that a standard of actual measurement could be imposed. As Order 2222 contemplates DERas of a size of 0.1MW, how does MISO propose to ensure that the actual resource response is measurable and measured for settlement?  Third, the definition above appears to envision that such resources will only be dispatch infrequently, on so called “event” days. Is this plausible?

For the above reasons, we have concerns about the use of Attachment TT as it currently stands for the measurement and verification of DERa performance.  

CONTINUED

The comments below were submitted in January 26 2022 but are resubmitting as MISO is again requesting input on some of these sections. Thus, we are resubmitting these comments.

ITC Order 2222 Tariff Language (Modules A, D & E-1, Attachment MM, and Schedules 26-A, 27 & 53) Comments

Comments for Module A--Definitions

• Injection and withdrawals at the BES level should be metered, reported and settled separately on a 5-minute basis. Netting should occur in terms of dollars at the settlement statement level, not in terms of offsetting energy because the value of the energy is not the same in each interval of the hour. Aggregating/netting at the hourly level does not accurately value the energy on a 5-minute basis.  MISO implemented 5-minute settlement in 2018.  And MISO itself notes the importance of measurement and settlement at the 5-minute level.  Please see:  https://www.misoenergy.org/about/media-center/miso-partners-with-customers-stakeholders-to-complete-transition-to-five-minute-settlements/
• If MISO chooses to allow netting and/or calculation instead of actual measurement, we respectfully suggest that MISO specifically identify these situations and explain why calculations are more just and reasonable than measurement. 
• Consider adding a discussion of periodicity to the definition of LMP.

Comments for Module D – IMM Module on Physical Withholding

None

Comments for Module E-1 – Resource Adequacy

None

Comments for Attachment MM--MVP Charge, Schedule 26-A – MultiValue Usage Rate

• ITC opposes exempting the broad class of DEARs from the MUR.  The purpose of the MVP portfolio is to provide transmission to support MISO States’ renewable energy mandates.  Thus, quite simply, the MVP’s support DEARs.   
• The MVP Portfolio facilities centralized dispatch of generation resources which brings operating efficiency to the region and spreading the benefits of low-cost generation throughout the MISO footprint. Further, the MVP Portfolio provides benefits across the MISO footprint in a manner that is roughly equivalent to costs allocated to each LRZ.
• DEARs will benefit from the MVP transmission and there is no justification to exempt these resources for their usage of the overall MISO transmission system.  In fact, not charging them will create a cross-subsidization where other resources will pay for the incremental portion of the MUR for which DEARs are responsible. 

Comments for Schedule 27 – Real-Time Offer Revenue Sufficiency Guarantee

None

Comments for Schedule 53 – Seasonal Accredited Capacity

None

CONTINUED

In an abundance of caution, and because MISO expressed at one point in the Fall of 2021 and again at the February 2022 meeting that they had not seen some of the comments ITC has submitted in the DERTF process, below is a set of comments we submitted on size, metering, and telemetry on June 28, 2021.

MISO is requesting feedback on the following questions by June 28, 2021

• What percent of resources being considered for wholesale market participation will exceed 5 MW at a single distribution interconnection location?

ITC is not able to respond directly to this question.  However, we propose in other comments that any single element of a DERa that is 5 MW or greater should have its own telemetry to the aggregator.  

• What priority would you assign the ability to represent more than one path to the transmission system for the DERa, recognizing that only one transmission path can be available at a time? Rate: Low, Medium, High

ITC recommends a low ranking. Most generation interconnected at the BES level has a single tie line. As the modeling complexity of DERas has yet to be determined, we suggest that a single path is a good place to start because it will help to make the modeling process more manageable. DERa telemetry to MISO should include the breaker status of each alternative pathway for the resource to the transmission system.  

• Are any of the resources being considered for wholesale market participation only installed on a single phase? 

ITC is not able to respond directly to this question, but we note that information of this type should be provided at registration, and the information should be communicated to the TOs.  All technical information about each registered DERa should be included in MISO registration processes and communicated to TOs in the appropriate models as is done for other resources on the system.  

• How can the filing framework documentation be improved?

ITC response: framework is helpful and consistent report outs will help to keep parties aligned.One enhancement would be for MISO to develop matrices that compare the various classifications of DRR and DERa resources, including telemetry, metering, and registration parameters. Separate tables showing the market services, qualification requirements, offer parameters and performance requirements for the same types of resources would help market participants understand the distinctions between the types of resources, and the different qualification and performance requirements. Yet another table to set forth how the wholesale settlements will work by the same resource types would also be helpful. Such information, compared across resource types, help MISO and TOs understand the resources on the system and their expected performance requirements. The Bulk Electric System is experiencing many changes and a clear and transparent accounting of resource types and locations on the system is important for reliable system operation. As these new resources come online, MISO should include them in reports detailing the MW of resource types on the system. 

• Should a DERA submit aggregated meter data or individual DER meter data for performance tracking? Why? 

