Modernizing Electricity Market Design; Notice Inviting Post-Technical Conference Comments, 70482-70485 [2021-26751]
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Federal Register / Vol. 86, No. 235 / Friday, December 10, 2021 / Notices
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intervention or protests.
Persons unable to file electronically
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assistance, contact the Federal Energy
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toll-free, (886) 208–3676 or TYY, (202)
502–8659.
Dated: December 6, 2021.
Kimberly D. Bose,
Secretary.
[FR Doc. 2021–26746 Filed 12–9–21; 8:45 am]
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DEPARTMENT OF ENERGY
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20426. Hand delivered submissions in
docketed proceedings should be
delivered to Health and Human
Services, 12225 Wilkins Avenue,
Rockville, Maryland 20852.
In addition to publishing the full text
of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the internet through the
Commission’s Home Page (https://
www.ferc.gov) using the ‘‘eLibrary’’ link.
Enter the docket number excluding the
last three digits in the docket number
field to access the document. At this
time, the Commission has suspended
access to the Commission’s Public
Reference Room, due to the
proclamation declaring a National
Emergency concerning the Novel
Coronavirus Disease (COVID–19), issued
by the President on March 13, 2020. For
assistance, contact the Federal Energy
Regulatory Commission at
FERCOnlineSupport@ferc.gov or call
toll-free, (886) 208–3676 or TYY, (202)
502–8659.
Dated: December 6, 2021.
Kimberly D. Bose,
Secretary.
[FR Doc. 2021–26749 Filed 12–9–21; 8:45 am]
BILLING CODE 6717–01–P
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DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. AD21–10–000]
Modernizing Electricity Market Design;
Notice Inviting Post-Technical
Conference Comments
On September 14, 2021 and October
12, 2021, the Federal Energy Regulation
Commission (Commission) convened
staff-led technical conferences to
discuss energy and ancillary services
markets in the evolving electricity
sector.
All interested persons are invited to
file initial and reply post-technical
conference comments on the topics in
Parts I and II below, which contain the
questions posed in each technical
conference agenda. Commenters may
reference material previously filed in
this docket, including the technical
conference transcripts, but are
encouraged to avoid repetition or
replication of previous material.
Commenters need not answer all of the
questions, but commenters are
encouraged to organize responses using
the numbering and order in the below
questions. Initial comments must be
submitted on or before February 4, 2022.
Reply comments must be submitted on
or before March 7, 2022.
I. Comments on Supplemental Notice
for September 14, 2021 Technical
Conference
We are seeking comments on the
topics discussed during the technical
conference held on September 14, 2021,
including responses to the questions
listed in the Supplemental Notice
issued in this proceeding on September
13, 2021 in accordance with the
deadlines and other guidance above.
The questions from the agenda are
included below.
Panel 1: Understanding the Need for
Additional Operational Flexibility in
RTO/ISO Energy and Ancillary Services
Markets
1. RTOs/ISOs and other industry
experts generally agree that power
systems will require greater flexibility
from system resources in the future.1
What operational capabilities or services
will be most valuable to RTO/ISO
operators in the future as the resource
mix and net load profile changes and
1 See, e.g., CAISO, Day-Ahead Market
Enhancements Revised Straw Proposal, at 7 (June
2020); SPP, Uncertainty Product Whitepaper, at 6
(Mar. 2020); NYISO, Reliability and Market
Considerations For A Grid in Transition, at 8–9
(Dec. 2019).
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why? Is there a desirable reaction time,
sustained performance duration, etc.
expected from a resource?
2. To what extent will the ‘‘traditional
ancillary services’’ defined in Order No.
888 2 and existing energy market designs
continue to ensure reliability as the
resource mix changes in RTO/ISO
markets in the future?
a. Will traditional ancillary services
provide the appropriate types and
adequate quantities of operational
flexibility RTOs/ISOs need to manage
both expected (e.g., reasonably
predictable) and unexpected (e.g.,
inherently uncertain and captured in
forecast errors) variability in net load?
b. Will existing RTO/ISO energy and
ancillary services market designs that
generally compensate certain traditional
ancillary services resources based on the
opportunity cost of foregone energy
sales—for example, spinning and nonspinning reserves—give resources a
sufficient economic incentive to offer
their flexible capabilities to the RTO/
ISO?
3. How should RTOs/ISOs define the
system’s need for operational flexibility,
now and in the future?
a. To what extent is operational
flexibility needed on a bi-directional
basis (i.e., both up and down) versus a
unidirectional basis (i.e., only up or
down)?
b. How do these needs compare to the
services provided by traditional
ancillary service products?
4. Could variable energy resources or
new resource types (e.g., storage, hybrid,
and co-located resources) be operated or
dispatched differently from the status
quo to provide greater operational
flexibility to the RTO/ISO, if so, how?
Given the evolving resource mix, are the
current eligibility requirements for each
resource type to provide ancillary
services appropriate?
