During the March 19, 2021 Distributed Energy Resource: Distribution Company – MISO Coordination Framework Workshop, MISO discussed O2222 requirements for information, data, metering and telemetry. MISO needs to understand the gap between current telemetry and metering paradigms for retail and wholesale markets, and what may need to change for increasing distribution located asset participation in wholesale markets. MISO shared discussion questions. Stakeholder feedback is requested on the discussion questions presented.
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Metering & Telemetry
Please provide feedback by April 9.
Consumers Energy appreciates the opportunity to respond to March 19, 2021 Distributed Energy Resource: Distribution Company – MISO Coordination Framework Workshop Metering and Telemetry (IR070) issues. Our feedback is detailed below for your consideration.
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1. What concerns your company about defining DERA requirements?
Consumers Energy recommends defining and delineating the respective roles and responsibilities for each entity, including each participating DER, DERA, RERRA, LBA, EDC and MISO.
The existing ARC process that MISO has chosen as the foundation for its DERA participation model is problematic and lacks safeguards to ensure meter accuracy and validation. Data accessibility in as close to real time as feasible would be required to mitigate current challenges and allow day ahead and real time participation as well as facilitate accurate billing and compensation for energy production and consumption.
Factors or challenges to facilitation of DERA market participation may include:
Demonstrated DERA generation capacity and reliability metrics
Accurate, transparent and accessible meter information.
Additional meters, telemetry, software for data capture and billing may be required
Data validation involvement
Demonstrated volume that provides value at the wholesale market level
Enforcement of Tariff language regarding failure to meet participation commitment
Multi-party dispute resolution process
2. What information do Distribution Utilities need for their planning purposes (long-term and operational)?
At a minimum, distribution utilities would require information on how the DERA will be operated, including but not limited to, participating DER, what parameters can be controlled, expected frequency of utilization, limits on number of implementations, etc., so the impact can be studied to determine whether any operational restrictions or facilities are required.
3. What information is needed by the Distribution Utility and/or RERRA to update the composition of an aggregation?
Composition changes may impact longer term planning as well as real time operation. Frequency likely should be in alignment with other MISO planning processes on a quarterly or annual basis as much as feasible. Changes to location, resource type, energy, demand or ancillary services offered and related information will be helpful to be able to respond to changing conditions as they occur.
4. What information does the Distribution Utility require for Real-Time Operations?
Consumers Energy would need to know unit status (on/off), voltage at the unit, MW being produced, MVar flows, and how a participating unit or aggregation could be isolated for worker and equipment protection to resolve local distribution outage or other issue.
5. Do distribution companies expect to require additional information from DERAs? If so, what might that include?
EDCs require access to accurate and transparent meter data regarding energy produced and consumed by a given entity for validation and billing/compensation. Meter data accuracy is a current challenge experienced during the ARC process as part of settlements.
6. What other drivers may define data requirements that need to be considered?
RERRA requirements. Meter access. EDC/LBA being different entities. Multi-party contracts and dispute resolution process requirements. Interconnection voltage, Asset Ownership.
Metering & Telemetry
7. Do state Public Utility Commissions (PUCs) have specific meter definitions or requirements other than American National Standards institute (ANSI)? If so, what are they?
The Michigan Public Service Commission (MPSC) Electric Interconnection and Net Metering Standards contain metering and telemetry requirements (R 460.648). The standard requires utilities to create uniform statewide interconnection requirements that further define metering and telemetry requirements. The MPSC and Consumers Energy interconnection requirement can be found at the following websites.
a. MPSC Electric Interconnection and Net Metering Standards Rules (https://ars.apps.lara.state.mi.us/AdminCode/DownloadAdminCodeFile?FileName=1983_2019-087LR_AdminCode.pdf )
b. Consumers Energy Interconnection Procedures (https://www.consumersenergy.com/residential/renewable-energy/generation-interconnection-information )
The State of Michigan is currently in the rulemaking process to update the MPSC Electric Interconnection and Net Metering Standards.
8. What telemetry options (network hardware, frequencies, communication protocols, etc.) do distribution companies use for distribution automation? Do you envision requiring their use for DERAs?
Most Generator Interconnection projects greater than 550kW and some projects as low as 150kW, require telemetry equipment to be installed at the generation site by the utility for supervisory control and data acquisition (SCADA). The utility equipment consists of real time automation controller (RTAC) that interfaces with utility metering at the point of common coupling and an interface device installed by the interconnecting entity. The utility RTAC exchanges data with the interconnecting entities interface device using DNP3 communication protocol over a fiber hardware interface. A cellular modem is typically used to remotely communicate with the RTAC at the interconnection sites.
MISO requires ICCP. We anticipate the DERA would also be required to supply meters capable of ICCP to participate in the Bulk Electric System.
9. What resources might be helpful to educate MISO and others about them?
EPRI is a good resource that has a Distribution Services Working Group talking about these issues.
10. According to stakeholders feedback as reported in the MISO Visibility paper (https://cdn.misoenergy.org/MISO%20DER%20Ensuring%20Grid%20Reliability495153.pdf, p. 10) some utilities require larger DER, those > 500 kW or > 1 MW, to provide information to them. What information is required?
The telemetry data exchanged with sites above 550kW and some as low as 150kW, typically consists of metering data (real/reactive/apparent power, voltage, current, power factor), site status information (recloser open/close status, inverter aggregate on/off status, relaying points, alarms, etc.), and control capabilities (utility trip).
11. What visibility requirements are in place for larger resources, such as those >1 MW?
Please refer to Question 8 and 10 responses. ICCP telemetry is required for resources over 550 kW.
12. For those utilities with remote DER monitoring and/or control capabilities, are you willing to talk with MISO about your experiences?
Yes. Consumers Energy has installed numerous telemetry packages at DER (generation) facilities. Please refer to Question 8 and 10 responses.
13. What opportunities for efficiencies might exist?
With so many variables still in play, it is difficult to define opportunities for efficiencies at this time.
