Foundation Solar Partners develops both transmission and distribution level solar projects in MISO territory, and we have a project portfolio of roughly 4GW under development. We recently became aware of MISO’s DER Affected System Study Proposal for DER’s.  Overall, we appreciate MISO’s need to ensure reliability on the transmission grid, and we do not have objections to the overall concept.

That said, we have some concerns with the new process as currently being proposed.  Primary concerns:

• We have been submitting projects into state-level interconnection queues for the past two years with specific LSE’s in the MISO footprint.  We have done so with the understanding that interconnection study costs and timelines for projects were defined in the state-level tariff. State level Interconnection rules are the basis for our development and capital deployment strategy – material changes to these rules executed without consideration of project development and investment timelines will materially impact our entire portfolio of renewable energy projects. If subjected to the current version of MISO’s proposal, these same projects could be subject to an increase in overall study costs by approximately 5x and could be significantly delayed relative to the interconnection process timelines laid out by the state and utility.
• Furthermore, we fear newly prescribed timeframes could slip even further as LSE’s transition from their existing interconnection process to accommodate this new study.  Local utilities will be forced to amend state level interconnection tariffs to accommodate major process changes that will accompany MISO’s proposal.
• These interconnection process changes will significantly harm our projects that were submitted into queue under rules defined by the state-level tariffs.  Many of these projects are in the interconnection process and have otherwise been fully developed.  Requiring retro-active Affected System Studies could lead to irreparable harm for these projects that have already endured years of planning and development spend.

FSP strongly recommends that any DER Affected Systems process changes be applied on a prospective basis. This important new process should only apply to projects that enter into DER queues on a prospective basis once the new rule has been finalized.  Projects that entered into queue under a previous set of rules should be grandfathered under such rules.

American Municipal Power (AMP) appreciates the opportunity to provide feedback on the MISO DER Affected System Study Whitepaper.

Due to the growing DER interconnections with distribution systems across the MISO footprint, AMP agrees that a more formal process to consistently and effectively evaluate DER transmission system impacts is needed.

However, AMP has the following concerns related to the processes discussed in the Whitepaper:

1. AMP recommends that when the MISO DER AFS process starts, the screening process, and all subsequent studies, should be carried out jointly by all affected parties, such as MISO, the TO, the DER Customer, and developer.
2. AMP recommends that in the event a study is needed, the DER Customer should be the point of contact for invoicing of the study deposit. MISO should invoice the DER Customer within 15 business days of the screening completion, rather than invoicing the TO. The DER customer should then be responsible for providing the deposit to MISO within 30 business days of the invoice. Additionally, any deposit money not used in the studies, should be returned to the DER Customer.

There is a concern regarding very small projects with an immaterial individual impact to the transmission system incurring significant delay and cost.

Example 1: a residential customer applies to install a 5 kW system. Their residence is connected to an existing substation with 6 MW of existing net injection (grandfathered). The 5 kW addition would push this above the existing size. Is the deadband of 1 MW expected to apply or is the customer now subject to full process & $60,000 cost?

Example 2: 5.45 MW of existing net injection, last study on substation at 4.5 MW. Several residential solar customers with a total of 50 kW of system capacity apply within a quarter to that same substation bringing the net injection to 5.5 MW. As the injection now exceeds 5 MW, 1 MW deadband is exceeded, and there is no option to waive the study, the homeowners now need to split the $60,000 cost and wait for the full study to be completed.

Thank you,

 Consumers Energy

Page 9, Figure 2, Note 2

• If only one DER “funding” network upgrade….  Since different TOs have different cost recovery mechanism, ATC suggests replacing “funding” with “caused” or “triggered”.

Page 14 – DER AFS data exchange

• The DER modeling information includes: (1) Substation name and associated transmission bus number; and (2) DER capacity, in megawatts, categorized by the fuel types found in BPM-015.
• Does this DER modeling information defined in the MOD-032 process?

Page 14 – Modeling assumptions and inputs

• “MISO selects the latest DPP Phase 3 model”
• MISO has 5 DPP regions. Will the model be the latest amongst the 5 or chosen some other way?
• Modeling between the five regions tend to diverge significantly by phase 3.
• Please clarify if it is the latest phase 3 model that is under study or the latest model from a completed phase 3.
• Please clarify whether identified DPP network upgrades will be included in the model.
• Do DPP generator withdrawals trigger a re-study?

Page 14 – Voltage and thermal analysis and constraint criteria

• “BPM-015 (r24), Section 6.1.1 (Thermal Analysis)”
  • Section 6.1.1 is titled “Steady State Analysis”, so either the reference or the section title is incorrect. We assume MISO meant section 6.1.1.1 Thermal Analysis
  • A sub-section is 6.1.1.1.9 Deliverability Analysis; does MISO intend to run deliverability analysis for these DERs?

Page 15 – DER AFS Report

• TO would like to be involved in the DER AFS report drafting and review prior to posting of public report and confidential DER AFS.
• Please add the clarity in Swimlane Diagram on page 18 to allow TO review the draft report before public posting.

Page 15 – Facilities Studies and Network Upgrades

• “MISO proposes that the TO return the Facilities Study agreement and deposit within 30 business days of MISO issuing the final DER AFS Report.”
• It reads like that’s a separate agreement and deposit in the Facilities Study phase.  The whitepaper did not specify the deposit amount or can the $60K deposit in the AFS continue to cover the FSA?

We appreciate the opportunity to provide feedback on MISO’s DER Affected Systems Study Business Practices Whitepaper discussed at the November 14, 2022, IPWG.  ITC appreciates that DERs are a new frontier for MISO and offer the following thoughts.

