MISO is requesting feedback on MISO DER Affected System Proposals.
Please provided feedback on the following:
Please provide feedback by April 4, 2023.
Transmission Owners Sector Feedback on MISO DER Affected System Proposal
April 4, 2020
At the March 14, 2023, meeting of the Interconnection Process Working Group (IPWG), MISO presented proposed BPM-015 redlines to incorporate a new Distributed Energy Resource (DER) affected systems study (AFS) process and requested stakeholder feedback. The MISO Transmission Owners[1] (Owners or TOs) provide the following feedback for MISO’s consideration in the ultimate implementation of the proposed new process.
Owners are experiencing varying levels of DER integration on the distribution systems interconnected to their facilities. For some, the level of DER integration has or has the potential to have an impact on the transmission system; for others, this risk is not on the near-term horizon. For the Owners who have not observed significant levels of DER interconnection, the proposed process introduces complexity, cost, uncertainty, and potential delay for retail customers that is not warranted. In all cases, the Transmission Owner that is directly upstream of the DER has primary responsibility for performing individual studies at the request of their interconnected Distribution Service Providers.
The BPM should clarify that:
Additionally, Distribution Provider studies are generally governed by retail tariffs that include timelines by which interconnection requests must be studied and either granted or denied, for example, 30 days. After the interconnection service is granted, there is no longer an opportunity for collecting funds from the retail customer for (1) the cost of an additional study by MISO, should one be triggered at some point in the future, or (2) an upgrade identified in an AFS that occurs after the interconnection agreement has been executed with the Distribution Provider.
There has been no stakeholder discussion on the allocation of cost for mitigating the potential impact to the Transmission System, which may include upgrades on the Distribution System or at the DER Interconnection, and while the BPM is silent, as that the TO is to be the entity that requests the study, the responsibility for ensuring that the risk to the Transmission System is mitigated. Stakeholders should have the opportunity for discussion on this aspect of the process.
Finally, the proposed process creates compliance obligations requiring significant coordination between TOs and Distribution Providers. Distribution Providers tend to participate in the Planning Subcommittee, given that the subject matter relevant to them is generally discussed there, but they do not tend to participate in the IPWG. The PSC is also the stakeholder forum for discussion of NERC Transmission Planning Study compliance issues, implicated by this proposed process, and the PSC has a standing agenda item for discussion of DER issues, including modeling of DERs. Therefore, the Owners request that the proposed BPM changes be brought to the PSC for review prior to being presented at the PAC for final Stakeholder review.
Feedback by Public Service Commission of Wisconsin (PSCW) Office of Regional Markets (ORM) Staff to the Midcontinent Independent System Operator (MISO) on MISO’s proposed BPM-15 redlines for the DER AFS process.
Section 8.3 page 122
MISO states the DER AFS begins with a screening. It would provide greater clarity to note that the screening is triggered by an EDC flagging the need for a screen based on a new DER interconnection request.
Section 8.3.2.2 page 127
In this section MISO specifies that there may be a request for the interconnection customer to pay more than the $60,000 if additional funding is needed for the DER AFS. Does this sentence need to be edited to clarify who would request these additional funds - MISO or the TO - and acknowledge that a RERRA could have their own requirements for reimbursement? There is text that appears earlier in this document acknowledging that reimbursement for the DER AFS to the TO must be “consistent with RERRA regulatory requirements and TO utility structures.”
Section 8.3.3 page 129
Can MISO add language about how notification will be given that a public report has been posted to the website? If MISO is not intending to make a public notification about such a posting, can MISO add language noting that the relevant RERRA will be notified by MISO?
Section 8.3.3 page 129
Can MISO add language about how notification will be given that a DER AFS comment report comment period is open? If MISO is not intending to make a public notification about the opportunity to provide feedback, can MISO add language noting that the relevant RERRA will be notified by MISO?
MISO - Implementation guidance for EDCs and RERRAs
We see that MISO removed the “Implementation guidance for EDCs and RERRAs” section. Is it possible to add this content back in, or add some of it back in? If not, is there another way to document the expectations outlined in this section in a public, permanent, and easily accessible way? Specifically, we are hoping MISO can preserve these paragraphs that outline expectations and roles:
MISO expects the MISO DER AFS screening and study process to be triggered by new DER interconnection requests. Existing DER should be included for purposes of screening and study, but MISO’s DER AFS process transition does not equate to a MISO request to evaluate all existing DER Substations that might exceed the new criteria. Consistent with MISO’s understanding of common RERRA interconnection practices, existing DER is “grandfathered” using the interconnection requirements that were in place at the time of interconnection.
In terms of which new DER applications might be included in MISO’s first DER AFS cycle, MISO suggests EDCs and RERRAs consider a cutoff point associated with state-Jurisdictional steps such as application deemed complete, EDC screening or, the EDC’s distribution system impact study. These DER interconnection process steps often feed into transmission studies and affected systems studies and may be an appropriate demarcation point that does not require DER interconnection customers to move backwards, or pause, within the relevant interconnection process. MISO anticipates that DER Substations that trigger MISO’s screening criteria will also trigger EDC distribution impact studies.
Since MISO DER AFS reports will address impacts at the DER Substation level, EDCs and RERRAs may need to document to allocate costs arising from impacts. MISO understands cost allocation principals are likely in place across many RERRAs’ jurisdictions. However, a decision may be necessary to reaffirm and/or clarify application of existing principles (e.g., “cost causer pays”) or consider new principles such as allocating costs a pro rata share.
