PAC: DER AFS BPM-015 Changes (20230426)

Feedback by Public Service Commission of Wisconsin (PSCW) Office of Regional Markets (ORM) Staff to MISO on BPM-015 (DER AFS)

Could MISO further clarify what processes, other than an EDC notifying the TO of the potential need to screen for DER net injection at a substation, MISO expects would trigger a TO to conduct a screen? We are asking because we were surprised by MISO’s comment in the last round of feedback that “MISO’s position is that the TO has the responsibility to coordinate with EDC or to define processes to become aware of when injection occurs at a DER Substation.” The whitepaper indicated that an EDC would provide the TO with information about a potential need to screen and, to the best of our knowledge, did not indicate that TOs would otherwise be responsible for defining processes to become aware of net injection. We maintain that some content clearly describing general expectations of upstream processes of the DER AFS would be helpful in the BPM, although we understand that retaining the entire “Implementation guidance for EDCs and RERRAs” section of the whitepaper would not conform to MISO’s BPM language.   

We understand that MISO does not generally codify review processes in the BPM. Is there another avenue through which MISO could formally commit to reviewing the DER AFS process within a specific timeframe after implementation? Stakeholders still have concerns about the AFS timelines, the level of sensitivity levels used for screens, and the frequency with which small DER projects could result in DER AFS. Furthermore, MISO was not able to offer an estimate for the number of new DER interconnection requests which will likely result in DER AFS, making it difficult to gauge the impact of this new process.

DTE appreciates the opportunity to provide feedback on the MISO DER Affected Systems proposal and BPM-15 redlines.  Though DTE acknowledges the importance of establishing the procedural infrastructure to support the growth and adoption of DERs we are concerned with the pace at which MISO is moving to revise current practices.  We question the urgency around the change and if its commensurate with the rate in which DERs are being injected into the grid.  Given the current DER volumes and rate of adoption, we feel there is opportunity for MISO and stakeholders to put more thought into the process to make for a more seamless transition.  For example, the current proposal adds more layers to the AFS screening, imposes modeling criteria inconsistent with current requirements, and is not aligned with NERC standards. 

Currently, DER coordination is between the EDC and the TO which provides efficiencies in communication between the parties with less handoffs to manage.  The new proposal will include additional screening from MISO, adding another entity to the process.  MISO and stakeholders should work towards streamlining the information exchanges to maintain a manageable turn around for DER customers.  Additionally, the entire process will be 180+ days which seems excessive given the current volume of DERs and will add to the delay in the interconnection timeline for a DER project. 

Lastly, from a modeling perspective the August implementation timeline does not coincide with time it will take for MISO to establish a defined modeling criteria.  The potential updates to MOD-032 are scheduled to occur in 2024-2026, which will create issues related to data requirements (e.g. dynamic data) and an excessive number of projects studied due to lack of a MW threshold being established during implementation.  We would like to see MISO urgently work towards addressing these concerns to make the transition to the new process seamless and efficient.  We’d also recommend that MISO collaborate with the various state public commissions so that they are aligned on both the cost and timeline of the new DER AFS process. 

The Coalition for Community Solar Access (“CCSA”) and the Sierra Club, (collectively, the “Joint Commenters”) appreciate the opportunity to provide feedback on the proposed redlines to BPM-015 to incorporate Distributed Energy Resource (DER) affected system study (AFS) practices, presented during the April 26, 2023 meeting of the Planning Advisory Committee (“PAC”).

We support the aim of the DER AFS proposal to maintain the safe and reliable operation of the transmission system. We believe that the objectives of the proposal can be achieved in a way that minimizes harm to DERs, allowing states to achieve clean energy goals in addition to maintaining safety and reliability.  With this in mind, the Joint Commenters respectfully offer the following recommendations and feedback on MISO’s proposed BPM revisions: 

1. MISO should revise its proposed implementation timeline to allow additional time for MISO and relevant regulatory authorities to engage additional stakeholders, initiate state-level implementation discussions, and develop a baseline assessment of grid conditions.

Experience in other parts of the country proves that successful implementation of the DER AFS proposal will require significant multi-jurisdictional coordination and utility preparedness for additional work. The Joint Commenters believe there are important lessons to learn from the launch of ISO New England’s affected systems study processes in particular. Initial lack of preparedness across the Northeast led to excessive delays and major interconnection queue backlogs, including a 1-GW backlog of distributed solar in the state of Massachusetts.[1] To ensure clearance of the backlog, state regulators ultimately had to facilitate biweekly meetings with developers, transmission owners (“TOs”), and electric distribution companies (“EDCs”). MISO should take advantage of the opportunity to learn from the experience in other RTOs, and to avoid a turbulent rollout of the DER AFS process by ensuring that states are sufficiently set up to coordinate with stakeholders from the beginning of the DER AFS process launch.