Technical Data

MISO identified in their White Paper that they are counting on a revision to the NERC MOD-032 standard as part of the identified process for DER.  ITC believes this should not be done until such time as this revision appears to be more certain.  A previous request to change this standard failed and numerous comments on this version are not favorable to this change as well.  ITC believes that MISO should instead modify its existing process to facilitate obtaining the data and having it modelled accurately by the Distribution Providers (Electric Distribution Companies – “DP”).  The DER entities provide both their connection location and their data to the DP for their original connection studies to the distribution systems.  Requiring a Transmission Owner to provide this information puts the TO in a position of obtaining the information second hand from the DP to turn over to MISO.  Putting the TO in the middle of this process, creates both an opportunity to introduce errors into the process and delays.  This might mean that any data errors would become the responsibility of the TO rather than the data originator.

With respect to the study process, the DP is again the entity best positioned to identify which DER entities are ‘grandfathered’ and which entities are new DP interconnections that need to be considered in an Affected System study. The DER works exclusively with the DP to provide the necessary technical information to be evaluated and to fulfill the DP’s connection requirements.  The TO does not have full visibility into DPs system unless the information is provided by a DP.  Thus, the DP should be the responsible entity to identify to the TO when an Affected study may be necessary for a variety of potential reasons including but not limited to this MISO Affected System Study.

MISO Study Costs

The DP will know which DER triggers and which DER should be involved in an Affected System Study, therefore it is more appropriate for the DP to be the party to receive the bill from MISO for the study costs rather than the TO.  As identified on page 18 of the MISO White Paper, the TO would be acting solely as a billing agent, and pass though the funds to MISO.  Once again, putting the TO in the middle of this process simply adds cost and additional delays to the process.  In addition, MISO has clearly not taken into account that requiring the TO to function as a billing agent will require significant time and personnel costs which must be recovered; however no recovery mechanism has been contemplated.  If the TO cannot recover these costs from the DP or DER, then their transmission customers will pick up the tab and this is inappropriate cost shifting.

MISO has identified on their flow chart, on page 18 of the White Paper, that the DP or EDC should be responsible for reconciliation of the costs of the System study. These entities are familiar with any state jurisdictional rules regarding a pass through of these costs to the DER entities.  MISO should also be providing some guidance on possible allocation of these costs to the various DER entities. 

Affected System Studies

MISO should consider if there are situations that could require coordination between the DER and DPP processes.  MISO currently evaluates external NRIS requests in coordination with its queue, and there may be situations or thresholds that could be identified where coordination is required.  It should be ensured that the DER Affected System process cannot be utilized as a tool to circumvent the queue, where for example, generation owners could elect to connect to the distribution system in areas where there is little transmission capacity in an effort to avoid cost sharing of backbone upgrades or elect to connect to a Distribution System to avoid exposure to potential MISO-SPP or MISO-PJM affected system study delays or upgrades, While today this may not be an obvious need, as the DER process grows over time, the need for this coordination may be more necessary to avoid a preference being provided to the DER process.

DRAFT MISO Distributed Energy Resources Affected System Studies Business Practices Feedback Request from 11/14/2022 MISO IPWG

In the November 14, 2022 IPWG, MISO is requesting feedback on the following MISO DER Affected System Proposals presented today by December 9, 2022.

• Process and technical elements contained in MISO’s DER Affected Systems Study Business Practices Whitepaper
• MISO’s proposed high-level implementation plan and timeframe

DTE is pleased to provide the following feedback on DRAFT MISO Distributed Energy Resources Affected System Studies Business Practices. 

1. Process and technical elements contained in MISO’s DER Affected Systems Study Business Practices Whitepaper

Overall/general process elements

MISO states it is not interested in controllable load[1], however how are large non exporting DER intended to be treated that may have significant variability in consumption due to internal changes in energy balance or time shifting due to storage?

Is the definition of DER as a resource capable of injecting power[2] intended to include any such resources regardless if it reached the distribution or transmission system?  Later in the document it is heavily implied that injection is only to the transmission system.

MISO needs to advise whether sub-transmission stations, that are represented in the MISO model, will be considered “DER Substations” and need to be screened the same as Transmission connected stations and be subject to the Affected System Study (AFS) fee or will it be limited to the station at the actual point of interconnection to the transmission?

What is the process for TO’s to handle asynchronous requests? Will TO “collect” EDC requests until MISO’s quarterly DER AFS starts or continue processing them asynchronously?

DTE’s current interconnection process requires DTE to submit an affected system notification of any known injection upon identification. The process proposed by MISO suggests a 6-9 months impact to EDC’s DER interconnection process timeline:

• quarterly nature of the proposed process may contribute for up to 3 months and
• AFS Cycle itself takes ~6 months or longer

A DER Customer will face new timing limitations for the state interconnection process under the proposed rules. The delay in the state interconnection process, caused by MISO AFS, may include financial and scheduling challenges for DER Customers and can potentially create a risk for a developer of being excluded by the state interconnection process for inaction.

MISO needs to clarify a process for a scenario when a project successfully completes MISO DER AFS, but is withdrawn or simply not committed to moving forward. If there is a lack of commitment by DER Customer for an extended period of time, future MISO DER AFS cycles may get impacted.

State interconnection process requires EDCs to provide DER Customers and developers with a definitive timeline. MISO needs to provide such timeline for MISO DER AFS process to RERRAs and EDCs to include it to state interconnection processes timeline.

Screening assumptions

The first main input into the screening is the full injection determination. In the DRAFT MISO Distributed Energy Resources Affected System Studies Business Practices, “Full injection could mean the full DER nameplate or be a lesser value should operational capacity limitations be proposed with adequate assurances. The TO, in concert with the EDC, determines the DER injection level submitted to MISO for screening.” From this language, it is unclear what is meant by adequate assurances. Additionally, since the TO and EDC work together to determine the injection level, it is unclear who is responsible for reviewing and approving the adequate assurances as part of the full injection determination.  MISO needs to provide clarification on “adequate assurances” and acceptance in relation to injection levels that are less than the full DER nameplate. For example, adequate assurances could mean local equipment, SCADA controlled power controls systems, or reverse power relaying.

Will MISO assume full injection of generation DER + storage DER less any house power requirements (i.e. no load scenario)?[3] Customer loads may be highly variable and not coupled to generation. More clarity on MISO DER AFS study assumptions is needed.

