{"document":{"slug":"order-er26-2691-duke-nitsa","title":"Order Accepting Proposed Tariff Revisions (Duke Energy Carolinas pro forma NITSA, ER26-2691-000 and -001)","issued":"2026-10-09","accession":"20261009-3054","docket":"ER26-2691-000","group":"Duke Energy Carolinas network service agreement and large-load shortfall payments","filer":"FERC","kind":"order","file":"sources/originals/20261009-3054_ER26-2691-000.docx","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20261009-3054","sha256":"68f645a380ba52b947da302814df50e9d1a8ef8be647002abfa01547eb366701","pages":null,"tokens":19613,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":19613,"text":"197 FERC ¶ 61,020\nUNITED STATES OF AMERICA\nFEDERAL ENERGY REGULATORY COMMISSION\n\nBefore Commissioners:  Laura V. Swett, Chairman;\n                                        David Rosner, Lindsay S. See,\n                                        Judy W. Chang, and David LaCerte.\n\nDuke Energy Carolinas, LLC\nDocket Nos.\n ER26-2691-000\n ER26-2691-001\n\nORDER ACCEPTING PROPOSED TARIFF REVISIONS\n\n (Issued October 9, 2026)\n\nOn May 29, 2026, pursuant to section 205 of the Federal Power Act (FPA)[fn:2] and Part 35 of the Commission’s regulations,[fn:3] Duke Energy Carolinas, LLC (DEC) filed revisions to its pro forma Network Integration Transmission Service Agreement (NITSA) under its Joint Open Access Transmission Tariff (Joint OATT).[fn:4]  As discussed below, we accept the proposed revisions to DEC’s pro forma NITSA, effective August 1, 2026, as requested. \nBackground\nDEC provides network integration transmission service (NITS) to 20 network customers, including municipalities, cooperatives, universities, and government agencies, in the DEC balancing authority area, which spans North Carolina and South Carolina.[fn:5]  DEC explains that the pro forma NITSA sets forth the terms and conditions for DEC, as transmission provider, to provide NITS to its network customers and is included in the Joint OATT as Attachment F-2.  All of DEC’s network customers have existing individual NITSAs on file with the Commission, most of which predate the 2012 filing of DEC’s pro forma NITSA.[fn:6] \nProposed Tariff Revisions\nDEC proposes revisions to the body of its pro forma NITSA and existing attachments, as well as to add a new Attachment F.  These revisions make changes to terms, conditions, and procedures pertaining to:  (1) Network Load designations;                  (2) requests for changes in transmission service to accommodate new or transferred Network Load; (3) rate treatment and financial security requirements for Network Upgrades; (4) shortfall payments for loads of 100 MW or greater; and (5) transmission customer audits, among other related changes.  Proposed Attachment F to DEC’s                 pro forma NITSA sets forth terms and conditions in cases in which the Transmission Customer has submitted a change in service request:  (1) for new Network Load at an existing Delivery Point; (2) for new Network Load at a new Delivery Point(s); or (3) to transfer existing Network Load from an existing Delivery Point(s) to another Delivery Point(s) (existing or new).\nDEC asserts that the proposed revisions are necessary to reflect profound changes in service requests fueled by increasing Network Load and the changing network resource mixes that have occurred since DEC’s last update to its pro forma NITSA.[fn:7]  DEC notes that customer-served load has increased by approximately 800 MW since 2012, which includes nine customer requests to serve new large Network Load[fn:8] ranging from 102 MW to a multi-phase project of 945 MW.  DEC states that in that same timeframe, there have been 224 requests on DEC’s system to:  (1) designate new resources and new Network Load; (2) establish new points of delivery; and (3) modify or terminate existing points of delivery, which has resulted in the installation of 289 new meters at points of delivery to provide network service.    \nDEC argues that it is reasonable to update its pro forma service agreements from time to time to reflect changing conditions, analogizing the proposed changes to the mandatory changes to pro forma service agreements the Commission required in Order No. 2023.[fn:9]  DEC states that the pro forma NITSA revisions add terms and conditions that are present in many of DEC’s individual NITSAs with its network customers.  \nNotices and Responsive Pleadings \nNotice of DEC’s filing was published in the Federal Register, 91 Fed. Reg. 33169 (June 3, 2026), with interventions and protests due on or before June 22, 2026.  Timely motions to intervene were filed by North Carolina Electric Membership Corporation and Seminole Electric Cooperative, Inc. \nSouthern Alliance for Clean Energy (SACE) and ElectriCities of North Carolina, Inc. (ElectriCities)[fn:10] filed timely motions to intervene and protests.  DEC filed an answer to the protests on July 6, 2026. \nOn July 29, 2026, a deficiency letter was issued requesting additional information regarding DEC’s proposal (Deficiency Letter).  On August 13, 2026, DEC submitted its response to the Deficiency Letter, which amended DEC’s filing (Deficiency Response).  Notice of DEC’s Deficiency Response was published in the Federal Register,                         91 Fed. Reg. 53408 (Aug. 18, 2026), with interventions and protests due on or before September 3, 2026.  None was filed. \nDiscussion\nProcedural Matters\nPursuant to Rule 214 of the Commission’s Rules of Practice and Procedure,                     18 C.F.R. § 385.214, the timely, unopposed motions to intervene serve to make the entities that filed them parties to this proceeding. \nRule 213(a)(2) of the Commission’s Rules of Practice and Procedure, 18 C.F.R.                § 385.213(a)(2), prohibits an answer to a protest unless otherwise ordered by the decisional authority.  We accept DEC’s answer because it has provided information that assisted us in our decision-making process.\nSubstantive Matters\nWe accept DEC’s proposed revisions to its pro forma NITSA, effective August 1, 2026, as requested.  We find that the revisions to DEC’s pro forma NITSA are just and reasonable and not unduly discriminatory or preferential, as discussed below.  \nNetwork Load Provisions\nFiling\nDEC proposes language in section 4 of Attachment A and section I.1 of new Attachment F to its pro forma NITSA that would apply to all requests for a change in service to add new Network Load or transfer existing Network Load from one delivery point to another.[fn:11]  Section I.1 of proposed new Attachment F would prohibit a transmission customer from seeking to increase or decrease the MW value of Network Load, unless and until that customer follows the study procedures in sections 32.1-32.4 of the Joint OATT.[fn:12]  To that end, DEC proposes language in sections 6.2 and 6.3 of Attachment A specifying that requests for changes in service under a NITSA may require a System Impact Study and/or Facilities Study.[fn:13]  In addition, proposed new                        subsection 4.4 of Attachment A and new Attachment F would require a network customer to submit a change in service request any time it seeks:  (1) new Network Load at a new or existing delivery point or points; or (2) transfer of existing Network Load from an existing delivery point to an existing or new delivery point.[fn:14]  Specifically, DEC proposes that the transmission customer must specify:  (1) the amount of MWs; (2) the type of service requested; (3) the desired in-service date; and (4) a load schedule detailing the timing and amount of load to be connected.[fn:15]  DEC argues that these proposed revisions align with sections 29.2, 31.1, and 31.2 of the Joint OATT, which DEC states mirrors the Commission’s pro forma OATT and are necessary for DEC to properly designate, study, and serve new load.[fn:16]    \nDEC contends that the proposed restriction on increasing or decreasing a Network Load’s MW size under section I.1 of new Attachment F is necessary to ensure that the Network Upgrades constructed to serve the Network Load are appropriately sized to meet the Network Load’s needs.[fn:17]  DEC explains that, on the one hand, allowing late additions of MWs could cause operational risks because the Network Upgrades that were constructed may be insufficient to reliably provide the additional service.  On the other hand, DEC states that preventing Network Customers from decreasing MWs ensures that the transmission system is not overbuilt, thus preventing undue cost shifts to other transmission customers.\nIn Attachment A to its pro forma NITSA, DEC proposed to add language in new subsection 4.1 stating that network customers’ load growth will not be treated as “Designation of Network Load” under Sections 31.2 and 31.3 of the Joint OATT and that a Network Customer’s estimated load growth will continue to be reflected in DEC’s annual update of forecasted Network Load under section 31.6 of the Joint OATT.[fn:18]  DEC states that this addition is necessary to delineate between load growth that is considered Designation of Network Load and load growth that is not, consistent with the Joint OATT.  New subsection 4.2 provides that the transmission customer’s behind-the-meter generation shall be included in the calculation of transmission customer’s network load, regardless of whether the load is served at retail or wholesale.  DEC argues that this addition is supported by Commission policy and Order No. 888.[fn:19]  \nDeficiency Letter and Deficiency Response\nThe Deficiency Letter asked DEC to explain whether the methodology, scope, or assumptions of the System Impact Study or Facilities Study will vary based on the MW size or other characteristics of the requested Network Load, including for requests of             100 MW or greater.[fn:20]  In response, DEC asserts that it uses the same methodology for the system impact and facilities studies that it performs regardless of the requested MW amount, but notes that the characteristics of each NITS request drive individualized scope and assumptions for the studies.[fn:21]  DEC explains that for the scope of the study, it establishes assumptions based on information in the NITS request, including the type, size, location, and operating characteristics of the load.  For example, DEC states that it performed system impact and facilities studies on a 945 MW NITS request for new Network Load to be served in York, South Carolina (Project Cobra), as well as additional NERC-compliant stability and power quality studies given the load’s size.  DEC adds that the Commission issued an order accepting the study agreement for Project Cobra.[fn:22]  \nThe Deficiency Letter also asked whether it is appropriate to apply the proposed Network Load rules in section 4 of Attachment A and section I.1 of Attachment F of DEC’s pro forma NITSA to all NITS requests, regardless of the size of the Network Load, as opposed to applying section I.1 of Attachment F solely to loads of 100 MW or greater.[fn:23]  In response, DEC states that section I.1 applies to each NITS request and does not prohibit customers from submitting successive requests to increase or decrease Network Load served by NITS.[fn:24]  DEC notes that this language is appropriate because the transmission customer has complete discretion to choose when to submit service requests, the desired MW amount, and the in-service date for requested load.[fn:25]  DEC asserts that it is appropriate to prevent transmission customers from increasing or decreasing the MWs in their service requests because the increased or decreased amount was not studied, and, as a result, the study report would not have identified the appropriate Direct Assignment Facilities and Network Upgrades.\n\tDEC argues that, accordingly, DEC proposed section I.1 to apply to all NITS requests because it will ensure that Direct Assignment Facilities and Network Upgrades are truly needed and sized correctly to reliably serve the amount of load requested and to avoid potential cost shifts to other customers.[fn:26]  DEC explains that cost shifting to other transmission customers could occur if its transmission system gets “overbuilt” to accommodate a NITS request that is later decreased in MW amount.[fn:27]  DEC provides an example in which certain transmission facilities are constructed to accommodate a service request but the requesting network customer takes less service than originally requested.  DEC explains that, in that case, the costs for Network Upgrades to serve the originally requested MW amount are included in transmission rate base, shifting costs to other transmission customers for Network Upgrades that are more extensive than was necessary to accommodate actual service taken.[fn:28]  Conversely, DEC provides an example where a transmission customer takes more service than originally requested.  DEC explains that, in that case, reliability could be compromised because more MWs are added to a system that was not designed to accommodate them.[fn:29]  DEC also notes that in such a scenario, DEC could construct certain Network Upgrades to accommodate the original request that are later removed from the system because they must be replaced by more extensive Network Upgrades.[fn:30]  DEC contends that this also imprudently shifts costs to other transmission customers because they must still pay for the Network Upgrades that were removed from the system.\n\tFinally, DEC states that similar language to section I.1 of Attachment F was included in 11 recent transmission security agreements and construction security agreements that the Commission accepted without modification.[fn:31]  \nCommission Determination\nWe find that DEC’s proposed changes and additions to Attachments A and F of its pro forma NITSA are just and reasonable and not unduly discriminatory or preferential.  As DEC explains, many of the revisions incorporate existing language and processes from the Joint OATT, providing further clarity and transparency to network customers entering into NITSAs.  Moreover, we find that DEC’s proposal to require network customers to submit a change in service request when they seek to add new or transfer existing Network Load and to follow the study procedures in sections 32.1-32.4 of the Joint OATT when seeking to increase or decrease the MW value of Network Load is reasonable.  Specifically, it will help DEC to ensure that the Network Upgrades that it constructs to serve a network customer’s Network Load are sufficient to reliably provide the requested service without resulting in DEC building more extensive Network Upgrades than necessary to provide that service, which could shift costs to DEC’s other transmission customers.[fn:32]  \nAs DEC details, it is currently experiencing significant load growth in its service territory.[fn:33]  We agree with DEC’s contention that such load growth could lead to operational challenges and cost shifting where a network customer is allowed, without any further study, to take more or less service under a NITSA than the network customer initially requested.  We further find that, as DEC explains, the proposed revisions will help to prevent the construction of inappropriately sized or unnecessary Network Upgrades that could either shift costs to other transmission customers (in the case of a decrease in service) or create reliability risks (in the case of an increase in service).  Given the recent projected rates of load growth in its service territory, DEC has explained that its transmission customers newly face both cost-shifting and reliability risks that they had not previously experienced, and DEC’s proposed changes will help to mitigate those risks.  For these reasons, we find that DEC’s new requirements for adding or transferring Network Load are just and reasonable. \nNetwork Upgrade Charges and Rolled-in Rate Treatment\nFiling\nDEC proposes a new section 6.6 to Attachment A, titled “Network Upgrade Charge.”  