ITC Comments:

Please see our last set of comments for details on recommended scan rates and telemetry requirements. Scan rates should not be relaxed for resources under 5 MW. Situational awareness and the ability to forecast anticipated ancillary services at the Bulk Electric System level requires a sophisticated understanding of resource operation at the distribution level.

Regarding a business case to walk through, it would be helpful to walk through the following:

Aggregator representing 2 resources, Resource 1 (R1) and Resource 2 (R2).

R1 is comprised of a 20 MW solar plant, 5 MW of storage

R2 is 6 MW comprised of 2 MW of Demand Response (water heaters and air conditioners) and 1 MW of storage, and a 2 MW emergency generator, and 1 MW rooftop solar.

Registration

• What are the registration requirements?
• What information about the types of elements that comprise each of R1 and R2 is required for registration?
• If the aggregator wants to switch up the composition of the DR in R2 adding and removing elements, does this matter to MISO? When would this be reflected in the models?
• What specifically would MISO model, if anything about these resources in the network models? Would this vary depending on size (or example R1 would be modeled but R2 not modeled?) What injection point would be assumed?

In Day-Ahead:

• Suppose R1 offers in for energy, Responsive Reserve and Short Term Reserves and clears all three. Assume energy clears 16 MW for HE8-HE20, RRS and STR clear for 2MW HE13-18.
• Suppose R2 clears for 2MW for RRS for HE16-HE18, and 1 MW of Energy for HE15.

In Real Time,

• Assume R1 gets deployed for energy for 16 MW every 5 min for HE8-18. For the first 15 minutes of HE15 2 MW RRS and STR are deployed.
• Assume R2 gets deployed for 1 MW of RRS during the last 15 minutes of HE15 and for 1 MW of Energy for the entire period for HE15-18.

Verification of Response:

• How would verification of the response be determined for each of R1 and R2?
• Where is it measured?
• When is it measured? 

Substitution

• Is the aggregator able to substitute response for R1 for R2? (Wouldn't think so as they are two resources. But if there is no telemetry how would MISO determine what the response was?) If necessary, please lower R2 to 4.9 MW size if MISO lands on no telemetry requirements for under 5 MW and then walk through the example.

Settlements

• How would settlement work for both DA and RT?
• Case i)  Assume all performance obligations met for both R1 and R2.
• Case ii) Suppose R2 does not supply what is required both for energy and for RRS (assume supplies only 0.5 MW of each).

Thanks,

Marguerite Wagner

Please see the emailed attachment for DTE's feedback.  

Comments of DTE-Electric on Order 2222 Filing Framework Iteration 2 in Response to Feedback Request from 8/2/2021 MISO DER Task Force

DTE is pleased to provide the following feedback on various aspects of MISO’s latest filing framework for compliance with Order 2222.  The responses below address various questions and feedback requests raised by MISO.  MISO’s questions and proposals for feedback are captured in regular type face and DTE’s responses are captured in bold type face. 

Interconnection

• How should MISO, DERA, and local utilities coordinate interconnections?
• Alternatives Considered

1. How should the coordination be triggered?
   1. Transmission backfeed
   2. DER size limit
   3. Utility specific
   4. What will be the study process?
      1. Cluster (group study)
      2. Individual requests
      3. How will the studies be coordinated with the remainder of the MISO Interconnection Queue?
         1. Request-date based
         2. Study-commencement based

DTE anticipates that rules for the state of Michigan will be announced in October and finalized in November of this year. At present, we expect those rules will allow projects under 1MW to proceed to interconnection without detailed study, provided they pass a series of screens based on FERC standards. Studies that do not pass the screens will be added to a cluster study. We are working to better understand the state process and requirements and are interested in learning more about how MISO’s process will mesh with it.

At this point, we believe the MSIO, DERA and local utilities coordination on DER interconnections can be triggered by all factors listed above including but not limited to transmission backfeed, DER size limit and utility specific.

[Slide 32, The Transmission (MISO) and Distribution (State) Processes] 

In cases where the Transmission Owner Study Process results in transmission upgrades, distribution companies need to incorporate that information into the Distribution Company Study Process. As such, there should be an arrow illustrating the routing of data from the Transmission Owner Study Process back into the Distribution Company Study Process.    

We’d also like to understand the timeframes TO and MISO should finish the transmission impacted study for DER interconnection if the transmission impact study is deemed necessary. Not putting a timeframe on the studies may risk some DER interconnection requests waiting for ever to get the approval, which is not satisfactory nor desirable for electric utilities or DER owners/providers.

