[Federal Register Volume 83, Number 119 (Wednesday, June 20, 2018)]
[Notices]
[Pages 28633-28635]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-13194]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket Nos. EL17-32-000; EL17-36-000]
Notice Inviting Post-Technical Conference Comments; Old Dominion
Electric Cooperative v. PJM Interconnection, L.L.C., Advanced Energy
Management Alliance v. PJM Interconnection, L.L.C
On April 24, 2018, Federal Energy Regulatory Commission
(Commission) staff convened a technical conference to obtain further
information concerning the above referenced proceedings pursuant to a
February 23, 2018 Commission order.\1\
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\1\ Old Dominion Elec. Coop. v. PJM Interconnection, L.L.C., 162
FERC 61,160 (2018).
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All interested persons are invited to file post-technical
conference comments on issues raised during the conference that they
believe would benefit from further discussion. In addition, parties are
invited to provide comments on the questions listed below, as well as
the questions featured on the Supplement Notice of Technical Conference
and Technical Conference Agenda issued on April 18, 2018.\2\ Commenters
need not respond to all topics or questions asked.
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\2\ Supplemental Notice of Technical Conference, Docket No.
EL17-32-000 and EL17-36-000 (Apr. 18, 2018).
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Commenters may reference material previously filed in this docket,
including the technical conference transcript, but are encouraged to
avoid repetition or replication of previous material. In addition,
commenters are encouraged, when possible, to provide examples in
support of their answers.
[[Page 28634]]
Comments must be submitted on or before 30 days from the date of this
notice and should not exceed 30 pages.
For more information about this technical conference, please
contact: John Riehl (Technical Issues), Office of Energy Market
Regulation, 202-502-6026, [email protected], Noah Monick (Legal
Issues), Office of General Counsel, 202-502-8299, [email protected].
Dated: June 13, 2018.
Kimberly D. Bose,
Secretary.
Post-Technical Conference Questions for Comment
Seasonal Load Variation & Alternate Market Designs
In these proceedings, parties argue that the move to a single,
annual capacity product has pushed valuable summer-only resources out
of the capacity market and thereby increased capacity costs with little
to no reliability benefit, given that PJM is a summer-peaking system.
These parties assert that procuring a portion of capacity as summer-
only allows PJM to procure significantly less capacity during non-
summer periods and provides equivalent reliability at lower total
capacity costs. In addition, intervenors have proposed alternate market
designs in PJM to better facilitate seasonal resource participation and
account for seasonal load variation. These proposed alternative market
designs include, but are not limited to: A re-introduction of a
seasonal product,\3\ a two-season market construct,\4\ a three-season
market construct,\5\ and a supplemental seasonal ticket scheme approach
for summer-period resources.\6\ Based on these proposed alternate
market designs, please answer the following questions.
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\3\ Preliminary Technical Conference Comments of Complainants
Old Dominion Electric Cooperative, Direct Energy Business, LLC, and
American Municipal Power, Inc. at 11-14.
\4\ Pre-Technical Conference Comments of NRDC & Sustainable FERC
Project at 10.
\5\ Pre-Technical Conference Comments of Advanced Energy
Management Alliance at 5-6.
\6\ Pre-Technical Conference Comments of James F. Wilson at 11.
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1. Some panelists indicated that the current annual construct and
existing aggregation rules result in a barrier to entry. Please comment
on whether or not there are barriers to entry and provide any
supporting information, such as unmatched MWs of capacity. Could this
be fully addressed by improving or modifying aggregation rules? If not,
what other changes would be required? What would be the downside of
modifying such rules?
2. According to the 2021/2022 Reliability Pricing Model (RPM) Base
Residual Auction (BRA) report,\7\ cleared megawatt quantities of wind,
solar, demand response, and energy efficiency resources all increased
compared to the 2020/2021 RPM BRA and at higher clearing prices
throughout the PJM footprint. Please comment on how these results
reflect on the efficacy of PJM's seasonal aggregation mechanism and the
ability of these resource types to participate in RPM as either annual
resources or aggregated resources under existing RPM rules. To the
extent you view one or more of the alternative market designs mentioned
above as better than the existing RPM rules, please explain how those
alternative designs would yield preferable auction outcomes relative to
those seen in the 2021/2022 BRA. Please provide evidence and
quantitative support where possible.
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\7\ PJM Interconnection, L.L.C., 2021/2022 RPM Base Residual
Auction Results (May 2018), available at: http://www.pjm.com/-/media/markets-ops/rpm/rpm-auction-info/2021-2022/2021-2022-base-residual-auction-report.ashx.
