Document ID: FERC-2018-0243-0001
Agency: ferc
Document Type: Notice
Title: Meetings: Participation of Distributed Energy Resource Aggregations in MarketsOperated by Regional Transmission Organizations and Independent System Operators, Distributed Energy Resources-Technical Considerations for the Bulk Power System; Technical Conference
Posted Date: 2018-02-22T05:00Z

[Federal Register Volume 83, Number 36 (Thursday, February 22, 2018)]
[Notices]
[Pages 7703-7707]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-03649]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Notice of Technical Conference

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                                                     Docket Nos.
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Participation of Distributed Energy         RM18-9-000
 Resource Aggregations in Markets Operated
 by Regional Transmission Organizations
 and Independent System Operators.
Distributed Energy Resources--Technical     AD18-10-000
 Considerations for the Bulk Power System.
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    Take notice that Federal Energy Regulatory Commission (Commission) 
staff will hold a technical conference to discuss the participation of 
distributed energy resource (DER) aggregations in Regional Transmission 
Organization (RTO) and Independent System Operator (ISO) markets, and 
to more broadly discuss the potential effects of distributed energy 
resources on the bulk power system. The technical conference will take 
place on April 10 and 11, 2018 at the Commission's offices at 888 First 
Street NE, Washington DC beginning at 9:30 a.m. and ending at 4:30 p.m. 
(Eastern Time). Commissioners will lead the second panel of the 
technical conference. Commission staff will lead the other six panels, 
and Commissioners may attend.
    The technical conference will address two broad set of issues 
related to DERs. First, the technical conference will gather additional 
information to help the Commission determine what action to take on the 
distributed energy resource aggregation reforms proposed in its Notice 
of Proposed Rulemaking on Electric Storage Participation in Markets 
Operated by Regional Transmission Organizations and Independent System 
Operators (NOPR).\1\ In the NOPR, the Commission proposed to require 
each RTO/ISO to define DER aggregators as a type of market participant 
that can participate in the RTO/ISO markets under the participation 
model that best accommodates the physical and operational 
characteristics of its DER aggregation.\2\ As discussed in the Final 
Rule issued concurrently with this Notice, the Commission is taking no 
further action in Docket No. RM16-23-000 regarding the proposed DER 
aggregation reforms.\3\ Instead, the Commission will continue to 
explore the proposed distributed energy resource aggregation reforms 
under Docket No. RM18-9-000. All comments previously filed in response 
to the NOPR in Docket No. RM16-23-000 will be incorporated by reference 
into Docket No. RM18-9-000, and any further comments regarding the 
proposed distributed energy resource aggregation reforms, including 
discussion of those reforms during this technical conference, should be 
filed henceforth in Docket No. RM18-9-000.\4\ Second, the technical 
conference will explore issues related to the potential effects of DERs 
on the bulk power system.
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    \1\ See Electric Storage Participation in Markets Operated by 
Regional Transmission Organizations and Independent System 
Operators, FERC Stats. & Regs. ] 32,718 (2016) (NOPR).
    \2\ Id. P 1.
    \3\ See Electric Storage Participation in Markets Operated by 
Regional Transmission Organizations and Independent System 
Operators, Final Rule, 162 FERC 61,127, Notice of Proposed 
Rulemaking, FERC Stats. & Regs. ] 32,718.
    \4\ Further comments regarding the proposed distributed energy 
resource aggregation reforms should no longer be filed in Docket No. 
RM16-23-000.
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    Attached to this Notice is a description of the seven panels that 
will be conducted at the technical conference.
    Further details of this conference will be provided in a 
supplemental notice.
    Those wishing to participate in this conference should submit a 
nomination form online by 5:00 p.m. on March 15, 2018 at: https://www.ferc.gov/whats-new/registration/04-10-18-speaker-form.asp.
    All interested persons may attend the conference, and registration 
is not required. However, in-person attendees are encouraged to 
register on-line by April 3, 2018 at: https://www.ferc.gov/whats-new/registration/04-10-18-form.asp. In-person attendees should allow time 
to pass through building security procedures before the 9:30 a.m. start 
time of the technical conference.
    The Commission will transcribe and webcast this conference. 
Transcripts will be available immediately for a fee from Ace Reporting 
(202-347-3700). A link to the webcast of this event will be available 
in the Commission Calendar of Events at www.ferc.gov. The Capitol 
Connection provides technical support for the webcasts and offers the 
option of listening to the conference via phone-bridge for a fee. For 
additional information, visit www.CapitolConnection.org or call (703) 
993-3100.
    Commission conferences are accessible under section 508 of the 
Rehabilitation Act of 1973. For accessibility accommodations please 
send an email to [email protected] or call toll free 1-866-208-
3372 (voice) or 202-208-8659 (TTY), or send a fax to 202-208-2106 with 
the required accommodations.
    For more information about this technical conference, please 
contact David Kathan at (202) 502-6404, [email protected], or 
Louise Nutter at (202) 502-8175, [email protected]. For 
information related to logistics, please contact Sarah McKinley at 
(202) 502-8368, [email protected].

