[Federal Register Volume 83, Number 87 (Friday, May 4, 2018)]
[Notices]
[Pages 19746-19750]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-09455]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RM18-9-000]


Participation of Distributed Energy Resource Aggregations in 
Markets Operated by Regional Transmission Organizations and Independent 
System Operators; Notice Inviting Post-Technical Conference Comments

    On April 10 and April 11, 2018, Federal Energy Regulatory 
Commission (Commission) staff convened 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 DERs on the bulk power system.
    All interested persons are invited to file post-technical 
conference comments on the topics concerning the Commission's DER 
aggregation proposal discussed during the technical conference, 
including the questions listed in the Supplemental Notices issued in 
this proceeding on March 29, 2018 and April 9, 2018. In addition, 
Commission staff is interested in comments on several follow-up topics 
and questions. Commenters need not respond to all topics or questions 
asked. Attached to this notice are the DER aggregation topics and 
questions related to Panels 1, 2, 3, 6, and 7 from the two previous 
notices, as well as Commission staff's follow-up questions related to 
those panels. Please file comments relating to these issues in Docket 
No. RM18-9-000.
    A notice inviting post-technical conference comments on the topics 
and questions relating to the potential effects of DERs on the bulk 
power system related to Panels 4 and 5 is being concurrently issued in 
Docket No. AD18-10-000. Please separately file

[[Page 19747]]

comments relating to Panels 4 and 5 in Docket No. AD18-10-000.
    Commenters may reference material previously filed in this docket 
but are encouraged to avoid repetition or replication of previous 
material. In addition, commenters are encouraged, when possible, to 
provide examples in support of their answers. Comments must be 
submitted on or before 60 days from the date of this notice and should 
not exceed 30 pages.
    For further information about this Notice, please contact:

Technical Information

    David Kathan, Office of Energy Policy and Innovation, Federal 
Energy Regulatory Commission, 888 First Street NE, Washington, DC 
20426, (202) 502-6404, [email protected].

Legal Information

    Karin Herzfeld, Office of the General Counsel, Federal Energy 
Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 
502-8459, [email protected].

    Dated: April 27, 2018.
Kimberly D. Bose,
Secretary.

Post-Technical Conference Questions for Comment

RM18-9-00

Economic Dispatch, Pricing, and Settlement of DER Aggregations (Panel 
1)

    In the Commission's Notice of Proposed Rulemaking on Electric 
Storage Participation in Markets Operated by Regional Transmission 
Organizations and Independent System Operators (NOPR), the Commission 
proposed to require each RTO/ISO to revise its tariff to 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, the Commission seeks 
additional information about how DER aggregations could locate across 
more than one pricing node. The Commission 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.
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    \1\ NOPR, FERC Stats. & Regs. ] 32,718 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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    Comments are requested on the following topics and questions that 
were included in previous supplemental notices:
    1. 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?
    2. 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?
    3. 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?
    4. 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?
    5. 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?
    6. 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?
    Based on the discussion at the April 10-11 Technical Conference, 
comments are also requested on the following additional questions:
    7. During the technical conference, several panelists indicated 
that there has been limited interest in using CAISO's DER provider 
model (DERP). Please explain why DER aggregators have not used that 
model to date, what other approaches, if any, that DERs are using to 
access the CAISO and other RTO/ISO markets, and whether those 
alternative approaches provide adequate RTO/ISO market access for both 
behind-the-meter and front-of-meter DERs.
    8. During the technical conference, some panelists noted that for 
multi-node aggregations (a) there is a need to accurately represent the 
capabilities of DER aggregations at each node that they are located, 
and (b) more accurate representation at each node of a multi-node 
aggregation begins to make the aggregation look like a single-node 
resource. Some of the benefits discussed of multi-node aggregation 
included allowing an aggregation of DERs to provide more reliable 
services to the market and reducing transaction costs as a market 
participant, among others. Conversely, there was a discussion of the 
market operator's need to accurately represent the capabilities of the 
aggregation at individual nodes. Please comment on the benefits of 
being able to aggregate across multiple nodes versus the market 
operator's need to accurately represent the capabilities of the 
aggregation at individual nodes. If multi-node resources present risks 
or challenges to the system, what are they? Can they be overcome? How?
    9. During the panel discussion, CAISO mentioned that it allows 
multi-node aggregations within a defined set of nodes that have been 
deemed to have sufficiently little congestion across the nodes. Other 
panelists expressed a preference for single node aggregations. Are 
there methods to identify sets of nodes within which aggregation could 
be allowed that would balance concerns with multi-node aggregations 
against the benefits of multi-node aggregations. For instance, are 
there ways to group nodes associated with load centers that would 
facilitate aggregation while not threatening reliability and 
undermining the benefits of nodal pricing?
    10. Would reducing the minimum size requirement for DER 
aggregations to participate in the RTO/ISO markets (for example, to 100 
kW as proposed in the NYISO DER Roadmap) help alleviate some of the 
concerns about requiring DER aggregations to be located only at a 
single pricing node? Or, would locating at a single node inhibit the 
development of DER aggregations