Metering should be at the level to which performance metrics are expected and enforced. Metering at the granularity that is synchronized with the performance anticipated by other BES resources could provide useful incentive alignment.¹   Additionally, Demand Response Resources that are part of an aggregation should be metered and reported separately to facilitate future modeling efforts. MISO and TOs will have a significant challenge anticipating the performance of DR resources as they become part of larger aggregations. Granular performance data from these resources will be helpful for planning, dispatch and settlements to anticipate future response as more distributed resources are integrated into the system. The decisions around performance, metering and settlements need to be aligned. Every MW dispatched from a DERa offsets a MW dispatched at the BES level and the system will have to reliably accommodate and respond to the performance of the DERas. Moreover, if performance, metering and settlement differ from other resources on the BES, the incentives to perform will be different than the incentives for other resources on the BES. Any differences in participation and performance incentives need to be documented and understood so that the system can be dispatched reliably. 

Under MISO BPM-002, Resources without Real-Time telemetry available to MISO through ICCP are price takers and cannot offer into the Energy or Operating Reserve Markets. Conversely, to be consistent with existing Real-Time standards applicable to the wholesale market, ICCP telemetry through ICCP could be required for DERas to offer into the Energy and Operating Reserve markets.²  Offering into the markets as Order 2222 envisions, MISO would dispatch DERa resources, and as the existing BPM makes clear, MISO would not dispatch the resources for settlement without appropriate telemetry. ITC supports the practices as set forth in MISO BPM-002 to facilitate reliability of the system as new Resources come online.  

Section 4.2.10.9 of MISO BPM-002 states: 

If a Resource smaller than 5 MW wants or needs to be settled by the Energy and Operating Reserve Markets, MISO will provide a CPNode for this Resource that will allow the Resource to be represented by an MP, designate an MDMA, and submit Metered values After-the-Fact (“ATF”) that will be used for Settlement purposes. 

However, the Resource will not be able to offer into the Energy and Operating Reserve Markets and will be a price taker at the appropriate Ex Ante and Ex Post LMP price for its output unless Real-Time telemetry is available to MISO through ICCP. [Emphasis Added] 

Section 4.2.10.12 of MISO BPM-002 states: 

All Generation Resources, External Asynchronous Resources and Regulating Reserve-Qualified DRRs-Type II greater than 5 MW must have Real-Time telemetry. Such Resources without Real-Time telemetry (smaller than 5 MW) are price takers in the Real-Time Energy and Operating Reserve Market. These Resources can have a CPNode established that allows them to submit meter values for energy settlements, but will not be dispatched in the Real-Time Energy and Operating Reserve Market. 

Active, as opposed to passive, participation in the wholesale markets as envisioned for DERas places these resources on par with other resources at the bulk electric system level.  ISO administered markets exist to facilitate reliability of the system and standards for participation at the wholesale level must be clear and enforceable to facilitate reliability. 

• How should wholesale market transactions by DERAs be tracked and reported to prevent double counting? 

As part of the Registration process, MISO should require DER aggregators to attest that no MW that comprise a particular DERa will offer into MISO markets for capacity, energy or ancillary services outside of the DERa offer. Specifically, that no members of the DERa will be part of: 

1. Emergency Demand Response (EDR) - Load reductions, behind the meter generation, and other demand resources that are available to reduce demand or increase generation in exchange for guaranteed recovery of costs associated with the response in accordance with Schedule 30 (EDR Provisions) of the Tariff.  
2. Load Modifying Resource (LMR) - These are either Demand resources or Behind the Meter Generation that have an obligation to reduce demand or increase generation during declared system emergencies. 

As part of Registration and on a periodic basis, MISO could require the Distribution entity to which the DERa is connecting to provide a list of aggregated entities (size, location), by aggregator, so that MISO understands the capabilities of the DERa (similar to other resource registration processes).  As with any resource, response from a DERa may vary.  Therefore, as discussed above, the metering and telemetry requirements for DERas need to be consistent with performance expectations. As DERas will be competing at the wholesale level, wholesale level expectations are necessary to be consistent with the rest of the market. The markets are the basis for reliability and MISO must ensure that incentives and performance requirements support efficient, reliable system operations. 

While further justification for granular metering and telemetry standards should not be necessary, it is useful to explore how DERa type resources are being used in other markets. Recently, 3000 MW of DERa type resources from a single entity cleared the PJM Capacity Auction.³ This is consistent with what is happening in MISO where over 11,000 MW of DERa type resources cleared in the MISO 2021 Planning Reserve Auction—a continuation of a trend that has been underway for years.⁴  

If MISO and stakeholders choose to implement the requirements for Order 2222 without granular metering and telemetry, a follow up plan should be established prior to go live, to review performance and commits to adjust metrics and participation requirements. This commitment could extend to the Tariff filing in which the compliance filing could commit to performance evaluation and to adjusting metering and telemetry requirements to provide situational awareness might be useful. 

• Small DERa (<1 MW) must self-commit

ITC Response: MISO should track the locations and MW of DERas. As noted elsewhere in the comments, the preponderance of DERas might reasonably be expected to locate in urban areas. If the saturation of self-commits creates difficult system operating conditions, MISO may want to revisit and lower or eliminate the self-commit standard. 

