IPWG: MISO DER Affected System Proposals (20220815)

MRES disagrees with changing the DER affected system study criteria from (5 MW net-injection and 1 % line load change) to (5 MW net-injection or 1 % line load change) as this will cause an unnecessary burden on both DER interconnection customers and MISO Transmission Owners especially on Appendix G facilities. Appendix G facilities can have very low ratings and a 1% line load change threshold could be very low. For example on a 40 MVA line it would only take a 400 kVA change in flow to trigger the affected system study. MRES strongly recommends changing the criteria back using “and” logic.

MRES also questions if MISO has the jurisdiction to require affected system studies for generators that do not have a net injection onto the transmission system. The generators are not using the transmission system or service, therefore, should not be subjected to MISO studies.

MRES also disagrees that the burden to gather and provide DER information to MISO should be put on the MISO Transmission Owners. For example, there is nothing in the Minnesota Distributed Energy Resource Interconnection Agreement that requires Area EPS Operators to coordinate with MISO Transmission Owners. It would be far more efficient and effective for MISO to go right to the Area EPS Operator for DER information.  MISO has more of a relationship with Network Customers/LSEs through the NITS agreement which specifies the need for load and generation information (i.e. load forecasts, designated generation, etc.) as opposed to the TO which may just have an interconnection agreement that likely does not address load or generation at all.

TO Feedback on DER Interconnection @ IPWG

The TOs appreciate that DERs are a new frontier for MISO and that many details must still be worked out.  We appreciate the opportunity to provide feedback on the most recent MISO proposal discussed at the August 15, 2022, IPWG.  Some of our comments below also apply to the earlier MISO IPWG presentations because the feedback response provided did not sufficiently address some TO’s concerns.  Overall, our position is that reliance on the TOs to be responsible for the data and study deposits is not appropriate for the reasons discussed below.  We hope that MISO will rethink these initial proposals and discuss alternatives with the stakeholders to find more appropriate solutions. 

Part I:  TO Provision of DER Data

In addition to responding to the four specific questions MISO requested for this feedback, the TOs continue to offer comments on DER technical data specifications discussed at the June IPWG and have identified an new issue not yet considered. 

Additional Feedback June 6^th:  DER Technical Data Specifications

In MISO’s response to the June feedback request, they stated they do not want to introduce a tiered approach to the DER process, but they have specified the TOs as the party responsible for obtaining data on the types and sizes of DER entities connecting to LSEs.  However, the only entity who would have the detailed information to identify who the DER entities are and where they are connecting to the electric grid are the LSEs.  However, the current MISO MOD-032 process specifies that the LSEs are responsible for providing the load records for each substation including not only the loads but also the amount and types of DER.  The LSE, not the TO, has a record of what types of units have been studied and where they have connected.  MISO’s preference for working directly with the TO is understandable for the sake of simplicity but is not feasible as the TO may not have access to this data. 

In addition, MISO’s idea of holding the TO responsible for the data for the Affected Systems Studies has the potential for introducing error into data through either a transposition of information or missing entities completely that should be included because the TO may have no current business relationship or direct knowledge of entities connecting to an adjacent distribution system.  All studies to be performed by the TO will be as if they are also an Affected System not just as the entity to which DER unit is connecting.  MISO’s desire to minimize MISO’s efforts is understandable but requiring a TO who has no relationship with the DER owners to manage information required by MISO is also unreasonable.  

MISO Question on modeling selection and dispatch assumptions and type of analysis selected

Once the Affected Parties begin performing studies, both MISO and the TOs will need to reach an agreement on how these studies will be performed.  The TOs have the following concerns:

• While MISO has proposed using Summer Peak loading for facilities reaching 5 MW injection for screening, DER from solar facilities reaches its peak output at hours later in the day when loads may be lower.  MISO should consider a percentage reduction in load from summer peak to assess screening DER solar resources for the 5 MW net injection criteria. 
• Both MISO and the TOs need to identify which year’s load forecast will be utilized when assessing the 5 MW net injection for both Summer and Shoulder Peak. 
• The treatment of DER injection at a substation where a load reduction occurs in the future where DER has met the injection criteria and now increases due to the load reduction needs to be determined.  Would the net DER be limited or would a restudy be initiated?
• The TOs have a question on the treatment of transmission system constraints that are identified but fall within MISO’s 1 MW dead band.  While MISO will not initiate a study until a 1.0 MW threshold has been passed, a TO constraint may have been exceeded.  Would MISO limit the injection or assign the costs of any projects needed to mitigate the constraints in the interim?