DEC asserts that, for Network Upgrades that are identified as needed to accommodate a request for change in service during the studies conducted under          sections 32.3 and 32.4 of the Joint OATT, the transmission customer will make monthly payments for actual project costs while the upgrades are under construction.[fn:34]  DEC explains that, once the upgrades have been placed into service, the transmission customer will receive a lump sum reimbursement of all costs advanced for Network Upgrades plus interest.  Proposed section 6.6.2 provides the terms and conditions under which the transmission provider will continue to construct Network Upgrades in the event of a billing dispute.[fn:35]  Moreover, DEC notes that proposed section 6.6.3 (Cost Recovery of Network Upgrades Once Placed In Service) provides that DEC will roll the costs of Network Upgrades into network transmission rates once those upgrades have been placed into service.  DEC states that the language was drafted broadly so that DEC could efficiently reimburse transmission customers as Network Upgrades are placed into service, including when the service request triggered several separate Network Upgrades.[fn:36]   \nSACE Protest\nSACE objects to DEC’s proposal to roll the costs of all Network Upgrades into transmission rates, which SACE claims could fail to insulate existing customers from the cost impacts of large load interconnections.[fn:37]  SACE argues that, although the language proposed in section 6.6 of Attachment A to DEC’s pro forma NITSA largely formalizes DEC’s traditional rate treatment for Network Upgrades, “current conditions caution against broad cost allocation in every case.”[fn:38]  Instead, SACE asserts that the Commission should maintain the flexibility to assess rate treatment for Network Upgrades on a case-by-case basis, at least for Network Upgrades caused by the addition of large loads.[fn:39]  SACE contends that, should DEC expand its transmission system in a “piecemeal manner”—that is, building Network Upgrades to accommodate individual large loads—and roll those costs into broadly applicable rates, existing customers’ rates will increase.[fn:40]  SACE asserts that existing customers should not have to pay for facilities from which they will not significantly benefit.  SACE states, moreover, that the Commission also cannot rely on state regulators to protect retail customers from                 large-load driven cost shifts because neither the North Carolina Utilities Commission nor the Public Service Commission of South Carolina has jurisdiction over DEC’s cooperative and municipal network customers. \nSACE avers that mandating rolled-in rate treatment in all cases is inappropriate because it undermines the Commission’s longstanding encouragement of transmission pricing flexibility.[fn:41]  SACE points to the Commission’s “or”/higher-of pricing policy as providing the flexibility to protect existing customers from unwarranted cost impacts.[fn:42]  SACE stresses that, while it is not advocating for any particular rate treatment of Network Upgrades in this proceeding, “the Commission should maintain optionality to pursue alternative cost recovery arrangements where doing so will protect existing customers from unduly bearing costs caused by large load” such as through incremental rates.[fn:43]    \nSACE also argues that codifying rolled-in rate treatment for all Network Upgrades into a pro forma service agreement undermines such pricing flexibility because it is difficult to file non-conforming agreements.[fn:44]  Relatedly, SACE states that DEC could bypass Commission review because transmission providers need not submit service agreements that track the pro forma language and such rolled-in Network Upgrades would only show up in DEC’s Electric Quarterly Reports.[fn:45]  SACE claims that accordingly, DEC’s network customers would have “no immediate recourse” and would lack the ability to timely scrutinize Network Upgrade cost recovery should they disagree with DEC that rolled-in rate treatment is appropriate in a given proceeding.[fn:46] \nAdditionally, SACE asserts that DEC does not connect the inclusion of the          rolled-in rate treatment provision with DEC’s other proposed changes to its pro forma NITSA that target the impacts of large load growth.[fn:47]  SACE argues that large load growth cautions against this uniform approach to rate treatment and notes that DEC’s peer OATTs do not appear to include similar provisions in their OATTs and pro forma NITSAs.  SACE avers that DEC’s citations to similar provisions in other individual NITSAs between DEC and network customers, which the Commission has had the opportunity to review, does not support including the rolled-in rate provision in the               pro forma NITSA.  SACE contends that DEC’s citation to 11 transmission service agreements between large load customers and transmission providers the Commission has approved is likewise unpersuasive because those agreements were bilateral contracts to which the Mobile-Sierra presumption applied, which requires a “showing of serious harm to the public interest to overcome.”[fn:48]  SACE states that, in contrast, the                Mobile-Sierra presumption does not apply to DEC’s proposed revisions to its pro forma NITSA because they are generally applicable terms and conditions.\nFinally, SACE contends that, given DEC’s proposal to also require Shortfall Payments (discussed below) for service requests of 100 MW or greater, the automatic application of rolled-in rate treatment could in reality be limited to those service requests, rather than all service requests.[fn:49]  SACE argues that this approach “would limit Commission scrutiny to those cases most likely to require significant network upgrades and create the potential for unjust and unreasonable cost shifts.”[fn:50]  SACE suggests that, to that end, the Commission could find that only Network Upgrades that are identified through a proactive regional transmission planning process warrant automatic rolled-in rate treatment.[fn:51]  According to SACE, this ensures that “only the costs of broadly beneficial projects are spread across the customer base, rather than piecemeal upgrades meant to serve individual loads.”[fn:52]\nDEC Answer\nDEC contends that SACE’s objection to rolling Network Upgrade costs into broadly applicable transmission rates rests on flawed premises.[fn:53]  DEC notes that the Commission has long held that network transmission facilities provide benefits to all users and that the costs of those facilities (i.e., Network Upgrades) should generally be rolled into the transmission rate base.[fn:54]  DEC asserts that accordingly, the language in section 6.6.3 of Attachment A simply restates its existing Commission-approved rate design and is consistent with Commission policy.  Further, because the formula rate itself is unaffected by DEC’s proposed revisions to its pro forma NITSA, DEC argues that SACE’s concern regarding rate recovery of Network Upgrade costs through DEC’s formula rates falls outside the scope of this FPA section 205 proceeding.[fn:55]   \nDEC also pushes back on SACE’s argument that the Commission must preserve incremental rates as an alternative cost-recovery option.[fn:56]  First, DEC notes that transmission providers, not transmission customers, have the burden to propose and justify cost recovery for Network Upgrades, including through incremental rates.  Second, DEC states that acceptance of its proposed pro forma NITSA would not diminish DEC’s ability to file a non-conforming NITSA should an alternative cost-recovery mechanism be needed to maintain just and reasonable rates.  DEC also asserts that SACE provides no evidence that continuing DEC’s practice of rolled-in rate treatment for Network Upgrades is unjust and reasonable.  DEC states that, moreover, SACE does not provide any examples of cases in which incremental rates have been assessed to network customers.[fn:57]  DEC states that instead, in the 32 years since the Commission’s Transmission Pricing Policy was established, the Commission has not approved incremental rates under any NITSA.[fn:58]\nCommission Determination\nWe find that DEC’s proposal to revise its pro forma NITSA to specify that it will roll into its rates for network transmission service the cost of Network Upgrades constructed to accommodate a NITS request, as reflected in section 6.6.3 of             Attachment A of its pro forma NITSA, as well as supporting language in other portions of section 6, is just and reasonable and not unduly discriminatory or preferential. \nFirst, as the Commission has repeatedly explained, Network Upgrades that are part of an integrated system benefit all system users.[fn:59]  This principle is reflected in the Joint OATT, which incorporates the Commission’s definition of Network Upgrades in the         pro forma OATT.[fn:60]  The Commission has, as a result, favored rolling the costs of network transmission facilities into rates for network transmission service as a default rate design,[fn:61] with some exception.[fn:62]  Accordingly, we find that DEC’s proposal to codify in the pro forma NITSA that the cost of Network Upgrades will be rolled into its transmission rates as the default comports with longstanding Commission policy. \nSecond, we disagree with SACE that proposed section 6.6.3 of Attachment A undermines the Commission’s policy on transmission pricing flexibility.  As DEC correctly states, the Transmission Pricing Policy Statement gives the transmission provider, not the transmission customer, the option to charge the higher of the embedded or incremental cost rate.[fn:63]  We are also unpersuaded by SACE’s related argument that DEC’s proposal is unjust and unreasonable because it would be difficult for DEC to justify a non-conforming NITSA that uses alternative pricing.  We agree with DEC that its proposed pro forma language does not diminish DEC’s ability to file a                           non-conforming NITSA should it determine that an alternative cost-recovery mechanism is necessary to maintain just and reasonable rates.  The Commission on a case-by-case basis “analyzes proposed deviations from pro forma agreements to ensure that operational or other reasons make the non-conforming provisions necessary” such as “to address specific reliability concerns, novel legal issues, or other unique factors.”[fn:64]  Accordingly, the Commission will consider non-conforming NITSAs that include an alternative cost-recovery mechanism such as an incremental rate.[fn:65]       \nThird, we note that, as is currently the case with respect to Network Upgrade cost challenges, transmission customers maintain the opportunity to challenge the recovery of Network Upgrade costs through DEC’s annual transmission formula rate update[fn:66] and to file an FPA section 206 complaint if they believe that the cost allocation for particular Network Upgrades or the formula rate protocols are unjust and unreasonable.[fn:67]  Neither avenue is affected by the fact that some Network Upgrades will be reflected initially in DEC’s EQRs.  Accordingly, we disagree with SACE that DEC’s proposed revisions negatively affect a network customer’s ability to challenge Network Upgrade costs included in the rolled-in rate. \nFourth, we disagree with SACE that DEC was required to tie the “invocation of rolled-in rate treatment in the pro forma NITSA to the large load growth that supports its other proposed changes.”[fn:68]  As discussed above, the Commission has a longstanding policy of allowing transmission providers to roll the costs of Network Upgrades into their transmission rates.  That policy does not change based on the size or scope of Network Upgrades constructed to fulfill a transmission customer’s request for network service.[fn:69]  \nFinally, we note that SACE’s concerns regarding retail cost allocation and rates pertaining to load additions are beyond the Commission’s jurisdiction.[fn:70]  \nShortfall Payments and Comparability of Terms \nFiling \nDEC states that, to minimize the potential cost and reliability impacts of large load service requests on other transmission customers, section II.5 of proposed Attachment F requires a Shortfall Payment for new or transferred Network Load of 100 MW or greater.[fn:71]  Under this provision, the network customer must pay a Committed Revenue Contribution equal to 75% of the MW value in the load schedule for each applicable month and year during the 15-year period following the in-service date of the Network Upgrades required to accommodate the load.  DEC states that, beginning on June 1 following the network customer’s commercial operation date and continuing each calendar year thereafter until the expiration of the 15-year term, DEC shall determine whether the transmission customer’s Actual Revenue Contribution equals or exceeds the Committed Revenue Contribution for the prior billing year.[fn:72]  DEC explains that, if the Actual Revenue Contribution does not equal or exceed the Committed Revenue Contribution for that calendar year, a “Customer Shortfall Event” is deemed to have occurred for that calendar year, and the customer would then have to make a Shortfall Payment to DEC’s transmission revenue requirement for each month and year the customer’s actual NITS falls short of the minimum, equivalent to the difference between the Actual Revenue Contribution and the Committed Revenue Contribution (Transmission Customer Shortfall Payment Obligation).[fn:73]  DEC states that the transmission customer shall pay the Shortfall Payment Obligation within 20 days of receipt of the invoice, which DEC explains is the standard payment period for bills relating to network transmission service.[fn:74]  DEC asserts that it chose the 100 MW threshold to distinguish large loads as presenting a higher risk of shifting costs to other customers if the load does not materialize.  DEC explains that this threshold targets load requests likely to significantly affect the bulk electric system and notes that “[it] has been successful with reliably integrating and serving such loads less than 100 MW on [its] system for decades.”[fn:75]  By setting the threshold at 100 MW or above, DEC states that it aims “to achieve timely, orderly, and non-discriminatory interconnection by avoiding unintended consequences of subjecting load that has traditionally been effectively integrated through existing processes.”[fn:76]  DEC states that this threshold also aligns with DEC’s retail agreements, which require increased customer protections for larger loads.\nDEC states that, to prevent double recovery of transmission facility costs, any payment made by a customer after a transmission customer Shortfall Event will be reflected in the transmission provider’s cost of service pursuant to Attachment H to the Joint OATT.[fn:77]  DEC states that rate treatment of such proceeds should be appropriately addressed in the annual formula rate update process.\nElectriCities Protest \nElectriCities objects to Duke’s proposed changes to network transmission service terms for customers seeking new or transferred loads of 100 MW or more.[fn:78]  While recognizing that Duke’s proposal addresses industry challenges related to rapid load growth and protects transmission customers against the costs of stranded Network Upgrades designed to facilitate large loads that do not materialize, ElectriCities claims that Duke has not shown that the terms imposed on network customers—such as the              100 MW threshold, 15-year minimum term, and revenue shortfall payments—are genuinely comparable to those applied to Duke’s own retail customers.  