Ongoing need to revisit and evaluate screening standards
Does MISO intend to revisit and evaluate screening standards for the DER AFS to determine if they are the appropriate level of sensitivity in the future? Given that the DER AFS are new to MISO, we recommend adding language to the BPM that these standards will be evaluated after a trial time period, such as a year.
Xcel Energy supports MISO’s proposed Affected System Study BPM language. MISO’s new process will help ensure DER interconnection processes run by Distribution companies account for the times when energy produced by DERs exceeds the demand in local areas and backflows onto the transmission system resulting in unpermitted use of the transmission system.
DTE appreciates the opportunity to provide feedback to MISO related to the redlines that have been proposed as part of the DER Affected Systems process. DTE has concerns with the requirement that DER information is submitted in IDEV or PSSE raw format. This stipulation places additional cost and administrative burdens on stakeholders that do not currently have the required software systems to provide the data in the requested format. Given the timeline in which MISO plans to implement the new DER AFS process more discussion should be had on the collection of data. We recommend that MISO adopt a more flexible approach towards data exchange that allows stakeholders to submit information with their current software systems. For example, MISO could allow stakeholders to submit the necessary data in the standard excel format. Then MISO could format the data for their software tool as an input to their powerflow case.
CCSA appreciates the opportunity to review and comment on proposed revisions to Business Practices Manual Number 015 (“BMP-015”) in order to incorporate the details of the DER Affected Systems Study proposal whitepaper.
As a general matter, CCSA remains concerned about MISO’s proposed implementation timeline for the DER AFS process. According to the latest whitepaper, released January 20, 2023, MISO expects to initiate the first DER screening cycle in approximately four months, in August of this year. Considering that August 2023 is quickly approaching – and CCSA is not aware of any MISO state that has opened a proceeding to revise existing regulations, despite the fact that many aspects of the MISO DER AFS proposal require reconsideration of existing state-level rules and processes, as MISO itself has acknowledged – CCSA reiterates previous requests to allow for an 18-month notice period prior to undertaking the initial DER screening cycle. At a minimum, we recommend that MISO consult with each Relevant Electric Retail Regulatory Authority (“RERRA”) on the appropriateness of the currently proposed implementation timeline.
CCSA proposes the following changes and clarifications to the revised BPM-015:
ATC appreciates the opportunity to provide feedback on MISO DER Affected System Proposals
Overall comment:
ATC requests that MISO add an “Op-out” provision to the DER Affected System process. As a Transmission-Only Utility, ATC is not vertically integrated and does not directly serve Retail Customers (potential DER owners). ATC only has business relationships with the Local Distribution Companies (LDCs or Electric Distribution Companies (EDCs) as used in the BPM) within ATC’s footprint. Thus, any coordination between MISO, ATC (the TO), the EDC and the DER must be performed between four parties. ATC experience that arranging for Agreements, Payments, Studies, between the EDCs and DERS will take much longer than the timeframes suggested in the DERC Affected System Study process outlined in the proposed changes to the BPM. ATC has in place an effective process to study DERs being added to its’ transmission system associated with the load interconnection process here at ATC. In consistent with ATC’s previous comments, we would like to request MISO to first address DER modeling requirement before implementing the DER Affected System Study.
Specific comments on the proposed changes to BPM-015
8.1 Definitions:
DER Substation – is MISO intending this process to include both non-BES and BES substations with DER interconnections?
RERRA – includes City Councils, Coop Governing Boards, State Public Utility Commissions – Who has the responsibility to advise all of these RERRAs of this proposed process and who will incorporate the policies of each of these entities into the overall MISO DER Affected System Process?
8.2 Scope
DERS may participate in the MISO market as a MISO Market Participant. Will MISO advise ATC (TO) when this occurs?
8.3 Procedure
8.3.2.1 Agreement
ATC is concerned there is not enough time to secure the agreements between both ATC and The EDC and the EDC and the DER.
8.3.2.2 Deposit Amounts
ATC is concerned that the $60,000 study deposit may be an impediment (barrier) to DER development.
ATC anticipates that collection of DER Study deposits will be complicated as ATC must collect from the EDC who in turn must collect from the DER before ATC can pay MSIO the Study Deposit.
8.3.2.4 Data Exchange
ATC is not confidant that all potential DER participants will have the ability to provide IDEV or PSSE (*.raw) format data.
8.3.3 Report
BPM states EDC is responsible to manage results, assign impacts and Deposit funding. Who ensures the impacts and cost allocation of the studies are allocated consistently across the various EDCs within the ATC footprint?
10 business days for the DER to fund a Facility study is too short for reasons stated above.
MISO should clarify how DER with existing deliverability rights to use the transmission system will impact the screening when determining if an affected system study is required. For example if a DER Substation has 5 MWs of load and 5 MWs of existing generation with NRIS/ deliverability rights (per the Interconnection Service Workbook https://cdn.misoenergy.org/MISO%20Generator%20Interconnection%20Service%20Workbook108135.xlsx) would adding 1 MW of new generation trigger the MISO affected system study process? MRES does not believe this should trigger the affected system process since the existing generation already has the rights to inject up to 5 MWs independent of load and the additional 1 MW of generation will only offset load and not inject onto the transmission system.