{"document":{"slug":"answer-el25-49-pjm-limited-protests","title":"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)","issued":"2026-10-14","accession":"20261015-5003","docket":"EL25-49-000","group":"PJM co-location compliance","filer":"PJM","kind":"motion for leave to answer and answer","file":"sources/originals/20261015-5003_PJM Answer to Limited Protests - ER26-1479 and EL25-49 .pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20261015-5003","sha256":"742d4f5e3c6e1f973860d7c0bc8bd174f44a11c17903e2af286ed60da5039217","pages":21,"tokens":5948,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":440,"text":"UNITED STATES OF AMERICA \nBEFORE THE \nFEDERAL ENERGY REGULATORY COMMISSION \n \n \n \n \n) \nPJM Interconnection, L.L.C.  \n \n) \n \nDocket Nos. EL25-49-000 \n \n \n \n \n \n \n) \n \n \n         EL25-49-001 \n \n \n \n \n \n \n) \n \n \n         EL25-49-002 \n ) \n \n \n \n) \nPJM Interconnection, L.L.C.  \n \n) \n \nDocket No. ER26-1479-000 \n \n \n \n \n \n \n) \n \n \nMOTION FOR LEAVE TO ANSWER AND ANSWER OF PJM \nINTERCONNECTION, L.L.C. \n \nPJM Interconnection, L.L.C. (“PJM”), pursuant to Federal Energy Regulatory \nCommission (“Commission” or “FERC”) Rules 212 and 213 of Practice and Procedure,1 \nrespectfully moves2 to answer the limited protests filed in response to PJM’s August 17, \n2026 compliance filing (“August Filing”).3  Several parties filed limited protests \nconcerning discrete aspects of the August Filing. 4  PJM provides this answer to clarify the \n \n1 18 C.F.R. §§ 385.212, 385.213. \n2 Good cause exists for the Commission to permit PJM’s answer.  The Commission routinely accepts answers \nto comments and protests when doing so will ensure a more accurate and complete record or will assist the \nCommission in its deliberative process by clarifying the issues. See, e.g., PJM Interconnection, L.L.C., 139 \nFERC ¶ 61,165, at P 24 (2012) (accepting answers to a protest because “they have provided information that \nassisted [the Commission] in [its] decision-making process”); PJM Interconnection, L.L.C., 158 FERC ¶ \n61,133, at P 12 (2017) (accepting answers to protests because they provided information that assisted in the \nCommission’s decision-making process); PJM Interconnection, L.L.C., 104 FERC ¶ 61,031, at P 10 (2003) \n(accepting answer because “it will not delay the proceeding, will assist the Commission in understanding the \nissues raised, and will [e]nsure a complete record upon which the Commission may act”).  These criteria are \nmet here as this submission addresses a number of substantive comments and protests on issues pending \nbefore the Commission for potential resolution.  PJM respectfully requests that the Commission grant its \nMotion because the Answer will help clarify the record and contribute to an understanding of the issues. \n3 PJM Interconnection, L.L.C., Compliance Filing of PJM Interconnection, L.L.C. in Response to Order on \nRehearing, Clarification, Compliance Filing, and Paper Hearing in Docket Nos. EL25-49-002, et al., Docket \nNos. ER26-1479-002, et al. (Aug. 17, 2026). \n4 PJM Interconnection, L.L.C., Limited Protest and Comments of Constellation Energy Generation, LLC, \nDocket Nos. EL25-49-002, et al. (Sep. 8, 2026)  (“Constellation Limited Protest”); PJM Interconnection, \nL.L.C., Limited Protest of American Municipal Power, Inc., Docket No. ER26-1479-002 (Sep. 8, 2026) \n(“AMP Limited Protest”); PJM Interconnection, L.L.C., Joint Comments and Limited Protest of Industrial \nCustomer Organizations and Amtrack to PJM Interconnection, L.L.C.’s August 17, 2026, Compliance Filing, \nDocket Nos. ER26-1479-001, et al. (Sep. 8, 2026) (“Amtrack Limited Protest”)."},{"page":2,"startToken":440,"endToken":734,"text":"2 \nrecord on certain issues raised in this proceeding.  As discussed below, there are certain \naspects of the language proposed for PJM’s Open Access Transmission Tariff (“Tariff”) \nthat may benefit from a more complete record that the additional changes being proposed \nin November will provide.  Thus, although PJM had requested an effective date of October \n17, 2026, for the changes to Tariff, Parts I, III, VI, VIII, and IX in the August Filing, it may \nbe appropriate for the Commission to defer consideration of these issues until it has the \nbenefit of a complete record following next month’s compliance filing. \nI. \nANSWER \nA. \nPJM’s Proposed Effective Date for Interim NITS \nConstellation Energy Generation, LLC (“Constellation”) avers the July 1, 2028 \neffective date for Interim Network Integration Transmission Service (“NITS”)5 in the \nAugust Filing is unsupported and neglects to give “serious consideration” to more \nexpedited implementation.6  That is simply not the case.  As stated in the August Filing, \nPJM’s operations personnel will need to implement a number of additional tools and \nprocesses to enable the automated provision of Interim NITS.7  This is a significant \nundertaking.  As more fully explained in the Affidavit of Christopher Pilong provided \nherewith as Attachment A, providing Interim NITS with the assistance of automation will \nrequire PJM to make significant modifications to its forecasts, operations, markets, and \nsettlement systems.8  PJM anticipates significant demand for Interim NITS that would \nnecessitate automation to be implemented efficiently.9  PJM’s systems do not currently \n \n5 Capitalized terms not otherwise defined herein shall have the meaning in PJM’s Tariff or August Filing. \n6 Constellation Limited Protest at 2-3. \n7 August Filing, Transmittal Letter at 23. \n8 Affidavit of Christopher Pilong (Attachment A) at ¶¶ 5-22, 30-37 (“Pilong Aff.”). \n9 Pilong Aff. at ¶ 5."