DERTF: Filing Framework Document – Iteration 6 (IR070) (20211129)

WPPI offers the following feedback on the questions posed by MISO re iteration 6 of MISO’s FERC O2x4 filing framework (DERTF, 11/29/2021):

(1)     DEAR (Distributed Energy Aggregated Resource) deliverability for MISO capacity market participation proposal

(a)     Is the proposed method for determining deliverability sufficient?

The proposed method for determining deliverability seems sufficient. Namely, deliverability will be met thru coordination between the aggregator and Electric Distribution Co., with the EDC coordinating with the Transmission Owner or MISO as needed.

(b)     If not, what other methods should MISO consider for DEARs to demonstrate deliverability in order to qualify for the capacity market?

Not applicable

(2)     Operations coordination framework proposal

The operations coordination framework seems reasonable. WPPI notes that the Electric Distribution Company (or EDC’s agent) determines whether communications will be between the EDC and the aggregator or between the EDC and the Distributed Energy Resource(s) in an aggregation, and the EDC will determine the method of communication.

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(3)     Registration coordination framework proposal

• Overall, the registration coordination framework proposal seems reasonable.
• S. 110 Enrollment of a DERA: Potential Timeline (1)

‒         “LBAs double counting check” and “RERRA double counting check”: It would be helpful to be more specific about what the LBA and RERRA are each checking.

‒         “EDC reliability review”: In addition to the reliability review, WPPI would expect the EDC to confirm DER(s) included in the proposed aggregation are not already included in another aggregation, unless this is already being checked by MISO (is this already being checked by MISO?). WPPI would also expect the EDC to address any eligibility issues not addressed by the RERRA.

Electric on Order 2222 Filing Compliance Framework Iteration 6 In response to Feedback Request from 11/29/21 MISO DER Task Force

FERC Order 2222 Filing Framework Iteration Six

DTE is pleased to provide the following feedback on various aspects of MISO’s latest filing framework for compliance with Order 2222.  The responses below address various questions and feedback requests raised by MISO.  MISO’s questions and proposals for feedback are captured in blue type face and DTE’s responses are labeled as such. 

1. Is the proposed method for determining deliverability sufficient? If not, what other methods should MISO consider for DEARs to demonstrate deliverability in order to qualify for the capacity market? (Slide 66)

DTE Response: Although the proposed method seems to be sufficient, we note that EDC aggregation review processes may make this step redundant.

2.  Feedback on registration and operations coordination framework proposal (Slides 106-116, 130-131)

Slide 107 – Changes to interconnection requirements or metering must be completed and verified prior to Step 20 at the end of the enrollment modification process. A clear verification step needs to be included.

Especially given the new “recommended” designation, the pre-enrollment process outlined in Steps 4-7 should be removed from the diagram. Step 11 needs to break into multiple steps that discussed in detail on page 110. The multi-step process laid out on page 110 needs to be detailed in the overall process and included on page 107.  We’d like MISO to fully understand that EDC or RERRA are not interested in conducting technical analysis or compatibility reviews prior to the official initiation of DERA on any DEAR’s enrollment requests. Reviews, analysis or communication prior to DEAR’s enrollment request and MISO’s reviews of DERA request can incur unnecessary costs from our ratepayers, which are clearly not in the best interest of the customers we serve. In addition to that, we don’t believe MISO is in the position to make the recommendation of such a pre-enrollment process (including “may want to study”). It should be left to states to decide whether such pre-enrollment is in the best interest of customers. EDC’s obligation on aggregation review is being specified by FERC and happens after enrollment requests are initiated by DERA.

Page 108 – please remove the aggregation formation step, which incur unnecessary costs to utilities and RERRA, and are not in the best interests of EDC customers.

Slide 110 –We also note that allowing the future system to provide open access to data included in the enrollment process, such as attestations, to stakeholders including the DERA, LBA, RERRA, EDC, and MISO may help streamline reviews across these entities.

LBA double counting check needs to be adjusted to LSE/EDC double counting check. We believe LBA is a typo. Please clarify and confirm.

Slide 111 – Beyond interconnection approval, there should be verification step with EDC to ensure that the required modifications have been completed, that resources have been successfully commissioned, and that they are authorized for parallel operation.

Given that enrollment process is new and will create unanticipated challenges and complexities, we do not believe that auto-approval (“no response” will move the request forward) is appropriate. Applications with inaccuracies or other issues may require additional communication that will exceed the original 60-day timeframe or cause the clock to restart and should not be automatically approved.

 Slide 112 – Step E should still be completed when assets are deleted from a DEAR so that utilities can get informed and re-assess the availability of system capacity. If a system is constrained, there may be other participants queued and waiting for availability.

Furthermore, Step E should be allowed the full 60 days for review. The request may move forward faster than the allotted time, but the full period of 60 days should be given.

