During the January 13, 2022 Distributed Energy Resources Task Force (DERTF) meeting, MISO discussed Use Case Chestnut. Stakeholder feedback is requested on the operational example presented. Questions for focus are:
Please provide feedback by January 27.
Advanced Energy Management Alliance (“AEMA”) [1] respectfully submits the following comments to the MISO Distributed Energy Resource Task Force (“DERTF”) on the feedback request made by MISO at the January 13, 2022, 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.
At the January 13th meeting of the DERTF (“January 13th Meeting”), MISO discussed Use Case Chestnut and then requested feedback on specific operational questions. AEMA offers the following feedback to the questions posed by MISO.
AEMA members have minimal experience with EDC notifications of distribution system issues that may prevent/preclude a DER from operating in response to a market registration. Having a robust notification process for emergency conditions is critical to ensuring reliable and efficient market operations. The EDC should have a process that facilitates changes in the MISO market model to ensure ongoing operational reliability and efficiency while minimizing market risk to the DERA market participant.
AEMA has no feedback on this question.
AEMA believes that this communication would primarily be handled through either phone or electronic notification between the EDC and the DERA. Ultimately, a fully automated process should be the goal, but the primary method may be more manual until new tools can be economically funded.
Initially, there are a variety of tools and processes that will be needed for timely notifications, which cover various time-horizons like Pre-Day Ahead, Day-Ahead, Intraday, Real-Time, and Settlements. These can include advanced notifications via telephone or electronic notifications. Information sharing may include access to bid capacity, services offered, cleared schedules, and real-time dispatch. Advanced metering tools could reduce the manual aspects, but these may not be economically feasible at the start of DER participation in the market. As penetration of DER participation in the MISO market increases, systematic, machine-to-machine technologies to allow EDCs to communicate outages that impact a DEARs ability to deliver on scheduled operations may be needed; however, these should become more common as the technology becomes more cost effective and proliferation of DER becomes higher. AEMA encourages EDCs, RERRAs, and MISO to begin with simpler processes and utilize a “crawl, walk, run” approach to the issues of coordination, communications, and controls.
AEMA appreciates MISO’s consideration of these comments as part of the Order 2222 compliance approach being discussed at 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
On behalf of Ameren Corporation, I submit the below feedback
During the January 13, 2022 Distributed Energy Resources Task Force (DERTF) meeting, MISO discussed Use Case Chestnut. Stakeholder feedback is requested on the operational example presented. Questions for focus are:
Document:
20211129 DERTF Item 05 Use Cases606530.pdf
BPM 031 - ICCP Data Requirements165746
Ameren relies upon interconnection standards to ensure the safe and reliable disconnection of any DER on our system. We have no specific or dedicated procedures to contact DER customers on our systems for DER’s below 10 MW.
Any procedures for notification or coordination with a DERA will have to be created from scratch. There are no procedures currently in place.
As with the implementation of a FERC Orders 888/889, we would suggest a site similar to the OASIS system that has been implemented for transmission be explored to create the transparency in the market place to registered participants. This site would be available to post planned outages and could also be utilized in a manner that would allow our real-time outage management system to post unplanned outages. Finally, this site could also facilitate notification to participants in the event an override has been issued for any requested dispatch.
As described above, a “Distribution OASIS” system could be explored to be created to manage all notifications from EDC’s and could have the ability to provide push notifications if the DERA’s, or other market participants, desired this information pushed to them.
While not specifically requesting this feedback, this use case references use of BPM 031 which is an ICCP requirement. Basically, this use case stipulates any DEAR is subject to the requirement of telemetry capable of ICCP scan rates. The use of the ICCP protocol and the associated rapid scan rates is a topic that needs to be well understood as the implementation of FERC Order 2222 is considered for implementation. Related to this topic, see page 97 of 20220113 DERTF Item 04 Compliance Framework - Iteration 7617870.pdf for potential of lowering this requirement if aggregation less than 5 MW.