14. Other?
Consumers Energy appreciated the opportunity to provide stakeholder feedback and has no additional comments at this time.
During the March 19, 2021 Distributed Energy Resource: Distribution Company – MISO Coordination Framework Workshop, MISO discussed O2222 requirements for information, data, metering and telemetry. MISO needs to understand the gap between current telemetry and metering paradigms for retail and wholesale markets, and what may need to change for increasing distribution located asset participation in wholesale markets. MISO shared discussion questions. Stakeholder feedback is requested on the discussion questions presented.
Environmental Sector Response:
The Environmental Sector appreciates this opportunity to provide feedback on the data collection, metering, and telemetry required for MISO to comply with FERC Order 2222 and eliminate barriers to DER participation in MISO’s markets.
General comments
The Environmental Sector is concerned that MISO may not be focusing on what is needed for participation in wholesale markets. The questions below seem to emphasize aspects of DERs primarily of interest to Distribution Utilities. Order 2222 found that just and reasonable wholesale market rates require removal of barriers to DER participation, and we believe that the Order 2222 compliance effort should focus on what is needed to meet MISO’s settlement, operational, and administrative needs.
Under Order 2222, the DER aggregator is the wholesale market participant. However, the questions below appear targeted at Distribution Utilities/RERRAs rather than aggregators. The questions are focused on matters that appear to be best resolved between Distribution Utilities and their regulators, without MISO involvement. MISO needs to allow DER participation in its markets while maintaining reliability. We believe the best approach to achieve those goals is to develop an understanding of MISO’s needs, current barriers to DER participation, and what the aggregators can provide now and may be able to provide in the future.
MISO’s questions should be focused on the settlement data and telemetry MISO requires from aggregators to get full DER participation in the markets while maintaining reliable operations. Below, we provide responses to MISO’s questions, but we urge MISO to redirect its focus away from what Distribution Utilities/RERRAs are doing toward what MISO needs from aggregators and what aggregators can provide.
Beyond the responses to specific questions below, we urge MISO to work with stakeholders to plainly state what data and telemetry MISO requires to comply with FERC Order 2222 and fully integrate DERs into MISO markets. This includes what kind of settlement quality customer specific data MISO needs.
Responses to MISO’s specific questions
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1. What concerns your company about defining DERA requirements?
Our primary interests are that DER Aggregations are defined so as to reduce barriers to participation and ensure that all DERs have a path to wholesale market participation. Specific issues to support those interests are:
2. What information do Distribution Utilities need for their planning purposes (long-term and operational)?
Distribution utility planning needs should be addressed between Distribution Utilities and their regulators. Environmental groups have no objections to MISO providing information and technical assistance to Distribution Utilities. However, those activities do not appear to be in scope for Order 2222 compliance, and are best addressed through future stakeholder work.
This question would be better focused on understanding what information the Distribution Utilities need from aggregators. MISO already has experience dealing with Aggregators of Retail Customers (ARCs) in states such as Illinois. What information do IL Distribution Utilities require of ARCs? Can MISO learn from those experiences? The aggregators will need MISO, as the transmission provider, to provide clear interconnection requirements to connect aggregated DERs.
3. What information is needed by the Distribution Utility and/or RERRA to update the composition of an aggregation?
DER aggregations are wholesale market constructs under FERC jurisdiction. Updating an aggregation is primarily an interaction between MISO and a DER aggregator.
Distribution Utilities/RERRAs do not play a major role in updating the composition of a MISO aggregation of DERs. Distribution Utilities’ role in updating aggregations is limited to review. For example, after a DER aggregator has submitted aggregation updates to MISO, Distribution Utilities might review the DERs to confirm they have proper distribution interconnections, are not taking service under tariffs that would lead to double-counting, and so on. This suggests that the information needed by Distribution Utilities is limited to identifying information such as customer account numbers.
4. What information does the Distribution Utility require for Real-Time Operations?
Consistent with our other responses, we believe the appropriate question is “What information does MISO need from aggregators for real-time operations?” MISO has experience with measurement and verification procedures for demand side management resources such as demand response resources type I and II, and energy efficiency resource. MISO may consider basing DER information requirements on the information MISO currently collect from these demand side resources for real time operations.
5. Do distribution companies expect to require additional information from DERAs? If so, what might that include?
DER aggregations are wholesale market constructs under FERC jurisdiction. Order 2222 is explicit that FERC sets eligibly requirements for DERAs. Thus, while Distribution Utilities are expected to require information about individual DERs, we do not believe that their role regarding DERAs is limited to review of aggregations submitted to MISO, as described in our response to question 3 above.
We strongly recommend that MISO avoid involvement in any efforts by Distribution Utilities/RERRAs to set requirements on, or otherwise claim jurisdiction over, DERAs. The MISO stakeholder process is not the correct venue to resolve such jurisdictional disputes. In any event, for purposes of Order 2222 compliance, FERC has established that DERA requirements are fully defined within RTO/ISO tariffs.
As noted above, MISO already has experience dealing ARCs in states such as Illinois. What information do IL Distribution Utilities require of ARCs? Can MISO learn from those experiences? Additionally, any data requirements MISO has for aggregators should not be onerous. For example, if the aggregator chooses to provide an ancillary service, it is reasonable for MISO to require the aggregator to provide the data granularity needed to provide that ancillary service, no more and no less.
6. What other drivers may define data requirements that need to be considered?
In the spirit of FERC Order 2222, MISO should work to provide aggregators with information useful to support DER development and provide signals to properly direct investment. We believe that expanded information about elemental pricing nodes is important.
Metering & Telemetry
1. Do state Public Utility Commissions (PUCs) have specific meter definitions or requirements other than American National Standards institute (ANSI)? If so, what are they?
The Environmental Sector is not aware of any definitions or requirements beyond ANSI.