    Dated: February 15, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

Distributed Energy Resources Technical Conference

Docket Nos. RM18-9-000 and AD18-10-000

April 10 and 11, 2018
Tuesday, April 10, 2018
    The purpose of this technical conference is to gather additional 
information to help the Commission determine what action to take on the 
distributed energy resource (DER) aggregation reforms proposed in the 
Commission's Notice of Proposed Rulemaking on Electric Storage 
Participation in Markets Operated by Regional Transmission 
Organizations and Independent System Operators (NOPR), and to explore 
issues related to the potential effects of DERs on the bulk power 
system. Panels 1 and 3 on the first day focus on specific NOPR 
proposals that relate to DER participation and compensation. Panel 2 
will provide a forum for Commissioners to discuss DER aggregation with 
a panel of state and local regulators. During the second day of the 
technical conference, operational issues associated with DER data, 
modeling, and coordination will be examined.
Panel 1: Economic Dispatch, Pricing, and Settlement of DER Aggregations
    The objective of this panel is to discuss the integration of DER 
aggregations into the modeling, clearing, dispatch, and settlement 
mechanisms of RTOs and ISOs as considered in the NOPR. The NOPR 
proposed to require each RTO/ISO to revise its tariff to

[[Page 7704]]

remove barriers to the participation of DER aggregations in its markets 
by, among other measures, establishing locational requirements for DER 
aggregations that are as geographically broad as technically 
feasible.\1\ The NOPR also addressed the use of distribution factors 
\2\ and bidding parameters \3\ for DER aggregations. In consideration 
of comments received in response to the NOPR, staff seeks additional 
information about how DER aggregations could locate across more than 
one pricing node. Staff would also like additional information about 
bidding parameters or other potential mechanisms needed to represent 
the physical and operational characteristics of DER aggregations in 
RTO/ISO markets. In particular, Commission staff expects to explore the 
following questions:
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    \1\ NOPR at P 139.
    \2\ The Commission proposed to require each RTO/ISO to revise 
its tariff to include the requirement that DER aggregators (1) 
provide default distribution factors when they register their DER 
aggregation and (2) update those distribution factors if necessary 
when they submit offers to sell or bids to buy into the organized 
wholesale electric markets. Id. P 143.
    \3\ The Commission sought comment on whether bidding parameters 
in addition to those already incorporated into existing 
participation models may be necessary to adequately characterize the 
physical or operational characteristics of DER aggregations. Id. P 
144.
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     Acknowledging that some RTOs/ISOs already allow 
aggregations across multiple pricing nodes, what approaches are 
available to ensure that the dispatch of a multi-node DER aggregation 
does not exacerbate a transmission constraint?
     Because transmission constraints change over time, would 
the ability of a multi-node DER aggregation to participate in an RTO/
ISO market need to be revisited as system topology changes?
     Do multi-node DER aggregations present any special 
considerations for the reliability of the transmission system that do 
not arise from other market participants? How could these concerns be 
resolved?
     What types of modifications would need to be made to the 
modeling and dispatch software, communications platforms, and 
automation tools necessary to enable reliable and efficient system 
dispatch for multi-node DER aggregations? How long would it take for 
these changes to be implemented?
     If the Commission requires the RTOs/ISOs to allow multi-
node DER aggregations to participate in their markets, how should a DER 
aggregation located across multiple pricing nodes be settled for the 
services that it provides? One approach to settling a multi-node DER 
aggregation could be to pay it the weighted average locational marginal 
price (LMP) across the nodes at which it is located. What are the 
advantages and disadvantages of this approach? Are there other 
approaches that should be considered?
     The NOPR considered the use of ``distribution factors'' to 
account for the expected response of DER aggregations from multiple 