DTE recommends Shoulder Peak to be included for distribution solar. Shoulder seasons most likely to have lowest line loading with maximum injection on a sunny day, which may not be an issue for loading, but may be causing high voltage.

Transmission Owner screening

Each DER Customer interconnection request at the substation level will have different commissioning dates, meaning DER will come online at various times in the future. For example, EDC receives three interconnection requests for “Lake Substation”. The first commissioning date is 2023, the second is the 2024 and the last is 2025.  What is the study process for MISO and TO in such a scenario when multiple DERs are proposed for the same DER Substation each with different commissioning dates? How will MISO DER AFS process include projected years and combinations of projects?

MISO needs to clarify whether the one megawatt threshold considers total net change or individual requests. For example, a 5 MW solar DER is studied at location A, but withdraws and is replaced by a different 5 MW solar DER at location B at the same station. Is the new 5 MW solar at location B considered a one MW change? Is the answer different if the changes at locations A and B happen in the same or different MISO DER AFS cycles? Will such change retrigger the AFS fee?

MISO screening

MISO needs to provide clarification on the purpose of MISO screening vs TO screening. Could the Transmission Owner conduct all of the screening and forward the projects that exceed the line loading and MW thresholds on to MISO to be included in the next DER AFS study? The additional screening at MISO may create unnecessary delays for DER customers, especially in the scenario where the DER injection exceeds 0MW but does not exceed the 1% line loading.

Deposit amount and payment methods

The “Study Deposits and Refunds” section of BPM-015 referenced as 2.4.2 in the document, specified incorrectly. The correct section number reference is 4.2.4.

In a case when EDC simultaneously processes multiple DER interconnections to the same substation, DER AFS deposit of $60,000 per substation is assumed independent from the total number of DERs being interconnected to a single substation simultaneously. This clarification would be appropriate in the DER AFS Business Practices white paper.

Modeling assumptions and inputs

MISO needs to clarify how the DER AFS quarterly process will be conducted in conjunction with its generator interconnection queue.  Will the DER AFS projects be included in the updated interconnection models?  What will be the dispatch levels?

DER AFS Report

The whitepaper is silent on how MISO proposes to provide notification to the TO, EDC and DER Customer(s) and other interested parties to view the public and confidential results and start the comment period. The notification process will be critical given the proposed limited comment period proposed.

10 business day comment period may be insufficient to disaggregate MISO DER AFS report, communicate to DER Customers and gather their feedback. DTE proposes an extension of the DER Customers, TOs and EDC comment period from 10 to 20 business days.

Additionally, what specific information will MISO provide that to stakeholders that will allow them to disaggregate the data?

Facilities Studies and Network Upgrades

MISO needs to clarify how will projects with different timing and/or withdrawals be handled in a multi-party agreement[4]?

2. MISO’s proposed high-level implementation plan and timeframe

In the executive summary section of the whitepaper, MISO states that the formal DER process change is being driven by growing DER interconnections with distribution systems across the MISO footprint.  We would like to understand the current volumes along with the growth rates in DERs across the MISO footprint.  The 2022 OMS DER Survey Results are inclusive of injecting DERs and demand respond. The MISO DER AFS white paper excludes controllable load and energy efficiency, which constitutes nearly half of the growth referenced in the 2022 OMS DER Survey Results. Specifically what rate of growth constitutes the transition to a more formal process.  We understand that there is a certain volume of DERs that would warrant a more formal process, but would like more clarity on what volume thresholds MISO is using in it analysis of the need for a new process when current processes are able to support the current volume of DER customers.

DTE appreciates MISO proactively creating a documented process to clearly set expectations with DER Customers, and align EDC, TO and RERRA processes ahead of implementation.

Feedback by Public Service Commission of Wisconsin (PSCW) Office of Regional Markets (ORM) Staff to Midcontinent Independent System Operator (MISO) on the MISO DER Affected System Study Whitepaper. 

Process and technical elements contained in MISO’s DER Affected Systems Study Business Practices Whitepaper 

1. Can MISO please share how it was determined that 5 MW of net injection, and 1% line loading in the 0-5 MW range, are the appropriate thresholds for the AFS? 
2. If a DER interconnection request included a battery or other technology that could absorb MW produced as needed, would that preclude the expectation of screening as net injection could be accounted for?  
3. In the whitepaper, a step allowing the DER customer an opportunity to withdraw their request after the need for an AFS has been identified is not included. If this is presumed to be allowed, MISO should specifically articulate that in the business practices.
4. Could MISO please clarify how many days a TO has to complete a screening after an EDC notifies them that it is warranted? Is it MISO’s understanding that MISO has authority to set the number of days for that process to take place? Figure 2 on page 9 references a due date for a TO cycle screening, but it appears there is not accompanying text in the paper that explains expectations regarding the cadence of such a cycle.
5. Figure 2 on page 9 includes text that says, “Due date for cycle.” Is “Due date for cycle” the cutoff date for the next round of quarterly AFS studies? If so, could you design this diagram so as to not align this step with the end of the 30-day period for the deposit so that the reader can see more clearly that a DER customer may need to wait a certain number of days for the next study cycle to begin, and also clarify the maximum number of days they would need to wait (e.g., 89 days)?
6. Is MISO capable of providing disaggregated results from the AFS? If so, MISO should offer this neutral third-party information to participants given potential tension between EDCs and DER customers. If MISO provides participants with both disaggregated and aggregated results, the EDC could still disaggregate the data according to their own methodology, but all parties involved would have access to a version of the disaggregated data that was done according to the method MISO outlined in the whitepaper. 
7. In the example given on page 11 in the blue box, should the word “net” appear before all instances of the word injection? 

MISO’s proposed high-level implementation plan and timeframe 

1. Does MISO generally expect that EDCs will refer only new DER interconnection requests for TO screening if a study is needed at the distribution level? If so, it would be helpful to see that in writing in the guidance in such general terms, rather than how it is written on page 17. The text on page 17 provides a recommendation specifically for “active” DER applications in the “first DER AFS cycle,” rather than general guidance.
2. How many AFS does MISO predict MISO will complete each year?  
3. Could MISO share numbered steps for the entire process, beginning with the EDC notifying the TO that there is a need for a screening? With so many steps, a detailed numbered sequence would provide readers with more clarity.

