Key takeaways
- The Federal Energy Regulatory Commission (FERC) recently issued a series of show cause orders, one for each of six Regional Transmission Organizations and Independent System Operators (RTOs/ISOs), that demand a sweeping overhaul of how grids integrate large load customers, including data centers.
- For each of the RTOs/ISOs, FERC outlined strengths and shortcomings relative to five categories of reform for RTOs/ISOs:
- Clarifying transmission service, application, and study rules for large load customers
- Establishing safeguards to protect against cost shifting
- Setting rules for co-location arrangements and behind-the-meter (BTM) generation
- Developing transmission services to enable large load flexibility
- Creating pathways for generation facilities to be studied along with large electrically proximate or co-located load
- Affected RTOs/ISOs, transmission owners, and other stakeholders should monitor and act on several July and August 2026 deadlines related to the show cause orders.
On June 18, 2026, FERC issued by unanimous vote six separate Section 206 show cause orders, one for each of the RTOs/ISOs: PJM, SPP, MISO, NYISO, CAISO, and ISO New England. For now, FERC has not issued similar show cause orders to utilities outside RTOs/ISOs.
For data center developers operating in organized markets, projects at or above the emerging 50-megawatt (MW), transmission-level threshold should expect more formalized tariff rules around application requirements, study procedures, readiness criteria, ongoing operating obligations, and pro forma transmission service terms. The orders also put cost allocation and cost transparency squarely in play: FERC is asking each region to justify—or replace—tariff provisions that lack public network-upgrade cost information, pro forma cost-recovery agreements, and financial-security mechanisms designed to mitigate cost shifting from large-load-driven upgrades to other transmission customers.
At the same time, FERC is inviting tariff structures that could accelerate viable projects, including interim and contract-demand transmission services for flexible loads, clearer rules for co-located and behind-the-meter generation, and generator interconnection pathways for loads served by electrically proximate generation. A key takeaway for the data center sector is that FERC is committed to prioritizing projects that can prove they are real, financeable, operationally flexible, and capable of integrating with the grid without imposing unjustified costs on other customers. Moreover, FERC embraced region-specific variations in tariff structure, so long as the core principles and areas of reform discussed below are met. As such, FERC focused on speed over uniformity, requiring significant tariff reforms in a lightning-fast 60 days.
Core areas of reform
While FERC chose regional tailoring over a single nationwide rule, it set forth a clear five-point common policy architecture: transparency, customer protection, flexible transmission service, resource adequacy, and better coordination between load and generation. More specifically, FERC set forth five major categories of reforms it is ordering each RTO/ISO to take on:
- Implement clear transmission service, application, and study rules for transmission customers that will serve large loads or develop new processes to do so, including consideration of alternative transmission technologies.
- Show that it has adequate safeguards against cost shifting or take steps to create such safeguards. Each RTO/ISO must provide unprecedented transparency into network upgrade costs that the states can then use to inform retail ratemaking.
- Demonstrate or create clear rules to guide co-location and the use of BTM generation.
- Approve or develop new transmission services to enable large load flexibility.
- Create study pathways, if they do not already exist, for generation facilities to be studied in a manner that accounts for a large electrically proximate or co-located load to prevent unnecessary and expensive transmission buildout.
At the June 18, 2026, open meeting announcing the show cause orders, Commissioner David Rosner articulated four pillars guiding FERC’s five focus areas:
- Protecting consumers by preventing cost shifting with mandatory contracts, reducing infrastructure costs with smarter studies, and boosting efficiency with grid-enhancing technologies.
- Enhancing transparency by providing transparency in transmission costs, improving load forecasting practices, and increasing disclosure of utility investments.
- Safeguarding reliability by establishing new large load impact studies, accelerating interconnection for system stability, and continuing the North American Electric Reliability Corporation (NERC) standards development process.
- Fostering innovation by accelerating co-located and proximate loads, leveraging advanced load flexibility, and completing studies faster (60 to 90 days).
Moreover, the show cause orders directed RTOs/ISOs to consider alternative transmission strategies (ATTs) like advanced power flow control devices, synchronous condensers, advanced conductors, and dynamic line rates when conducting transmission service request studies for large loads. The orders thus provide a strong boost in priority for cost-saving ATTs that in the past have tended to languish in the transmission planning process.
