EL25-49-000 · 2026-10-14 · PJM
Motion for Leave to Answer and Answer of PJM Interconnection, L.L.C. to the limited protests of its August 17, 2026 compliance filing (EL25-49 and ER26-1479)
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
)
PJM Interconnection, L.L.C.
)
Docket Nos. EL25-49-000
)
EL25-49-001
)
EL25-49-002
)
)
PJM Interconnection, L.L.C.
)
Docket No. ER26-1479-000
)
MOTION FOR LEAVE TO ANSWER AND ANSWER OF PJM
INTERCONNECTION, L.L.C.
PJM Interconnection, L.L.C. (“PJM”), pursuant to Federal Energy Regulatory
Commission (“Commission” or “FERC”) Rules 212 and 213 of Practice and Procedure,1
respectfully moves2 to answer the limited protests filed in response to PJM’s August 17,
2026 compliance filing (“August Filing”).3 Several parties filed limited protests
concerning discrete aspects of the August Filing. 4 PJM provides this answer to clarify the
1 18 C.F.R. §§ 385.212, 385.213.
2 Good cause exists for the Commission to permit PJM’s answer. The Commission routinely accepts answers
to comments and protests when doing so will ensure a more accurate and complete record or will assist the
Commission in its deliberative process by clarifying the issues. See, e.g., PJM Interconnection, L.L.C., 139
FERC ¶ 61,165, at P 24 (2012) (accepting answers to a protest because “they have provided information that
assisted [the Commission] in [its] decision-making process”); PJM Interconnection, L.L.C., 158 FERC ¶
61,133, at P 12 (2017) (accepting answers to protests because they provided information that assisted in the
Commission’s decision-making process); PJM Interconnection, L.L.C., 104 FERC ¶ 61,031, at P 10 (2003)
(accepting answer because “it will not delay the proceeding, will assist the Commission in understanding the
issues raised, and will [e]nsure a complete record upon which the Commission may act”). These criteria are
met here as this submission addresses a number of substantive comments and protests on issues pending
before the Commission for potential resolution. PJM respectfully requests that the Commission grant its
Motion because the Answer will help clarify the record and contribute to an understanding of the issues.
3 PJM Interconnection, L.L.C., Compliance Filing of PJM Interconnection, L.L.C. in Response to Order on
Rehearing, Clarification, Compliance Filing, and Paper Hearing in Docket Nos. EL25-49-002, et al., Docket
Nos. ER26-1479-002, et al. (Aug. 17, 2026).
4 PJM Interconnection, L.L.C., Limited Protest and Comments of Constellation Energy Generation, LLC,
Docket Nos. EL25-49-002, et al. (Sep. 8, 2026) (“Constellation Limited Protest”); PJM Interconnection,
L.L.C., Limited Protest of American Municipal Power, Inc., Docket No. ER26-1479-002 (Sep. 8, 2026)
(“AMP Limited Protest”); PJM Interconnection, L.L.C., Joint Comments and Limited Protest of Industrial
Customer Organizations and Amtrack to PJM Interconnection, L.L.C.’s August 17, 2026, Compliance Filing,
Docket Nos. ER26-1479-001, et al. (Sep. 8, 2026) (“Amtrack Limited Protest”).PDF page 2
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record on certain issues raised in this proceeding. As discussed below, there are certain
aspects of the language proposed for PJM’s Open Access Transmission Tariff (“Tariff”)
that may benefit from a more complete record that the additional changes being proposed
in November will provide. Thus, although PJM had requested an effective date of October
17, 2026, for the changes to Tariff, Parts I, III, VI, VIII, and IX in the August Filing, it may
be appropriate for the Commission to defer consideration of these issues until it has the
benefit of a complete record following next month’s compliance filing.
I.
ANSWER
A.
PJM’s Proposed Effective Date for Interim NITS
Constellation Energy Generation, LLC (“Constellation”) avers the July 1, 2028
effective date for Interim Network Integration Transmission Service (“NITS”)5 in the
August Filing is unsupported and neglects to give “serious consideration” to more
expedited implementation.6 That is simply not the case. As stated in the August Filing,
PJM’s operations personnel will need to implement a number of additional tools and
processes to enable the automated provision of Interim NITS.7 This is a significant
undertaking. As more fully explained in the Affidavit of Christopher Pilong provided
herewith as Attachment A, providing Interim NITS with the assistance of automation will
require PJM to make significant modifications to its forecasts, operations, markets, and
settlement systems.8 PJM anticipates significant demand for Interim NITS that would
necessitate automation to be implemented efficiently.9 PJM’s systems do not currently