 Slide 115 –In contrast to the existing depiction of swim lanes, it may be prudent to break out additional “Dispatch Agent” and “Market Agent” roles. PJM is adopting a model that clearly defines the roles of Dispatch Agent and Market Agent and provides utilities with the first right of refusal to act in these roles on behalf of DEARs. DTE would like the flexibility to act as a dispatch agent, particularly for DEAR comprised of large DER resources capable of impacting grid safety and reliability. In cases where DEARs are not considered impactful to grid safety and reliability, we may allow DERAs to take on the dispatch agent role. We would like MISO to consider adopting the PJM model that defines these functions and provides utilities the ability to perform them.

 Slide 116 – The arrows among MISO, TOP/LBA, EDC, DERA and DERO on reliability actions and operating instructions need to be clearly specified. For instance, 1) a communication pathway needs to exist between EDC and DERO’s on operating instructions independent of any state-defined frameworks that allow direct communication between DERA and EDC. 2) when TOP/LBA issues manual reliability actions, are they expected to communicate back to MISO and DERA, or are they expected to communicate to the EDC, particularly given the communication between EDC and DERA doesn’t exist today and in some states may never exist?

In considering the EDC as Dispatch Agent model, the operating instruction will be between EDC and DERO, instead of DERA and DERO. A new swim lane called “Dispatch Agent” needs to be specified and DERA will be re-branded as “Market Agent”.

Slide 131 – Before any changes are made to the allowed frequency of aggregation modification, input should be solicited from utilities and state regulators. It is not clear whether utilities will have the resources to support more frequent re-reviews.

3. How might dual participation in retail programs and MISO markets be tracked to prevent double counting in Settlements? (Slide 88)

DTE Response: It isn’t clear how the DERA will be able to collect meter data for only wholesale activity and provide it to MISO. Furthermore, first excising data for wholesale transactions will require additional effort toward reconstituting data to get a complete picture of DEAR activity and to prevent double counting.

TO: MISO DISTRIBUTED ENERGY RESOURCE TASK FORCE
FROM: THE ENTERGY OPERATING COMPANIES
SUBJECT: FERC ORDER 2222 FILING FRAMEWORK – DISTRIBUTED ENERGY AGGREGATED RESOURCE (DEAR) DELIVERABILITY FOR MISO CAPACITY MARKET PARTICIPATION, OPERATIONS COORDINATION FRAMEWORK AND REGISTRATION COORDINATION FRAMEWORK
DATE: DECEMBER 13, 2021

The following feedback is offered by the Entergy Operating Companies ("EOCs")[1] in response to the request made during the November 29, 2021 Distributed Energy Resource Task Force (DERTF) meeting concerning the FERC Order 2222 filing framework and the related topics of Distributed Energy Aggregated Resource (DEAR) deliverability for MISO capacity market participation, operations coordination framework and registration coordination framework. 

Distributed Energy Aggregated Resource (DEAR) deliverability for MISO capacity market participation proposal

• The EOCs are in agreement with MISO’s proposal concerning DEAR deliverability.  In that, the Distributed Energy Resource Aggregator (DERA) should coordinate with the Electric Distribution Company (EDC) to determine potential impacts to the distribution system.  If no impacts are identified, then the DEAR deliverability would be the sum of the parts of the underlying DERs and DER groups within the DEAR.      

Operations coordination framework proposal

• In response to MISO’s operations coordination framework proposal, the EOCs reiterate our previous comments which stated that coordination activities and any changes needed to the EDC systems and processes as a result of compliance with Order 2222 should be driven by the Relevant Electric Retail Regulatory Authority (RERRA), as well as the individual EDC and its interconnection agreement with the DEAR/DERA.  The EOCs’ EDCs have and will continue to provide a range of operation for DERs/DEARs under the interconnection process.  Therefore, it is anticipated the EOC EDCs will not need to be involved with day-to-day coordination activities under normal operating conditions.   
• Currently, and as we move forward under Order 2222, the individual EOC EDCs reserve the right to disconnect any interconnected DER/DEAR at their discretion to preserve the reliability of the Distribution Network.  If these actions became necessary, they would be done so consistent with our interconnection requirements, the interconnection agreement in place, and policies and procedures approved by the EOC EDCs’ respective retail regulators.    

Registration coordination framework proposal

• The EOCs have been participating in and working with other EDCs as a part of the EDC Coalition.  As such, we are in general support of the EDC Coalition’s recommendations concerning enrollment processes, handoffs, and associated timelines.
• The EOCs request that MISO provide clarity on what would restart the 60-day clock in the EDC review process.  For example, since MISO is relying on the attestation of the Market Participant, the EDC may receive incomplete information and/or the Market Participant might not meet the EDC’s requirements.  If so, would the 60-day clock restart? 

The EOCs appreciate the opportunity to comment

DEAR Deliverability

The OMS DER Work Group recognizes that coordination between the DERA and EDC is important and necessary and will likely interact with state authority. OMS acknowledges this issue and looks forward to engaging in the coordination framework discussion at an upcoming IPWG meeting.