ElectriCities is concerned that a lack of comparability could give Duke an unfair competitive advantage and shift risk and costs to its network transmission customers. ElectriCities urges the Commission to require Duke to submit actual retail agreements or tariffs to demonstrate that its proposed terms for network customers are consistent with those for its retail customers, especially for large load additions.\nDEC Answer \nDEC emphasizes that, while it is committed to providing comparable transmission service to both wholesale and retail customers, the comparability standard does not require identical contract terms.[fn:79]  Instead, Duke argues that the standard—based on the FPA’s prohibition of undue discrimination—requires similar treatment only for entities that are similarly situated.  Because wholesale network transmission service customers and large load retail customers receiving bundled service are fundamentally different in their service offerings and associated risks, DEC argues that comparable but not identical terms are justified.  DEC agrees with ElectriCities that comparability is important, especially for new or transferred network loads greater than 100 MW for both wholesale and retail customers, and notes that its proposed revisions ensure that wholesale customers are subject to protection terms similar to those already required of retail large load customers.\nTo the argument that DEC has not submitted actual retail agreements or tariffs to demonstrate that its proposed terms for large load customers are consistent across wholesale and retail services, DEC responds that filing these agreements is unnecessary because all current retail tariffs, rate schedules, and service regulations are publicly accessible online.[fn:80] \nDEC states that it applies a 100 MW threshold to distinguish large loads for both wholesale and retail customers.[fn:81]  Additionally, DEC states that it requires a 15-year minimum contract term for both wholesale and retail customers with loads of 100 MW or greater.[fn:82]  DEC states that it requires both retail and wholesale customers with loads of 100 MW or greater to provide security for Network Upgrades, which can take the form of cash, letter of credit, or, for retail customers with corporate parents, parent guarantees.  DEC states that wholesale customers, typically municipalities and cooperatives, do not have parent entities that can offer such guarantees. \nAdditionally, DEC explains that both retail and wholesale customers whose loads are 100 MW or greater must pay a shortfall liability payment if their actual load falls below 75% of the forecasted amount.[fn:83]  DEC explains that for wholesale customers, this is based on whether they achieve 75% of their committed revenue contributions to transmission rates based on the amount of load they identified in their request for change in network service provided to the transmission provider.  For retail customers, the 75% threshold is based on whether they achieve 75% based on billing demand for retail service.  \nDEC argues that it has demonstrated that its proposed terms for large load customers are comparable across both wholesale and retail services, and therefore, the proposed pro forma NITSA terms are just, reasonable, and not unduly discriminatory or preferential. \nDeficiency Response\nThe Deficiency Letter asked DEC to confirm whether any portion of the Shortfall Payment made under Attachment F is also recovered through transmission rates under section 6.6.3 of Attachment A and to identify the tariff provision that prevents double recovery.[fn:84]  In response, DEC clarifies that it is not seeking to recover the amount of a Shortfall Payment from both (1) wholesale transmission customers paying wholesale transmission formula rates and (2) the individual NITS customer responsible for the shortfall payment.[fn:85]  DEC explains that section II.5 of Attachment F is structured to prevent double recovery by providing a direct charging mechanism via an invoice to be sent by the transmission provider to only the NITS customer responsible for the Shortfall Payment per the terms of its individual NITSA.  DEC explains that sections 5.1-5.5 of section II of Attachment F describe how the Shortfall Payment is calculated and invoiced, which is specific to the particular NITS customer, and not charged to transmission customers via formula rates.  Thus, DEC states that the Shortfall Payment would not be included in DEC’s wholesale transmission formula rates as an addition to the transmission revenue requirement because the Shortfall Payment would be charged to a particular NITS customer.\nThe Deficiency Letter also asked DEC, to the extent a Shortfall Payment is credited to formula rates, how and when it is reflected through Attachment H.[fn:86]  DEC asserts that any Shortfall Payment paid by the obligated NITS customer would be credited to FERC Account No. 456.[fn:87]  DEC explains that FERC Account No. 456 is a revenue account, not an expense account, and that within the transmission formula rate, balances in Account No. 456 are credited to and reduce the transmission revenue requirement, which benefits all OATT formula rate customers.  DEC explains that the formula rate update process occurs on an annual basis in May, using the prior calendar year FERC Form No. 1 data to populate the formula rate.  Thus, DEC states, a revenue credit for a Shortfall Payment will be reflected in the transmission formula rate that is based on FERC Form No. 1 for the year in which the Shortfall Payment occurred.  DEC states that, for example, if it receives a Shortfall Payment from a NITS customer in 2028, the payment will be recorded in FERC Account No. 456 and reported in DEC’s 2028 FERC Form No. 1.  The amount in Account No. 456 will then be incorporated into the wholesale formula rate during the 2029 Annual Update, impacting rates charged to customers from June 1, 2029 to May 31, 2030.\nDEC notes that it does not currently have any active or pending NITSA agreements with customers that include the shortfall liability provisions described in the proposed pro forma NITSA.[fn:88]  DEC contends that a shortfall liability situation can only occur if several specific steps take place:  (1) a DEC NITS customer proposes changes to NITS involving a load of 100 MW or greater; (2) DEC amends the current NITSA with such customer to fill out the bracketed information in Attachment F to the NITSA to include information about the shortfall liability provisions; (3) the revised NITSA becomes effective; (4) any Direct Assignment Facilities and Network Upgrades have been constructed if needed to accommodate such change in service request; (5) an annual assessment of a shortfall liability obligation has occurred; (6) DEC determines that a shortfall payment obligation exists; (7) DEC issues an invoice to the NITSA customer pursuant to the terms of Attachment F to the NITSA to charge the Shortfall Payment amount; and (8) DEC receives a payment from the customer of such amount.  Only after these steps, and once DEC issues an invoice and receives payment, would a Shortfall Payment be credited, the earliest of which can happen being 2027.  DEC maintains that the Shortfall Payment liability obligation is just and reasonable and supported by Commission precedent.  DEC states that, although the topic is outside the current filings, DEC’s pending transmission formula rate update will properly credit any Shortfall Payments.  DEC argues that addressing crediting in the formula rate does not make the obligation unjust or unreasonable, especially because multiple conditions must be met before DEC receives any Shortfall Payment.\nCommission Determination\nWe find that DEC’s proposed revisions requiring a network customer (with network loads 100 MW or greater) to pay a Shortfall Payment if actual NITS falls below 75% of the MW value of service in the load schedule for each month and year during the 15-year period following the in-service date of its Network Upgrades, are just and reasonable and not unduly discriminatory or preferential.  The purpose of the Shortfall Payment mechanism is to reduce the potential cost impacts of large load service requests on other DEC transmission customers if the Network Load does not materialize or otherwise takes less service than anticipated.  We also find that DEC’s proposed treatment of the Shortfall Payment does not result in double recovery of the same costs through two separate charging mechanisms.\nAs DEC explains in its Deficiency Response, proposed section II.5 of Attachment F provides a direct charging mechanism whereby DEC invoices only the specific NITS customer responsible for the Shortfall Payment, calculated and invoiced per the terms of that customer’s individualized NITSA.[fn:89]  This is distinct from and does not duplicate recovery of Network Upgrade costs through DEC’s wholesale transmission formula rate under Attachment H.  Specifically, DEC explains that any Shortfall Payment paid by the network customer will be credited to FERC Account No. 456, a revenue account, rather than an expense account, and that balances in Account No. 456 are in turn credited to the transmission revenue requirement within DEC’s transmission formula rate.[fn:90]  Accordingly, Shortfall Payments serve to reduce, rather than add to, DEC’s revenue collection through its transmission revenue requirement.  \nBased on the record before us, we also find that the 100 MW threshold is just and reasonable.  As discussed above, DEC explains that it has experience integrating loads smaller than 100 MW into the transmission system without issue and that loads of                100 MW present a greater risk of cost shifting should the load not materialize.\nIn addition, ElectriCities’ argument that DEC has failed to demonstrate comparability between the terms imposed on wholesale network customers and those imposed on its retail large-load customers misses the mark.  The Commission’s comparability standard prohibits undue discrimination by requiring that utilities provide the same transmission service to third-party customers as compared to the utilities’ own use of their systems.[fn:91]  Moreover, the Commission has held, and the D.C. Circuit agrees, that the comparability principle does not require comparable pricing between unbundled wholesale and bundled retail transmission service.[fn:92]  Accordingly, DEC is required to provide non-discriminatory service to all of its wholesale transmission customers.  The Commission lacks jurisdiction over retail customers, and we therefore dismiss ElectriCities’ argument.[fn:93]  \nFor the same reason, we disagree with ElectriCities that DEC was required to file non-jurisdictional retail agreements or tariff sheets to substantiate the comparison.\nSecurity Requirements\nFiling\nDEC proposes new section 6.4 (Security) to Attachment A.  It states: \nAs per Section 32.4 of Tariff which provides that Transmission Customer shall provide the Transmission Provider with security (a letter of credit or cash) “equivalent to the costs of new facilities or upgrades consistent with commercial practices as established by the Uniform Commercial Code” if new facilities or upgrades are required to accommodate a change in service request.  Transmission Customer shall comply at all times relevant under this Service Agreement with the “Duke Energy Credit Risk Management Policy to Implement Security Required Pursuant to               Section 32.4 of the Joint OATT” which is posted on Transmission Provider’s OASIS website.[fn:94]\nDEC states that section 6.4 is intended to prevent uncured payment defaults that could unfairly shift the costs of Network Upgrades constructed to accommodate a transmission customer’s change in service request to other transmission customers.[fn:95]  DEC states that such a cost shift would be “an inequitable, unfair, and lopsided outcome in which customers that did not request a change in network service are left to pay unpaid bills of a network customer that was the initiator of a change in network service.”[fn:96]  DEC notes that the language incorporates existing language from section 32.4 of the Joint OATT and explains that the Credit Policy “provides technical details about types, issues, and forms of security” that would be acceptable.[fn:97]\nRelatedly, proposed section 6.6.3 states that DEC will release any security provided by the transmission customer within 90 days of the relevant Network Upgrades being placed into service.[fn:98]  Proposed section 6.7 states that, pursuant to section 31.5 of the Joint OATT, transmission customers will not be relieved of paying for Network Upgrades that are constructed should a transmission customer cancel or delay its requested change in NITS.[fn:99]  DEC states that, as the language in section 6.7 has been part of the Commission’s pro forma OATT and incorporated in the Joint OATT since 2012, DEC now proposes to include this language in its pro forma NITSA for greater transparency.[fn:100]  \nElectriCities Protest\n\tElectriCities claims that DEC’s proposed new language in section 6.4 of Attachment A to its pro forma NITSA regarding providing security for Network Upgrades is inconsistent with section 32.4 of the Joint OATT.[fn:101]  Specifically, ElectriCities takes issue with the language indicating that network customers “shall comply at all times relevant under this Service Agreement with ‘Duke Energy Credit Risk Management Policy to Implement Security Required Pursuant to Section 32.4 of the Joint OATT’ which is posted on Transmission Provider’s OASIS website.”[fn:102]  ElectriCities argues that, by incorporating by reference the Credit Policy into DEC’s    pro forma NITSA, section 6.4 imposes a new requirement that departs from and is not superior to the existing requirement in section 32.4 of the OATT.  While acknowledging that the Credit Policy is available on DEC’s OASIS, ElectriCities asserts that this new condition imposes unstated consequences should a transmission customer fail to comply with the policy.[fn:103]  ElectriCities states that, accordingly, it is not just and reasonable for DEC to incorporate by reference the Credit Policy into its pro forma NITSA when that policy has not been included in the Joint OATT and filed with the Commission, and the offending sentence should be removed from section 6.4.  ElectriCities adds that incorporating the new requirement in DEC’s pro forma NITSA would allow DEC to change its credit policy without providing a meaningful opportunity for a network customer “to challenge the effects of such a change on its ability to continue to qualify for service.”[fn:104]\n\tMoreover, ElectriCities notes that section 6.4 lacks the $10 million threshold for triggering a transmission customer’s obligation to post security for Network Upgrades that appears in the Credit Policy.[fn:105]  ElectriCities asserts that DEC’s reference to the Credit Policy in proposed section 6.4 does not cure this inconsistency and that proposed section 6.4 should instead reference section 32.4 of the Joint OATT.\nDEC Answer\n\tDEC argues that it is not imposing a new condition on transmission customers, as the requirement that network customers provide security has existed since the inception of the Commission’s pro forma OATT in 1996, which DEC adopted without modification in the Joint OATT.[fn:106]  DEC explains that the Credit Policy details the types of security other than a letter of credit that network customers may provide.  DEC also asserts that, contrary to ElectriCities’ contention, the Credit Policy need not be part of the Joint OATT.  DEC avers that Order No. 890 established that transmission providers must “post on their public websites all rules, standards, and practices that relate to transmission service and provide a link to those rules, standards, and practices on OASIS.”