The Joint Commenters appreciate the current proposal’s allowance of approximately eight months – from release of the Draft Whitepaper in November 2022, which is the first comprehensive articulation of MISO’s proposal, to the proposed commencement of initial screening in August 2023 – of notice for stakeholders. However, given typical state rulemaking timelines, this notice period is insufficient. The Joint Commenters request instead that MISO modify its implementation schedule to have the “DER Cycle 1 screening” begin in Q2 2024.  

In response to stakeholders who have previously raised this concern about state readiness, MISO staff have requested specific examples of areas where state regulators may need to open rulemakings or otherwise engage with stakeholders. Some examples are included below. This list is not comprehensive but illustrates the breadth of open questions that may need to be addressed at the state level.

At a minimum, to ensure efficient and transparent rollout of this proposal, state regulatory authorities:

1. May need to develop guidelines for determining and administering cost allocation for network upgrades to DER customers.
2. May need to develop protocols for DER developers to challenge the need for network upgrades or to consider alternative solutions (such as curtailment/flexible interconnection, or non-wires solutions, among others.) 
3. May need to update Confidential Energy Infrastructure Information (“CEII”) access rules. 
4. May wish to update or create websites to better facilitate sharing of information on AFS studies and protocols.
5. May need to develop guidelines to ensure fair treatment of DER projects in comparison to utility-owned projects with the context of the MISO DER AFS process.
6. May wish to commence proceedings to explore how to make electric distribution companies’ planning processes flexible and comprehensive enough to mitigate the need for network upgrades and keep costs lower for ratepayers.
7. Will need to continue to stay deeply engaged in this study process with regular meetings with relevant TOs, EDCs, and MISO to track progress and any risk to schedule. 
8. Should, at a minimum, allow for technical conferences and/or discussions about the implementation of these studies and their impacts to be discussed amongst stakeholders at the state level and instruct the utilities on an implementation path that minimizes harm to DER projects participating in state programs.

Notably, this work has not yet begun. The Joint Commenters are not aware of any new public proceedings, technical conferences, or working groups where the above issues or the MISO DER AFS itself is being actively discussed by state regulatory authorities in a public forum.

2. MISO should perform a DER AFS process trial run and undertake a baseline assessment of current grid conditions. 

MISO has indicated that it plans to share screening study results only once the new DER AFS process is implemented. The Joint Commenters urge MISO to work with TOs and EDCs to instead conduct a trial run and a baseline assessment of grid conditions using the 1% and net injection screens, and share the results with stakeholders, prior to implementing the DER AFS proposal. The purpose of the baseline assessment is twofold: (1) it will serve as a trial run for future studies, allowing EDCs, TOs, and MISO to identify process issues, and (2) also allow stakeholders to better understand potential impacts of the new proposal prior to implementation. Additional time is needed to perform this work and would be enabled by the 18-month notice period we’ve requested.

Respectfully submitted,

              /s/                                                                                                              /s/                                          

Samantha Weaver                                                                                   Justin Vickers
Director of Interconnection & Grid Integration                                    Senior Attorney
Coalition for Community Solar Access                                                 Sierra Club

DRAFT Transmission Owner Feedback on DER AFS Revisions

May 19, 2023

Comments are due to MISO by May 22, 2023

PAC: DER AFS BPM-015 Changes (20230426)

In the April 26, 2023, meeting of the Planning Advisory Committee (PAC), MISO discussed proposed redlines to BPM-015 to incorporate Distributed Energy Resource (DER) affected system study (AFS) practices and requested feedback on the proposed changes.  The Transmission Owners (Owners or TOs) appreciate the changes that have been made to BPM – 015 since the March 14 meeting of the Interconnection Process Working Group, and the discussion with stakeholders on the proposed changes at the recent PAC, IPWG, and PSC meetings.

Following these discussions, the Owners have additional comments, questions, and clarifications on the proposed BPM language, as described below.