• No size limit for individual DER within an aggregation 

ITC Response: MISO should track the locations and MW of DERas. As noted elsewhere in the comments, the preponderance of DERas might reasonably be expected to be in urban areas. If the saturation of self-commits creates difficult system operating conditions, MISO may want to revisit the self-commit standard.  Additionally, it is imperative for system reliability that incentives to participate in a DERa do not result in avoidance of other existing obligations, say for interconnection at the BES level, for resources with the technical capabilities to do so. 

• No size limit for DER aggregations in total 

ITC Response: MISO should track the locations and MW of DERas. As noted elsewhere in the comments, the preponderance of DERas will reasonably be expected to be in urban areas. If the saturation of self commits creates difficult system operating conditions, MISO may want to revisit the self-commit standard.  Additionally, for reliability, it is imperative that incentives to participate in a DERa do not result in avoidance of other existing obligations, say for interconnection at the BES level for resources that could do so, or for dispatch, telemetry, and/or other performance and reporting requirements. 

While MISO has not requested input at this time on telemetry, ITC offers the comments below to supplement those we have previously submitted on this technical issue. 

ITC submits these comments to supplement the comments we have previously submitted. These comments are particularly important given the work group/MISO recommendation on the potential for no limit to DERa size, potential element for no limit to DERa component size, and the self-commitment for DERas under 1 MW. 

ITC supports a telemetry requirement consistent with that of other resource operators –that between a 2 and 10 second scan rate--be required for DERas. These are in addition to the other comments we filed on IR070. The basis for this recommendation is: 

1. Order 2222 provides for the participation of distribution-level resource aggregations at the wholesale-market level. The use of distribution-level resources to serve demand will, all other things being equal, displace output of resources interconnected at the Bulk Electric System (BES) level. As DER aggregations are dispatched to serve load, they will displace resources managed by Generator Operators with NERC level compliance obligations or guidelines. Thus, the performance and visibility of DERa resources for capacity and energy should be on par with the performance expected of resources at the BES level. Said another way, to the extent that DERas may or may not be able to provide the same services or have the same performance requirements as BES level resources, or to the extent that they provide improved services, MISO may want to expand or modify performance rules and/or market-based grid reliability services to be able to manage the BES under increasingly complex scenarios. To this end, telemetry scan rates for DERas should be 10 seconds or less, or consistent with the scan rates required for generators in each LBA/TOP zone. Such scan rates are necessary for MISO and TOP visibility into the operation and reliability of the system. 

1. As we have noted verbally at the DERTF meeting on 6/7/21, and the MSC on 6/10/21, and in our comments above, one might reasonably anticipate that the preponderance of DER aggregations will be in urban centers—precisely because there is more load there that could respond. This creates potential issues arising from the concentration of these resources –such as modification of flow patterns on the distribution and potentially the bulk electric transmission system that were not anticipated when the systems were designed. A telemetry scan rate of two-to ten-seconds will facilitate operational awareness and help MISO systems and operators function with the most current information, similar to how MISO monitors the performance of other resources.  

1. Any DERa or DERa component that is able to provide >= 5 MW at a single location should be telemetered to the aggregator. This expands on our comments above by suggesting that sub-aggregation level telemetry should be required for resources above a certain MW threshold. At some point, MISO may need such data from the aggregator--particularly if significant concentrations of resources are present and operating in a small geographic area. Moreover, establishing such a requirement at the outset will facilitate more accurate dispatch and facilitate documentation of resource response. Such a requirement is consistent with MISO BPM-002 that requires resources greater than 5 MW be modeled.⁵ As there may be an incentive to connect multiple resources under the modeling threshold level, MISO, through the registration process, may want to monitor the number of resources close to the threshold level to see if lowering the modeling threshold requirement is necessary.   

1. From a market efficiency standpoint, the dispatch of Regulation and Responsive reserve from other resources, as well as Ramp calculations, could be impacted by a scan rate slower than the 2-10 second rate for DER aggregations because a slower scan rate would introduce an additional uncertainty parameter (output of the DER aggregations) that would need to be estimated and included in the state estimator and dispatch algorithm  calculations. In particular, regulation service where resources receive a pulse vey four seconds runs at a faster rate than the 30 second scan rate MISO is evaluating. These ancillary services are important for the reliable operation of the BES. MISO already requires similar telemetry from DRR Type II resources and we recommend that consideration be given to applying these requirements to DERas.  As noted earlier, every wholesale dispatch instruction to a DERa supplants a dispatch instruction to a resource interconnected at the BES level. Thus, again, the visibility, performance and control of DERa resources is important to the secure operation of the BES. 