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Panel 2: Revising Existing Operating
Reserve Demand Curves (ORDCs) To
Address Operational Flexibility Needs
in RTOs/ISOs
1. Contingency reserves are provided
by existing 10- and 30-minute reserve
products and are designed to ensure the
system can recover from a contingency
(e.g., a generator or transmission
outage). How will the procurement of
2 Order No. 888 required the following six
ancillary services be offered in an open access
transmission tariff: (1) Scheduling, System Control
and Dispatch Service; (2) Reactive Supply and
Voltage Control from Generation Sources Service;
(3) Regulation and Frequency Response Service; (4)
Energy Imbalance Service; (5) Operating Reserve—
Spinning Reserve Service; and (6) Operating
Reserve—Supplemental Reserve Service. Order No.
888, FERC Stats. and Regs. ¶ 31,036, at 31,703
(1996).
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additional contingency reserves help
RTO/ISO operators manage routine
operational flexibility needs (e.g. needs
driven by net load variability and
uncertainty)?
2. What are the benefits of procuring
contingency reserves beyond the
minimum reserve requirement through a
given ancillary service product?
a. If employing such a method, how
should RTOs/ISOs determine the
market’s demand for contingency
reserves (both the quantity and
willingness to pay) beyond the
minimum reserve requirement of a
given contingency reserve product?
b. What principles should RTOs/ISOs
follow if they consider revising the
shape of the ORDC for a given
contingency reserve product (e.g.,
introducing additional steps or
graduation to the ORDC curve)? For
example, should the willingness to pay
for such additional reserves be based on
the Value of Lost Load times the loss of
load probability with a given quantity of
the reserve product associated with the
ORDC, the cost of actions operators
would take to procure additional
reserves, or some other valuation
method? How should customer
willingness to pay be incorporated?
3. Reserve shortage prices are
administratively determined penalty
factors invoked when the system falls
below the minimum requirement of one
or more reserve products. To what
extent can higher reserve shortage prices
inform investment decisions and reflect
the value of flexible resource
capabilities?
a. What principles should RTOs/ISOs
follow if they consider revising the
shortage price associated with the ORDC
of a given contingency reserve?
b. How should the shortage prices of
individual contingency reserve products
be determined? For example, should the
shortage prices reflect the marginal
reliability value of each individual
reserve product? How should customer
willingness to pay be incorporated?
c. How should shortage pricing be
implemented when the system is short
both 10- and 30-minute reserves? Does
establishing shortage prices based on
the marginal reliability value of each
contingency reserve product that is in
shortage ensure that adding the shortage
prices reflects the combined reliability
impact of being short of those reserve
products?
d. Do differences in shortage prices
across regions present operational
challenges today? Is there an
expectation that such differences could
present operational challenges in the
future as the resource mix and load
profiles change? Is there a need to better
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align shortage pricing across RTOs/
ISOs, and if so, what principles should
be considered in doing so?
4. To what extent do RTOs/ISOs use
contingency reserves to manage noncontingency related operational
uncertainties (e.g., expected and
unexpected net load variability)? If such
reserves are used for this purpose,
should this alter an RTO/ISO’s approach
to establishing the maximum height and
shape of the ORDC? Under such
approaches, how do prices in the ORDC
appropriately reflect the marginal
reliability value contingency reserves
provide?
5. Is there a particular point at which
procuring reserves beyond the
minimum reserve requirement can
reduce or conflict with the objectives of
shortage prices? What is an appropriate
balance between raising shortage prices
and procuring reserves beyond the
minimum reserve requirement given
that procuring additional reserves can
reduce the probability of the RTO/ISO
experiencing a shortage?
Panel 3: Creating New Products To
Address Operational Flexibility Needs
in RTOs/ISOs
1. Ramp products, as distinguished
from traditional ancillary service
products, are relatively new ancillary
services that are in place in CAISO and
MISO, and approved for
implementation in SPP. Ramp products
are generally not designed to address
contingencies 3 but are instead a
mechanism to position the system
efficiently to meet forecasted ramping
needs in future intervals at least cost on
an expected basis.
a. RTO/ISO ramp products procure
ramp on a short-term basis (e.g., for
intervals of 10 or 15 minutes), but
longer-term ramp products are being
considered. For example, SPP is
considering a longer-term ramp
product 4 and the California Department
of Market Monitoring has advised
CAISO to consider a longer-term ramp
product.5 What drives the need for, and
what are the benefits of, a longer-term
ramp product compared to the existing
3 For example, ramping products are not designed
to be substitutable with the reserve products used
for managing contingencies. See e.g. CAISO,
Flexible Ramping Products Straw Proposal at 7, 10
(Nov. 1, 2011) https://www.caiso.com/Documents/
FlexibleRampingProductStrawProposal.pdf; Sw.
Power Pool, Inc., Filing, Docket No. ER20–1617–
000, at 13 (filed Apr. 21, 2020).
4 See Sw. Power Pool, Inc., ‘‘RR449—Uncertainty
Product’’ (July 27, 2021), https://www.spp.org/
Documents/64125/rr449.zip. See also Sw. Power
Pool, Inc., Uncertainty Product Prototype Design
Whitepaper (Mar. 13, 2020).
5 CAISO Department of Market Monitoring,
Comments on Issue Paper on Extending the DayAhead Market to EIM Entities, at 8 (Nov. 22, 2019).
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shorter-term ramp products or
traditional reserve products?