The Coalition for Community Solar Access (“CCSA”), Azimuth Renewables, and Trajectory Energy Partners appreciate the opportunity to provide feedback on the Draft Midcontinent Independent System Operator (“MISO”) Distributed Energy Resources (“DER”) Affected System Studies (“AFS”) Business Practices Whitepaper issued on November 4, 2022 (“Draft Whitepaper”). 

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, CCSA and the undersigned respectfully offer the following recommendations and feedback on the Draft Whitepaper: 

1. MISO should revise its proposed implementation timeline to include an 18-month notice period, to allow MISO and relevant regulatory authorities to engage additional stakeholders, initiate state-level implementation discussions, and develop a baseline assessment of grid conditions.

Successful implementation of the DER AFS proposal will require significant multi-jurisdictional coordination and utility preparedness for additional work. CCSA notes the opportunity to learn from experiences in other jurisdictions, where initial lack of preparedness led to excessive timelines that once stifled renewable development and led to major interconnection queue backlogs. For example, similar affected system study proposals in the Northeast have in the past delayed development of over 1 GW of distributed solar.[1]

CCSA appreciates 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. CCSA requests instead that MISO modify its implementation schedule to have the “DER Cycle 1 screening” begin in Q2 2024. [2]

In response to stakeholders who have previously raised this concern, MISO staff have requested specific examples so that they may understand implications. 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. Will need to continue to stay deeply engaged in this study process with regular meetings with relevant Transmission Owners, Electric Distribution Companies, and MISO to track progress and any risk to schedule. 

2. Should commence a proceeding to 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.

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 for determining and administering cost allocation for Network Upgrades to DER customers. 

6. 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.

7. May need to develop protocols for DER developers to challenge the need for network upgrades. 

8. May wish to commence proceedings to explore how to make electric distribution companies’ planning processes flexible enough to mitigate the need for network upgrades and keep costs lower for ratepayers. 

Notably, this work has not yet begun. CCSA is 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. 

Furthermore, the MISO DER AFS proposal itself requires additional stakeholder engagement. Historically, few DER developers have been required to engage in the MISO studies and even fewer have participated in its workgroups.  To date, very few DER project developers have submitted feedback on the proposal as was presented in the Interconnection Policy Working Group (“IPWG”). At a minimum, CCSA recommends that the Draft Whitepaper should be presented during a future meeting of the DER Task Force, and attendees should be invited to offer feedback. CCSA thus requests an 18-month notice period to allow sufficient time for stakeholders to provide feedback and adjust regulations and business processes.  

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. [3] CCSA urges MISO to work with transmission owners (“TOs”) and electric distribution companies (“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. 

3. The DER AFS proposal should clarify that previously-studied projects are not subject to re-study. 

CCSA and the undersigned appreciate MISO’s implementation guidance articulated in the Draft Whitepaper. We understand that only new DER interconnection applications will trigger a DER AFS study and, as MISO states, “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.” 

CCSA remains concerned about impacts to projects that enter the development stage after the MISO DER AFS process is implemented.  This concern is well-illustrated in steps #4-7 of MISO’s “Lake Substation” example, described on page 11 of the Draft Whitepaper. In step 4 of this example, a 0.5-MW project is screened by the TO and moves forward without study. However, a subsequent interconnection request (for 0.75 MW, in step 6) triggers a screening and study of the same 0.5-MW project that had previously been screened and allowed to move forward. In this scenario, the cost and timeline uncertainty experienced by the 0.5-MW project is untenable. Distributed solar projects operate on thin margins and cannot withstand this kind of timeline delays or unpredictable costs. Moreover, an applicant should not be subject to “double jeopardy” that could require multiple studies of the same project and location. Once a project has been cleared in the initial screen, those results should be upheld. 

Furthermore, due to dynamics created by unpredictable costs and timelines, there is a high risk of DER project withdrawal. This is likely to result in a high risk of restudy. CCSA notes that the proposal also does not directly address how project attrition will be captured in the screening or study process. 

To reduce project development risk and related “churn” in interconnection queues, the MISO proposal should include a clear cutoff point for when a project will no longer be subject to delays or costs associated with a MISO DER AFS. CCSA proposes that DERs that have previously been included in a DER AFS transmission owner screening should be excluded from restudy (except to calculate aggregate impacts for screening purposes). 

If MISO declines to exempt such projects, it should instead, at a minimum, increase the “deadband” or buffer size from 1 MW to 5 MW, in order to afford the same consideration to community solar-scale projects as it does to residential projects in the context of re-study.

4. DERs with completed interconnection applications should be excluded from the first MISO DER AFS cycle.

In its implementation guidelines, MISO suggests a “cutoff” point for the DER projects that might be included in its first DER AFS study cycle and recommends associating the cutoff with the EDC’s distribution system impact study. [4]

In the interest of reducing risk to project development, CCSA requests instead that the cutoff point should be associated with DERs that have an interconnection application deemed complete as of the date of the first MISO DER AFS cycle.

5. Additional implementation issues

Cost Allocation for Network Upgrades

The Draft Whitepaper states that an indicative cost estimate for Network Upgrades will be provided prior to beginning a Facilities Study. CCSA and the undersigned request additional details as to how cost allocation for Network Upgrades will be addressed. In particular, we also ask that MISO include implementation guidelines within the Draft Whitepaper that allow DERs to take on a pro-rata share of transmission-level upgrades. 

Tracking and Reporting Guidelines 

CCSA appreciates MISO’s inclusion of specific guidelines covering the DER AFS tracking and reporting information that will be made publicly available. Currently, MISO proposes to provide the following screening results: 

• 1% Screen (Pass/Fail)

• Net Injection (0 – 5 MW) Screen (Pass/Fail)

• Net Injection (greater than 5 MW) Screen (Pass/Fail) 

CCSA supports making this information publicly available. To provide more actionable information for stakeholders, MISO should provide exact screening values instead of “pass/fail” for the 1% and Net Injection screens.  