MISO's DER rules should seek to leverage existing metering infrastructure to the maximum extent possible. Based on this, we recommend that MISO accept data from any meter configuration considered revenue grade by the appropriate RERRA.
2. What telemetry options (network hardware, frequencies, communication protocols, etc.) do distribution companies use for distribution automation? Do you envision requiring their use for DERAs?
The Environmental Sector does not have a list of telemetry options. MISO should set a high priority on avoiding any rules that lead to duplicate telemetry requirements. We support all efforts by MISO to identify distribution utility telemetry systems to best take advantage of existing infrastructure. To further this goal, MISO might consider maintaining a repository of Distribution Utility/DERRA telemetry options/requirements.
However, we stress that distribution utility requirements are a matter between the distribution utility and their regulators. MISO should not require any telemetry options that are not strictly necessary for DERs to participate in MISOs markets. Because the aggregator will be participating directly in MISO markets, MISO’s focus should be on what information is needed from the aggregator regarding visibility, identified by service and product.
The requirements for telemetry must be proportional to the services being offered and genuine operational needs for real-time information. In particular, we are concerned that simply applying telemetry requirements developed for large power plants to all sizes of DERs will create barriers. MISO should base all telemetry requirements on operational, as opposed to settlement, needs. Telemetry requirements should also consider the size of the DERs and whether the DERs will ever result in net injection into the transmission system. At least in cases where DERs are simply offsetting wholesale load, telemetry requirements may be best based on current requirements for demand resources rather than generators.
3. What resources might be helpful to educate MISO and others about them?
MISO should look to the aggregators for help in identifying resources. MISO should also look RTOs that have already developed rules on DERAs, such as California and New York.
4. According to stakeholders feedback as reported in the MISO Visibility paper (https://cdn.misoenergy.org/MISO%20DER%20Ensuring%20Grid%20Reliability495153.pdf, p. 10) some utilities require larger DER, those > 500 kW or > 1 MW, to provide information to them. What information is required?
Please see our response to question 2.
5. What visibility requirements are in place for larger resources, such as those >1 MW?
Please see our response to question 2. Any visibility requirements should be based on MISOs needs. In general, we acknowledge that MISO may have greater need for real time visibility of larger DERs.
This question should be first answered by MISO depending on the type of resource and market product in which a DERA will be participating. For example, MISO should first explain what visibility requirements it has for non-spin ancillary services, then, based on the capabilities of the aggregators to meet those requirements or provide MISO with similar information, MISO should take any steps necessary to modify its visibility and telemetry requirements to allow DERAs to participate.
Any visibility requirements should be justified and proportional for the services provided.
6. For those utilities with remote DER monitoring and/or control capabilities, are you willing to talk with MISO about your experiences?
We support any efforts by MISO to make use of existing control systems, and to catalogue them as a service to market participants.
However, FERC’s direction to MISO is to identify markets where DERs are technically capable of participating and then to facilitate that participation. We would appreciate clarification on the role MISO anticipates Distribution Utilities control or monitoring will have for DERS participating in MISO markets.
7. What opportunities for efficiencies might exist?
See our response to question 8 below.
8. Other?
MISO should use this stakeholder opportunity to better understand the needs and capabilities of aggregators. MISO should also solicit input from would-be DER aggregators on the resources they intend to aggregate and specific technical requirements. For example, MISO may consider the following questions:
Provided below are Alliant Energy comments in response to the questions posed for electric Distribution Companies following the March 19th Distributed Energy Resource: Distribution Company meeting.
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What concerns your company about defining DERA requirements?
What information do Distribution Utilities need for their planning purposes (long-term and operational)?
What information is needed by the Distribution Utility and/or RERRA to update the composition of an aggregation?
What information does the Distribution Utility require for Real-Time Operations?
Do distribution companies expect to require additional information from DERAs? If so, what might that include?
1. We would like to see MISO’s proposed required information first and can then provide comments on if additional information may be required.
2. It may be required for the DERA to communicate/coordinate the individual DER dispatch to ensure distribution system safety and reliability
What other drivers may define data requirements that need to be considered?
1. Distribution System Operations
Metering & Telemetry
Do state Public Utility Commissions (PUCs) have specific meter definitions or requirements other than American National Standards institute (ANSI)? If so, what are they?
What telemetry options (network hardware, frequencies, communication protocols, etc.) do distribution companies use for distribution automation? Do you envision requiring their use for DERAs?
What resources might be helpful to educate MISO and others about them?
According to stakeholders feedback as reported in the MISO Visibility paper (https://cdn.misoenergy.org/MISO%20DER%20Ensuring%20Grid%20Reliability495153.pdf, p. 10) some utilities require larger DER, those > 500 kW or >1 MW, to provide information to them. What information is required?
What visibility requirements are in place for larger resources, such as those >1 MW?
For those utilities with remote DER monitoring and/or control capabilities, are you willing to talk with MISO about your experiences?
What opportunities for efficiencies might exist?
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What concerns your company about defining DERA requirements?
WPPI has no feedback for this question.
What information do Distribution Utilities need for their planning purposes (long-term and operational)?
We will need locations and generator size to plan infrastructure sizing and protection settings. Larger installations may require engineering studies or changes to the distribution system, which may require significant time to study and perform upgrades to the system.
What information is needed by the Distribution Utility and/or RERRA to update the composition of an aggregation?
DUs will need the generator rating and type (PV, wind, ES, etc.) along with their locations. Probably will need operational characteristics, especially for systems that include energy storage. Granted much of this information is probably already gathered during an interconnection application (with the exception of demand “pure” response that is accomplished through load curtailment on its own), but knowing which resources are aggregated and assumed operated together will be necessary.
What information does the Distribution Utility require for Real-Time Operations?
For WPPI Energy’s distribution utility members, to date, the key information (static) for real-time operations is the location of distributed energy resources on their systems to facilitate safety and reliability when the utility is working on the system in that area.
Do distribution companies expect to require additional information from DERAs? If so, what might that include?
