During the June 7, 2021 Distributed Energy Resources Task Force (DERTF) meeting, MISO presented Iteration 1 of FERC Order 2222 Filing Framework. Stakeholder feedback is requested on Filing Framework Document, DERa Resource Modeling, Settlements and dual participation. Focus should be on the following questions:
Please provide feedback by June 28.
DTE is pleased to provide the following feedback on various aspects of MISO’s latest filing framework for compliance with Order 2222. Please refer to the emailed attachment for DTE's detailed responses to questions raised in MISO's presentation. Please also post the emailed attachment on the stakeholder portal or in future meeting materials.
As Voltus has pointed out in prior comments and in a presentation to the DER task force, the major deficiency of MISO’s framework for 2222 thus far is the approach to aggregation.
Voltus agrees with the comments filed by AEMA, which argue that MISO must not limit aggregations to a single EP Node. This limitation will have the de facto effect of making aggregation impossible. Locating a meaningful number of different DER resource types within a single EP Node is not feasible given the small geographic reach of any given node. Limiting aggregations to a single EP Node therefore violates the express purpose of Order No. 2222, which requires that the ISOs create meaningful market participation models for DER aggregations.
Order No. 2222 also requires ISOs to allow aggregations that are “as geographically broad as technically feasible.” Limiting aggregations to a single EP Node does not pass this test: aggregations across CP Nodes are “technically feasible,” as is evident from the hundred of megawatts of Demand Response Resources as well as several gigawatts of Load Modifying Resources already operating in MISO. What is feasible could reasonably vary by product, with higher levels of aggregation available to capacity versus reserves versus energy. MISO must investigate the question of feasibility on a product-by-product basis.
In many other areas, MISO’s proposals are promising. The current approaches to DERA modeling, resource size limitations, and eligibility are largely logical and compliant with Order 2222. Some enhancements could be made to the commercial modeling data requirements, however. The proposal now conflates information that should be provided at the DER level versus the DERA level. For example, given that heterogeneous aggregations of different types of DERs will be permitted, the “unit type” and “fuel type” data should be set at the DER level rather than DERA. This would allow for one DERA to include multiple DERs with different fuel types. Resource size data (i.e. MW values) for modeling should also be submitted at the DER level, so that DERA formation and registration can proceed for any combination of specific DERs (aggregate data would simply sum across individual MW values).
The draft real-time data requirements also deserve further consideration. It is not clear if MISO intends to require these real-time data streams for all DERAs regardless of the service provided (e.g. capacity vs. regulation), nor is it clear how output measured in MVAR or breaker status meet MISO’s criteria of being “Automated”, “Accurate”, and “Actionable”. These two real-time metrics in particular may not be technologically feasible for all DERs, yet are listed on slide 46 among the draft real-time data requirements.
In short, MISO’s progress is commendable but a few key areas require further debate before they are submitted to FERC. Brief responses to specific feedback requests are below:
What percent of resources being considered for wholesale market participation will exceed 5 MW at a single distribution interconnection location?
5 MW or larger single resources are relatively rare (5%?) compared to the many, many 1 kW- 5 MW residential and small commercial facilities hosting DERs.
Should a DERA submit aggregated meter data or individual DER meter data for performance tracking? Why?
Where M&V includes within-day adjustments to baselines, meter data should be provided by individual DERs. This approach will allow within-day adjustments to vary between different resources within an aggregation, therefore improving baseline accuracy. For other M&V methods, such as a firm service level baselines or “meter-before, meter-after”, the simplicity of data aggregation is preferable to individual metering.
How should wholesale market transactions by DERAs be tracked and reported to prevent double counting?
Program enrollment processes should be used to prevent conflicting enrollments, which will obviate the need to check for double counting once DERAs are operational in the market.
During the June 7, 2021 Distributed Energy Resources Task Force (DERTF) meeting, presented Iteration 1 of FERC Order 2222 Filing Framework. Stakeholder feedback is requested on Filing Framework Document, DERa Resource Modeling, Settlements and dual participation.
Environmental Sector Response:
The Environmental Sector appreciates this opportunity to provide feedback on MISO’s new Filing Framework Document and various questions from MISO. In this document, we both respond to MISO’s specific questions and provide general feedback on the framework.