The different products and services that DER’s and DERA’s can offer to the marketplace are not fully defined or vetted yet. Ameren believes the requirements will obviously be different for each of these products and services based on their required service to the market. To enable the marketplace to move forward, it is possible to use existing metering and communication capabilities to allow DER’s and DERA’s to serve basic Energy, Capacity and potentially some ancillary services. We would suggest that the existing products in the marketplace that can utilize existing technology be clearly identified and have the priority to be fully vetted and defined to allow Order 2222 to move forward for implementation. To the extent that a resource is to be utilized from something such as frequency responsive products, it is possible that additional metering and telemetry that is not currently in place should be implemented. In this example, the MISO requirement for this product includes technology according to BPM 031. For these types of requirements that may include requirements for additional additions to our systems, we have the opportunity to continue to the task force process and discuss this more fully and vet the decision in cooperation with all stakeholders once the implications are fully understood.
As an energy aggregator with experience operating in all North American markets, Voltus responds to these questions.
As a DERA potentially paying non-performance penalties, Voltus seeks to understand the emergency conditions that would prompt an EDC to override MISO day-ahead dispatch.
EDC's should articulate "use cases" clearly articulating the problems they are trying to solve. Nearly 20 years of demand response experience has not demonstrated a need to notify the DER due to a distribution system issue.
In our experience, EDCs in states that allow ARCs are proactively automating their existing tools and processes to allow for batch loading of DERs. Any new tools or processes are expected to be minimum for EDCs to comply with this FERC Order 2222 since EDCs have interconnection rules in place for DER interconnections. Bulk data uploads would streamline the process for EDCs and Aggregators.
Please see attachment.
DERTF Feedback Request # 3 – Chestnut Use Case
During the January 13, 2022 Distributed Energy Resources Task Force (DERTF) meeting, MISO discussed Use Case Chestnut. Stakeholder feedback is requested on the operational example presented. Questions for focus are:
Thinking of your current processes, what are the typical methods and timeframes associated with EDC notifications to DER owners/operators when a DER is disconnected under emergency conditions?
Both 1MW DER’s in the use case would have been required to have a scada controlled interconnect device due to their size as part of our interconnection requirement. In this case the assumption is the facilities were damaged on a circuit adjacent to the DER facility. The DER facility would be disconnected as part of the switching to use the DER circuit to restore the adjacent circuit. The timing of the switching depending on the amount of switching required and available resources may take up to several hours. The DER operator would be notified as part of the switching step execution. If the car damaged a pole on the circuit with the DER we would have expected the interconnect device to isolate the solar garden immediately as part of its protection requirements. Current communication to the DER aggregator as to the status of the DER would occur via phone.
Does your EDC intend to use similar protocols and tools to notify a DERA when EDC overrides (e.g., DER disconnections) are necessary under emergency conditions?
As long as the DER is 1MW or larger the current process could be utilized. This process may not be scalable for larger quantities of DERs on distribution. Smaller DER’s would need to have communication and control capability. The processes associated with larger quantities of smaller DER’s would need to be developed.
What new tools or processes might your EDC require, if any, to communicate directly with DERA rather than an existing DER owner or operator, as might be done under today’s typical DER notification protocols?
Current processes could be revised to communicate with the DERA vs the DER operator with little change required as it applies to larger DERs.
What tools or processes could be needed if the timeframe for DERA notification needed to be shortened - for instance, along the lines of state-of-the-art utility outage notification communication tool timeframes for load customers (e.g., mobile apps, web based)?
An automated outage and/or override process to provide notification would be desired.
Please provide feedback by January 27.
WPPI offers the following feedback on the operational questions posed:
(1) Thinking of your current processes, what are the typical methods and timeframes associated with EDC notifications to DER owners/operators when a DER is disconnected under emergency conditions?
(2) Does your EDC intend to use similar protocols and tools to notify a DERA when EDC overrides (e.g., DER disconnections) are necessary under emergency conditions?
(3) What new tools or processes might your EDC require, if any, to communicate directly with DERA rather than an existing DER owner or operator, as might be done under today’s typical DER notification protocols?
(4) What tools or processes could be needed if the timeframe for DERA notification needed to be shortened - for instance, along the lines of state-of-the-art utility outage notification communication tool timeframes for load customers (e.g., mobile apps, web based)?