[fn:107]  DEC adds that Order No. 890 explicitly contemplated that security requirements would be posted on OASIS and, therefore, DEC need not include the Credit Policy in the Joint OATT.[fn:108]\n\tDEC also disagrees with ElectriCities’ contention that section 32.4 of the Joint OATT does not support the language in section 6.4 of Attachment A stating that the network customer “shall comply at all times relevant under this Service Agreement” with the Credit Policy and that network customers could face “unstated consequences” for failure to so comply.[fn:109]  In particular, DEC argues that the risk that a transmission customer does not pay for Network Upgrades under section 32.4 of the Joint OATT exists from the time the customer executes a NITSA until such upgrades are constructed and placed into service.[fn:110]  DEC asserts that, accordingly, section 6.4 of Attachment A’s requirement that the transmission customer maintain security “at all times relevant” under the NITSA is necessary to prevent non-payment.  DEC states that this approach comports with the Commission’s intention in Order No. 890 that the transmission customer, and not the transmission provider, would bear this risk.[fn:111]  DEC also points to the Commission’s preliminary findings in recent orders that transmission cost recovery agreements should require Eligible Customers to provide security sufficient to cover the obligations of any Network Upgrades constructed as part of a request for transmission service on behalf of a large load.[fn:112]\n\tIn response to ElectriCities’ argument that transmission customers would have no meaningful way to challenge the effects of future changes to the Credit Policy, DEC contends that its approach complies with Commission’s requirement that transmission providers post on their websites and OASIS the method by which they will amend their business practices, including credit requirements.[fn:113]  DEC notes that it has done so, and that its policy provides that “changes will be posted at least two weeks in advance of a change, which will provide customers a chance to prepare for the change and to provide feedback to DEC if they have questions or concerns about the changes.”[fn:114]  DEC argues that, as a result and contrary to ElectriCities’ claim, transmission customers will have advanced notice on the opportunity to provide feedback to any changes DEC may make to its Credit Policy.[fn:115]  \nCommission Determination\n\tWe find that the proposed security provision in section 6.4 of Attachment A to DEC’s pro forma NITSA is just and reasonable and not unduly discriminatory or preferential.  We agree with DEC that the language does not create a new requirement.  Instead, section 6.4 merely reiterates network customers’ existing obligation under the Joint OATT to provide acceptable forms of security for Network Upgrades stemming from a new service request.  Section 6.4’s reference to the Credit Policy, meanwhile, points transmission customers to DEC’s existing business practices, which detail how and in what form customers may provide security, among other things.[fn:116]  We also find that DEC complies with the Commission’s requirements under Order No. 890 to provide its credit policy on OASIS, as well as sufficient explanation for how transmission customers can provide feedback on future changes to the Credit Policy.[fn:117]  Moreover, we agree with DEC that it is reasonable to require transmission customers to provide security for Network Upgrades identified in a service request until those upgrades have been placed into service.  This approach aligns with the Commission’s adoption of Attachment L to the pro forma OATT in Order No. 890.[fn:118]\n\tMoreover, we find ElectriCities’ suggestion that DEC’s inclusion of the Credit Policy by reference in section 6.4 of its pro forma NITSA imposes a new requirement that departs from the existing requirement in section 32.4 of the Joint OATT to be immaterial.  As DEC states, section 6.4 simply notes transmission customers’ general obligation to provide security equivalent to the cost of Network Upgrades, which is an existing requirement under the Joint OATT.[fn:119]      \nAudits\nFiling\t\nDEC proposes to update sections 9.1 and 9.2 of its pro forma NITSA to expand the period that parties have to audit their bills from one calendar year to 18 months, allowing customers broader rights to inspect and audit billing records.[fn:120]  Additionally, DEC revises subsection 9.3 to eliminate following language: \nWith the exception of quantifiable changes in the amounts of the billings, the audit report, supporting materials, and all other audit results of all such audits shall be kept confidential by the Parties and shall not be released to any other party without the express written consent of the other Party except that in the event that a matter subject to audit becomes the subject of dispute resolution or litigation in any forum with jurisdiction, a Party may disclose to the decision maker the audit report, supporting materials, other audit results of all such audits, and any related information, provided that the other Party is afforded notice and an opportunity to request that such information be protected against disclosure to third parties.\nDEC states that the proposed change removes the obligation to provide a     decision-maker in a litigation matter with an audit report of a billing issue, favoring instead the existing language in the section that provides greater confidentiality of an audit report not to be released to any third party without the written consent of the other party to the NITSA.[fn:121]\nElectriCities Protest\nElectriCities objects to DEC’s proposal to remove the clause in section 9.3 in the body of its pro forma NITSA related to audit rights.[fn:122]  ElectriCities argues that removing the clause is not just and reasonable because it could prevent DEC’s customers from being able to disclose DEC’s record and books to an adjudicatory body (including the Commission) should the parties be unable to resolve a billing dispute.  ElectriCities contends that the current language in section 9.3 properly balances the Commission’s interest in obtaining billing information to resolve disputes between DEC and its network customers with DEC’s interest in protecting commercially sensitive information from competitors.  \nDEC Answer\nDEC states that audits of the parties’ financial accounts and records with respect to transmission billing contain confidential and proprietary financial information that may include:  (1) customer name, contact information, and account number; (2) historical and current records of the amount of transmission usage by the customer; (3) historical and current records of the amount of transmission usage by customer per point of delivery; (4) historical and current records of the amount of transmission usage by customer’s members (if customer is a cooperative); (5) historical and current records of payments for transmission service; (6) transmission pricing information, including detailed breakdowns of components of transmission pricing; and (7) transmission billing information including bank account information.[fn:123]  DEC argues that audit rights are two-way rights applicable to both the transmission provider and the transmission customer and that it is appropriate that the party whose highly confidential financial and billing information is to be disclosed to a third party be requested to consent to such disclosure.   \nCommission Determination\nWe find that the proposed revisions to section 9.1 and section 9.2 of DEC’s             pro forma NITSA to expand the period that parties have to audit their bills from one calendar year to 18 months and the proposed deletions in section 9.3 to remove the obligation to provide a decision-maker in a litigation matter with an audit report of a billing issue without the written consent of the other party to the NITSA are just and reasonable.  We agree with DEC that is reasonable an audit report containing confidential financial and billing information should not be released to any third party without the written consent of the other party to the NITSA.  We are not persuaded by ElectriCities’ argument that removing the carve out for matters sent to an adjudicatory body is unjust and unreasonable.  We also find that the proposed deletion in section 9.3 does not foreclose disclosure of an audit report to the Commission for review.[fn:124] \nOther Changes to the Pro Forma NITSA\nFiling\nBody of the Pro Forma NITSA\nDEC proposes several changes to the body of the pro forma NITSA that are largely administrative.  Specifically, DEC proposes to replace placeholder fields for agreement numbers, customer names, and dates to facilitate customization and remove rollover rights provisions as duplicative of the Joint OATT and Order No. 890.[fn:125]  In section 10.0 (Delivery Points), DEC proposes to clarify the transmission customer’s construction obligation and include a requirement for planning load ramp schedules.  Proposed section 12.0 would add breach, cure, and default provisions, consistent with generator interconnection agreements under Order Nos. 2023 and 2023-A.  DEC also proposes to delete outdated Rural Utilities Service approval requirements, modernize reference to sections 205 and 206 of the FPA, and revise the signature page to ensure accurate identification of parties and signatories.  \nAttachment A – (Specifications for Network Integration Transmission Service)\n\tIn section 2.0 (Description of Capacity and/or Energy to be Transmitted by Transmission Provider Across the Transmission Provider’s Transmission System (including electric control area in which the transaction originates)), DEC proposes to clarify that capacity and energy resources are delivered to the transmission customer’s delivery points from the transmission provider’s transmission system, rather than simply to the transmission provider’s transmission system and that, where appropriate, distribution facilities may serve delivery points.[fn:126] \n\tIn section 3.0 (Resources), DEC proposes to add bracketed placeholders for the network customer’s designated network resources, distinguishing between owned generation and contracts.  DEC argues that this change is necessary because listing the customer’s owned generation and contracts in individual NITSAs should not be considered non-conforming.[fn:127]  \n\tIn section 6.7 (Request for Change in Service), DEC proposes to clarify that customers remain responsible for the costs of transmission facilities constructed by the transmission provider even if a requested change in service is cancelled or delayed.[fn:128]  DEC states that this language has been part of its Commission accepted pro forma tariff and incorporated in the Joint OATT since 2012. \n\tIn section 6.9 (Ancillary Services Charge), DEC proposes to clarify how a transmission customer may satisfy its obligations under Schedule 2 and Schedule 3 and notes that services under Schedules 4, 5, and 6 may be provided by the transmission provider, with charges outlined in the Joint OATT.[fn:129]\n\tIn section 6.13 (Distribution Rates), DEC proposes to revise the section title, remove the references to a nonexistent NITSA attachment, and correct an erroneous reference to a nonexistent NITSA attachment.[fn:130]  Finally, DEC proposes to add      section 7.0 to permit customers to move their load to another control area if desired.[fn:131]  \nAttachment B – (Delivery Points)\nDEC proposes to add bracketed placeholders for delivery point number and names and to remove the Delivery Point Data Sheet from its pro forma NITSA, in favor of posting it on the publicly available portion of its OASIS website.[fn:132]  DEC states that this will improve accessibility and allows the form to be updated without amending its        pro forma NITSA through the regulatory process. \nAttachment C – (Transmission and Distribution Rates)\nDEC proposes to revise the title of the attachment to add “Transmission” to reflect the reality that certain delivery points may be served by transmission or distribution facilities.[fn:133]  DEC also proposes to duplicate the distribution rates formula to create an analogous transmission-rate formula for delivery points.  DEC proposes new language that provides that a transmission customer or provider may terminate a delivery point and provides terms and conditions for the termination, including application of the loss due to early retirement calculations.[fn:134]  DEC also proposes to revise the table of delivery locations to use bracketed placeholders for customer-specific data, which DEC asserts should not render individual NITSAs with customers to be non-conforming.  Finally, DEC proposes changes to correct internal references and remove embedded images that do not comply with eTariff standards.  \nAttachment D – (Network Operating Agreement)\nDEC proposes to delete the existing Attachment D (Power Factor Penalty) and replace it with a section titled “Network Operating Agreement.”[fn:135]  DEC explains that it has proposed to delete Attachment D because:  (1) the power factor requirements applicable to a transmission customer are referenced in the Network Operating Agreement; and (2) DEC wishes to incentive customers to comply with the power factor requirements rather than charging a monetary penalty for non-compliance, which is not helpful from a system reliability or operational perspective.\nDEC proposes various revisions throughout revised Attachment D to correct terminology and update internal references.[fn:136]  DEC also proposes to revise section 3 (Network Operating Committee Agreements) to require approval of decisions and agreements made by the Network Operating Committee to be evidenced by each party to the committee instead of by each member of the committee, which DEC asserts reduces administrative burden, while ensuring each party’s consent.    \nDEC proposes several revisions to section 5 (Metering) to update definitions and reflect current operational realities of metering arrangements, including inserting bracketed optionality to specify which party (transmission provider or transmission customer) is responsible for the purchase, installation, operation, maintenance, repair, and replacement of metering equipment.[fn:137]  DEC asserts that this change acknowledges the current reality that either the transmission customer or transmission provider can fulfill those responsibilities.    \nDEC proposes to similarly revise section 6 (Control Area and Data Equipment) to reflect the operational reality of construction, installation, and operation of control area and data equipment, correct cross-references, and update defined terms.[fn:138]  In section 6 subsection b, DEC proposes to insert bracketed optionality denoting that either the transmission customer or transmission provider shall install data acquisition equipment.  DEC states that the option to select the proper entity and remove the non-applicable entity in individual NITSAs with customers should not render those NITSAs as                         non-conforming.[fn:139]  DEC proposes new subsections d, e, and f in section 6 to set forth terms and conditions relating to dynamic scheduling arrangements.  DEC explains that such arrangements have become more prevalent on the DEC system, and the existing Network Operating Agreement does not have adequate or specific terms and conditions to address such arrangements.  \nDEC proposes to revise section 7 (Operating Requirements) to acknowledge situations in which the transmission customer may not be operator of its resources but can cause an operator to operate its resources in a manner compliant with the agreement.