Given we are almost nine months away from the required FERC compliance filing, MISO should convene a workshop for DER aggregators to hear directly similar to the workshops with EDCs and RERRAs.
Responses to MISO questions
How can the filing framework documentation be improved?
The Environmental Sector is generally supportive of MISO’s Filing Framework Document.
MISO should include definitions of ESR, DERa, and DR in the document.
MISO should include a more detailed description of the tradeoffs of using the DIR/ESR participation model vs other existing products.
MISO should consider how it can more clearly flag issues that it believes are required to be part of its Order 2222 compliance filing as opposed to issues that will be useful during the compliance/implementation process. Also, because this is meant to be an iterative document, we suggest that MISO (1) include a slide at the beginning pointing the reader to the most recent changes, and (2) commit to communicating with the DERTF listserv when updates are made to the document.
What percent of resources being considered for wholesale market participation will exceed 5 MW at a single distribution interconnection location?
The Environmental Sector expects that 5 MW resources at a single distribution interconnection location will be common. For example, bus depots and other fleet facilities have the potential to be a common resource that will exceed 5 MW.
What priority would you assign the ability to represent more than one path to the transmission system for a DERa, recognizing that only one transmission path can be available at a time? (Rate: Low, Medium, High)
The Environmental Sector is not currently able to provide a priority level for this. We believe that the priority will depend on various use cases, and we urge MISO to explore those use cases in determining whether to prioritize this issue. If representing more than one path will significantly increase DERA flexibility, MISO should coordinate with distribution utilities on best practices for identifying alternative paths.
Are any of the resources being considered for wholesale market participation only installed on a single phase?
While the Environmental Sector expects that most resources will be three-phase, MISO should maintain flexibility to accommodate single phase resources. For example, residential buildings, including multi-unit buildings, are likely to be on a single phase.
Should a DERA submit aggregated meter data or individual DER meter data for performance tracking? Why?
DERA should be required to submit aggregated meter data by default. Requiring individual DER meter data for all DERa may create a significant logistical barrier for DERA participation. If MISO finds situations where individual DER meter data is necessary, it should clearly articulate why.
How should wholesale market transactions by DERAs be tracked and reported to prevent double counting?
The Environmental Sector requests clarification on the priority for tracking and reporting double counting of wholesale services. Wholesale double counting should be handled at registration, not with each transaction.
Other Comments on the Framework Document
In addition to the responses above, we offer the following comments on the framework.
Slide 8: The best way to future-proof the framework and address the uncertainty in the blue box is to make the rules as generic and flexible as possible—focus on getting DERs integrated into existing products and markets rather than overdetermined “participation models”.
Slide 15: We agree with this overall responsibility framework, with two comments:
Slide 28: We strongly support this slide. This flow agrees with our understanding of the Order 2222 non-discriminatory interconnection requirements. Two questions:
Slide 38: Several questions on these participation models.
Slide 39: Has MISO considered allowing aggregation for ancillary services across reserve zones rather than by node? We note that the commercial model on slide 45 seems to allow for “AS only” resources.
Slides 48-49: We remain concerned about the limits self-committing puts on smaller resources and would appreciate a more in-depth look at how cost sensitive DERa work under the DIR/ESR participation model. Two cases to consider are DERa that can provide relatively expensive energy, say around $200/MWh, and low margin DERs that can shift consumption around. Those correspond to CHP and smart thermal loads, respectively.
Slides 58-62: On meter data, we support the DERA submitting aggregated data broken out as suggested by MISO in slide 58, alternative 1.
On double counting, we support addressing it through the registration process, especially in the enrollment and compatibility check phases. The idea on slide 61 of identifying which retail tariffs would result in double counting is a good one but should probably be done on a product-by-product basis. For example, a DERa under an interruptible tariff that is used as a resource adequacy asset should not be eligible to provide capacity but might still be able to provide energy and ancillary services.
Hopefully, few or no tariffs will be in the “sometimes compatible” category. Some of the issues about time of use rates might have been worked out in the implementation of Order 745—to MISO’s example, is it clear that time-differentiated energy rates make a resource ineligible to provide DR?