Operations coordination framework

The OMS DER Work Group would like to suggest that MISO add a separate line for RERRA coordination that illustrates where MISO thinks RERRA action may be needed. One area, as referenced above, may be setting up communications between the DERA and EDCs to ensure that each entity has the information it needs to operate the distribution system in a reliable manner. The OMS DER WG recognizes this may be a state-by-state determination, but thinks it is important to include potential RERRA roles in order to fully represent all interactions on a single chart. Including all interactions (both mandatory and suggested) will also help inform stakeholders and RERRAs of any gaps in the operational coordination process.  

Registration coordination framework

The OMS DER Work Group appreciates Slide 108 where MISO outlines processes where MISO is not involved. Slides like these help RERRAs focus their attention on potential gaps that fall outside of the MISO process and will help individual RERRAs make decisions regarding any insufficiencies.    

Regarding Slides 110-112, the OMS DER WG would like to ask what MISO envisions for the RERRA double counting check. Would this include a review of any retail tariffs the DERs may be enrolled in and a verification of whether that resource, particularly dual use resources, may participate in MISO’s markets? If so, it may make sense for the “RERRA double counting check” to occur simultaneously with the last ten business days of EDC reliability review, or directly thereafter. Generally, RERRA’s do not have access to individual customer data, therefore, in order to perform the double counting check the RERRA would need to confidentially acquire this data directly from MISO or through the EDC. (This also applies to DR aggregation today.) Having the “RERRA double counting check” occur simultaneously with the EDC reliability review may be ideal, as it is likely the RERRA will need to coordinate with the EDC regardless. The OMS DER WG suggests MISO explore moving the “RERRA double counting check” or further explain its reasoning for its current placement. We would also like to note that the RERRA placement may also depend on what is covered in the LBA (which should be the LSE?) double counting check and the level of interaction between the LBA/LSE and RERRA at that stage.

MISO Distributed Energy Resources Task Force (DERTF)

Ameren Response to MISO's Iteration 6 of FERC Order 2222 Filing Framework

Questions from MISO:

• What enhancements do stakeholders foresee for their policies, processes, and systems, based on known Order 2222 requirements?
• What is the required timeline for those enhancements?

Additional Note Included in our Response:

We are currently undergoing a comprehensive and detailed review of our processes, procedures and systems, and would appreciate the opportunity to provide additional information to MISO upon completion of the review. We anticipate completion of this review by mid-January 2022 and will provide any additional considerations by January 31, 2022.

Policies, Processes, and Systems Requiring Enhancements for FERC 2222:

• DERMS Selection and Implementation
• ADMS
• AMI
• 15 minute interval capabilities for Delivered/Received energy.
• Energy from PV Solar customers stored in "Received Energy Register."
• Load profile channel data sent via AMI Network to AMI Head End every 4 hours then to MDMS for billing and analytical use.
• Register values sent once per day (between midnight and 4am) to Head End system then to MDMS. 
• MDMS validations must be run before the data can move to CSS for billing.
• Settlement Systems
• Registration System – At this time we intend to use EDI for communication of switching-related and usage-related information between Ameren, the ARCs/DERa, and MISO.
• GIS

• DSM Regulations
  • There may be required changes to DSM regulations as well.
  • Load Forecasting
    • Until we know what type of information we might receive we cannot fully understand the DER impact on our load and load forecasting.
    • Customer Interactions/Satisfaction.
    • Asset Management.
    • Outage Management.
    • Administrative Rules (not an assurance in both Missouri and Illinois, but just as likely as not.)
    • Retail Tariff modifications to both enable participation and prevent duplicate compensation.
    • Development of Demand Side Management Tariffs.

Timeline Requirements:

• Regulatory Process
  • Administrative rule changes, if needed, would potentially require years of workshops and filings for both us and for the Missouri Public Service Commission and the Illinois Commerce Commission.
  • Some modifications aren't possible except during rate cases which may not happen instantaneously after the MISO tariff is final.
  • Retail tariffs will have to be changed, which cannot be done until the MISO tariff/processes are final.
  • Once our retail tariffs are changed, we will then need to iterate through changes in our demand side management tariffs. 
  • AMI Meters
    • Not fully deployed in Ameren Missouri prior to 2025.

Joint Comments of AEEand NRDC to MISO DERTF are sent in a pdf file to stakeholder relations

WEC Energy Group does not believe the proposed method for determining DEAR deliverability is sufficient because it is not comparable to the deliverability requirements of other resources that inject power into the transmission system. DEARs with the potential to inject power into the transmission system (DER aggregation exceeds the load at the EPNode) should have the same deliverability requirements as External Resources. External Resources are required to demonstrate either firm Transmission Service to a Load within an LRZ or external Network Resource Interconnection Service.

The proposed requirement for the EDC to determine the impacts of a DEAR on the transmission system is inappropriate because the EDC does not have the authority, expertise or modeling capability to determine impacts on the transmission system. Similar to External Resources, DEARs that inject power into the transmission system should obtain either firm Transmission Service or external NRIS through the Transmission Provider (MISO).

Xcel Energy provides the following feedback to MISO regarding the registration coordination framework proposal (see email to stakeholder relations).