5 Capitalized terms not otherwise defined herein shall have the meaning in PJM’s Tariff or August Filing.
6 Constellation Limited Protest at 2-3.
7 August Filing, Transmittal Letter at 23.
8 Affidavit of Christopher Pilong (Attachment A) at ¶¶ 5-22, 30-37 (“Pilong Aff.”).
9 Pilong Aff. at ¶ 5.
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have the ability to track individual large loads, associate those loads with a specific
transmission service reservation, track service limits for a particular reservation, and direct
curtailment down to an individual reservation.10 Therefore, PJM will have to make
significant changes to its system to provide Interim NITS.11 Constellation suggests that
PJM should be in a position to implement this service on the same timeframe PJM proposed
to implement its proposed Interim Resource Adequacy Service (“IRAS”).12 IRAS was
proposed to be implemented on an aggregate, zonal basis using largely existing tools,
whereas Interim NITS curtailment will occur on an individual transmission service request
basis and requires entirely new tools and automation.13
Since the August Filing, PJM has further refined the timeline for making the
requisite system changes to accommodate Interim NITS. Currently, PJM anticipates
modifying the systems needed to begin accepting requests for the new transmission
services in September of 2027. PJM is developing a proposal for a new a study process
that would evaluate large loads and generation interconnection requests together in a
unified cluster study that would take roughly a year to complete.14 PJM plans to file that
proposal on or before November 16, 2026, in response to the Large Load Show Cause
Order. Assuming the Commission accepts that proposal, PJM anticipates opening the
10 Pilong Aff. at ¶¶ 28-30.
11 Pilong Aff. at ¶¶ 16-20, 30-37.
12 Constellation Limited Protest at 3-5; see PJM Interconnection, L.L.C., Proposal of PJM Interconnection,
L.L.C. to Establish Interim Resource Adequacy Service and a Large Load Registry to Address System
Reliability, Docket No. ER26-3515-000 (Aug. 13, 2026).
13 Pilong Aff. at ¶¶ 27-40.
14 See Donnie Bielak, Director, Interconnection Planning, Show Cause for Large Loads Framework, PJM
Interconnection, L.L.C. (Sep. 16, 2026), https://www.pjm.com/-/media/DotCom/committees-
groups/workshops/cllsco/2026/20260916/20260916-item-03---show-cause-for-large-loads-approach---
presentation.pdf [https://perma.cc/44V9-48WU].
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application process in September of 2027, conducting the study in 2028, and beginning to
provide service in first quarter 2029.15 PJM remains committed to continuing to explore
ways to promptly implement the new Commission-directed transmission services,
including the feasibility of implementing disfavored options that rely on more manual
processes as opposed to automated processes.16
B.
Necessary Study Process
Constellation asks the Commission to order PJM to clarify that Necessary Studies
need not be repeated where the scope of the previously conducted study has not changed.17
As Constellation notes, however, the Commission clarified in the June Hearing Order that
the scope of the Necessary Study process should not change.18 While PJM will not repeat
studies already performed, project scope or other technical changes may trigger the need
for additional study. By way of example, if a generator elects to reduce its Capacity
Interconnection Rights (“CIR”) consistent with the Commission’s directives as part of a
co-located load arrangement, but that CIR reduction was not previously communicated to
PJM and thus not studied, the impact of that CIR reduction will have to be assessed.
C.
Transmission Owner Technical Requirements
Constellation claims PJM added language regarding complying with the
Transmission Owner’s technical requirements in Tariff Part XI section 702.4 for Interim
NITS without the Commission ordering it to do so.19 That is incorrect. The June Hearing
Order clarified that the provision of any new transmission service must be compliant with
15 See id.
16 Pilong Aff. at ¶¶ 5, 9.
17 Constellation Limited Protest at 5.
18 Id. (citing PJM Interconnection, L.L.C., 195 FERC ¶ 61,209, at P 283 (2026) (“June Hearing Order”)).
19 Constellation Limited Protest at 7-8.
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both PJM’s and the Transmission Owners’ technical requirements to limit withdrawals
from the system.20 Interim NITS is such a service, as customers must be able to limit their
withdrawals from the system consistent with the existing system limits (i.e., prior to the
completion of network upgrades needed to provide NITS).21 Therefore, PJM
appropriately added this language to the Proposed Part XI, section 702.4 in the August
Filing.
D.