DERa Modeling

Regarding the statement “The flexibility of the elements of the node is at the discretion of the DERA”, DTE would like to note that any changes to the composition of a CPNode/EPNode need to be reviewed by distribution utilities. These changes may trigger an aggregation re-review.

EDCs will likely need information above and beyond MISO’s minimal requirements, such as MVAR and power factor, to enable operations. A single data pipeline that provides required data to both MISO and EDCs would be less costly and onerous for DERas than creating and maintaining parallel infrastructure for MISO and EDCs independent from one another. MISO should provide a process for collecting and sharing data that fulfills not only its own minimum requirements, but those of EDCs as necessary.

Performance Tracking

• Assumptions
  • A DER is limited to one LSE (for Order 745 treatment)
  • An individual DER will be homogeneous and will be designated as demand response, injecting or storage
  • DERa performance based on summed individual DER meter data

Clarification on the assumptions and diagram above would be helpful. Particularly, does this framework imply that as a use case 10 Tesla Powerwall units on the same street or in a neighborhood could be controlled by a third party and registered as an individual storage DER? Use cases like this would make it difficult to appropriately reconcile retail billing and wholesale dispatch across devices.

Proposed alternate wording: Clarification on what constitutes a single DER, as depicted in the diagram above, would be helpful.  Specifically, would the 10 Tesla Powerwall units constitute a single DER?  DTE would see these as 10 individual DERs as each is presumably serving a different retail customer.  Tracking these 10 devices as a single DER will make it more difficult for the EDC/LSE to appropriately reconcile retail billing and wholesale dispatch at the customer level.  The same issue applies to water heaters, thermostats, etc. They are located on different premises and different parts of the system. MISO needs to change the graphical representation and provides the clarification that 20 residential water heaters or 30 residential thermostats are DER aggregations and should not be considered as single DERs.

Double Counting

The EDC should be allowed to validate whether this attestation is accurate as part of the EDC review process.

The timeframe under which this data is made available is important and impacts EDC billing processes. Shortening the settlement cycle from 105 days to 14 days would help minimize impact to retail billing.

Because the EDC bears the burden of verifying meter data, including this database in the compliance filing would help enable our work and lighten the load. Excluding this tool from the filing and pushing it to a multi-year roadmap for future development would require EDCs to build duplicative temporary stopgap tools and increase work unnecessarily.

• How might dual participation in retail programs and MISO markets be tracked to prevent double counting?
  • Alternatives Under Consideration

1. DERA reports only wholesale transactions to MISO
2. DERA reports only wholesale transactions to MISO. MISO notifies LSE and EDC and makes submitted meter data available for review
3. DERA coordinates with EDC to utilize existing infrastructure and metering to capture meter data. DERA reports only wholesale transactions to MISO
4. Use independent data repository to store standardized wholesale and retail transaction data where LSE and EDC can review. DERA reports wholesale transactions from repository to MISO

DTE supports the independent data repository described in alternative 4 as an ideal long-term solution. Understanding that it may take time to implement this system, we believe alternative 3 describes the minimum data infrastructure requirements necessary to track participation and prevent double counting. EDC infrastructure should be utilized wherever possible and can be enhanced with additional metering necessary to separate retail transactions from wholesale transactions. Leveraging EDC infrastructure in this manner would eliminate potential discrepancies between EDC owned meters and DERA owned meters. Accuracy of load calculations is important and is dependent upon the accuracy of meter data.

Telemetry

There is an apparent discrepancy between the stakeholder comment and the MISO response here, in that the stakeholder comment refers to “DERs 5 MW or greater” and the response refers to “DERa over 5 MWs”. The rest of the document makes MISO’s position clear, but the contrast here should be amended for clarity.

• Assumptions
  • ICCP with WAN requires significant setup for new connections
  • Other technologies may be feasible but are not available and tested in the MISO footprint

Some EDCs do not permit inter-organizational links to their EMS/ADMS systems that are not done via ICCP. The current slide doesn’t reflect this benefit / consideration of using ICCP.

• How often is data required via telemetry to support DERa in operations and settlements?
  • Alternatives Under Consideration

1. Relax scan rates for non-regulation qualified, dispatchable DERa that are <5 MW from 2 sec to 10-30 sec. Other resources remain at 2 sec

This option is acceptable provided the telemetry is being done via ICCP.