[1]  See https://www.greentechmedia.com/articles/read/massachusetts-grid-study-disrupts-1gw-distributed-solar-pipeline. 
[2] The Implementation Schedule is included in Table 4 on page 16 of the Draft Whitepaper.
[3] See https://cdn.misoenergy.org/IPWG%20MISO%20DER%20Affected%20System%20Proposals%20Response%20(20221010)626893.pdf at p. 10.
[4] Draft Whitepaper at p. 34.

Signed, 

                   /s/                             
Samantha Weaver
Director of Interconnection and Grid Integration Policy
Coalition for Community Solar Access

                   /s/                             
Ethan Case
Vice President of Development
Azimuth Renewables

                   /s/                              
Josh Bushinsky
Partner
Trajectory Energy Partners

MidAmerican Energy Company appreciates the opportunity to comment on the Draft MISO Distributed Energy Resources Affected System Studies Business Practices Whitepaper. MidAmerican’s feedback reflects our role as both a MISO Transmission Owner and as an Electric Distribution Company administering DER interconnection requests in Iowa, Illinois, and South Dakota.

MidAmerican proposes that MISO limit the requirement for performing DER Affected System Studies (AFS) to DER interconnection requests larger than 1 MW to focus MISO, Transmission Owner (TO), and Electric Distribution Company (EDC) resources on those DER projects more likely to impact the transmission system.

The majority (>99%) of DER interconnection requests are for projects smaller than 1 MW requesting interconnection behind an existing retail customer electric service. These retail customers do not control which substation they are fed from and are typically installing DER for self-use (most often to participate in net metering programs) and not to participate in a MISO market. Any impact these small customer DER have on the transmission system is incidental and analogous to the normal fluctuations in customer load that is captured as part of the annual load data acquisition for power flow model building.

DER interconnection requests larger than 1 MW are more likely to be stand-alone resources not connecting behind an existing customer electric service (e.g. community solar projects) although some larger commercial or industrial customers request DER interconnections of this size. Because stand-alone resources do not need to connect behind a specific existing electric service, they have freedom to choose their proposed point of interconnection based on other factors. MidAmerican’s experience is that developers of stand-alone DER projects often look at rural areas where presumably they can acquire a large amount of land for a more affordable cost and receive the necessary land zoning classification to allow for the construction of their project. This can lead to the clustering of large DER projects connecting to lightly loaded rural substations. These are the substations MidAmerican would expect to see backfeeding onto the transmission system and where we think adverse impacts on the transmission system are most likely to be identified in MISO AFS.

A difficulty MidAmerican sees with MISO’s current proposal for the Transmission Owner screening of DER interconnections described on page 11 of the draft whitepaper is the need to track the cumulative addition of small DER to determine when the 1 MW dead band limit is exceeded and an additional MISO AFS is required (MISO example steps 4 through 7 on page 11). The process as it is currently described does not provide certainty for Interconnection Customers, the EDC, and the TO to know when a MISO AFS may be required. Whether or not a project will need to participate in a MISO AFS needs to be known after the EDC has completed the load screening and before the generator interconnection agreement (GIA) is executed. Once an EDC has signed a GIA with a DER customer, we cannot go back and assign them upgrades later per the state interconnection rules. We cannot tell them they have an open ended obligation and may be subject to an AFS and potential upgrades in the future at some unknown date if additional DER connects to their same substation and they end up in a group of projects that causes the 1 MW dead band limit to be exceeded (MISO example step 7 on page 11).

MISO’s current proposal could result in a situation where a small residential or commercial customer DER project causes the 1 MW dead band limit to be exceeded and is responsible for funding the MISO AFS because other higher queued DER projects connecting to the same substation already have executed GIAs and cannot be assigned additional costs. The proposed $60,000 AFS study deposit could be larger than the total cost of a small DER installation. It is not just and reasonable to assign these costs to a small DER customer given their limited impact on the transmission system.

Limiting MISO AFS studies to DER interconnection requests larger than 1 MW eliminates the need to track when the 1 MW dead band limit is exceeded and allows EDCs and TOs to clearly communicate to the DER Interconnection Customer at the start of the interconnection process whether or not they could be subject to a MISO AFS. Implementing a larger than 1 MW size threshold for DER subject to MISO AFS screening does not require changes to MISO’s proposal to consider all DER connected to a substation when performing the AFS.

To eliminate potential gaming of the 1 MW AFS size threshold, MidAmerican proposes that MISO include wording to prevent such practices and provide EDCs and TOs the discretion to determine whether or not multiple DER interconnection requests smaller than 1 MW near the same point of interconnection on the distribution system constitute a single project if they share the same owner, developer or contacts.

The Environmental Sector submits the following comments regarding the MISO DER Affected System Study Whitepaper (hereinafter, “Whitepaper”):

Jurisdictional Issues

On page 12 (below Figure 3), the Whitepaper states, “The TO may invoice the EDC or DER Customer directly, depending on the RERRA interconnection rules and TO utility structure.” 

We suggest that the above quoted sentence should be changed to the following (or similar): “The TO may be reimbursed for any DER AFS Costs^[1] consistent with RERRA regulatory requirements and TO utility structures.”

First, for clarity’s sake, and for the same jurisdictional reasons referenced below, we agree with MISO that TOs are the correct entity from which MISO should be collecting payment for applicable DER AFS fees.

However, although MISO correctly identifies the jurisdictional dynamics that limit its ability to extend its DER AFS requirements into certain RERRA jurisdictional processes, MISO should still refrain from suggesting any particular downstream process that is under RERRA jurisdiction. Furthermore, MISO is not in contractual privity with DER Customers, and while the language quoted from the Whitepaper above is permissive (using “may”), MISO should be careful from suggesting particular processes that may not be enforceable in some situations, even when such suggestions are coupled with caveats.