Interim NITS And Resource Adequacy
Constellation expresses concern that PJM will limit the provision of Interim NITS
due to resource adequacy considerations.22 That is not the case. The August Filing
specified that PJM will provide Interim NITS consistent with system reliability.23 In
evaluating a request for Interim NITS, PJM will examine the ability of the system to
provide some level of deliverability for a service request while maintaining the reliability
of the system.24 Consistent with the Commission’s orders, the August Filing specified that
Interim NITS will be interruptible and curtailed before firm services like Firm Contract
Demand Service or NITS that are capacity-backed services.25 In the event of a capacity
shortage, Interim NITS will be curtailed before capacity-backed services during
operations.26
20 June Hearing Order at PP 458, 486-87.
21 See August Filing, Attachment A (Proposed Marked Tariff) at Part XI, section 705.1.
22 Constellation Protest at 8-9.
23 August Filing, Attachment A (Proposed Marked Tariff) at Part XI, section 702.3.
24 Id.
25 See August Filing, Attachment A (Proposed Marked Tariff) at Part XI, section 705.1.
26 August Filing, Attachment A (Proposed Marked Tariff) at Part XI, section 705.2.
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E.
Partial NITS
Constellation seeks clarification regarding the statement in the August Filing
concerning the provision of partial NITS (i.e., NITS in an amount less than requested or
for a term shorter than requested).27 PJM clarifies that this is existing NITS under Part III
of the Tariff. When applying for NITS under Part III of the Tariff, an Eligible Customer
provides a description of Network Load at each delivery point, including forecasted total
load over a ten-year period.28 To the extent PJM cannot meet the full requested schedule
for commencement of service, PJM instead provides the available amount of full NITS
service it can provide based on available transfer capability.29
F.
Behind The Meter Generation (“BTMG”) Issues
1.
An Interconnection Service Agreement does not disqualify from
netting.
National Railroad Passenger Corporation (“Amtrak”) and various industrial
customers express concern that the definitions PJM proposed may somehow disqualify
industrial customers that sell surplus energy to the grid from netting their load under their
existing BTMG arrangements.30 This matter is premature and beyond the scope of the
pending compliance filing. PJM has proposed no such restriction nor does it intend to
include such a restriction in its upcoming compliance filing. PJM posted draft Tariff
language to implement the BTMG netting provisions for stakeholder feedback in advance
of the upcoming November compliance filing.31 The draft Tariff language includes
27 Constellation Limited Protest at 6-7.
28 Tariff, Part III, section 29.2(iii).
29 Tariff, Part III, section 29.2A.
30 See Amtrack Limited Protest at 8-10.
31 PJM Interconnection, L.L.C., PJM draft Tariff language, subject to change Draft Retail BTMG language
for November 2026 filing (Sep. 16, 2026), https://www.pjm.com/-/media/DotCom/committees-
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grandfathering provisions for existing commercial arrangements, co-generation, and a
transition period.32 It does not exclude based on whether the load has an Interconnection
Service Agreement. However, given the confusion surrounding eligibility for netting, PJM
intends to propose clarifications to the definition of BTMG in the November compliance
filing to specify that load with BTMG is excluded from the definition of Co-Located Load.
PJM will continue to engage with stakeholders on this issue in advance of the November
filing.
2.
PJM agrees that a clarification of the defined term, “Eligible
Generating Facility” is warranted.
American Municipal Power, Inc.’s (“AMP”) limited protest avers that the proposed
definition of an “Eligible Generating Facility” may disqualify Non-Retail BTMG from
qualifying for use of the new transmission services.33 The August Filing made the new
interim NITS available to Eligible Customers taking service on behalf of Eligible Load,
which was defined to include both Co-Located Load and load connected to Behind the
Meter Generation.34 PJM did not intend to exclude Non-Retail Behind the Meter
Generation from eligibility for the new transmission services. Accordingly, PJM, does not
object to AMP’s proposed revision to Eligible Generating Facility definition set forth in its
pleading.35 However, any Eligible Customer taking interim NITS to serve load with Non-
Retail Behind the Meter Generation will need to meet the operational requirements
groups/workshops/cllsco/2026/20260916/20260916-item-02---oatt-342-revisions---redline.pdf
[https://perma.cc/AP3E-8LRH].
32 Id.
33 AMP Limited Protest at 5-6.
34 August Filing, Attachment A (Proposed Marked Tariff) at Definitions A-B (Behind the Meter
Generation).
35 AMP Limited Protest at 7.
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associated with that service set forth in the Tariff (e.g., limit withdrawals from the
transmission system).
II.
CONCLUSION
Based on the foregoing, PJM requests that the Commission grant PJM’s motion for
leave to answer and accept the foregoing answer and affidavit.
Respectfully submitted
/s/ Ruth M. Porter
Mark J. Stanisz
Associate General Counsel
PJM Interconnection, L.L.C.