[[Page 19748]]

regardless of the minimum size requirement?
    11. How are the concerns about constraints on the transmission 
system different for multi-node demand response aggregations versus 
multi-node DER aggregations?
    12. During the technical conference, some panelists raised 
questions regarding potential tradeoffs between establishing rules for 
DER aggregations now in anticipation of a high DER future, and the 
potential technology and market efficiency costs of requiring nodal 
aggregation or other measures to manage the potential effects of DER 
aggregations before it is necessary. What are these tradeoffs? Do they 
change over time? Does the penetration of DERs affect how to assess the 
tradeoffs? Does the penetration of DERs affect the appropriate 
locational requirements for DER aggregations?

Discussion of Operational Implications of DER Aggregation With State 
and Local Regulators (Panel 2)

    Comments are requested on state and local regulator concerns about 
the operational effects that DER participation in the wholesale market 
could have on facilities they regulate. Please respond to the following 
topics and questions that were included in previous supplemental 
notices:
    1. 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?
    2. 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?
    3. What entities should be included in the coordination processes 
used to facilitate the participation of DER aggregations in RTO/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?
    4. 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?
    5. 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?
    Based on the discussion at the April 10-11 Technical Conference, 
comments are also requested on the following additional question:
    6. During the technical conference, some panelists noted interest 
in a limited opt-out provision which would allow states to require DERs 
to choose participation in either the RTO/ISO market or retail 
compensation programs, but not both. How would such a limited opt-out 
be implemented? What are the benefits and drawbacks of such an 
approach?

Participation of DERs in RTO/ISO Markets (Panel 3)

    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\ In consideration 
of comments received in response to the NOPR, the Commission seeks 
additional information about 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.
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    \4\ Id. P 134.
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    Comments are requested on the following topics and questions that 
were included in previous supplemental notices:
    1. Given the variety of wholesale and retail services, is it 
possible to 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?
    2. 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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    3. 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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[[Page 19749]]

Coordination of DER Aggregations Participating in RTO/ISO Markets 
(Panel 6)

