IPWG: Requirements under FERC Order 2222 (20210316)

Muscatine Power & Water has reviewed the IPWG document for FERC Order 2222 and has no questions at this time.

The Organization of MISO States’ Distributed Energy Resources Working Group (OMS DERWG) and Transmission Planning Working Group (TPWG) appreciate the opportunity to submit the following comments in response to MISO’s feedback request regarding its Order 2222 overview to the IPWG and input on the initial question set. This feedback does not represent the position of the OMS Board of Directors.

1. Meeting Intent and Goals of Order 2222: First, the OMS DER WG and TPWG would like to note what FERC highlighted in Order 2222 regarding interconnection - that RTO/ISOs market rules often limit the services that DERs are eligible to provide, including imposing prohibitively expensive or otherwise burdensome interconnection requirements. OMS DERWG and TPWG would encourage the development of any additional MISO interconnection processes to ensure that it is not unduly burdensome or creates barriers to distributed energy resource aggregation (DERA) participation in wholesale markets.  Additionally, as noted by some commenters in the Order 2222 docket, it is important that both MISO’s and the states’ interconnection processes be evaluated to ensure that neither process creates undue barriers and that they continue to ensure reliable and safe distribution system operations. The OMS DER WG and TPWG acknowledge their role in this work via our state interconnection processes and the continued work required by our respective states.
2. Both State and MISO Interconnection Process Transparency: As FERC recognized, the state-based interconnection process is crucial in the success of Order 2222, largely in three major process steps – first, in ensuring the individual distributed energy resources are initially interconnected in a safe and reliable manner, second, that any creation of a DERA, is evaluated in a timely and robust manner to ensure distribution system safety and reliability, and third, details on when a DERA may change its composition. OMS DER WG and TPWG encourage a clear and transparent processes for each of these three steps, as needed, at both the state-level and at MISO.
3. MISO Process for State-Based Interconnection Required Affected System Study: The OMS DERWG and the TPWG encourages MISO to establish a clear process for when a state interconnection process identifies a MISO-controlled transmission system as a potentially affected system. This process should include: procedures for notifying MISO, steps and information (including timelines) that must be provided to MISO to coordinate and jointly-study the impact, dispute resolutions processes, any other processes needed to ensure clarity and transparency, and clear delineation in the process guidance of what information will be able to be provided to the distribution utility, the DERA, and the RERRA (what information may be protected or trade secret).  The amount of information and study results will be important to state regulators in resolving disputes and potentially the assignment of associated costs.
4. MISO State-Interconnection Affected System Screens: MISO noted that screens based on some metrics (DER-size, affected system impact etc.) may be used, while we support the development of these screens, first priority should be put on process, and if time and bandwidth allow between now and April 2022 – screening discussions should be started, but not hold up the development of a clear process.
5. Input on MISO Questions Set: At a high level, it is crucial that during interconnection/interface discussions terms and words are properly defined from both a MISO and state perspective to ensure there are not double meanings; many terms used at MISO are also used in state-based processes and the terms or words have wildly different meanings in each context.
6. Non-Order 2222 DER Interconnection and T/D Processes: While noted in the March 16 presentation on Slide 9 that “DER’s will connect to the distribution system and participate only in retail programs, but may inject power onto the transmission system” is ‘beyond the scope of Order 2222’ the OMS DER WG and TPWG recommend that this conversation and work should commence at the IPWG outside of the Order 2222 process. While we agree this is beyond the scope of Order 2222 itself, it is anticipated that the Order will likely spur retail programs and potentially these issues at MISO. Additionally, with the increase in potentially both wholesale and retail program DER penetration – it will be important to have established processes that complement each other and do not create incentives or disincentives to use a retail or wholesale program options based on potentially diverging interconnection implications at the RTO-level for similar resource types.
7. MISO Input on DER-Aggregation Formation Needs: At the time of registration as a market participant, and formation of a DERA, Order 2222 indicates that distribution utilities, with RERRA oversight, will review the effects of the (aggregate) DERA on the distribution system; however, that time period is noted to ‘not to exceed 60 days’. This results of this DERA review may have impacts on individual DER interconnections, which would then require coordination at the state level to remedy that interconnection. MISO and stakeholders should discuss what information is needed to consider a DERA’s impact (DERs interconnected individually but operating in tandem), and how that process will need to consider potential new state-based interconnection process-triggered affected system studies, and what process (and timeframe) will need to be coordinated and how it would, or would not, fit within the 60 day review period.