By not indicating a particular reimbursement mechanism, our suggested change also helps expand the perception of options that may be available for the collection and reimbursement of such funds. For example, one RERRA might decide to institute a flat fee system to spread the costs of all DER AFS-associated fees and network upgrade costs (together, hereinafter “DER AFS Costs”). As another example, another RERRA may create project size minimums that must be cleared before a DER Customer may be subject to any DER AFS Cost reimbursement responsibilities. Keeping the language as it exists in the current draft risks creating the perception that there is a preference for how DER AFS Costs should be recovered, and may make it more difficult for individual RERRAs to institute cost recovery systems that are more appropriate for their respective jurisdictions.

RERRA Regulatory Impacts; Implementation Timelines

While we acknowledge that RERRAs are already doing this, we also ask that MISO consider including a suggestion that RERRAs examine the impact of MISO’s proposed DER AFS process on existing rules and regulations to ensure that MISO’s DER AFS process does not result in any unintended consequences. This is consistent with the manner in which the Whitepaper describes the cutoff point associated with determining whether DERs currently in development are or are not included in the MISO’s first DER AFS cycle (see page 17).

In this regard, we also suggest that MISO work with RERRAs to ensure that the onset of new DER AFS rules give RERRAs sufficient time to implement any regulatory changes that may be necessary as a result of new DER AFS processes. Currently, MISO is proposing six months between when the new BPM would be effective and the start of the first DER AFS study cycle. This is likely not enough time for all RERRAs to institute any needed changes within their respective regulatory frameworks, and we ask that MISO (to the extent it hasn’t already) consult with each RERRA to confirm what implementation timeline would be most appropriate.

DER Size Thresholds

In contrast to the above points, and to the extent it is within MISO’s jurisdiction (we acknowledge that it likely is not), MISO should institute a minimum DER project size for inclusion in any DER AFS Costs. The DER AFS timeline may needlessly delay the installation of smaller DERs, such as those used in the residential context, by wrapping in such relatively small projects into a process designed to capture the impacts of larger, often investor-owned, DER projects. Likewise, certain jurisdictions have interconnection processes designed to be shorter than that of the DER AFS Study process currently being proposed.^[2] Additionally, the extra costs associated with DER AFS may be overly burdensome for some customers, especially in the residential context. A minimum project size threshold, if designed appropriately, could eliminate cost uncertainty and undue delays for smaller DER projects, e.g. less than 100kW.^[3] Similarly, smaller projects, when combined with a much larger project, may end up paying a disproportionate share of total DER AFS Costs if combined on a pro rata basis, and we encourage MISO to focus cost reimbursements on those DERs that are anticipated to have the greatest impact on the transmission system. We encourage MISO to continue any conversations it may have with state regulators with respect to how any of the above impacts may be avoided.

Clarifications Regarding Existing DERs

The section entitled, “Implementation guidance for EDCs and RERRAs,” on pages 16-17 of the Whitepaper, could still benefit from a little more clarification. In that regard, we ask the following:

• Please confirm that existing, fully interconnected and operating DER projects will not be subject to DER AFS Costs. While we understand that existing DERs must be included in any DER AFS study triggered by a new DER project, we would like clarification that existing DERs will still not be responsible for any resulting DER AFS Costs. While this idea is suggested in this section of the Whitepaper, it does not appear to be explicitly stated. 
• In a similar vein to the above point, please confirm that when a new DER has gone through a DER AFS cycle that may or may not result in any costs, that DER will thereafter be exempt from any new costs that stem from or are identified in future DER AFS cycles. 

Reporting Information

In addition to the items listed on page 16 of the Whitepaper, we suggest that MISO provide the detailed “line item” level billing information regarding DER AFS invoices directly to all relevant parties upon request, including individual DER interconnection customers. Providing cost transparency will ensure that DER Customers understand what they are paying for, understand what they might expect in future studies in terms of effort and cost, and aid in the decision making process on whether or not new DER investment makes sense.

Stakeholder Engagement

At the October DERTF meeting, it was abundantly clear that many stakeholders who are focused on DER issues were caught off guard by the DER AFS proposal being discussed at IPWG. While we recognize that MISO had made efforts to inform stakeholders outside of the IPWG process that such discussions were taking place, the reality is that this notice did not strike home, and those stakeholders that are very interested in DER issues are only recently factually aware of the proposed DER AFS concept. As such, we encourage MISO to seriously consider the impacts this communication misalignment has had on developing an inclusive DER AFS process that best considers the perspectives of all MISO stakeholders, and then act on that consideration.^[4]

SunPower appreciates the opportunity to provide feedback on the Draft Midcontinent Independent System Operator (“MISO”) Distributed Energy Resources (“DER”) Affected System Studies (“AFS”) Business Practices Whitepaper issued on November 4, 2022 (“Draft Whitepaper”). We support efforts to preserve the reliability of the electric transmission system under MISO’s oversight and recognize that the intent of the Draft Whitepaper is to ensure adequate transmission capacity. SunPower believes that MISO’s goals can be attained without jeopardizing the progress made in bringing the benefits of DER to consumers and the electric grid.

About SunPower

SunPower is an American company established in 1985. We provide American residential consumers with the bill savings and resiliency benefits of distributed solar, battery storage, and electric vehicle (“EV”) chargers, and utilize these technologies to provide electric grid services. We also provide consumers with associated financial products, including loans and equipment leases, to enable access to this critical technology. SunPower is committed to diversity, equity, and inclusion as exemplified by our industry-leading 25x25 Initiative. This initiative is designed to ensure the benefits of distributed solar and storage serve all Americans.

SunPower currently serves more than 440,000 U.S. residential customers. Our business represents 11% of the total U.S. residential solar market. We employ approximately 2,000 employees in 10 states and the District of Columbia in addition to the 2,000+ employees and contractors who work for Blue Raven Solar, a company wholly owned by SunPower, that does business in 40 cities across 21 states. We also work with a robust network of more than 700 dealers – primarily independent, small businesses - located in 45 states who, collectively, employ more than approximately 14,000 people. SunPower and/or our dealers are licensed to do business in 49 states plus the District of Columbia.

