EL26-71-000 · 2026-06-18 · FERC

CAISO show cause order

195 FERC ¶ 61,214 
UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
Before Commissioners:  Laura V. Swett, Chairman; 
                                        David Rosner, Lindsay S. See, 
                                        Judy W. Chang, and David LaCerte. 
 
California Independent System Operator Corporation 
Citizen S-Line Transmission LLC  
Citizens Sunrise Transmission LLC  
Citizens Sycamore-Penasquitos Transmission LLC  
City of Anaheim, California  
City of Azusa, California  
City of Banning, California  
City of Colton, California  
City of Pasadena, California  
City of Riverside, California 
DCR Transmission, L.L.C.  
DesertLink, LLC  
GridLiance West LLC  
Horizon West Transmission, LLC 
LS Power Grid California, LLC  
Morongo Transmission LLC  
Pacific Gas and Electric Company  
San Diego Gas & Electric Company  
Southern California Edison Company  
Startrans IO, L.L.C.  
SunZia Transmission, LLC  
Trans Bay Cable LLC  
Valley Electric Association, Inc.  
Viridon Path 15, LLC  
Western Area Power Administration 
Docket No.
 
EL26-71-000 
 
 
 
ORDER INSTITUTING PROCEEDING  
UNDER SECTION 206 OF THE FEDERAL POWER ACT 
 
(Issued June 18, 2026)

Docket No. EL26-71-000 
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Paragraph Numbers 
I. Background ..................................................................................................................... 6. 
A. Growth of Large and Co-Located Loads and ANOPR ............................................. 6. 
B. Recent Proceedings Addressing Large and Co-Located Loads .............................. 11. 
1. PJM Co-Location Proceedings ............................................................................ 12. 
2. SPP High Impact Large Load and High Impact Large Load Generation 
Assessment Process ................................................................................................. 15. 
3. SPP Conditional High Impact Large Load Service ............................................. 17. 
II. CAISO’s Existing Processes ........................................................................................ 19. 
A. Existing Tariff Processes ......................................................................................... 19. 
B. Recent Stakeholder Proceedings in CAISO ............................................................ 28. 
III. Discussion ................................................................................................................... 31. 
A. Transmission Service to Eligible Customers on Behalf of Large Loads ................ 38. 
1. Jurisdiction ........................................................................................................... 41. 
2. Tariff Provisions .................................................................................................. 48. 
B. Cost Shifting Risk Among Transmission Customers .............................................. 65. 
1. Jurisdiction ........................................................................................................... 67. 
2. Additional Cost Transparency ............................................................................. 70. 
3. Cost Recovery Agreements ................................................................................. 76. 
C. Co-Location Arrangements and Load with Behind the Meter Generation ............. 85. 
1. Definition ............................................................................................................. 87. 
2. Jurisdiction ........................................................................................................... 91. 
3. Tariff Provisions .................................................................................................. 93. 
D. Extending New Transmission Services to Eligible Customers Taking Service on 
Behalf of Flexible Large Loads ................................................................................. 103. 
E. Interconnection Customers Serving Electrically Proximate Large Load and Co-
Located Load .............................................................................................................. 106. 
F. Informational Report .............................................................................................. 120. 
IV. Briefing Questions .................................................................................................... 123.

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Over the past year, the Commission has taken action in numerous dockets1 to 
address issues related to (a) unprecedented increases in requests for transmission service 
to serve large loads2 and (b) growing interest in the co-location of loads with generating 
facilities (co-location arrangements3).  Separately, the Secretary of Energy (Secretary) 
released an advance notice of proposed rulemaking (ANOPR) in October 2025.  The 
ANOPR, issued pursuant to section 403 of the Department of Energy Organization Act,4 
directed the Commission to consider taking additional actions to address the addition of 
large and co-located loads to the transmission system.5  The records in these proceedings 
illustrate a host of urgent challenges associated with providing the transmission service 
needed to serve the ongoing influx of large loads while maintaining reliability and 
affordability.  In particular, stakeholders have expressed concerns that large loads are not 
efficiently and appropriately integrated onto the transmission system; have identified a 
 
1 See, e.g., PJM Interconnection, L.L.C., 190 FERC ¶ 61,115 (2025) (PJM Show 
Cause Order); PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2025) (PJM Co-
Location Order); Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026) (SPP HILL Order); 
Sw. Power Pool, Inc., 195 FERC ¶ 61,196 (2026) (SPP CHILLS Order); see also, e.g., 
Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025); Commonwealth Edison Co., 
194 FERC ¶ 61,181 (2026). 
2 As explained below, it appears that it would be reasonable to define a large load 
as (1) a new commercial or industrial customer, (2) located at a single site behind one or 
more points of interconnection, (3) that has a peak load of 50 MW or greater, (4) 
interconnects to the transmission system at a voltage level of greater than 69 kV, and (5) 
is not part of a co-location arrangement.  See infra P 57. 
3 As explained below, it appears that it would be reasonable to define co-located 
load as a configuration that refers to end-use customer load that is physically connected 
to the facilities of an existing or planned generating facility on the interconnection 
customer’s side of the point of interconnection to the RTO/ISO’s transmission system.   
In this order, we will use the term co-location arrangement when referring to both the   
co-located load and the associated generating facility.  See infra P 88. 
4 42 U.S.C. § 7173. 
5 See Interconnection of Large Loads to the Interstate Transmission System, 
Advance Notice of Proposed Rulemaking, Docket No. RM26-4-000 (Oct. 23, 2025) 
(ANOPR); see also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy, Docket No. 
RM26-4-000 (Oct. 23, 2025).  The ANOPR uses the term “hybrid facilities,” which it 
explains are large loads that “share a point of interconnection with new or existing 
generation facilities.”  ANOPR at P 12.  In this order, as explained below, we use the 
term co-located load.

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number of unique challenges that large load integration poses for the reliable operation of 
that system; and have debated how best to ensure that the rates, terms, and conditions of 
transmission service remain just and reasonable as more and more large loads are 
onboarded onto that system.6  The records in these proceedings likewise present serious 
concerns about the lack of clarity and consistency in Regional Transmission Organization 
or Independent System Operator (RTO/ISO) tariffs—including with respect to the rates, 
terms, and conditions of service that apply to flexible large loads, co-location 
arrangements, load with behind the meter generation, and generating facilities with 
electrically proximate large load7 or co-located load.  
 
The findings in several recent Commission proceedings establish the foundations 
of a just and reasonable framework for addressing these concerns and ensuring the 
timely, efficient, and reliable integration of large and co-located loads onto the 
transmission system.  For example, Southwest Power Pool, Inc. (SPP) has recently taken 
a number of innovative and proactive steps to address the challenges of integrating large 
loads, co-located loads, and/or generation and electrically proximate large load onto the 
transmission system while ensuring that its tariff remains just and reasonable, and PJM 
Interconnection, L.L.C. (PJM) has likewise taken steps toward that goal in response to 
this Commission’s directives.8  By contrast, in the California Independent System 
Operator Corporation (CAISO) region, neither CAISO nor a significant number of the 
 
6 Throughout this order we rely on comments and answers filed in response to the 
ANOPR in Docket No. RM26-4-000 and all referenced comments in this order were filed 
in that docket, unless otherwise noted.  A full list of commenter names and abbreviations 
is attached to this order as an Appendix.  Additionally, we have relied on the discussions 
held in the Federal and State Current Issues Collaborative in Docket No. AD24-7-000 
(NARUC Collaborative).  All entities who wish to participate in this docket, regardless of 
participation in the ANOPR proceeding or NARUC Collaborative, should file to 
intervene in Docket No. EL26-71-000. 
7 As explained below, for purposes of this order, an “electrically proximate large 
load” is a large load, as defined in this order, that is sufficiently electrically close to the 
interconnection customer’s requested point of interconnection, such that the impact on 
the transmission system of the combination of the generating facility and the load, with 
the exception of the transmission facilities between the two, will be effectively the same 
as if they were located at the same substation (e.g., large load that is located no more than 
two substations away from the generating facility).  See infra P 112. 
8 PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order,           
193 FERC ¶ 61,217, order on reh’g, 195 FERC ¶ 61,209 (2026) (PJM Co-Location 
Rehearing Order); SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order,            
195 FERC ¶ 61,196.

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Participating Transmission Owners9 have filed proposals to address the challenges 
associated with the integration of large and co-located loads.10   
 
As discussed below, we find that CAISO’s existing Open Access Transmission 
Tariff (Tariff) and/or the Transmission Owner Tariffs (TO Tariffs) of the Participating 
Transmission Owners appear to be unjust, unreasonable, or unduly discriminatory or 
preferential.  We thus institute a show cause proceeding pursuant to section 206 of the 
Federal Power Act (FPA),11 and we direct CAISO and the Participating Transmission 
Owners, within 60 days of the date of this order, to either:   
(1) show cause as to why their tariffs remain just and reasonable and not unduly 
discriminatory or preferential without provisions addressing:   
(a) the application process, study procedures, and ongoing operational 
requirements that apply to Eligible Customers12 seeking transmission 
service on behalf of large loads;  
 
9 Participating Transmission Owners refers to the entities listed in the caption of 
this order.  Although DATC Path 15, LLC is listed as a signatory to the Transmission 
Control Agreement in CAISO’s Tariff, Viridon Path 15 LLC succeeded DATC Path 15, 
LLC on March 28, 2025.  We recognize the Participating Transmission Owners include 
entities that are not subject to the Commission’s jurisdiction because they are not public 
utilities pursuant to section 201(f) of the FPA.  See 16 U.S.C. § 824(f); City of Anaheim, 
171 FERC ¶ 61,263, at PP 19-22 (2020).  Although the Commission retains the authority 
to review those entities’ formula rates to ensure that CAISO’s rates remain just and 
reasonable, we acknowledge that those entities are not subject to the Commission’s 
jurisdiction over public utilities pursuant to section 201(f) of the FPA.  However, we have 
included them here because their Transmission Owner Tariffs on file with the 
Commission detail the wholesale load interconnection process in CAISO.  If a non-public 
utility wishes to be removed from this proceeding, we will rescind the show cause order 
against them at their request, and we expect CAISO to respond to this order regarding the 
non-public utility’s CAISO Tariff provisions on file with the Commission.  See Sw. 
Power Pool, Inc., 180 FERC ¶ 61,022, at P 40 (2022).   
10 We note that certain Participating Transmission Owners have made filings 
related to these challenges.  See, e.g., GridLiance West LLC, Filing, Docket No.      
ER26-2272-000 (filed Apr. 21, 2026) (proposing tariff revisions to extend its existing 
interconnection procedures to end-use customers).  
11 16 U.S.C. § 824e. 
12 CAISO’s Tariff defines Eligible Customer as:

Docket No. EL26-71-000 
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(b) additional transparency concerning the network upgrade13 costs to 
provide transmission service to Eligible Customers on behalf of large loads; 
and a pro forma cost recovery agreement between CAISO, the relevant 
transmission owner, and Eligible Customer taking transmission service on 
behalf of the large load to mitigate the risk of cost shifting among 
transmission customers, and a mechanism to ensure such payments are 
appropriately credited toward transmission owners’ transmission revenue 
requirements consistent with the Commission’s cost-of-service regulations; 
(c) the rates, terms, and conditions of service that apply to co-location 
arrangements;  
(d) transmission services that reflect Eligible Customers taking 
transmission service on behalf of co-located loads, load with behind the 
meter generation, and flexible large loads that are willing and able to limit 
their use of the transmission system under certain conditions;14 and 
 
(i) any utility (including Participating [Transmission Owners], 
Market Participants and any power marketer), federal power 
marketing agency, or any person generating Energy for sale 
or resale . . . ; and (ii) any retail customer taking unbundled 
transmission service pursuant to a state retail access program 
or pursuant to a voluntary offer of unbundled retail 
transmission service by the Participating [Transmission 
Owner]. 
CAISO, CAISO eTariff, app. A (Definitions), Eligible Customer (1.0.0) (CAISO Tariff).  
However, under the CAISO Tariff, Scheduling Coordinators must identify the Eligible 
Customers they represent.  Id. § 4.5.2 (Eligible Customers and Convergence Bidding 
Entities) (1.0.0), 4.5.2.1.  Therefore, as CAISO explains and as discussed below, demand 
is met through the market participation of Scheduling Coordinators.  CAISO, Large Load 
Considerations Issue Paper 11 (Jan. 30, 2026), https://www.caiso.com/documents/issue-
paper-large-load-consideration-jan-20-2026.pdf (CAISO Large Load Issue Paper).   
13 The term network upgrades is used throughout this order to refer to 
modifications or additions to transmission-related facilities that are integrated with and 
support the overall transmission system.  See pro forma OATT § 1.27 (Definitions – 
Network Upgrades).  We note that CAISO’s definition of Network Upgrades applies only 
to additions, modifications, and upgrades required to accommodate the interconnection of 
generating facilities.  See CAISO Tariff, app. A (Definitions), Network Upgrades (0.0.0). 
14 As explained below, for purpose of this order, “flexible” large loads are a subset 
of large loads, as used in this order, that are not co-located with generation, but are

Docket No. EL26-71-000 
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(e) the rates, terms, and conditions of service applicable to interconnection 
customers serving electrically proximate large load or co-located load; or 
(2) explain what changes to their tariffs would remedy the identified concerns if 
the Commission were to determine that the tariffs have in fact become unjust and 
unreasonable or unduly discriminatory or preferential and, therefore, proceeds to 
establish a replacement tariff.   
 