At this time, aside from knowing the distributed energy resources that make up a given aggregation, we don’t expect WPPI’s distribution utility members to need additional information (static) from DERAs. That said, MISO’s proposal to limit a DERA to aggregations behind a single EPNode (except in the case of a Distributed Energy Resource – Type I) is helpful to get a handle on the impact of a DERA on the distribution system.
What other drivers may define data requirements that need to be considered?
WPPI has no feedback for this question.
Metering & Telemetry
Do state Public Utility Commissions (PUCs) have specific meter definitions or requirements other than American National Standards institute (ANSI)? If so, what are they?
The Public Service Commission of WI (PSCW) requirements for revenue metering for customers is in PSC 113 and interconnected generators is in PSC 119. PSC 119 will be going through an update soon. Currently, PSC 119 makes a modest reference to ANSI and makes no requirement of specific metering, but does reference UL1741 and IEEE1547. Also, PSC 119 includes general rules to protective system functions depending on the size of the system.
What telemetry options (network hardware, frequencies, communication protocols, etc.) do distribution companies use for distribution automation? Do you envision requiring their use for DERAs?
Currently, WPPI’s distribution utility members have very little distribution automation in place (couple of percent over 50 municipal utilities and 1 coop). While they are interested in distribution automation, to date, the added complexity and cost have exceeded the estimated benefits. WPPI’s distribution utility members plan their systems to handle the load and distributed energy resources on their systems without needing to monitor the loads and DERs (of any size) in real-time. WPPI’s distribution utility members rely on appropriate planning (including sizing, protection schemes), general knowledge of their systems, and active management of daily conditions (e.g., system reconfigurations to facilitate maintenance) as needed, to ensure the safe and reliable operation of their systems without real-time monitoring.
What resources might be helpful to educate MISO and others about them?
WPPI has no feedback for this question.
According to stakeholders feedback as reported in the MISO Visibility paper (https://cdn.misoenergy.org/MISO%20DER%20Ensuring%20Grid%20Reliability495153.pdf, p. 10) some utilities require larger DER, those > 500 kW or > 1 MW, to provide information to them. What information is required?
See our response to the above question "What telemetry options (network hardware, frequencies, communication protocols, etc.) do distribution companies use for distribution automation? Do you envision requiring their use for DERAs?".
What visibility requirements are in place for larger resources, such as those >1 MW?
See our response to the above question "What telemetry options (network hardware, frequencies, communication protocols, etc.) do distribution companies use for distribution automation? Do you envision requiring their use for DERAs?".
For those utilities with remote DER monitoring and/or control capabilities, are you willing to talk with MISO about your experiences?
WPPI (wholesale supplier to 50 municipal utilities and 1 coop) brings near real-time (up to 15-30 minute lag) data into its system operations center for many of its Load Modifying Resources that have cleared the MISO Planning Resource Auction. (We don’t have near real-time data for all the behind-the-meter generator LMRs.) In the case of some of the behind-the-meter generators LMR, WPPI can remote start/stop. Although our experience is limited, we are happy to discuss with MISO.
What opportunities for efficiencies might exist?
WPPI has no feedback for this question.
Other?
The Entergy Operating Companies Feedback on FERC Order 2222 Compliance Plans for Distributed Energy Resources Aggregators (DERA) Market Participation in MISO
Item 4 Discussion Questions for DER DC Meeting on March 19, 2021
April 9, 2021
Following are the Entergy Operating Companies (Entergy’s) responses to questions posed to Electric Distribution Companies (EDCs) at the March 19, 2021 DER Distribution Companies Workshop as part of MISO stakeholder discussions to prepare FERC Order 2222 compliance plans to enable Distributed Energy Resources Aggregators (DERA) to participate in MISO’s wholesale markets.
As described in more detail below, in developing the requirements necessary to implement FERC Order 2222, it is important that all individual resources in an aggregation are metered.
For Demand Response Resources (DRs) the controlling device is located behind the participating Customer’s meter, so meter data is needed to verify the Customer’s response to the load reduction instruction. DR verification at the MISO Transmission level is not feasible because it would require an extremely large number of controllable devices to detect load changes, so if Distributed Resource is included in the aggregation separate metering is required to obtain load data. Requiring telemetry to individual resources in a DERA’s aggregation will provide visibility and situational awareness, though if certain resources can be grouped together perhaps telemetering the group would be sufficient
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a. What concerns your company about defining DERA requirements?
As an integrated utility that is also an EDC, Entergy’s response below addresses data needs at all levels. In addition to data requirements that will be defined by MISO, EDCs will also need to establish data requirements for resources participating an aggregation that is participating in MISO’s markets, and these must be coordinated with the Transmission Owner responsible for settlement data at the EP Node, which MISO has proposed to establish at the transmission/distribution substation level. It is important that these requirements will work together, which requires some level of coordination as they are developed.
Broadly, MISO’s DER Aggregation and DERA requirements need to reflect: (i) an EDC’s information needs regarding maintaining reliable and safe operations of the distribution system, (ii) the fact that the distribution system is dynamic and is often reconfigured for varying periods of time (e.g., sub-hourly to weeks to months); and (iii) the information and communication needs associated with capability of EDCs to override MISO’s dispatch under Order 2222. All of these needs must be reflected in MISO’s DERA registration requirements and incorporated in the EDC review of DERA registrations. The information requirements would include, but not be limited to:
(A) the size and location of the individual resources in an aggregation,
(B) the location of the injection and withdrawal points on the distribution system,
(C) the RTO-ISO services the aggregation intends to provide, and
(D) whether the DERA will use discrete groupings of the individual resources within the aggregation to provide various wholesale products.
MISO must establish telemetry and metering procedures and requirements that will support heterogenous aggregations (e.g., aggregations that include injection, demand response, and storage resources) while providing: (1) the necessary data for real time (RT) visibility, dispatch and performance; and (2) accurate metering of individual resources in the aggregation so that the performance of both injection and withdrawals assets in the aggregation are measured.