Parking Lot

• Should large DER assets be required to participate in markets individually?
  • Alternatives Considered

1. Individual assets above 5 MW and desiring to participate in Bulk market should be represented individually and not in a DERa

We believe further discussion regarding the maximum allowable size for DER participating in DERA should be added to the parking lot for further discussion. DTE supports a maximum limit of 5 MW on the size of individual DERs participating in a DERa for the following reasons:

• MISO and distribution utilities must have the visibility and access to dispatch signals, operational status, telemetry information and control for individual DER resources exceeding a certain size threshold to effectively manage the operation and reliability of the system. The larger the DER resources, the more impactful they can be on the operation and reliability of the grid. Allowing large DER resources to be aggregated into a DERA will prevent MISO and distribution utilities from having the granularity of the data, information and control stated above, creating challenges in effectively monitoring, controlling and managing grid operation and reliability. 
• The necessity of setting a size limit for individual DERs participating in a DERa is further solidified by the fact that not all states have the same telemetry requirements for large DER resources. While one state may require any individual DER greater than 1 MW to have telemetry, another state may not have any telemetry requirement specified in the interconnection process under state jurisdiction at all. Hence, it is very important to have the MISO rules/tariff address potential gaps that may exist in various state interconnection processes and ensure the granularity of the data and control pertaining to dispatch, operation and injection/withdrawals, etc., are available for large DER resources that are more likely to create reliability and operational challenges to the grid.
• Furthermore, even the most robust interconnection process today does not address demand response resources. To that extent, any demand reduction caused by individual DERs does not undergo as thorough impact studies as DERs injecting energy into the grid. Having a size limit for individual DERs participating in a DERa will at least provide the opportunity and visibility for utilities and MISO to better target and address potential system reliability and stability issues pertaining to minimum load. 
• Such a size limit is echoed in the FERC PURPA order on July 16, 2020 (Order 872), where FERC established a rebuttable presumption for a utility’s obligation to purchase from a QF with a net capacity at or below 5 MW for small power production facilities. This is driven by the fact that a QF that is bigger than 5 MW has non-discriminatory access to energy markets. This also implies that a DER greater than 5 MW has the capability to participate in the MISO market on its own and doesn’t need to be aggregated to overcome the competition barrier, as intended by FERC order 2222.
• DTE also notes that while hosting capacity for an individual circuit will vary from circuit to circuit, a size limit of 4-5 MW is generally aligned with the allowable maximum DER size that can be hosted by some higher voltage circuits on its distribution system.
• Both PJM and SPP have found compelling reasons and made proposals to set the size limit of individual DERs at 5 MW participation in a DERa. MISO should consider adopting similar proposal. 

In conclusion, for the reasons listed above, DTE recommends a size limit reflecting the lower of 5 MW or any relevant limitations from state-level rules for individual DERs participating in a DERa.   DTE believes that if the allowable scope of an aggregation continues to be at an EPNode level as MISO has proposed, then a maximum aggregation size may be less necessary than a maximum size for individual resources.  However, if MISO were to expand the allowable scope beyond a single EPNode, this question would need to be revisited.

Please see https://info.aee.net/hubfs/FERC%202222%20Use%20Cases%20Report.pdf, especially but not exclusively Use Case 3 and variations on this theme.

TO: MISO DER TASK FORCE
FROM: THE ENTERGY OPERATING COMPANIES
SUBJECT: FILING FRAMEWORK - OPT-IN, TELEMETRY SCAN RATES AND PARKING LOT ITEMS
DATE: AUGUST 16, 2021

In response to MISO’s questions concerning Distributed Energy Resource (DER) compliance framework related to small utility opt-in, telemetry scan rates and parking lot items under FERC Order 2222 as presented in the August 2, 2021 DERFT meeting, the Entergy Operating Companies ("EOCs" or “Entergy”)[1] offer the following comments.

The Organization of MISO States’ Distributed Energy Resources Working Group (OMS DER WG) appreciates the opportunity to submit the following comments. This feedback does not constitute a position of the OMS Board of Directors. 

OMS DER WG would suggest continuously clarifying the language MISO uses when discussing DER Aggregators (DERA), DER aggregations (DERa), and “individual DERs”. Based on the discussion on August 2^nd, at times it was unclear which variation of DER the presenter was referring to, causing stakeholder confusion and questions.  