We are also concerned with CAISO’s need to ensure adequate generation to serve 
new large loads.15  We therefore direct CAISO to submit, within 30 days of the date of 
issuance of this order, an informational report on how CAISO intends to ensure that 
adequate generation will be available to serve existing and new large loads, as detailed 
later in this order.   
 
We recognize that large loads, including data centers, are actively working with 
transmission owners and other relevant entities to interconnect to, and to take service 
from, the transmission system.  We appreciate that different large loads are currently at 
different stages of that process.  We also understand that large loads and Eligible 
Customers taking transmission service on behalf of large loads are negotiating, entering 
into, and/or have executed various agreements related to interconnecting to the 
transmission system and/or the provision of transmission service.  This proceeding is not 
intended to disrupt existing commercial arrangements, but rather to establish prospective 
reforms.  Accordingly, any tariff revisions offered by CAISO and/or the Participating 
Transmission Owners in response to this proceeding should (a) propose a reasonable 
implementation period to ensure minimal disruption to such existing commercial 
arrangements, and (b) allow a reasonable amount of time to finalize ongoing agreements 
that are nearing completion as of the date such tariff provisions are filed with the 
Commission.  Such proposed tariff revisions should include a reasonable effective date 
that accommodates such considerations regarding these existing commercial 
arrangements. 
 
willing and able to limit their energy withdrawals from the transmission system under 
certain conditions.  See infra note 218. 
15 Cf. PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 237-239 (highlighting 
PJM’s ongoing Critical Issue Fast Path stakeholder process to consider proposals to help 
integrate large load additions without causing resource inadequacy and directing an 
informational report on the status of those proposals).

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I. 
Background 
A. 
Growth of Large and Co-Located Loads and ANOPR 
 
As the Secretary explained in the ANOPR, electricity demand in the United States 
is expected to grow at an extraordinary pace in the near term, largely due to the rapid 
growth of large loads.16  The Secretary highlighted findings from the North American 
Electric Reliability Corporation (NERC) that show that demand growth is now higher 
than at any point in the past two decades, driven in part by increasing quantities of large 
commercial and industrial load, most notably data centers, connecting rapidly to the 
transmission system.17  The Secretary also highlighted NERC’s conclusion that the size 
and speed with which data centers can be connected to the grid present unique challenges 
for demand forecasting and system planning.  The ANOPR proposed that, in light of the 
unprecedented current and expected growth of large loads seeking to interconnect to the 
transmission system, the Commission should standardize interconnection procedures and 
agreements for large loads, including those that seek to share a point of interconnection 
with new or existing generation facilities.18 
 
On April 16, 2026, the Commission issued an order regarding its intent to act with 
respect to the ANOPR docket.19  In that order, the Commission explained that it agreed 
with the Secretary “that, ‘[i]n light of the unprecedented current and expected growth of 
large loads’ such as data centers, there is an urgent need for thoughtful reforms to ensure 
that large loads are ‘able to connect to the transmission system in a timely, orderly, and 
 
16 ANOPR at 2 (citing U.S. Dep’t of Energy, Resource Adequacy Report: 
Evaluating the Reliability & Security of the United States Electric Grid (July 2025), 
www.energy.gov/sites/default/files/2025-
07/DOE%20Final%20EO%20Report%20%28FINAL%20JULY%207%29.pdf). 
17 Id. (citing NERC, 2024 Long- Term Reliability Assessment 8 (Dec. 2024, 
updated July 2025), 
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Long%2
0Term%20Reliability%20Assessment_2024.pdf). 
18 Id. P 12.  For example, the ANOPR proposed that load and hybrid facilities 
should be studied together with generating facilities, observing that “siting a large load 
near or at the same point of interconnection as a new generating facility could reduce the 
network upgrades needed to interconnect only the load or only the generating facility.”  
ANOPR at P 20. 
19 Interconnection of Large Loads to the Interstate Transmission Sys., 195 FERC   
¶ 61,045 (2026) (Order Regarding Intent to Act).

Docket No. EL26-71-000 
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non-discriminatory manner.’”20  After recognizing the Commission’s recent actions in 
proceedings involving issues associated with large loads,21 the Commission concluded 
that it was clear that additional “action is warranted to support further progress where it is 
needed.”22 
 
CAISO’s comments in response to the ANOPR recognize the growth of large 
loads and highlight the challenges that the integration of large loads poses to transmission 
system operations given those loads’ size, operational behavior, and unique potential to 
impact the transmission system.23  A number of large load projects are underway in the 
CAISO footprint.  Those projects have been driven by a number of factors, including data 
center development, electric vehicle charging, and electrification of agricultural and 
industrial processes, among others.24  Further, as of January 2026, the California Energy 
Commission forecasts data center load in the CAISO balancing authority area to increase 
by 1.8 GW by 2030 and 4.9 GW by 2040.25  PG&E indicates that by the end of 2024, the 
megawatts attributable to large load customers in its region who were requesting 
transmission-level interconnections exceeded existing transmission-level customers’ 
megawatts by 4,000%.26  Southern California Edison also notes that it has seen an 
increase in data centers in its service territory.27 
 
20 Id. P 2. 
21 Id. (citing PJM Co-Location Order, 193 FERC ¶ 61,217; SPP HILL Order, 194 
FERC ¶ 61,031; Commonwealth Edison Co., 194 FERC ¶ 61,181; Tri-State Generation 
& Transmission Ass’n, 193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, LLC, 193 
FERC ¶ 61,237). 
22 Id. PP 3-4. 
23 CAISO November 21 ANOPR Comments at 3-4; see also CAISO Large Load 
Issue Paper at 13-14; Southern California Edison December 5 ANOPR Comments at 3-4 
(noting concern about reliability and resource adequacy challenges due to large load 
additions).  
24 CAISO Large Load Issue Paper at 3.  
25 Id. at 8. 
26 PG&E November 21 ANOPR Comments at 3. 
27 Southern California Edison December 5 ANOPR Comments at 3.

Docket No. EL26-71-000 
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While CPUC asserts that issues related to large and co-located load integration are 
better addressed at the state level in CAISO,28 and PG&E asserts that CAISO’s existing 
processes work well,29 many entities in CAISO suggest that additional reform is needed.  
CAISO and PG&E generally support standardized study process requirements, as 
contemplated in the ANOPR with accommodation for regional variations, for large loads 
and co-location arrangements.30  CAISO also supports establishing operational and 
information sharing requirements for large loads to ensure reliability and help prevent 
cost shifting.31  CAISO likewise supports efforts to ensure that co-located loads pay for 
ancillary services from which they benefit.32  CAISO and California DWR note the 
benefit of encouraging flexible or curtailable loads to help avoid unnecessary network 
upgrades or new generation.33  California DWR also raises concerns about cost shifting 
where network upgrades are built to support large load additions that do not materialize 
as planned.34  CPUC supports additional transparency related to the addition of large 
loads, particularly for the costs of network upgrades associated with large load 
additions.35 
 
Moreover, many commenters in the ANOPR proceeding filed persuasive 
comments documenting, generally, the need for clear and consistent tariff provisions to 
 
28 See generally CPUC November 21 ANOPR Comments at 1-4; see also PG&E 
November 21 ANOPR Comments at 3-7 (detailing and explaining the advantages of 
PG&E’s state-level rules).  
29 PG&E November 21 ANOPR Comments at 12. 
30 CAISO November 21 ANOPR Comments at 7-8; PG&E November 21 ANOPR 
Comments at 14 (noting that standardized requirements could be effective to address 
speculative projects and provide transmission providers with useful information). 
31 CAISO November 21 ANOPR Comments at 9-11. 
32 Id. at 15-16. 
33 Id. at 15; California DWR November 21 ANOPR Comments at 3-6; see also 
PG&E November 21 ANOPR Comments at 16 (recognizing benefits of large and         
co-located load flexibility). 
34 California DWR November 21 ANOPR Comments at 8; see also CPUC 
November 21 ANOPR Comments at 16 (noting that it supports ratepayer protections and 
efforts to mitigate risk of cost shifting); Southern California Edison December 5 ANOPR 
Comments at 3 (supporting protections to prevent cost shifting to other customers). 
35 CPUC December 5 ANOPR Comments at 16-19.

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ensure regulatory and process certainty, fairness and consistency, and efficiency as large 
and co-located loads are added to the transmission system in increasing numbers.36  
There is also broad support for rules that help to ensure that other transmission customers 
are not unfairly burdened with additional costs or reliability impacts as large and co-
located loads interconnect to the transmission system.37  In addition, many ANOPR 
commenters highlighted the need to efficiently integrate large loads, particularly data 
centers, to support national security priorities and economic development.38   
B. 
Recent Proceedings Addressing Large and Co-Located Loads 
 
Over the past year, the Commission has begun to address, both sua sponte and in 
response to complaints and FPA section 20539 filings, the growing use of co-location 
arrangements.40  The Commission’s orders in those proceedings have addressed the need 
 
36 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; 
Calibrant November 21 ANOPR Comments at 1-3; CEBA November 21 ANOPR 
Comments at 9-11; Constellation November 21 ANOPR Comments at 6; DCC November 
21 ANOPR Comments at 3-4; ECA November 21 ANOPR Comments at 7-11; EPSA 
November 21 ANOPR Comments at 4-6; Infrastructure Masons December 5 ANOPR 
Comments at 4-7; Microsoft November 21 ANOPR Comments at 9-10; National Grid 
November 21 ANOPR Comments at 7; ODEC December 5 ANOPR Comments at 2-4; R 
Street November 21 ANOPR Comments at 3; Switch December 5 ANOPR Comments at 
3; Tract November 21 ANOPR Comments at 5; Vantage November 21 ANOPR 
Comments at 5-6; Vistra December 5 ANOPR Comments at 1-2. 
37 See, e.g., APPA November 21 ANOPR Comments at 6; Buckeye November 21 
ANOPR Comments at 17; Exelon November 21 ANOPR Comments at 10; Kansas 
Commission November 21 ANOPR Comments at 12; NCSL November 21 ANOPR 
Comments at 1; NRECA November 21 ANOPR Comments at 8-9; NY UIU November 
21 ANOPR Comments at 3; OCC November 21 ANOPR Comments at 9; Oklo 
December 5 ANOPR Comments at 3; Southeast PIOs December 5 ANOPR Comments 
11-15; State Entities November 21 ANOPR Comments at 7-8; Tri-State November 21 
ANOPR Comments at 8; UCS November 21 ANOPR Comments at 9-11; U.S. 
Representatives November 21 ANOPR Comments at 1. 
38 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; 
DCC November 21 ANOPR Comments at 3; ECA November 21 ANOPR Comments at 
6; Geronimo November 21 ANOPR Comments at 1-2; Google November 21 ANOPR 
Comments at 2-3; Verrus December 5 ANOPR Comments at 2. 
39 16 U.S.C. § 824d. 
40 See PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order,    
193 FERC ¶ 61,217, order on reh’g, PJM Co-Location Rehearing Order, 195 FERC