nodes. Are there other characteristics of DER aggregations that may not 
be accommodated by existing bidding parameters in the RTOs/ISOs? If so, 
what are they? Would new bidding parameters be necessary? If so, what 
are they?
Panel 2: Discussion of Operational Implications of DER Aggregation With 
State and Local Regulators
    This panel will provide a forum for Commissioners to discuss the 
NOPR's DER aggregation proposals with state and local regulators. The 
discussion will provide an opportunity for state and local regulators 
to provide their perspectives and concerns about the operational 
effects that DER participation in the wholesale market could have on 
facilities they regulate. In particular, Commissioners expect to 
explore the following questions:
     What are the potential positive or negative operational 
impacts (e.g., safety, reliability, and dispatch) that DER 
participation in the wholesale market could have on facilities 
regulated by state and local authorities? How should the costs 
associated with monitoring and addressing such potential impacts on the 
distribution grid caused by the NOPR proposal be addressed, and fairly 
allocated? Are existing retail rate structures able to allocate costs 
to DER aggregations that utilize the distribution systems, and if not, 
what modifications or coordination are feasible?
     Do state and local authorities have operational concerns 
with a DER aggregation participating in both wholesale and retail 
markets? If so, what, if any, coordination protocols between states or 
local regulators and regional markets would be required to facilitate 
DER aggregations' participation in both retail and wholesale markets? 
Could the use of appropriate metering and telemetry address the ability 
to distinguish between markets and services, and prevent double 
compensation for the same services? What is the role of state and local 
regulators in monitoring and regulating the potential for such double 
compensation? How should regional flexibility be accommodated?
     What entities should be included in the coordination 
processes used to facilitate the participation of DER aggregations in 
Regional Transmission Organization (RTO) and Independent System 
Operator (ISO) markets? Should state and local regulatory authorities 
play an active role in these coordination processes? Is there a need to 
modify existing RTO/ISO protocols or develop new protocols to 
accommodate state participation in this coordination? What should be 
the role of state and local regulators in the NOPR's proposed 
distribution utility review of DER aggregation registrations?
     Does the proposed use of market participation agreements 
address state and local regulator concerns about the role of 
distribution utilities in the coordination and registration of DERs in 
aggregations? Are the proposed provisions in the market participation 
agreements that require that DER aggregators attest that they are 
compliant with the tariffs and operation procedures of distribution 
utilities and state and local regulators sufficient to address such 
concerns?
     What are the proper protections and policies to ensure 
that DER aggregations participating in wholesale markets will not 
negatively affect efficient outcomes in the distribution system?
Panel 3: Participation of DERs in RTO/ISO Markets
    DERs can both sell services into the RTO/ISO markets and 
participate in retail compensation programs. To ensure that that there 
is no duplication of compensation for the same service, in the NOPR the 
Commission proposed that individual DERs participating in one or more 
retail compensation programs, such as net metering or another RTO/ISO 
market participation program, will not be eligible to participate in 
the RTO/ISO markets as part of a DER aggregation.\4\ This panel will 
explore potential solutions to challenges associated with DER 
aggregations that provide multiple services, including ways to avoid 
duplication of compensation for their services in the RTO/ISO markets, 
potential ways for the RTOs/ISOs to place appropriate restrictions on 
the services they can provide, and procedures to ensure that DERs are 
not accounted for in ways that affect efficient outcomes in the RTO/ISO 
markets. In particular, Commission staff expects to explore the 
following questions:
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    \4\ Id. P 134.
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     Given the variety of wholesale and retail services, is it 
possible to

[[Page 7705]]