With the ability to aggregate many retail assets into a single demand response (DR) resource as part of a DER Aggregation, MISO must require interval metering of load that will be capable of verifying performance. DR information aggregated at the transmission level will provide no indication of the performance of a DR resource within a DER Aggregation absent a requirement to separately meter loads. These meter and information requirements should be incorporated into MISO’s a DERA registration that includes demand response or storage resources as part of the aggregation.
Entergy’s biggest concerns regarding the definition of DERA requirements is ensuring that the relevant parties have access to the data necessary to support reliable operations, testing, performance, verification, and settlement from both the retail and the wholesale perspectives.
For the reasons noted above, relative to performance verification and settlements, a DR in an aggregation requires two meters. Advanced Metering Infrastructure (AMI) has the capability to gather and communicate the data that is needed for verification, performance, testing and settlements for Demand Response Resources. [1] Regardless of whether or not the incumbent EDC has installed AMI, clear and attainable requirements surrounding poling and data transmission intervals must be established by MISO for the individual resources in a DER aggregation.
Throughout the responses below, Entergy refers to Advanced Metering Infrastructure (AMI)[2] as necessary to support Distributed Energy Resources Aggregators (DERA) market participation. These references to AMI are intended as “shorthand” for the communication and telemetry infrastructure that is necessary to support such participation, and describe how Entergy will be addressing these needs as the Operating Companies continue to transition their Distribution Systems to be AMI-enabled. In these responses, Entergy recognizes that EDCs are currently at varying stages of this transition, and the range includes utilities that have not made any such changes to their systems. However, AMI provides the functions that are needed to address the questions MISO has asked.
b. What information do Distribution Utilities need for their planning purposes (long-term and operational)?
Long-term and operational planning of the Distribution Network is complicated by the fact that it is much more difficult than modeling the Transmission System as loads and generation on the Distribution Network are rapidly changing and there are frequent Network reconfigurations that would necessitate daily modeling updates. New communications must be established between MISO and the EDC so that any reconfiguration of the distribution system can be communicated quickly to MISO and the DERA.
Distribution facilities cannot be appropriately planned, either long-term or operationally, without accurate load data at both the feeder and the bus levels. For long-term planning, aggregated data regarding market participation and performance is needed at the load bus and feeder level, but for operational planning purposes, real time data and communication regarding dispatch of participating DERs is needed.
For long-term planning purposes, aggregated load data at the bus level is needed to provide clarity on how demand at each bus is impacted at the same moment in time by the dispatch of these resources.
For both long-term and operational planning, Distribution Utilities will need to be able to group bus-feeder loads participating in Order 2222 DERs aggregations to properly account for both their potential impact, either from being dispatched by MISO or from withdrawing from the aggregation.
When a DR (including non-injecting storage applications) is included in a DER Aggregation, it will be necessary for MISO to require separate metering of non-injection resources included in the aggregation. Without implanting the recommended communication, metering, and telemetry requirements, it will not be possible to perceive load changes on the distribution system, particularly with regard to load data that is adequate to verify performance and settlement of the non-injection resources in the aggregation.
Operational visibility into MISO’s dispatch instructions, supported by appropriate communications to the Distribution Operator is also needed because the resource may also be participating in a retail program and the Distribution Operator may rely on its availability to perform address a network need or issue, or in the alternative may need to curtail its potential dispatch by MISO due to a Network issue occurring in RT.
Specifically, for a heterogenous DER aggregation with DR resources in the aggregation, MISO needs to require meters that can communicate load data in real time. Smart (AMI) metering of the individual resources in an aggregation could communicate such load data.
There are a variety of challenges today in MISO’s process for LSE validation of demand response (DR) resources included in a registered DR aggregation. At a minimum, an annual registration requirement that includes MW potential of the individual participating resources (DR or DERs in an aggregation more generally) may be a means of improving transparency and legitimacy. If an DERA could add or remove resources more than once a year, there must be a notice and registration of the resource that is communicated to MISO and the UDC. This registration (either annually or more often) is needed on a Distribution Feeder basis. The metering of DR resources is needed. Reliance on static or historic customer baselines of performance is not reasonable. As the variety, type, and number of DR resources increases (within a heterogeneous aggregation with DR resources or DR resources on their own) the inaccuracies with using customer baseline information to measure performance will also increase.
Currently for both DRRs and EDRs that participate as LMRs (where performance is only assessed during emergency deployments) there are no firm “requirements” for testing and proving the performance capability in order to ensure the resources are available for their full “output” 24 hours a day, 7 days a week, for 8760 hours. The same is true for DRRs participating in MISO’s energy market. If these resources become more prevalent in MISO’s markets, testing and proving of a DER’s (or DERA’s) performance capability will be critical to system planning and other process to prevent the accumulation of MW that may not collectively or individually be capable of performing the service they are seeking to provide, which can have an impact on system planning. As a result, it is important that firm and verifiable requirements be established at the outset of Order 2222 Implementation.
Order 2222 specifically requires a DO (or distribution utility (DU)) review process that includes criteria by which the DO would determine the performance capability of the DERs participating in a DERA and whether such participation will pose significant risks to the reliable and safe operation of the distribution system. Per the Order, MISO is also required to share information and data with the DO and the DO’s review must be incorporated into the DERA registration process. As noted in response to “a.” above, EDCs have several information and operational needs that should be included in the registration process. And, MISO should not register a DERA unless the information and communication needs among MISO, the DERA, and the EDC are established such that all the parties know of MISO’s dispatch of the aggregation and an EDC’s override determinations.
Long Term resource availability is critical for accreditation into total network generation. Accreditation of interconnected DERs over a specific performance period would allow reductions in fossil fuel generation that could result in fuel savings and greenhouse gas reductions.