MISO question on study process components, including the 90-day timeline for DER study

MISO plans to utilize the latest Phase 3 model for the DER studies.  The TOs have a number of questions:

• Will ERIS and NIRS generation in those models be dispatched to their ERIS and NIRS levels to show the full impact of all generation? 
• Will DER generation be dispatched in future MTEP, Generator Deliverability and DPP studies? 
• Will MISO and the TOs be studying all DER injections in one study to show a full system impact of DER injections on the grid or is MISO planning to look at injection sites one at a time?

In our experience, it would be virtually impossible for a TO to process and identify a location requiring a study to an EDC/LSE, have them identify the list of DERs along with all of their contact information, collect all of their technical information from the DER entities, and transmit this information to MISO all within the proposed 90 day study time frame time.  This time period also does not consider the internal processes the DERs may have themselves for assembling the required data and submitting it to the TOs.  While this may sound reasonable on paper to MISO staff and other stakeholders, it does not comport with a good engineering practice. 

There is a great deal of information necessary to coordinate between MISO, the TO, the LSE, and the DER prior to kicking off a DER study once it is determined one is necessary.  Due to this, the 90-day time frame is likely to be too short.  We recommend that potentially 120 days or more should be explored. 

New issue:  considerations of existing DERs

One item that MISO has not yet discussed is how their process will accommodate DER entities that have been connected to the LSE systems for years already.  These entities may contribute to the need for an injection study.  They however are not the drivers causing one as they were studied years ago when they were initially connected.  MISO should weigh in on what specific treatment should be made for these entities.

Part II:  TO Provision of Study Deposits Within 10 Days

In the June IPWG discussion, MISO’s proposal generally represented that the TO would be the entity responsible for invoicing the DER for the study deposits, collecting the funds, and providing those to MISO all within a 10 day time periods.  The TOs understand that MISO might not want to accept this administrative task and instead would prefer some other entity be responsible.  However, as stated in some TOs individual feedback, this assignment to the TOs is both inappropriate and the time frame suggested is unworkable. 

On further review, it is apparent that MISO’s June 6^th presentation language does not clearly define exactly who is responsible for invoicing and study deposit payments.  For example:

• Slides 9 & 10:  MISO suggests that either the TO or the EDC would invoice the DER customer.
• Slide 10: MISO proposes that the TO would be responsible for aggregating and disaggregating funds to the EDCs and/or DER customers at each substation. 
• Slide 11: MISO clearly states the TO has 10 days as a deposit timeframe. 

However, in response to some individual TO feedback, MISO’s response makes it clear that the TO will be held responsible because MISO expresses concern about an undefined concept of “… “tier-bypassing” where information flows skip around a tier of the power system hierarchy….” We reiterate that there are several reasons for MISO to rethink the original proposal. 

The reality is that it would be virtually impossible for a TO to process an invoice generated by MISO, delivery it to one or more DERs, collect study deposit funds from them, and transmit those funds to MISO all within 10 business days.  This time period does not match with accounting conventions which have numerous fiscal safeguards and requirements.  Further, it does not consider whatever internal processes the DERs may have require.  While this proposal may sound reasonable on paper to MISO staff and other stakeholders, it does not comport with accounting practices.  

One TO researched this carefully with their accounting department and that accounting process is illustrated below.  The 10-day turnaround for TOs to retrieve study deposits from DERs and then give those deposits to MISO is unattainable, and that TO estimates that the process will need a minimum of 45 days to complete, given their internal accounting processes and an estimate of the DER’s own internal accounting processes.  It’s important to note that the number of DERs involved in a specific study is not known, it could be one or many, all with their own internal accounting processes that could require different processing time periods.  Further, MISO will need to determine the split of costs between individual DER interconnecting, as the TOs will not have the necessary information.   

While accounting practices will vary among TOs, the description below provides further insight into why a 10 day process is not feasible. 