1. MISO has multiple tools comprised (in part or in whole) of Demand Response Resources. Presently Load Modifying Resources, LMRs, resources are not dispatched until a Max Gen Emergency Step 2a or higher. Specifically, “If MISO does NOT declare a Max Gen Emergency Event Step 2a or higher at least two hours prior to the start of the Scheduling Instructions issued in anticipation, the LMRs are NOT obligated to perform.”⁶ The choice not to dispatch LMRs until this step in the emergency sequence arguably makes these resources as important if not more important than other resource types on the MISO system—because they are dispatched only close to a ‘last resort.’  While this does not place the burden on the LMRs to be available all the time, they are required to be available for dispatch in dire Capacity Emergencies. Thus, the scan rate should be on par with other BES resources. To date, nothing would preclude an LMR from being part of a DERa.  However, we suggest that this be clarified and/or tracked in registration to avoid double counting as we note above. 

[1] Note that as Resource types have evolved, MISO has had to ‘play catch up’ after BES system impacts were identified for Resources that were not dispatchable. By learning from past experience with Dispatchable Intermittent Resources, hopefully unintended consequences for new Resource types can be minimized or avoided. (FERC docket ER20-595)

2 MISO BPM-002, 4.2.10.9, Version October 15, 2020

3 Enel X was awarded 2,900 MW of committed capacity resources for the 2022-2023 delivery period in the latest capacity auction held by PJM.,- The auction cleared an overall total of 144,477 MW at a clearing price of $50/MW-day, a 64% decrease from the previous auction's clearing price.:https://www.prnewswire.com/news-releases/enel-x-awarded-nearly-3-000-mw-at-pjm-capacity-auction-accelerating-the-transition-to-a-cleaner-grid-301312612.html

4 Slide 10 at:  https://cdn.misoenergy.org/PY2122%20Planning%20Resource%20Auction%20Results541166.pdf

5 MISO BPM-002, 4.2.10.9, Version October 15, 2020

6 MISO Market Capacity Emergency SO-P-EOP-00-002 Rev: 10 Section 4.2.6 Max Gen Event Step 2a - MISO Actions

ITC has submitted other comments during the DERTF processes as well—both written and during meetings; not including them here does negate, or detract from, our view of their continued relevance.

Will be submitting an email attachment.  The documents do not want to upload correctly.

Clean Grid Alliance Comments on Order 2222 Tariff Language

Feb 24, 2022

Clean Grid Alliance appreciates the opportunity to provide comments to the DERT on Order 2222 Tariff Language: 

We encourage MISO to clarify the proposed language to Module A that excludes interconnection of DER from MISO dispute resolution. There are two aspects of a DER interconnection that might be disputed—impacts and policy related to the distribution system, and impacts and policy related to the transmission system. While impacts to the distribution system may or may not be jurisdictional to MISO, impacts and policy related to the transmission system are clearly jurisdictional to MISO and should be eligible for MISO dispute resolution. We recommend that MISO revise the proposed language to reflect that. 

Clean Grid Alliance continues to have serious concerns about MISO’s plan to put into Business Practice Manuals, critical Order 2222 details that unquestionably belong in its Tariff filing, particularly related to impacts to the transmission system. Standardized, transparent, study procedures, including dispatch methodologies for DERs and DEARs that intend to participate in the MISO wholesale market (and therefore will have associated power flows on the transmission system), MUST be studied for those power flows with dispatch to the MISO market. These studies, including upgrade criteria, must be consistent with other market participants requirements in determining impacts, mitigation, and (potential) cost sharing with transmission-connected generators in the MISO queue. This is an essential/critical element of the Order 2222 filing that is completely missing.  

DERs today are already participating in MISO’s wholesale markets, and doing so with zero transparency, and no established procedure to model or account for the flows associated with those transactions in MISO’s MTEP or Generator Interconnection planning. The need for modeling and policy exists today, and is expected to only scale in magnitude after Order 2222 filing. MISO has already noted in stakeholder meetings that it has seen over 100 new distribution interconnections in the last year alone. To not include procedures for evaluating and modeling the impacts of DERs and DEARs to MISO’s transmission system is negligent at best, and at worst exposes MISO’s market to significant potential for “gaming” and unplanned reliability risks with those flows unaccounted for. MISO must address this shortcoming in its Tariff filing before April by adding provisions related to study methodologies, and thresholds for determining and mitigating impacts to the transmission system as a “Tariff-defined”, pre-requisite for any DEAR seeking participation in any aspect of the MISO market. 

MISO has proposed changes to Module C to allow DEARs to be eligible to serve as SSR alternatives, yet has not proposed to account for the flows on the transmission system that will necessarily occur and enable them to do so. Furthermore, if a DEAR is able to change configuration monthly, will those changes impact status as a SSR alternative? How will impacts to the transmission system arising from those changes be studied? 

Finally, we believe that clear market participation rules and guidelines must be established within MISO’s Tariff for EDC owned DEARs to prevent market manipulation by those entities. Without such policy in place as part of MISO’s compliance filing, and especially combined with the earlier noted shortcoming in transparency and evaluation of impacts to the transmission system by DEARs, combined with no upper limit restriction on their size, this presents a “wide-open, inviting” opportunity for any entity so inclined to advantage itself, if not addressed as part of the Order 2222 compliance filing in April. 

Sincerely,

Rhonda R. Peters, Ph.D.