The show cause orders tailored the reform areas above to the specific issues facing each RTO/ISO and varying levels of progress. Southwest Power Pool (SPP) in particular was held up as a positive example in light of its efforts to adopt transparent and streamlined interconnection processes for high impact large loads (HILLs) and co-located generation resources. However, FERC found further work was needed in every RTO/ISO to achieve the articulated goals, and it did not mandate that RTOs/ISOs adopt identical processes. The tables at the end of this Update provide further details for each RTO/ISO across the five reform areas.
Next steps
The battleground now moves to the regional stakeholder processes, where critical issues will be addressed, such as whether the regions elect to file their own Section 205 solutions; how they define “large load” and “flexible large load”; what minimum cost-recovery and financial security requirements they propose; and whether PJM-style interim network integration transmission service (NITS), firm contract-demand service, and non-firm contracts demand service become the national template by region-by-region adoption.
FERC requires responses to the show cause orders by August 17, 2026, which will be a challenging deadline to meet for RTOs/ISOs that need buy-in for reforms from stakeholders through governance processes already embedded in their tariffs. FERC noted that RTOs/ISOs could request an extension of 90 days by August 3, 2026, but the clear message was that speed is a priority, and FERC will have little patience for gridlock or delay. While FERC did not propose to alter any RTO/ISO governance processes with these orders, some commissioners expressed willingness to take additional steps if they were not satisfied with the speed and scope of proposed reforms arising out of the stakeholder process. Stakeholders should watch this RTO/ISO governance issue as it evolves, in particular with the commissioner-led technical conference on PJM’s governance structure next month.
In addition to the response to the show cause order, FERC directed each RTO/ISO to file by July 20, 2026, an informational report regarding how the RTO/ISO intends to ensure that adequate generation will be available to serve existing and new large loads. Interested parties may intervene in each docket by July 9, 2026, and reply to the RTOs/ISOs’ show cause responses by September 16, 2026.
The tables below give a broad overview of FERC’s findings on the sufficiency (and lack thereof) of the RTOs/ISOs’ tariff provisions in interconnecting large loads and the direction FERC gave each RTO/ISO with respect to the five major categories of reform.
Transmission Service to Eligible Customers on Behalf of Large Loads |
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PJM[1] |
Large load threshold: Peak load of ≥50 MW, interconnecting above 69 kV, and not part of a co-location arrangement Transmission service: Although PJM and/or the transmission owners may have existing load integration processes, including studies that are performed in evaluating the provision of transmission service to eligible customers on behalf of large loads, PJM’s tariff lacks a clear study process addressing the unique operational and reliability challenges of serving large loads and speculative and duplicative requests to avoid excessive and unnecessary network upgrades (PJM Order at P 1 n.2). FERC specifically identified the risks that PJM and/or transmission owners may not capture system impacts and that PJM may lack ongoing visibility and operational control (PJM Order at P 54). |
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SPP[2] |
Large load threshold: A new or increased commercial/industrial load at a single site through shared points of interconnection (POIs) or delivery points that is ≥10 MW at ≤69 kV or ≥50 MW at ≥69 kV Electric storage resources are excluded. Transmission service: SPP’s directive is materially narrower because FERC had already accepted SPP’s HILL study process and found it a just and reasonable approach for integrating new large loads (SPP Order at P 35). FERC limited its concerns to requiring evaluation of alternative transmission technologies and adding pro forma service-agreement provisions memorializing ongoing operational requirements (Id.). |
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NYISO[3] |
Large load threshold: ≥50 MW, interconnecting above 69 kV, and not part of a co-location arrangement Transmission service: NYISO already has load-interconnection procedures, but key requirements are only partly in the tariff and are supplemented by non-tariff documents and varying transmission-owner facilities-study procedures (NYISO Order at P 46). FERC emphasized that NYISO may conduct a system impact study or NITS study only if requested by the eligible customer or if the customer proceeds under Attachment P, creating a gap compared with a mandatory large-load study framework (Id.). NYISO also has a particularly large growth record—more than 40 large load projects totaling more than 10,000 MW in the queue as of November 2025 (NYISO Order at P 79). |
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MISO[4] |