Addressing double counting at the transaction level seems quite complicated, and it might be best to wait for use cases that show this to be necessary before proceeding.
Slides 63-65: We remain concerned about the potentially high costs of MISO’s proposed telemetry solutions. Relaxing from 2 sec to 10 sec is unlikely to have a significant impact. We ask MISO to look more deeply into which there are other situations whereby telemetry requirements can be further relaxed.
There seems to be inconsistency between the stated need for real-time data and the requirement that DERa less than 1 MW self-commit. What is the justification for requiring real-time data from small non-dispatchable resources? MISO should consider requiring settlement-only data from self-committing resources.
What level of telemetry does MISO have at the nodes? Is it possible that nodal telemetry can meet operational needs, allowing for more DERa to only need settlement data?
Slide 69: Most of the distribution utility review should happen during the RERRA-jurisdictional interconnection process for the individual DERs. There should be little discretionary evaluation done by EDCs when DERs/DERa register with MISO, ideally limited to a simple confirmation of correct account numbers, verifying interconnection status, and checking for retail rates that could lead to double counting. Given that this will be an administrative process, it should require far less than 60 days—we suggest 10. Finally, EDC failure to respond should result in approval of the DER/DERa registration
MEMORANDUM
TO: MISO DER TASK FORCE
FROM: THE ENTERGY OPERATING COMPANIES
SUBJECT: FILING FRAME WORK, MODELING AND DATA
DATE: JUNE 28, 2021
In response to MISO’s questions concerning Distributed Energy Resource (DER) compliance framework, DER aggregation DERa) resource modeling and DERa data, under FERC Order 2222 as presented in the June 7, 2021 DERFT meeting, the Entergy Operating Companies ("EOCs" or “Entergy”)[1] offer the following comments.
1. General feedback related to the presentation and the framework as a whole:
2. DER aggregation Resource Modeling:
3. DER aggregation Data:
Settlement Data Dispute Resolution: Consistent with prior EOC feedback, Entergy believes that a dedicated process, outside of the formal Dispute Resolution Process, should be established for reconciliation of meter data and performance of DERa or a DER within the aggregation in order to prevent both double-counting and inaccurate settlements. As noted above, Entergy supports MISO’s alternative under consideration that would have a DERA coordinate with an EDC to utilize existing infrastructure and metering to capture meter data.
4. Entergy Feedback on Demand Response settlements under Order 745 (slide 59)
The EOCs appreciate the opportunity to provide input.
[1] The Entergy Operating Companies are Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, Entergy New Orleans, LLC, and Entergy Texas, Inc.
What percent of resources being considered for wholesale market participation will exceed 5 MW at a single distribution interconnection location?
Currently, >5MW resources are not a large concern, since Illinois has few resources of that size. If there are larger resources, they tend to participate directly in the MISO markets on their own without an aggregator. However, given that Order No. 2222 is technology-leading, , and with other state and federal policies incenting developments like electric vehicle fleets, this could change in the future. In the future, larger resources may be more common.
• 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
Generally, multiple transmission paths are a low priority in Illinois. In Illinois, there is more concern with the interconnection queue and bringing renewable resources online. Multiple transmission paths are not cost effective. Long haul issues and increased import limits, which improve capacity and are facilitated by improved transmission, would be more beneficial.
• Are any of the resources being considered for wholesale market participation only installed on a single phase
While larger customers may want three phase, we suspect the bulk of the DER aggregation will be for residential customers, which are all single phase. Even for non-residential customers, only half of Ameren Illinois’ non-residential customers are on a three phase. Depending on what business models develop, some aggregators may have an interest in three phase power.
How should wholesale market transactions by DERAs be tracked and reported to prevent double counting?
Data accuracy, in terms of both registration and metering, needs to be addressed. First, well-designed practices to prevent resources from being registered in more than one aggregation are crucial. The registration process must be clear and comprehensive, in order to catch any double registrations that occur. Logic systems that capture and address resources registering in more than one aggregation are useful to address this problem; Ameren Illinois has already successfully put this into practice to accommodate DR aggregations. It will be important that aggregators know what the resources in their aggregations are and where they are located.