Slide 68-69 of the Compliance Framework was particularly confusing, as an ‘individual DER’ was interpreted in differing ways by stakeholders and MISO. It is OMS’s understanding that in this instance ‘individual DER’, as clarified by MISO, actually refers to a single DER aggregation (DERa), not an individual water heater, solar panel, or battery. OMS would maintain that it is very important to use precise terminology in future slide decks and looks forward to MISO’s clarification in all discussion between DER, DERa, and sub-aggregations (either resource-specific, DER-sub-aggregations or other sub-aggregation terminology).  

Regarding the opt-in and 4 million MW hour considerations, OMS DER WG does not think there needs to be a time permit for the opt-in to be authorized. Any ‘opt-in’ time period and considerations will be evaluated during a RERRA approval for opt-in authorization and any rescission of an RERRA opt-in authorization would need to consider both wholesale and retail considerations (existing participation, registrations, etc.). 

Alliant Energy Comments

Provided below are Alliant Energy’s comments in response to the questions posed during the Distributed Energy Resources Task Force meeting held on August 2, 2021. 

For small utilities opt-ins, MISO seeks general feedback and input on the following questions:  Who is responsible for verifying this data?

MISO should be responsible for accepting allowed bids which should include verifying if the bid is eligible.

Should scan rates be relaxed for non-regulation qualified, dispatchable resources less than 5 MWs?

MISO should differentiate between DRR and DERa resources when discussing scan rates.

For DERa resources scan rates should be relaxed to allow more market participation.  Payment will be based on actual performance and assuming these resources do not have negative impacts on the system (verified through interconnection study and agreement) the value of high scan rates is offset by the cost increases to implement.

MISO has started a Parking Lot for future additional work on DER/ Demand Response, and coordination topics, and seeks related feedback on items to be captured in this Parking Lot.

Distribution Utility Review Process (Clause 292)

MISO has this on the calendar for Q4 2021 but MISO/Transmission/DERA/EDC Coordination

Suggested use cases that can be transparently evaluated by the DERTF.

We need more time to document these use cases.

Energy: Wind PPA

Energy: Solar Facility

Ancillary: Solar + ESS

Capacity: Solar + ESS

Existing DER case

New DER case

Same distribution circuit vs Same distribution substation (load EPnode)

Advanced Energy Management Alliance (“AEMA”) [1] respectfully submits the following comments to the MISO Distributed Energy Resource Task Force (“DERTF”) on the second iteration of the Order 2222 Filing Framework that was presented at the August 2, 2021, meeting of the DERTF.[2] AEMA is a trade association under Section 501(c)(6) of the Federal tax code whose members include national distributed energy resource companies and advanced energy management service and technology providers, including demand response (“DR”) providers, as well as some of the nation’s largest demand response and distributed energy resources. AEMA members support the beneficial incorporation of distributed energy resources (“DER” or “DERs”), including advanced energy management solutions, into wholesale markets as a means to achieving electricity cost savings for consumers, contributing to system reliability, and ensuring balanced price formation. These comments represent the collective consensus of AEMA as an organization, although they do not necessarily represent the individual positions of the full diversity of AEMA member companies.

AEMA appreciates MISO sharing the ongoing iterations of the comprehensive proposal to comply with FERC Order 2222. In the feedback request, MISO asked for comments on specific issues and the AEMA responses are as follows: 

• General feedback on the direction of MISO.

AEMA supports MISOs proposal to utilize the aggregated meter values for settlements. During the DERTF meeting, there was confusion expressed by stakeholders on slides 68-70 of the Compliance Framework presentation. The confusion centered on what is meant by metering at the “individual DER” level.[3] From the verbal discussion and the example on slide 70, it appears that MISO is proposing to receive a single meter value from aggregations of similar DER types, but not the individual DERs. MISO would then aggregate those meter values into a single value to determine aggregate performance. Since the DER Aggregator (DERA) has the capability of utilizing different DERs for meeting performance obligations, this process should be acceptable since the evaluation is not against the specific DER types. 

Ultimately, AEMA recommends MISO require the DERA to only supply a single set of metered values for the load reduction and injection portions of each DERa of heterogeneous resources, as opposed to breaking out each individual resource type by homogeneous associations.

Whether MISO follows its current proposal, or simplifies the process as AEMA recommends, AEMA reiterates MISO should not require individual DER metering because it would be a substantial and costly barrier to participation of DERAs that provides no value to MISO operations. (For example, requiring meter values of each solar panel in a small solar farm or each thermostat from an aggregation of many thermostats). 