[fn:140]  Further, DEC proposes changes to:  (1) include consideration of underfrequency relay systems; (2) include NERC and SERC requirements in addition to Good Utility Practice as the standards by which the transmission provider may reasonably modify the load shedding system; and (3) clarify that the parties, upon request, will provide each other with copies of NERC compliance reports.[fn:141]\nIn section 9.0 (Network Planning), DEC proposes to revise the first sentence to insert the word “annually” to underscore the annual nature of the obligation of the transmission customer to provide the transmission provider with a current and 10-year projection of network loads and resources by September 1st of each year.[fn:142]  In               section 11.0, DEC proposes to clarify that the transmission customer is responsible for making arrangements for the scheduling and delivery of the electric capacity and energy from the designated Network Resource within the transmission customer’s Control Area to the transmission provider Control Area, and any other neighboring transmission provider’s Control Area. \nDEC proposes the addition of a new section 12 (Power Factor Requirements) to state that, in compliance with Section 24.3 of the Joint OATT, the transmission customer shall comply with the power factor requirements set forth in section 5.3.1(a) of the transmission provider’s Facilities Connection Requirement document posted on its OASIS website.[fn:143]  \nAttachment E – (Other Charges/Credits)\nDEC proposes to add a new Attachment E with a placeholder in brackets to insert any other charges or credits not already referenced in its pro forma NITSA.[fn:144]  DEC states that many of the NITSAs do not contain any other charges or credits listed in this attachment.  DEC notes that the Commission reviews such charges and credits as part of the filing of individual NITSAs containing such charges. \nCommission Determination\nWe find that the proposed changes to Attachment A of DEC’s pro forma NITSA are just and reasonable because they more accurately reflect how network service operates and will allow DEC to conduct studies to meet its responsibility, as the transmission provider, to ensure continued reliability of the transmission system.\nWe further find that the proposed revisions to Attachments B, C, D, and E of DEC’s pro forma NITSA are just and reasonable.  The proposed revisions address the impact of changing system conditions on DEC’s provision of NITS and provide greater clarity for DEC’s network customers.\nWe note, however, that although we find DEC’s proposed revisions to its                   pro forma NITSA are just and reasonable and not unduly discriminatory or preferential based on the record in this proceeding, DEC may still (and we encourage it to) at any time either execute non-conforming NITSAs that provide greater protection against cost shifting to other DEC transmission customers, or propose additional consumer protections to this pro forma NITSA.  The Commission’s longstanding transmission pricing policy provides flexibility for transmission providers to seek the higher of either rolled-in or incremental pricing for transmission service requests that necessitate expansion of the transmission system.[fn:145]  Should DEC determine that a new or expanded request for transmission service would trigger substantial upgrades that could raise costs for other transmission customers, it should strongly consider filing a non-conforming agreement to charge an incremental rate.  In such a case, DEC also would have an opportunity to explain in support of its filing why, under that specific set of facts and circumstances, deviating from the pro forma we accept in this order is necessary to protect its existing customers.[fn:146] \nAlong the same lines, we encourage DEC and other transmission providers to continue to consider where they can erect further protections against the potential for cost shifting among transmission customers.  These measures may include proposing substantial shortfall payments, such as the shortfall payment structure approved in this order, which are designed to ensure that transmission customers make a meaningful contribution to the costs of building out the transmission system to serve them, even if the new Network Load does not materialize or otherwise takes less service than anticipated.[fn:147]  Other measures may include greater deployment of alternative transmission technologies and grid enhancing technologies, both to use the existing transmission system as efficiently as possible and to right-size any further transmission system expansion.\nLastly, we note that, because DEC’s proposal came to us under FPA section 205, the Commission is statutorily bound to a reactive role in assessing the proposal.[fn:148]  To be clear, however, our approval today in no way prejudges the outcomes of the June 2026 Large Load Show Cause Order proceedings under FPA section 206,[fn:149] nor the ANOPR proceeding in Docket No. RM26-4-000, which remains open.[fn:150]\nWe recognize that building out the transmission system to serve the nation’s growing demand for electricity can require substantial financial investment.  We encourage transmission providers—including DEC—to continually reevaluate their study processes and transmission service agreements to ensure both that they are minimizing the costs of Network Upgrades required and that they have sufficient protections in place to shield other transmission customers from potential cost shifts as new technologies and trends in load growth emerge.\nThe Commission orders:\nDEC’s proposed revisions to the pro forma NITSA are hereby accepted, effective August 1, 2026, as requested, as discussed in the body of this order.\nBy the Commission.  Commissioner Rosner is concurring with a separate statement \n\t\t\t  attached.\n\t\t\t  Commissioner See is concurring with a separate statement \n\t\t\t  attached.\n\t\t\t  Commissioner Chang is dissenting with a separate statement\n \t\t\t  attached.\n\n( S E A L )\n\n\nDebbie-Anne A. Reese,\nSecretary.\n\n\n\n\nAppendix A – eTariff Records\nDuke Energy Carolinas, LLC, Tariffs, Rate Schedules and Service Agreements, Attachment F-2, Service Agreement for NITS (DEC Zone) (8.0.0). \n\nUNITED STATES OF AMERICA\nFEDERAL ENERGY REGULATORY COMMISSION\n\nDuke Energy Carolinas, LLC\nDocket No.\nER26-2691-000\nER26-2691-001\n\n\n(Issued October 9, 2026)\n\nROSNER, Commissioner, concurring: \n\nI concur in today’s order and I write separately to highlight two truths.  \nFirst, Duke’s existing tariff includes zero protections safeguarding residential consumers and small businesses from bearing the costs of transmission for new large loads such as data centers.  Duke’s proposal offers meaningful, if imperfect, new protections, and for that reason the Commission is right to accept it.  Given the pace of data center development, we cannot afford to tinker with and reject iterative FPA section 205 filings for months or years while regular people remain unprotected.  \nSecond, this filing highlights a broader problem: consumer protections are inadequate across the country.  The risks that remain under the filing we accept today make clear that there is more work to do.  To the extent state regulatory actions are not sufficient to protect consumers, the Commission has an obligation to seriously consider expanding the cost recovery framework it established in the Large Load Show Cause Orders.[fn:151]  The Department of Energy’s ANOPR remains pending and provides an opportunity to consider a more uniform approach.[fn:152]  And, as always, if the Commission initiates a proceeding under FPA section 206, the Commission will correct any currently effective rates that it finds no longer just and reasonable.  In the meantime, we must put initial safeguards in place without delay. \n\nFor these reasons, I respectfully concur.\n________________________\nDavid Rosner\nCommissioner\nUNITED STATES OF AMERICA\nFEDERAL ENERGY REGULATORY COMMISSION\n\nDuke Energy Carolinas, LLC\nDocket No.\nER26-2691-000\nER26-2691-001\n\n\n(Issued October 9, 2026)\n\nSEE, Commissioner, concurring: \n\nToday’s order involves one of the most pressing cost allocation issues we face: how to ensure large load pays its way and that residential and small business customers aren’t saddled with stranded costs if those loads don’t materialize, don’t take service at the expected level, or exit prematurely.  I concur in today’s order because the safeguards Duke Energy Carolinas, LLC (DEC) memorializes in its pro forma Network Integration Transmission Service Agreement fall within the range of just and reasonable.  Though not perfect, they will help protect existing customers from the impacts of large loads—and they are better than the status quo’s alternative that leaves those customers wholly exposed.  I write separately to urge DEC to continue looking out for existing customers’ interests as it applies (and potentially further modifies) this policy in the months and years ahead.\nThe electric industry is in the midst of transformative change, and our regulatory framework must keep pace.  Meeting growing demand, including from large loads, requires substantial investment in the grid.  But as we build the infrastructure needed to serve growing demand, we must ensure that the customers driving new costs bear appropriate responsibility for them.  \nLong-familiar transmission pricing policies, including rolled-in rates, may be a viable tool to help achieve that goal by requiring large loads to pay for a significant share of system upgrades.  They do not, however, address what happens when anticipated demand from large loads fails to materialize or grows more slowly than expected.  So we need strong and tailored protections to ensure that existing ratepayers are not left paying for investments built for someone else.\nDEC’s proposal helps address that risk: the Committed Revenue Contribution mechanism will ensure that the transmission customer serving large loads pays for at least 75% of the planned load amount for 15 years, even if the actual load ends up being lower.[fn:153]  To my mind, this proposal is an incremental improvement, not a slam dunk.  For example, a Committed Revenue Contribution of 75% may be near the low end of what’s just and reasonable to protect other customers.  DEC also could have further strengthened its approach by requiring transmission customers serving large loads to back up their payment obligations with financial security at a large load-worthy scale.  That additional step would ensure that if the transmission customer serving large loads goes bankrupt, other ratepayers will not be stuck paying for grid upgrades they did not cause.\nBut here is where our standard of review matters.  To date, the Commission has taken up questions like these in the context of Mobile-Sierra protected agreements, where we presume they pass legal muster absent evidence they “seriously harm the public interest.”[fn:154]  DEC’s proposal for today came to us under FPA section 205—which allows more searching review, but still keeps the Commission statutorily bound to a reactive role in assessing if DEC hit the just-and-reasonable zone.[fn:155]  And in that section 205 posture, I believe DEC satisfied the statutory standard with its improvement over the status quo and its 75 percent-floor, 15-year assurances.  (To be clear, incremental gains may not be enough in a section 206 posture where the Commission affirmatively sets a replacement rate.  So today’s decision in no way prejudges acceptable outcomes in the June 2026 Large Load Show Cause Order proceedings.[fn:156])  \nImplicit in recognizing a zone of potential solutions is the idea that no one-size-fits-all answer likely exists when it comes to the “right” customer protection measures.  Even so, just and reasonable rates require a meaningful commitment from the large load customer (often through the transmission customer serving them) to mitigate stranded asset risks.  And though today’s proposal does that, there’s more DEC can and should do to protect all of its customers as it applies the new policy case-by-case. \nFor one, as the order recognizes, DEC should avail itself of the flexibility our transmission pricing policy affords.  Today we accept DEC’s proposal to codify rolled-in rate treatment as the default for large load-driven network upgrades because it is consistent with our current transmission pricing policy, which gives transmission providers the option to charge either rolled-in rates or, if higher, the incremental rate.  But I urge DEC to remain watchful.  A primary goal of our “higher of” policy is to allow transmission providers to charge the higher incremental rate when doing so would hold native load customers harmless from system expansion costs.[fn:157]  There may well be circumstances where large load requests drive significant network upgrade costs well beyond the norm, and rolling those costs into the rate everyone pays would raise rates for existing customers.  In those cases, DEC’s ratepayers would be better served by DEC filing a non-conforming agreement to charge an incremental rate, with a supporting record explaining why deviating from the pro forma we accept today is necessary to protect its existing customers in that specific case.[fn:158]  Doing so would not only put to proper use the flexibility in current Commission policy to protect customers, but also better uphold the commitments Duke made when it signed the Ratepayer Protection Pledge to keep large load costs with large load customers.[fn:159]\nAdditionally, as the Commission explained in the Show Cause Orders (and as I highlighted in my separate statements[fn:160]), we can have more confidence that rolled-in rate treatment works for existing ratepayers if transmission providers are vigilant about using the most cost-effective options for upgrading the grid.  There, we preliminarily required transmission owners in RTO and ISO regions to evaluate whether Alternative Transmission Technologies can meet system upgrade needs driven by large loads, and to demonstrate why traditional upgrades are preferable if they choose not to go with ATTs in whole or in part.[fn:161]  DEC is not currently subject to that obligation, but I strongly urge them to take on the customer-forward charge regardless.  Building out the grid our country needs is necessarily expensive.  Making cost-conscious and accountable choices about the type of upgrades to meet new loads’ needs could not matter more.\nI appreciate the initial steps DEC has taken in this filing to protect existing customers from the cost implications as large loads continue entering the system.  Also true: that work remains ongoing, including every time it applies these protections in practice. \n\nFor these reasons, I respectfully concur.\n\n\n\n______________________________\nLindsay S. See\nCommissioner\nUNITED STATES OF AMERICA\nFEDERAL ENERGY REGULATORY COMMISSION\n\nDuke Energy Carolinas, LLC\nDocket Nos.\nER26-2691-000\nER26-2691-001\n\n\n(Issued October 9, 2026)\n\nCHANG, Commissioner, dissenting: \n\nIn today’s order, the Commission accepts Duke Energy Carolinas, LLC’s (DEC) proposed revisions to its pro forma Network Integration Transmission Service Agreement (NITSA)) to address increased network load growth and changing network resources, including an influx of large loads.  I dissent because DEC has not demonstrated that its Committed Revenue Contribution proposal adequately protects existing customers and is thus just and reasonable.  I also write separately because DEC’s filing highlights broader concerns regarding (1) the cost impact of Network Upgrades built to serve new large loads on other customers and (2) transparency around those cost impacts, both of which are critical to protecting existing customers from undue cost shifts.\nBackground\nIn response to changes it has observed in requests for network transmission service, DEC proposes a suite of reforms to update the rates, terms, and conditions reflected in its pro forma NITSA.  