universally characterize a set of wholesale and retail services as the 
``same service''? If so, how could the Commission prohibit a DER from 
providing the same service to the wholesale market as it provides in a 
retail compensation program?
     In Order No. 719, the Commission stated that ``[a]n RTO or 
ISO may place appropriate restrictions on any customer's participation 
in an [aggregation of retail customers]-aggregated demand response bid 
to avoid counting the same demand response resource more than once.'' 
\5\ How have the RTOs/ISOs effectuated this requirement or otherwise 
ensured that demand response participating in their markets is not 
being double counted? What would be the advantages and disadvantages of 
taking this approach for DER aggregations instead of the approach 
proposed in the NOPR for preventing double compensation for the same 
service?
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    \5\ Wholesale Competition in Regions with Organized Electric 
Markets, Order No. 719, FERC Stats. & Regs. ] 31,281, at P 158 
(2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ] 
31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ] 61,252 
(2009).
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     What other options besides the NOPR's proposed limits on 
dual participation exist to address issues associated with the 
participation of DERs or DER aggregations in one or more retail 
compensation programs or another wholesale market participation program 
at the same time as it participates in a wholesale DER aggregation? Is 
there a way to coordinate DER participation in multiple markets or 
compensation programs? Is a possible solution having a targeted 
prohibition, such as the limitation placed on net-metered resources in 
CAISO? \6\ Are there other means?
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    \6\ See CAISO Tariff, Sec.  4.17.3(d).
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Wednesday, April 11, 2018
Panel 4: Collection and Availability of Data on DER Installations
    To plan and operate the bulk power system, it is important for 
transmission planners, transmission operators, and distribution 
utilities to collect and share validated data across the transmission-
distribution interface. In September 2017, the North American Electric 
Reliability Corporation (NERC) published a Reliability Guideline on DER 
modeling (Guideline) that specified the minimum DER information needed 
by transmission planners and planning coordinators to assist in 
modeling and assessments.\7\ The Guideline references the importance of 
static data (such as the capacity, capabilities, and location of a DER 
installation) for the entities involved in the planning of the bulk 
power system. This panel will focus on understanding the need for bulk 
power system planners and operators to have access to accurate data to 
plan and operate the bulk power system, explore the types of data that 
are needed, and assess the current state of DER data collection. The 
panel will also address regional DER penetration levels and any 
potential effects of inaccurate long-term DER forecasting. A Commission 
Staff DER Technical Report is being issued concurrently with this 
Notice to provide a common foundation for the topics raised in this 
panel. For this panel, Commission staff expects to explore the 
following questions:
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    \7\ See NERC Distributed Energy Resource Modeling Reliability 
Guideline, at 5 (Sept. 2017), available at http://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Reliability_Guideline_-_DER_Modeling_Parameters_-_2017-08-18_-_FINAL.pdf.
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     What type of information do bulk power system planners and 
operators need regarding DER installations within their footprint to 
plan and operate the bulk power system? Would it be sufficient for 
distribution utilities to provide aggregate information about the 
penetration of DERs below certain points on the transmission-
distribution interface? If greater granularity is needed, what level of 
detail would be sufficient? Is validation of the submitted data 
possible using data available?
     What, if any, data on DER installations is currently 
collected, and by whom is it collected? Do procedures and appropriate 
agreements exist to share this data with affected bulk power system 
entities (i.e., those entities responsible for the reliable operation 
of the bulk power system or for modeling and planning for a reliable 
bulk power system)? Is there variation by entity or region?
     At various DER penetration levels, what planning and 
operations impacts do you observe? Do balancing authorities with 
significant growth in DERs experience the need to address bulk power 
system reliability and operational considerations at certain DER 
penetration levels? What are they? Is the MW level of DER penetration 
the most important factor in whether DERs cause planning and 
operational impacts, or do certain characteristics of installed DERs 
affect the system operator's analysis? Is the point at which DER 
penetration causes bulk power system reliability and operational 
impacts the point at which it becomes necessary for distribution 
utilities to provide information on DERs to the bulk power system 
operator, or is there some other threshold that could trigger a need 
for sharing this information? How much might the answer to these 
questions vary on a regional basis, and what factors may contribute to 
this variance?
     How are long-term projections for DER penetrations 
developed? Are these projections currently included in related 
forecasting efforts? Do system operators study the potential effects of 
future DER growth to assess changing infrastructure and planning needs 
at different penetration levels?
     What are the effects on the bulk power system if long-term 
forecasts of DER growth are inaccurate? Are these effects within 
current planning horizons? Are changes in the expected growth of DERs 
incorporated into ongoing planning efforts?
     How are DERs incorporated into production cost modeling 
studies? Do current tools allow for assessment of forecasting 
variations and their effects?
     Noting that participation in the RTO/ISO markets by DER 
aggregators may provide more information to the RTOs/ISOs about DERs 
than would otherwise be available, should any specific information 
about DER aggregations or the individual DERs in them be required from 
aggregators to ensure proper planning and operation of the bulk power 
system?
     Do the RTOs/ISOs need any directly metered data about the 
operations of DER aggregations to ensure proper planning and operation 
of the bulk power system?
Panel 5: Incorporating DERs in Modeling, Planning and Operations 
Studies
    Bulk power system planners and operators must select methods to 
feasibly model DERs at the bulk power system level with sufficient 
granularity to ensure accurate results. The chosen methodology for 
grouping DERs at the bulk power system level could affect planners' 
ability to predict system behavior following events, or to identify a 
need for different operating procedures under changing system 
conditions. Further, the operation of DERs can affect both bulk power 
systems and distribution facilities in unintended ways, suggesting that 
new tools to model the transmission and distribution interface may be 
needed. Staff is also aware of ongoing work in this area, for example 
efforts at NERC, national labs and other groups, to evaluate options 
for studies in these areas, which could also inform future work. This 
panel will focus on the incorporation of DERs into different types of 
planning and operational studies, including options for modeling