In terms of meter data, it is important to determine whether resources are delivering the energy they promise. At some point, MISO will need individual meter data. Non-utility meters, such as data from the inverter, may not provide sufficient accuracy. DER resources can have a dynamic nature: resources are added and others drop out. This churn makes tracking resources accurately difficult, but also necessary. It would also be useful to measure aggregator capacity seasonally, since under the new seasonal construct resources may have different capacity at different times of year.
Xcel Energy appreciates the opportunity to provide feedback on the following items from the June 7 DERTF:
DERa Resource Modeling
What percent of resources being considered for wholesale market participation will exceed 5 MW at a single distribution interconnection location?
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)
Are any of the resources being considered for wholesale market participation only installed on a single phase?
Settlement
Should a DERA submit aggregated meter data or individual DER meter data for performance tracking? Why?
How should wholesale market transactions by DERAs be tracked and reported to prevent double counting?
How can the filing framework documentation be improved?
Iteration 1 of the Filing Framework document is well organized and helpful for tracking issues and progress.
What percent of resources being considered for wholesale market participation will exceed 5 MW at a single distribution interconnection location?
Minnesota Power does not have very many of these participants yet, though we are seeing an increase in the number of applications looking for additional information.
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)
Low, there may be only one option to the transmission grid from the distribution system on the majority of the installations.
Are any of the resources being considered for wholesale market participation only installed on a single phase?
We expect the majority of the installations, unless larger than 1 MW to 5 MW, would be single phase installations.
Need to determine if the DERA or EDC is responsible for metering and communications equipment at the DER sites. If it’s Minnesota Power, we would meter each site individually so whomever handles the data would need to let us know which way to provide it. It can be done either way from our perspective.
How should wholesale market transactions by DERAs be tracked and reported to prevent double counting?
Minnesota Power would just be providing the data from each site or aggregated. It would need to be watched carefully in aggregations to ensure that a metering site wasn’t being used in multiple locations with the same aggregation.
General Comment:
Minnesota Power customer electric rates are tied to the usage of our entire system (generation, transmission, distribution). We also charge neighboring utilities a wheeling rate to use our infrastructure. Will the DERA be charged a similar rate for the use of a utility’s system?
Sincerely,
Marcia A. Podratz
Regulatory Compliance Principal
Minnesota Power
No recommendations at this time.
Expect a low percent of resources that may participate in aggregations will exceed 5MW at a single distribution interconnection location.
Low priority, in that the DERa should not dispatch if system is in a reconfigured state.
Yes, potentially the vast majority of the resources considered for aggregation would be installed on a single phase.
Need individual DER meter data to prevent double counting
DERA wholesale market transactions should be tracked and reported at the individual DER level to prevent double counting and take into account retail choice/net metering or other complexities.
Consumers Energy appreciates the opportunity to provide feedback on MISO’s Distributed Energy Resource Task Force (DERTF) Filing Framework Document
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)
Consumers Energy is interpreting this question to mean whether a DERa would be able to sell into the market at different locations based on changes in composition, operating state of the aggregation, or other appropriate reasons. We believe the ability for MISO to accommodate this is important and should be a high priority. This will ensure that DERas are able to participate at the CPnode that is most appropriate on a continuing basis, notwithstanding changes in composition or physical location(s) of its component DERs. Without some mechanism for doing this, DERas could end up participating in locations that are suboptimal based on the composition of the aggregation or have to go through the DERa registration process again (MISO and stakeholders would have to determine some comprehensible threshold for when this would be required).
However, DERAs should not be able to change the CPnode the aggregation is selling into absent some compelling reason for doing so, such as the ones articulated above. To allow otherwise would present inappropriate arbitrage opportunities. Accordingly, there should be a review and approval process for such changes.
We also note that any physical changes to the locations of DERs in an aggregation would have to be subject to EDC and LBA interconnection procedures, requirements, and approval processes.
Should a DERA submit aggregated meter data or individual DER meter data for performance tracking? Why?