Among these changes, DEC proposes a set of specific reforms targeted at transmission service requests that are 100 MW or greater.  \nAs relevant here, DEC proposes a customer protection framework that: (1) establishes a 15-year transmission service obligation, based on a specified ramp schedule for the load serving entity (LSE) serving the new large load; and (2) requires that LSE to  commit to pay a minimum amount equal to 75% of the MW value in the load schedule for each month and year during that 15 year period, called the “Committed Revenue Contribution,” to be assessed as a shortfall payment if the LSE fails to meet those ramp schedule and revenue contributions.  Shortfall payments are credited against the transmission service revenue requirement borne by all of DEC’s transmission customers through its transmission formula rates.  \nDEC also proposes to codify, in its pro forma NITSA, that costs of network upgrades for all transmission service requests – including those driven by large loads – will be rolled into transmission rates once those upgrades enter into service.  Furthermore, because DEC will rely on pro forma NITSAs, individual agreements will be reported to the Commission via its Electronic Quarterly Report (EQR) process unless a specific agreement is contested or does not conform to the pro forma NITSA.  As a result, the content of those agreements, including the Network Upgrades and associated costs, will not generally be filed at the Commission for review and public disclosure.\nDEC Has Not Demonstrated that Its Committed Revenue Contribution Proposal Adequately Protects Customers Against the Risk of Cost Shifts\nDEC bears the burden of establishing that its proposal – which (among other revisions) modifies its pro forma NITSA to create new rates, terms, and conditions of service for a specific class of transmission customers that take network service on behalf of large loads – is just and reasonable and not unduly discriminatory or preferential.  As discussed below, I do not believe DEC has carried that burden on the record before us, and I would reject DEC’s filing with guidance to improve or better support a refiled proposal.  \nDEC’s Committed Revenue Contribution Proposal Does Not Include Sufficient Security Requirements to Protect Customers Against the Risk of Cost Shifts\nAs discussed below, DEC proposes to require long-term financial commitments from LSEs that serve large loads.  Directionally, DEC’s proposal is positive.  However, I would reject DEC’s proposal with guidance because it fails to include meaningful security requirements to backstop those long-term financial commitments and thus fails to adequately mitigate cost shifting risks.  \nDEC’s proposed Committed Revenue Contribution framework requires LSEs serving new large loads to commit to paying at least 75% of a defined level of transmission service for 15 years, or to pay a shortfall payment if their actual NITS contribution falls below that minimum level.[fn:162]  This arrangement essentially establishes a long-term take-or-pay arrangement with LSEs serving loads that exceed 100 MW, paid by LSEs through either transmission service or shortfall charges.  I conceptually support this kind of long-term payment obligation construct, which, if properly designed, can protect other transmission customers against the risk of cost shifting, particularly if large loads do not materialize as planned or terminate their service earlier than anticipated.[fn:163]\nHowever, not all long-term payment commitments are created equal, and the Commission has an obligation to assess, as part of its mandate to ensure just and reasonable rates, whether an FPA section 205 proposal adequately protects other customers.[fn:164]  Here, DEC’s stated purpose for its Committed Revenue Contribution proposal (including the associated shortfall payment obligation) is to protect existing transmission customers against potential impacts from cost shifts for network upgrades needed to accommodate new large load additions.[fn:165]  DEC’s filing acknowledges that large loads present a higher risk of shifting costs to other customers if the load does not materialize; indeed, that risk is the basis for the additional obligations being imposed on specific LSEs, including the Committed Revenue Contribution and associated shortfall payment requirements.[fn:166]  \nDEC’s stated goal is laudable, but I am not persuaded on this record that the proposal meets it.  DEC proposes to impose substantial 15-year payment obligations on specific LSEs that serve large loads, but proposes no specific security requirements to backstop those obligations.  Instead, it appears that DEC relies on the generally-applicable security provisions included in its pro forma NITSA, resulting in potential security obligations underpinning a 15-year revenue commitment on the order of a month of transmission revenues, or perhaps at most five months.[fn:167]  If an LSE defaulted and could no longer pay an amount greater or equal to its Committed Revenue Contribution, then there would be limited, if any, security to backstop its payment obligations, and other transmission customers would be left paying the bill.[fn:168]  DEC thus introduces a significant disconnect between the duration and magnitude of the Committed Revenue Contribution payment obligation and the actual security that underpins it, which in turn exposes other transmission customers to the cost shifting risk this proposal is ostensibly designed to mitigate.[fn:169]  \nAccordingly, while DEC’s Committed Revenue Contribution proposal is a step in the right direction, I do not believe DEC has demonstrated that it is just and reasonable.  DEC need not require security for 100% of the associated obligation, but some greater alignment between the payment obligations and security underpinning them is warranted.  As a result, instead of accepting this proposal, I would have rejected DEC’s filing with guidance to develop supplemental security requirements for transmission customers that are subject to DEC’s Committed Revenue Contribution construct.   \nDEC Does Not Adequately Support the Size of the Committed Revenue Contribution\nAs discussed above, DEC’s proposed Committed Revenue Contribution framework requires an LSE serving new large loads to commit to paying at least 75% of a defined level of transmission service for 15 years, or to pay a shortfall payment if its actual NITS contribution drops below that minimum level.  In DEC’s proposed framework, this specific percentage – the requirement to pay for 75% of the projected transmission service obligation – functionally establishes the level of protection for other customers, as it sets the minimum payment obligation for LSEs serving large loads.  \nWhile the Commission has accepted agreements reflecting similar revenue contribution obligations, those agreements were evaluated under the Mobile-Sierra framework, and thus the Commission did not scrutinize whether the specific level reflected in those agreements was, in fact, just and reasonable.[fn:170]  As a result, DEC’s filing is the first time that the Commission has had the opportunity to evaluate the justness and reasonableness of such a provision, rather than simply deferring to bilaterally negotiated terms under the Mobile-Sierra framework.  \nAlthough DEC’s proposal might be a just and reasonable level of protection for other customers, DEC has not adequately explained the basis for its proposed 75% threshold.  The Commission should expect more from utilities than proposing, without any explanation or justification, specific thresholds that are foundational to customer protection frameworks.  I hope that the Commission, through the Large Load Show Cause Order proceedings, will establish a well-defined and workable approach for evaluating customer protection proposals like that before us, which will benefit customers and utilities alike.  Until then, the Commission should thoughtfully examine the appropriate level of protection based on the record before it.  On the record here, I would reject DEC’s proposal with guidance to provide DEC the opportunity to better support that figure or propose and defend a different threshold.  \nDEC’s Filing Highlights Broader Customer Protection Issues\nIn addition to the concerns raised above, DEC’s proposal highlights customer protection challenges around cost assignment and transparency that the Commission has raised as part of its Large Load Show Cause Orders.  While I would not reject DEC’s filing on these grounds, given relevant Commission precedent, I nonetheless take this opportunity to reiterate why additional large load reforms are necessary to adequately protect customers against unjustified cost shifts.   \nDefaulting to Rolled-in Rate Treatment for Large Load Network Upgrades Might Not Adequately Protect Other Customers\nIn its Large Load Show Cause Orders, the Commission found that the relevant tariffs may be unjust and unreasonable because they lack adequate mechanisms to mitigate the risk of cost shifting among transmission customers, and proposed to require the RTOs/ISOs to adopt pro forma cost recovery agreements to protect other customers.[fn:171]  In my concurrence to those orders, I noted that “transmission revenue contributions untethered from any assessment of the actual cost of providing transmission service induced by individual large loads may be insufficient to adequately protect other customers against unjustified cost shifts,” and encouraged the continued exploration of various customer protection approaches to help inform the Commission.[fn:172]  DEC’s proposal reinforces both my concern and the need for the Commission to consider additional cost allocation options to protect other customers.\nHere, DEC proposes to roll the costs of Network Upgrades, including those built to serve LSEs with new large loads, into transmission rates paid by all network customers.  The order accepts that proposal, noting that the Commission’s default practice is to roll into rates the costs of all Network Upgrades.[fn:173]  However, it is unclear from the record before us whether that rolled-in rate treatment will actually protect other customers from cost shifts driven by new service requests to large loads.  In the absence of better information about the relative costs of incremental versus rolled-in rates for a specific service request, other transmission customers will have limited ability to assess the specific Network Upgrade costs associated with any individual transmission service request intended to serve large loads, and thus limited ability to confirm whether the LSE’s Committed Revenue Contribution covers at least the incremental cost of those Network Upgrades.[fn:174]     \nThat outcome is consistent with the existing Commission policy but highlights precisely why that policy is deficient.  As I have previously written, the Commission should be open to alternative transmission pricing approaches to ensure that existing customers do not bear the costs of extraordinary transmission upgrade costs incurred to serve large loads or the risk that such loads do not materialize.[fn:175]  That could take various forms, such as enforcing “higher of” pricing (i.e., requiring that service for new loads be priced at the “higher of” incremental or rolled in rates).  Overall, the Commission should do more than simply presume rolled-in rate treatment is sufficient customer protection in all instances.  If that requires a change to Commission policy, then we should make it. \nCosts Driven by Large Loads Necessitate Additional Transparency\nIn the Large Load Show Cause Orders, the Commission identified an emerging need for additional transparency associated with new large loads and associated upgrades.[fn:176]  Although such proceedings are limited to regional transmission organizations and independent system operators, the need for additional transparency in the face of large load growth and associated transmission upgrades is applicable to all transmission owners.\nIn the instant filing, DEC’s proposed NITSA language leaves unchanged the level of transparency that parties, including customers, regulators, and consumer advocates, have into the cost and nature of transmission upgrades built to serve large loads.  Network Upgrades driven by large load customers will be reflected in pro forma NITSAs, which in turn will be reported to the Commission via EQRs, rather than actually filed.  While this level of transparency is consistent with current Commission requirements, it falls far short of the standard proposed by the Commission in the Large Load Show Cause Orders, as it fails to provide the information consumers and other stakeholders need for timely evaluation of the reasonableness of the rate treatment or whether costs are being correctly allocated under that selected rate treatment.  \nIn response to arguments made by protesters that DEC’s proposed NITSA would hinder their ability to meaningfully and timely evaluate the reasonableness of a specific rate treatment, the order points out that parties can challenge the allocation of specific costs by filing complaints related to these costs in DEC’s formula rate annual informational filings.[fn:177]  However, challenges to the formula rate annual informational filings would not allow stakeholders to challenge the appropriateness of a rate treatment embedded in an executed NITSA that is reported to the Commission in an EQR.  Instead, this process would only provide information for projects already in service and does not provide information on whether a transmission project was constructed to serve the needs of a specific large load.[fn:178]  Similarly, EQR data does not identify such projects that are still only in the planning phase and therefore does not provide transparency into the reasonableness of a specific rate treatment before an executed NITSA is reported to the Commission in an EQR. \nSimply put, parties need access to information on new transmission projects before such projects are undertaken so that they can engage during the planning period and assess the reasonableness of the rate treatment and cost impacts of new Network Upgrades, particularly if those will be rolled into rates that all customers must pay.  The information currently available to interested parties from DEC, as described in the order, appears insufficient, even though it complies with relevant precedent.\nConclusion\nNotwithstanding my concerns, I appreciate that DEC took the initiative to submit customer protection reforms to the Commission.  We should, as the Commission has done,[fn:179] encourage utilities to voluntarily submit filings that bolster customer protections while rigorously scrutinizing those filings to ensure they actually protect customers against the risk of unjustified cost shifts resulting from the addition of large loads to the system.  The Commission’s actions in the Large Load Show Cause Orders reflect its intent to lead on this issue and its recognition that the status quo is insufficient.  As the Commission considers these types of proposals, we therefore can and should expect more than just a demonstration that a filing is better than the inadequate status quo.  \nUnfortunately, the Commission’s findings here both set precedent and send signals about what the Commission considers an acceptable level of customer protection and evidentiary record to support it.  I do not believe that DEC has demonstrated that its filing represents an acceptable level of customer protection, and the precedent the Commission establishes here takes a step backwards from the strong arguments set forth in the Large Load Show Cause Orders.  