[[Page 7706]]

DERs and the methodology for the inclusion of DERs in larger regional 
models. The Commission Staff DER Technical Report issued concurrently 
with this Notice is intended to provide a common foundation for the 
topics raised in this panel. For this panel, Commission staff expects 
to explore the following questions:

     What are current and best practices for modeling DERs in 
different types of planning, operations, and production cost studies? 
Are options available for modeling the interactions between the 
transmission and distribution systems?
     To what extent are capabilities and performance of DERs 
currently modeled? Do current modeling tools provide features needed to 
model these capabilities?
     What methods, such as net load, composite load models, 
detailed models or others, are currently used in power flow and dynamic 
models to represent groups of DERs at the bulk power system level? 
Would more detailed models of DERs at the bulk power system level 
provide better visibility and enable more accurate assessment of their 
impacts on system conditions? Does the appropriate method for grouping 
DERs vary by penetration level?
     Do current contingency studies include the outage of DER 
facilities, and if they are considered, how is the contingency size 
chosen? At what penetration levels or under what system conditions 
could including DER outages be beneficial? Are DERs accounted for in 
calculations for Under Frequency Load Shedding and related studies?
     What methods are used to calculate capacity needed for 
balancing supply and demand with large amount of solar DER (ramping and 
frequency control) and determining which resources can provide an 
appropriate response?
Panel 6: Coordination of DER Aggregations Participating in RTO/ISO 
Markets
    In the NOPR, the Commission proposed to require each RTO/ISO to 
revise its tariff to provide for coordination among itself, a DER 
aggregator, and the relevant distribution utility or utilities when a 
DER aggregator registers a new DER aggregation or modifies an existing 
DER aggregation.\8\ The Commission proposed that this coordination 
would provide the relevant distribution utility or utilities with the 
opportunity to review the list of individual resources that are located 
on their distribution system that enroll in a DER aggregation before 
those resources may participate in RTO/ISO electric markets. This panel 
will examine the potential ways for RTOs/ISOs, distribution utilities, 
retail regulatory authorities, and DER aggregators to coordinate the 
integration of a DER aggregation into the RTO/ISO markets. In addition, 
because the use of grid architecture \9\ can help identify the 
relationships among the entities involved in coordinating the 
integration of DER aggregations, this panel will also examine the 
potential architectural designs for the initial coordination processes 
from the point of view of the RTO/ISO markets. In particular, 
Commission staff expects to explore the following questions:
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    \8\ NOPR at P 154.
    \9\ As an aid to thinking about the electric power grid, Pacific 
Northwest National Laboratory and others have coined the term ``grid 
architecture,'' which they define as the application of network 
theory and control theory to a conceptual model of the electric 
power grid that defines its structure, behavior, and essential 
limits. See, e.g., https://gridarchitecture.pnnl.gov/. Expanding 
upon this concept, some thinkers have begun discussing different 
types of ``grid architecture,'' which presumably differ in 
structure, behavior or essential limits from current norms.
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     If the Commission adopts its proposal to require the RTO/
ISO to allow a distribution utility to review the list of individual 
resources that are located on their distribution system that enroll in 
a DER aggregation before those resources may participate in RTO/ISO 
electric markets, is it appropriate for distribution utilities to have 
a role in determining when the individual DERs may begin participation? 
Should the RTO/ISO tariff provide the distribution utility with the 
ability to provide either binding or non-binding input to the RTO/ISO? 
Should the RTO/ISO provide the distribution utility with a specific 
period of time in which to consult before DERs may begin participation? 
Should the Commission require the RTO/ISO to receive explicit consent 
from the distribution utility before a DER is included in a DER 
aggregation? Are there other approaches to coordinate with the 
distribution utility? What are the advantages and disadvantages of 
these approaches?
     Are new processes and protocols needed to ensure 
coordination among DER aggregators, distribution utilities, and RTOs/
ISOs during registration of a new DER aggregations? How can the 
Commission ensure that any new processes and protocols occur in a way 
that provides adequate transparency to the interested parties and also 
occurs on a timely basis?
     Should there be a coordination agreement in place prior to 
the participation of DER aggregation in RTO/ISO markets? Who should be 
parties to this coordination agreement? How would the coordination 
agreement be enforced?
     What is the best approach for involving retail regulatory 
authorities in the registration of DER aggregations in the RTO/ISO 
markets?
     What types of grid architecture could support the 
integration of DER aggregations into the RTO/ISO markets? Knowing that 
a variety of grid architectures are being explored in various regions, 
does it make sense for the Commission to consider specific 
architectural requirements for RTOs/ISOs for the effective integration 
and coordination of DER aggregations?
Panel 7: Ongoing Operational Coordination
    This panel will focus primarily on the operational considerations 
associated with both individual DERs and DER aggregations and with the 
interactions and communications between DERs, DER aggregators, 
distribution utilities, and transmission operators. In the NOPR, the 
Commission acknowledged that ongoing coordination between the RTO/ISO, 
a DER aggregator, and the relevant distribution utility or utilities 
may be necessary to ensure that the DER aggregator is dispatching 
individual resources in a DER aggregation consistent with the 
limitations of the distribution system.\10\ The Commission proposed 
that each RTO/ISO revise its tariff to establish a process for ongoing 
coordination, including operational coordination, among itself, the DER 
aggregator, and the distribution utility to maximize the availability 
of the DER aggregation consistent with the safe and reliable operation 
of the distribution system. To help effectuate this proposal, the 
Commission also proposed to require each RTO/ISO to revise its tariff 
to require the DER aggregator to report to the RTO/ISO any changes to 
its offered quantity and related distribution factors that result from 
distribution line faults or outages. The Commission also sought comment 
on the level of detail necessary in the RTO/ISO tariffs to establish a 
framework for ongoing coordination between the RTO/ISO, a DER 
aggregator, and the relevant distribution utility or utilities. To 
further explore these issues, Commission staff expects to explore the 
following questions:
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    \10\ NOPR at P 155.
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     What real-time data acquisition and communication 
technologies are currently in use to provide bulk power system 
operators with visibility into the distribution system? Are they 
adequate to convey the information necessary for