2. Will establishing reserve and ramp
prices based on foregone energy
revenues provide such signals in a
system with a high penetration of
variable energy resources, many of
which have low or zero marginal costs?
a. If not, what other options exist to
ensure sufficient compensation for
resources providing reserve and ramp
capability?
b. Historically, the prices for the ramp
products in CAISO and MISO have
often been zero. Are ramp prices
expected to increase over time as system
needs evolve? If so, what specific
conditions might cause ramp prices to
increase? Will any expected ramp price
increases be sufficient to incent and
appropriately compensate the ramp
capability RTOs/ISOs and others expect
will be needed due to the changing
resource mix?
3. CAISO is considering a Day-Ahead
Energy Market Enhancement proposal
that seeks to ensure that the day-ahead
market clears sufficient resources to
address expected net load variability
and uncertainty that arises between dayahead and real-time. What are the
expected advantages and disadvantages
of revising the day-ahead market
construct in this way to procure
additional operational flexibility?
4. The Electric Reliability Council of
Texas, Inc. (ERCOT) has proposed to
procure fast-responding, limited
duration products to address primary
frequency control issues associated with
declining system inertia.6 CAISO also
intends to initiate a stakeholder process
to discuss, among other options,
compensating internal resources for the
provision of primary frequency
response.7 What are the merits of such
reforms and should they be considered
in other regions?
5. What other new products not yet
discussed at this conference, do you
think could increase operational
flexibility in RTOs/ISOs?
a. Can capacity markets or other,
potentially new, ‘‘intermediate’’ forward
market constructs that clear between
existing capacity market auctions and
the day-ahead timeframe help ensure
that RTO/ISO operators have sufficient
operational flexibility in real time?
b. For example, can a new shorterterm forward market to procure
expected operational flexibility needs
6 See Pengwei Du et al., New Ancillary Service
Market for ERCOT, IEEE Access Volume 8, https://
ieeexplore.ieee.org/abstract/document/9208672.
7 See CAISO, 2021 Three-Year Policy Initiatives
Roadmap and Annual Plan, https://www.caiso.com/
InitiativeDocuments/2021FinalPolicyInitiatives
Roadmap.pdf.
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held closer to the delivery period (e.g.,
three months ahead as opposed to three
years ahead) and with a more granular
delivery period than the annual capacity
market (e.g., monthly or seasonal
delivery period, or a delivery period
based on the hours of an RTO/ISO’s
morning or evening ramp as opposed to
the annual delivery period of most RTO/
ISO capacity markets) help ensure that
RTO/ISO operators have sufficient
operational flexibility in real time?
Panel 4: Market Design Issues and
Tradeoffs To Consider in Reforms To
Increase Operational Flexibility in RTO/
ISO Energy and Ancillary Services
Markets
1. To date, most RTOs/ISOs have
pursued new ramping products or
ORDC reforms, but not both. What are
the tradeoffs to consider when deciding
between these two approaches and how
do they interact? Should these two types
of reforms be considered substitutes or
complements? Does the opportunitycost-based method of establishing
reserve and ramping product prices
send appropriate long-term signals to
resources to invest in or maintain
flexible capabilities?
2. Some entities have observed that
offering additional resource capabilities
into energy and ancillary services
markets may not be in the financial
interest of certain resources because
doing so could lower energy prices by
either avoiding scarcity conditions or
obviating the need to commit more
expensive units, and thus reduce their
expected energy and ancillary services
markets revenue. Are such incentive
issues relevant in the context of
reforming energy and ancillary services
markets to address operational
flexibility needs? If so, how should such
issues be addressed?
3. What other market design issues
and tradeoffs should RTOs/ISOs,
stakeholders, and regulators consider
when designing and implementing
reforms to energy and ancillary services
markets to increase operational
flexibility?
4. What are the tradeoffs to consider
in procuring flexibility in the energy
and ancillary services markets versus
the capacity market or another new
shorter-term forward market construct?
II. Comments on Supplemental Notice
for October 12, 2021 Technical
Conference
We are seeking comments on the
topics discussed during the technical
conference held on October 12, 2021,
including responses to the questions
listed in the Supplemental Notice
issued in this proceeding on October 7,
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2021 in accordance with the deadlines
and other guidance above. The
questions from the agenda are included
below.
Panel 1: Incenting Resources To Reflect
Their Full Operational Flexibility in
Energy and Ancillary Services Offers
1. Do any existing RTO/ISO energy
and ancillary services market
participation rules, supply offer rules,
eligibility requirements, and relevant
procedures encourage certain resources
to offer into the market inflexibly (i.e.,
without reflecting the full range of their
physical operating capabilities)? For
example, are any changes to resource
supply offer rules or uplift eligibility
requirements needed to ensure
resources submit physical offer
parameters (e.g., notification time,
minimum run time, ramp rates) that
reflect their flexible capabilities? To
what extent do RTOs/ISOs account for
existing fuel limitations, like natural gas
supplies, that have the potential to
impact resource flexibility?
2. Do any existing RTO/ISO energy
and ancillary services market rules
exhibit an undue preference for certain
resource types over other resource
types? If so, please explain how and
provide examples.
3. To what extent do existing selfscheduling or self-commitment rules in
RTO/ISO markets reduce the amount of
operational flexibility available to the
RTO/ISO in real time and the system’s
need for operational flexibility? Are
options for self-scheduling and selfcommitment needed to allow resource
owners to make the best use of their
assets over time?