Demonstrative of SunPower’s position in the U.S. solar market are our recent business partnerships with General Motors (“GM”), KB Home, First Solar, IKEA, and OhmConnect. The SunPower-GM collaboration may be of interest to MISO. This collaboration includes developing a new home energy system that will enable GM EVs to provide backup energy to a home when properly equipped. SunPower is GM’s preferred EV charger installation provider and its exclusive solar provider. This collaboration brings together SunPower's home energy expertise and installation capabilities with GM's leadership in EV and battery technology to help provide customers with more resilient, sustainable, and cost-effective energy.

The Impact of the Draft Whitepaper on Residential Solar

SunPower, as one of the largest providers of residential solar, battery storage, and grid services in the United States, offers comments focusing on the potential impacts of the Draft Whitepaper’s proposals on residential DER.[1] Residential rooftop solar represents a large portion of energy deployment in this country and a quickly growing part of our national economy.  Residential solar accounted for 29% of all installed solar capacity nationally in the second quarter of 2022.[2] As written, SunPower is concerned that the proposals in the Draft Whitepaper could impair consumers’ ability to save money, improve their own energy independence, and help reduce carbon emissions through behind the meter (“BTM”) DER, as well as hamper state goals to increase renewable energy production.

SunPower’s specific concern is that the Draft Whitepaper contemplates even a small residential (both single-family and multifamily) solar or solar + storage installation seeking interconnection with the electric distribution system triggering the need for an expensive and lengthy AFS of the impact on a substation and the electric transmission system. While MISO conducts the AFS, which could take at least 145 days, no additional residential solar or solar + storage interconnections could occur on the distribution circuit connected to the substation in question. Moreover, the Draft Whitepaper proposes collecting a $60,000 deposit from the entity seeking interconnection, which could be a homeowner.

SunPower submits that such a burden on homeowners seeking to install solar is unwarranted and will effectively prohibit any residential solar installations on distributions circuits connected to substations nearing the threshold triggers reflected in the Draft Whitepaper. SunPower urges MISO to include an express exemption in the final DER AFS Business Practices for residential solar and solar + storage installations connected to the distribution system. Single-family residential systems, the vast majority of which are less than 25 kilowatts (“kW”), often fall under fast track interconnection procedures because of their limited impact on distribution circuits, let alone any impact on substations and transmission lines. MISO’s own Generator Interconnection Procedures provide in Attachment X: Appendix 4 a streamlined interconnection process for DER no more than 10 kW seeking interconnection to the transmission system.

With the drive to electrify the transportation and energy system in the United States, SunPower also suggests that MISO consider increasing the size of what it characterizes as small DER. While 10 kW still accommodates many residential installations, states within the MISO footprint have begun to consider larger systems as still being within the category of small DER for net metering and other purposes.[3]

The impediment the Draft Whitepaper poses for BTM residential systems is also a hindrance to state decarbonization efforts. States within MISO’s footprint have adopted in various forms decarbonization requirements and goals.[4] Empowering residential customers, and increasingly low-income and historically disadvantaged customers, to assist in decarbonizing our energy sector and benefit from BTM DER is often a crucial and necessary element of state plans. Exempting residential BTM solar and solar + storage installations will protect consumers and facilitate state decarbonization efforts without impairing MISO’s objectives.

SunPower thanks MISO for considering its requested limited exemption for residential solar and solar + storage installations for single-family and multifamily properties and welcomes further opportunities for input.

Sincerely,

Suzanne Leta

Senior Director, Head of Policy and Strategy

SunPower

Entergy Operating Company Feedback on MISO DER Affected System Study Whitepaper.

December 9, 2022

The Entergy Operating Company[1] (Entergy) appreciate the opportunity to provide feedback on MISO’s DER Affected Systems Study Business Practices Whitepaper, discussed at the November 14, 2022, IPWG. 

The comments below focus on the Process and Technical elements contained in MISO’s DER Affected Systems Study Business Practices Whitepaper, and are consistent with concerns raised submitted by the Transmission Owners (TOs) in the context of Order 2222 implementation, which essentially explained that a TO is not involved in the study of one a DER or a DER Aggregation until the interconnected EDC/Distribution Planner alerts the Owner that there is a potential impact to the Transmission System due to the impact of one or more Distributed Energy Recourse behind the point of interconnection to that System.[2]  These comments are relevant here, because MISO’s proposed quarterly Affected Systems Study process is essentially a study of aggregated DERs behind a single bus, which is the same level at which a DER Aggregation is permitted to participate under MISO’s Order 2222 Compliance Filing.

 Technical elements contained in MISO’s DER Affected Systems Study Business Practices Whitepaper

DER Modeling – Consistency and Transparency is needed:

MISO identified in their White Paper that they are counting on a revision to the NERC MOD-032 standard as part of the identified process for DER.  

On Page 8l, MISO refers to “NERC’s recent Project 2022-02 to revise NERC Standard MOD-032-1.21” and states that MISO views this effort as, “the most appropriate venue to enable uniform DER modeling data collection requirements across the MISO footprint and industry.”  While MISO also states that “the DER AFS process does not seek to address existing modeling issues,” has MISO considered how the proposed AFS process will be impact or be impacted by the ongoing work in the MOD-032 Users Group to move from voluntary reporting of DER information by resource type at the bus-level to mandatory reporting of this information?  

Going forward, it is important that there is consistency in planning model assumptions and the Affected System Study Assumptions, and the planning models are the most appropriate source for this information, but the MOD-032 User Guide needs to be revised to make clear that the responsibility to submit DER information into MOD is assigned to the Distribution Provider (DP), which does not consistently occur, but should not fall to the Transmission Owner by default.  Transparency in the how these resources are modeled is important in the overall stakeholder process, and this can not be overlooked as MISO’s DER policies evolve. 