Docket No. EL26-71-000 
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for clear and consistent tariff provisions regarding the rates, terms, and conditions of 
service that apply to co-location arrangements and for transmission services that reflect 
Eligible Customers taking transmission service on behalf of co-located loads and load 
with behind the meter generation that are willing and able to limit their energy 
withdrawals from the transmission system under certain conditions.  Several other 
Commission proceedings have addressed the challenges of integrating large loads onto 
the transmission system, including the need for clear and consistent tariff provisions 
regarding the provision of transmission service to Eligible Customers on behalf of large 
loads and for interconnection customers serving electrically proximate large load.  As 
explained below, these proceedings provide examples that will help to ensure that 
jurisdictional transmission service is provided in a manner that is just and reasonable and 
maintains reliability as large loads are integrated onto the transmission system and co-
location arrangements become more common.  It is in this context that the Commission 
now considers whether CAISO’s Tariff and/or the TO Tariffs remain just and reasonable 
without similar provisions. 
1. 
PJM Co-Location Proceedings 
 
On February 20, 2025, the Commission initiated a show cause proceeding against 
PJM and the PJM transmission owners regarding the lack of tariff provisions addressing 
with sufficient clarity or consistency the rates, terms, and conditions of service that apply 
to co-location arrangements.41  The Commission explained when initiating that 
proceeding that the absence of such provisions may leave entities unable to determine 
what steps they can or must take to effectuate co-location arrangements of various 
configurations and how to do so in a manner that is just and reasonable.42  On December 
18, 2025, the Commission found that PJM’s tariff was indeed unjust and unreasonable 
because it does not contain provisions addressing with sufficient clarity or consistency 
the rates, terms, and conditions of service that apply to interconnection customers serving 
 
¶ 61,209; SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC ¶ 
61,196. 
41 See PJM Show Cause Order, 190 FERC ¶ 61,115. 
42 Id. P 74.  The PJM Show Cause Order defined co-located load as a 
“configuration [that] refers to end-use customer load that is physically connected to the 
facilities of an existing or planned Customer Facility on the Interconnection Customer’s 
side of the Point of Interconnection (‘POI’) to the PJM Transmission System.”  Id. P 3 
n.4.

Docket No. EL26-71-000 
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co-located load and Eligible Customers taking transmission service on behalf of co-
located load.43   
 
Specifically, the Commission found that the PJM tariff was unjust and 
unreasonable because there is a lack of sufficient clarity or consistency as to the rates, 
terms, and conditions of service that apply to interconnection customers serving co-
located load.44  The Commission also found that PJM’s tariff was unjust and 
unreasonable because it does not include transmission services that reflect Eligible 
Customers taking transmission service on behalf of co-located loads that are willing and 
able to limit their energy withdrawals from the transmission system under certain 
conditions.45  Additionally, the Commission found that PJM’s behind the meter 
generation rules were no longer just and reasonable.46  The Commission directed PJM to 
file a compliance filing to revise its tariff:  (1) to set forth specific terms and conditions 
that an interconnection customer in PJM seeking to serve co-located load must follow in 
order to effectuate a co-location arrangement;47 (2) to require that the Eligible Customer 
taking transmission service on behalf of co-located load takes one of three transmission 
services:  (a) network integration transmission service (NITS) or a new interim, non-firm 
transmission service while network upgrades to provide full NITS service are constructed 
(interim NITS); (b) a new firm contract demand transmission service; or (c) a new non-
firm contract demand transmission service;48 (3) to revise the behind the meter generation 
rules and implement a transition process for existing behind the meter generation 
participants;49 and (4) to make several clarifications on how certain aspects of PJM’s 
generator interconnection process apply to interconnection customers seeking to serve  
co-located load.50   
 
43 PJM Co-Location Order, 193 FERC ¶ 61,217. 
44 Id. P 176.  
45 Id. P 177. 
46 Id. P 179. 
47 Id. PP 187-192, 225-230. 
48 Id. PP 193-218.  The Commission also established a paper hearing to determine 
the just and reasonable rates, terms, and conditions for the new transmission services.  Id. 
PP 219-220. 
49 Id. PP 221-224.  
50 Id. PP 161, 231-236.

Docket No. EL26-71-000 
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On June 18, 2026, concurrently with the instant order, the Commission issued an 
order modifying the discussion in the PJM Co-Location Order and setting aside the order 
in part; accepting in part and rejecting in part PJM’s compliance filing, and directing a 
further compliance filing; and establishing as just and reasonable certain rates, terms, and 
conditions for the new transmission services (i.e., interim NITS, firm contract demand 
transmission service, and non-firm contract demand transmission service).51 
2. 
SPP High Impact Large Load and High Impact Large Load 
Generation Assessment Process 
 
On January 14, 2026, the Commission accepted revisions to SPP’s tariff to add a 
high impact large load (HILL) study process and High Impact Large Load Generation 
Assessment (HILLGA) process.52  SPP’s tariff revisions established HILLs as a new 
category of load;53 imposed enhanced study requirements to enable SPP to assess the 
HILL’s reliability impacts on the transmission system;54 and created additional, ongoing 
 
51 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 7-9.  PJM’s 
compliance filing proposing revisions in response to the Commission’s directives 
regarding clarification that certain aspects of PJM’s generator interconnection process 
apply to interconnection customers seeking to serve co-located load was accepted in part 
on April 16, 2026.  PJM Interconnection, L.L.C., 195 FERC ¶ 61,030 (2026). 
52 SPP HILL Order, 194 FERC ¶ 61,031 at PP 61, 64.   
53 SPP defines a HILL as:   
A new commercial or industrial load, or increase in 
commercial or industrial load, at a single site connected 
through one or more shared Points of Interconnection (POIs) 
or delivery points, where such load is either (1) 10 MW or 
more if connected to the Transmission System at a voltage 
level less than or equal to 69 [kilovolts (kV)]; or (2) 50 MW 
or more if connected to the Transmission System at a voltage 
level greater than 69 kV.  An Electric Storage Resource is not 
considered a HILL.  
SPP, Open Access Transmission Tariff, Sixth Revised Vol. No. 1, pt. I, § 1 (Definitions 
H) (1.0.0). 
54 SPP HILL Order, 194 FERC ¶ 61,031 at PP 13-17 (explaining that the HILL 
process requires up to three additional studies beyond those required of all transmission 
service requests for transmission customers requesting to add or modify a delivery point 
associated with a HILL, including a HILL delivery point study, HILL supplemental load

Docket No. EL26-71-000 
- 15 - 
operational requirements for transmission customers serving HILLs to ensure continued 
reliability of the transmission system.55  The tariff revisions also established the HILLGA 
process, a new generator interconnection service and related interconnection process to 
facilitate the prompt interconnection of generating facilities that are specifically identified 
for, and limited to, serving a HILL and are located no more than two substations away 
from the HILL.56   
 
The Commission stated that SPP demonstrated that the “unprecedented growth in 
large loads in the SPP region presents significant and unique operational and planning 
challenges.”57  The Commission found that SPP demonstrated that its proposed HILL 
process was a just and reasonable approach for integrating transmission customers’ new 
large loads onto SPP’s transmission system in a reliable manner.58  The Commission 
found that it was reasonable to impose additional study requirements and other proposed 
requirements given the unique operating characteristics of HILLs.  The Commission 
further found that the proposed study requirements would ensure the reliable integration 
of the transmission customer’s HILLs onto SPP’s transmission system and would provide 
SPP with information about their impact on SPP’s transmission system, including the 
transmission system’s ability to withstand and control disturbances by the HILL at the 
 
connection study, and potential supplemental Electromagnetic Transient study). 
55 Id. P 18 (explaining that market participants registering a HILL must (1) follow 
all nonconforming load requirements (e.g., additional load forecast requirements); (2) 
provide load data via telemetry in real time; (3) have remote capability to disconnect the 
load from the transmission system made available to the transmission operator; (4) have 
an up/down ramp rate not exceeding 20 MW per minute unless otherwise directed; (5) 
include additional information with registration; and (6) not have withdrawals from the 
transmission system without appropriate transmission service); id. P 19 (explaining that 
the transmission owner, at the transmission customer’s expense, must install a phasor 
measurement unit or similar equipment); id. PP 20-21 (explaining that the transmission 
customer will be required to comply with ride-through requirement guidelines). 
56 Id. P 27 (explaining that, under the HILLGA process, SPP proposes to study 
HILLGA requests to determine whether any network upgrades are needed to 
accommodate the generating facility’s injection to the local area); id. P 32 (explaining 
that SPP will grant HILLGA customers a new type of interconnection service, load 
limited resource interconnection service, which grants limited interconnection service 
solely to serve the associated HILL).  
57 Id. P 60. 
58 Id. P 61.

Docket No. EL26-71-000 
- 16 - 
point of interconnection.59  In addition, the Commission found that the proposed study 
deposits would discourage speculative HILL study requests.60  Finally, the Commission 
concluded that the proposed ongoing reliability requirements would allow SPP to 
maintain reliable operation of its transmission system by increasing SPP’s visibility, 
providing necessary data, and imposing real-time operational safeguards for HILLs.61  In 
accepting HILLGA, the Commission found that “SPP’s HILLGA process reasonably 
provides a flexible, expedited, and separate serial interconnection process that will 
facilitate the prompt interconnection of generating facilities that are limited to serving a 
HILL in the same local area.”62   
3. 
SPP Conditional High Impact Large Load Service 
 
On June 5, 2026, the Commission accepted revisions to SPP’s tariff to add a new 
type of non-firm transmission service, conditional high impact large load service 
(CHILLS).63  CHILLS allows transmission customers serving HILLs to reliably receive 
transfers of energy until sufficient designated resources and/or network upgrades are in 
place to support long-term, firm transmission service.64  CHILLS is an as-available 
transmission service that will transfer energy to designated points of delivery to serve the 
portion of a HILL eligible to receive CHILLS, subject to curtailment and interruption.65  
CHILLS has a maximum term of seven years, which is intended to incentivize 
transmission customers seeking CHILLS to obtain the designated resources and/or 
 
59 Id. P 62. 
60 For the HILL delivery point study, SPP required a $10,000 non-refundable 
application fee and a $100,000 study deposit, with an additional $200,000 study deposit if 
an Electromagnetic Transient study was also required.  Id. P 15.  For the HILL 
supplemental load connection study, SPP allows the host transmission owner to require a 
$25,000 study deposit.  Id. P 16. 
61 Id. P 63. 
62 Id. P 64. 
63 SPP CHILLS Order, 195 FERC ¶ 61,196 at P 1. 
64 Id. P 7.  
65 Id. PP 9-10.

Docket No. EL26-71-000 
- 17 - 
complete the network upgrades needed to procure long-term firm transmission service 
through existing tariff processes.66   
 
The Commission found that SPP had shown that unprecedented growth in large 
loads presents significant and unique operational and planning challenges.67  The 
Commission also found that SPP’s ability to add HILLs to its transmission system in a 
timely manner may be limited due to delays in obtaining sufficient designated resources 
and completing network upgrades needed to provide long-term firm transmission service 
to such load.68  The Commission concluded that CHILLS is a just and reasonable and not 
unduly discriminatory or preferential approach to addressing the need to expeditiously 
interconnect and provide transmission service to new HILLs, while maintaining the 
reliable operation of SPP’s transmission system.69 
II. 
CAISO’s Existing Processes 
A. 
Existing Tariff Processes 
 
Unlike other regions, CAISO does not offer traditional Order No. 88870 network 
and point-to-point transmission services, offers no firm, long-term transmission 
reservations of capacity, and does not provide a formal application process for 
transmission service.71  Instead, CAISO offers a single “daily” transmission service     
 
66 Id. P 9. 
67 Id. P 84. 
68 Id. 
69 Id. 
70 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 (1996) (cross-
referenced at 75 FERC ¶ 61,080), order on reh’g, Order No. 888-A, FERC Stats. & Regs. 
¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), order on reh’g, Order No. 888-B,      
81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), 
aff’d in relevant part sub nom. Transmission Access Pol’y Study Grp. v. FERC, 225 F.3d 
667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002). 
71 See Cal. Indep. Sys. Operator Corp., 123 FERC ¶ 61,180, at P 7 n.8 (2008) 
(CAISO).