Large load threshold: ≥50 MW, interconnecting above 69 kV, and not part of a co-location arrangement Transmission service: In MISO, transmission owners lead load connection, and MISO plays a supplemental role (MISO Order at P 21). Many transmission owner load-addition processes are not in the MISO tariff (Id.). FERC also noted MISO’s own statement that the tariff does not provide a consistent or transparent framework for large loads (MISO Order at P 29). |
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CAISO[5] |
Large load threshold: ≥50 MW, interconnecting above 69 kV, and not part of a co-location arrangement Transmission service: CAISO does not offer traditional Order No. 888 network/point-to-point services, offers no firm long-term transmission reservations, and has no formal application process for transmission service (CAISO Order at P 19). FERC found that participating transmission owners (PTOs) handle wholesale load interconnection studies while the customer must retain a scheduling coordinator to access CAISO service. CAISO does not appear to conduct network-upgrade studies outside the transmission planning process (TPP) (CAISO Order at P 39). FERC therefore focused heavily on clarifying which tariff—CAISO’s or the PTOs’—will contain the application process, study procedures, 60- or 90-day study timeline, operational requirements, and agreement terms (CAISO Order at PP 58–64). |
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ISO-NE[6] |
Large load threshold: ≥50 MW, interconnecting above 69 kV, and not part of a co-location arrangement Transmission service: FERC identified a potential for large-load growth and concern that the absence of clear tariff rules may itself limit growth (ISO-NE Order at P 41). ISO-NE has more detailed regional-service study mechanics in the tariff, but FERC still focused on unclear regional/local study responsibilities and PTO-specific procedures (Id.). |
Cost Shifting Risk Among Transmission Customers |
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PJM |
FERC identified a lack of adequate mechanisms to mitigate cost shifting, focusing on the absence of a pro forma cost recovery agreement between PJM, the relevant transmission owner, and the eligible customer (PJM Order at P 66). FERC also required transparency for network upgrades evaluated in the local transmission planning process that are needed to serve large loads (PJM Order at P 73). |
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SPP |
FERC recognized that SPP has taken significant steps to curb speculative requests through HILL but still found insufficient centralized information on large-load-driven network upgrade costs (SPP Order at P 54). SPP’s existing reporting was described as largely aggregate regional reporting, not detailed cost estimates for large-load-driven network upgrades (SPP Order at P 55). FERC also focused on SPP’s Attachment AQ/AX/Z1 context, including that certain network upgrades can be base plan funded and allocated through rolled-in rates, creating a distinct cost-shift concern despite SPP’s existing HILL and CHILLS reforms (SPP Order at P 19). |
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NYISO |
FERC directed NYISO to address both centralized website transparency and a pro forma cost recovery agreement (NYISO Order at PP 82–91). NYISO-specific concerns include that portions of the wholesale load-interconnection process are outside the tariff, including transmission owner facilities studies and interconnection agreements memorializing costs and cost allocation (NYISO Order at P 90). |
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MISO |
MISO’s cost-shifting issue is tied to several different cost-allocation pathways: Direct assignment facilities are charged to the eligible customer, but network upgrades may become MISO Transmission Expansion Plan MTEP transmission delivery service projects rolled into zonal rates, and local “Other Projects” may also be recovered through TO rates (MISO Order at PP 23–24). FERC directed MISO to address website transparency and a pro forma cost recovery agreement to ensure eligible customers bear the risk of large-load-driven costs (MISO Order at PP 77, 84). |
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CAISO |
FERC acknowledged the cost-shifting concerns may not be present in the same way as in other RTOs/ISOs, given PTO wholesale load-interconnection processes that can directly assign interconnection costs. FERC nevertheless remained concerned that speculative large-load requests can affect PTO transmission revenue requirements recovered through CAISO’s access charge (CAISO Order at P 83). FERC also directed CAISO/PTOs to assess centralized website transparency and a pro forma cost recovery agreement, while allowing credit support posted under retail arrangements to avoid duplicative requirements (CAISO Order at PP 75, 80). |
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ISO-NE |
FERC found that regional network service requests may be studied in a cluster study with cost-allocation mechanisms, but FERC found that ISO-NE’s provisions may not clearly contemplate upgrades or facilities identified for regional network service (ISO-NE Order at P 57). FERC also remained concerned about local transmission planning projects recovered through PTO transmission revenue requirements when large loads fail to materialize or come in below proposed MW levels (ISO-NE Order at P 78). FERC directed ISO-NE to address centralized website transparency and pro forma cost recovery agreements with minimum contribution and credit support (ISO-NE Order at PP 65, 80). |