Technical Consultant for Clean Grid Alliance

The OMS DERWG appreciates the opportunity to provide feedback on MISO’s proposed tariff language as part of its Order 2222 Compliance. This OMS Board of Directors has not considered this issue, and therefore, this feedback does not constitute a position of the OMS Board of Directors.

Module A (Page 2 sub-point e): Includes a list of disputes NOT covered by Attachment HH; “Disputes arising among or between EDCs, LBAs, DERAs, LSE or any other party that involve matters that are not part of the EDC review process, including but not limited to the interconnection of a DER.” 

Comment: The OMS DERWG appreciates clarity on what types of disputes will and will not be covered by MISO’s existing processes set forth in Attachment HH. However, in the future, MISO’s coordination framework should account for potential disputes between DERA, EDCs, LBAs, TOs, and other entities. Creating a DER database with geospatial data showing boundaries for EPNodes/CPNodes will help reduce potential disputes around DEAR eligibility and also serve to streamline the review/registration process.

Module B (page 3 section 31.0.0): Point-to-Point Transmission Service customers are not required to obtain Transmission Service for the receipt of Energy and transmission of such Energy associated with Electric Storage Resources when withdrawing Energy while providing Regulating Service or Down Ramp Capability. MISO’s comment in the redlined tariff “tracked changes” version states; “Order 841 provision not being extended to DEAR so do not include DEAR here.”

Comment: The Order 841 exemption from obtaining transmission service for regulation service or down ramp capability should be extended to DEAR that include energy storage as part of the aggregation. At minimum, the exemption should be offered to homogenous DEAR that only include energy storage resources since these DEAR would effectively have the same technical capabilities as  entities that are ESR-registered under Order 841. Denying this exemption to such DEAR may impose a barrier to project development and raises concerns about discrimination against DEAR that may function in the same manner as an ESR. Should MISO disagree with this assessment, please explain why it is appropriate to not extend the Order 841 exemption to energy storage included under a DEAR.

Module C (page 95-96 section 34.0.0): MISO tariff language states; “LBAs will work with the EDC, and Transmission Provider to review the composition of a CPNode proposed for the DEAR.  The Transmission Provider will provide LBAs and EDCs with access to the electrical location and magnitude of each resource enrolled by a DERA to perform operational planning studies.  If the LBA takes no action, the EPNode will be assigned by the Transmission Provider.  If the LBA confirms the DEAR then the LBA shall identify the EPNode assignment.   If the LSE takes no action, the Load Zone associated to the DEAR will be assigned by the Transmission Provider.  If the LSE confirms the DEAR, then the LSE shall identify or approve the Load Zone associated with the DRR, LMR, or EDR. 

Comment: The importance of MISO’s role as a coordinator between DERA, EDC, LBA, LSE and TOs is evident in the tariff language cited here. Development of a geospatial database that includes physical boundaries for EP/CPNodes will be extremely important for facilitating the DEAR review/registration process outlined in MISO’s tariffs, as well as interconnection/review processes undertaken by EDCs, RERRAs, TOs and other entities.

MEMORANDUM
TO: MISO DISTRIBUTED ENERGY RESOURCE TASK FORCE
FROM: THE ENTERGY OPERATING COMPANIES
SUBJECT: FERC ORDER 2222 FILING FRAMEWORK – ORDER 2222 TARIFF LANGUAGE
DATE: FEBRUARY 24, 2022

The following feedback is offered by the Entergy Operating Companies ("EOCs")[1] in response to the request made during the February 10, 2022, Distributed Energy Resource Task Force (DERTF) meeting concerning the FERC Order 2222 filing framework and the related Order 2222 Tariff language edits to Modules A, B, C, E-1, and Attachment TT. 

Module A Section 12 – Common Tariff Provisions – Dispute Resolution Process:

• The EOC’s support the use of the current Market Settlements dispute process through the MISO settlements group for Market Activities related Order 2222 participation. 

Module B – Transmission Service:

• MISO should add clarify language to Module B to ensure that it is understood that this Module pertains to a MISO initiated Manual Redispatch and is not related to an Electric Distribution Company (EDC) requiring a DEAR to redispatch or come offline in response to distribution system safety or reliability concerns.  Additional language should also be added that makes it clear that market or settlement implications related to needed EDC initiated redispatch is borne solely by the DEAR and is not the responsibility of the EDC. 

Module C – Energy and Operating Reserves Market

• The proposed Module C Tariff contains extensive language and detail surrounding Electric Storage Resource (ESR) participation in the Day Ahead and Real Time Markets, which appears to be addressing FERC 841 ESR participation.  While this language is in close parallel and was used to develop the DEAR participation model, the EOC’s recommend that MISO more fully vet the ESR resource type with Stakeholders prior to the inclusion of the ESR language in any filing with FERC.    
• Attached are a small number of Module C edits
  • Metering requirements on page 36, Tariff section 38.2.5.e.v.(a.) adding:
    • Resources that are part of a Distributed Energy Resource Aggregation (DEAR) should use the retail meters of the relevant Electric Distribution Company (EDC) for settlement unless the EDC has agreed to the use of third-party metering for settlement.
• DEAR participation in the Day Ahead Market and the Required Distributed Energy Aggregated Resource Offer Components on pages 275-277.
  • Edits to various offer limits.