4. Do current RTO/ISO offer rules,
market power mitigation practices, and
reference levels prevent or discourage
resources from including in their offers
the additional costs, if any, that
resources incur from being more flexible
(e.g., longer-term wear and tear on
natural gas resources due to increased
cycling, battery warranty
considerations, etc.)? Are such costs
difficult to quantify? If so, please
explain why. How should RTOs/ISOs
review such costs to ensure that
resources’ energy and ancillary services
supply offers are competitive?
Panel 2: Maximizing the Operational
Flexibility Available From New and
Emerging Resource Types
1. Do existing RTO/ISO energy and
ancillary services market rules,
practices, or procedures prevent or
otherwise obstruct relatively new and
emerging resource types from fully
participating in RTO/ISO markets and
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offering the operational flexibility they
are technically capable of providing?
2. To what extent do existing RTO/
ISO energy and ancillary services
market rules require standalone variable
energy resources to respond to dispatch
instructions (e.g., curtailment)?
a. To what extent are standalone
variable energy resources technically
capable of being ‘‘dispatchable?’’ Is
there a distinction between being
dispatched down and being curtailed?
b. Under what circumstances can a
standalone variable energy resource be
dispatched up versus down?
3. To what extent do resource
capabilities vary amongst different
classes and vintages of variable energy
resources (e.g., newer vs. older wind
turbine models, onshore vs. offshore
wind, fixed-tilt vs. tracking solar, etc.)
and do offer rules currently reflect such
differences, if any?
4. To what extent are emerging
resource types, such as hybrids, storage
resources, and distributed energy
resource aggregations technically
capable of providing existing ancillary
service products or other reliability
services? Acknowledging that some
market rules are evolving due to Order
Nos. 841 8 and 2222,9 do current RTO/
ISO market rules for ancillary services
and other reliability services, such as
eligibility requirements, align with these
emerging resource types’ capabilities?
5. What RTO/ISO energy and
ancillary services market reforms could
be adopted, if any, to ensure that new
and emerging resource types are able to
offer their full operational capabilities
into RTO/ISO energy and ancillary
services markets to help operators
manage changing system needs?
a. Would shortening the day-ahead
market interval length increase the
operational flexibility available from
resources? What considerations (e.g.,
computing time) are important to
consider when establishing the length of
energy and ancillary services market
intervals?
b. RTOs/ISOs often require resources
that provide ancillary services to be
capable of doing so for a duration of 60
minutes. Does this eligibility
requirement limit the pool of resources
available to offer ancillary services into
RTO/ISO markets? Would reexamining
the need for this particular eligibility
8 Electric Storage Participation in Markets
Operated by Regional Transmission Organizations
and Independent System Operators, Order No. 841,
83 FR 9580, 162 FERC ¶ 61.127.
9 Participation of Distributed Energy Resource
Aggregations in Markets Operated by Regional
Transmission Organizations and Independent
System Operators, Order No. 2222, 85 FR 67094,
172 FERC ¶ 61,247.
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requirement present reliability concerns
or raise other issues for operators? If so,
please explain.
Panel 3: Revising RTO/ISO Market
Models, Optimization, and Other
Software Elements To Address
Operational Flexibility Needs
1. What are the challenges to
incorporating uncertainty within the
current RTO/ISO market software? For
example, how can improvements in
forecasting, the use of intra-day
commitment processes that include a
range of forecasts, or longer look-ahead
commitment and dispatch horizons
result in more efficient unit
commitment and dispatch in real time?
2. Can changes to RTO/ISO unit
commitment and dispatch software
address the need to posture system
resources optimally to meet expected
and unexpected ramp and operational
flexibility needs?
a. How are these enhancements
tailored to the expected magnitude of
forecast errors in different time periods?
b. How would multi-period dispatch
modeling in the real-time market help
address operational flexibility needs?
What are the advantages and
disadvantages of a binding as opposed
to an advisory multi-period dispatch
model?
c. What are the computational
burdens associated with such modeling
enhancements?
3. To what extent can software
enhancements for modeling specific
technology types (e.g., multiconfiguration modeling of combined
cycle units, storage, etc.) help address
the system’s changing operational
needs?
4. Can multi-day-ahead markets or
hour-ahead markets help address
operational flexibility needs in RTOs/
ISOs? What is the objective of such
approaches, and are there potential
drawbacks?
Panel 4: Out-of-Market Operator Actions
Used To Manage Net Load Variability
and Uncertainty
1. RTO/ISO reports and filings to the
Commission indicate that at times
operators take out-of-market actions to
address net load uncertainty. What
impacts do such actions have on price
formation in RTO/ISO energy and
ancillary services markets? How strong
are those impacts, both in terms of
individual instances of operator actions
and in terms of more general effects on
the efficiency of the markets?
2. Do RTOs/ISOs anticipate that,
without RTO/ISO market reforms, outof-market operator actions will increase
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70485
over time in response to changing
system needs?
3. To what degree, if any, do out-ofmarket actions by operators undermine
RTO/ISO energy and ancillary services
market reforms, such as operating
reserve demand curve reforms or ramp
products, designed to incent resources
to provide RTO/ISO operators with the
operational flexibility needed to manage
the system?