Co-location Arrangements and Behind-the-Meter Generation |
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PJM |
FERC noted that co-located load concerns are being addressed in a separate, ongoing PJM Federal Power Act (FPA) Section 206 proceeding (PJM Order at P 2). FERC nevertheless referenced the PJM Co-Location Order background, including directives for co-located terms, three new transmission services, BTMG revisions, and generator-interconnection clarifications (PJM Order at P 13). |
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SPP |
SPP does not allow BTMG netting to reduce NITS charges, so FERC did not address BTMG netting rules for SPP (SPP Order at P 67 n.140). FERC nevertheless found that SPP lacks sufficiently clear provisions for co-location arrangements, including how interconnection customers may use generator-interconnection processes, how an eligible customer is designated for co-located load, and how wholesale charges apply (SPP Order at PP 76, 78). FERC invited SPP to explain whether HILL Generation Assessment (HILLGA) already clarifies some co-location requirements or can be modified to do so (SPP Order at P 76). |
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NYISO |
FERC found that NYISO lacks sufficient co-location provisions, including tariff clarity on how interconnection customers use NYISO generator-interconnection processes and how an eligible customer is designated for charges (NYISO Order at P 104). FERC also specifically questioned NYISO’s use of actual energy withdrawals rather than gross load for transmission service charges for host loads configured in a Behind-the-Meter Net Generation Resource (BTM:NG) arrangement (NYISO Order at P 110). |
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MISO |
FERC noted that MISO does not allow BTMG netting to reduce NITS charges, so FERC did not address BTMG netting rules (MISO Order at P 86, n.194). FERC nevertheless found MISO lacks sufficient co-location tariff clarity, including standard procedures for zero-injection generator arrangements that MISO is developing in its stakeholder process (MISO Order at P 97). |
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CAISO |
CAISO does not define BTMG and does not have a process to evaluate load co-located with generating facilities (CAISO Order at PP 26, 89). FERC found CAISO lacks tariff provisions for co-location rates/terms, designation of the eligible customer for charges, and ancillary-service charges on a gross-demand basis (CAISO Order at PP 86, 96, 98). CAISO also has a distinct BTMG-netting issue: FERC found CAISO allows load with BTMG to net BTMG against load for regional access charge purposes and asked whether that remains just and reasonable, including below a potential MW materiality threshold (CAISO Order at P 102). |
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ISO-NE |
ISO-NE’s tariff does not define BTMG, and FERC adopted for purposes of the order a PJM-like BTMG concept as generation delivering energy to load without using transmission or distribution facilities (ISO-NE Order at P 87). FERC found that ISO-NE lacks co-location clarity, including study scope, designation of the eligible customer, and gross-demand charges for regulation and black start services (ISO-NE Order at PP 94–96). ISO-NE also has a BTMG-netting issue because its regional network service charge can exclude load offset by a generator asset behind the same retail customer meter (ISO-NE Order at P 100). |
New Transmission Services for Flexible Large Loads |
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PJM |
FERC found that PJM’s existing NITS and firm/non-firm point-to-point services remain available but do not reflect flexible large loads’ ability to limit system use (PJM Order at P 86). FERC directed PJM to assess extension of the PJM co-location services—interim non-firm NITS while network upgrades are built, permanent firm contract demand service, and permanent non-firm contract demand service—to flexible large loads (PJM Order at P 87). |
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SPP |
SPP already has “CHILLS,” an as-available non-firm service for HILLs, that can last up to seven years while designated resources and/or network upgrades are completed (SPP Order at P 17). Nevertheless, FERC found CHILLS may not be equivalent to interim NITS and directed SPP to explain whether CHILLS is sufficient, revise CHILLS, or propose other tariff changes (SPP Order at P 84). FERC also referenced SPP’s PALS proposal as a stakeholder initiative that may address temporary and permanent flexible-load service gaps (Id.). |
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NYISO |
NYISO’s existing transmission services are NITS and firm point-to-point transmission service (NYISO at P 112). FERC directed NYISO to assess whether it must add interim non-firm NITS while network upgrades are built, plus permanent firm and non-firm contract demand services (NYISO at P 113). |
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MISO |
MISO’s existing services are NITS and firm/non-firm point-to-point transmission service (MISO Order at P 104). FERC directed MISO to assess interim non-firm NITS and permanent firm/non-firm contract demand services for flexible large loads (MISO Order at P 105). MISO is already considering incremental service until network upgrades are completed and other interim or non-firm service options in its stakeholder process (MISO Order at P 31). |