2750 Monroe Blvd.
Norristown, PA 19403-2429
(610) 666-4707
mark.stanisz@pjm.com
October 14, 2026
Wendy B. Warren
Ruth M. Porter
Wright & Talisman, P.C.
1200 G Street, NW, Suite 600
Washington, DC 20005
(202) 393-1200
warren@wrightlaw.com
porter@wrightlaw.com
Counsel for
PJM Interconnection, L.L.C.
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CERTIFICATE OF SERVICE
I hereby certify that I have on this day served the foregoing document on each
person designated on the service list compiled by the Secretary in these proceedings.
Dated at Washington, DC on this 14th day of October 2026.
/s/ Ruth M. Porter
Ruth M. Porter
Wright & Talisman, P.C.
1200 G Street, NW, Suite 600
Washington, DC 20005
(202) 393-1200
porter@wrightlaw.com
Counsel for
PJM Interconnection, L.L.C.
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Attachment A
Affidavit of Christopher Pilong
Senior Director, Operations Planning
PDF page 11
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
PJM Interconnection, L.L.C.
)
Docket Nos. EL25-49-000
)
EL25-49-001
)
EL25-49-002
)
)
PJM Interconnection, L.L.C.
)
Docket No. ER26-1479-000
AFFIDAVIT OF CHRISTOPHER PILONG
ON BEHALF OF PJM INTERCONNECTION, L.L.C.
1.
My name is Christopher Pilong and my business address is 2750 Monroe Blvd.,
Audubon, Pennsylvania 19403. I am the Senior Director, Operations Planning at
PJM Interconnection, L.L.C. (“PJM”). In that role, I am responsible for functions
that support the reliable planning and preparation of PJM’s bulk electric system for
real-time operations. My responsibilities include oversight of operational studies,
processes, tools, and coordination activities with Generation Owners, Transmission
Owners and neighboring entities, as well as gas-electric coordination with the
natural industry.
2.
I am submitting this affidavit in support of PJM’s proposed revisions to the PJM
Open Access Transmission Tariff (“Tariff”) filed August 17, 2026, to comply with
the Federal Energy Regulatory Commission’s (“Commission”) directives in its
June 18, 2026 order,1 including the directive to reconsider the proposed effective
date for PJM to offer the new transmission services for Eligible Customers taking
service on behalf of Co-Located Load and load with Behind the Meter Generation.
Because PJM has to date only proposed Tariff language for Interim Network
Integration Transmission Service (“NITS”), my affidavit is limited to addressing
implementation of that service.
3.
In this affidavit, I explain:
• The operational complexities associated with implementing Interim
NITS on an automated basis and scope of changes on PJM’s systems
that will be needed to accommodate automated provision of Interim
NITS and the anticipated timing of implementing those changes.
• Why the timeline PJM proposed for Interim Resource Adequacy
Service (“IRAS”) implementation is not comparable to Interim NITS.
4.
This affidavit addresses implementation rather than the legal merits of any
particular Tariff design. Because the Commission has not yet issued an order and
final Tariff language, implementation requirements will depend on the terms of the
1 PJM Interconnection, L.L.C, 195 FERC ¶ 61,209 (2026).PDF page 12
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order, including eligibility, priority, duration, curtailment standards, notice
requirements, transition rules, settlement treatment, and the relationship of these
services to existing transmission and market obligations.
5.
As explained below, PJM should not treat the implementation of Interim NITS as
a simple Tariff or software-configuration change. PJM expects to receive
significant interest in customers taking Interim NITS. Given the anticipated level
of demand, there is significant value in incorporating Interim NITS into PJM’s
existing automated systems and processes. Providing Interim NITS on an
automated basis involves introducing a new operational status that must remain
consistent across planning, market, scheduling, outage, reliability, dispatch,
settlement, and customer-facing processes.
I.
OPERATIONAL DESIGN AND PROCEDURE CHANGES
6.
Once the Commission approves proposed Tariff language, PJM first would need to
convert the Commission’s requirements into objective and auditable operating
rules. Those rules would need to define when service is available, the transmission
capability that supports it, the events that permit or require curtailment, the
sequence and priority of curtailment, restoration criteria, customer notification, and
the treatment of partial curtailments. The rules also would need to address conflicts
among
reliability
directives, transmission service priorities, generation
commitments, and market outcomes.
7.