MISO should require each individual resource, in an aggregation of an Energy Pricing (EP) node, to be metered and reported separately at each Point of Interconnection (POI). If there are multiple resources at one site connected through the same POI, those resources can be aggregated as a Distributed Energy Resource aggregation (DERa - Asset), but injection and demand response (DR) must be separately metered. It should be noted that metering configurations may be impacted by Relevant Electric Retail Regulatory Authority (RERRA) and/or Electric Distribution Company (EDC) requirements. If a DR exists within a DERa, then the load will always need to be metered separately in order to calculate net benefits.
How should wholesale market transactions by DERAs be tracked and reported to prevent double counting?
Wholesale and retail tariffed services must be accounted for separately and accurately, either through direct measurement or calculation. For all wholesale transactions, DERAs should identify the component DERs that will be providing the services being aggregated and offered into the market and then provide meter data that validates the delivery of those services. EDCs will need access to this data for distribution planning, distribution operations, data validation, market settlements, and other reporting requirements. Accordingly, Consumers Energy proposes that MISO develop, with the engagement of stakeholders, a data repository tool which would house individual DER meter data (associated in some fashion with the relevant aggregation) and require DERAs to share the data with both MISO and the EDCs. This will ensure that DER output can be added back to retail load, if appropriate, to avoid double counting. MISO should manage the repository and be responsible for cyber-security and data privacy. Our support for a MISO-managed data repository tool is dependent upon reaching an appropriate construct with MISO and stakeholders that ensures MISO only receives that data which they need to carry out its function as transmission provider. For security purposes, no extraneous data shall be provided. Our support is also contingent upon our endorsement of the cyber-security and data privacy protocols developed by MISO and stakeholders.
There should also be a BPM supported ongoing measurement and verification (M&V) regime for individual DERs. M&V is a service which may be provided by either the EDC or a third party depending, among other things, on RERRA requirements. Any M&V process must also include a periodic audit and a progressive dispute resolution process. Regarding the latter, there must be interim steps in any dispute resolution process in order to handle minor infractions in a relatively efficient manner. Finally, the EDC will need access to M&V results, and the underlying data, based on the enrolled market product.
EDCs retain the right to set metering, communications requirements and infrastructure needs that are distinct from MISO requirements for DER participation under FERC Order 2222. EDC metering, communications requirements and infrastructure needs should not be required to be modified due to DER market participation under FERC Order 2222.
The DERA (Market Participant (MP)) is responsible for securing the metering required for wholesale participation. The EDC or RERRA may require metering of the DERa (Asset) or DER needed for retail billing or distribution wheeling independently of MISO’s requirements. If the EDC metering satisfies MISO’s requirements and standards, Consumers Energy prefers that the DERA (MP) use the data collected from EDC metering for wholesale participation. If MISO requirements cannot be met with EDC metering capabilities, the EDC cannot be forced by MISO to modify its standards. Demand Response (DR) resources may have metering requirements that differ from non-demand response DERs.
MISO’s metering requirements must address the different possible configurations of a DERA which could include, but are not limited to:
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.
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:
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.
[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/PY21-22%20Planning%20Resource%20Auction%20Results541166.pdf
WPPI offers the following in response to the questions posed in this DERTF feedback request:
Q1 How can the filing framework documentation be improved?
WPPI finds the filing framework documentation helpful and we don’t have any suggested improvements. In particular, given breadth of issues that MISO needs to address in its Order 2222 compliance and the long timeline, we appreciate the identification of new material (vs. material previously presented).
Q2 What percent of resources being considered for wholesale market participation will exceed 5 MW at a single distribution interconnection location?
At this point, WPPI is not aware of any resources being considered for wholesale market participation. However, we expect WPPI members (50 municipal utilities and 1 coop) to avoid wholesale market participation that would result in back feed from the distribution system to the transmission system, given the complications it would present on the distribution system. Considering that limitation, of WPPI’s 158 delivery points, about 30 may be able to support wholesale market participation of more than 5 MW.
Q3 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)
Medium priority. There is a distribution steady state (~98-99% of the time) that can provide the basis for the EPNode (aka transmission path) that serves any given load. However, that EPNode can change, particularly when there is work on the distribution system. While nearby EPNodes tend to have similar prices, appropriate locational pricing is fundamental to the MISO market. A high level of DERa participation and/or a DERa that is [10]% or more of its steady state EPNode may indicate a high (vs. medium) priority be assigned to the ability to represent more than one path to the transmission system for the DERa (recognizing only one transmission path can be available at a time).