Docket No. EL26-71-000 
- 18 - 
that is available to all Eligible Customers on a day-to-day basis.72  All energy that is 
transmitted under CAISO’s Tariff that is not associated with historical rights or certain 
wheeling transactions is treated as “new firm use,” and those accessing the CAISO-
controlled transmission system cannot reserve transmission capacity beyond the         
day-ahead time frame.73   
 
In CAISO’s transmission service model, Scheduling Coordinators represent 
Eligible Customers and submit bids, or self-schedules, for supply or demand for energy 
to CAISO.74  Scheduling Coordinators have equal access to all available transmission 
capacity each day and CAISO uses the submitted bids for supply and demand to dispatch 
the market making use of all available transmission capacity.  If there is not enough 
available transmission capacity, CAISO curtails schedules based upon Tariff-defined 
scheduling priorities.75    
 
The processes for studying load additions in the CAISO footprint are not detailed 
in CAISO’s Tariff.  Rather, CAISO’s Participating Transmission Owners play the lead 
role in managing the interconnection of load to the transmission system and have their 
own study processes and requirements for such interconnections.76  CAISO’s primary 
role with respect to load additions is to account for state-projected additions of load in its 
Transmission Planning Process (TPP).77  CAISO operates under the assumption that if 
transmission infrastructure is developed to serve new loads as contemplated in the TPP, 
the market will reliably meet demand.78   
 
The TPP is conducted annually and is highly integrated with state processes and 
forecasts, including the California Energy Commission’s development of a statewide 
electricity demand forecast and CPUC’s development of integrated resource plans.79  In 
 
72 Id. P 7. 
73 Id. 
74 CAISO Tariff, § 4.5.3 (Responsibilities of a Scheduling Coordinator) (11.0.0). 
75 See CAISO, 123 FERC ¶ 61,180 at PP 7-8; Cal. Indep. Sys. Operator Corp.,  
185 FERC ¶ 61,085, at P 5 (2023). 
76 CAISO Large Load Issue Paper at 3, 5-6. 
77 Id. at 8-10.  CAISO incorporates the California Energy Commission’s demand 
forecast into the TPP. 
78 Id. at 9, 11. 
79 CAISO collaborates with the California Energy Commission and CPUC on

Docket No. EL26-71-000 
- 19 - 
the TPP, CAISO approves transmission solutions, which include new transmission 
facilities and network upgrades or additions to existing transmission facilities, to meet 
needs identified by CAISO.80  The TPP is conducted in three phases:  In Phase 1, CAISO 
develops planning assumptions and a study plan; in Phase 2, CAISO completes the 
comprehensive transmission plan; and, in Phase 3, CAISO evaluates proposals to 
construct and own certain network upgrades or additions.81   
 
To address load additions that occur after the development of the demand forecast 
and CPUC resource portfolios, the Participating Transmission Owners may propose 
transmission solutions and network upgrades in the TPP.82  Those proposed solutions and 
network upgrades must be submitted to CAISO for concurrence that the load 
interconnection and potential network upgrades to interconnect the load meet 
transmission reliability requirements and are consistent with the long-term transmission 
plans in the area.  The Participating Transmission Owners construct and own the resulting 
network upgrades.83  
 
Costs of transmission additions or network upgrades are borne by the Participating 
Transmission Owner that will be the owner of the transmission addition or network 
upgrade, and the Participating Transmission Owner incorporates those costs into its 
transmission revenue requirement.84  A Participating Transmission Owner’s transmission 
revenue requirement is divided into regional (high voltage) and local (low voltage) 
components that are under CAISO’s operational control.85  The Participating 
 
electric system planning through a memorandum of understanding.  See CAISO 
November 21 ANOPR Comments at 6-7 (citing Memorandum of Understanding Between 
CPUC and the California Energy Commission and CAISO Regarding Transmission and 
Resource Planning and Implementation (Dec. 2022), 
https://www.caiso.com/Documents/ISO-CEC-and-CPUC-Memorandum-of-
Understanding-Dec-2022.pdf). 
80 See CAISO Tariff, § 24.1 (Overview) (3.0.0). 
81 See id. § 24.2 (Nature of the Transmission Planning Process) (8.0.0). 
82 CAISO Large Load Issue Paper at 9-10. 
83 CAISO only considers the transmission aspect of solutions in the TPP.  
84 CAISO Tariff, § 24.14.2 (Cost of Needed Addition or Upgrade to be Borne by 
PTO) (0.0.0). 
85 In CAISO, low voltage facilities are considered to be under 200 kV and 
therefore included in the local transmission revenue requirement; facilities 200 kV and 
greater are included in the regional transmission revenue requirement.  See id. app. F

Docket No. EL26-71-000 
- 20 - 
Transmission Owners recover their transmission revenue requirement through the Access 
Charge, also referred to as the Transmission Access Charge.86  The Participating 
Transmission Owners directly collect the local component of their transmission revenue 
requirement from customers in their service area, referred to as the Local Access Charge, 
while the regional component of the transmission revenue requirement of every 
Participating Transmission Owner is combined together and divided by gross load to 
develop a “postage stamp” rate that is assessed to all market participants volumetrically, 
known as the Regional Access Charge.  CAISO collects the Regional Access Charge and 
then remits the monies associated with costs recovered to the Participating Transmission 
Owners.87   
 
The TO Tariffs include the physical interconnection process for requests to 
interconnect wholesale load that is eligible to request interconnection under FPA section 
210(a) directly to the CAISO-controlled grid.88  While there is no pro forma TO Tariff, 
the majority of the TO Tariffs contain similar sections regarding the interconnection 
process and, with limited exceptions, are structured identically.  Each TO Tariff provides 
that the Participating Transmission Owner will review interconnection applications from 
eligible entities to determine whether a System Impact Study is necessary.89  If 
conducted, the System Impact Study may indicate that a Facilities Study, which the 
Participating Transmission Owner will conduct in accordance with its TO Tariff, is 
 
(Rate Schedules) (30.0.0), § 12.1(a)(i). 
86 CAISO’s Tariff provides that “[t]he Access Charge includes the Regional 
Access Charge and the Local Access Charge.  The Access Charge will recover the 
Participating [Transmission Owners’] Transmission Revenue Requirement in accordance 
with Appendix F, Schedule 3.”  See id. app. A (Definitions), Access Charge (1.0.0). 
87 See id. § 26.1 (Access Charges) (8.0.0). 
88 Some Participating Transmission Owners have established or proposed state-
level large load-specific interconnection procedures and requirements for retail load 
interconnecting at the distribution or transmission level.  See, e.g., PG&E November 21 
ANOPR Comments at 3-7 (describing its proposed Electric Rule 30). 
89 See, e.g., Pac. Gas & Elec. Co., Transmission Owner Tariff and Related Service 
Agreements, § 10.4 (Review of Completed of Interconnection Application) (0.0.0).  The 
interconnection process in the TO Tariffs does not apply to all Eligible Customers, as 
defined by the TO Tariff, but instead is limited to wholesale load eligible to request 
interconnection consistent with FPA section 210(a).  See, e.g., id. § 10.1 (Applicability) 
(0.0.0).  All other requested interconnections are governed by the local regulatory 
authority.  Id. § 8.1 (Participating TO Obligation to Interconnection) (0.0.0).

Docket No. EL26-71-000 
- 21 - 
necessary.90  The TO Tariffs generally do not explain the details of the study processes or 
any technical or reliability considerations included in the studies.  After completion of the 
requisite studies, the applicant and Participating Transmission Owner execute an 
Interconnection Agreement, which will include the cost responsibilities for any required 
network upgrades or direct assignment facilities.91  Additionally, the TO Tariffs provide 
that the Participating Transmission Owners will offer partial interim service if the studies 
determine that there is not adequate transmission capability to satisfy the full amount of 
interconnection service requested by the applicant.  In that instance, the Participating 
Transmission Owner will provide the portion of the requested interconnection service 
that can be accommodated without any additional direct assignment facilities or 
reliability upgrades.92  Further, the TO Tariffs offer expedited interconnection procedures 
for new network upgrades to interconnect wholesale load.93  The interconnection process 
does not grant transmission service; rather, the applicant must retain the services of a 
Scheduling Coordinator to access transmission service over the CAISO-controlled grid.94  
Of note, the costs of these network upgrades to effectuate load interconnection are not 
rolled into the transmission revenue requirement of the Participating Transmission Owner 
and are instead directly assigned to the Eligible Customer.95 
 
CAISO does not have a process to evaluate load that is co-located with generating 
facilities.96  CAISO’s Tariff sets forth generally applicable Tariff provisions regarding 
 
90 See, e.g., S. Cal. Edison Co., Transmission Owner Tariff, § 10 (Interconnection 
Process) (15.0.0). 
91 See, e.g., Pac. Gas & Elec. Co., Transmission Owner Tariff and Related Service 
Agreements, § 8.1.2 (Costs Associated with Interconnection) (0.0.0). 
92 See, e.g., S. Cal, Edison Co., Transmission Owner Tariff § 10.10. 
93 See, e.g., id. § 10.11. 
94 See CAISO Tariff, § 2.1 (Open Access) (0.0.0).  
95 Although the TO Tariff interconnection process does not grant transmission 
service, the network upgrades identified through the interconnection process, which are 
subject to an interconnection agreement, may be akin to those that would be constructed 
to accommodate a transmission service request in other RTOs/ISOs; however, it is 
unclear from the TO Tariffs.  
96 See CAISO November 21 ANOPR Comments at 6 (noting that co-located retail 
loads are subject to state jurisdiction tariffs and generation is subject to the generator 
interconnection process).

Docket No. EL26-71-000 
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generator interconnection97 and other generator interconnection procedures, including the 
Generator Interconnection and Delivery Allocation Procedures (GIDAP)98 and the 
Resource Interconnection Standards (RIS).99  The GIDAP and the RIS address CAISO’s 
primary process for studying interconnection requests, the Queue Cluster study process.  
CAISO’s GIDAP applies to Queue Clusters 5 through 14 and consists of Phase I and 
Phase II interconnection studies that evaluate the impact of all interconnection requests 
on the CAISO controlled grid and identify cost estimates for network upgrades needed to 
address such impacts, with annual reassessments that account for changes in the 
interconnection queue.100  CAISO’s RIS applies to Queue Cluster 15 and subsequent 
Queue Clusters and consists of:  (1) a cluster study that evaluates the impact of all 
interconnection requests on the CAISO controlled grid and identifies cost estimates for 
network upgrades needed to address such impacts, (2) an annual reassessment, which 
includes the cluster restudy, that accounts for changes in the interconnection queue, and 
(3) a clustered facilities study to specify and provide cost responsibility to implement the 
conclusions of the cluster study report and connect the interconnection facilities to the 
transmission system.101  The GIDAP and RIS also provide processes for allocating 
Transmission Plan Deliverability (TP Deliverability).102  
 
97 CAISO Tariff, § 25 (Interconnection of Generating Units And Facilities) (0.0.0).   
98 Id. app. DD (Generator Interconnect & Deliverability Allocation Procedure) 
(7.0.0).  
99 Id. app. KK (Resource Interconnection Standards) (0.0.0).  
100 Id. app. DD, §§ 6 (Initial Activities & Phase I of the Interconnection Study 
Process for Queue Clusters) (22.0.0), 7 (Activities in Preparation for Phase II) (17.0.0),   
8 (Phase II Interconnection Study & TP Deliverability Allocation Processes) (22.0.0). 
101 Id. app. KK, §§ 2 (Scope and Application) (0.1.0), 2.4.3.1, 7 (Annual 
Reassessment, Cluster Restudy & Activities) (1.1.0), 7.4 (Reassessment Process),            
8 (Interconnection Facilities Study & TP Deliverability) (5.0.0), 8.1.2.  
102 Under the Tariff, TP Deliverability is defined as:  
The capability, measured in MW, of the CAISO Controlled 
Grid as modified by transmission upgrades and additions 
modeled or identified in the annual Transmission Plan to 
support the interconnection with Full Capacity Deliverability 
Status or Partial Capacity Deliverability Status of additional 
Generating Facilities in a specified geographic or electrical 
area of the CAISO Controlled Grid.

