83 FR 7703 - Notice of Technical Conference

DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission

Federal Register Volume 83, Issue 36 (February 22, 2018)

Page Range		7703-7707
FR Document		2018-03649

Federal Register, Volume 83 Issue 36 (Thursday, February 22, 2018)

[Federal Register Volume 83, Number 36 (Thursday, February 22, 2018)]
[Notices]
[Pages 7703-7707]
From the Federal Register Online [www.thefederalregister.org]
[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 accessibility@ferc.gov 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, david.kathan@ferc.gov, or
Louise Nutter at (202) 502-8175, louise.nutter@ferc.gov. For
information related to logistics, please contact Sarah McKinley at
(202) 502-8368, sarah.mckinley@ferc.gov.

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

7704 Federal Register / Vol. 83, No. 36 / Thursday, February 22, 2018 / Notices

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

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7706 Federal Register / Vol. 83, No. 36 / Thursday, February 22, 2018 / Notices

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

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Federal Register / Vol. 83, No. 36 / Thursday, February 22, 2018 / Notices 7707

transmission and distribution operators DEPARTMENT OF ENERGY The filings in the above proceeding
to assess distribution system conditions are accessible in the Commission’s
in real time? Are new systems or Federal Energy Regulatory eLibrary system by clicking on the
approaches needed? Does DER Commission appropriate link in the above list. They
aggregation require separate or [Docket Nos. EL17–70–000; QF17–935–001; are also available for review in the
additional capabilities and QF17–936–001] Commission’s Public Reference Room in
infrastructure for communication and Washington, DC. There is an
control? Zeeland Farm Services, Inc.; Notice of eSubscription link on the website that
• What processes/protocols do Amended Petition for Declaratory enables subscribers to receive email
distribution utilities, transmission Order notification when a document is added
operators, and DERs or DER aggregators to a subscribed docket(s). For assistance
Take notice that on February 14, 2018, with any FERC Online service, please
use to coordinate with each other? Are pursuant to Rule 215 of the Rules of
these processes/protocols capable of email FERCOnlineSupport@ferc.gov.or
Practice and Procedure of the Federal call (866) 208–3676 (toll free). For TTY,
providing needed real-time Energy Regulatory Commission
communications and coordination? call (202) 502–8659.
(Commission),1 and section Comment Date: 5:00 p.m. Eastern time
What new processes, resources, and 292.203(d)(2) of the Commission’s
efforts will be required to achieve on March 7, 2018.
regulations,2 Zeeland Farm Services,
effective real-time coordination? Inc. (Zeeland or Petitioner) submitted an Dated: February 15, 2018.
• What are the minimum set of amendment to its petition for Nathaniel J. Davis, Sr.,
specific RTO/ISO operational protocols, declaratory order, filed on May 3, 2017, Deputy Secretary.
performance standards, and market requesting that the Commission grant [FR Doc. 2018–03647 Filed 2–21–18; 8:45 am]
rules that should be adopted now to Zeeland limited waiver from the FERC BILLING CODE 6717–01–P
ensure operational coordination for DER Form 556 filing requirement 3 for two
aggregation participating in the RTO/ qualifying small power production
ISO markets? What additional protocols facilities, as more fully explained in the DEPARTMENT OF ENERGY
may be important for the future? Should petition.
the Commission adopt more Any person desiring to intervene or to Federal Energy Regulatory
prescriptive requirements with respect protest in this proceeding must file in Commission
to coordination than those proposed in accordance with Rules 211 and 214 of [Project No. 2804–035]
the NOPR? If so, what should the the Commission’s Rules of Practice and
Commission require? Procedure (18 CFR 385.211 and Goose River Hydro, Inc.; Notice of
• Should distribution utilities be able 385.214) on or before 5:00 p.m. Eastern Application Tendered for Filing With
to override RTO/ISO decisions time on the specified comment date. the Commission and Soliciting
regarding day-ahead and real-time Protests will be considered by the Additional Study Requests
dispatch of DER aggregations to resolve Commission in determining the
appropriate action to be taken, but will Take notice that the following
local distribution reliability issues? If hydroelectric application has been filed
so, should DER aggregations nonetheless not serve to make protestants parties to
the proceeding. Any person wishing to with the Commission and is available
be subject to non-deliverability for public inspection.
penalties under such circumstances? become a party must file a notice of
intervention or motion to intervene, as a. Type of Application: New minor
• Is it possible for DERs or DER license
appropriate. Such notices, motions, or
aggregations participating in the RTO/ b. Project No.: P–2804–035
protests must be filed on or before the
ISO markets to also be used to improve c. Date filed: February 2, 2018
comment date. Anyone filing a motion
distribution system operations and d. Applicant: Goose River Hydro, Inc.
to intervene or protest must serve a copy
reliability? If so, please provide e. Name of Project: Goose River
of that document on the Petitioner.
examples of how this could be The Commission encourages Hydroelectric Project
accomplished. electronic submission of protests and f. Location: On the Goose River, near
• Can real-time dispatch of aggregated interventions in lieu of paper, using the Belfast, Waldo County, Maine. No
DERs address distribution constraints? If FERC Online links at http:// federal or tribal lands would be
not, can tools be developed to www.ferc.gov. To facilitate electronic occupied by project works or located
accomplish this? service, persons with internet access within the project boundary.
• Should individual DERs be required who will eFile a document and/or be g. Filed Pursuant to: Federal Power
to have communications capabilities to listed as a contact for an intervenor Act 16 U.S.C. 791(a)–825(r).
comply with control center obligations? must create and validate an h. Applicant Contact: Nicholas
What level of communications security eRegistration account using the Cabral, Goose River Hydro Inc., 67 Swan
should be employed for these eRegistration link. Select the eFiling Lake Ave., Belfast, ME 04095, (207)–
communications? link to log on and submit the 604–4394, gooseriverhydro@gmail.com.
intervention or protests. i. FERC Contact: Julia Kolberg, 888 1st
• How might recent and expected St. NE, Washington, DC 20426, (202)
technical advancements be used to Persons unable to file electronically
should submit an original and 5 copies 502–8261, Julia.kolberg@ferc.gov.
enhance the coordination of DER j. Cooperating agencies: Federal, state,
of the intervention or protest to the
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aggregations, for example, integrating local, and tribal agencies with
Energy Management Systems (EMS) and Federal Energy Regulatory Commission,
888 First Street NE, Washington, DC jurisdiction and/or special expertise
Distribution Management Systems with respect to environmental issues
(DMS) for efficient operational 20426.
that wish to cooperate in the
coordination? 1 18 preparation of the environmental
CFR 385.215 (2017).
[FR Doc. 2018–03649 Filed 2–21–18; 8:45 am] 2 18 CFR 292.203(d)(2). document should follow the
BILLING CODE 6717–01–P 3 18 CFR 292.203(a)(3). instructions for filing such requests

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Document Created: 2018-02-22 02:50:50
Document Modified: 2018-02-22 02:50:50

Category		Regulatory Information
Collection		Federal Register
sudoc Class		AE 2.7: GS 4.107: AE 2.106:
Publisher		Office of the Federal Register, National Archives and Records Administration
Section		Notices
FR Citation		83 FR 7703

83 FR 7703 - Notice of Technical Conference

DEPARTMENT OF ENERGYFederal Energy Regulatory Commission

Federal Register Volume 83, Issue 36 (February 22, 2018)

DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission