In the January 22, 2024, Electric Distribution Company (EDC) Workshop, stakeholders were invited to submit feedback on EDC, Transmission Owner (TO), and/or MISO Distributed Energy Aggregated Resource (DEAR) reliability reviews. Please provide feedback by February 5, 2024.
Specific points include:
ITC appreciates the opportunity to offer comments on the reliability review of DER/DEARs.
Potential Study Gaps?
We support the standardized sequencing proposed by MISO on slide 8 Workplan Prioritization (misoenergy.org) wherein eligibility is determined before reliability. As we understand it this means managing DER/DEAR studies after the resources and/or aggregations have interconnected and passed all required interconnection screening and been deemed eligible (by all governing entities) to be part of an aggregation that will participate in MISO wholesale markets. One risk we note is that it could be the case that not all elements of a DER/DEAR will have been subject to interconnection screening/studies—in particular loads at distribution level that might be comprised of aggregations of individual elements such as car chargers, water heaters, etc. when they were initially interconnected. Is this a gap in that aggregations comprised solely of loads, or aggregations of loads with sources of more direct energy (though still loads at some points) such as battery discharge, may not have been studied at interconnection?
As explained further below, we think that the reliability studies need to be integrated with other studies MISO performs.
Use Existing Timelines & Processes to Extent Possible to Create ‘level’ Expectations for resources at all interconnection levels
Because the focus of the studies is primarily the reliability of the system (rather than the interconnection of large generators), it would be useful for a MISO work group, perhaps the Planning Subcommittee and the DERTF together to work on an integrated timeline for Affected Systems Studies. To the extent possible, evaluating DER/DERAs and changes thereto, should be done on a timeline that exists for studies presently undertaken by MISO. Adding in additional layers of complexity by developing new, stand alone, study processes has the potential to create gaps in both the DER/DEAR studies and AFS for other types of resources and loads. Moreover, there will need to be tight coordination between MISO, the TO, and the reliability study arm of the EDCs—so the timelines need to be developed with that in mind.
On slide 18, MISO notes that its reliability reviews will be quarterly. This seems reasonable, but it may not flange up perfectly with the FERC timeline requirement. It also seems like there may be an opportunity—depending on the initial screening results, for MISO to request the TO/TP to do the reliability study because the TO/TP has access to the information required for system protection studies.
Is it the case that all elements of a proposed aggregation have gone through an interconnection study as MISO seems to indicate?
One of MISO’s points in the 1/22/24 meeting was that to be part of an aggregation, components of a DER/DEAR had to have already gone through an interconnection study process. We think it would be valuable to understand the types of studies, if any, done during interconnection of various types of technologies that could comprise a DEAR. For example, does demand response when used in conjunction with DER generation go through an interconnection study? If not, should there be different considerations for entities that may have already gone through an interconnection study to connect on the distribution system?
EDCs to study DER/DEARs first then TOs?
After the EDC studies the aggregation, TOs will need to study all of the DER/DEARs that include demand response due to the potential islanding of generation that may not trip off. This will require coordination between the EDC and the Transmission Provider.
Outcomes of the EDC Review process (slide 10)
We suggest that conditional approval should not be an option. A resource either is, or it is not, able to operate in a reliable manner in the proposed aggregation. Moreover, any limitations on operation need to be managed by the aggregator not by the EDC, TO or MISO. At all times, DERs/DEARs should be subject to compliance requirements for market participation and following basepoints. MISO’s proposal for conditional approval seems like it would require multiple scenario studies on the part of the EDC, TO and MISO. There should be a stakeholder discussion on what constitutes a single study vs. multiple studies, and the expectations and costs around this. This issue will become more important as aggregation elements change and, or, if multi-node aggregations would ever be considered.
TO DER/DEAR Studies (Slide 17)
What is the difference between “TO DEAR screening failed” and “TO Study Impacts” in the DER AFS process (slide 17)? Is this attempting to capture differences between interconnection of DERs and any DEARs operating together?
Cost Allocation
ITC supports allocating upgrade costs on the TO system through their Attachment O (or a mechanism similar to Attachment FF rules). For upgrades on the EDC system this is best left to each EDC to determine.