Accordingly, rather than accept DEC’s filing, I would reject it with guidance to encourage DEC to strengthen and re-file its proposal. \n\n\nFor these reasons, I respectfully dissent.\n\n\n\n________________________\nJudy W. Chang\nCommissioner\n\n\n\n\n\n\n\n\nFootnotes\n[fn:2] 16 U.S.C. § 824d.\n[fn:3] 18 C.F.R. pt. 35 (2025).\n[fn:4] Duke Energy Carolinas, LLC, Tariffs, Rate Schedules and Service Agreements, Open Access Transmission Tariff (18.0.0).  The Joint OATT is the unified transmission tariff shared by DEC, Duke Energy Progress, LLC, and Duke Energy Florida, LLC that establishes the terms, conditions, and rates for open access point-to-point and Network Integration Transmission Service across those utilities’ transmission systems, among other things.  See Duke Energy Corp., 139 FERC ¶ 61,193 (2012).\n[fn:5] Filing, Transmittal Letter at 2.\n[fn:6] Filing, Transmittal Letter at 2.\n[fn:7] Id. at 2-3; see Duke Energy Carolinas, LLC, Docket No. ER21-2900-004                 (Apr. 28, 2022) (delegated order) (accepting substantive updates to DEC’s pro forma NITSA).\n[fn:8] As explained below, DEC defines loads of 100 MW or greater as large loads.\n[fn:9] Filing, Transmittal Letter at 4.\n[fn:10] ElectriCities filed its protest on behalf of itself, North Carolina Municipal Power Agency No. 1, and North Carolina Eastern Municipal Power Agency.\n[fn:11] Filing, Transmittal Letter at 20.\n[fn:12] Id. at 21-23.\n[fn:13] Id. at 11; see attach. A.\n[fn:14] Id.; see attach. F (explaining, under “New or Transferred Network Load,” the types of service requests to which the terms and conditions of Attachment F applies).\n[fn:15] Id. at 20-21.\n[fn:16] Id. (citing Joint OATT §§ 29.2, 31.1, 31.2).\n[fn:17] Id. at 22.  Proposed section I.1 of Attachment F also stipulates that the transmission customer will not connect any new Network Load to the transmission system until the in-service date specified in the NITSA unless all Network Upgrades necessary to accommodate the load have been constructed or the parties agree to an earlier in-service date.  See attach. F § I.1.\n[fn:18] Filing, Transmittal Letter at 10.\n[fn:19] Id. (citing Mw. Indep. Transmission Sys. Operator, Inc., 106 FERC ¶ 61,073,            at P 26 (2004); Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Servs. by Pub. Utils.; Recovery of Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,736 (1996) (cross-referenced at 75 FERC ¶ 61,080); Order No. 888-A, FERC Stats. & Regs   ¶ 31,048, at 30,258-261; Fla. Power & Light Co., 105 FERC ¶ 61,287, at P 19 (2003); Consumers Energy Co., 98 FERC ¶ 61,333, at 62,410 (2002)).  DEC adds that new subsection 4.3 provides that generation behind the second meter of a transmission customer will not be included in that customer’s calculation of network load unless the Commission “rules otherwise and Transmission Provider includes all such load on its own system as part of its system load in the denominator of the Load Ratio Share calculation.”  Id. at 10-11 (citation omitted).\n[fn:20] Deficiency Letter at 2.\n[fn:21] Deficiency Response at 6-10.\n[fn:22] Id. at 11 (citing Duke Energy Carolinas, LLC, 195 FERC ¶ 61,010, at P 8 (2026)).\n[fn:23] Deficiency Letter at 2.\n[fn:24] Deficiency Response at 11.\n[fn:25] Id. at 12.\n[fn:26] Id.\n[fn:27] Id. at 12-13.\n[fn:28] Id. at 14-15.\n[fn:29] Id. at 13.\n[fn:30] Id. at 13-14.\n[fn:31] Id. (citing PECO Energy Co., 193 FERC ¶ 61,148 (2025); PECO Energy Co., 195 FERC ¶ 61,074 (2026); Commonwealth Edison Co., 194 FERC ¶ 61,109 (2026); Commonwealth Edison Co., 194 FERC ¶ 61,106 (2026); Commonwealth Edison Co.,      194 FERC ¶ 61,110 (2026); Commonwealth Edison Co., 194 FERC ¶ 61,113 (2026) (ComEd); Commonwealth Edison Co., 194 FERC ¶ 61,184 (2026); Commonwealth Edison Co., 194 FERC ¶ 61,185 (2026); Commonwealth Edison Co., 194 FERC ¶ 61,181 (2026); Commonwealth Edison Co., 194 FERC ¶ 61,183 (2026); Dayton Power & Light Co., 195 FERC ¶ 61,059 (2026)).\n[fn:32] Filing, Transmittal Letter at 22.\n[fn:33] Id. at 2-4 (detailing load growth of 800 MW and 224 requests for new or modified points of delivery on DEC’s transmission system since 2012); DEC, Testimony of Eric S. Grant, Docket No. ER26-2691-000, at 3-5 (filed May 29, 2026) (noting a forecasted energy demand on DEC’s system of about 80 terawatt-hours and strong economic growth in the Carolinas) (Grant Test.).\n[fn:34] Id. at 12; attach. A § 6.6.1.\n[fn:35] Attach. A § 6.6.2.\n[fn:36] Filing, Transmittal Letter at 12-13.\n[fn:37] SACE Protest at 3-4.\n[fn:38] Id. at 5.\n[fn:39] Id. at 5-6.\n[fn:40] Id. at 7.\n[fn:41] Id. at 7-8.\n[fn:42] Id. at 8 (citing Inquiry Concerning the Comm’n’s Pricing Pol’y for Transmission Servs. Provided by Pub. Utils. Under the Fed. Power Act, FERC Stats. and Regs. ¶ 31,005, at 31,137-38 (1994) (Transmission Pricing Policy Statement)).\n[fn:43] Id. at 7-8, 11.\n[fn:44] Id. at 8 (citing Midwest Indep. Transmission Sys. Operator, Inc., 111 FERC              ¶ 61,421, at PP 10-11 (2005)).\n[fn:45] Id. at 8-9 (citing Sw. Power Pool, Inc., 169 FERC ¶ 61,058, at P 13 (2019); Sw. Power Pool, Inc., 133 FERC ¶ 61,084, at PP 6, 8 (2010)).\n[fn:46] Id. at 9.\n[fn:47] Id. at 10.\n[fn:48] Id. at 10-11 (citing Commonwealth Edison Co., 194 FERC ¶ 61,109; PECO Energy Co., 193 FERC ¶ 61,148 at PP 28-29).\n[fn:49] Id. at 11.\n[fn:50] Id.\n[fn:51] Id. at 11-12 (citing Duke Energy Carolinas, LLC, 186 FERC ¶ 61,178 (2024)).\n[fn:52] Id. at 12.\n[fn:53] DEC Answer at 2-3.\n[fn:54] Id. at 3 (citing Mun. Energy Agency of Neb., 189 FERC ¶ 61,099, at P 42 (2024); City of Anaheim, 113 FERC ¶ 61,091, at P 35 (2005)).  DEC points to the definition of Network Upgrades in the Commission’s pro forma OATT, which is reflected in the Joint OATT.  See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at               app. D, § 1.26; Joint OATT § 1.26.\n[fn:55] DEC Answer at 4-5 (citations omitted).\n[fn:56] Id. at 6.\n[fn:57] Id. at 7.\n[fn:58] Id. at 7-8 (citing Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237, at PP 15, 18 (2025) (Lockhart) (rejecting an amended NITSA because DEC did not demonstrate that the proposed incremental rate was just and reasonable).\n[fn:59] See, e.g., Pub. Serv. Co. of Colo., 62 FERC ¶ 61,013, at 61,061-62 (1993); Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277, 1285 (D.C. Cir. 2007) (endorsing the Commission’s “long-held understanding that Network Upgrades provide system-wide benefits”).\n[fn:60] Joint OATT § 1.26 (defining Network Upgrades as “[m]odifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider’s overall Transmission System for the general benefit of all users of such Transmission System”); Order No. 888, FERC Stats. & Regs. ¶ 31,036, at app. D, § 1.26; see Mun. Energy Agency of Neb., 189 FERC ¶ 61,099 at n.105 (“The Commission has also recognized the general benefits of network transmission facilities in its definition of Network Upgrades in the pro forma [OATT].”).\n[fn:61] See, e.g., Buckeye Power, Inc. v. Am. Transmission Sys. Inc., 148 FERC                     ¶ 61,174, at P 12 (2014) (“Commission policy favors a roll-in of rates on integrated transmission systems, absent special circumstances.”) (Buckeye).\n[fn:62] See, e.g., Duke Energy Carolinas, LLC, 168 FERC ¶ 61,190, at P 4 (2019) (detailing the “any degree of integration” and Mansfield tests, which are used to determine whether certain transmission facilities are integrated into a transmission provider’s transmission system and, therefore, whether the costs of such facilities should be rolled into transmission rates).\n[fn:63] Transmission Pricing Policy Statement, FERC Stats. and Regs. ¶ 31,005                  at 31,137 (“[T]he Commission has allowed a utility to charge transmission-only customers the higher of embedded costs (for the system as expanded) or incremental expansion costs, but not the sum of the two.”) (emphasis added); see, e.g., Ne. Tex. Elec. Coop., Inc., 111 FERC ¶ 61,189, at P 48 (2005) (stating that “the transmission provider can charge the higher of the incremental cost of network facilities or the rolled in rate”) (emphasis added); Ne. Utils. Serv. Co., 58 FERC ¶ 61,070, at 61,205-06 (1992).\n[fn:64] See Lockhart, 193 FERC ¶ 61,237 at P 19 (citations omitted); Order No. 890, 118 FERC ¶ 61,119 at PP 870, 884; Entergy Servs., Inc., 58 FERC ¶ 61,234, at 61,769 (1992).\n[fn:65] See Lockhart, 193 FERC ¶ 61,237 at P 16 (explaining that the Commission will consider an incremental rate so long as the filing includes “sufficient cost support for the Commission to find that the proposed incremental rate . . . is just and reasonable”).\n[fn:66] See, e.g., ComEd, 194 FERC ¶ 61,113 at n.60 (“As with any input to the formula rate, the formula rate protocols provide interested parties notice of and an opportunity to review and challenge the rates that will be charged.”); see Joint OATT        attach. H.2 §§ 1f (“[A]ll charges billed under formula rates are subject to prudence challenges and after-the-fact refund”), 2 (detailing the annual review process, including the ability for interested parties to request information from DEC and to challenge any aspect of the formula rate), 3 (explaining resolution of challenges).\n[fn:67] Attach. A § 14 (“Transmission Customer shall have the right to make a unilateral filing with the Commission to modify this Service Agreement pursuant to section 206 or any other applicable provision of the Federal Power Act.”); see, e.g., Buckeye, 148 FERC ¶ 61,174 at PP 1-2 (affirming initial decision on complaint requiring a transmission provider to implement a rolled-in rate design for transmission facilities of all voltages).\n[fn:68] SACE Protest at 10.\n[fn:69] See Sw. Power Pool, Inc., 177 FERC ¶ 61,056, at P 22 (2021) (“The use of                pro forma service agreements ensures that customers receive non-discriminatory service and that all customers are treated on a consistent and fair basis.”).\n[fn:70] See, e.g., Midcontinent Indep. Sys. Operator, Inc., 195 FERC ¶ 61,212, at P 46 (2026) (citing 16 U.S.C. § 824(b)(1)); FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 279-80 (2016); N.Y. v. FERC, 535 U.S. 1, 28 (2002); PJM Interconnection, L.L.C.,                         190 FERC ¶ 61,115, at PP 68-69 (2026)).\n[fn:71] Filing, Transmittal Letter at 23-24, 31.\n[fn:72] Id. at 24; attach. F §§ II.5.3.\n[fn:73] See attach. F §§ II.5.3 (Transmission Customer Shortfall Event and Payment Obligation), 5.4 (illustrative example of how and when a transmission customer would be subject to a Shortfall Payment).\n[fn:74] Filing, Transmittal Letter at 24 (citing Joint OATT, § 7.1 (Billing Procedure) (stating that, with respect to bills for services under the Joint OATT, “[t]he invoice shall be paid by the Transmission Customer within twenty (20) days of receipt.”).\n[fn:75] Id. at 23.\n[fn:76] Id.\n[fn:77] Id. at 25.\n[fn:78] ElectriCities Protest at 6-7.\n[fn:79] DEC Answer at 17.\n[fn:80] Id. at 19.\n[fn:81] Id. at 20-21.\n[fn:82] Id. at 22.\n[fn:83] Id. at 24-25.\n[fn:84] Deficiency Letter at 2.\n[fn:85] Deficiency Response at 2.\n[fn:86] Deficiency Letter at 2.\n[fn:87] Deficiency Response at 3.\n[fn:88] Id. at 5.\n[fn:89] Deficiency Response at 2-3.\n[fn:90] Id. at 3.\n[fn:91] Ala. Power Co., 190 FERC ¶ 61,151, at P 95 (2025) (“Order No. 888 and the pro forma OATT require non-discriminatory service, but under the comparability standard, this only requires that comparable service be provided to comparable customers . . . where entities are not similarly situated, it is not unduly discriminatory or preferential to treat them differently.”); see Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,647.\n[fn:92] Pac. Gas & Elec. Co., 195 FERC ¶ 61,035, at P 19 (2026) (citing Ala. Mun. Elec. Auth. v. Ala. Power Co., 119 FERC ¶ 61,286, at P 36 (2007); Ala. Mun. Elec. Auth. v. FERC, 662 F.3d 571, 572-73 (D.C. Cir. 2014)).\n[fn:93] Supra P 34.\n[fn:94] Attach. A § 6.4 (quoting Joint OATT § 32.4); see Duke Energy LLC, Duke Energy Credit Risk Management Policy to Implement Security Required Pursuant to Section 32.4 of the Joint OATT (June 2026), https://www.oasis.oati.com/woa/docs/DUK/DUKdocs/Duke_Energy_Credit_Procedures_for_Joint_OATT_Section_32.4  (Duke_6-17-26).pdf (Credit Policy).  Section 32.4 of the Joint OATT states, in relevant part:  “The Eligible Customer shall provide the Transmission Provider with a letter of credit or other reasonable form of security acceptable to the Transmission Provider equivalent to the costs of new facilities or upgrades consistent with commercial practices as established by the Uniform Commercial Code.”  Joint OATT § 32.4.\n[fn:95] Filing, Transmittal Letter at 11-12.\n[fn:96] Id. at 12; see Grant Test. at 11-12 (asserting that the security language is necessary to “set clear expectations [regarding the] monetary obligations of the network customer representing the change in service”).\n[fn:97] Id. at 11-2.\n[fn:98] Attach. A § 6.6.3 (Cost Recovery of Network Upgrades Once Placed In Service).\n[fn:99] Id. § 6.7 (Charge for Cancelled or Delayed Request for Change in Service).\n[fn:100] Filing, Transmittal Letter at 13.\n[fn:101] ElectriCities Protest at 4.\n[fn:102] Id. (citing attach. A § 6.4).\n[fn:103] Id. at 5.\n[fn:104] Id.\n[fn:105] Id.\n[fn:106] DEC Answer at 10-11.\n[fn:107] Id. at 11-12 (quoting Preventing Undue Discrimination & Preference in Transmission Serv., Order No. 890, 118 FERC ¶ 61,119, at P 1652 (2007)).\n[fn:108] Id. at 12 (citing Order No. 890, 118 FERC ¶ 61,119 at P 1661).  DEC also notes that peer transmission providers have also posted their credit security policies on OASIS.  Id. at 12-13 (citations omitted).\n[fn:109] Id. at 13-14.\n[fn:110] Id. at 14 (citing Joint OATT § 32.4).\n[fn:111] Id. at 13-14 (citing Order No. 890, 118 FERC ¶ 61,119 at P 453).\n[fn:112] Id. at 14 (citing PJM Interconnection, L.L.C., 195 FERC ¶ 62,211, at P 83 (2026); Midcontinent Indep. System Operator, Inc., 195 FERC ¶ 61,212, at P 84 (2026)).\n[fn:113] Id. at 15 (citing Order No. 890, 118 FERC ¶ 61,119 at P 1655).\n[fn:114] Id. (quoting Duke Energy Carolinas, LLC, OASIS Business Practices 1 (Feb. 2026), https://www.oasis.oati.com/woa/docs/DUK/DUKdocs/Practices_posted_2.27.26_-_CLEAN.pdf).\n[fn:115] Id. at 16.\n[fn:116] See Joint OATT § 32.4 (“The Eligible Customer shall provide the Transmission Provider with a letter of credit or other reasonable form of security . . ..”) (emphasis added).\n[fn:117] Order No. 890, 118 FERC ¶ 61,119 at PP 1651-53 (requiring transmission providers to post on their public websites all rules, standards, and practices that relate to transmission service and to post a link to those rules, standards, and practices on OASIS); id. at 1655 (requiring transmission providers to publicly post “a statement of the process by which the transmission provider will amend these rules, standards, and practices that are accessible via OASIS” and to “specify a mechanism to provide reasonable notice of any proposed changes to a posted business practice and the respective effective date of such change”).\n[fn:118] Order No. 890 required transmission providers to add a new Attachment L to their OATTs, “Creditworthiness Procedures.”  Attachment L states that Transmission Providers may require transmission customers to provide and maintain security during the term of a NITSA “that protects the Transmission Provider against the risk of                    non-payment.”  Id. at App. C, Att. L.  We also note that section 6.6.3 of Attachment A provides that DEC will release the security provided by the network customer within                  90 days following the in-service date of the relevant Network Upgrades.\n[fn:119] See Joint OATT § 32.4.\n[fn:120] Filing, Transmittal Letter at 7.\n[fn:121] Id.\n[fn:122] ElectriCities Protest at 8.\n[fn:123] DEC Answer at 9.