},{"page":3,"startToken":734,"endToken":1052,"text":"3 \nhave the ability to track individual large loads, associate those loads with a specific \ntransmission service reservation, track service limits for a particular reservation, and direct \ncurtailment down to an individual reservation.10  Therefore, PJM will have to make \nsignificant changes to its system to provide Interim NITS.11  Constellation suggests that \nPJM should be in a position to implement this service on the same timeframe PJM proposed \nto implement its proposed Interim Resource Adequacy Service (“IRAS”).12  IRAS was \nproposed to be implemented on an aggregate, zonal basis using largely existing tools, \nwhereas Interim NITS curtailment will occur on an individual transmission service request \nbasis and requires entirely new tools and automation.13   \nSince the August Filing, PJM has further refined the timeline for making the \nrequisite system changes to accommodate Interim NITS.  Currently, PJM anticipates \nmodifying the systems needed to begin accepting requests for the new transmission \nservices in September of 2027.  PJM is developing a proposal for a new a study process \nthat would evaluate large loads and generation interconnection requests together in a \nunified cluster study that would take roughly a year to complete.14  PJM plans to file that \nproposal on or before November 16, 2026, in response to the Large Load Show Cause \nOrder.  Assuming the Commission accepts that proposal, PJM anticipates opening the \n \n10 Pilong Aff. at ¶¶ 28-30. \n11 Pilong Aff. at ¶¶ 16-20, 30-37. \n12 Constellation Limited Protest at 3-5; see PJM Interconnection, L.L.C., Proposal of PJM Interconnection, \nL.L.C. to Establish Interim Resource Adequacy Service and a Large Load Registry to Address System \nReliability, Docket No. ER26-3515-000 (Aug. 13, 2026). \n13 Pilong Aff. at ¶¶ 27-40. \n14 See Donnie Bielak, Director, Interconnection Planning, Show Cause for Large Loads Framework, PJM \nInterconnection, L.L.C. (Sep. 16, 2026), https://www.pjm.com/-/media/DotCom/committees-\ngroups/workshops/cllsco/2026/20260916/20260916-item-03---show-cause-for-large-loads-approach---\npresentation.pdf [https://perma.cc/44V9-48WU]."},{"page":4,"startToken":1052,"endToken":1335,"text":"4 \napplication process in September of 2027, conducting the study in 2028, and beginning to \nprovide service in first quarter 2029.15  PJM remains committed to continuing to explore \nways to promptly implement the new Commission-directed transmission services, \nincluding the feasibility of implementing disfavored options that rely on more manual \nprocesses as opposed to automated processes.16 \nB. \nNecessary Study Process \nConstellation asks the Commission to order PJM to clarify that Necessary Studies \nneed not be repeated where the scope of the previously conducted study has not changed.17  \nAs Constellation notes, however, the Commission clarified in the June Hearing Order that \nthe scope of the Necessary Study process should not change.18  While PJM will not repeat \nstudies already performed, project scope or other technical changes may trigger the need \nfor additional study.  By way of example, if a generator elects to reduce its Capacity \nInterconnection Rights (“CIR”) consistent with the Commission’s directives as part of a \nco-located load arrangement, but that CIR reduction was not previously communicated to \nPJM and thus not studied, the impact of that CIR reduction will have to be assessed. \nC. \nTransmission Owner Technical Requirements \nConstellation claims PJM added language regarding complying with the \nTransmission Owner’s technical requirements in Tariff Part XI section 702.4 for Interim \nNITS without the Commission ordering it to do so.19  That is incorrect.  The June Hearing \nOrder clarified that the provision of any new transmission service must be compliant with \n \n15 See id. \n16 Pilong Aff. at ¶¶ 5, 9. \n17 Constellation Limited Protest at 5. \n18 Id. (citing PJM Interconnection, L.L.C., 195 FERC ¶ 61,209, at P 283 (2026) (“June Hearing Order”)). \n19 Constellation Limited Protest at 7-8."},{"page":5,"startToken":1335,"endToken":1607,"text":"5 \nboth PJM’s and the Transmission Owners’ technical requirements to limit withdrawals \nfrom the system.20  Interim NITS is such a service, as customers must be able to limit their \nwithdrawals from the system consistent with the existing system limits (i.e., prior to the \ncompletion of network upgrades needed to provide NITS).21   Therefore, PJM \nappropriately added this language to the Proposed Part XI, section 702.4 in the August \nFiling. \nD. \nInterim NITS And Resource Adequacy \nConstellation expresses concern that PJM will limit the provision of Interim NITS \ndue to resource adequacy considerations.22  That is not the case.  The August Filing \nspecified that PJM will provide Interim NITS consistent with system reliability.23  In \nevaluating a request for Interim NITS, PJM will examine the ability of the system to \nprovide some level of deliverability for a service request while maintaining the reliability \nof the system.24  Consistent with the Commission’s orders, the August Filing specified that \nInterim NITS will be interruptible and curtailed before firm services like Firm Contract \nDemand Service or NITS that are capacity-backed services.25  In the event of a capacity \nshortage, Interim NITS will be curtailed before capacity-backed services during \noperations.26   \n \n20 June Hearing Order at PP 458, 486-87. \n21 See August Filing, Attachment A (Proposed Marked Tariff) at Part XI, section 705.1. \n22 Constellation Protest at 8-9. \n23 August Filing, Attachment A (Proposed Marked Tariff) at Part XI, section 702.3. \n24 Id. \n25 See August Filing, Attachment A (Proposed Marked Tariff) at Part XI, section 705.1. \n26 August Filing, Attachment A (Proposed Marked Tariff) at Part XI, section 705.2."},{"page":6,"startToken":1607,"endToken":1897,"text":"6 \nE. \nPartial NITS \nConstellation seeks clarification regarding the statement in the August Filing \nconcerning the provision of partial NITS (i.e., NITS in an amount less than requested or \nfor a term shorter than requested).27  PJM clarifies that this is existing NITS under Part III \nof the Tariff.  