On a separate topic, it is AEMA’s understanding that MISO is proposing to require Real Time (RT) telemetry at 2-second intervals at the aggregated level for aggregations of DER above 5 MWs or those providing Regulation service. AEMA requests MISO clarify that any RT telemetry requirement is requested at the aggregated level and will not be required at the individual DER level regardless of individual DER size. AEMA will reemphasize that the DERA 

AEMA also requests MISO present a summary of the timing of settlement meter data. Specifically, when is the meter data due for specific settlement statements, and are the expectations from DERAs any different from all other market participants?

• Items captured in the Parking Lot for future additional work on DER/ Demand Response, and coordination topics, and related topics.

While AEMA recognizes the concept of creating a Parking Lot for capturing future work related to DER makes sense for certain issues, AEMA urges MISO to avoid using the Parking Lot as much as possible. For example, currently, some market processes, not technically feasible, should move to the Parking Lot until they are technically feasible (for example, after the Market System Enhancement (MSE) project is completed). MISO should create a process to revisit those project enhancements at that point in time as part of the compliance commitment to Order 2222. 

MISO should not use the Parking Lot to hold items that could currently be implemented as part of the proposed compliance plan. Compliance with Order 2222 should pull in all as many options as are feasible during the initial project execution, when implementation costs would likely be at a minimum. Shifting enhancements to a parking lot could create future cost barriers to implementation if the enhancement. As AEMA mentioned in previous comments, there are elements of the MISO compliance proposal which limit the potential participation of DERAs in the MISO market. For example, limiting aggregation to a single CP node is a significant barrier to participation. MISO has not demonstrated that absolutely no level of aggregation or aggregation for limited-service offerings is technically infeasible. 

• Should scan rates be relaxed for non-regulation qualified, dispatchable resources less than 5 MWs?

Yes. Scan rates should be relaxed for non-regulation qualified, dispatchable resources, less than 5 MWs. This relaxation should be matched to services being provided and simple DER response should not have an ICCP requirement associated with them. Installing advanced, real-time metering at a 2-second interval can be costly and does not provide commensurate value to the MISO grid operator because resources of a few MWs are within the noise band of MISO operations. This is similar to some resources today, such as DRR Type I, which does not provide Real-Time telemetry.

• For small utilities opt-ins, MISO seeks general feedback and input on the following questions:

• What about utilities that may fall above the line in one fiscal year and below the line the next year?

Based on the timing requirements associated with registering and modeling in the MISO market, AEMA recommends MISO develop a timing calendar allowing for published data to be reviewed for utility load levels. This could be published EIA data or other publicly available data sources, presuming the data sources meet the Order 2222 requirement[4] that the data is based upon the utilities prior fiscal year’s data. In the event data for the prior fiscal year is not available to align with MISO’s registration, modeling, and other MISO auction timelines, then AEMA recommends MISO include in its compliance filing that the most recent publicly available data on a utility’s fiscal year sales be used for determining if a utility falls above or below the 4 million MWh threshold. 

Once the data is published, a timeline for DERAs to secure approval from RERRAs regulating the identified utilities that have are found to be below the 4 million MWh threshold, registering and getting the resource into the market should be identified giving the DERA a full year of market participation. This may mean the participation calendar does not match the normal annual calendar.  

For example, if data is published in March for the prior year and it takes 60 days for a resource to be registered, modeled, and begin participation in the market, then the participation year could run from June through May of the following year.

• Who is responsible for verifying this data?

MISO should establish a process examining publicly available data, such as the EIA data, and then rely upon the DERA to certify the data at registration. The DU can examine the information for any concerns during their safety and reliability review. MISO should instruct the DU to notify them (and the DERA) if they anticipate load levels to fall below 4 mm MW-hrs.

• For those utilities which opt-in, over what period of time is that opt-in “authorized”? How does this align with MISO process timelines?

MISO should suggest utilities seeking to “opt-in” align with the timeline stated above, where an “opt-in” lasts at least a year and gives time for registration and modeling before the clock begins. For example, MISO could establish a process allowing “opt in” on a quarterly basis, beginning at the next quarter and lasts for one calendar year from the start. Obviously, more details would need to be worked out, but this would be the basic principle for handling “opt-ins.”

• Suggested use cases that can be transparently evaluated by the DERTF. 