The OMS DERWG and TPWG also recognize that an expedited review process is likely appropriate for updates to existing DER aggregations. Presumably, and subject to the scope of the update, there will be minimal reliability impacts when removing/adding to an existing aggregation. However, for clarity, accuracy, and ease of tracking registrations, the same information that the DERA submitted upon initial registration should be required to be resubmitted when updating the aggregation. (for both existing resources and additions) This will allow the RTO/RERRA/distribution utility to see what resource is being removed/added to verify the retail rate the resource may be under, ensure that participation is not precluded by that retail tariff, and verify the new customer information. The OMS WGs expect that requiring such information to be resubmitted would not place an undue burden on the DERA, as such registration information should be readily accessible and updated on an ongoing basis.     

8. Cost-Causation: MISO has included in the set of questions one question on the assignment of cost for any needed network upgrades. The OMS DER WG and TPWG assume there may be costs associated with several facets of a DER interconnection process depending on the results of the system impact studies (both distribution-level and at MISO) including: 1) distribution system upgrades (upgraded transformers or lines), MISO-controlled transmission network upgrades (BES Network Upgrades), as well as general distribution-utility technology improvement costs (increased communication systems, ADMS, DERMS, or general distribution upgrades). Each of these categories are costs that historically have been reviewed at state Commissions and they are anticipated to continue. Due to the interrelated nature of these potentially DER or DERA-related system upgrade needs, the interrelatedness of these upgrades with the on-going general distribution advancements and system improvements, and the likelihood of future distribution level solutions (non-traditional solutions or non-wire alternatives) to mitigate potential bulk-system network upgrades, it is assumed the state would continue in its role of regulating interconnections with the distribution system and over the distribution utility and ensuring distribution-utility related costs are prudent. The OMS DER WG and TPWG assume who bears any additional system costs will be managed through the states and each state’s interconnection process and procedures.   

9. General Input on Order 2222 Issues and Stakeholder Meetings: Provide additional transparency on a comprehensive Order 2222 topic and issues using a Gantt chart format; as issues arise in multiple MISO stakeholder committees – it is important that advance and cross-notice is provided between stakeholder groups.

The OMS DER WG and TPWG encourage robust discussions at the IPWG about all of the items listed above.  

Xcel Energy is submitting its comment in PPT format.  Each slide represents one of the questions raised by MISO

March 16, 2021 IPWG DER Interconnection Requirements Under FERC Order 2222 Entergy Operating Company Feedback

March 30, 2021

In the March 16, 2021 meeting of the Interconnection Process Working Group (IPWG), stakeholders were invited to submit feedback on MISO’s initial responses regarding DER Interconnection Requirements under FERC Order 2222 and to provide any additional questions.  The Entergy Operating Companies provide the following feedback for MISO’s information and consideration.

MISO Questions on Interconnection Process arising from Order 2222

·  How different requested interconnection size may impact the process; max size threshold, etc.

o   Each of Entergy’s five jurisdictions have net energy metering (NEM) rules that apply to generator interconnections on distribution, and each has different NEM generator size limits.  The highest size limit is in Arkansas, which recently increased their maximum NEM generator size to 20 MWAC.  Under its NEM rules, Arkansas also permits customers to install “remote generators” that have no associated electric load and interconnect those remote generators to the distribution system. 

o   Under Entergy Services’ distribution system interconnection standards, bi-directional metering capability is required, but the need for bi-directional NEM meters is being replaced by AMI.  Generally speaking, any proposed generator above 20 MW would fall outside of Entergy’s Services’ distribution system interconnection standards.  A resource larger than 20 MW seeking to inject energy must interconnect on the Transmission System, but technical and physical limitations may apply to resources under 20 MW seeking to interconnect on the distribution system.

o   Entergy’s five retail regulators specify certain procedures, processes, and parameters (e.g., fees, timing, etc.) under their respective NEM rules regarding customers seeking to interconnect generators to the distribution system.  If the proposed generator in question does not fall under the regulator’s NEM rules, Entergy Services’ distribution system interconnection standards would govern the interconnection. 