Existing operating agreements, manuals, desk procedures, emergency procedures,
training materials, operator displays, alarm protocols, and shift turnover practices
would require review and, in many cases, revision. PJM would need clear decision
rights for declaring a qualifying condition, approving a curtailment, communicating
the instruction, monitoring compliance, and restoring service. Procedures must
work during normal operations, constrained operations, emergencies, restoration,
and periods when communications or applications are degraded.
8.
Interim NITS presents a number of implementation challenges. Network service
ordinarily is embedded in network modeling, designation of network resources and
load, transmission planning assumptions, scheduling rights, market participation,
and long-term reliability obligations. An “interim” status therefore must be defined
consistently across time horizons and must not inadvertently create rights,
priorities, or planning assumptions beyond those authorized by the Commission.
9.
Implementing this construct for Interim NITS would require exception
management. Examples include late or inaccurate data, a customer’s failure to
curtail, a change in topology after the applicable study, overlapping transmission
reservations, generator or transmission outages, load forecast error, restoration
following a contingency, and a service period that crosses operating days or
settlement intervals. Some manual workarounds may exist, but they are not
preferable or durable substitutes for controlled and auditable production processes.
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II.
COORDINATION WITH TRANSMISSION OWNERS, GENERATION
OWNERS, AND CUSTOMERS
10.
Implementation of Interim NITS would require substantial coordination with PJM
Transmission Owners. Transmission Owners would need to understand and support
the service definitions, study assumptions, facility ratings, topology inputs, local
operating procedures, switching implications, notification paths, and field
execution responsibilities. Where a curtailment is intended to relieve a local or
regional constraint, PJM and the affected Transmission Owner must agree on the
relevant monitored facilities, contingencies, expected distribution factors,
validation method, and restoration criteria.
11.
Transmission Owner systems and procedures may require corresponding changes.
These may include energy management system displays, outage coordination
practices, control-center instructions, operator training, customer communications,
and evidence retention. Differences among Transmission Owner footprints, legacy
systems, and local procedures will require testing by affected zone rather than
reliance on a single generic implementation.
12.
Coordination with Generation Owners and other market participants also is
necessary because new service states can alter commitment, dispatch, reserve
procurement, congestion management, and outage assumptions. PJM would need
to explain how a curtailment instruction interacts with generation dispatch
instructions, must-offer or availability obligations, bilateral arrangements, and any
generation or storage serving the affected load.
13.
Customers receiving the service would need defined telemetry, metering,
communications, scheduling, and response obligations. PJM would need validated
points of contact available at all times, test protocols, escalation paths, and
consequences for non-performance. Meter-data latency and granularity must be
sufficient to determine whether the requested relief occurred and when it occurred.
14.
A further implementation uncertainty is the identity and operational role of the new
“Eligible Customer” that would take service on behalf of the underlying load.
Depending on the final tariff construct, that entity may not be the load-serving
entity, end-use customer, Transmission Owner, or market participant with which
PJM currently exchanges operating instructions. PJM therefore would need to
verify the entity’s legal and operational authority to act for the load; define its
responsibilities relative to those other parties; establish secure, continuously staffed
primary and backup communication channels; identify authorized contacts and
escalation paths; and develop protocols for issuing, acknowledging, executing, and
documenting curtailment and restoration instructions. PJM also would need to
determine required telemetry, metering, scheduling, outage, cybersecurity, identity-
management, and data-sharing arrangements; execute any necessary agreements or
registrations; conduct communications and failover testing; train the parties; and
confirm that an instruction to the Eligible Customer can be translated into timely,
measurable action at the affected load. If the identity, authority, technical
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capability, or relationship of the Eligible Customer to the underlying load is not
known early in implementation, onboarding and certification could become a
critical-path item and could extend the implementation schedule.
15.
Reliability Coordinators and neighboring systems may also need notice where
implementation changes interchange schedules, coordinated flowgate impacts,
congestion management, or other interregional processes. Any external
coordination must be aligned with applicable reliability standards and existing joint
operating agreements.
III.
TOOL AND SYSTEM IMPACTS
16.
The affected technology footprint is broad. Detailed design would be required to
identify the authoritative source for each service attribute and to ensure that status
changes propagate consistently. At a minimum, PJM would need to assess and
likely modify the following categories of tools:
• Transmission-service request, study, reservation, and contract-administration
applications, including customer-facing portals and study queues;
• Network-model
management,
topology
processing,
facility-rating,
contingency-analysis, and power-flow applications;
• Energy management system and operator displays, including alarms, logs,
switching and constraint information, and real-time security analysis;
• Day-ahead and real-time market engines, unit commitment and security-
constrained economic dispatch, reserve optimization, and pricing processes;
• Load forecasting, interchange scheduling, and transmission loading relief or
congestion-management processes;
• Generation and transmission outage scheduling and outage-impact assessment
tools;
• Telemetry, metering, data historians, event logging, operator logs, and
compliance evidence repositories;
• Market settlements calculation and reporting systems; and
• Data publication, market notifications, reporting, analytics, and customer-
support tools.