Operational Planning and Unit Commitment:
Given the critical nature of monitoring the actual loading of energy-storage resources along with the exporting of power back onto the Distribution Grid in real time, telemetry data from smart (AMI) metering is ultimately needed to provide the necessary real time data, along with measuring these power transitions consistently and accuracy. In addition, to avoid double counting, separate metering would allow independent monitoring of injections and withdrawals to support separate accounting, and any additional riders/cost associated with exporting power would be accounted for under the separate-independent metering/account.
MISO must coordinate with the DERA and the DO
In addition to a MISO-DERA participation agreement, MISO should establish a standard MISO-DO agreement that would set out the coordination between MISO and the DO (e.g., addressing data flows and communications).
MISO must coordinate with Distribution Utility to address data flows and communications. MISO currently receives communications and data flows information from both the Generation and Transmission Networks. The same sort of infrastructure and processes need to be developed and managed to receive Distribution DER and Load data.
The Distribution Operator also requires awareness of MISO commitment instructions to ascertain potential reliability issues resulting from the dispatch of the resource as well as resource availability for retail commitment, if it is also offering services through a retail program. MISO also needs awareness of any Distribution System Operational issues in advance in order to optimize commitment solutions that are possible. A new communication need must be addressed that is associated with capability of UDCs to override MISO’s dispatch. Ideally, the Distribution Operator would have a means of providing MISO with some type of flow limit data (in or out) to ensure that MISO does not over-commit resources (incurring stranded MWs).
c. What information is needed by the Distribution Utility and/or RERRA to update the composition of an aggregation?
The same information required for the initial registration is needed for any updates to the composition of an aggregation, though it would be helpful to provide a list of the changes being made.
d. What information does the Distribution Utility require for Real-Time Operations?
(A) the size and location of the individual resources in an aggregation,
(B) the location of the injection and withdrawal points on the distribution system,
(C) the RTO-ISO services the aggregation intends to provide, and
(D) whether the DERA will use discrete groupings of the individual resources within the aggregation to provide various wholesale products.
In addition, the ability to override a MISO dispatch order under Order 2222 requires (i) the EDC to be aware of MISO’s dispatch, and (ii) MISO and the DERA to be aware of the EDC’s override decision. These needs require a communication and coordination system that does not exist today; new systems and new personnel will be required. As mentioned earlier, the distribution system is dynamic and is often reconfigured for varying periods of time (e.g., sub-hourly to weeks to months) which can be the source of an EDC exercising the override right.
Entergy’s default data pull-back over the network is every 4-hours but could be configured for a more frequent data pull every hour. Entergy is currently deploying new AMI Metering to all 3.1 million Operating Company Customers. With this new smart meter technology being deployed as standard, the same smart meters technology and communication infrastructure would be capable of meeting MISO minimum telemetry and data transfer requirements. Potential errors in measurement of performance and settlement data are also minimized by using the same metering for load data and DERs, along with separate directional-specific metering with separate accounting. If AMI has not been installed for any of the individual resources in a DER aggregation, it should be required by MISO.
Unlike Transmission and Generation Networks, the Distribution Network is impossible to model in real time due to constantly changing load, distributed generation, and potential for changes in configuration. For demand response, visibility associated with interconnected DERs and DERAs per Order No. 2222 requires independent meter data, along with load data, to measure the response for DR. Also unlike Transmission and Generation, Transmission Operator management of real time telemetry data is provided within ~4-second intervals, but it is technically desired that DER, DERA and DR real time telemetry data be capable of being provided at 5-minute intervals or longer in order to determine the actual response on the Distribution Grid, given that considerable influences must occur to actually measure any demand response at the Transmission level.
Today, the Energy Operating Companies as Market Participants monitor the MISO Communications System Start/Stop display that provide start/stop instructions in Day Ahead or Real Time for generation resources, which include DRR-Type I or could include DRR-Type II, on an hourly basis (though the Operating Companies would prefer to receive them on a 5-minute basis). MISO’s dispatch instructions include a commit reason for the dispatch of registered unit(s), which can include reliability commitments. Today, when registered LMRs are called upon to address reliability issues during a Max Gen Event Step 2, the need for load reduction is communicated by MISO to the Market Participant.
DER market participation will likewise require MISO, the Distribution Operator, the Market Participant, the DERA (Aggregator), and in some circumstances the Transmission Operator, to have an open communication process to inform one another of material changes that occur in Real-Time operations.
Practically speaking, smart metering technology is a requirement for utilities to develop a demand response market within a MISO-managed area. New smart meter technology must also be expanded to measure interconnected DERs and DERAs to have the same accuracy and time stamp as the connected loads. For DR, load data would also be used to measure actual response. Smart meter infrastructure should also be used for communication and telemetry data in real time.
e. Do distribution companies expect to require additional information from DERAs? If so, what might that include?
f. What other drivers may define data requirements that need to be considered?
Double counting concerns exist and could happen in part, if a DER has a separate account that is not properly managed. Entergy’s Distribution Interconnection Standard currently allows Net Metering for DERs below 300 KVA, and a bidirectional meter is used. In support of future potential Customer participation in a new MISO Order 2222 DER aggregation, Entergy’s DER Interconnection Procedure will require a sperate AMI Meter to measure the contribution of the DER from the Customer, and the Customer would opt out of the Retail Net Metering program in order to opt into the MISO Order 2222 DER aggregation regime.
Metering & Telemetry
g. Do state Public Utility Commissions (PUCs) have specific meter definitions or requirements other than American National Standards institute (ANSI)? If so, what are they?
All of Entergy’s retail regulators require the metering accuracy which is governed by the ANSI standards. This topic is complex, and more discussion is need between MISO and its stakeholders.
h. What telemetry options (network hardware, frequencies, communication protocols, etc.) do distribution companies use for distribution automation?
Itron/Silver Spring Network Bridge, 900MHz with DNP Protocol (dual-band mesh capability of 900MHz and 2.4GHz frequencies in which we do not currently use the 2.4GHz band, though it is available).
Do you envision requiring their use for DERAs?