Module E-1 – Resource Adequacy:

• No Comments at this time

Attachment TT – Measurement and Verification Criteria:

• The EOC’s ask that MISO provide commentary on why the current Measurement and Verification (M&V) processes are proposed to be used with DEAR participation under Order 2222.  With the proposed 2030 implementation date, there should be improvements in technology and processes that would allow for more accurate measurements vs current baseline methodologies.  As stated in previous feedback, the EOC’s believe that much of this is achievable now via Advanced Metering Infrastructure (AMI).  Applying newer technologies in lieu of using baseline calculations, would allow retail customers to be confident that they are receiving what they are paying for. 

The EOCs appreciate the opportunity to comment.

Voltus Comments to MISO February 24, 2022, DERTF Feedback Request

During the February 2022 Distributed Energy Resources Task Force (DERTF) meeting, MISO reviewed proposed tariff language changes to Modules A, B, C, & E-1, and Attachment TT. Stakeholder feedback is requested on the proposed language.

38.7. Distributed Energy Resource Aggregators

38.7.A.i. Information Requirements – Redline change

Voltus proposes adding these sentences to confirm M&V for DER Groups, which are homogenous aggregations. These sentences come from MISO Compliance Framework Iteration 8 at slide 107.

“Measurement and Verification procedures selection as specified in Attachment TT appropriate to the types of resources within the DEAR. Within Distributed Energy Resource Group(s), resources have the same measurement and verification methodology. Each Distributed Energy Resource Group(s) measured values will need to be provided to MISO for settlements.” 

38.7.A. ii. Process to identify double counting – Only a comment

Voltus asserts MISO should clarify that double counting only occurs when a single MWh of curtailment is paid for multiple services. Otherwise, FERC has allowed dual participation--even simultaneously--in multiple product types by a single MW.

Perhaps the March DERTF should discuss some examples of these double counting instances that are left to the Business Practices Manual, slide 86 of MISO Compliance Framework Iteration 8 only discusses 3 instances for double counting, even those are generic in nature. For example, it is not clear what MISO means by this statement on that slide 86 – “A DEAR offers to provide capacity in MISO while DERs within the aggregation allow interruption by LSE as part of a Planning Resource”

“The Transmission Provider will coordinate with relevant parties to assist in the review of information provided to determine whether such end use customer is currently enrolled to provide the same service in the Transmission Provider’s markets as part of an existing resource, or at retail, as set forth in the Business Practices Manual.”

38.7.A. iii. Notifications and Approvals \ 2. LBA and LSE or EDC - Redline change

Voltus proposes this insertion

DERAs must update the list of DERs in each aggregation and any associated information and data associated with the constituent DERs.  DERAs will not be required to re-enroll the entire DEAR for such modifications. The Transmission Provider will provide the LBA, EDC and LSE upto sixty (60) Business Days in total to take any necessary action(s) for such modifications. In the event that the LBA, EDC or LSE does not take action within sixty (60) Business Days of being notified, such modifications will be deemed approved by default.    

Thank you for the opportunity to comment. We look forward to MISO’s responses to these proposed comments.

Respectfully Submitted

Rao Konidena

Voltus Consultant

Rkonidena76@gmail.com

(612) 594 9257

Advanced Energy Management Alliance (“AEMA”) [1] respectfully submits the following comments to the MISO Distributed Energy Resource Task Force (“DERTF”) on the feedback request made by MISO at the February 10, 2022, meeting of the DERTF.[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 February 10^th meeting of the DERTF, MISO proposed tariff language changes to Modules A, B, C, and E-1. Additionally, MISO proposed changes to Attachment TT. In response to the proposed tariff language changes, AEMA offers the following feedback:

• Module A: Definitions:

Proposal Summary: MISO proposes to utilize the standard Attachment HH (Dispute Resolution Procedures) of the MISO Tariff for disputes “over the coordination or application of the distribution utility review process among or between the Transmission Provider, an Electric Distribution Company, and a Distributed Energy Resource Aggregator.” The interconnection of a DER is excluded from Attachment HH. 

AEMA Feedback: AEMA has no opposition to the suggested changes.

• Module B: Transmission Service:

Proposal Summary: MISO has proposed to add Distributed Energy Aggregated Resources (DEAR) to sections on Manual Redispatch by the Transmission Provider “in order to maintain reliability of the Transmission System in circumstances where automated Real-Time Energy and Operating Reserve Market generation dispatch procedures set for in Module C are inadequate to maintain reliability.”

AEMA Feedback: AEMA supports the proposal based upon equitable treatment with other resources in the MISO market that are impacted by Manual Redispatch. 