17.
PJM also would need end-to-end auditability. For each relevant interval, PJM
should be able to reconstruct the authorized service level, transmission conditions,
applicable curtailment priority, notices sent, operator actions, customer response,
market results, and settlement treatment. That requirement implicates data
retention, cybersecurity review, access controls, change management, and
business-continuity testing.
IV.
MARKET CLEARING, RELIABILITY AND SETTLEMENT IMPACTS
18.
Market clearing requires a consistent representation of which load is firm, which
load may be curtailed, when curtailment is available, and whether the curtailment
is a pre-contingency control, a post-contingency action, or an emergency measure.
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That representation can affect constraint formulation, load distribution,
commitment, dispatch, reserve requirements, congestion, losses, prices, and
interchange feasibility.
19.
If the market engines assume curtailment that operators cannot execute with
sufficient certainty or speed, the resulting solution could understate reliability
needs. Conversely, excluding available curtailment from all market and reliability
analyses could produce inefficient commitments or congestion outcomes. PJM
therefore would need validated rules for when the service may be modeled, the
confidence assigned to it, and any conservative operating margin required.
20.
PJM also would need to determine whether and how curtailment affects locational
marginal prices, make-whole payments, uplift, transmission charges, congestion
rights, reserve or emergency compensation, deviation charges, and other settlement
outcomes. The treatment must be internally consistent and understandable to
market participants. PJM would need to update its settlement calculation and
reporting systems to account for proposed differences between the settlements
treatment for NITS and Interim NITS services. The systems Electric Distribution
Companies (“EDCs”) and Load Serving Entities (“LSEs”) use to submit revenue
quality metered load data will also need to be updated to allow differentiation of
the metered load served under NITS service from the load served under Interim
NITS service given the differing settlements treatment. Further, EDCs and LSEs
will need to develop their own procedures to track and report the load of end-use
customers taking the new transmission service to PJM distinctly from those using
regular NITS service.
21.
Reliability studies would need to evaluate contingencies in which the curtailable
load does not respond, responds only partially, or is unavailable because of
communications, equipment, or customer conditions. Operators would need
alternative actions for such failures. The design also should avoid dependence on
a single point of failure and should define how service is suspended during tool
outages or uncertain system conditions.
22.
Implementation may require revisions to model-development schedules, case-
building processes, seasonal and near-term studies, operator drills, and reliability
assessments. The interaction with generator deactivations, new resource
interconnections, load additions, transmission upgrades, and temporary operating
guides must be evaluated so that interim service does not obscure an emerging
reliability need.
V.
IMPLEMENTATION SCHEDULE
23.
Assuming a Commission order provides sufficiently complete direction and does
not require immediate service, I estimate that a controlled production
implementation would require approximately 18 to 24 months after the later of
(a) issuance of a final, non-ambiguous order and (b) availability of final tariff
language and business requirements. A narrower implementation for a very
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limited number of pre-identified customers could potentially be staged earlier, but
only if reliability protections, manual controls, and scope limits are expressly
defined. A materially broader or differently designed service could require more
than 24 months.
24.
An indicative schedule is as follows. Activities would overlap, and later phases
depend on timely resolution of policy questions:
i.
Order analysis and requirements confirmation — approximately 0 to 3
months. Interpret the order; identify affected tariff, manual, agreement, and
reliability provisions; resolve ambiguities; define eligibility, priority,
curtailment, restoration, data, and settlement rules; establish governance and
implementation scope.
ii.
Detailed process and solution design—approximately 2 to 6 months. Map
end-to-end processes; complete reliability and market-impact analyses; define
data ownership and interfaces; develop exception handling; coordinate with
Transmission Owners, Generation Owners, customers, and neighboring
entities.
iii.
Development and procedure revision—approximately 5 to 14 months.
Configure or develop affected applications and interfaces; revise manuals, desk
procedures, forms, operating agreements, training, notifications, reports, and
customer materials; establish telemetry and metering requirements.
iv.
Integrated testing—approximately 12 to 18 months. Perform component,
interface, regression, cyber, performance, failover, settlement, and zone-
specific Transmission Owner testing; correct defects and repeat tests.
v.
Readiness, training, and controlled deployment—approximately 16 to 21
months. Train and qualify operators and support staff; conduct drills; complete
customer certification; verify round-the-clock contacts; execute cutover and
rollback plans; begin with controlled enrollment where appropriate.
vi.