MISO DER Affected Systems proposal- ATC Comments to MISO                                                 Sept 9, 2022

• Please clarify how the screening process should be applied in the shoulder cases?
  • Besides the summer peak, the proposal also requires Transmission Owners to apply the 5 MW injection screening process to shoulder peak on a different DER fuel types (solar, storage, wind, hybrid, waste heat, hydro).  However, it is likely there will have multiple fuel types DERs (existing and new) connected at one interconnection point. 
  • Please clarify how an upgrade is identified and how the cost gets allocated.
    • The scenario for this question is a DER is studied with no upgrades identified and then in the next study having an additional DER at the same feeder/substation which caused the need for an upgrade.
    • Please clarify the MISO response that local jurisdiction would dictate the cost allocation.
    • Please clarify how the MTEP processes will maintain equitable treatment to both DPP and DER stakeholders and will coordinate the DPP and DER in circumstances where one process may appear to have a shorter schedule to completion. 
      • There is some concern that the subsequent DPP generators could either lead to DPP generators getting assigned to an upgrade due to the increased DER flow or missing the DER flows in the DPP cycle models if they aren’t added in the DPP process at the appropriate time during the DPP model building.
      • Please clarify how MISO would manage the model assumptions when the accumulated 5+ MW DER is mixed with existing and new DER on one interconnection point. 
      • Please clarify the justification to not require stability analysis.
        • NERC has several reports where DER tripping has at least contributed to large events in CA. SPIDERWG has had a lot of discussion on the effects of DER tripping on FIDVR.
          • In WI ATC will continue to see wholesale tripping until IEEE 1547-2018 is adopted by the PSCW.
          • Requiring stability analysis would incentivize stakeholders to provide accurate and appropriate models when they are needed.

Azimuth Renewables appreciates the opportunity to provide feedback and looks forward to working with MISO to implement key changes.

Azimuth Renewables has developed dozens of solar farms connected to the distribution system within MISO and currently has hundreds of megawatts moving through the interconnection process with MISO distribution utilities.

Azimuth has the following comments for requested feedback:

Process certainty (i.e., DER withdrawal study implications)

Azimuth’s greatest concern is how any process change will impact projects currently under study and development. A quick process change without sufficient notice could have major cost and project timeline impacts upon many projects under development. This is particularly true for projects that have security deposits and penalties associated with commercial operation date deadlines. A quick process change at MISO that adds additional cost and time, or even potential cost and time, would be severely disruptive to these projects and businesses.

To address the issue of impacting current projects under development, Azimuth strongly recommends that any DER Affected Systems process changes be applied on a prospective basis. Ideally, MISO should provide at least eighteen months notice to local utilities, state regulators, and DER companies before making a finalized DER Affected Systems process change effective. Any projects that have applied at the distribution utility level for interconnection prior to the effective date of a change should be grandfathered into existing MISO’s distribution interconnection process as laid out in MISO’s current Distribution Interconnection Request Instructions.

Azimuth Renewables estimates that tens of thousands of projects representing gigawatts of new generation additions may be impacted by the proposed process shift. While there appears to have been some discussion of potential impacts during the February 7^th meeting, the materials and discussion to date do not appear to offer an assessment of the magnitude of impact of the proposed new screening criteria or the proposed DER Affected Systems study process. Azimuth recommends that MISO staff collect data on the total number of distribution interconnection applications within the MISO footprint for the purposes of assessing the magnitude of impact of the proposed changes.

Achieving process certainty requires that all stakeholders in the entire DER interconnection process, and not just stakeholders involved in the proposed MISO DER Affected Systems process, should be fully informed of this process change prior to any finalization and implementation. Azimuth strongly recommends the IPWG explicitly solicit input from the DER Taskforce before the proposal is finalized.

Azimuth’s understanding is that the IPWG’s current proposed approach is to require TOs carry out MISO’s proposed change, including developing and applying new cost allocation methods to DER customers, while requiring all other entities involved in the DER interconnection process to adjust local processes in response to the TO and the proposed changes at MISO. While this approach is fully appropriate from a MISO jurisdiction perspective, there are many practical challenges of implementation that should be considered. Some of these challenges include the need to adjust local interconnection rules at state commissions (an issue previously raised by MISO), the need to inform businesses that have not historically interfaced with MISO, the need for TOs to develop and potentially seek state regulatory approval for new DER system upgrade cost allocation methodologies, and the need to inform end users of DER technologies. We estimate that 18 months will be sufficient to allow stakeholders to become informed and adjust local rules and business practices to accommodate this change at MISO. Failure to provide time for local entities to adjust to a change in MISO rules will lead to a great deal of process uncertainty for many entities.