·   Parties that need to be included in the coordination – noting that the TO role is not specified in the Order

o   Presently, interconnection requirements apply to resources that are intended to run in parallel with the distribution regardless of whether they will be injecting energy to the grid.  In the future distribution interconnection requirements may also need to provide for potential injection by participants such as commercial electric vehicle fleets. 

o   The Transmission Owner (TO) role is coordinating with the DO in determining transmission system impacts of distribution-connected resource and notify MISO, as appropriate, of the need for MISO to perform an Affected System Study.

o   DO/TO/Resource Owner must coordinate.  The LSE may also need to be notified for Resource Adequacy or Energy/Resource Planning, depending on the circumstances such as the resource size or DR programs offered by the LSE.  New processes will need to be established to determine the circumstances that would require communication and how that communication would occur (e.g. on a schedule based on timing/MW accumulation, etc.), particularly as participation levels grow.

o   The services that the resource owner seeks to offer into MISO’s markets may drive interconnection requirements, such as metering that is needed for settlement and verification.  Therefore, the resource owner’s intent needs to be known at the time of the interconnection application, and may need to be re-evaluated in the future, if the resource owner seeks to change its participation in MISO’s markets. 

·     Timing Requirements? This question is interpreted by Entergy to relate to interconnection study/request submission timing requirements.

o   Distribution Interconnection study timing requirements differ by jurisdiction.  For example, the Arkansas PSC requires their first step (a Preliminary Interconnection Site Review Request or PISRR) to be completed in 30 days.  That step may trigger further steps like a Feasibility Study or SIS; the timing of which is up to ETR (meaning it is not proscribed, but customers/developers still complain that it takes too long).  In other jurisdictions, the regulator might prescribe that the utility has 45 days from receipt of a complete interconnection application to finish the process and install the appropriate metering so the generator can operate and run in parallel. 

·      High-level screening for transmission impacts?  Who should perform this?

o   The DO/TO should be responsible for evaluating transmission system impacts of a distribution interconnected resource and notifying MISO if affected system studies are needed.

·     If Network Upgrades are needed, how are these documented?

o   Entergy believes that today, this is accomplished a Facility Construction Agreement, and questions whether there is a need to make any changes to the current process. If the TO identifies Transmission System Network Upgrades, the TO would notify MISO as an impacted Affected System. MISO would confirm the need for such network upgrades through an Affected System Impact Study and document the list of upgrades in the Affected System SIS. A Facilities Study would then be performed for each Network Upgrade and the list of upgrades would finally be documented in a Facility Construction Agreement between the parties.

·     Cost responsibility – who has the authority to assign?

o   Under current wholesale and retail tariff provisions, cost responsibility for network upgrades associated with a DER interconnection would be assigned to the resource owner.  Retail regulatory rules prevail on cost assignment for distribution facility upgrades; however, generally speaking and with some exceptions, new rules require that resource owners (customers or 3^rd-party provider) fund any necessary upgrades to allow the interconnection to proceed.

External NRIS – what changes are needed?

Current tariff/BPM provisions apply to transmission-connected resources only; clarification is needed to for the same type of Interconnection Service to apply to distribution-connected resources.  It is also not clear how the deliverability of energy “to the MISO border” that is required to procure External NRIS would be evaluated.  Whether External NRIS can be obtained where the Retail Service Provider does not have a distribution service tariff must also be addressed and clarified.

Order 2222 implicates many aspects of DER interconnection and operation.  In this comment WPPI Energy focuses on the transmission-planning aspects.  It appears to us that it may be helpful for MISO to work with states and transmission owners to develop broadly applicable screening criteria, where these have not already been established, to determine the consultation and transmission-system study requirements that should apply to DER interconnections with differing characteristics.