In regard to feedback request 1 (slide 8), NIPSCO prefers Option 2 which allows greater flexibility in choosing how 60-day EDC reviews are conducted.
AES Indiana (AESI) appreciates the opportunity to comment on the MISO proposed additions to FERC 2222 compliance presented.
Regarding the Options noted on Slide 8 of the January 22 EDC workshop presentation, AES Indiana supports Option 2. Our current process, for single DER applications, includes first checking eligibility in the initial review and validating the applicant meets all eligibility requirements. Once we determine that eligibility has been met, the reliability/engineering review happens directly after. For smaller level 1 and 2 applications in the AESI footprint these two steps are often completed almost in parallel since these size systems typically have minimal impact on the circuit. In contrast, for larger level 2 and 3 applications, the AESI team often requires a more complete and detailed analysis of the impact on the circuit and system.
Regarding the Options noted on Slide 21 of the January 22 EDC workshop presentation, AES Indiana understands and appreciates the focus on utilizing cost causation principles as the starting point for consideration. AESI would like to suggest the potential opportunity to blend Options 1 & 2 in a phased approach. By utilizing the more straightforward, less burdensome Option 1, load and entities benefit from expeditious determination of cost allocations and transparency in the results. Option 2, while more burdensome from an analytical standpoint, correctly assigns costs commensurate with system impact. AESI believes this is the most fair and equitable treatment. Though, in addition, we advocate for an approach that implements Option 1 while the wholesale market participation of DEARs is “new” and then a move to implement Option 2 when the market is "less new" for DEARs. To explain further, the timing of this switch could either be time-based, participation-based or total cost-based determination. After a pre-determined set of years, participation level, or total cost caused is reached, the cost allocation method would switch from Option 1 to Option 2. The mature market, like that of the existing transmission interconnection queue of large wholesale generators, will benefit from the use and availability of more granular cost allocation to properly inform potential participants of risks and opportunities.
Finally, with cost allocation Option 2, AESI would ask MISO to better enumerate the entity responsibilities for completing the work to prepare information needed to identify impact contributions caused by aggregation.
AES Indiana does not have any specific comments at this time regarding the conceptual proposals through the January 22 presentation, but reserves the right to make comments in the future prior to MISO’s compliance filing in April.
DTE Electric appreciates the opportunity to provide feedback on the Order 2222 Reliability Reviews. MISO requested feedback on 3 items
1. Options for meeting the 60 calendar day requirement for EDC Reviews (Slide 8)
2. Options for cost allocation (Slide 22)
3. Conceptual proposals throughout today’s presentation to be considered for tariff language development (bold language throughout deck)
WPPI’s responses to the specific points in this feedback request following the Electric Distribution Co. Workshop, 1/22/2024 are as follows:
The OMS Distributed Energy Resources Work Group (DERWG) provides this feedback to MISO on DER reliability reviews. This feedback is from an OMS work group and does not represent a position of the OMS Board of Directors.
60-Day Calendar Requirement and Placement of RERRA Review
The OMS DERWG supports MISO’s proposal to sequence the RERRA eligibility review after the EDC eligibility review is complete. As verbally described during the workshop, this process envisions that the RERRA review would occur on Day 11 of the 60-day EDC review process. Sequencing the RERRA eligibility review after the EDC eligibility review is logical because the RERRA does not have firsthand access to customer account information, tariff information, etc. to enable it to complete the review without coordinating with the EDC to acquire the relevant information.
Using DR aggregation today as an example, while the RERRA confidentially receives DR registration information directly from MISO, the RERRA does not itself have access to the level of information needed to determine the DR/DERs eligibility to participate and must therefore reach out to the EDC for this information as it conducts this review (for example: what retail tariff the customer might be on, what that account’s peak load might be, what customer class the account represents, etc.). Since the EDC will have already conducted its own eligibility review at this point, the information should be readily available to the RERRA. Since both the EDC and the RERRA are working from the same information and presumably through established guidance from the RERRA ahead of this stage, it is unlikely that the RERRA will come to a different conclusion and reject large portions of the DERA at this point necessitating an EDC restudy.