4. How can RTOs/ISOs best mitigate
the risks of out-of-market operator
actions undermining incentives for
resource operational flexibility, to the
extent such risks exist?
Technical Information: Alex Smith,
Office of Energy Policy and Innovation,
Federal Energy Regulatory Commission,
888 First Street NE, Washington, DC
20426, (202) 502–6601,
alexander.smith@ferc.gov.
Legal Information: Adam Eldean,
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC 20426,
(202) 502–8047, adam.eldean@ferc.gov.
Dated: December 6, 2021.
Kimberly D. Bose,
Secretary.
[FR Doc. 2021–26751 Filed 12–9–21; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. ER22–541–000]
NSF Chaumont Site 1 LLC;
Supplemental Notice That Initial
Market-Based Rate Filing Includes
Request for Blanket Section 204
Authorization
This is a supplemental notice in the
above-referenced proceeding of NSF
Chaumont Site 1 LLC’s application for
market-based rate authority, with an
accompanying rate tariff, noting that
such application includes a request for
blanket authorization, under 18 CFR
part 34, of future issuances of securities
and assumptions of liability.
Any person desiring to intervene or to
protest should file with the Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC 20426,
in accordance with Rules 211 and 214
of the Commission’s Rules of Practice
and Procedure (18 CFR 385.211 and
385.214). Anyone filing a motion to
intervene or protest must serve a copy
of that document on the Applicant.
Notice is hereby given that the
deadline for filing protests with regard
to the applicant’s request for blanket
E:\FR\FM\10DEN1.SGM
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]]>Agencies
[Federal Register Volume 86, Number 235 (Friday, December 10, 2021)]
[Notices]
[Pages 70482-70485]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-26751]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. AD21-10-000]
Modernizing Electricity Market Design; Notice Inviting Post-
Technical Conference Comments
On September 14, 2021 and October 12, 2021, the Federal Energy
Regulation Commission (Commission) convened staff-led technical
conferences to discuss energy and ancillary services markets in the
evolving electricity sector.
All interested persons are invited to file initial and reply post-
technical conference comments on the topics in Parts I and II below,
which contain the questions posed in each technical conference agenda.
Commenters may reference material previously filed in this docket,
including the technical conference transcripts, but are encouraged to
avoid repetition or replication of previous material. Commenters need
not answer all of the questions, but commenters are encouraged to
organize responses using the numbering and order in the below
questions. Initial comments must be submitted on or before February 4,
2022. Reply comments must be submitted on or before March 7, 2022.
I. Comments on Supplemental Notice for September 14, 2021 Technical
Conference
We are seeking comments on the topics discussed during the
technical conference held on September 14, 2021, including responses to
the questions listed in the Supplemental Notice issued in this
proceeding on September 13, 2021 in accordance with the deadlines and
other guidance above. The questions from the agenda are included below.
Panel 1: Understanding the Need for Additional Operational Flexibility
in RTO/ISO Energy and Ancillary Services Markets
1. RTOs/ISOs and other industry experts generally agree that power
systems will require greater flexibility from system resources in the
future.\1\ What operational capabilities or services will be most
valuable to RTO/ISO operators in the future as the resource mix and net
load profile changes and
[[Page 70483]]
why? Is there a desirable reaction time, sustained performance
duration, etc. expected from a resource?
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\1\ See, e.g., CAISO, Day-Ahead Market Enhancements Revised
Straw Proposal, at 7 (June 2020); SPP, Uncertainty Product
Whitepaper, at 6 (Mar. 2020); NYISO, Reliability and Market
Considerations For A Grid in Transition, at 8-9 (Dec. 2019).
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2. To what extent will the ``traditional ancillary services''
defined in Order No. 888 \2\ and existing energy market designs
continue to ensure reliability as the resource mix changes in RTO/ISO
markets in the future?
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\2\ Order No. 888 required the following six ancillary services
be offered in an open access transmission tariff: (1) Scheduling,
System Control and Dispatch Service; (2) Reactive Supply and Voltage
Control from Generation Sources Service; (3) Regulation and
Frequency Response Service; (4) Energy Imbalance Service; (5)
Operating Reserve--Spinning Reserve Service; and (6) Operating
Reserve--Supplemental Reserve Service. Order No. 888, FERC Stats.
and Regs. ] 31,036, at 31,703 (1996).
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a. Will traditional ancillary services provide the appropriate
types and adequate quantities of operational flexibility RTOs/ISOs need
to manage both expected (e.g., reasonably predictable) and unexpected
(e.g., inherently uncertain and captured in forecast errors)
variability in net load?
b. Will existing RTO/ISO energy and ancillary services market
designs that generally compensate certain traditional ancillary
services resources based on the opportunity cost of foregone energy
sales--for example, spinning and non-spinning reserves--give resources
a sufficient economic incentive to offer their flexible capabilities to
the RTO/ISO?
3. How should RTOs/ISOs define the system's need for operational
flexibility, now and in the future?
a. To what extent is operational flexibility needed on a bi-
directional basis (i.e., both up and down) versus a unidirectional
basis (i.e., only up or down)?
b. How do these needs compare to the services provided by
traditional ancillary service products?
4. Could variable energy resources or new resource types (e.g.,
storage, hybrid, and co-located resources) be operated or dispatched
differently from the status quo to provide greater operational
flexibility to the RTO/ISO, if so, how? Given the evolving resource
mix, are the current eligibility requirements for each resource type to
provide ancillary services appropriate?