The Owners appreciate the importance of identifying the potential for Distributed Energy Resources to impact the Transmission System but are also mindful of the cost and manpower impact of these studies on other interconnection and planning matters, relative to the number of substations that could be subject to this process, potentially multiple times, and in addition to the section-specific comments below, the Owners request that MISO consider including provisions to allow MISO to use TO study results, to the extent practicable, to minimize the costs associated with these studies.  For example:

MISO’s DER AFS process will be limited to evaluating thermal and voltage constraints; however, Owners have observed that protection upgrades are the most common upgrades required for the DER to interconnect.  While these upgrades don’t impact the topology of the grid, they are transmission upgrades that may be cost-assigned to the DER owner. To identify whether system protection upgrades are needed, the TO must perform analysis that also generally includes thermal and voltage analyses.  Can MISO leverage the Owners’ analyses to ensure all necessary upgrades are identified without duplicating efforts and costs?

Section 8.1 Definitions

DER – Substation It is not clear from the definition how the “DER Substation” would be identified if two substations are impacted. 

• Is this defined to represent the substation impacted by the primary feeder on which the DER is interconnected? 
• If there is a desire to have the ability to inject at multiple points, would each substation require a separate study?
• Should we consider the term “DER Point of Injection” which means the point on the transmission system where energy from the DER flows onto facilities modeled in the MISO MTEP power flow cases? This would mean that aggregated DERs into the same POI could be consolidated into one study.

Section 8.2 Scope

This section states: “MISO’s DER AFS is intended to evaluate the impacts of DER newly proposed for interconnection through the applicable EDC and RERRA process. DERs that have an existing interconnection service agreement, according to the applicable EDC and RERRA processes, are not intended for inclusion in the impacts evaluation group under MISO’s DER AFS studies...”

Regarding MISO’s intent for the process to apply to “DER newly proposed for interconnection through the applicable EDC and RERRA process” but not to “DERs with an existing interconnection service agreement,” tor purposes of implementation, the Owners request the following clarifications be included in this section or in the description of the Screening and AFS processes, as appropriate:

-          Is it assumed that DERs with an existing interconnection service are included in the base case models, or is the TO expected to update the base case models with additional DER data?   For example,

-          is the Owner expected to disaggregate load data submitted by the LSE to determine if additional DERs should be included in the Screening and Study models?

-          Is the designation of DERs modeled as gen vs. negative load relevant to how they should be modeled in these studies? 

-          If the concern relates to voltage and short circuit impacts, then the DER should be modeled as generation and not just as negative load.

-          If negative load is to be modeled, how should the fuel source be determined?

-          In order to avoid confusion between newly interconnected DERs included in the study that may have executed interconnection agreements due to RERRA timing requirements or because the potential for the cumulative impact of DERs at a substation did not exist when the DER was seeking to interconnect, the Owners recommended modifying the proposed language to refer to “DERs with pre-existing interconnection service agreements . . . “ rather than “DERs with an existing interconnection service agreement . . .”   

For purposes of clarity and achieving the objective stated at the Planning Advisory Committee to identify the potential of DERs to inject power onto the transmission system, the Owners request that the Scope include a threshold of “at least 1MW” for DERs to be included in the Screening and Study models, both newly connecting DERs.  This threshold should apply to the initial and any subsequent studies and would be consistent with the current provisions of BPM-020 Section 5.3.2.3.11, “Evaluating Constraints and Accepting Transmission Service” which refers to this threshold:

A facility will be considered constrained if it becomes overloaded when modeling the transaction or aggravates an existing overload. The constraint must be impacted by the transaction by a five (5%) percent distribution factor with system intact, or three (3%) percent under contingent conditions. Regardless of the distribution factor, any impacts under 1MW will be ignored.

Similarly, the proposed 1% change criteria should be over the 1MW threshold for the substation to be subject to MISO’s AFS process.  Given the cost of these studies, the TO’s evaluation of potential injection should suffice for these very low levels of potential injection, particularly since the tolerance of the model solution is typically at 1 MW, so for any potential impact below 1 MW would be accepted as a valid solution, i.e. within the established tolerance. For these reasons, the Owners suggest that a 1MW threshold applied in this study would be consistent with mitigation requirements applied in other MISO planning studies. 

Regarding the timing of these studies, relative to the RERRA jurisdictional process requirements, the Scope should clarify that to the extent there is a conflict between the MISO’s process and RERRA interconnection timing requirements, specifically with regard to the identification of potential upgrades or the execution of Interconnection Agreements, RERRA rules prevail, as Distribution Interconnection is their area of authority.

See Appendix for examples.