Yes, It’s nearly impossible for the Transmission Operator to measure DERAs at the Transmission level due to the substantial load change requirement; therefore, for most DERAs measurements, load data at the Distribution node must be provided that could be provide only from load-metering.
i. What resources might be helpful to educate MISO and others about them?
Entergy has internal videos, presentations and documents that could provide insight on AMI devices and implementation along with information concerning Mesh Networks and data flow functions.
j. According to stakeholders feedback as reported in the MISO Visibility paper (https://cdn.misoenergy.org/MISO%20DER%20Ensuring%20Grid%20Reliability495153.pdf, p. 10) some utilities require larger DER, those > 500 kW or > 1 MW, to provide information to them. What information is required?
Entergy’s Interconnection Standard requires separate metering on single source DERs 300 kW and above from which exported power data along with standard AMI Metering telemetry data (time and voltage) are provided. DERs below 300 kW are standardly enrolled with a Net Meter (dollar-for-dollar rate) program, with the aggregation of multiple (same owner) account also allowed enrollment into the Net Meter program for Arkansas only.
k. What visibility requirements are in place for larger resources, such as those >1 MW?
Along with standard AMI Metering, SCADA and Direct Transfer Trip communications are established. For the most part, autonomous controls are established for Distribution exporting and loading. Per Entergy’s DER Standards for Distribution Interconnection, DER communication/telemeter requirement is managed in accordance with Section 3.39 “Communication Criteria for Requiring Telemetering” in which the telemeter is based on the “Case” type and capacity size of the interconnecting DER.
l. For those utilities with remote DER monitoring and/or control capabilities, are you willing to talk with MISO about your experiences?
Yes
m. What opportunities for efficiencies might exist?
It would be extremely difficult for a DERMS to manage DERs beyond a specific feeder without a super-computer and extreme instrumentation of the Distribution Network, since a human operator could not react fast enough; therefore, autonomous control/settings for peak-load reduction and Demand Response devices would likely be the standards, so the use of load data would be critical to measure response.
n. Other?
[1] The Department of Energy defines advanced metering infrastructure (AMI) as an integrated system of smart meters, communications networks, and data management systems that enables two-way communication between utilities and customers.
[2] The Department of Energy defines advanced metering infrastructure (AMI) as an integrated system of smart meters, communications networks, and data management systems that enables two-way communication between utilities and customers.
Advanced Energy Management Alliance (“AEMA”) [1] respectfully submits the following comments to the MISO Distributed Energy Resource (DER) Workshop: Distribution Company – MISO Coordination on the Questions about Data, Metering and Telemetry arising from FERC Order 2222 that were presented at the March 19, 2021 workshop. 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 recognizes that the issue of information, data, metering, and telemetry can be complicated, and that MISO is in the initial stages of evaluating the any impacts related to increasing the participation of distribution level resources the wholesale market. AEMA would recommend that MISO focus only on what is absolutely needed for the services being provided by any potential DER participation. As MISO highlighted in the presentation on March 19, the current requirements vary based upon “resource type, size, and the products “they provide. It is reasonable and appropriate that requirements are different depending upon the various factors mentioned and particularly upon the services being provided.
MISO has noted that “Metering” is primarily utilized for “after the fact” settlements. Requirements for metering should continue to be focused on being able to verify performance and determining appropriate settlements. The settlement values should be provided in aggregate from the DERA provider and not be required at the sub-metering level for MISO settlements.
On the other hand, “Telemetry” should be focused on Real-Time operations and giving visibility of resource performance where needed. It is reasonable and appropriate that small resources and small resource aggregations would not need Real-Time telemetry because the real time changes of the asset values are not needed for services like energy and spinning reserves and are not actionable for MISO operations. For example, a DERA of 2 or 4 MW’s is not within the actionability of MISO. MISO should establish reasonable requirements for any telemetry values from DERAs that are based upon services being provided (like regulation) and size of the assets.
On the specific questions raised by MISO, AEMA would offer the following feedback:
Data
As a coalition of companies that actively manage DER participation in various wholesale markets throughout the country, AEMA members are most concerned about MISO and/or other entities creating onerous and unnecessary barriers to participation through expanded data requirements that would add no value to MISO system operations. MISO should focus on identifying what is needed and actionable from resources participating in the markets. This focus should be on performance at the “aggregated” level. When a DERA aggregates several small DERs, then overall aggregation becomes a single resource within MISO. The exchange of data and information should be with that single aggregated resource as opposed to all the individual DERs. A maximum size for single DERs or overall aggregations may need to be established. Resources under those size thresholds would appear as a single resource to MISO operations and settlements and may have different data and telemetry requirements based upon size.
While AEMA is not a Distribution Utility, the needs of entities for planning purposes should focus on the nature of any DER and the historical performance during critical system hours. For example, it seems reasonable that a Distribution Utility would need to have information about any DER activities that impact the peak and critical loads of the system. It does not seem reasonable that the Distribution Utility would need access to all aspects and information of DERA participation in the market (telemetry and bid data). System planning is primarily the domain of Transmission Companies, MISO, RERRA and, to a lesser extent, Distribution Utilities. If MISO chooses to involve the DERA in planning activities, the time and information involved should not be unduly burdensome to the DERA. The DERA should not be required to become a conduit between MISO and the DU.
Updating the composition of an aggregation should not create barriers to participation of the DERA. Once a DERA is registered with MISO and participating in the market, then the DERA should be able to notify the DU and/or RERRA of changes when they happen. If the DU or RERRA has concerns, then the DU or RERRA should have a mechanism to raise the concerns., Absent the statement of a concern from DU or RERRA about the registration change, the change should happen automatically through updates in the MISO model.
The information that a Distribution Utility requires should vary based upon type, size, and the products being provided by the DER. Those should form the basis of interconnection at the distribution level and not be driven by MISO because each Distribution Utility may be different based upon geographic size and density of load.
Any additional information that the distribution companies might expect to require should be reasonable, appropriate, and actionable. Expanded information requests should have a justification.