Advanced Energy Management Alliance

MISO Interconnection Process Working Group (IPWG)

“Questions on Interconnection” Feedback

March 30, 2021

Advanced Energy Management Alliance (“AEMA”) [1] respectfully submits the following comments to the MISO Interconnection Process Working Group (“IPWG”) on the Questions about Interconnection Process arising from FERC Order 2222 that were presented at the March 16, 2021 meeting of the IPWG. 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 recognizes that there are many questions that have been identified related to the interconnection process for DERs and appreciates that MISO is in the early stage of considering these issues. AEMA would underscore that primary focus of Order 2222 is on removing barriers to DER Aggregators (DERA) participation in Wholesale Markets like MISO. A DERA that is registering an aggregation of resources to participate in the market should not be subject to the interconnection process since those DERs have already been interconnected to the system. As MISO considers possible changes to the interconnection process for DERs, MISO should be cautious not to create new barriers for DER and should recognize that participation of DERAs in the MISO Market is a separate issue.

On the specific questions raised by MISO, AEMA would offer the following feedback:

• How different requested interconnection size may impact process? Max size threshold? Etc?

AEMA has suggested to the MISO Distributed Energy Resource Task Force (“DERTF”) that MISO consider utilizing a threshold size for aggregation across multiple nodes. AEMA has recommended allowing aggregation of up to 5-MWs of DERs over multiple nodes while aggregations over 5-MWs would need to be limited to a single pricing node. Creating a hard limit such as this gives an opportunity for Aggregators to collect multiple DERs into a participation model that is located in geographic proximity without creating significant disruptions to MISO system operations. Threshold limits like 5-MWs can be below the actionability of MISO operations when dispatching the overall system but still contribute to the overall performance of grid operations. Having this type of differentiating limit for interconnection could be useful as well.  

As MISO looks at the interconnection process, AEMA would suggest that MISO adopt a similar strategy for determining which interconnection process a distributed level resource needs to go through.

For example, AEMA recommends that MISO establish a maximum DER injection limit from a single resource. This limit could define whether the interconnection is handled locally or by MISO. AEMA suggests that MISO set a maximum injection limit of 20 MW for any single DER (this echoes a similar process in the NYISO). If the new DER has a maximum injection of greater than 20 MW, and desires to participate in the MISO market, then it would need to register as a MISO defined resource (no longer as a DER) and go through the established MISO interconnection process.

Resources interconnecting below the limit would interconnect through the local facility owner per the current processes.

For DERA seeking to participate in the Planning Resource Auction (PRA), MISO should only consider examining deliverability for the portion of the Resource that could physically inject into the system. As an illustration, consider a series of 10-kW batteries attached to 5 kW loads. Capacity credit for serving the specific load that the batteries are attached to should be granted without demonstration of deliverability because the batteries exist at the same interconnect points and can reduce the net load to zero.

Beyond reducing to net the distribution level load to zero, the batteries in this example would also be capable of injecting energy into the system as well. MISO should look at options for determining deliverability that are reasonable for the small interconnection. This could include localized studies beyond full interconnect study. Again, this could be predicated on a maximum size threshold. Perhaps this is 5 MW for an aggregation across multiple nodes or 20 MW of injection from a single resource.

• Parties that need to be included in coordination? TO role is not specified in Order.

Coordination of DERA registrations should include MISO, the Distribution Utility and the RERRA. Given that MISO has the overall NERC responsibility as the Balancing Authority (BA) and Transmission System Operator (TSO), it is reasonable that MISO should facilitate the communications with the Transmission Owner, Local Balancing Authority and Local System Operator as applicable.

MISO should rely on the DERA to certify eligibility of the DER aggregation.

• Timing Requirements?

With the establishment of size thresholds mentioned above, MISO could follow the current timing requirements for those resources that require MISO interconnection approval although an expedited interconnection process for small resources would be helpful.

• High level screen for Transmission impact? Who performs?

As indicated above, MISO should consider establishing size thresholds for DER interconnection and follow a similar process for interconnection that it does today, where only those resources above the threshold move through the MISO process. Those DERs seeking interconnection that are below the threshold, would work through the local distribution utility and RERRA.

• If Network Upgrades are needed how are those documented?

If MISO chooses to modify the interconnection process and establishes size thresholds for the interconnection, any needed network upgrades should follow the current processes, recognizing that network upgrades would not be needed if the DER is only serving to net against existing distribution load. Interconnection and Network Upgrades would only be applicable to situations where a single resource has more than some threshold level of energy injection.

• Cost responsibility? Who has the authority to assign?

As discussed above, cost responsibility would follow similar processes to today, depending upon the threshold point of any interconnect study.

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