Section 8.3. Procedure

-       Local Planning Criteria, referenced in the first paragraph of this section, should be capitalized.

-       The beginning of the third paragraph should clearly state that a DER AFS report will be issued “at the conclusion of the DER AFS, should one ultimately be performed.”  This clarification is needed because, for example, a DER project may be withdrawn or modified by the DER Customer if the need for Network Upgrades is identified in Screening, in which case the DER AFS would not be performed.

-       Regarding the Report, and the opportunity for review, this Section should refer to Section 8.3.3, which provides additional details regarding this element of the process.

Section 8.3.1.1 – Screening Assumptions

This section begins by stating, “The TO and MISO shall assume full injection of DER resources when applying DER screens.”

-          The Owners request that MISO clarify in the BPM whether only the DER resources being studied are to be modeled at full injection in every study model or all DERs in the study model are to be modeled at full injection.

Table 8.1 DER AFS Screening Adaption for summer peak and shoulder peak selection

Is this dispatch intended to apply to the study generator(s) or all DERs in the study? The BPM language is unclear on this point.

Section 8.3.1.2 – Transmission Owner Screening

Regarding subsequent studies being triggered by one megawatt (1 MW) or greater additional net injection, should a screening study show no impacts, or if an identified Network Upgrade is funded,

-          Is this provision intended to imply that the TO can decline to make an upgrade if it is identified as needed if the impact is mitigated or eliminated on the distribution side of the substation?

-          If a/the subject DER does not interconnect due to the need for an upgrade, or if the need for the upgrade has been mitigated or eliminated on the distribution side of the substation, is there a need for a “any incremental injection” to trigger another study, or would another Screening suffice? 

-          Given the high cost of these studies, a Screening should suffice, if a TO Screening identifies a future need for a MISO review.

-          This section refers to a “TO screening deadline” but this deadline is not defined in the BPM, and it should be, as the referenced illustration (Figure 8-2) is also vague as to the “Due date for Cycle TO screening”.  The BPM should clarify how these due dates will be established.

Section 8.3.1.3 MISO Screening

-       See the comment above regarding the “TO Screening Deadline”

-          Change reference to 0-5 MW in third paragraph to 1-5 MW consistent with TO-proposed threshold.

-          Regarding the statement that the TO may be reimbursed for any DER AFS Costs consistent with RERRA regulatory requirements and TO Utility Structures, there is no need to include this statement, as the TO does not need authorization from MISO to collect these funds from the RERRA or EDC.

Section 8.3.2. Study Process

The Owners suggest adding, “if an AFS is needed,” at the beginning of this paragraph.  As it is written, the statement that these studies will be performed “at least a quarterly cadence” appears to conflict with the following statement that a study cadence may be skipped if there are no requests for a DER AFS at the beginning of a quarterly cycle.

8.3.2.1 Agreement

Regarding the TO and MISO DER AFS agreement(s):

-          If the same TO has multiple substations being studied in a quarterly cycle, the TOs recommend including all studies in the scope of a single Agreement with distinct study scopes for each substation.

-          The BPM language should also address what would happen if more than one substation may be impacted by a project.

8.3.2.2 Agreement Deposit Amount and Payment Methods

Again, regarding the statement that the TO may be reimbursed for any DER AFS Costs consistent with RERRA regulatory requirements and TO utility structures, again, this language is unnecessary as this is not a matter subject to MISO’s authority.  If MISO believes language is necessary as to the cost reimbursement for DER AFS, the Owners propose that reimbursement for DER AFS Costs be consistent with the appropriate tariff.

8.3.2.3 Data Exchange

-       While this Section states that the screening data will be used for the AFS, it lists two data elements, “(3) equivalent short circuit impedance by fuel type, and (4) reactive power control mode and settings by fuel type,” that are not listed in the screening data requirements in Section 8.3.1.2.  Clarification is needed regarding whether additional information is needed for the AFS or if this information is also needed for Screening and these Sections should be reconciled.

-       Regarding the reference to “aggregate DER Connected”, is this referring to just the DER represented in the MTEP base model used for the study, or all existing DER located on the feeder?

8.3.2.4 Modeling Assumption and Inputs

Regarding existing DER data included as negative load in the MTEP base models when reported by Members, TOs also have the option to submit DERs as generators; will this also be modeled by MISO?  This should be stated here, or the reference to the negative load DERs should be deleted.