Note: The DERWG believes it is critical to point out that this circular information problem could be avoided by the creation of a single data and information sharing platform to allow all entities involved in the registration process to securely access relevant information. CUS’s DER Registry is one such example as mentioned in previous feedback. If this information/data exchange problem was resolved in such a manner, it would alleviate this problem and eliminate the current sequencing concerns, and the RERRA would be able to conduct its review without necessitating direct coordination with the EDC.
Cost Allocation Options
The OMS DERWG does not have a strong preference between the three cost allocation proposals at this time but requests additional information about the complexity and any additional cost of pursuing Option 2. As MISO notes in the slides, Option 2 seems more accurate for cost allocation purposes, but this advantage should be weighed against the inherent complexity and additional costs.
The OMS DERWG appreciates MISO’s statement that this DERA reliability review envisions coordination streams that may not exist today. As this proposed process is structurally similar to the DER AFS process, similar TO-EDC coordination and communication needs to occur before and during implementation, including the potential creation of billing systems to handle study deposits or system upgrades. Since DERs are functionally part of the local distribution system, RERRAs may also need to provide cost allocation guidance to their jurisdictional entities.
As such, the OMS DERWG encourages MISO to be precise in its language when crafting its compliance and keep the entirety of the coordination effort and associated complexity in mind. Based on verbal stakeholder feedback during the workshop, it may also be helpful to clearly delineate the roles and functions of each entity for both the DER AFS process (impact of individual DERs interconnecting) and this DERA Reliability Review (impact of aggregated DERs). Something like a MISO one-pager on these processes may be helpful guidance, in addition to the language in the Tariff and BPMs.
Conceptual Proposals throughout Presentation to be considered for Tariff language development (bold language throughout deck)
Per Slide 12, the DERWG supports MISO acting as the data/information exchange conduit to share information about the results of the EDC reliability review. This is another area where a single platform (e.g., DER Registry) could be helpful.
Consumers Energy appreciates the opportunity to provide the following feedback on the MISO workshop:
It was helpful to understand that this entire process is predicated on a complete and active distribution interconnection. Clarity on that point would be welcome in the revised tariff/BPM updates.
It is not clear whether MISO will be reviewing these applications for completeness/correctness and whether there may be an iterative process to resubmit applications until they are ready to be processed.
It is not clear who will be responsible for collecting fees. Consumers Energy feels MISO should collect fees during its application process and pay out individual utilities for the studies performed, similar to the MISO interconnection process in place today. This would avoid delays in the process to stop and gather payment.
It is unclear when the review process starts. Consumers Energy believes the review window should not begin until after payment and a complete application are received.
There is an assumption that an aggregation will pass or be allowed with modifications. There is no path for an aggregation that is simply not possible and should be denied.
Consumers Energy does not believe it should be the responsibility of the EDC to recommend modifications (i.e. reduced aggregation which avoids reliability concerns). This increases study complexities which may be impractical to complete in the required timeline.
It is not clear that aggregations should remain within a single EDC.
Thank you,
Consumers Energy Team
Xcel Energy appreciates the opportunity to provide feedback regarding the Reliability Review as presented at the EDC Order 2222 Workshop on January 22, 2024.
Regarding the sequencing of eligibility and reliability presented on slide 8 at the 1/22/24 EDC Workshop, we prefer option 2: EDC defined sequencing of eligibility and reliability. This would allow the RERRA review to occur following the EDC eligibility review but concurrently with the EDC reliability review, if the EDC so chooses. We also encourage the states to consider approval of the LSE eligibility review PROCESS (with random audits) instead of reviewing each DEAR to improve the efficiency of the process.