Q4 Are any of the resources being considered for wholesale market participation only installed on a single phase?
At this early stage, it is difficult for WPPI to know whether resources being considered for wholesale market participation are/will be installed on a single phase. However, to the extent a DERa consists of homes and/or small commercial customers, they are overwhelmingly single phase. We expect projects larger than about 50 kW will be installed on 3 phase.
Q5 Should a DERA submit aggregated meter data or individual meter data for performance tracking? Why? And Q6 How should wholesale market transactions by DERAs be tracked and reported to prevent double counting?
For WPPI, the answers to questions to Q5 and Q6 depend on what meter and other data a DERA must provide MISO in order to (1) allow the distribution utility to separate their load purchases from MISO from the DERA’s participation in MISO and (2) provide for confirmation that no wholesale purchases (in the case of an Electric Storage Resource) were used at retail. At this point, outside of demand response included in a DERa (addressed by MISO’s compliance with Order 745), it is not clear to WPPI what data a DERA must provide in order to accomplish these two objectives. WPPI suggests that the DERTF explore various possible DER aggregations in order to determine what data are necessary to ensure DERA participation in MISO is accurately measured and any purchases are not used a retail.
Advanced Energy Management Alliance
MISO Distributed Energy Resource Task Force (DERTF)
“FERC Order 2222 – MISO Filing Framework Document – Iteration 1
June 28, 2021
Advanced Energy Management Alliance (“AEMA”) [1] respectfully submits the following comments to the MISO Distributed Energy Resource Task Force (“DERTF”) on the first iteration of the Order 2222 Filing Framework that was presented at the June 7, 2021, meeting of the DERTF. 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.
AEMA appreciates MISO sharing the first revision of the comprehensive proposal with the DERTF and for the opportunity to provide feedback. In the feedback request, MISO has requested general feedback on the proposal and specific feedback on the questions identified below. The responses of AEMA to the feedback request is as follows:
Although not directly requested, AEMA would like to comment on a key element of the proposal, particularly the intention to limit aggregation of DERs to a single EPNode. Within the presentation to the DERTF, MISO communicated its plan to move forward with limiting DERA aggregation participation to a single EPNode. As mentioned in prior comments from AEMA and others, AEMA strongly urges MISO to reexamine this recommendation. One of the primary objectives of FERC Order 2222 is to allow for aggregation of multiple DERs that are “as geographically broad as technically feasible.”[2]
The efficiency and economies of scale relative to multi-node homogeneous and heterogeneous aggregation of DER make aggregation across multiple nodes a critical element of compliance to the FERC Order and efficient participation.
The flexibility of aggregating DER across multiple geographic nodes also provides better opportunities for a DERA to ensure reliable supply of services during periods of distribution (or transmission) system reconfiguration or outages.
AEMA requests that MISO explore the definition of “technically feasible” and look beyond what is currently feasible or feasible without modifications. For example, is it possible to allow aggregations across multiple nodes at a limited scope? AEMA suggests that MISO should allow aggregation of some level of participation over multiple EP Nodes, perhaps within a defined MISO Zone or Balancing Area.
Aggregations above a reasonably defined limit might be restricted to a single EP node or nodes that are geographically close, but in defined amounts, multi-zone aggregations should be allowed. This provision would allow DERAs to combine resources across geographic areas that are less densely populated in an efficient manner and participate in the MISO market.
Of particular concern to AEMA is that MISO, in its simplified evaluation framework, has failed to demonstrate that aggregation across limited nodes is not technically feasible as directed by FERC in Order 2222.[3]
Additionally, MISO should consider different geographic scopes of aggregation based on the type of service being provided. For example, DERAs supplying capacity or spinning reserves could be aggregated differently than resources providing only energy or regulation. This is made even more relevant since MISO dispatches spinning reserves and capacity resources on a pro rata basis today.