• Module C: Energy and Operating Reserve Markets

Proposal Summary: MISO has proposed the following:

• 38.1.1 (c), (k), and (z): MISO proposes to include DEARs in MISO’s purview for Coordination of Maintenance Schedules. Changes will also allow MISO to receive and maintain data and information related to operations and will allow MISO to coordinate with DERAs regarding claimed capacity, operations, modeling, metering, settlements, and/or any other information related to the participation of a DERA, DEAR or individual DER.
• 38.2.2 (h): MISO proposes rules for Market Participant seeking to offer DEAR into the market.
• 38.2.5 (a): MISO proposes to add language that a DEAR shall “report only wholesale injections and withdrawals.”
• 38.2.7: MISO proposes an option for DERA to potentially be counted as a SSR (System Support Resource).
• 38.3: MISO proposes that a DERA engaged in Market Activities must be qualified as a Market Participant and fulfill the requirements of the Tariff.
• 38.7.A.i: MISO proposes language stating that a DERA registration for a Distributed Energy Aggregation Resource (DEAR) “be associated with a Commercial Pricing Node,” with “a mapping of the single Elemental Pricing Node making up the Commercial Pricing Node… of a DEAR.” Registration enrollment is detailed in this section. This section does require an “attestation by that DERA that it has obtained all necessary approvals… for the DERA to participate in the Transmission Provider’s markets.” AEMA Feedback: As stated in previous feedback, AEMA does not support the limitation of each DEAR being associated with a single Elemental Pricing Node. This limit represents a significant barrier to participation. MISO should include options for limited aggregation of DERs across multiple Pricing Nodes and expand the options as MISO market and operations systems increase in capacity and capability to handle broader aggregations.  
• 38.7.A.ii. MISO proposes that MISO will coordinate with relevant parties to “identify double counting,” and that the details will be contained in the Business Practices Manual. AEMA Feedback: AEMA requests that more detail on the definition of double counting be included in the Tariff. The definition and categorization of double counting for services has the potential for misunderstanding and dispute. MISO should include examples that distinguish the differences in what is and what is not double counting that includes net-metering, energy, capacity, and the specific ancillary services. AEMA is concerned that there could be disputes over the difference between double counting, which is prohibited, and complementary counting, which is permissible.
• 38.7.A.iii.1. RERRA Notifications and Approvals. MISO proposes to request that the DERA notify the RERRA upon enrollment of a DEAR in the MISO market. For utilities greater than 4 million MW-hr., MISO will not reject the registration unless it receives notice from RERRA that contests the DEAR participation. For utilities less than 4 million MW-hr., MISO proposes to reject the DEAR unless the RERRA sends a positive affirmation of the ability for the DEAR to participate in market. AEMA Feedback: AEMA has no opposition to the language for utilities greater than 4 million MW-hr. AEMA is concerned about the potential for delays in RERRA response on utilities less than 4 million MW-hr. and the 10-day requirement. MISO should accept alternative confirmation of small utility “opt-in” as opposed to waiting for a positive affirmation from the RERRA. For example, if the small utility has “opted-in” there could be publicly available documentation to that effect that could be utilized to confirm. In either case, MISO should not automatically reject the registration after 10-days. If MISO requires a positive affirmation, then MISO should simply place the registration on hold until confirmation is received. Additionally, AEMA requests that MISO includes clarifying language regarding the circumstances where a RERRA may contest a DEAR after the initial approval where the size of the utility has not changed relative to the 4 million MW/hr. threshold. 
• 38.7.A.iii.2. LBA and LSE or EDC Notifications and Approvals. MISO proposes to provide the LBA, LSE, and EDC with sixty (60) Business Days to review registration information. No response from the LBA, EDC, or LSE within 60 days will default the enrollment to “approved.” AEMA Feedback:AEMA supports the language and default to “approved” for enrollment when there is no response from the LBA, LSE, or EDC. AEMA also supports the inclusion of language on how MISO will assign the participation model (EPNode and Load Zone) for situations when there is a lack of response by the LBA, LSE, or EDC.
• 38.7.B. MISO proposes to communicate DEAR clearing in the MISO Energy and Operating Reserve Market and the Planning Resource Auction to both the DEAR and the applicable Local Balancing Authority (LBA). 
• 38.7.C. MISO proposes to establish metering requirements in accordance with Module C, Module E-1, and Attachment TT. Meter requirements are as specified in Section 38.2.5.e. and telemetry requirements are specified in the Business Practices Manual. The current MISO BPM-031-r16 requires 4-second scan rate for Market Participant receipt and 2-second scan rate for MISO receipt. That same BPM sets a 5-MW minimum size for the requirements to be applicable. AEMA Feedback: AEMA recognizes the need for MISO to have Real Time telemetry on larger resources providing Ancillary Services like Regulation; however, the cost of Real Time telemetry can be a significant barrier to participation for small resources, particularly if they are only providing Energy and/or Spinning Reserve Response. MISO should clarify the 5-MW minimum size applicability for the future. This limit should be incorporated into the Tariff if MISO’s intention is to maintain the 5 MW threshold for Real-Time telemetry requirements on all DEAR.
• 38.7.D. MISO proposes that DERAs will submit meter data for DEARs using aggregations and groups that were used in registration for settlement in accordance with Module C. MISO also proposes that it may “review” DERA participation if the LSE successfully disputes the settlement of the DERA more than 10% of the time and refer the matter to the RERRA and/or IMM if the review indicates DERA and/or LSE is “engaging in activity that is inconsistent with the Energy and Operating Reserves Markets.” 
• 39.1.2 MISO proposes to include DEARs within the rules for Self-Scheduling of Resources. 
• 39.2.1A.a. and 39.2.1A.g. MISO proposes to include DEARs within the product requirements for operating reserves, establishing the same limits for DEARs that currently exist for other resources in MISO. 
• 39.2.1B MISO proposes to include DEARs within those resources that can provide Operating Reserves.
• 39.2.5E MISO proposes to define the Offer Rules for a DEAR to participate in the Day-Ahead Energy and Operating Reserve Market. A DEAR my offer to withdraw and/or inject Energy, Regulating Reserve, Spinning Reserve, Supplemental Reserve, Up Ramp Capability, Down Ramp Capability, and/or Short-Term Reserve if it is capable of providing the services. Offer Caps include a $1,000/MWh soft Energy offer price cap and $2,000/MWh hard Energy offer price cap. 
• 39.2.9 MISO proposes to incorporate DEAR Offers into the factors for Locational Marginal Price determination.
• 39.3.2A and 39.3.2B MISO proposes to incorporate DEARs into Day-Ahead Credits on Energy and Ancillary Services and Day-Ahead Revenue Sufficiency Guarantee Payments.
• 40.1 et al. MISO proposes to incorporate DEARs into the Reliability Assessment Commitment (RAC) and Look-Ahead Commitment (LAC).
• 40.2.7B MISO proposes to incorporate DEAR offer rules into the Electric Storage Resource section.
• 40.2.20 and 40.2.23 MISO proposes to incorporate DEARs into Capacity Shortage Condition responses and Contingency Reserve Deployment.
• 40.3.3.1 MISO proposes to incorporate Distributed Demand Response Resources into the sections on Market Charges relative to Net Benefits Price Threshold.
• 40.3.3.3 MISO proposes to incorporate DEARs into Real-Time Credits calculations on Energy and Operating Reserve Markets and Real-Time Revenue Sufficiency Guarantee.
• 40.3.4 MISO proposes to establish an Excessive Energy Threshold as “the minimum of ten percent (10%) of the Hourly Economic Maximum or 6 MW,” which is similar to treatment of Electric Storage Resources.
• 40.3.5.2 et al. MISO proposes to incorporate DEARs into resources that are eligible for Real Time Operating Reserve Sufficiency Guarantee Payments (RTORSGP).
• 40.3.6.2 et al. MISO proposes to incorporate DEARs into resources that are eligible for Day-Ahead Margin Assurance Payment (DAMAP). 