Stabilization and full production—approximately 21 to 24 months. Monitor
outcomes; reconcile market and settlement results; resolve defects; validate
operational relief; complete post-implementation review; and expand only after
readiness criteria are met.
25.
This estimate assumes that PJM can assign adequate subject-matter experts and
development capacity; affected Transmission Owners and customers make
corresponding changes on schedule; required data and telemetry are available; no
material rehearing or compliance-filing ambiguity delays final requirements; and
the implementation can be coordinated with established market-model, software-
release, training, and seasonal-readiness calendars.
26.
Schedule risk would increase if the order requires service before necessary system
changes are complete, applies broadly at inception, changes curtailment priority,
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requires new optimization logic, alters pricing or settlement rules, depends on new
telemetry or Transmission Owner functionality, or requires parallel implementation
during a peak-season freeze or other major market release.
VI.
DIFFERENCES FROM IRAS IMPLEMENTATION
27.
Constellation Energy Generation, LLC (“Constellation”) incorrectly characterizes
Interim NITS implementation as comparable to the implementation of the IRAS
framework. The two initiatives differ materially in scope, operational complexity,
required market system modifications, transmission service administration impacts,
and reliability implementation requirements.
28.
While IRAS primarily establishes a planning and accreditation framework that
relies upon existing market and operational constructs, Interim NITS requires PJM
to develop entirely new processes for administering, tracking, limiting, and
curtailing transmission service associated with individual large load customers.
Accordingly, the implementation timelines are not analogous.
29.
Interim NITS requires PJM to manage transmission service at an Eligible Customer
and transmission service request level, as opposed to zonal level. PJM’s current
operating and emergency procedures are primarily designed around zonal load
forecasting, zonal load management, and system-wide reliability actions. Under
existing arrangements PJM forecasts load at the transmission zone level. In
addition, capacity obligations are assigned at the zone and LSE level. Emergency
load management actions are generally executed through zonal or broader
reliability directives. Market systems clear generation against aggregate load
forecasts rather than individual transmission customers.
30.
Interim NITS introduces an entirely different construct requiring PJM to identify,
monitor, and potentially curtail transmission service attributable to specific large
loads. Unlike a zonal curtailment approach, customer-specific transmission service
curtailments require various actions directed at the individual loads being served
by Eligible Customers. This will require PJM to have the capability to identify the
individual affected loads in the operations systems and track the transmission
service rights associated with those loads. PJM will then need to have the capability
to determine the customer-specific curtailment quantities, which will require
further development of priority and allocation methodologies. PJM will also have
to coordinate this implementation with the Transmission Owners. PJM will also
need to have protocols to validate customer-specific exception conditions and take
customer-specific actions in real time. These capabilities do not exist today within
PJM’s operating platform and must be newly developed.
31.
Implementation of Interim NITS requires significant modifications to several
existing systems and business processes used to administer transmission service.
Among other changes, PJM must develop capabilities to register and maintain
Eligible Customers’ individual large loads, associate those loads with transmission
service reservations, and track load-specific transmission service limits. PJM will
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also need to establish curtailment eligibility criteria, create notification and
communication protocols, and integrate transmission service information across
planning, operations, and settlements systems. PJM will also need to develop
auditable compliance records for transmission service administration.
32.
These requirements represent a substantial departure from PJM’s current
transmission service framework, which was not designed to administer
transmission service limitations on individual end-use customer loads. By contrast,
IRAS largely leverages existing planning, capacity market, and resource
accreditation processes.
33.
PJM will have to modify the market-clearing engines to implement Interim NITS
on an automatic basis. Constellation understates the degree to which Interim NITS
affects PJM's market systems. To implement Interim NITS, PJM must evaluate
modifications to both Day-Ahead and Real-Time market operations.
34.
Day-Ahead Market Impacts. For implementation of Interim NITS in the Day-
Ahead Market, PJM must make significant modifications to the current system.
Moreover, to do so, PJM must determine a range of implementation details
including how Interim NITS will be represented in the Day-Ahead load forecast,
whether curtailment limitations affect demand bid treatment, and how transmission
service restrictions impact commitment decisions. PJM will also need to determine
how reliability commitments should account for potentially interruptible
transmission service. The Day-Ahead market engine currently assumes load
forecasts consistent with existing transmission service obligations. Introducing
customer-specific transmission service constraints may require system design
changes and extensive testing to ensure appropriate unit commitment outcomes.
35.