AEMA appreciates the comprehensive nature of the filing framework document that MISO presented at the June 7 meeting of the DERTF. The Table of Contents, internal hyperlinks, and thoroughness of the document are extremely helpful. AEMA encourages MISO to keep the comprehensive nature of the document so that it remains a “one stop shop” for the compliance direction of MISO. The breakdown of alternatives considered, and evaluation considerations is helpful to understanding MISOs rationale on the alternative selected. One modification that would be useful would be to clearly identify which Section of the FERC Order is being addressed in each evaluation section. For example, Sections C, D, and E are discussed in the proposal and then MISO looks at “range of DER aggregations’ characteristics.” For the issues and alternatives being considered, what is the Section is being addressed?
Slide 11 shows a calendar framework. It would be helpful if MISO could label the calendar with at least the months in which the meetings occur.
AEMA would like to request clarity on the statement, “new DERa market resource model that will be created…” as described in slide 43. Will this “new model” be accessible at the 0.1 MW level? Is MISO proposing that a DERA can register a DERa as any of the existing participation models including this new representative aggregate generator model from slide 43? Will this new representative aggregate generator model be eligible to supply the full suite of ancillary services and capacity?
Slide 46 seems to indicate that all DERa would have to supply Real-Time data in all cases; however, many resource types in the MISO market do not have to supply Real-Time data today. Requiring Real-Time data from all resource types for all services provided would be a significant barrier to participation without a reasonable justification for the expenses. MISO should adjust requirements in this proposal to mirror recommendations previously provided by AEMA (in the straw proposal presented to the DERTF) to only require Real-Time data if it is needed for reliability. For example, if the resource is providing regulation, then Real-Time data at the aggregation would be necessary. However, resources providing spinning reserves and simple energy response are not required to have Real-Time data today.
Additionally, it would be helpful if MISO shared any “minority opinions” relative to solutions and rationale for not selecting the alternative. For example, are there options that are simply not “technically feasible” under any circumstances, as opposed to those are more difficult to implement? Certainly, if there is no technical capability, then those solutions will be more difficult to implement, but a solution that is complex and requires resources to implement, should not be quickly dismissed.
Slides 22-24 detail the ability for a utility to opt-out from allowing DERAs to aggregate DER resources if the utility has less than 4 million MWh in sales in the prior fiscal year,[4] but only with RERRA approval, as noted in Order 2222. The questions posed on slide 24 will be important for stakeholders and MISO staff to consider. While this item will require further stakeholder discussion, AEMA recommends using publicly verifiable data sources, such as the EIA data referenced for use in the table on slide 23 (or other source that is known at the time of DERa registration for the upcoming delivery year). As the RERRA will ultimately decide whether DERs within a small utility may participate as part of a DERa, opt-in designations could potentially be made for a particular DERA (or DERAs) or selection of DERs. Regardless of how the RERRA decides to provide notice of the opt-in status for a particular small utility, the designation should remain in place for, at minimum, the delivery year for which a DERA is registering resources, and should remain effective until such time as the utility’s fiscal year sales increase beyond 4 million MWh (where the ability to opt-out would no longer exist), or have a clearly-stated end date that aligns with MISO’s process timelines and further define the process by which the DER, DERA or RERRA may extend the opt-in.
AEMA represents a broad cross section of distributed energy resource companies. It is difficult to predict the percentage of resources that will exceed 5 MW’s at a single location because of the number of variables in play. Currently, MISO is proposing to only allow aggregation at a single EP node. This significant barrier to participation of DERAs in the MISO market will tend to push the percentage of resources exceeding 5 MW higher because only in situations where there are large concentrations of resources will it potentially be economic to register for participation. Additionally, it is unclear when MISO will begin to allow DER participation in the market. If the participation of DER is delayed many years, then there will be a higher number of small DER because small technologies are becoming more economic and prolific, which will allow for more resources aggregating at smaller levels. MISO should not create any barriers related to size of resources at a single interconnection location.
In general, AEMA does not represent Transmission Owners or Distribution Operators, so AEMA would defer feedback on this question to those entities directly involved with system operations and modeling. However, AEMA would note that the additional complexity of system modeling should only be added if it adds value that is commensurate with cost. Additional modeling should not be added as a “nice to do.”
FERC Order 2222 is written to ensure that participation of aggregated DER in the wholesale market remains technology neutral. While most DERs that are utilized today are multi-phase, it is possible that single phase resources could either be expanded or invented that could be utilized as a market asset. MISO should ensure that single phase technologies are able to participate in the market without significant barriers to participation.