Currently the proposed BPM has one set of modeling assumptions for DER generation for each fuel type and a different set of assumptions for the dispatch of those same generator types for generators connected to the BES.  Is this reasonable or should the dispatch for the same types of generation in an area have the same dispatch assumptions?

If MISO is looking for the TO to model existing DER that is currently modeled as negative load, this may take time to verify that nothing is being double counted for the DER in a possible net load amount at the station and to determine the generation types. Sufficient time needs to be allotted during the model build and review process to verify DERs are being incorrectly represented.

8.3.3         Report

-       Regarding the reference to “cumulative DER data” is the “cumulative DER” included in the model for the substation being studied, or is it all of the DERs on the relevant line?  Recommend replacing “cumulative” with “aggregate” to be consistent with multiple DERs at a single DER Point of Interconnection.

-          If it is all of the DERs on the line, is it only those that are included in the MTEP base case model being used for the study, or is the TO expected to provide MISO with information relating to all DER connected behind the substation?  Presumably some would also be accounted for in the load data provided by the LSE, referenced earlier as the source of load data, which the TO may not have visibility into; if Owners are expected to receive this data from the EDC, time will be needed to develop processes for the Owner to request and receive the data from the EDC.

-       In the paragraph describing the timing allotted for Report Review, the number of days by which MISO will respond to comments is blank and should specify that the response timing is tied to either the date that the specific comment was submitted or the date by which all comments were due.  The Owners suggest that it would be more efficient to tie MISO’s response to the time at which all comments were due.

8.3.4.     Facilities Studies and Network Upgrades

This section states that, “After the Facilities Study, a MISO MPFCA is needed between MISO, the TO, and DER Customers.”  However, funding and cost recovery mechanisms for Network Upgrades driven by DER interconnections may vary; therefore, “DER Customers” should likely be replaced with “the relevant Funding Party or Parties”.

8.3.5 Tracking and Reporting Information

Regarding the information that MISO intends to include in the posted AFS Report this section should refer back to the information protection provisions contained in Section 8.3.3.

The Owners appreciate the opportunity to comment.

Appendix:  Retail Interconnection Timing Requirements Examples

Arkansas and Mississippi have specific timing requirements for the initial screening review for NEM projects.

-          Arkansas is 30 days.

-          Mississippi has different application levels for their NEM program with times varying from 15-30 days. Once an interconnection agreement is submitted at the end of the process the typical requirements is to have them interconnected within 30 days.

Here is a sample summary of general EDC timing for the various steps that may be encountered during the interconnection process, some of which are mandated by RERRA requirements, and others are guided by EDC policies and practices: 

Michigan’s DER requirements - high level summary:

•             Study fees are capped - $1,000 for Fast Track (5MW cap) application, $300 for a Normal Track application, $10,000 for System Impact Study Fee, $15,000 for Facilities Study Fee

•             System Impact Studies must be completed within 60 days (affected system impacts will also be identified)

•             Facilities Studies must be completed within 80 days

•             DERs are required to pay for all interconnection facilities and distribution upgrades (no mention of affected system upgrades, but there appears to be flexibility for each EDC’s interconnection procedures and agreements)

•             EDCs are required to include in their interconnection procedures the process for affected systems

•             EDCs are responsible for specifying the requirements within the interconnection agreement to support ISO/RTO regulations

Michigan and Wisconsin:

Generally, once the “Initial Screening Review” is complete, a study cost estimate is required to be provided to the EDC (often within 10 days). In Wisconsin and Michigan, study results need to complete within 60 days at most, which would not allow for the MISO study process to be completed. This either puts the system at risk, by allowing the DER to go in-service to meet the State timelines, or delays meeting the State regulated obligations. As currently proposed, the MISO DER screening process would not have been completed yet to allow the LDC to know if additional MISO study cots are required by the TO. 

American Municipal Power (AMP) appreciates the opportunity to provide feedback on DER AFS BPM-015 changes and has the following questions:

• How do the proposed BPM redline changes interact with the Distribution System Interconnection Request Instructions (found here:https://cdn.misoenergy.org/Distribution_System_Interconnection_Request_Instructions108140.pdf)?

• Is the proposed BPM change applicable to DER participating in the RTO markets only, or is it applicable to any DER that is interconnecting to the system?

• The referenced whitepaper on DER Affected System Studies Business Practices defines DER as any source of electric power located on the distribution system. Are there any other considerations for applicable DER, such as size of DER, for example?

• Does this DER definition and proposed process include every residential rooftop solar installation?