AEMA Feedback: Aside from the specific concerns listed above, AEMA has no additional objections to the proposal by MISO.

• Module E-1: Resource Adequacy

Proposal Summary: MISO proposes to include Distributed Energy Aggregated Resources (DEAR) that are not interconnected to the Transmission System the list of resources that are “grossed up” to remove the general impact of transmission losses for purposes of Capacity Accreditation since these resources are directly connected at the point of the load. Additionally, MISO proposes to include “Demand behind a DEAR,” in the Coincident Peak Demand and Local Reserve Zone Peak Demand forecasts submitted by Load Serving Entities. MISO also defines testing requirements, exclusions, and limited use rules for DEARs. A demonstration of deliverability is required for injected MWs. MISO proposes to accredit a DEAR “based on the sum of the individual accredited values of the underlying Distributed Energy Resources within the aggregation.”  

AEMA Feedback: AEMA supports the 10 MW exclusion for GVTC, and the other elements of the proposal based upon equitable treatment with other resources. 

• Attachment TT: Measurement and Verification (M&V) Criteria. 

Proposal Summary: MISO proposes to incorporate DEAR into the current M&V process that exists for DRR, LMR and EDR. This proposal includes multiple options for M&V including the ability to request a custom base line.

AEMA Feedback: AEMA supports the proposal based upon equitable treatment to other resources in the MISO market.

AEMA appreciates MISO’s consideration of these comments as part of the Order 2222 compliance approach being discussed at the DERTF. 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 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

This feedback is submitted on behalf of the Missouri Joint Municipal Electric Utility Commission. The focus of the feedback is on the verification required to be submitted by aggregators that RERRAs have approved such aggregators' participation. 

Under Module C 38.2.2.h (v) it states: "verify to the Transmission Provider during the asset registration process that it has received any required approvals from all applicable RERRAs to enable such Resources to provide products and services under this Tariff." 

MJMEUC believes that the verification by the aggregator under this language is insufficient for RERRAs that govern municipal utilities. RERRAs for municipal utilities are typically City Councils which can only provide approvals by passing city ordinances. Therefore, MJMEUC recommends that a provision be added to the Tariff language specifying that for RERRAs that govern municipal utilities, an aggregator shall submit a certified copy of an ordinance passed by the RERRA approving the aggregator’s participation.