When applying for NITS under Part III of the Tariff, an Eligible Customer \nprovides a description of Network Load at each delivery point, including forecasted total \nload over a ten-year period.28  To the extent PJM cannot meet the full requested schedule \nfor commencement of service, PJM instead provides the available amount of full NITS \nservice it can provide based on available transfer capability.29   \nF. \nBehind The Meter Generation (“BTMG”) Issues \n1. \nAn Interconnection Service Agreement does not disqualify from \nnetting. \nNational Railroad Passenger Corporation (“Amtrak”) and various industrial \ncustomers express concern that the definitions PJM proposed may somehow disqualify \nindustrial customers that sell surplus energy to the grid from netting their load under their \nexisting BTMG arrangements.30  This matter is premature and beyond the scope of the \npending compliance filing.  PJM has proposed no such restriction nor does it intend to \ninclude such a restriction in its upcoming compliance filing.  PJM posted draft Tariff \nlanguage to implement the BTMG netting provisions for stakeholder feedback in advance \nof the upcoming November compliance filing.31  The draft Tariff language includes \n \n27 Constellation Limited Protest at 6-7. \n28 Tariff, Part III, section 29.2(iii). \n29 Tariff, Part III, section 29.2A. \n30 See Amtrack Limited Protest at 8-10.  \n31 PJM Interconnection, L.L.C., PJM draft Tariff language, subject to change Draft Retail BTMG language \nfor November 2026 filing (Sep. 16, 2026), https://www.pjm.com/-/media/DotCom/committees-"},{"page":7,"startToken":1897,"endToken":2164,"text":"7 \ngrandfathering provisions for existing commercial arrangements, co-generation, and a \ntransition period.32  It does not exclude based on whether the load has an Interconnection \nService Agreement.  However, given the confusion surrounding eligibility for netting, PJM \nintends to propose clarifications to the definition of BTMG in the November compliance \nfiling to specify that load with BTMG is excluded from the definition of Co-Located Load.  \nPJM will continue to engage with stakeholders on this issue in advance of the November \nfiling. \n2. \nPJM agrees that a clarification of the defined term, “Eligible \nGenerating Facility” is warranted. \nAmerican Municipal Power, Inc.’s (“AMP”) limited protest avers that the proposed \ndefinition of an “Eligible Generating Facility” may disqualify Non-Retail BTMG from \nqualifying for use of the new transmission services.33  The August Filing made the new \ninterim NITS available to Eligible Customers taking service on behalf of Eligible Load, \nwhich was defined to include both Co-Located Load and load connected to Behind the \nMeter Generation.34  PJM did not intend to exclude Non-Retail Behind the Meter \nGeneration from eligibility for the new transmission services.  Accordingly, PJM, does not \nobject to AMP’s proposed revision to Eligible Generating Facility definition set forth in its \npleading.35  However, any Eligible Customer taking interim NITS to serve load with Non-\nRetail Behind the Meter Generation will need to meet the operational requirements \n \ngroups/workshops/cllsco/2026/20260916/20260916-item-02---oatt-342-revisions---redline.pdf \n[https://perma.cc/AP3E-8LRH]. \n32 Id. \n33 AMP Limited Protest at 5-6. \n34 August Filing, Attachment A (Proposed Marked Tariff) at Definitions A-B (Behind the Meter \nGeneration). \n35 AMP Limited Protest at 7."},{"page":8,"startToken":2164,"endToken":2273,"text":"8 \nassociated with that service set forth in the Tariff (e.g., limit withdrawals from the \ntransmission system).  \nII. \nCONCLUSION \nBased on the foregoing, PJM requests that the Commission grant PJM’s motion for \nleave to answer and accept the foregoing answer and affidavit.   \n \nRespectfully submitted \n/s/ Ruth M. Porter \n \nMark J. Stanisz \nAssociate General Counsel \nPJM Interconnection, L.L.C. \n2750 Monroe Blvd. \nNorristown, PA  19403-2429 \n(610) 666-4707 \nmark.stanisz@pjm.com    \n \n \n \n \nOctober 14, 2026 \nWendy B. Warren \nRuth M. Porter \nWright & Talisman, P.C. \n1200 G Street, NW, Suite 600 \nWashington, DC  20005 \n(202) 393-1200 \nwarren@wrightlaw.com \nporter@wrightlaw.com \n \n \nCounsel for  \nPJM Interconnection, L.L.C."},{"page":9,"startToken":2273,"endToken":2347,"text":"CERTIFICATE OF SERVICE \n \n \nI hereby certify that I have on this day served the foregoing document on each \nperson designated on the service list compiled by the Secretary in these proceedings. \n \nDated at Washington, DC on this 14th day of October 2026. \n \n \n \n \n \n \n \n/s/ Ruth M. Porter \n \nRuth M. Porter \nWright & Talisman, P.C. \n1200 G Street, NW, Suite 600 \nWashington, DC 20005 \n(202) 393-1200 \nporter@wrightlaw.com \n \n \nCounsel for  \nPJM Interconnection, L.L.C."},{"page":10,"startToken":2347,"endToken":2357,"text":"Attachment A \n \n \n \n \n \n \n \nAffidavit of Christopher Pilong \nSenior Director, Operations Planning"},{"page":11,"startToken":2357,"endToken":2691,"text":"UNITED STATES OF AMERICA \nBEFORE THE \nFEDERAL ENERGY REGULATORY COMMISSION \n \nPJM Interconnection, L.L.C.  \n \n) \n \nDocket Nos. EL25-49-000 \n \n \n \n \n \n \n) \n \n \n         EL25-49-001 \n \n \n \n \n \n \n) \n \n \n         EL25-49-002 \n ) \n \n \n \n) \nPJM Interconnection, L.L.C.  \n \n) \n \nDocket No. ER26-1479-000 \n \nAFFIDAVIT OF CHRISTOPHER PILONG \nON BEHALF OF PJM INTERCONNECTION, L.L.C. \n \n1. \nMy name is Christopher Pilong and my business address is 2750 Monroe Blvd., \nAudubon, Pennsylvania 19403.  I am the Senior Director, Operations Planning at \nPJM Interconnection, L.L.C. (“PJM”).  In that role, I am responsible for functions \nthat support the reliable planning and preparation of PJM’s bulk electric system for \nreal-time operations.  My responsibilities include oversight of operational studies, \nprocesses, tools, and coordination activities with Generation Owners, Transmission \nOwners and neighboring entities, as well as gas-electric coordination with the \nnatural industry. \n2. \nI am submitting this affidavit in support of PJM’s proposed revisions to the PJM \nOpen Access Transmission Tariff (“Tariff”) filed August 17, 2026, to comply with \nthe Federal Energy Regulatory Commission’s (“Commission”) directives in its \nJune 18, 2026 order,1 including the directive to reconsider the proposed effective \ndate for PJM to offer the new transmission services for Eligible Customers taking \nservice on behalf of Co-Located Load and load with Behind the Meter Generation.  \nBecause PJM has to date only proposed Tariff language for Interim Network \nIntegration Transmission Service (“NITS”), my affidavit is limited to addressing \nimplementation of that service. \n3. \nIn this affidavit, I explain: \n• The operational complexities associated with implementing Interim \nNITS on an automated basis and scope of changes on PJM’s systems \nthat will be needed to accommodate automated provision of Interim \nNITS and the anticipated timing of implementing those changes. \n• Why the timeline PJM proposed for Interim Resource Adequacy \nService (“IRAS”) implementation is not comparable to Interim NITS. \n4. \nThis affidavit addresses implementation rather than the legal merits of any \nparticular Tariff design.  Because the Commission has not yet issued an order and \nfinal Tariff language, implementation requirements will depend on the terms of the \n \n1 PJM Interconnection, L.L.C, 195 FERC ¶ 61,209 (2026)."},{"page":12,"startToken":2691,"endToken":3086,"text":"2 \norder, including eligibility, priority, duration, curtailment standards, notice \nrequirements, transition rules, settlement treatment, and the relationship of these \nservices to existing transmission and market obligations.   \n \n5. \nAs explained below, PJM should not treat the implementation of Interim NITS as \na simple Tariff or software-configuration change.  PJM expects to receive \nsignificant interest in customers taking Interim NITS.  Given the anticipated level \nof demand, there is significant value in incorporating Interim NITS into PJM’s \nexisting automated systems and processes.  Providing Interim NITS on an \nautomated basis involves introducing a new operational status that must remain \nconsistent across planning, market, scheduling, outage, reliability, dispatch, \nsettlement, and customer-facing processes.   \n \nI. \nOPERATIONAL DESIGN AND PROCEDURE CHANGES  \n6. \nOnce the Commission approves proposed Tariff language, PJM first would need to \nconvert the Commission’s requirements into objective and auditable operating \nrules.  Those rules would need to define when service is available, the transmission \ncapability that supports it, the events that permit or require curtailment, the \nsequence and priority of curtailment, restoration criteria, customer notification, and \nthe treatment of partial curtailments.  The rules also would need to address conflicts \namong \nreliability \ndirectives, transmission service priorities, generation \ncommitments, and market outcomes. \n7. \nExisting operating agreements, manuals, desk procedures, emergency procedures, \ntraining materials, operator displays, alarm protocols, and shift turnover practices \nwould require review and, in many cases, revision.  PJM would need clear decision \nrights for declaring a qualifying condition, approving a curtailment, communicating \nthe instruction, monitoring compliance, and restoring service.  Procedures must \nwork during normal operations, constrained operations, emergencies, restoration, \nand periods when communications or applications are degraded. \n8. \nInterim NITS presents a number of implementation challenges.  Network service \nordinarily is embedded in network modeling, designation of network resources and \nload, transmission planning assumptions, scheduling rights, market participation, \nand long-term reliability obligations.  An “interim” status therefore must be defined \nconsistently across time horizons and must not inadvertently create rights, \npriorities, or planning assumptions beyond those authorized by the Commission. \n9. \nImplementing this construct for Interim NITS would require exception \nmanagement.  Examples include late or inaccurate data, a customer’s failure to \ncurtail, a change in topology after the applicable study, overlapping transmission \nreservations, generator or transmission outages, load forecast error, restoration \nfollowing a contingency, and a service period that crosses operating days or \nsettlement intervals.  Some manual workarounds may exist, but they are not \npreferable or durable substitutes for controlled and auditable production processes."},{"page":13,"startToken":3086,"endToken":3495,"text":"3 \nII. \nCOORDINATION WITH TRANSMISSION OWNERS, GENERATION \nOWNERS, AND CUSTOMERS \n10. \nImplementation of Interim NITS would require substantial coordination with PJM \nTransmission Owners. Transmission Owners would need to understand and support \nthe service definitions, study assumptions, facility ratings, topology inputs, local \noperating procedures, switching implications, notification paths, and field \nexecution responsibilities.  Where a curtailment is intended to relieve a local or \nregional constraint, PJM and the affected Transmission Owner must agree on the \nrelevant monitored facilities, contingencies, expected distribution factors, \nvalidation method, and restoration criteria. \n11. \nTransmission Owner systems and procedures may require corresponding changes.  \nThese may include energy management system displays, outage coordination \npractices, control-center instructions, operator training, customer communications, \nand evidence retention.  Differences among Transmission Owner footprints, legacy \nsystems, and local procedures will require testing by affected zone rather than \nreliance on a single generic implementation. \n12. \nCoordination with Generation Owners and other market participants also is \nnecessary because new service states can alter commitment, dispatch, reserve \nprocurement, congestion management, and outage assumptions. PJM would need \nto explain how a curtailment instruction interacts with generation dispatch \ninstructions, must-offer or availability obligations, bilateral arrangements, and any \ngeneration or storage serving the affected load. \n13. \nCustomers receiving the service would need defined telemetry, metering, \ncommunications, scheduling, and response obligations.  PJM would need validated \npoints of contact available at all times, test protocols, escalation paths, and \nconsequences for non-performance.  