\n[fn:124] See 16 U.S.C. § 825(b) (“The Commission shall at all times have access to and the right to inspect and examine all accounts, records, and memoranda of . . . public utilities, and it shall be the duty of such licensees and public utilities to furnish to the Commission . . . any information with respect thereto which the Commission may by order require.”); 18 C.F.R. § 388.112(b) (2025) (detailing requirements that parties in certain Commission proceedings must provide a protective order that governs requests for parties to proceedings to obtain privileged information).\n[fn:125] DEC states that the Commission has previously accepted DEC NITSAs with the City of Kings Mountain, North Carolina (Docket No. ER26-550 (Jan. 16, 2026)) and NCMPA (Docket No. ER26-440-000 (Jan. 2, 2026)) that omitted this same language concerning rollover rights.\n[fn:126] Filing, Transmittal Letter at 9.\n[fn:127] Id. (citing Sw. Power Pool, Inc., 169 FERC ¶ 61,058, at P 20 (2019) (“[W]e agree with SPP and Xcel that sections 8.10 and 8.12 of Attachment 1 to SPP’s pro forma service agreement are considered to be “fill-in-the-blank” sections and we do not consider a service agreement to be non-conforming because SPP filled-in the blanks.”).\n[fn:128] Id. at 13.\n[fn:129] See attach. A § 6.9 (Ancillary Services Charge).  Schedule 2 concerns reactive supply and voltage control from generation source service, and Schedule 3 concerns regulation and frequency response service.\n[fn:130] Filing, Transmittal Letter at 13-14.\n[fn:131] Id. at 14.\n[fn:132] Id.\n[fn:133] Id. at 14-15.\n[fn:134] Id. at 15.\n[fn:135] Id.\n[fn:136] Id. at 16.\n[fn:137] Id. at 17.\n[fn:138] Id. at 17-18.\n[fn:139] Id. at 18.\n[fn:140] Id.\n[fn:141] Id. at 18-19.\n[fn:142] Id. at 19.\n[fn:143] Id.\n[fn:144] Id. at 19-20.\n[fn:145] Transmission Pricing Policy Statement, FERC Stats. and Regs. ¶ 31,005                   at 31,137 (“[T]he Commission has allowed a utility to charge transmission-only customers the higher of embedded costs (for the system as expanded) or incremental expansion costs, but not the sum of the two.”).\n[fn:146] The Commission on a case-by-case basis “analyzes proposed deviations from pro forma agreements to ensure that operational or other reasons make the         non-conforming provisions necessary” such as “to address specific reliability concerns, novel legal issues, or other unique factors.”  See, e.g., Lockhart, 193 FERC ¶ 61,237       at P 19.  See also Order No. 890, 118 FERC ¶ 61,119 at PP 870, 884, order on reh’g, Order No. 890-A, 121 FERC ¶ 61,297 (2007), order on reh’g, Order No. 890-B,          123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).\n[fn:147] Supra P 46.\n[fn:148] See MISO Transmission Owners v. FERC, 45 F.4th 248, 253 (D.C. Cir. 2022); Advanced Energy Mgmt. All. v. FERC, 860 F.3d 656, 662 (D.C. Cir. 2017) (discussing the Commission’s “passive and reactive” role under FPA section 205).\n[fn:149] PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, errata notice, 196 FERC ¶ 61,122 (2026); Sw. Power Pool, Inc., 195 FERC ¶ 61,213 (2026); N.Y. Indep. Sys. Operator, Inc., 195 FERC ¶ 61,216 (2026); Midcontinent Indep. Sys. Operator, Inc.,                  195 FERC ¶ 61,212, errata notice, 196 FERC ¶ 61,123 (2026); Cal. Indep. Sys. Operator Corp., 195 FERC ¶ 61,214 (2026); ISO New Eng. Inc., 195 FERC ¶ 61,215, errata notice, 196 FERC ¶ 61,012 (2026).\n[fn:150] See Interconnection of Large Loads to the Interstate Transmission System, Advance Notice of Proposed Rulemaking, Docket No. RM26-4-000 (Oct. 23, 2025).\n[fn:151] See e.g., PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, at PP 77-84 (2026).\n[fn:152] See Interconnection of Large Loads to the Interstate Transmission System, Advance Notice of Proposed Rulemaking, Docket No. RM26-4-000 (Oct. 23, 2025) (ANOPR).\n[fn:153] Duke Energy Carolinas, LLC, 197 FERC ¶ 61,020 at P 35 (2026).\n[fn:154] PECO Energy Co., 193 FERC ¶ 61,148 at P 28 (2025); see also, e.g., Commonwealth Edison Co., 194 FERC ¶ 61,109 (2026).\n[fn:155] See MISO Transmission Owners v. FERC, 45 F.4th 248, 253 (D.C. Cir. 2022); Advanced Energy Mgmt. All. v. FERC, 860 F.3d 656, 662 (D.C. Cir. 2017) (discussing the Commission’s “passive and reactive” role under FPA section 205).\n[fn:156] PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, errata notice, 196 FERC ¶ 61,122 (2026); Sw. Power Pool, Inc., 195 FERC ¶ 61,213 (2026); N.Y. Indep. Sys. Operator, Inc., 195 FERC ¶ 61,216 (2026); Midcontinent Indep. Sys. Operator, Inc., 195 FERC ¶ 61,212, errata notice, 196 FERC ¶ 61,123 (2026); Cal. Indep. Sys. Operator Corp., 195 FERC ¶ 61,214 (2026); ISO New Eng. Inc., 195 FERC ¶ 61,215, errata notice, 196 FERC ¶ 61,012 (2026).\n[fn:157] Inquiry Concerning the Commission’s Pricing Policy for Transmission Servs. Provided by Pub. Utils. Under the Fed. Power Act, 59 FR 55031 at n.7 (Nov. 3, 1994), FERC Stats. and Regs. ¶ 31,005 (1994).\n[fn:158] The Commission on a case-by-case basis “analyzes proposed deviations from pro forma agreements to ensure that operational or other reasons make the non-conforming provisions necessary,” such as “address[ing] specific reliability concerns, novel legal issues, or other unique factors.”  See, e.g., Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 at P 19 (2025).  See also Preventing Undue Discrimination & Preference in Transmission Serv., Order No. 890, 118 FERC ¶ 61,119 at PP 870, 884, order on reh’g, Order No. 890-A, 121 FERC ¶ 61,297 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).\n[fn:159] Exec. Off. of the President, Ratepayer Protection Pledge (Mar. 4, 2026), https://www.whitehouse.gov/releases/2026/03/ratepayer-protection-pledge/ (“Companies will pay for all new power delivery infrastructure upgrades required to service their data centers, including adequate network upgrade costs to ensure that these expenses are not passed on to the ordinary household.”).\n[fn:160] See, e.g., PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 (2026) (See, Comm’r, concurring at PP 7-8).\n[fn:161] See, e.g., PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 at PP 61-62 (2026).\n[fn:162] Specifically, DEC proposes to require that transmission customers serving a new or transferred Network Load of 100 MW or greater to commit to pay at minimum a Committed Revenue Contribution equal to 75% of the MW value in the load schedule for each applicable month and year during the 15-year period following the in-service date of the Network Upgrades required to accommodate the load.  As the order explains, “if the Actual Revenue Contribution does not equal or exceed the Committed Revenue Contribution for that calendar year, a ‘Customer Shortfall Event’ is deemed to have occurred for that calendar year, and the customer would then have to make a Shortfall Payment to DEC’s transmission revenue requirement for each month and year the customer’s actual NITS falls short of the minimum, equivalent to the difference between the Actual Revenue Contribution and the Committed Revenue Contribution.”  Duke Energy Carolinas, LLC, 197 FERC ¶ 61,020, at P 35 (2026) (Order).\n[fn:163] These types of obligations are also a central component of the customer protection framework advanced by the Commission in its large load show cause orders.  PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, errata notice, 196 FERC ¶ 61,122 (2026); Midcontinent Indep. Sys. Operator, Inc., 195 FERC ¶ 61,212 (2026); Sw. Pwr. Pool, Inc., 195 FERC ¶ 61,213 (2026); Calif. Indep. Sys. Operator Corp., 195 FERC 61,214 (2026); ISO New England, Inc., 195 FERC ¶ 61,215 (2026) (ISO-NE Show Cause Order); N.Y. Indep. Sys. Operator, Inc., 195 FERC ¶ 61,216 (2026) (collectively, Large Load Show Cause Orders).  I will cite to the ISO-NE Show Cause Order for representative citations.\n[fn:164] I have previously noted that the Commission lacks a framework through which it can conduct that assessment.  E.g., PECO Energy Co., 193 FERC ¶ 61,148 (2025) (Comm’r Chang, concurring) (noting at P 6 “that the Commission will increasingly be asked to review one-off agreements purporting to protect customers against transmission cost shifts, without a substantive framework for assessing the adequacy of those protections”).\n[fn:165] E.g., DEC Transmittal at 31 (“As such, the revised Attachment F-2 (pro forma NITSA) contains a comprehensive package of safeguards to protect customers from the impact of changes in service requests, including large load service requests, as well as to minimize the impact on other customer load applicants if the new network load (and its contribution to transmission revenue requirement) does not achieve commercial operation or take the minimum level of service as and where proposed.”); id. (“Together, these protections reflect a Transmission Customer’s commitment to its own project and guards against shifting costs and risks to other customers, as well as minimizes the risk that the presence of oversized or unrealistic applications unreasonably harm other applicants for network service.”).\n[fn:166] E.g., id. at 23 (“The 100 MW threshold is intended to distinguish large loads that present a higher risk of shifting costs to other customers if the load does not materialize.”)\n[fn:167] Proposed section 6.4 of the pro forma NITSA incorporates language already existing in Section 32.4 of DEC’s Joint OATT and requires Transmission Customers to provide DEC with security in situations in which new facilities or network upgrades are necessary to accommodate a change in service requests.  Section 6.6.3 specifies that DEC shall release the security provided by Transmission Customer within 90 days following the in-service date of the Network Upgrades.  DEC can require additional limited security in the event that it concludes a Transmission Customer does not meet its creditworthiness requirements.  See DEC Joint OATT, Attachment O, sections 1.2, 1.3, & 1.4.\n[fn:168] Notably, just this week DEC entered into a settlement governing retail rates, terms, and conditions of service for large loads that includes more robust security requirements for Network Upgrade costs that span the contract term of 10-15 years.  These security obligations, which are directly tied to the cost of the Network Upgrades, extend beyond the construction phase for Network Upgrades and thus appear to meaningfully exceed those required of Transmission Customers serving large loads under DEC’s proposal.  DEC, Joint Reply Comments in Support of Large Load Tariff Settlement, In the Matter of:  Application of Duke Energy Carolinas, LLC for Adjustment of Rates and Charges, Applicable to Elec. Svc. in N.C. and Performance-Based Regulation, Docket No. E-7, Sub 1329, at 10-11 (filed Oct. 6, 2026) (discussing the security requirements included in the proposed settlement).\n[fn:169] For example, in the Large Load Show Cause Orders, the Commission proposed to require cost recovery agreements between Eligible Customers that serve large loads and transmission owners, to help protect against cost shifting from large loads to other transmission customers.  E.g., ISO-NE Show Cause Order, 195 FERC ¶ 61,215 at PP 74-81.  DEC’s Committed Revenue Contribution construct is aimed at the same purpose and is functionally similar in many respects to the model proposed by the Commission in those orders.  However, the Commission also preliminarily found that “the cost recovery agreement should include a credit support (or other financial security requirement) sufficient to secure the obligations of the Eligible Customer taking transmission service on behalf of a large load to pay the amounts owed pursuant to the cost recovery agreement,” and noted that credit support posted as part of a retail agreement could be satisfactory.  E.g., id. P 80.  The Commission thus specifically and intentionally paired “a specified minimum financial contribution and financial security sufficient to secure such contribution” as “necessary to mitigate cost shifting if the Eligible Customer ultimately takes less transmission service than anticipated….”  Id. (emphasis added).\n[fn:170] See, e.g., Commonwealth Edison Co., 194 FERC ¶ 61,184, at P 36 (2026); id. (Comm’r Chang, concurring at P 1).\n[fn:171] E.g., ISO-NE Show Cause Order, 195 FERC ¶ 61,215 at PP 74-81.  The Commission also preliminarily found that those agreements “are necessary to help ensure that the Eligible Customer is responsible for timely paying the costs of large load-driven transmission (i.e., the costs required to provide them with the requested transmission service, including the cost of any needed network upgrades)….”  Id. P 77.\n[fn:172] E.g., id. (Comm’r Chang, concurring at P 8).\n[fn:173] Order at P 30.\n[fn:174] DEC’s parent company, Duke Energy, signed the White House Ratepayer Protection Pledge, which DEC discusses at length in its transmittal letter.  That pledge requires companies to pay “for new power delivery infrastructure” and pay “whether they use power or not.”  See Exec. Off. of the President, Ratepayer Protection Pledge (Mar. 4, 2026), https://www.whitehouse.gov/ratepayer-protection-pledge/.  DEC’s revised NITSA provisions arguably accomplish the latter but do not address the former, and thus it is unclear whether DEC’s proposal actually meets its parent’s commitments under that pledge.\n[fn:175] E.g., PECO Energy Co., 193 FERC ¶ 61,148 (2025) (Comm’r Chang, concurring); ISO-NE Show Cause Order, 195 FERC ¶ 61,215 (Comm’r Chang, concurring at P 8).\n[fn:176] E.g., ISO-NE Show Cause Order, 195 FERC ¶ 61,215 at PP 69-74.  The Commission specifically found that tariffs may not be just and reasonable unless they feature an online database in an easily accessible format that provides information related to transmission service requested by Eligible Customers on behalf of large loads.\n[fn:177] Order at P 32.\n[fn:178] DEC features a historic formula rate, meaning that its rates are based on the plant in service and expenses from prior years.  Thus, DEC’s transmission formula rate annual informational filings describe costs for projects that are already in service and therefore only provide a look-back at projects that have been completed.\n[fn:179] E.g., ISO-NE Show Cause Order, 195 FERC ¶ 61,215 at P 35 (encouraging the submission of FPA section 205 filings to address issues identified in the Large Load Show Cause Orders).\n\nheader1 (Word template)\nCUICUI- 1 -\nCUI\nCUI\n\nheader2 (Word template)\nDocket Nos. ER26-2691-000 and ER26-2691-001\t- 1 -"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":1,"endAt":858,"startToken":0,"endToken":118},{"p":1,"at":858,"title":"Background","method":"printed heading","endPage":1,"endAt":4729,"startToken":118,"endToken":719},{"p":1,"at":4729,"title":"Discussion","method":"printed heading","endPage":1,"endAt":56453,"startToken":719,"endToken":8788},{"p":1,"at":56453,"title":"Attachment A – (Specifications for Network Integration Transmission Service)","method":"printed heading","endPage":1,"endAt":58497,"startToken":8788,"endToken":9091},{"p":1,"at":58497,"title":"Attachment B – (Delivery Points)","method":"printed heading","endPage":1,"endAt":58926,"startToken":9091,"endToken":9160},{"p":1,"at":58926,"title":"Attachment C – (Transmission and Distribution Rates)","method":"printed heading","endPage":1,"endAt":59895,"startToken":9160,"endToken":9300},{"p":1,"at":59895,"title":"Attachment D – (Network Operating Agreement)","method":"printed heading","endPage":1,"endAt":64251,"startToken":9300,"endToken":9936},{"p":1,"at":64251,"title":"Attachment E – (Other Charges/Credits)","method":"printed heading","endPage":1,"endAt":78634,"startToken":9936,"endToken":12117},{"p":1,"at":78634,"title":"Background","method":"printed heading","endPage":1,"endAt":93348,"startToken":12117,"endToken":14329},{"p":1,"at":93348,"title":"Conclusion","method":"printed heading","endPage":1,"endAt":94851,"startToken":14329,"endToken":14552},{"p":1,"at":94851,"title":"Footnotes","method":"Word notes","endPage":1,"endAt":125064,"startToken":14552,"endToken":19613}]}