[[Page 7707]]

transmission and distribution operators to assess distribution system 
conditions in real time? Are new systems or approaches needed? Does DER 
aggregation require separate or additional capabilities and 
infrastructure for communication and control?
     What processes/protocols do distribution utilities, 
transmission operators, and DERs or DER aggregators use to coordinate 
with each other? Are these processes/protocols capable of providing 
needed real-time communications and coordination? What new processes, 
resources, and efforts will be required to achieve effective real-time 
coordination?
     What are the minimum set of specific RTO/ISO operational 
protocols, performance standards, and market rules that should be 
adopted now to ensure operational coordination for DER aggregation 
participating in the RTO/ISO markets? What additional protocols may be 
important for the future? Should the Commission adopt more prescriptive 
requirements with respect to coordination than those proposed in the 
NOPR? If so, what should the Commission require?
     Should distribution utilities be able to override RTO/ISO 
decisions regarding day-ahead and real-time dispatch of DER 
aggregations to resolve local distribution reliability issues? If so, 
should DER aggregations nonetheless be subject to non-deliverability 
penalties under such circumstances?
     Is it possible for DERs or DER aggregations participating 
in the RTO/ISO markets to also be used to improve distribution system 
operations and reliability? If so, please provide examples of how this 
could be accomplished.
     Can real-time dispatch of aggregated DERs address 
distribution constraints? If not, can tools be developed to accomplish 
this?
     Should individual DERs be required to have communications 
capabilities to comply with control center obligations? What level of 
communications security should be employed for these communications?
     How might recent and expected technical advancements be 
used to enhance the coordination of DER aggregations, for example, 
integrating Energy Management Systems (EMS) and Distribution Management 
Systems (DMS) for efficient operational coordination?

[FR Doc. 2018-03649 Filed 2-21-18; 8:45 am]
BILLING CODE 6717-01-P