MISO has shared several use cases and stated that they are looking at the AEE presentation and the work of EPRI for additional use case examples.[5] These examples will be very valuable in understanding how compliance with Order 2222 will work, from registration to settlements. AEMA encourages MISO to compile these cases mentioned in the MISO presentation and begin flushing out the details of those cases first.

AEMA appreciates MISO’s consideration of these comments as part of the Order 2222 compliance approach being discussed in the DERTF. We welcome any questions, and encourage you to contact either Katherine Hamilton, Executive Director of AEMA, or DeWayne Todd, representative of AEMA, should you wish to discuss with AEMA members.

Respectfully Submitted, 

Katherine Hamilton
Executive Director, Advanced Energy Management Alliance
Katherine@aem-alliance.org
202-524-8832

or

DeWayne Todd
DDT LLC
dewaynetodd1297@gmail.com
812-573-8052

WPPI’s feedback on Iteration 2 of FERC Order 222 Filing Framework presented at the DERTF, 8/2 is as follows:

(1)    Parking Lot: It makes sense to focus on what is necessary for compliance with O2x4 and leave refinements/enhancements to be worked later, depending on the level of participation of DER aggregations (DERas) in MISO markets and the priority of Parking Lot issues relative to other potential initiatives. WPPI does not have any issues to add to the Parking Lot.

(2)    Scan rates: Scan rates should be relaxed for non-regulation, qualified, dispatchable resources less than 5 MW if such relaxed scan rates provide a material reduction in the burden on a DER Aggregator (DERA).

(3)    Small utilities opt-in: It seems this would be best managed by utilities just above the 4M MWh opt-in threshold and their Relevant Electric Retail Rate Regulatory Authority. It may be an issue they will want to address in an agreement between the utility and the DERA.

(4)    Use cases: At this time, WPPI does not have any specific DERas it is anticipating on our member distribution systems. However, we are very interested in exploring a variety of use cases in order to determine the data necessary to separate a DERa’s participation in MISO from a Load Serving Entity’s participation in MISO (namely, the LSE’s load purchases), as well as ensure a DER in a DERa does not use wholesale purchases at retail. To the extent a DERa’s participation in MISO can be directly metered (including metered and subject to measurement and verification as is the case with demand response), such separation is relatively straightforward. However, what data are necessary if a DERa includes one or more DERs that participate in retail program/s? Includes one or more DERs that have behind the retail meter solar and storage? (Just a couple of examples.)

• Should scan rates be relaxed for non-regulation qualified, dispatchable resources less than 5 MWs? Yes, slower scan rates should be acceptable for small resources.
• For small utilities opt-ins, MISO seeks general feedback and input on the following questions:

• What about utilities that may fall above the line in one fiscal year and below the line the next year?  The language in the Final Rule is the opt-in applies to small utilities and the threshold is set based on the retail sales in the prior year.  Based on the language in the Final Rule any year the utility is above the threshold DER could participate without RERRA action.  Any year the utility is below the threshold DER would require a RERRA opt-in to participate in the wholesale market.
• Who is responsible for verifying this data?  MISO should request that the RERRA provide or verify the MWh of retail sales for the utility from the prior year.
• For those utilities which opt-in, over what period of time is that opt-in “authorized”? How does this align with MISO process timelines?  The opt-in is over whatever time the RERRA authorizes the opt-in to be effective.  In general, we agree that the shortest term would be the product term.  For example, if the RERRA authorizes an opt-in for a DER to participate as a capacity resource that opt-in would be in effect for a minimum of the capacity year.  If the RERRA authorizes an opt-in to participate in the energy and ancillary services markets the authorization would be on a day-to-day basis unless or until the RERRA establishes and end date or terminates the opt-in.

Consumers Energy appreciates the opportunity to provide comments regarding the second iteration of MISO’s FERC Order 2222 Filing Framework Document

• Items captured in the Parking Lot for future additional work on DER/ Demand Response, and coordination topics, and related topics.

MISO’s proposal to create a ‘Parking Lot’ which will house issues that require further definition beyond the needs of the FERC Order 2222 compliance filing is one that Consumers Energy can support.  It may ultimately make the compliance filing effort more efficient as well.  There have been times when conversations at the DER meetings have gotten derailed on very nuanced or significantly technical points.  With the creation of the Parking Lot, stakeholders can now be assured that even if their concern is not going to be addressed at a meeting, it will be captured in the Parking Lot and addressed at another time.  Documenting these issues is vitally important so that we do not lose the thought leadership provided by the stakeholder community.