Panel 2: Revising Existing Operating Reserve Demand Curves (ORDCs) To
Address Operational Flexibility Needs in RTOs/ISOs
1. Contingency reserves are provided by existing 10- and 30-minute
reserve products and are designed to ensure the system can recover from
a contingency (e.g., a generator or transmission outage). How will the
procurement of additional contingency reserves help RTO/ISO operators
manage routine operational flexibility needs (e.g. needs driven by net
load variability and uncertainty)?
2. What are the benefits of procuring contingency reserves beyond
the minimum reserve requirement through a given ancillary service
product?
a. If employing such a method, how should RTOs/ISOs determine the
market's demand for contingency reserves (both the quantity and
willingness to pay) beyond the minimum reserve requirement of a given
contingency reserve product?
b. What principles should RTOs/ISOs follow if they consider
revising the shape of the ORDC for a given contingency reserve product
(e.g., introducing additional steps or graduation to the ORDC curve)?
For example, should the willingness to pay for such additional reserves
be based on the Value of Lost Load times the loss of load probability
with a given quantity of the reserve product associated with the ORDC,
the cost of actions operators would take to procure additional
reserves, or some other valuation method? How should customer
willingness to pay be incorporated?
3. Reserve shortage prices are administratively determined penalty
factors invoked when the system falls below the minimum requirement of
one or more reserve products. To what extent can higher reserve
shortage prices inform investment decisions and reflect the value of
flexible resource capabilities?
a. What principles should RTOs/ISOs follow if they consider
revising the shortage price associated with the ORDC of a given
contingency reserve?
b. How should the shortage prices of individual contingency reserve
products be determined? For example, should the shortage prices reflect
the marginal reliability value of each individual reserve product? How
should customer willingness to pay be incorporated?
c. How should shortage pricing be implemented when the system is
short both 10- and 30-minute reserves? Does establishing shortage
prices based on the marginal reliability value of each contingency
reserve product that is in shortage ensure that adding the shortage
prices reflects the combined reliability impact of being short of those
reserve products?
d. Do differences in shortage prices across regions present
operational challenges today? Is there an expectation that such
differences could present operational challenges in the future as the
resource mix and load profiles change? Is there a need to better align
shortage pricing across RTOs/ISOs, and if so, what principles should be
considered in doing so?
4. To what extent do RTOs/ISOs use contingency reserves to manage
non-contingency related operational uncertainties (e.g., expected and
unexpected net load variability)? If such reserves are used for this
purpose, should this alter an RTO/ISO's approach to establishing the
maximum height and shape of the ORDC? Under such approaches, how do
prices in the ORDC appropriately reflect the marginal reliability value
contingency reserves provide?
5. Is there a particular point at which procuring reserves beyond
the minimum reserve requirement can reduce or conflict with the
objectives of shortage prices? What is an appropriate balance between
raising shortage prices and procuring reserves beyond the minimum
reserve requirement given that procuring additional reserves can reduce
the probability of the RTO/ISO experiencing a shortage?
Panel 3: Creating New Products To Address Operational Flexibility Needs
in RTOs/ISOs
1. Ramp products, as distinguished from traditional ancillary
service products, are relatively new ancillary services that are in
place in CAISO and MISO, and approved for implementation in SPP. Ramp
products are generally not designed to address contingencies \3\ but
are instead a mechanism to position the system efficiently to meet
forecasted ramping needs in future intervals at least cost on an
expected basis.
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\3\ For example, ramping products are not designed to be
substitutable with the reserve products used for managing
contingencies. See e.g. CAISO, Flexible Ramping Products Straw
Proposal at 7, 10 (Nov. 1, 2011) https://www.caiso.com/Documents/FlexibleRampingProductStrawProposal.pdf; Sw. Power Pool, Inc.,
Filing, Docket No. ER20-1617-000, at 13 (filed Apr. 21, 2020).
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a. RTO/ISO ramp products procure ramp on a short-term basis (e.g.,
for intervals of 10 or 15 minutes), but longer-term ramp products are
being considered. For example, SPP is considering a longer-term ramp
product \4\ and the California Department of Market Monitoring has
advised CAISO to consider a longer-term ramp product.\5\ What drives
the need for, and what are the benefits of, a longer-term ramp product
compared to the existing
[[Page 70484]]
shorter-term ramp products or traditional reserve products?
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\4\ See Sw. Power Pool, Inc., ``RR449--Uncertainty Product''
(July 27, 2021), https://www.spp.org/Documents/64125/rr449.zip. See
also Sw. Power Pool, Inc., Uncertainty Product Prototype Design
Whitepaper (Mar. 13, 2020).
\5\ CAISO Department of Market Monitoring, Comments on Issue
Paper on Extending the Day-Ahead Market to EIM Entities, at 8 (Nov.
22, 2019).
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2. Will establishing reserve and ramp prices based on foregone
energy revenues provide such signals in a system with a high
penetration of variable energy resources, many of which have low or
zero marginal costs?
a. If not, what other options exist to ensure sufficient
compensation for resources providing reserve and ramp capability?
b. Historically, the prices for the ramp products in CAISO and MISO
have often been zero. Are ramp prices expected to increase over time as
system needs evolve? If so, what specific conditions might cause ramp
prices to increase? Will any expected ramp price increases be
sufficient to incent and appropriately compensate the ramp capability
RTOs/ISOs and others expect will be needed due to the changing resource
mix?