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3. Under either a two-season or three-season market construct, how
would PJM optimize capacity procurement within and across seasons?
Would each season have a distinct demand curve and auction that clears
independently of other seasons, or would all seasonal auctions be
cleared simultaneously to optimize procurement for a delivery year?
4. During the technical conference, Mr. Falin of PJM noted that PJM
performs a winter-period peak load test known as a Capacity Emergency
Transfer Objective and Capacity Emergency Transfer Limit (CETO CETL
analysis). Mr. Falin explained that during the winter-period CETO CETL
analysis, PJM divides its region into sub-regions and tests how many
MWs of emergency imports are needed to satisfy reliability criteria
given that specific sub-region's quantity of installed reserves.\8\
Please describe the assumptions that PJM makes when it performs a CETO/
CETL analysis for winter-period peak loads. What assumptions are
markedly different from summer-period peak load CETO/CETL analyses?
Does PJM perform winter- and summer-period CETO/CETL analyses for all
sub-areas or LDAs?
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\8\ Tr. 83:5-13 (Falin).
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5. What other implementation challenges would be involved in
transitioning to a two-season or three-season market construct (aside
from a lengthy stakeholder process)?
Peak Shaving
In these proceedings, intervenors argue that the practice of peak
shaving produces far fewer benefits than previously understood and,
thus, peak shaving practices are not a viable pathway for demand
response resources in lieu of participation on the supply side of PJM's
capacity market. Based on this characterization of peak shaving's
limited impacts, please address the following questions.
1. During the technical conference, Mr. Falin of PJM indicated that
PJM has put on hold possible changes to the PRD program to align the
program with PJM's annual capacity construct. Is PRD a feasible path
forward for incorporating seasonal DR resources in the capacity market?
Please explain why or why not.
2. During the technical conference, Mr. Falin stated that, in order
for peak shaving activity to be reflected in load forecasts, peak
shaving actions will need to be based on specific triggers, and commit
to be interrupted a certain number of times per summer with a certain
hourly duration. Direct load control programs operated by electric
distribution companies that cycle air conditioners or other appliances
typically have these attributes specified in their tariffs. What is the
status of the recognition of these programs in PJM's load forecasts?
Please describe the mechanisms, calculations, and adjustments that PJM
uses to account for load serving entity (LSE) or electric distribution
company (EDC) direct load control and load management programs in PJM
load forecasting. Are these load forecast adjustments performed at the
request of the EDC, or are there clear and specific procedures or rules
that are applied non-discriminatorily to all LSE and electric
distribution company direct load control and load management programs?
3. During the technical conference, Mr. Falin stated that PJM
conducts its load forecast modeling, and calculates model forecast
accuracy, at the PJM system level. Mr. Falin also stated that PJM
compared forecasted zonal load to average historical contribution of
each zone to the PJM's overall peak and that number is within a tenth
or two-tenths of a percent of PJM's zonal forecast. Did PJM observe any
differences in the model errors by zone, especially for the zones that
have operated summer-focused load management programs for years? How
does the frequency of summer-focused load management programs'
deployment, especially their infrequent deployment during system peaks,
impact PJM load forecasts and
[[Page 28635]]
the calculated model errors at the zonal level?
4. According to information provided in the AEMA complaint in
Docket No. EL17-36-000, Baltimore Gas & Electric (BG&E) worked with PJM
in Maryland Public Service Commission Rate Case No. 9406 to reflect its
air-conditioner direct control program into an alternate load forecast
for its zone, but not at the full load reduction that the program can
produce. Please describe the processes involved in creating that
alternative load forecast and the assumptions underlying BG&E's partial
adjustment.
5. In PJM's June 2017 white paper ``Demand Response Strategy'', PJM
stated ``Ideally, PJM would have a truly unrestricted peak-load
forecast with a complete understanding of explicit (dispatch and/or
managed by PJM) versus implicit (managed by LSE, EDC or end-use
customer) DR, allowing more visibility to quantify forecast risk.'' \9\
Please describe the steps PJM is taking to accomplish this goal. Are
these steps sufficient to accomplish this goal? Why or why not? How is
PJM working to change its load forecasting methodology to achieve this
goal?
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\9\ PJM Interconnection, Demand Response Strategy at 30-31,
(Jun. 2017), available at http://www.pjm.com/~/media/library/
reports-notices/demand-response/20170628-pjm-demand-response-
strategy.ashx.
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[FR Doc. 2018-13194 Filed 6-19-18; 8:45 am]
BILLING CODE 6717-01-P