Docket No. EL26-71-000 
- 23 - 
 
Pursuant to the Tariff, an interconnection customer may request a limited 
operation study to determine the extent to which the generating unit and the 
interconnection customer’s interconnection facilities may operate prior to the completion 
of the Participating Transmission Owners’ interconnection facilities or network 
upgrades.103  CAISO and the Participating Transmission Owner may permit an 
interconnection customer to operate its electric generating unit and interconnection 
facilities in accordance with such studies.  An interconnection customer may also request, 
and CAISO may provide, surplus interconnection service for an unneeded portion of 
interconnection service capacity at an existing point of interconnection.104  If the 
interconnection customer would not require a new interconnection request under the 
Tariff, CAISO may study a request for surplus interconnection service as a modification 
under section 6.7.2 of the GIDAP or RIS; otherwise, the request is studied as a new 
interconnection request in the cluster study process.105  
B. 
Recent Stakeholder Proceedings in CAISO 
 
In January 2026, CAISO published an issue paper on large load considerations 
that described CAISO’s role as it relates to large load integration and identified issues 
that may arise in future stakeholder discussions.106  CAISO formally began a policy 
initiative in February 2026 to consider new policies due to the emergence of large loads 
and co-located generation, including presenting the issue paper to and soliciting 
 
Id. app. A (TP Deliverability) (1.0.0); see also id. app. DD, § 8 (Phase II Interconnection 
Study & TP Deliverability Allocation Processes); id. app KK, § 8 (Interconnection 
Facilities Study & TP Deliverability), 8.9 (Allocation Process for TP Deliverability). 
103 Id. app. DD, § 14 (PTOs Interconnection Facilities and Network Upgrades) 
(12.0.0), 14.2.4; id. app. KK, § 14 (Construction and Neighboring System Impacts) 
(1.1.0), 14.2.4. 
104 Id. app. DD, § 3 (Interconnection Requests) (17.0.0), 3.4 (Surplus 
Interconnection Service); id. app. KK, § 3 (Interconnection Requests) (3.0.0), § 3.4 
(Surplus Interconnection Service). 
105 Id. app. DD, § 6.7 (Initial Activities and Phase I of the Interconnection Study 
Process for Queue Clusters), 6.7.2; id. app. KK, § 6 (Cluster Study Process), 6.7.2. 
106 See CAISO Large Load Issue Paper.

Docket No. EL26-71-000 
- 24 - 
comments from stakeholders.107  CAISO also held a stakeholder meeting in March 2026 
on technical requirements for large loads.108 
 
CAISO also established an informal large load technical requirements working 
group in October 2025.109  That working group is comprised of Participating 
Transmission Owners with active large load interconnection requests and aims to develop 
a coordinated set of technical requirements for interconnecting data center loads to the 
CAISO-controlled grid.  CAISO states that the working group has been addressing topics 
recommended by NERC, including technical requirements.110 
 
While we are encouraged by CAISO’s stakeholder efforts, and by its initial 
attention to the pressing concerns associated with large and co-located loads111 and to the 
Secretary’s interest in these issues,112  we are initiating this FPA section 206 proceeding 
in order to ensure that CAISO’s ongoing processes generate reforms that are sufficiently 
timely and comprehensive to address the concerns we today identify.  As such, and as the 
Commission explained in the April Order Regarding Intent to Act, we find that the 
Commission must now take further action to ensure that CAISO and/or the Participating 
Transmission Owners promptly propose revisions to ensure that their tariffs remain just 
and reasonable. 
 
107 See CAISO, Initiative: Large Loads, 
https://stakeholdercenter.caiso.com/StakeholderInitiatives/Large-loads (providing link to 
presentation and comments submitted by stakeholders).   
108 Id. 
109 CAISO Large Load Issue Paper at 13. 
110 Id. at 13-14. 
111 See Elliot Mainzer, CEO Elliot Mainzer’s Recent Congressional Testimony on 
Grid Reliability, Energy Matters Blog (Apr. 18, 2025), 
https://www.caiso.com/about/news/energy-matters-blog/ceo-elliot-mainzers-recent-
congressional-testimony-on-grid-reliability (“Currently, there is about 1 GW of data 
center load connected to the CAISO system.  The [California Energy Commission] 
projects an increase in data center loads over the next 15 years, with a sharp increase 
projected to start around the 2028 timeframe.  The CAISO is working diligently to serve 
emerging large electric loads within our footprint, including major enhancements to the 
transmission system in the Silicon Valley.”).  
112 See supra PP 6-7.

Docket No. EL26-71-000 
- 25 - 
III. 
Discussion 
 
Based on the discussion below, pursuant section 206 of the FPA, we direct CAISO 
and the Participating Transmission Owners, within 60 days of the date of this order, to 
either:   
(1) show cause as to why their tariffs remain just and reasonable and not unduly 
discriminatory or preferential without provisions addressing:   
(a) the application process, study procedures, and ongoing operational 
requirements that apply to Eligible Customers seeking transmission service 
on behalf of large loads;  
(b) additional transparency concerning the network upgrade costs to 
provide transmission service to Eligible Customers on behalf of large loads, 
a pro forma cost recovery agreement between CAISO, the relevant 
transmission owner and Eligible Customer taking transmission service on 
behalf of the large load to mitigate the risk of cost shifting among 
transmission customers, and a mechanism to ensure such payments are 
appropriately credited towards transmission owners’ transmission revenue 
requirements consistent with the Commission’s cost-of-service regulations;  
(c) the rates, terms, and conditions of service that apply to co-location 
arrangements;   
(d) transmission services that reflect Eligible Customers taking 
transmission service on behalf of co-located loads, load with behind the 
meter generation, and flexible large loads that are willing and able to limit 
their use of the transmission system under certain conditions; and 
(e) the rates, terms, and conditions of service applicable to interconnection 
customers serving electrically proximate large load or co-located load; or  
(2) explain what changes to their tariffs would remedy the identified concerns if 
the Commission were to determine that their tariffs have in fact become unjust and 
unreasonable or unduly discriminatory or preferential and, therefore, proceeds to 
establish replacement tariffs.   
 
We also direct CAISO to submit, within 30 days of the date of issuance of this 
order, an informational report on how CAISO intends to ensure that adequate generation 
will be available to serve existing and new large loads.   
 
Interested entities may respond within 30 days of CAISO’s and the Participating 
Transmission Owners’ filings, addressing either or both of:  (1) whether the existing

Docket No. EL26-71-000 
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tariffs remain just and reasonable and not unduly discriminatory or preferential; and (2) if 
not, what changes to the tariffs should be implemented as replacement rates.   
 
We recognize that CAISO and/or the Participating Transmission Owners (to the 
extent the matters addressed herein implicate aspects of their TO Tariffs) may elect to 
address some or all of the issues discussed in this order by proposing revisions to their 
tariffs pursuant to their applicable FPA section 205 filing rights.  We strongly encourage 
this.  Although both the Secretary’s ANOPR and our own Order Regarding Intent to Act 
expressly recognized (and indeed encouraged) that possibility,113 no such filings were 
received from CAISO or the Participating Transmission Owners by the Commission prior 
to the issuance of this order.  Should CAISO and/or the Participating Transmission 
Owners elect to make such filings in response to this order, those filings should state 
explicitly that the proposals are being submitted under FPA section 205.  Should CAISO 
and/or the Participating Transmission Owners submit a filing under FPA section 205, 
they should also explain which of the Commission’s above directives their filing 
addresses and how it resolves them.  Additionally, any such filing should provide a 
reasoned explanation for how the proposal will avoid disrupting existing commercial 
arrangements and clearly identify a reasonable effective date that accommodates such 
existing commercial arrangements. 
 
The Commission will consider requests from CAISO and/or the Participating 
Transmission Owners to hold, for up to 90 days, all or certain aspects of this FPA section 
206 proceeding in abeyance, including the deadline to respond to this order.  Any such 
abeyance, which will begin as of the deadline to respond to this order, would be 
considered to provide CAISO and the Participating Transmission Owners time while they 
work through the applicable stakeholder processes to develop FPA section 205 filings to 
revise their tariffs to address the issues raised in this order.  Requests for a full or partial 
abeyance114 should be submitted prior to the deadline to respond to this order, 
specifically within 45 days of issuance of this order, to allow time for the Commission to 
act on the abeyance request.  We emphasize that we will not grant such abeyances 
reflexively, that any abeyance will be limited to 90 days, and that we will look with great 
disfavor toward requests to extend the abeyance period.  We anticipate that successful 
abeyance requests, if any, will include both (1) a robust description of the content of a 
 
113 See ANOPR at P 32; Order Regarding Intent to Act, 195 FERC ¶ 61,045 at P 5. 
114 A partial abeyance may be appropriate to the extent CAISO and/or 
Participating Transmission Owners are developing FPA section 205 filings in response to 
only a subset of the directives in this order.  For any remaining directives, we expect a 
response to this order within the 60-day deadline set forth herein.

Docket No. EL26-71-000 
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potential future filing under FPA section 205 and (2) a reasoned and specific explanation 
of when such a filing is expected to be made. 
 
In cases where, as here, the Commission institutes a section 206 investigation on 
its own motion, section 206(b) of the FPA requires that the Commission establish a 
refund effective date that is no earlier than the date of the publication by the Commission 
of notice of its intention to initiate such proceeding nor later than five months after the 
publication date.  In such cases, in order to give maximum protection to customers, and 
consistent with our precedent, we have historically tended to establish the section 206 
refund effective date at the earliest date allowed by section 206, and we do so here as 
well.115  That date is the date of publication of notice of initiation of this proceeding in 
the Federal Register. 
 
We recognize that the framework under which CAISO provides transmission 
service is unique among the RTOs/ISOs and that certain responsibilities fall to the 
Participating Transmission Owners.116  We therefore expect that CAISO and the 
Participating Transmission Owners will coordinate with each other, as appropriate, to 
develop responses to this order that address the concerns we identify below.   
A. 
Transmission Service to Eligible Customers on Behalf of Large Loads 
 
We today make a preliminary finding that CAISO’s Tariff and/or the TO Tariffs 
appear to be unjust and unreasonable because they lack provisions that address, with 
sufficient clarity and consistency, how CAISO and/or the Participating Transmission 
Owners will timely study (i.e., within 60-90 days of receiving the request) the provision 
of transmission service to Eligible Customers on behalf of large loads.117   
 
Throughout this order, we use the phrase “the provision of transmission service to 
Eligible Customers on behalf of large loads” to encompass the provision of new, 
modified, or additional jurisdictional transmission service to Eligible Customers on 
behalf of large loads.  We use this phrase broadly and recognize that in CAISO there is 
 
115 See, e.g., Idaho Power Co., 145 FERC ¶ 61,122 (2013); Canal Elec. Co.,        
46 FERC ¶ 61,153, order on reh’g, 47 FERC ¶ 61,275 (1989). 
116 We recognize, for example, that under the current framework, CAISO does not 
conduct a study process for the provision of transmission service and note that the 
Participating Transmission Owners may be able to augment their existing study processes 
for load interconnections to respond to the Commission’s concerns. 
117 As discussed below, our findings here also apply to the study process for 
unbundled retail transmission service requests by end-use large load customers, as 
allowed by state law or voluntary utility rules.