3. CAISO is considering a Day-Ahead Energy Market Enhancement
proposal that seeks to ensure that the day-ahead market clears
sufficient resources to address expected net load variability and
uncertainty that arises between day-ahead and real-time. What are the
expected advantages and disadvantages of revising the day-ahead market
construct in this way to procure additional operational flexibility?
4. The Electric Reliability Council of Texas, Inc. (ERCOT) has
proposed to procure fast-responding, limited duration products to
address primary frequency control issues associated with declining
system inertia.\6\ CAISO also intends to initiate a stakeholder process
to discuss, among other options, compensating internal resources for
the provision of primary frequency response.\7\ What are the merits of
such reforms and should they be considered in other regions?
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\6\ See Pengwei Du et al., New Ancillary Service Market for
ERCOT, IEEE Access Volume 8, https://ieeexplore.ieee.org/abstract/document/9208672.
\7\ See CAISO, 2021 Three-Year Policy Initiatives Roadmap and
Annual Plan, https://www.caiso.com/InitiativeDocuments/2021FinalPolicyInitiativesRoadmap.pdf.
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5. What other new products not yet discussed at this conference, do
you think could increase operational flexibility in RTOs/ISOs?
a. Can capacity markets or other, potentially new, ``intermediate''
forward market constructs that clear between existing capacity market
auctions and the day-ahead timeframe help ensure that RTO/ISO operators
have sufficient operational flexibility in real time?
b. For example, can a new shorter-term forward market to procure
expected operational flexibility needs held closer to the delivery
period (e.g., three months ahead as opposed to three years ahead) and
with a more granular delivery period than the annual capacity market
(e.g., monthly or seasonal delivery period, or a delivery period based
on the hours of an RTO/ISO's morning or evening ramp as opposed to the
annual delivery period of most RTO/ISO capacity markets) help ensure
that RTO/ISO operators have sufficient operational flexibility in real
time?
Panel 4: Market Design Issues and Tradeoffs To Consider in Reforms To
Increase Operational Flexibility in RTO/ISO Energy and Ancillary
Services Markets
1. To date, most RTOs/ISOs have pursued new ramping products or
ORDC reforms, but not both. What are the tradeoffs to consider when
deciding between these two approaches and how do they interact? Should
these two types of reforms be considered substitutes or complements?
Does the opportunity-cost-based method of establishing reserve and
ramping product prices send appropriate long-term signals to resources
to invest in or maintain flexible capabilities?
2. Some entities have observed that offering additional resource
capabilities into energy and ancillary services markets may not be in
the financial interest of certain resources because doing so could
lower energy prices by either avoiding scarcity conditions or obviating
the need to commit more expensive units, and thus reduce their expected
energy and ancillary services markets revenue. Are such incentive
issues relevant in the context of reforming energy and ancillary
services markets to address operational flexibility needs? If so, how
should such issues be addressed?
3. What other market design issues and tradeoffs should RTOs/ISOs,
stakeholders, and regulators consider when designing and implementing
reforms to energy and ancillary services markets to increase
operational flexibility?
4. What are the tradeoffs to consider in procuring flexibility in
the energy and ancillary services markets versus the capacity market or
another new shorter-term forward market construct?
II. Comments on Supplemental Notice for October 12, 2021 Technical
Conference
We are seeking comments on the topics discussed during the
technical conference held on October 12, 2021, including responses to
the questions listed in the Supplemental Notice issued in this
proceeding on October 7, 2021 in accordance with the deadlines and
other guidance above. The questions from the agenda are included below.
Panel 1: Incenting Resources To Reflect Their Full Operational
Flexibility in Energy and Ancillary Services Offers
1. Do any existing RTO/ISO energy and ancillary services market
participation rules, supply offer rules, eligibility requirements, and
relevant procedures encourage certain resources to offer into the
market inflexibly (i.e., without reflecting the full range of their
physical operating capabilities)? For example, are any changes to
resource supply offer rules or uplift eligibility requirements needed
to ensure resources submit physical offer parameters (e.g.,
notification time, minimum run time, ramp rates) that reflect their
flexible capabilities? To what extent do RTOs/ISOs account for existing
fuel limitations, like natural gas supplies, that have the potential to
impact resource flexibility?
2. Do any existing RTO/ISO energy and ancillary services market
rules exhibit an undue preference for certain resource types over other
resource types? If so, please explain how and provide examples.
3. To what extent do existing self-scheduling or self-commitment
rules in RTO/ISO markets reduce the amount of operational flexibility
available to the RTO/ISO in real time and the system's need for
operational flexibility? Are options for self-scheduling and self-
commitment needed to allow resource owners to make the best use of
their assets over time?
4. Do current RTO/ISO offer rules, market power mitigation
practices, and reference levels prevent or discourage resources from
including in their offers the additional costs, if any, that resources
incur from being more flexible (e.g., longer-term wear and tear on
natural gas resources due to increased cycling, battery warranty
considerations, etc.)? Are such costs difficult to quantify? If so,
please explain why. How should RTOs/ISOs review such costs to ensure
that resources' energy and ancillary services supply offers are
competitive?