Existing metering infrastructure should be considered when defining data requirements. As much as possible, the utilization of existing metering and data alternatives should be used, depending upon the services being provided.
Metering & Telemetry
Various states have differing standards for metering requirements. MISO should look to compile a summary of the differences across the footprint to understand the distinctions and any pros/cons of those variations.
With any telemetry option, MISO (and others) should focus on performance requirements of the hardware as opposed to specific types of metering and telemetry. For example, what is needed from the meter should be defined as opposed to specific types/brands of meters. Additionally, the level of granularity should depend upon what service is being supplied by the DER. The requirements from a resource providing regulation are very different from a resource suppling emergency energy only.
MISO might invite providers of DER services in various markets to share how data and information exchange is utilized to confirm market participation and performance. AEMA has multiple member companies experienced in this type of market participation.
AEMA would leave this response to those utilities in the categories listed; however, the use of thresholds for data is reasonable.
Again, AEMA would leave this to utilities to respond but suggest that AEMA has recommended that MISO establish certain threshold registration limits. For example, aggregation across multiple nodes should be allowed if the aggregation is below some threshold like 5 MW. Different visibility requirements should be in place for various resource aggregation sizes and perhaps no single resource should be added to an aggregation if the single resource has the capacity for significant injections to the system (for example over 20 MWs).
Although AEMA does not have utility members, it has many members with experience in operating DER in various ISO/RTO markets and would be happy to talk with MISO about those experiences.
There are multiple opportunities for efficiency created by Order 2222. These include the ability to combine many smaller DERs into a cost competitive aggregation that can participate in the MISO market to make the system more efficient and cost effective. Additionally, the utilization of existing metering to understand how the current metering infrastructure can be utilized for future performance is much more efficient than creating new requirements that necessitate the installation of new metering.
Excessive metering and/or telemetry requirements will significantly stifle the participation of Distributed Energy Resources in the MISO Markets. MISO should carefully consider any changes to the tariff and the impact/costs/benefits associated with those requirements before suggesting changes to the tariff to ensure that a considerable barrier to participation is not created.
AEMA appreciates MISO’s consideration of these comments as part of the Order 2222 compliance approach being discussed in the DERTF and Coordination Workshop. 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 meet 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
GRE doesn't anticipate requiring further information about DERA beyond what is already collected by direction of the existing MISO Tariff through existing resource requirements and ARCs.
Per feedback question #12, GRE uses a variety of remote DER monitoring and control capabilities using a hybrid of various telecommunication technologies, and GRE would be happy to talk with MISO about our experiences.
Un-metered residential DR participation
For distributed DER assets which may be localized un-metered appliances behind the customer meters (interruptible A/C, water heaters, other consumer products), GRE would like to see MISO preserve the ability for Market Participants to use statistical methods and custom baseline methodologies to estimate the MWh delivered from a dispatch instruction, in the absence of a direct sub-meter on the physical asset itself. Preserve the ability to use substation/feeder meter readings to represent aggregated DER fleet response, when individual asset metering is cost prohibitive and not feasible for residential DER assets. These statistical aggregated methodologies should be equally valid and applicable for all grid services that don't require real-time ICCP telemetry, and therefore can continue to be a qualifiable M&V methodology for Capacity, Energy, Spinning Reserve, Supplemental Reserve, and most any other grid service other than fast frequency response ancillary services.
Asynchronous Disconnected Islands powered by DER generators
GRE requests MISO make specific recognition for retail customer premises which can physically disconnect from the grid and operate on an asynchronous island using a customer-sited DER generator to be evaluated the same way as an interruptible load Demand Resource rather than as a Behind The Meter Generator. An example could be a customer with a transfer switch to a fossil-fuel backup generator on site, fuel cell batteries on site, or a transfer switch to a rooftop PV/battery backup system - each of which would completely serve the customer load during switched island operations.
Metering allowed as DR
Since the DER generator serves to provide energy only to the localized islanded load, it is unnecessary for the DER generator's output to be metered as is written in Attachment TT 3.i.a for LMR-BTMG. The proof of DER service is in the absence of load, and as such a baseline M&V methodology akin to Attachment TT 3.i.b - 3.i.d which compares average premise load to the curtailed premise load should suffice to prove to MISO that the requested grid service was delivered. This would provide a more logical and efficient pathway to resource registration for this customer's DER asset, in the case when the distribution utility is measuring load at the point of disconnect rather than measuring a new sub-meter's production energy of a generator, which is superfluous and redundant capital equipment.
PRM treatment as DR
LMR-DR UCAP is grossed up by TL % because it is not using the transmission system, and the UCAP is grossed up by PRM % because it is removing load from the network for which MISO capacity pool won’t need to hold margin for.
LMR-BTMG UCAP is grossed up by TL % because it’s not using the transmission system, but does not get grossed up by PRM because it’s not reducing load, it’s just a generator serving load locally. MISO has stated that part of the reason why you’re adding PRM back in [for DR] is because it’s load you potentially not needing to serve. For BTMG you’re not removing load, you’re just serving load with a generator. This MISO reasoning presumes the BTMG is staying synchronized and connected to the grid, potentially even backflowing and net injecting onto the transmission system.
Since asynchronous disconnected islands powered by DER generators are disconnecting from the grid and islanding asynchronously from the MISO network, the premise appears to curtail load like a LMR-DR. Using the rationale of MISO's PRM% gross-up treatment, this customer premise appears as a disconnected load that the MISO network resource pool need not serve, and should then qualify as a Demand Resource and meet the same criteria for PRM% grossing up, since the MISO capacity pool wouldn’t need to hold margin for this facility. It shouldn't matter if the load was de-energized/shutdown or switched off the network to an asynchronous island; in either case, it relieves MISO's market participants from holding margin for it. In this case, the asset's UCAP should get PRM% grossed up.
Please see MGE's feedback in the accompanying document.