Meter-data latency and granularity must be \nsufficient to determine whether the requested relief occurred and when it occurred. \n14. \nA further implementation uncertainty is the identity and operational role of the new \n“Eligible Customer” that would take service on behalf of the underlying load.  \nDepending on the final tariff construct, that entity may not be the load-serving \nentity, end-use customer, Transmission Owner, or market participant with which \nPJM currently exchanges operating instructions.  PJM therefore would need to \nverify the entity’s legal and operational authority to act for the load; define its \nresponsibilities relative to those other parties; establish secure, continuously staffed \nprimary and backup communication channels; identify authorized contacts and \nescalation paths; and develop protocols for issuing, acknowledging, executing, and \ndocumenting curtailment and restoration instructions.  PJM also would need to \ndetermine required telemetry, metering, scheduling, outage, cybersecurity, identity-\nmanagement, and data-sharing arrangements; execute any necessary agreements or \nregistrations; conduct communications and failover testing; train the parties; and \nconfirm that an instruction to the Eligible Customer can be translated into timely, \nmeasurable action at the affected load.  If the identity, authority, technical"},{"page":14,"startToken":3495,"endToken":3815,"text":"4 \ncapability, or relationship of the Eligible Customer to the underlying load is not \nknown early in implementation, onboarding and certification could become a \ncritical-path item and could extend the implementation schedule. \n15. \nReliability Coordinators and neighboring systems may also need notice where \nimplementation changes interchange schedules, coordinated flowgate impacts, \ncongestion management, or other interregional processes.  Any external \ncoordination must be aligned with applicable reliability standards and existing joint \noperating agreements. \nIII. \nTOOL AND SYSTEM IMPACTS \n16. \nThe affected technology footprint is broad.  Detailed design would be required to \nidentify the authoritative source for each service attribute and to ensure that status \nchanges propagate consistently.  At a minimum, PJM would need to assess and \nlikely modify the following categories of tools: \n• Transmission-service request, study, reservation, and contract-administration \napplications, including customer-facing portals and study queues; \n• Network-model \nmanagement, \ntopology \nprocessing, \nfacility-rating, \ncontingency-analysis, and power-flow applications; \n• Energy management system and operator displays, including alarms, logs, \nswitching and constraint information, and real-time security analysis; \n• Day-ahead and real-time market engines, unit commitment and security-\nconstrained economic dispatch, reserve optimization, and pricing processes; \n• Load forecasting, interchange scheduling, and transmission loading relief or \ncongestion-management processes; \n• Generation and transmission outage scheduling and outage-impact assessment \ntools; \n• Telemetry, metering, data historians, event logging, operator logs, and \ncompliance evidence repositories; \n• Market settlements calculation and reporting systems; and \n• Data publication, market notifications, reporting, analytics, and customer-\nsupport tools. \n17. \nPJM also would need end-to-end auditability.  For each relevant interval, PJM \nshould be able to reconstruct the authorized service level, transmission conditions, \napplicable curtailment priority, notices sent, operator actions, customer response, \nmarket results, and settlement treatment.  That requirement implicates data \nretention, cybersecurity review, access controls, change management, and \nbusiness-continuity testing. \nIV. \nMARKET CLEARING, RELIABILITY AND SETTLEMENT IMPACTS \n18. \nMarket clearing requires a consistent representation of which load is firm, which \nload may be curtailed, when curtailment is available, and whether the curtailment \nis a pre-contingency control, a post-contingency action, or an emergency measure."},{"page":15,"startToken":3815,"endToken":4222,"text":"5 \nThat representation can affect constraint formulation, load distribution, \ncommitment, dispatch, reserve requirements, congestion, losses, prices, and \ninterchange feasibility. \n19. \nIf the market engines assume curtailment that operators cannot execute with \nsufficient certainty or speed, the resulting solution could understate reliability \nneeds.  Conversely, excluding available curtailment from all market and reliability \nanalyses could produce inefficient commitments or congestion outcomes.  PJM \ntherefore would need validated rules for when the service may be modeled, the \nconfidence assigned to it, and any conservative operating margin required. \n20. \nPJM also would need to determine whether and how curtailment affects locational \nmarginal prices, make-whole payments, uplift, transmission charges, congestion \nrights, reserve or emergency compensation, deviation charges, and other settlement \noutcomes.  The treatment must be internally consistent and understandable to \nmarket participants.  PJM would need to update its settlement calculation and \nreporting systems to account for proposed differences between the settlements \ntreatment for NITS and Interim NITS services.  The systems Electric Distribution \nCompanies (“EDCs”) and Load Serving Entities (“LSEs”) use to submit revenue \nquality metered load data will also need to be updated to allow differentiation of \nthe metered load served under NITS service from the load served under Interim \nNITS service given the differing settlements treatment. Further, EDCs and LSEs \nwill need to develop their own procedures to track and report the load of end-use \ncustomers taking the new transmission service to PJM distinctly from those using \nregular NITS service. \n21. \nReliability studies would need to evaluate contingencies in which the curtailable \nload does not respond, responds only partially, or is unavailable because of \ncommunications, equipment, or customer conditions.  