Docket No. EL26-71-000 
- 28 - 
no formal application process for transmission service and that CAISO does not offer 
traditional Order No. 888 transmission services, as discussed above.  We also recognize 
that the Participating Transmission Owners have responsibility for wholesale load 
interconnection studies.  Thus, we understand that an Eligible Customer118 submits an 
interconnection application to the Participating Transmission Owner, who then completes 
the requisite studies as needed to interconnect new load.  The Eligible Customer then 
must retain the service of a Scheduling Coordinator to access the CAISO market and 
represent its load.119  CAISO does not appear to conduct studies to determine the 
necessary network upgrades needed for the provision of transmission service to Eligible 
Customers outside of the TPP.120  CAISO, however, is responsible for access to and the 
provision of transmission service, including transmission and ancillary services, to all 
Eligible Customers, and the reliability of that transmission service.121  We note that this 
phrase is not limited to instances where an Eligible Customer submits an application to 
request new transmission service.  It also includes instances where an Eligible Customer 
requests a new or modified point of delivery to serve a large load, where a large load 
seeks a new or modified delivery point as an unbundled retail transmission service 
customer, or where large loads are otherwise included in an Eligible Customer’s reported 
load growth and that Eligible Customer is taking network transmission service.    
 
We direct CAISO and the Participating Transmission Owners, to the extent the 
matters addressed herein implicate aspects of their respective tariffs, to explain whether 
their tariffs remain just and reasonable without an application process, study procedures, 
and ongoing operational requirements that address the unique characteristics and 
challenges of providing transmission service to Eligible Customers on behalf of large 
loads, or to propose appropriate tariff revisions.   
 
118 We note, however, that under the TO Tariffs this applies only to Eligible 
Customers who are also wholesale load eligible to request interconnection consistent with 
FPA section 210(a).  E.g., Pac. Gas & Elec. Co., Transmission Owner Tariff, § 10.1. 
119 See supra P 20. 
120 See supra P 21. 
121 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,731 (“An ISO should be 
responsible for ensuring that all users have non-discriminatory access to the transmission 
system and all services under ISO control. . . . [T]he ISO should be responsible for 
ensuring that services (for all users, including new users) can be provided reliably, and 
for developing and implementing policies related to curtailment to ensure the on-going 
reliability and security of the system.”).

Docket No. EL26-71-000 
- 29 - 
1. 
Jurisdiction 
 
At the outset, we clarify the principles relating to the Commission’s jurisdiction 
over the matters relevant to the integration of large loads onto the transmission system 
and the impacts of large loads on the transmission system.  We recognize that rates, 
terms, and conditions associated with the addition of and service to large loads implicate 
both federal and state interests.  We also recognize that resolution of issues related to 
large load additions will require the involvement of both federal and state actors, 
including the Commission, state public utility commissions, and other state and local 
entities.  We are encouraged by efforts made at the state level to address issues related to 
large load additions that fall within state jurisdiction.122   
 
As discussed below, however, certain aspects of the process for integrating large 
loads onto the transmission system fall squarely within the Commission’s exclusive 
jurisdiction.   
 
Specifically, we find that it is within the Commission’s exclusive authority to 
ensure that transmission provider and/or transmission owner tariffs include sufficiently 
clear and consistent provisions governing how transmission service to Eligible Customers 
on behalf of large loads interconnecting to the transmission system will be studied, 
including whether new or upgraded transmission facilities are necessary to provide the 
requested transmission service.  The Commission has jurisdiction over the study process 
for transmission service to both Eligible Customers on behalf of large loads and 
unbundled retail transmission service to end-use large load customers where, pursuant to 
state law or a public utility’s voluntary offer of such service, the large load is an Eligible 
Customer under the transmission provider and/or transmission owner tariffs.123 
 
The Commission is a creature of statute and has jurisdiction over only those 
matters that Congress has given it the authority to regulate.124  That authority includes 
jurisdiction over the wholesale sale and transmission of electricity in interstate 
commerce, including all facilities used for such sale and transmission.125  As relevant 
 
122 See generally NARUC April 14 ANOPR Comments (highlighting action taken 
by state public utility commissions related to large loads). 
123 Under the pro forma OATT, Eligible Customers include end-use customers 
seeking unbundled retail transmission service, pursuant to state law or public utility’s 
voluntary offer of such service.  Pro forma OATT, § 1.12 (Definitions – Eligible 
Customer); see also CAISO Tariff, app. A, Eligible Customer. 
124 Atl. City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002). 
125 16 U.S.C. § 824(b)(1).

Docket No. EL26-71-000 
- 30 - 
here, the Commission must ensure that the rates, charges, and classifications for such 
transmission of electricity—as well as the practices directly affecting such transmission 
of electricity—are just and reasonable and not unduly discriminatory or preferential.126  
The Supreme Court has held that the Commission’s authority over interstate transmission 
is not limited to wholesale transmission service and that the Commission has authority 
over unbundled retail transmission service.127  As part of its transmission authority, the 
Commission has exercised jurisdiction over the terms of certain interconnections to the 
transmission system as an element of transmission service,128 including the 
interconnection of wholesale load to the transmission system.129  
 
As applied to large load additions to the transmission system, these principles 
mean that the Commission has exclusive jurisdiction over the rates, terms, and conditions 
of interstate transmission service to Eligible Customers on behalf of large loads 
connecting to the transmission system, and the practices directly affecting the provision 
of such interstate transmission of electricity.  An essential component of providing such 
transmission service is the process by which the transmission provider and/or 
transmission owner evaluates (1) whether it can provide the requested transmission 
service and (2) the impact that providing such transmission service will have on the 
jurisdictional transmission system, including determining whether any new or upgraded 
transmission facilities are needed to provide transmission service while maintaining 
reliable operation of the transmission system.  This transmission service study process 
determines what network upgrades are needed to provide transmission service to Eligible 
Customers on behalf of large loads, the costs of which are included in transmission rates.  
As such, this study process directly affects Commission-jurisdictional transmission 
rates.130  The Commission has exclusive authority to ensure that the process to study the 
 
126 Id. §§ 824d, 824e; see FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 278 
(2016) (EPSA) (approving “a common-sense construction of the FPA’s language, 
limiting FERC’s ‘affecting’ jurisdiction to rules or practices that ‘directly affect the 
wholesale rate’” (cleaned up)).    
127 New York v. FERC, 535 U.S. at 17, 19-20 (upholding the Commission’s 
exercise of jurisdiction over unbundled retail transmission service). 
128 Tenn. Power Co., 90 FERC ¶ 61,238, at 61,761 (2000) (Tennessee Power), 
order denying reh’g, 91 FERC ¶ 61,271 (2000); Standardization of Generator 
Interconnection Agreements & Procs., Order No. 2003, 104 FERC ¶ 61,103, at P 9 
(2003); see also Laguna Irrigation Dist., 91 FERC ¶ 61,340, at 62,152 (2000). 
129 Pac. Gas & Elec. Co., 109 FERC ¶ 61,392, at P 37 (2004); Pac. Gas & Elec. 
Co., 115 FERC ¶ 61,193, at PP 36-38 (2006). 
130 Cf. Transmission Plan. & Cost Allocation by Transmission Owning &

Docket No. EL26-71-000 
- 31 - 
provision of transmission service to Eligible Customers is just and reasonable and not 
unduly discriminatory or preferential.  We therefore find that we have authority to ensure 
that tariffs include provisions that clearly and consistently address the study process for 
the provision of transmission service to Eligible Customers on behalf of large loads, 
including the unique impacts that providing transmission service to Eligible Customers 
on behalf of large loads may have on the transmission system. 
 
At the same time, we continue to recognize that the FPA expressly reserves to 
states the authority over any other sale of electric energy, including retail sales and 
wholesale sales not in interstate commerce (such as wholesale sales within the Electric 
Reliability Council of Texas region), as well as facilities used for the generation and 
distribution of electricity.131  As such, we recognize that states will continue to regulate:  
(1) the specific terms of retail sales to large load;132 (2) which entities may make retail 
sales within their borders, including which entities are legally permitted to provide 
electricity to retail large load customers;133 and (3) any siting decisions and construction 
associated with the large load project.134  Nothing in this order is intended to intrude upon 
state authority over retail service to large loads.   
 
In sum, we today exercise our authority to ensure that the process by which 
jurisdictional transmission providers and/or transmission owners will study the provision 
of jurisdictional transmission service to Eligible Customers on behalf of large loads 
interconnecting to the transmission system, including where, as allowed by state law a 
public utility’s voluntary offer of such service, an end-use large load seeks unbundled 
 
Operating Pub. Utils., Order No. 1000, 136 FERC ¶ 61,051, at P 112 (2011) (“It is 
through the transmission planning process that public utility transmission providers 
determine which transmission facilities will more efficiently or cost-effectively meet the 
needs of the region, the development of which directly impacts the rates, terms and 
conditions of jurisdictional service.”). 
131 16 U.S.C. § 824(b)(1); see Dayton Power & Light Co. v. FERC, 126 F.4th 
1107, 1129 (6th Cir. 2025). 
132 See EPSA, 577 U.S. at 279-80 (recognizing state authority over retail electricity 
sales); New York v. FERC, 535 U.S. at 28 (same). 
133 PJM Show Cause Order, 190 FERC ¶ 61,115 at PP 68-69. 
134 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th 229, 238 (D.C. 
Cir. 2025) (citing 16 U.S.C. § 824(b)(1)) (recognizing state authority over generation 
resource mix, including through their siting authority); Order No. 1000, 136 FERC          
¶ 61,051 at P 107 (acknowledging state authority over siting, permitting, and construction 
of transmission facilities).

Docket No. EL26-71-000 
- 32 - 
retail transmission service, is just and reasonable and not unduly discriminatory or 
preferential.  Pursuant to that authority, we find that CAISO’s Tariff and/or TO Tariffs 
appear to be unjust and unreasonable or unduly discriminatory or preferential because 
they lack sufficiently clear and consistent provisions regarding the study process related 
to the provision of transmission service to Eligible Customers on behalf of large loads.  
We need not comprehensively address the Commission’s jurisdiction over other aspects 
of the addition of large loads to the transmission system at this time.   
2. 
Tariff Provisions 
 
In the following section, we begin by considering CAISO’s Tariff and/or the TO 
Tariffs as they relate to how CAISO and/or the Participating Transmission Owners will 
study the provision of transmission service to Eligible Customers on behalf of large loads 
and explain our concerns that the lack of sufficiently clear and consistent provisions 
regarding the study process for the provision of transmission service to Eligible 
Customers on behalf of large loads is unjust and unreasonable or unduly discriminatory 
or preferential.  We then consider whether CAISO’s Tariff and/or the TO Tariffs are 
unjust and unreasonable without certain elements.  First, we consider whether CAISO’s 
Tariff and/or the TO Tariffs lack sufficiently clear and consistent tariff provisions 
establishing an appropriate definition of large load, as a separate category of load.  
Second, we consider whether CAISO’s Tariff and/or the TO Tariffs lack sufficiently 
clear and consistent tariff provisions establishing an application process and requirements 
for Eligible Customers requesting transmission service on behalf of large loads and a 
study process that considers the unique operational challenges of providing transmission 
service to Eligible Customers on behalf of large loads.  Third, we consider whether the 
CAISO’s Tariff lacks sufficiently clear and consistent Tariff provisions establishing 
ongoing operational requirements necessary to ensure that CAISO can reliably provide 
transmission service given the unique operational impacts on the transmission system of 
providing transmission service to Eligible Customers on behalf of large loads.  Finally, 
we consider whether CAISO’s Tariff and/or the TO Tariffs require such ongoing 
operational requirements for Eligible Customers taking transmission service on behalf of 
large loads to be memorialized in service agreements. 
 
We preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be 
unjust and unreasonable or unduly discriminatory or preferential because they do not 
contain provisions addressing with sufficient clarity and consistency how CAISO and/or 
the Participating Transmission Owners will study the provision of transmission service to 
Eligible Customers on behalf of large loads.  We recognize that CAISO and/or the 
Participating Transmission Owners may have existing load integration processes, 
including studies that are performed in evaluating the provision of transmission service to

Docket No. EL26-71-000 
- 33 - 
Eligible Customers on behalf of large loads.135  However, we are concerned that those 
processes and any required studies with regard to the provision of transmission service 
are not described in their tariffs with the degree of clarity and specificity necessary to 
ensure that the transmission provider can mitigate operational risks of providing 
transmission service to Eligible Customers on behalf of large loads, given their impact on 
the transmission system, avoid disputes regarding how studies are conducted, deter 
speculative or duplicative requests for transmission service by Eligible Customers on 
behalf of large loads, and help avoid excessive and unnecessary network upgrades.   
 