We believe the potential outcomes of the EDC review process need to be aligned with the EDC process, not with DERA decisions regarding the EDC decision. As such, the potential outcomes should include approve, approve with transmission impacts identified, or deny. Denial would include (1) Missing information required to evaluate the eligibility and reliability of the DEAR (such as listing the Market Services that the DEAR is expecting to provide); (2) Lack of completed interconnection studies for all of the DER comprising the DEAR; and (3) violation of eligibility and/or reliability criteria. All of these would stop the 60 day clock and require a subsequent DEAR submission for another EDC review (with a new 60 day clock). The EDC will not know if the DERA withdraws the DEAR so that should not be an outcome of the EDC process. If MISO continues to use the "Conditional Approval" as an EDC outcome, MISO is responsible for enabling the communication from the EDC to MISO to identify the DERs that need to be removed/revised and ensuring that the DERA makes the appropriate adjustments to the DEAR. This aligns with the proposal that MISO will notify the DERA of eligibility review criteria violated. MISO should also notify the DERA of the reliability review criteria violated.
We agree with MISO that the Transmission reliability reviews occur outside of the 60 day window allotted for the EDC eligibility and reliability review and to retain the Reasonable Efforts language regarding that review. Regarding MISO's interpretation that the EDC reliability review cannot be paused, we note that there could be extenuating circumstances, such as large volumes of DEAR registrations occurring at one time, that may require a pause. We agree with other stakeholders that LMR annual registration will increase the number of DEARs to review prior to the LMR registration deadline which could create a substantial volumes of DEARs to evaluate at one time.
EDC Workshop Feedback: Order 2222 Reliability Reviews
February 5, 2024
In the January 22, 2024, Electric Distribution Company (EDC) Workshop, stakeholders were invited to submit feedback on EDC, Transmission Owner (TO), and/or MISO Distributed Energy Aggregated Resource (DEAR) reliability reviews. Specific points on which feedback was requested include:
MISO is retaining the initial filing proposal that the DEAR review will automatically result in approval should the 60 day review period end prior to the reviews concluding. Tariff changes will be proposed for the selected option.
The Entergy Operating Companies[1] provide the following feedback on these items for MISO’s consideration:
1. Options for meeting the 60 calendar day requirement for EDC Reviews (Slide 8) PP 265
Entergy also supports open timeframes for the EDC to manage its own review process, but to support efficiency, Entergy prefers a structure where the Eligibility Review is completed by both the EDC and the RERRA prior to performing reliability reviews of the DERA. This approach will avoid unnecessary engineering studies and the cost associated with them.
The Reliability Review is a more time-intensive and process that is more costly for the Market Participant and is not necessary if the asset is not eligible to participate in an aggregation or the Aggregation is not permitted under the relevant retail regulatory construct. Therefore, Entergy favors this approach.
For the reasons stated above, relating to the efficiency of the review process, Entergy does not support either having parallel processes for Eligibility and Reliability or performing the Reliability Review prior to the confirmation of eligibility.
2. Options for cost allocation (Slide 21) PP306
Options for cost allocation resulting from identified impact during the reliability review
Entergy tends to agree with MISO that Option 1, assigning costs to each DEAR at a given substation with identified impacts based on capacity-weighted ratio, appears to be a less complex approach to cost allocation. Entergy suggests that MISO also include language noting that cost allocation is subject to Retail Regulatory rules.
3. Conceptual proposals to be considered for Tariff language development
Proposed timing of RERRA Review (slide 9)
Entergy suggests that requiring the RERRA eligibility review prior to the EDC review would be most efficient.
Eligibility Criteria (slide 11)
MISO has suggested defining eligibility as confirming that the aggregation or the assets included in it are not “double counting” their participation in both Retail and Wholesale markets (unless permitted by the RRERA) along with "Accuracy of location and data components that represents each Component DER, as further defined in the relevant Business Practice Manuals."
While Entergy agrees with MISO that if an aggregation includes incorrect locational information and data would not be eligible to participate in MISO markets, we suggest that it also include an assessment of the participation requirements and limitations of the RRERA.
MISO is proposing an initial deposit amount of $60,000 per DEAR identified as causing a potential MISO system impact, consistent with the per substation amount for DER AFS, and noted that FERC directed “MISO to explain how this would not create undue barriers to entry for distributed energy resource aggregations, as required by Order No. 2222”
It is not clear from the presentation how the proposed approach is consistent with the DER AFS, which assigns costs by substation, not by asset.
[1] The Entergy Operating Companies are Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, Entergy New Orleans, LLC, and Entergy Texas, Inc.