Operators would need \nalternative actions for such failures.  The design also should avoid dependence on \na single point of failure and should define how service is suspended during tool \noutages or uncertain system conditions. \n22. \nImplementation may require revisions to model-development schedules, case-\nbuilding processes, seasonal and near-term studies, operator drills, and reliability \nassessments.  The interaction with generator deactivations, new resource \ninterconnections, load additions, transmission upgrades, and temporary operating \nguides must be evaluated so that interim service does not obscure an emerging \nreliability need. \nV. \nIMPLEMENTATION SCHEDULE \n23. \nAssuming a Commission order provides sufficiently complete direction and does \nnot require immediate service, I estimate that a controlled production \nimplementation would require approximately 18 to 24 months after the later of \n(a) issuance of a final, non-ambiguous order and (b) availability of final tariff \nlanguage and business requirements.  A narrower implementation for a very"},{"page":16,"startToken":4222,"endToken":4563,"text":"6 \nlimited number of pre-identified customers could potentially be staged earlier, but \nonly if reliability protections, manual controls, and scope limits are expressly \ndefined.  A materially broader or differently designed service could require more \nthan 24 months. \n24. \nAn indicative schedule is as follows.  Activities would overlap, and later phases \ndepend on timely resolution of policy questions: \ni. \nOrder analysis and requirements confirmation — approximately 0 to 3 \nmonths. Interpret the order; identify affected tariff, manual, agreement, and \nreliability provisions; resolve ambiguities; define eligibility, priority, \ncurtailment, restoration, data, and settlement rules; establish governance and \nimplementation scope. \nii. \nDetailed process and solution design—approximately 2 to 6 months. Map \nend-to-end processes; complete reliability and market-impact analyses; define \ndata ownership and interfaces; develop exception handling; coordinate with \nTransmission Owners, Generation Owners, customers, and neighboring \nentities. \niii. \nDevelopment and procedure revision—approximately 5 to 14 months. \nConfigure or develop affected applications and interfaces; revise manuals, desk \nprocedures, forms, operating agreements, training, notifications, reports, and \ncustomer materials; establish telemetry and metering requirements. \niv. \nIntegrated testing—approximately 12 to 18 months. Perform component, \ninterface, regression, cyber, performance, failover, settlement, and zone-\nspecific Transmission Owner testing; correct defects and repeat tests. \nv. \nReadiness, training, and controlled deployment—approximately 16 to 21 \nmonths. Train and qualify operators and support staff; conduct drills; complete \ncustomer certification; verify round-the-clock contacts; execute cutover and \nrollback plans; begin with controlled enrollment where appropriate. \nvi. \nStabilization and full production—approximately 21 to 24 months. Monitor \noutcomes; reconcile market and settlement results; resolve defects; validate \noperational relief; complete post-implementation review; and expand only after \nreadiness criteria are met. \n25. \nThis estimate assumes that PJM can assign adequate subject-matter experts and \ndevelopment capacity; affected Transmission Owners and customers make \ncorresponding changes on schedule; required data and telemetry are available; no \nmaterial rehearing or compliance-filing ambiguity delays final requirements; and \nthe implementation can be coordinated with established market-model, software-\nrelease, training, and seasonal-readiness calendars. \n26. \nSchedule risk would increase if the order requires service before necessary system \nchanges are complete, applies broadly at inception, changes curtailment priority,"},{"page":17,"startToken":4563,"endToken":4974,"text":"7 \nrequires new optimization logic, alters pricing or settlement rules, depends on new \ntelemetry or Transmission Owner functionality, or requires parallel implementation \nduring a peak-season freeze or other major market release. \nVI. \nDIFFERENCES FROM IRAS IMPLEMENTATION \n27. \nConstellation Energy Generation, LLC (“Constellation”) incorrectly characterizes \nInterim NITS implementation as comparable to the implementation of the IRAS \nframework.  The two initiatives differ materially in scope, operational complexity, \nrequired market system modifications, transmission service administration impacts, \nand reliability implementation requirements. \n \n28. \nWhile IRAS primarily establishes a planning and accreditation framework that \nrelies upon existing market and operational constructs, Interim NITS requires PJM \nto develop entirely new processes for administering, tracking, limiting, and \ncurtailing transmission service associated with individual large load customers.  \nAccordingly, the implementation timelines are not analogous. \n \n29. \nInterim NITS requires PJM to manage transmission service at an Eligible Customer \nand transmission service request level, as opposed to zonal level.  PJM’s current \noperating and emergency procedures are primarily designed around zonal load \nforecasting, zonal load management, and system-wide reliability actions.  Under \nexisting arrangements PJM forecasts load at the transmission zone level.  In \naddition, capacity obligations are assigned at the zone and LSE level.  Emergency \nload management actions are generally executed through zonal or broader \nreliability directives.  Market systems clear generation against aggregate load \nforecasts rather than individual transmission customers. \n \n30. \nInterim NITS introduces an entirely different construct requiring PJM to identify, \nmonitor, and potentially curtail transmission service attributable to specific large \nloads.  