Moreover, we are concerned that the existing tariffs do not contain other elements 
akin to those described below, which we preliminarily find may be necessary to ensure 
that the rates, terms, and conditions of jurisdictional transmission service are just and 
reasonable.   
 
At the outset, we recognize that the Participating Transmission Owners may be 
primarily responsible for conducting the studies that (1) evaluate whether a large load 
may be interconnected to the transmission system and served by the Eligible Customer 
and (2) determine whether network upgrades are necessary to provide transmission 
service.  We appreciate that this role may stem from how CAISO and the Participating 
Transmission Owners allocated rights and responsibilities in the governing documents 
establishing CAISO.  While we do not seek to alter that allocation of rights and 
responsibilities, we are concerned that CAISO’s Tariff and/or the TO Tariffs may not 
clearly specify which entity will be responsible for studying the provision of transmission 
service to Eligible Customers on behalf of large loads.   
 
We are further concerned that CAISO’s Tariff and/or the TO Tariffs lack a study 
process that addresses the unique operational and reliability challenges that providing 
transmission service to Eligible Customers on behalf of large loads presents to the 
transmission system.  Large loads can be more energy intensive and geographically 
concentrated than traditional load, and exhibit different load profiles.136  CAISO itself has 
recognized that large loads can have a disproportionate impact on system reliability due 
to their size and unique characteristics and that the scale, pace, and characteristics of 
large load growth present significant operational and planning challenges.137  As a result, 
 
135 See supra P 25. 
136 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at PP 7-8; NERC, 
Characteristics and Risks of Emerging Large Loads (July 2025), 
https://www.nerc.com/globalassets/who-we-are/standing-committees/rstc/whitepaper-
characteristics-and-risks-of-emerging-large-loads.pdf (NERC Characteristics and Risks 
of Large Loads). 
137 See CAISO November 21 ANOPR Comments at 1-2.

Docket No. EL26-71-000 
- 34 - 
providing transmission service to Eligible Customers on behalf of large loads may be 
more complex and could raise greater reliability concerns for the transmission system, 
relative to a situation where Eligible Customers seek transmission service on behalf of 
traditional load.     
 
Without a clear and consistent process to study the provision of transmission 
service to Eligible Customers on behalf of large loads, CAISO and/or the Participating 
Transmission Owners may not fully capture the transmission system impacts of providing 
such transmission service, which could result in significant operational risks for the 
transmission system.  Furthermore, we are concerned that, without sufficiently clear and 
consistent tariff provisions, CAISO will not have the ongoing visibility and operational 
control necessary to provide reliable transmission service. 
 
We are also concerned that the absence of sufficiently clear and consistent tariff 
provisions for how CAISO and/or the Participating Transmission Owners will study the 
provision of transmission service to Eligible Customers on behalf of large loads will lead 
to disputes over a variety of issues—e.g., study timelines and delays,138 how the 
transmission service needed on behalf of the large load is studied,139 what types of 
network upgrades are considered, and how required network upgrades to provide the 
requested transmission service are determined.140  Such disputes may arise from the lack 
 
138 See, e.g., CEBA November 21 ANOPR Comments at 12-13; Eolian November 
21 ANOPR Comments at 14-16; Institute for Progress November 21 ANOPR Comments 
at 7-8; Microsoft November 21 ANOPR Comments at 9; ODEC December 5 ANOPR 
Comments at 4. 
139 Commenters raised concern that large loads are not studied with consideration 
of their known operating characteristics, including their willingness to be flexible or 
curtailable.  See, e.g., ClearPath November 21 ANOPR Comments at 5-6; Constellation 
November 21 ANOPR Comments at 23-24; Critical Loop November 21 ANOPR 
Comments at 3; GridCare December 5 ANOPR Comments at 1-2; L. Lynne Kiesling 
November 21 ANOPR Comments at 10. 
140 Specifically, commenters raised concern that transmission providers/owners 
may only consider traditional transmission infrastructure or that there is a lack of 
consideration of alternative transmission solutions.  See, e.g., ACORE November 21 
ANOPR Comments at 3-4, 6-7; American Terawatt November 21 ANOPR Comments at 
4-5; Calibrant November 21 ANOPR Comments at 1-2, 3; CEBA November 21 ANOPR 
Comments at 9-10; Chamber of Commerce November 21 ANOPR Comments at 3; CTC 
Global Corporation November 21 ANOPR Comments at 1-3; DCC November 21 
ANOPR Comments at 10-11; GridCARE December 5 ANOPR Comments at 4; Industrial 
Customers November 21 ANOPR Comments at 27-28; Infrastructure Masons December 
5 ANOPR Comments at 18; Iron Mountain Data Centers, LLC November 21 ANOPR

Docket No. EL26-71-000 
- 35 - 
of transparency in how studies are performed and how decisions will be made.141  We are 
thus concerned that the lack of clear and consistent provisions in CAISO’s Tariff and/or 
the TO Tariffs related to the study process for the provision of transmission service to 
Eligible Customers on behalf of large loads appears to be unjust and unreasonable or 
unduly discriminatory or preferential.   
 
Lastly, we are concerned that CAISO’s existing Tariff and/or the TO Tariffs fail to 
deter speculative or duplicative requests for transmission service by Eligible Customers 
on behalf of large loads.  Many ANOPR comments assert that clear and consistent 
provisions establishing study timelines and costs, readiness requirements, and/or 
penalties will deter speculative or duplicative requests related to large load additions.142  
Commenters explain that speculative requests may bog down and delay the study 
process, wasting time and resources for transmission providers;143 result in inaccurate 
study results or delays for other Eligible Customers seeking transmission service on 
 
Comments at 3-4; Land Trust Alliance November 21 ANOPR Comments at 5-6; PIOs 
November 21 ANOPR Comments at 22; Southeast PIOs November 21 ANOPR 
Comments at 44-45; WATT and Advancing Modern Powerlines November 21 ANOPR 
Comments at 5-8. 
141 See, e.g., CEBA November 21 ANOPR Comments at 12; ECA December 5 
ANOPR Comments at 1-2; Eolian November 21 ANOPR Comments at 17-18; EPSA 
November 21 ANOPR Comments at 6; Infrastructure Masons December 5 ANOPR 
Comments at 4, 6-7; Southeast PIOs November 21 ANOPR Comments at 39-40; Switch 
December 5 ANOPR Comments at 3; Tract November 21 ANOPR Comments at 5; 
Vantage November 21 ANOPR Comments at 5-6; Verrus November 21 ANOPR 
Comments at 6, 12; Vistra December 5 ANOPR Comments at 27. 
142 See, e.g., ACORE November 21 ANOPR Comments at 6; AEU November 21 
ANOPR Comments at 17-18; Amazon November 21 ANOPR Comments at 6; Crusoe 
December 5 ANOPR Comments at 5-6; EDF Power November 21 ANOPR Comments at 
12-13; EEI November 21 ANOPR Comments at 20; Fervo November 21 ANOPR 
Comments at 3; GridCare December 5 ANOPR Comments at 5; Invenergy November 21 
ANOPR Comments at 6; Microsoft November 21 ANOPR Comments at 9; Ohio FEA 
November 21 ANOPR Comments at 4. 
143 See, e.g., ATC November 21 ANOPR Comments at 12; Eolian November 21 
ANOPR Comments at 17-18; GridCare December 5 ANOPR Comments at 5; Illinois AG 
November 21 ANOPR Comments at 9-10; Institute for Progress November 21 ANOPR 
Comments at 9; Ohio FEA November 21 ANOPR Comments at 4; Vistra November 21 
ANOPR Comments at 23.

Docket No. EL26-71-000 
- 36 - 
behalf of load;144 create a substantial risk of cost shifts if the large load additions do not 
materialize as planned;145 and distort load forecasts.146  Clear and consistent study 
procedures that include readiness requirements (i.e., meaningful milestones and/or 
financial commitments) can help ensure that Eligible Customers’ requests for 
transmission service on behalf of large loads are more viable and more likely to 
materialize as planned, given that they must meet specific milestones and/or pay costs to 
proceed.   
 
More specifically, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs 
appear to be unjust and unreasonable because they lack sufficiently clear and consistent 
tariff provisions that address certain aspects of the process to provide transmission 
service to Eligible Customers on behalf of large loads, including:   
(1) a definition of large load sufficient to capture loads that present the unique 
challenges described herein;  
(2) the application process for requesting transmission service to Eligible 
Customers on behalf of large loads and the study procedures, including readiness 
requirements, for studying the provision of transmission service to Eligible 
Customers on behalf of large loads;  
 
144 See, e.g., Amazon November 21 ANOPR Comments at 6; CEBA November 21 
ANOPR Comments at 8; ClearPath November 21 ANOPR Comments at 4; Geronimo 
November 21 ANOPR Comments at 12; TAPS November 21 ANOPR Comments at 14-
15. 
145 See, e.g., Buckeye November 21 ANOPR Comments at 1-2; Exelon November 
21 ANOPR Comments at 3; Kansas Commission November 21 ANOPR Comments at 
12; NRECA November 21 ANOPR Comments at 9; OCC November 21 ANOPR 
Comments at 9; Southeast PIOs November 21 ANOPR Comments at 20; State Entities 
November 21 ANOPR Comments at 7-8; TAPS November 21 ANOPR Comments at 15, 
22-24; Tri-State November 21 ANOPR Comments at 6, 8; Vistra November 21 ANOPR 
Comments at 23. 
146 See, e.g., CEBA November 21 ANOPR Comments at 8; EEI November 21 
ANOPR Comments at 20; ELCON November 21 ANOPR Comments at 7; Invenergy 
November 21 ANOPR Comments at 6; GridCare December 5 ANOPR Comments at 5; 
OCC November 21 ANOPR Comments at 9; PIOs November 21 ANOPR Comments at 
5; Southeast PIOs November 21 ANOPR Comments at 41; Talen November 21 ANOPR 
Comments at 9.

Docket No. EL26-71-000 
- 37 - 
(3) ongoing operational requirements for transmission customers147 serving large 
loads necessary to ensure reliable operation of the transmission system; and  
(4) pro forma provisions in transmission service agreements, or other applicable 
agreements, to memorialize these terms. 
 
First, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be 
unjust and unreasonable because they lack a definition of large load, as a new category of 
load.  As CAISO acknowledges, integrating large loads poses specific challenges.  
CAISO states that although large loads are retail customers, they can impact reliability in 
ways comparable to large wholesale generators.148  An appropriate definition, including a 
load size and interconnection voltage threshold, should be based on the characteristics of 
CAISO’s transmission system.  That said, based on the record in the ANOPR 
proceeding,149 it appears that it would be reasonable to define a large load as a new 
commercial or industrial customer, located at a single site behind one or more points of 
interconnection, and that has a peak load of 50 MW or greater, interconnects to the 
transmission system at a voltage level of greater than 69 kV, and is not part of a co-
location arrangement.  In their responses to this order, CAISO and/or the Participating 
Transmission Owners should explain whether their tariffs remain just and reasonable 
without such a definition or propose tariff revisions establishing their own definition of 
large load. 
 
Second, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to 
be unjust and unreasonable because they lack sufficiently clear and consistent provisions 
establishing the application process and study procedures that will be used when CAISO 
 
147 We note that such ongoing operational requirements should apply to 
transmission customers, rather than Eligible Customers, as these requirements apply after 
the Eligible Customer has an executed (or a filed unexecuted) service agreement for 
transmission service and have become transmission customers under the Tariff.  
148 CAISO November 21 ANOPR Comments at 1-2. 
149 See, e.g., Constellation November 21 ANOPR Comments at 13 (supporting a 
voltage threshold); DTE November 21 ANOPR Comments at 3, 17-19 (recommending a 
threshold of an amount between 50 MW to 100 MW); Eolian November 21 ANOPR 
Comments at 8-9 (recommending a voltage threshold greater than or equal to an amount 
between 60 kV to 100 kV); Illinois AG November 21 ANOPR Comments at 7 
(supporting a 20 MW or 50 MW threshold and consideration of other factors, such as 
voltage level); ITC November 21 ANOPR Comments at 3 (recommending a threshold of 
between 50 MW to 100 MW); Nebraska Board November 21 ANOPR Comments at 4 
(proposing a 50 MW threshold); New Mexico Commission November 21 ANOPR 
Comments at 5 (proposing a 50 MW threshold).

