[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, <a href="/cdn-cgi/l/email-protection#02686d6a6c2c706b676a6e42646770612c656d74"><span class="__cf_email__" data-cfemail="600a0f080e4e120905080c20060512034e070f16">[email protected]</span></a>, Noah Monick (Legal 
Issues), Office of General Counsel, 202-502-8299, <a href="/cdn-cgi/l/email-protection#462829272e682b29282f252d062023342568212930"><span class="__cf_email__" data-cfemail="87e9e8e6efa9eae8e9eee4ecc7e1e2f5e4a9e0e8f1">[email protected]</span></a>.

    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


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