Azimuth Renewables believes that more information about the current status of MISO’s current Distribution Interconnection Request process is important to inform this work. Information such as where historical requests are arising, how many requests MISO has received for Distribution Interconnection Request screens and studies in the past three years, and how many requests MISO anticipates receiving in the future. Azimuth agrees with previous commenters who suggested that the current level of injection from the distribution grid to the transmission system may or may not merit a MISO-wide process shift at this time.

Azimuth Renewables is concerned about the potential for interconnection process delays resulting from tighter screening criteria that will result in a much higher volume of interconnection requests. Azimuth would like to see a specific organizational plan, including staffing and budget support plans, for how MISO intends to avoid organizational delays faced by many other entities administering interconnection studies during periods of sudden increases in study volumes. In our experience, interconnection process rules are almost always a secondary concern relative to the organizational plan to do the actual work of studying new requests within a reasonable time frame.

Azimuth Renewables would appreciate a cited reference list of specifically what Business Practice Manual and/or tariff changes that MISO is proposing to make.

With respect to how to handle a proposed DER Affected Systems study withdrawal scenario, Azimuth strongly recommends further developing a proposed process redline before tackling this issue. More reliable study cost information, proposed DER study timelines, and views of how TOs may apply varied local cost allocation methodologies for system upgrades are required for meaningful feedback for a MISO-wide process shift. Azimuth recommends soliciting feedback from the DER Taskforce so that industry segments and business that may have dozens or hundreds of smaller rooftop projects impacted by study withdrawal scenarios provide input.

Model Selection and Dispatch Assumptions

Prior to finalizing model selection and dispatch assumptions, Azimuth would like to see the core cost assumptions underlying the proposed screening and proposed DER Affected Systems study objectives outlined and discussed. This effort, and accompanying modeling parameter selection, appears to be guided by the assumption that distribution connected generators studied under the current process are a net cost causer per OCMS cost allocation principles. Azimuth Renewables has not seen convincing evidence that such a cost shift is actually occurring on all parts of the MISO system. A more holistic cost/benefit analysis to test and elaborate upon the underlying cost causation assumptions being used to justify the proposed MISO distribution interconnection process changes would be helpful in framing screening and study objectives. Additionally, addressing objectives in addition to reliability concerns, such as addressing congestion being attributed to distribution interconnected resources, should be considered and reviewed by stakeholders before embedding these objectives into MISO processes.

Azimuth believes that screening and modeling differences in ERIS vs. NRIS interconnection service requests, especially for larger distribution interconnection service requests, is extremely important. Ahead of screening for potential studies or studying for potential upgrades, TOs and MISO should collect information on ERIS vs. NRIS interconnection service requests to avoid false positives in screens and studies for network upgrades. Azimuth’s view is that ERIS distribution interconnection applicants make a choice to forgo a firm and lasting reservation for transmission service capacity. Thus, such interconnection requests should be screened and studied in a manner that takes this interconnection service choice into account, including distinguishing between upgrades required for reliability and upgrades desired for other objectives such as congestion. This includes screening ERIS interconnection applicants as being curtailed during periods of congestion for the purposes of assigning system upgrades.

Generally, Azimuth does not want to see projects delayed, either through study or through the construction of network upgrades, for impacts that could be avoided via voluntary curtailment which we are electing through interconnection applications to the distribution utility.

Studying larger distribution ERIS interconnection service requests alongside the latest DPP 3 is only appropriate if key ERIS interconnection service parameters are taken into account relative to DPP 3 applicant interconnection service parameters (e.g. NRIS interconnection service). If MISO develops screens and studies that lead to ERIS distribution interconnection customers bearing system upgrade costs in a manner that is akin to NRIS studies – which, in Azimuth’s view, is a potential outcome of the current proposal – then the resulting DER Affected Systems study process should also convey the benefits of reserved transmission capacity and full market access and a reduced risk of curtailment due to congestion.

Study Process Components

Azimuth Renewables appreciates the information provided so far. More information about the DER Affected Systems study costs, parameters, potential system upgrade cost allocation methodologies, and timelines will be helpful to better assess and respond to the proposed changes.

Some separation of projects by size should be considered as part of the study process.

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We are grateful for the opportunity to comment and look forward to working with MISO on this issue in the future.