There are multiple places among MISO’s Tariff, BPMs, and User Guides that impact DER modeling practices.  These should be evaluated collectively by MISO with a go to ensure and consistency and transparency among them all.

Proposed DER Affected systems screening and study process

Related to the comments above:

Page 9, Figure 2 ”Illustration of DER AFS timeline view” states:

“TO submits DER Substation Information to MISO.”  Entergy recommends that MISO insert the addition underlined below:

“TO submits DER Substation and relevant EDC contact to MISO.”

“MISO invoices TO study deposit for each DER Substation exceeding criteria.“  Entergy recommends that MISO include the underlined additions below:

“MISO invoices the EDC for the TO study deposit for each DER Substation exceeding screening criteria.“ 

On Page 14, the DER AFS data exchange introduction states:

“… DER modeling information includes: (1) Substation name and associated transmission bus number; and (2) DER capacity, in megawatts, categorized by the fuel types found in BPM-015.”

• Is, or will the DER modeling information submission process for these studies be defined in the publicly posted MOD-032 User Guide?  If so, this should be specified in the DER Affected Systems Study Business Practices, and if not, the model data submission process should be described in another guidance document that is accessible to all stakeholders, and it should be clear how the information submitted in this process will be treated in MISO’s other planning models.

Rather than waiting on NERC to revise Industry Standards, MISO should modify its own processes to facilitate obtaining the data from the party who is responsible for it, the Distribution Providers (DP or Electric Distribution Company, EDC), resulting in improved modeling accuracy, and allowing all entities with access to the model to use consistent dispatch assumptions.  DER entities provide both their connection location and their unit data to the DP for their necessary distribution connection studies,and requiring a TO to provide this information to MISO, rather than requiring the DP to put the information into MOD is not consistent with the current data submission requirements in the MOD-032 User Guide.  This discrepancy in process puts the TO in the position of middle-man for the information that should already be accessible to MISO and creating both an opportunity to introduce errors and delays in the process that could result in data errors that would become the responsibility of the TO, rather than the data originator.

With respect to when the initial study is triggered, the DP is also the entity best positioned to identify which DER customers are considered “new interconnections” requiring consideration in an Affected System study by MISO.  The DER owner works exclusively with the DP to provide the necessary technical information to be evaluated and to fulfill the DP’s connection requirements and the DP has full visibility into DPs system which must be communicated by the DP when an Affected System Study or Screening is needed. 

Regarding the Transition to this new process, Entergy encourages MISO to pause the application of the new process until these questions have been addressed and there is a clear understanding of who is responsible for providing DER data in MISO’s planning models, given the slow progress of NERC standard revision effort.

 Study Costs described on Page 13

As described above, DPs are in the best position to have situational awareness regarding when an interconnecting DER triggers an Affected System Study and which DER(s) should be involved in it, For this reason the DP is the more party appropriate for to be the party to receive the bill from MISO for the study costs rather than the TO.  As identified on page 18 of the MISO White Paper, also referenced below, MISO proposes that the TO act as a billing agent for MISO, and pass the study funds to MISO, which would again, put the TO in the middle of this process and add cost and delays to the process. 

due to the significant time and personnel costs that would be required to be recovered by the TO, and for which no recovery mechanism has been contemplated.  If the TO cannot recover these costs from the DP or DER, then their transmission customers will pick up the tab and this is inappropriate cost shifting, and this is a significant risk under the prosed 30 day turn around requirement, which could lead to a TO beginning work on a study related to a DER Interconnection request that may be withdrawn before the Study Deposit is ever paid.

Modeling assumptions and inputs on Page 14

This section states, “MISO selects the latest DPP Phase 3 model”.  More detail is needed in this section, such as:

• Clarifying the “latest phase 3 model” as the one under study or from a completed phase 3.
• Whether identified DPP network upgrades will be included in the model.
• If withdrawals by one DER in a study that included multiple DERs would trigger a re-study?

Has MISO considered whether the latest Phase 1 base case model may contain more recent modeling assumptions regarding load and approved Network Upgrades, and thus may be more appropriate for this analysis, given the staleness of data included in a DPP study that began years prior to the DER AFS?

Page 15

DER AFS Report

These Business Practices should specify that the TO will be involved in the DER AFS report drafting and will have the opportunity to review the draft report prior to posting of public and confidential reports.

• Please also include “TO review the draft report before public posting” in the Swimlane Diagram on page 18 to reflect the comments above and would be consistent with MISO’s indication on the flow chart that the DP or EDC would be responsible for reconciliation of the costs of the System study, which Entergy supports because these entities are familiar with any state jurisdictional rules regarding a pass through of these costs to the DER entities. 
• To the extent thatMISO can provide any information in the System Impact Study Report regarding the possible allocation of these and any resulting Network Upgrade costs, MISO should do so. 

Facilities Studies and Network Upgrades – timing of Study

This section states, “MISO proposes that the TO return the Facilities Study agreement and deposit within 30 business days of MISO issuing the final DER AFS Report.”

• While this section is describing the agreement that would be needed once the need for Network Upgrades has been identified, please refer to the comments above in reference to Figure 2 on Page 9, suggesting that Study Deposits be collected from the relevant EDCs identified by the Transmission Owner, as the EDCs are essentially in the role of the Interconnection Customer. 
• If the TO is expected to deliver the Facilities Study deposit to MISO for the Study that the TO will be contracted to perform under the referenced Agreement, MISO will need to provide more time for the Owner to collect these funds from the relevant EDC.  It would be more efficient for MISO to receive the study funds from the relevant EDC contacts provided by the TO, while the TO uses this time to work on the necessary Facilities Study Agreement(s).
• The whitepaper did not specify the deposit amount for the Network Upgrades Facilities Study or whether the $60K deposit in the AFS would continue to cover the FSA if there are any funds remaining following the AFS?

Affected System Studies – Other Considerations

MISO should also consider if there are situations that could require coordination between the DER and DPP processes, and how such situations will be managed should be included in the related Business Practices.