Unlike a zonal curtailment approach, customer-specific transmission service \ncurtailments require various actions directed at the individual loads being served \nby Eligible Customers.  This will require PJM to have the capability to identify the \nindividual affected loads in the operations systems and track the transmission \nservice rights associated with those loads.  PJM will then need to have the capability \nto determine the customer-specific curtailment quantities, which will require \nfurther development of priority and allocation methodologies.  PJM will also have \nto coordinate this implementation with the Transmission Owners.  PJM will also \nneed to have protocols to validate customer-specific exception conditions and take \ncustomer-specific actions in real time.  These capabilities do not exist today within \nPJM’s operating platform and must be newly developed. \n \n31. \nImplementation of Interim NITS requires significant modifications to several \nexisting systems and business processes used to administer transmission service.  \nAmong other changes, PJM must develop capabilities to register and maintain \nEligible Customers’ individual large loads, associate those loads with transmission \nservice reservations, and track load-specific transmission service limits.  PJM will"},{"page":18,"startToken":4974,"endToken":5369,"text":"8 \nalso need to establish curtailment eligibility criteria, create notification and \ncommunication protocols, and integrate transmission service information across \nplanning, operations, and settlements systems.  PJM will also need to develop \nauditable compliance records for transmission service administration. \n \n32. \nThese requirements represent a substantial departure from PJM’s current \ntransmission service framework, which was not designed to administer \ntransmission service limitations on individual end-use customer loads.  By contrast, \nIRAS largely leverages existing planning, capacity market, and resource \naccreditation processes. \n \n33. \nPJM will have to modify the market-clearing engines to implement Interim NITS \non an automatic basis.  Constellation understates the degree to which Interim NITS \naffects PJM's market systems.  To implement Interim NITS, PJM must evaluate \nmodifications to both Day-Ahead and Real-Time market operations. \n \n34. \nDay-Ahead Market Impacts.  For implementation of Interim NITS in the Day-\nAhead Market, PJM must make significant modifications to the current system.  \nMoreover, to do so, PJM must determine a range of implementation details \nincluding how Interim NITS will be represented in the Day-Ahead load forecast, \nwhether curtailment limitations affect demand bid treatment, and how transmission \nservice restrictions impact commitment decisions.  PJM will also need to determine \nhow reliability commitments should account for potentially interruptible \ntransmission service.  The Day-Ahead market engine currently assumes load \nforecasts consistent with existing transmission service obligations.  Introducing \ncustomer-specific transmission service constraints may require system design \nchanges and extensive testing to ensure appropriate unit commitment outcomes. \n \n35. \nReal-Time Market Impacts.  The Real-Time implementation of Interim NITS \npresents additional complexity.  To implement Interim NITS in Real-Time, PJM \nmust determine various parameters for including Interim NITS in the Real-Time \nMarket.  For example, PJM must determine when customer-specific transmission \nservice limitations become binding and how transmission service curtailments \ninteract with dispatch and reserve commitments.  PJM must also establish how \noperators will recognize and model curtailed load and how real-time telemetry and \noperational visibility requirements will be satisfied.  PJM must also determine how \nreliability actions are coordinated with transmission owners and affected \ncustomers.  Ultimately, the interaction between customer-specific transmission \nservice restrictions and real-time security-constrained economic dispatch in \nimplementing Interim NITS requires detailed design, testing, and validation to \navoid unintended reliability consequences. \n \n36. \nReliability Risks.  The reliability and operational risks associated with Interim \nNITS differ materially from those of IRAS.  IRAS primarily affects resource \naccreditation and resource adequacy planning.  Interim NITS directly affects real-\ntime operational execution.  Specifically, Interim NITS requires PJM to establish"},{"page":19,"startToken":5369,"endToken":5720,"text":"9 \ncustomer-specific curtailment methodologies and reliability-based criteria to \ntrigger those curtailment methodologies.  Once those methodologies and criteria \nare established, PJM also must establish operator procedures and communication \nprotocols for implementation, along with compliance and audit processes.  \nMoreover, PJM must establish processes for coordination with the transmission \nowners and load-serving entities.  As part of this effort, PJM will need to ensure \nappropriate dispute resolution mechanisms for transmission service administration \nbecause any errors in these processes could result in improper curtailment of \ntransmission customers.  Because Interim NITS directly impacts operational \nreliability actions, PJM must ensure comprehensive testing and validation prior to \nimplementation. \n \n37. \nSoftware Development and Testing.  The software development needs and testing \nrequirements to implement Interim NITS are also significantly greater than IRAS.  \nImplementation of Interim NITS requires coordinated modifications across \nmultiple platforms, including the transmission service systems, load forecasting \nsystems, and customer registration systems.  PJM will also have to modify its \nmarket clearing applications, operator tools, settlements systems, reporting and \ncompliance systems, and the data interfaces with transmission owners.  