MISO should have the DERA submit aggregated meter data and not individual DER meter data for performance tracking. The reason that the DERA should only be submitting the aggregated values for performance is that the DERA is participating in the market as an aggregation of individual DERs. The DERA is uniquely situated to make use of the suite of aggregated resources to ensure resource performance. From hour-to-hour and day-to-day, the DERA will take advantage of the collection of resources to ensure that the performance obligations are met, and settlement is appropriate. Creating a requirement to supply individual DER meter data can create a significant burden that has no value. This additional requirement would serve as a barrier to participation for the DERA and potentially remove the performance flexibility that aggregations can bring to the table. The importance of metering data is to ensure overall performance. This assurance can be determined through the aggregated meter data.
The primary concern about double counting is ensuring that a resource is not compensated twice for providing the same service. MISO should confirm during the registration process that the individual DERs that are registered within the aggregation are not part of other programs (such as retail programs). This confirmation can be part of the outreach to the appropriate Distribution Utility to ensure that the DER is not already registered to provide services. MISO can communicate with the DU to ensure that if there are future changes to the status of the DER, then those changes should be communicated back to MISO to avoid double counting. MISO can request an attestation from the DERA at registration that the DERs are not part of another program that would potentially lead to double counting. With the assurances at registration, the DERA would “report only wholesale transactions to MISO,” which is the first alternative under consideration in the MISO proposal to the DERTF on June 7 (slide 60).
AEMA appreciates MISO’s consideration of these comments as part of the Order 2222 compliance approach being discussed in 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
[1] For additional information, see AEMA website: http://aem-alliance.org
[2] Order No. 2222, 172 FERC ¶ 61,247 at P 188. “Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators”
[3] Order No. 2222, 172 FERC ¶ 61,247 at P 204.
[4] Herein referred to as “small utility” or “small utilities”
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)
Medium priority: ATC and our customers have identified this as a concern and have started working with our Local Distribution Companies (LDCs) to identify if they have alternative locations to connect DERs to the transmission system. ATC has seen this issue in real time which actually prevented one customer from using their DER at an alternate location when the main connection was planned out of service. At the time, MISO did not have a way to handle this. One concern is that any alternate outlets in the Planning model may be needed in the Operations model which then drives EMS and SCADA additions, which drives additional costs and complexity.
Should a DERA submit aggregated meter data or individual DER meter data for performance tracking? Why?
ATC would prefer individual metering for data analytic purposes to anticipate and learn how each resource behaves. This will be especially helpful if an aggregation is made up of multiple resource types (e.g. wind and solar).
NIPSCO thanks MISO for the opportunity to provide feedback on DER questions related to Order 2222.
1) DERa Resource Modeling:
a. What percent of resources being considered for wholesale market participation will exceed 5 MW at a single distribution interconnection location?
NIPSCO believes the majority of the interconnections are pushing to be in the range of 5-20 MW. At this time, NIPSCO predicts that smaller resource customers will continue to prefer to participate in retail program offerings versus the wholesale market.
b. 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
NIPSCO places the priority as Low. NIPSCO would like the DERA to operate when the system topology is normal.
c. Are any of the resources being considered for wholesale market participation only installed on a single phase?
Yes. NIPSCO’s residential resources are installed on a single phase that can be considered for wholesale market participation.
2)Metering/Telemetry/Settlements:
a. Should a DERA submit aggregated meter data or individual DER meter data for performance tracking? Why?
NIPSCO believes DERA can submit aggregated data by EPNode, however, the EDC's will need the individual DER metered information so that they can account for the wholesale energy produced by the DER asset versus the retail power. Additionally, each individual DER meter data is needed in order to determine the impact to the distribution system. The DERA can submit aggregate meter data, but it must list every individual DER contribution and location. This tracking would assist in preventing double counting.
b. How should wholesale market transactions by DERAs be tracked and reported to prevent double counting?
NIPSCO believes the aggregators will need to share the customers that are in their aggregation. This can be done through data sharing between DERA’s and EDC's. Metering resources separate from load will aid in preventing double counting.