Panel 2: Maximizing the Operational Flexibility Available From New and
Emerging Resource Types
1. Do existing RTO/ISO energy and ancillary services market rules,
practices, or procedures prevent or otherwise obstruct relatively new
and emerging resource types from fully participating in RTO/ISO markets
and
[[Page 70485]]
offering the operational flexibility they are technically capable of
providing?
2. To what extent do existing RTO/ISO energy and ancillary services
market rules require standalone variable energy resources to respond to
dispatch instructions (e.g., curtailment)?
a. To what extent are standalone variable energy resources
technically capable of being ``dispatchable?'' Is there a distinction
between being dispatched down and being curtailed?
b. Under what circumstances can a standalone variable energy
resource be dispatched up versus down?
3. To what extent do resource capabilities vary amongst different
classes and vintages of variable energy resources (e.g., newer vs.
older wind turbine models, onshore vs. offshore wind, fixed-tilt vs.
tracking solar, etc.) and do offer rules currently reflect such
differences, if any?
4. To what extent are emerging resource types, such as hybrids,
storage resources, and distributed energy resource aggregations
technically capable of providing existing ancillary service products or
other reliability services? Acknowledging that some market rules are
evolving due to Order Nos. 841 \8\ and 2222,\9\ do current RTO/ISO
market rules for ancillary services and other reliability services,
such as eligibility requirements, align with these emerging resource
types' capabilities?
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\8\ Electric Storage Participation in Markets Operated by
Regional Transmission Organizations and Independent System
Operators, Order No. 841, 83 FR 9580, 162 FERC ] 61.127.
\9\ Participation of Distributed Energy Resource Aggregations in
Markets Operated by Regional Transmission Organizations and
Independent System Operators, Order No. 2222, 85 FR 67094, 172 FERC
] 61,247.
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5. What RTO/ISO energy and ancillary services market reforms could
be adopted, if any, to ensure that new and emerging resource types are
able to offer their full operational capabilities into RTO/ISO energy
and ancillary services markets to help operators manage changing system
needs?
a. Would shortening the day-ahead market interval length increase
the operational flexibility available from resources? What
considerations (e.g., computing time) are important to consider when
establishing the length of energy and ancillary services market
intervals?
b. RTOs/ISOs often require resources that provide ancillary
services to be capable of doing so for a duration of 60 minutes. Does
this eligibility requirement limit the pool of resources available to
offer ancillary services into RTO/ISO markets? Would reexamining the
need for this particular eligibility requirement present reliability
concerns or raise other issues for operators? If so, please explain.
Panel 3: Revising RTO/ISO Market Models, Optimization, and Other
Software Elements To Address Operational Flexibility Needs
1. What are the challenges to incorporating uncertainty within the
current RTO/ISO market software? For example, how can improvements in
forecasting, the use of intra-day commitment processes that include a
range of forecasts, or longer look-ahead commitment and dispatch
horizons result in more efficient unit commitment and dispatch in real
time?
2. Can changes to RTO/ISO unit commitment and dispatch software
address the need to posture system resources optimally to meet expected
and unexpected ramp and operational flexibility needs?
a. How are these enhancements tailored to the expected magnitude of
forecast errors in different time periods?
b. How would multi-period dispatch modeling in the real-time market
help address operational flexibility needs? What are the advantages and
disadvantages of a binding as opposed to an advisory multi-period
dispatch model?
c. What are the computational burdens associated with such modeling
enhancements?
3. To what extent can software enhancements for modeling specific
technology types (e.g., multi-configuration modeling of combined cycle
units, storage, etc.) help address the system's changing operational
needs?
4. Can multi-day-ahead markets or hour-ahead markets help address
operational flexibility needs in RTOs/ISOs? What is the objective of
such approaches, and are there potential drawbacks?
Panel 4: Out-of-Market Operator Actions Used To Manage Net Load
Variability and Uncertainty
1. RTO/ISO reports and filings to the Commission indicate that at
times operators take out-of-market actions to address net load
uncertainty. What impacts do such actions have on price formation in
RTO/ISO energy and ancillary services markets? How strong are those
impacts, both in terms of individual instances of operator actions and
in terms of more general effects on the efficiency of the markets?
2. Do RTOs/ISOs anticipate that, without RTO/ISO market reforms,
out-of-market operator actions will increase over time in response to
changing system needs?
3. To what degree, if any, do out-of-market actions by operators
undermine RTO/ISO energy and ancillary services market reforms, such as
operating reserve demand curve reforms or ramp products, designed to
incent resources to provide RTO/ISO operators with the operational
flexibility needed to manage the system?
4. How can RTOs/ISOs best mitigate the risks of out-of-market
operator actions undermining incentives for resource operational
flexibility, to the extent such risks exist?
Technical Information: Alex Smith, Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, (202) 502-6601, [email protected].
Legal Information: Adam Eldean, Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426, (202) 502-8047, [email protected].
Dated: December 6, 2021.
Kimberly D. Bose,
Secretary.
[FR Doc. 2021-26751 Filed 12-9-21; 8:45 am]
BILLING CODE 6717-01-P