• Should scan rates be relaxed for non-regulation qualified, dispatchable resources less than 5 MWs?

The scan rate requirement for non-regulation qualified dispatchable resources needs to be based on the market services provided and should require the most stringent of (i) MISO requirements; (ii) State interconnection requirements; and (iii) Electric Distribution Company (EDC) requirements.

• For small utilities opt-ins, MISO seeks general feedback and input on the following questions:

• ­    What about utilities that may fall above the line in one fiscal year and below the line the next year?

As anticipated by the question , the minimum opt-in tenure should be one year and should track the Planning Year (PY) schedule (currently June – May).  This question illustrates why it is important to have the exact same set of rules for large distribution utilities required to comply with FERC Order 2222 and for small utilities choosing to opt-in to the FERC Order 2222 requirements.  This way, if a utility toggles back and forth between a small and a large designation, there is no need for anyone to do anything special or out of the ordinary.  The same processes and procedures can be followed and all parties (distribution utility, transmission owner, MISO, RERRA) can simply maintain their existing rights and obligations.  Such a construct is not only easier to manage and administer, but it will also allow smaller utilities to offer programs that are greater than one year in duration, which is something desired by certain customer segments.  It would be difficult, if not impossible, for utilities bordering small/large status to offer multi-year programs if it feared that it would need to comply with two potentially different sets of rules from year to year.  Keeping one set of rules for all utilities, whether complying mandatorily or voluntarily with FERC Order 2222, provides the end-use customer with the greatest set of alternatives.

• ­    Who is responsible for verifying this data?

Verification rules should be the same for large utilities that are required to comply with FERC Order 2222 and for small utilities that choose to opt-in to the requirements of FERC Order 2222.  These rules should remain the same for all parties involved, namely the distribution utility, the transmission company, MISO and the RERRA.  Creating a second set of ‘special’ rules solely for the small utilities not only has the potential to cause confusion and errors, but will also shift additional burdens onto the remaining players (large distribution utilities, transmission owners, MISO, RERRA) as these parties will need to assume any verification responsibilities that should be assigned to the small distribution utility.

• ­    For those utilities which opt-in, over what period of time is that opt-in “authorized”? How does this align with MISO process timelines?

As noted above, the minimum opt-in tenure should be one year and should track the Planning Year (PY) schedule (currently June – May).  Implementation of FERC Order 2222 is already going to require significant changes to existing processes and procedures.  The industry does not need to further complicate matters by creating special rules, be they about time periods or anything else, for small utilities that opt-in.  One set of rules for all utilities will suffice and, as noted above, will also be to the benefit of customers.

• Suggested use cases that can be transparently evaluated by the DERTF.

Consumers Energy has no suggested use cases at this time.

Once again, thank you for providing the opportunity to provide comments on this issue.

Voltus Comments to MISO Aug 2, 2021 DERTF Feedback Request

DERTF Feedback Requested on Filing Framework Document – Iteration 2 (IR070)

MISO requested stakeholder feedback on the following:

1. Items captured in the Parking Lot for future additional work on DER/ Demand Response, and coordination topics, and related topics.

Voltus appreciates MISO's intent behind the Parking Lot for placing any future additional work so that the FERC Compliance Filing timeline is not impacted. However, Voltus cautions MISO that the MISO Parking Lot should not be a place to defer items, which could be worked via the DERTF pro-actively to meet the FERC Order 2222 compliance requirements.

For example, MISO currently has Demand Response Resource (DRR) Type I and II market participation models for demand response programs. We don't see any need for MISO to place DRR improvements in the parking lot when MISO could take active steps towards making DRR compliant for O2222 requirements.

Another example would be the interconnection requirements. Several stakeholders in Interconnection Planning Working Group, Distribution Utility Coordination meetings, and the DERTF have asked MISO to discuss interconnection requirements sooner than putting them off after the compliance filing.

1. Should scan rates be relaxed for non-regulation qualified, dispatchable resources less than 5 MWs?

Voltus answers "yes," telemetry requirements should be relaxed for non-regulation resources (regardless of their size).

As mentioned in slide 9 of Voltus May 10, 2021, MISO DERTF presentation, we propose MISO match metering granularity and telemetry requirements to services offered by the Aggregated DER. This proposed approach would be consistent with the current MISO practice of requiring hourly data from MISO capacity market participants and 5-min data from DRR Type I resources providing reserves in the ancillary services market. Hence telemetry requirements should be relaxed for non-regulation resources regardless of their size.  

1. For small utilities opt-ins, MISO seeks general feedback and input on the following questions:

a)     What about utilities that may fall above the line in one fiscal year and below the line the next year?

b)     Who is responsible for verifying this data?

c)     For those utilities which opt-in, over what period of time is that opt-in "authorized"? How does this align with MISO process timelines?

Voltus believes RERRAs should be able to determine the duration of their opt-ins and scope those opt-ins as they see fit. RERRAs should be able to limit opt-ins to apply to particular resources participating in particular market programs or products.

1. Suggested use cases that can be transparently evaluated by the DERTF.

Voltus proposes 3 use cases that demonstrate:

1. It is feasible to use existing baselines established for demand response programs for all DERs.
2. Established DR M&V can be used for a single DER with multiple underlying technologies & one point of metering.
3. Established DR M&V can be used for an aggregation of many DERs with varying underlying technologies.

Voltus Use case 1 - Use existing baselines established for demand response programs for all DERs.

In use case 1, presented on May 10, 2021, MISO DERTF meeting, the consumption baseline—as calculated for existing DR resources--is established at a positive 10 MW. Load of the DER is 5 MW in Interval 1, 0 MW in Interval 2, -5 MW in Interval 3, and -10 MW in Interval 4.  Negative load implies the DER is injecting load to the grid.

Table 1: Voltus Use case 1 - Use existing baselines established for demand response programs for all DERs

This use case illustrates that the existing baselines established for demand response programs can measure both curtailment and injection. The two—curtailment vs. injection—can be distinguished for purposes of applying FERC Order 745’s Net Benefits test, as curtailment is reflected in performance between the baseline and 0 load while injection is reflected as performance below the x axis.

Figure 1: Voltus Use case 1 - Use existing baselines established for demand response programs for all DERs

Voltus Use case 2 - Established DR M&V can be used for a single DER with multiple underlying technologies & one point of metering

In use case 2, within a single facility there are multiple technologies such as a DR resource, a generator, and an energy storage device. Despite the complex mix of technologies contributing to the DER’s performance, the exact same M&V as seen in use case 1 can apply because the technologies share a single metering point.

Table 2: Voltus Use case 2 - Established DR M&V can be used for a single DER with multiple underlying technologies & one point of metering

This particular use case 2 illustrates how a single facility with multiple technologies can function as one DER with a single point of metering. There is no need for the M&V to account for this performance by looking at each individual technology because the net impact to the grid is identical to use case 1.

Figure 2: Voltus Use case 2 - Established DR M&V can be used for a single DER with multiple underlying technologies & one point of metering

Voltus Use case 3 - Established DR M&V can be used for an aggregation of many DERs with varying underlying technologies.

Use case 3 shows an aggregation of different DERs with varying underlying technologies such as solar and diesel generators in addition to curtailable loads. There are 4 individual DERs in this use case, some of which provide grid services by reducing grid demand relative to a baseline and some of which respond to dispatch instructions by increasing generation. The graphic illustrates that the aggregate performance is the sum of individual DER performances.

The consumption baseline in Curtailable Load 1 DER is established at 10 MW, similar to the existing DR program example in Voltus Use Case 1. And the performance of the DR program was 8 MW in Interval 1, 6 MW in Interval 2, 4 MW in Interval 3, and 2 MW in Interval 4.

In Curtailable Load 2 DER, the consumption baseline varies according to the interval. For this curtailable load 2, the baseline is 5 MW in Interval 1, 4 MW in Interval 2, 6 MW in Interval 3, and 5 MW in Interval 4. And the performance of the DR program was 3 MW in Interval 1, 2 MW in Interval 2, 5 MW in Interval 3, and 1 MW in Interval 4.

In Solar Array DER, the solar array generation output varies by interval. In Interval 1, the solar output is 5 MW. In Interval 2, the output is 6 MW, and Intervals 3 and 4 stay constant at 8 MW.

And finally, in the Diesel Generator DER, the diesel generator's output is a constant 2 MW for 4 Intervals.

Table 3: Voltus Use case 3 - Established DR M&V can be used for an aggregation of many DERs with varying underlying technologies

This particular use case 3 illustrates that the aggregate performance is the sum of individual DER performance regardless of if that performance if achieved through curtailment or injection.  

Figure 3: Voltus Use case 3 - Established DR M&V can be used for an aggregation of many DERs with varying underlying technologies