Each of \nthese modifications requires requirements development, software design, coding, \nintegrated system testing, market participant testing, operator training, and \nproduction deployment. \n \n38. \nUnlike IRAS, which predominantly leverages established planning and capacity \nmarket constructs, Interim NITS introduces entirely new operational functionality \nthat must function correctly during emergency grid conditions. Consequently, \nextensive development and testing are necessary to avoid reliability risks.  Any \nincremental benefits associated with implementing Interim NITS do not justify \naccelerating implementation at the expense of reliability. \n \n39. \nPJM agrees that large load growth presents emerging reliability challenges.  \nHowever, implementation speed cannot come at the expense of operational \naccuracy and reliability.  The Commission has consistently recognized that RTOs \nmust ensure that major operational, market, and transmission administration \nchanges are fully designed, tested, and validated before implementation.  The \ncomplexity associated with customer-specific transmission service management \nwarrants a deliberate implementation schedule that ensures reliable, transparent, \nand non-discriminatory administration. \n \n40. \nAccordingly, the implementation timeline proposed by PJM reflects the substantial \noperational, software, market, and transmission service changes necessary to \nimplement Interim NITS successfully and cannot reasonably be equated to the \nimplementation requirements associated with IRAS."},{"page":20,"startToken":5720,"endToken":5826,"text":"10 \nVII. \nCONCLUSION \n41. \nIn my opinion, implementing Interim NITS safely and reliably requires coordinated \nchanges across PJM operations, Transmission Owners, Generation Owners, \ncustomers, market systems, transmission-service systems, settlements, training, \nand compliance processes.  The work must proceed from a stable service definition \nand must include integrated testing under normal, constrained, emergency, and \ndegraded-tool conditions. \n42. \nA Commission-authorized transition period of approximately 18 to 24 months \nwould provide a reasonable implementation window under the assumptions stated \nabove.  That period is necessary to reduce the risk of inconsistent service treatment, \nnon-executable market assumptions, unreliable curtailment, settlement errors, and \ninadequate operator or stakeholder readiness. \n43. \nThis concludes my Affidavit."},{"page":21,"startToken":5826,"endToken":5948,"text":"UNITED STATES OF AMERICA \nBEFORE THE \nFEDERAL ENERGY REGULATORY COMMISSION \n \nPJM Interconnection, L.L.C.  \n \n) \n \nDocket Nos. EL25-49-000 \n \n \n \n \n \n \n) \n \n \n         EL25-49-001 \n \n \n \n \n \n \n) \n \n \n         EL25-49-002 \n ) \n \n \n \n) \nPJM Interconnection, L.L.C.  \n \n) \n \nDocket No. ER26-1479-000 \n \n \nVERIFICATION OF CHRISTOPHER PILONG \n \nI, Christopher Pilong, pursuant to 28 U.S.C. § 1746, state, under penalty of perjury, \nthat I am the Christopher Pilong referred to in the foregoing “Affidavit of Christopher \nPilong on Behalf of PJM Interconnection, L.L.C.,” that I have read the same and am \nfamiliar with the contents thereof, and that the facts set forth therein are true and correct to \nthe best of my knowledge, information, and belief. \n/s/ Christopher Pilong \n \nChristopher Pilong \nSenior Director  \nOperations Planning \nPJM Interconnection, L.L.C. \n                                                                                     \nExecuted on: October 14, 2026"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":2,"endAt":622,"startToken":0,"endToken":540},{"p":2,"at":622,"title":"I. ANSWER","method":"printed heading","endPage":2,"endAt":634,"startToken":540,"endToken":542},{"p":2,"at":634,"title":"A. PJM’s Proposed Effective Date for Interim NITS","method":"printed heading","endPage":4,"endAt":397,"startToken":542,"endToken":1109},{"p":4,"at":397,"title":"B. Necessary Study Process","method":"printed heading","endPage":4,"endAt":1221,"startToken":1109,"endToken":1238},{"p":4,"at":1221,"title":"C. Transmission Owner Technical Requirements","method":"printed heading","endPage":5,"endAt":447,"startToken":1238,"endToken":1407},{"p":5,"at":447,"title":"D. Interim NITS And Resource Adequacy","method":"printed heading","endPage":6,"endAt":3,"startToken":1407,"endToken":1608},{"p":6,"at":3,"title":"E. Partial NITS","method":"printed heading","endPage":6,"endAt":713,"startToken":1608,"endToken":1722},{"p":6,"at":713,"title":"F. Behind The Meter Generation (“BTMG”) Issues","method":"printed heading","endPage":8,"endAt":115,"startToken":1722,"endToken":2182},{"p":8,"at":115,"title":"II. CONCLUSION","method":"printed heading","endPage":8,"endAt":120,"startToken":2182,"endToken":2183},{"p":8,"at":120,"title":"CONCLUSION","method":"printed heading","endPage":9,"endAt":0,"startToken":2183,"endToken":2273},{"p":9,"at":0,"title":"CERTIFICATE OF SERVICE","method":"printed heading","endPage":10,"endAt":0,"startToken":2273,"endToken":2347},{"p":10,"at":0,"title":"Attachment A","method":"printed heading","endPage":12,"endAt":837,"startToken":2347,"endToken":2797},{"p":12,"at":837,"title":"I. OPERATIONAL DESIGN AND PROCEDURE CHANGES","method":"printed heading","endPage":13,"endAt":3,"startToken":2797,"endToken":3087},{"p":13,"at":3,"title":"II. COORDINATION WITH TRANSMISSION OWNERS, GENERATION","method":"printed heading","endPage":14,"endAt":570,"startToken":3087,"endToken":3566},{"p":14,"at":570,"title":"III. TOOL AND SYSTEM IMPACTS","method":"printed heading","endPage":14,"endAt":2372,"startToken":3566,"endToken":3772},{"p":14,"at":2372,"title":"IV. MARKET CLEARING, RELIABILITY AND SETTLEMENT IMPACTS","method":"printed heading","endPage":15,"endAt":2607,"startToken":3772,"endToken":4163},{"p":15,"at":2607,"title":"V. IMPLEMENTATION SCHEDULE","method":"printed heading","endPage":17,"endAt":232,"startToken":4163,"endToken":4594},{"p":17,"at":232,"title":"VI. DIFFERENCES FROM IRAS IMPLEMENTATION","method":"printed heading","endPage":20,"endAt":4,"startToken":4594,"endToken":5721},{"p":20,"at":4,"title":"VII. CONCLUSION","method":"printed heading","endPage":20,"endAt":10,"startToken":5721,"endToken":5722},{"p":20,"at":10,"title":"CONCLUSION","method":"printed heading","endPage":21,"endAt":979,"startToken":5722,"endToken":5948}]}