    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.\7\ 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. In 
consideration of comments received in response to the NOPR, the 
Commission seeks additional information on 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 \8\ 
can help identify the relationships among the entities involved in 
coordinating the integration of DER aggregations, the Commission is 
also interested in comments about potential architectural designs for 
the initial coordination processes from the point of view of the RTO/
ISO markets.
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    \7\ NOPR, FERC Stats. & Regs. ] 32,718 at P 154.
    \8\ 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 researchers have begun discussing different 
types of ``grid architecture,'' which presumably differ in 
structure, behavior or essential limits from current norms.
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    Comments are requested on the following topics and questions that 
were included in previous supplemental notices:
    1. 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?
    2. 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?
    3. 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?
    4. What is the best approach for involving retail regulatory 
authorities in the registration of DER aggregations in the RTO/ISO 
markets?
    5. 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?
    Based on the discussion at the April 10-11 Technical Conference, 
comments are also requested on the following additional questions:
    6. During the technical conference, several panelists expressed the 
need for criteria to evaluate the ability of an individual DER to 
participate in a DER aggregation. What specific criteria should 
distribution utilities use to evaluate the ability of a DER to 
participate in an aggregation, and who should set these criteria?
    7. During the technical conference, several panelists expressed the 
need for criteria to evaluate the ability of a DER aggregation to 
participate in the RTO/ISO markets. What specific criteria should 
distribution utilities use to evaluate the ability of a DER aggregation 
to participate in the RTO/ISO markets, and who should set these 
criteria?
    8. Some panelists suggested that the state and RTO/ISO 
interconnection processes could provide the means to evaluate the 
ability of a DER to participate in an RTO/ISO market. To the extent 
that RTOs/ISOs currently have a process that applies to the 
interconnection of DERs to Commission-jurisdictional transmission and 
distribution facilities, please explain the process and criteria 
evaluated, including referencing any relevant tariff or business 
practice manual provisions.
    9. During the technical conference, panelists highlighted the 
importance of coordination procedures and frameworks. Should 
coordination frameworks for DER aggregation, particularly between RTOs/
ISOs and distribution utilities, be required or encouraged to be 
developed between the appropriate entities?
    10. During the technical conference, some panelists commented on 
the importance of specifying roles with regard to DER aggregation. What 
should be the specific roles and responsibilities for distribution 
utilities, DER aggregators, retail regulators, and RTOs/ISOs associated 
with the participation of DER aggregators in RTO/ISO markets? Should 
the Commission specify these roles?
    11. During the technical conference, several panelists discussed 
the need to know the attributes of DERs on their distribution system. 
Please describe, where applicable, what types of static and dynamic 
information is currently being provided about aggregated or individual 
DERs to distribution utilities and to RTOs/ISOs. Is there additional 
static information about aggregated DERs or the individual DERs in 
those aggregations that distribution utilities need that would not be 
made available during the interconnection process? What, if any, 
dynamic information would the distribution utility need from the RTO/
ISO in real time regarding DER aggregations that are participating in 
the RTO/ISO markets, or the individual DERs in those aggregations? How 
would the distribution utility use this static or dynamic information?
    12. As more DERs are added to the distribution system, the system 
may become more variable due to the output of certain variable 
resources such as wind and solar PV, and the operation of self-
scheduled resources such as batteries and electric vehicles. Given this 
anticipated volatility at the distribution level, would the 
participation of aggregations of these DERs in the RTO/ISO markets 
further increase or decrease system variability?
    13. Do the safety and reliability concerns discussed at the 
technical conference exist on distribution systems with high DER 
penetration regardless of whether those resources are participating in 
the RTO/ISO markets? What current standards, procedures, or other 
measures are used to manage the safety and reliability of a 
distribution

[[Page 19750]]

system with high DER penetration where those resources do not 
participate in the RTO/ISO markets? Would these measures also help 
manage the safety and reliability of a distribution system where these 
resources do participate in the RTO/ISO markets? Would additional 
safety and reliability measures be necessary if DERs participate in the 
RTO/ISO markets, or would the current safeguards against backflows, 
islanding, or other concerns adequately ensure safety and reliability? 
If additional measures are necessary, what are they?

Ongoing Operational Coordination (Panel 7)

    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.\9\ 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.
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    \9\ NOPR, FERC Stats. & Regs. ] 32,718 at P 155.
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    Comments are requested on the following topics and questions that 
were included in previous supplemental notices:
    1. 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 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?
    2. 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?
    3. 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?
    4. 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?
    5. 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.
    6. Can real-time dispatch of aggregated DERs address distribution 
constraints? If not, can tools be developed to accomplish this?
    7. 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?
    8. 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. 2018-09455 Filed 5-3-18; 8:45 am]
 BILLING CODE 6717-01-P