Real-Time Market Impacts. The Real-Time implementation of Interim NITS
presents additional complexity. To implement Interim NITS in Real-Time, PJM
must determine various parameters for including Interim NITS in the Real-Time
Market. For example, PJM must determine when customer-specific transmission
service limitations become binding and how transmission service curtailments
interact with dispatch and reserve commitments. PJM must also establish how
operators will recognize and model curtailed load and how real-time telemetry and
operational visibility requirements will be satisfied. PJM must also determine how
reliability actions are coordinated with transmission owners and affected
customers. Ultimately, the interaction between customer-specific transmission
service restrictions and real-time security-constrained economic dispatch in
implementing Interim NITS requires detailed design, testing, and validation to
avoid unintended reliability consequences.
36.
Reliability Risks. The reliability and operational risks associated with Interim
NITS differ materially from those of IRAS. IRAS primarily affects resource
accreditation and resource adequacy planning. Interim NITS directly affects real-
time operational execution. Specifically, Interim NITS requires PJM to establish
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customer-specific curtailment methodologies and reliability-based criteria to
trigger those curtailment methodologies. Once those methodologies and criteria
are established, PJM also must establish operator procedures and communication
protocols for implementation, along with compliance and audit processes.
Moreover, PJM must establish processes for coordination with the transmission
owners and load-serving entities. As part of this effort, PJM will need to ensure
appropriate dispute resolution mechanisms for transmission service administration
because any errors in these processes could result in improper curtailment of
transmission customers. Because Interim NITS directly impacts operational
reliability actions, PJM must ensure comprehensive testing and validation prior to
implementation.
37.
Software Development and Testing. The software development needs and testing
requirements to implement Interim NITS are also significantly greater than IRAS.
Implementation of Interim NITS requires coordinated modifications across
multiple platforms, including the transmission service systems, load forecasting
systems, and customer registration systems. PJM will also have to modify its
market clearing applications, operator tools, settlements systems, reporting and
compliance systems, and the data interfaces with transmission owners. Each of
these modifications requires requirements development, software design, coding,
integrated system testing, market participant testing, operator training, and
production deployment.
38.
Unlike IRAS, which predominantly leverages established planning and capacity
market constructs, Interim NITS introduces entirely new operational functionality
that must function correctly during emergency grid conditions. Consequently,
extensive development and testing are necessary to avoid reliability risks. Any
incremental benefits associated with implementing Interim NITS do not justify
accelerating implementation at the expense of reliability.
39.
PJM agrees that large load growth presents emerging reliability challenges.
However, implementation speed cannot come at the expense of operational
accuracy and reliability. The Commission has consistently recognized that RTOs
must ensure that major operational, market, and transmission administration
changes are fully designed, tested, and validated before implementation. The
complexity associated with customer-specific transmission service management
warrants a deliberate implementation schedule that ensures reliable, transparent,
and non-discriminatory administration.
40.
Accordingly, the implementation timeline proposed by PJM reflects the substantial
operational, software, market, and transmission service changes necessary to
implement Interim NITS successfully and cannot reasonably be equated to the
implementation requirements associated with IRAS.
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VII.
CONCLUSION
41.
In my opinion, implementing Interim NITS safely and reliably requires coordinated
changes across PJM operations, Transmission Owners, Generation Owners,
customers, market systems, transmission-service systems, settlements, training,
and compliance processes. The work must proceed from a stable service definition
and must include integrated testing under normal, constrained, emergency, and
degraded-tool conditions.
42.
A Commission-authorized transition period of approximately 18 to 24 months
would provide a reasonable implementation window under the assumptions stated
above. That period is necessary to reduce the risk of inconsistent service treatment,
non-executable market assumptions, unreliable curtailment, settlement errors, and
inadequate operator or stakeholder readiness.
43.
This concludes my Affidavit.
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
PJM Interconnection, L.L.C.
)
Docket Nos. EL25-49-000
)
EL25-49-001
)
EL25-49-002
)
)
PJM Interconnection, L.L.C.
)
Docket No. ER26-1479-000
VERIFICATION OF CHRISTOPHER PILONG
I, Christopher Pilong, pursuant to 28 U.S.C. § 1746, state, under penalty of perjury,
that I am the Christopher Pilong referred to in the foregoing “Affidavit of Christopher
Pilong on Behalf of PJM Interconnection, L.L.C.,” that I have read the same and am
familiar with the contents thereof, and that the facts set forth therein are true and correct to
the best of my knowledge, information, and belief.
/s/ Christopher Pilong
Christopher Pilong
Senior Director
Operations Planning
PJM Interconnection, L.L.C.
Executed on: October 14, 2026