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CAISO |
CAISO does not offer Order No. 888 transmission services and instead has daily service where energy is generally treated as “new firm use” (CAISO Order at PP 101, 104). |
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ISO-NE |
ISO-NE’s existing services include regional network service, local network service, and firm/non-firm local point-to-point service (ISO-NE Order at P 102). FERC directed ISO-NE to assess interim non-firm network service and permanent firm/non-firm contract demand services for flexible large loads (ISO-NE Order at P 103). |
Interconnection Customers Serving Electrically Proximate Large Loads |
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PJM |
FERC found that PJM lacks generator-interconnection procedures or services reflecting a generator’s commitment to match output to an electrically proximate large load or large co-located load, or to limit injections using control/protection systems (PJM Order at P 95). FERC suggested three possible pathways: a new interim service tied to hourly load forecasts, use of existing Energy Resource Interconnection Service (ERIS) or Network Resource Interconnection Service at an existing point of interconnection with net-injection limits, and a new load-limited service for a new generating facility and new large co-located load with no injection (PJM Order at P 100). PJM must also address market/resource adequacy treatment for such generation in PJM’s energy/ancillary and capacity constructs (PJM Order at P 109). |
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SPP |
SPP has an existing HILLGA process, which FERC previously accepted as a flexible, expedited, separate serial interconnection process for generating facilities limited to serving a HILL in the same local areas (SPP Order at P 16). |
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NYISO |
NYISO’s order identifies no specific process for studying co-located generator and load interconnections, and NYISO’s generation cluster process is separate from its load-interconnection process (NYISO Order at P 33). FERC directed NYISO to assess new generator-interconnection study procedures/services for electrically proximate or large co-located loads, while making clear NYISO need not copy SPP’s HILLGA process exactly (NYISO Order at PP 121, 123). |
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MISO |
FERC found that MISO lacks generator-interconnection study procedures/services tailored to electrically proximate large loads or large co-located loads, notwithstanding MISO’s work on a zero-injection generator interconnection agreement concept (MISO Order at PP 98, 113). MISO must also address energy/ancillary services and capacity/resource adequacy treatment for such generation (MISO Order at P 127). |
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CAISO |
FERC found that CAISO lacks generator-interconnection procedures/services for electrically proximate large load or large co-located load (CAISO Order at P 13). FERC suggested the three pathways—matched-output interim service, use of existing ERIS/NRIS with net-injection limits, and a new no-injection load-limited service—while inviting CAISO-specific proposals (CAISO Order at P 113). CAISO’s additional briefing questions specifically ask about participation in CAISO energy/ancillary markets and, where applicable, resource-adequacy accounting and capacity-market treatment (CAISO Order at P 127). |
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ISO-NE |
FERC found that ISO-NE lacks generator-interconnection procedures/services reflecting a generator’s commitment to service electrically proximate or large co-located load (ISO-NE Order at P 111). ISO-NE must also address energy/ancillary-services participation and resource-adequacy/capacity-market treatment for generation serving electrically proximate or co-located large load (ISO-NE Order at P 124). |
Endnotes
[1] The secretary of the Department of Energy’s Advance Notice of Proposed Rulemaking (ANOPR) and FERC’s “Order Regarding Intent to Act” recognized the possibility (and strongly encouraged) “that PJM and/or Transmission Owners . . . may elect to address some or all of the issues discussed in [the PJM Order] by proposing revisions to [PJM’s tariff] pursuant to their applicable FPA section 205 filing rights.” Order Instituting Proceeding under Section 206 of the Federal Power Act, 195 FERC ¶ 61,211 at P 38 (2026) (PJM Order). FERC noted that if “PJM and/or the Transmission Owners submit a filing under FPA section 205, they should . . . explain which of the Commission’s . . . directives [in the PJM Order] their filing addresses and how it resolves them.” Id.
[2] Order Instituting Proceeding under Section 206 of the Federal Power Act, 195 FERC ¶ 61,213 at PP 1 n.2, 15, n.54 (2026) (SPP Order).
[3] Order Instituting Proceeding under Section 206 of the Federal Power Act, 195 FERC ¶ 61,216 at P 1, n.2 (2026) (NYISO Order).
[4] Order Instituting Proceeding under Section 206 of the Federal Power Act, 195 FERC¶ 61,212 at P 1, n.2 (2026) (MISO Order).
[5] Order Instituting Proceeding under Section 206 of the Federal Power Act, 195 FERC ¶ 61,214 at P 1, n.2 (2026) (CAISO Order).
[6] Order Instituting Proceeding under Section 206 of the Federal Power Act, 195 FERC ¶ 61,215 at P 1, n.2 (2026) (ISO-NE Order).