Docket No. EL26-71-000 
- 38 - 
and/or the Participating Transmission Owners evaluate the provision of transmission 
service to Eligible Customers on behalf of large loads.  CAISO and/or the Participating 
Transmission Owners should explain whether their tariffs remain just and reasonable, for 
example, without: (1) an application process that accepts Eligible Customers’ 
applications for transmission service on behalf of large loads on a rolling basis; (2) a  
non-refundable application fee and sufficient readiness requirements that escalate at 
distinct phases of the study process to deter duplicative or speculative requests for 
transmission service (e.g., meaningful milestones and/or financial commitments); and (3) 
information and data requirements that Eligible Customers must submit to CAISO and/or 
the Participating Transmission Owners regarding the characteristics of the large load on 
behalf of which the Eligible Customer is taking transmission service, including disclosure 
to CAISO of any substantially similar pending transmission service requests on behalf of 
the same large load customer.150  CAISO and/or the Participating Transmission Owners 
may also elect to propose tariff revisions establishing such an application process, fee, 
and requirements.   
 
Further, CAISO’s Tariff and/or the TO Tariffs appear to lack sufficiently clear and 
consistent provisions establishing a study process for evaluating the provision of 
transmission service to Eligible Customers on behalf of large loads that considers the 
unique characteristics and impacts of large loads on the transmission system.  For 
example, we are concerned that CAISO’s Tariff and/or the TO Tariffs may not clearly 
and consistently require CAISO or the Participating Transmission Owners to conduct 
studies that evaluate the transmission system’s ability to withstand risks observed from 
analyzed large load behavior created by the large load at the point of interconnection, or 
any other necessary supplemental studies to evaluate the impact of providing 
transmission service to Eligible Customers on behalf of large loads.151  Additionally, we 
preliminarily find that CAISO’s Tariff and/or TO Tariffs appear to be unjust and 
unreasonable because they lack appropriate provisions recognizing within the study 
process for the provision of transmission service the unique operational characteristics of 
large loads that are willing and able to limit their energy withdrawals under certain 
conditions, which may thereby lessen or potentially avoid the need for certain network 
upgrades.  While flexible large loads can reduce the demand on the transmission system, 
 
150 The Electric Reliability Council of Texas (ERCOT) has proposed a similar 
disclosure requirement in its Batch Zero process for large load interconnections.  ERCOT 
Planning Guide, § 9.7.1(1)(b) (proposed Mar. 4, 2026). 
151 See generally NERC, Industry Recommendation:  Large Load Interconnection, 
Study, Commissioning, and Operations (Sep. 2025), 
https://www.nerc.com/globalassets/programs/bpsa/alerts/2025/nerc-alert-level-2--large-
loads.pdf (finding that unique operational characteristics of large loads necessitate 
enhancements to studies).

Docket No. EL26-71-000 
- 39 - 
and therefore potentially reduce the need for additional transmission capacity, additional 
informational and study requirements may be necessary to account for the dynamic 
nature of these types of loads while maintaining reliability.152  Additionally, we note that 
accurate models using Electromagnetic Transient studies may help to ensure that 
transmission service needed on behalf of large loads can be provided without 
compromising reliability.153   
 
Additionally, we preliminarily find that CAISO’s Tariff and/or TO Tariffs appear 
to be unjust and unreasonable because they lack clear and consistent provisions requiring 
the evaluation of alternative transmission technologies154 as potential solutions to 
accommodate an Eligible Customer’s request for transmission service on behalf of a large 
load.  Alternative transmission technologies can add more capacity on existing 
transmission lines quickly, often within one to three years.155  Unlike with traditional load 
growth,156 large load customers often have development timelines requiring 
 
152 See, e.g., AEMA November 21 ANOPR Comments at 6; Thermal Battery 
Alliance November 21 ANOPR Comments at 7; Verrus November 21 ANOPR 
Comments at 10. 
153 See, e.g., NERC, Draft Reliability Guideline: Risk Mitigation for Emerging 
Large Loads 6-7 (May 2026), https://www.nerc.com/globalassets/who-we-are/standing-
committees/rstc/reliabilityguideline_riskmitigationforemerginglargeloads.pdf; NERC, 
Assessment of Gaps in Existing Practices, Requirements, and Reliability Standards for 
Emerging Large Loads 31 (Mar. 2026), https://www.nerc.com/globalassets/our-
work/guidelines/reliability/white-paper---assessment-of-gaps.pdf; see also SPP HILL 
Order, 194 FERC ¶ 61,031 at P 62. 
154 For purposes of this order, alternative transmission technologies include static 
synchronous compensators, static VAR compensators, advanced power flow control 
devices, transmission switching, synchronous condensers, voltage source converters, 
advanced conductors, tower lifting, and dynamic line ratings.  We note that the 
Commission has also referred to these types of technologies as Grid Enhancing 
Technologies (GET). 
155 WATT and Advancing Modern Powerlines November 21 ANOPR Comments 
at 5-6. 
156 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at P 7 (explaining that the 
HILL proposal was needed in part due to large load customers frequently requesting 
transmission service within months rather than years of their intended commercial 
operation, straining legacy regulatory frameworks and planning processes originally 
designed for slow, incremental, and predictable load growth); see also Commission Staff, 
2025 State of the Market Report 8 (Mar. 2026) (“[D]ata centers have characteristics

Docket No. EL26-71-000 
- 40 - 
interconnection to the transmission system faster than traditional network upgrades can 
be built, necessitating a sufficient evaluation of alternative transmission technologies that 
can more quickly accommodate transmission service requests from Eligible Customers 
on behalf of large loads.157  The Commission has previously recognized that alternative 
transmission technologies have the potential to mitigate or defer the need for traditional 
network upgrades and often can be deployed both more quickly and at lower cost than 
traditional network upgrades, and therefore failing to consider whether alternative 
transmission technologies can meet transmission needs more efficiently or cost-
effectively than traditional network upgrades has the potential to render Commission-
jurisdictional rates unjust and unreasonable.158  Further, to the extent network upgrade 
costs to accommodate an Eligible Customer’s request for transmission service on behalf 
of a large load are rolled into a transmission owner’s transmission revenue requirement, 
transmission customers other than the Eligible Customer may bear a portion of those 
 
unlike more traditional loads [including] size, strong desire for faster interconnection, and 
potential flexibility.”). 
157 Exec. Off. of the President, Winning the Race: America’s AI Action Plan at 1-2, 
15 (July 2025), https://www.whitehouse.gov/wp-content/uploads/2025/07/Americas-AI-
Action-Plan.pdf (explaining that accelerated deployment of AI data centers is a critical 
matter of national security and international economic competitiveness, and 
recommending federal policy action to optimize the existing grid through advanced grid 
technologies); WATT and Advancing Modern Powerlines November 21 ANOPR 
Comments at 5-8 (“[Alternative transmission technologies’] deployment timelines are 
more aligned with the interconnection needs of new large loads, which may only take 1-2 
years to construct.”); Industrial Customers November 21 ANOPR Comments at 28 
(“Achieving speed-to-power in the near-term, while also protecting customers, will 
require the use of GETs, advanced reconductoring, and unlocking all available system 
capacity.”); Energy Systems Integration Group, Historical and Modern Large Loads: 
Characteristics, Context, and Industry Action to Meet Grid and Customer Needs, at 4 
(Mar. 2026), https://www.esig.energy/wp-content/uploads/2026/03/ESIG-Historical-vs-
Modern-Large-Loads-white-paper-2026.pdf (describing the timing mismatch between 
how long it takes to build a new data center and how long it takes to plan, permit, and 
build transmission). 
158 Improvements to Generator Interconnection Procs. & Agreements, Order No. 
2023, 184 FERC ¶ 61,054 at P 1583, order on reh’g, 185 FERC ¶ 61,063 (2023), order 
on reh’g, Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC ¶ 61,134 
(2024); see also Bldg. for the Future Through Elec. Reg’l Transmission Plan. & Cost 
Allocation, Order No. 1920, 187 FERC ¶ 61,068 at P 1201, order on reh’g, Order No. 
1920-A, 189 FERC ¶ 61,126 (2024), order on reh’g, Order No. 1920-B, 191 FERC         
¶ 61,026 (2025).

Docket No. EL26-71-000 
- 41 - 
network upgrade costs, highlighting the need for clear and consistent provisions requiring 
the evaluation of least-cost options like alternative transmission technologies to mitigate 
the rate impact on all transmission customers.    
 
CAISO and/or Participating Transmission Owners should explain whether the 
Tariffs remain just and reasonable without provisions that (1) require the evaluation of 
alternative transmission technologies in studies for the provision of transmission service, 
using models that are capable of evaluating the transmission system to accurately account 
for advanced transmission technologies, in all instances, without the need for a request 
from the Eligible Customer seeking transmission service on behalf of a large load; and 
(2) if traditional network upgrades are selected instead of alternative transmission 
technologies, inclusion in the study report to the Eligible Customer seeking transmission 
service on behalf of a large load of a sufficiently clear demonstration of why alternative 
transmission technologies are not feasible (i.e., would not resolve reliability violations 
identified or meet the relevant planning criteria) or would not result in lower costs or a 
faster timeline for accommodating the transmission service request; or propose Tariff 
revisions establishing such provisions.  This transparency and informational requirement 
is warranted for the regulatory scheme we are establishing for transmission service 
requests by Eligible Customers on behalf of large loads given demand from and the 
expedited development timelines for large load customers.  We underscore that we are 
not mandating the use of alternative transmission technologies.  To the extent 
stakeholders believe that specific characteristics of providing transmission service to 
Eligible Customers on behalf of large loads warrant requirements beyond those 
contemplated here, we seek further briefing. 
 
Finally, based on the record, it appears reasonable that such study processes, 
culminating in a report to the Eligible Customer with the results of the studies, including 
any Direct Assignment Facilities and network upgrades necessary to accommodate the 
transmission service request as well as a non-binding good-faith estimate of the cost and 
the time to construct such facilities, should take no more than 60-90 days calendar days to 
complete.159  To the extent CAISO or the Participating Transmission Owners already 
have such procedures and conduct such studies, but those processes are not included in 
their tariffs, CAISO and the Participating Transmission Owners should explain their 
 
159 Several commenters support a 60-day timeline.  See, e.g., Constellation 
November 21 ANOPR Comments at 26; Critical Loop December 5 ANOPR Comments 
at 8; EDF Power November 21 ANOPR Comments at 16; Tract November 21 ANOPR 
Comments at 9.  Other commenters note that SPP’s HILL process has a 90-day timeline, 
or otherwise support a 90-day timeline.  See, e.g., AEMA November 21 ANOPR 
Comments at 3; Eolian December 5 ANOPR Comments at 27; Industrial Customers 
November 21 ANOPR Comments at 20; PJM November 21 ANOPR Comments at 7; 
SPP November 21 ANOPR Comments at 16-17.

Docket No. EL26-71-000 
- 42 - 
existing processes and consider whether amendments are necessary to the tariffs to 
memorialize those processes  and also address the concerns expressed herein.  Otherwise, 
CAISO and/or the Participating Transmission Owners should explain whether their tariffs 
remain just and reasonable without:  (1) sufficiently clear and consistent provisions to 
evaluate the impact of providing the requested transmission service to Eligible Customers 
on behalf of large loads, including identifying the Direct Assignment Facilities and 
Network Upgrades necessary to provide such service reliably; (2) provisions to 
appropriately recognize within the transmission service study process the unique 
operational characteristics of large loads; (3) a study deadline of no more than 60-90 
calendar days; or propose Tariff revisions establishing them. 
 
Third, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to 
be unjust and unreasonable because they lack provisions addressing ongoing operational 
requirements for transmission customers taking transmission service on behalf of large 
loads.  We are concerned that without such requirements the rates, terms, and conditions 
of transmission service may be unjust and unreasonable.  The unique nature of these large 
loads creates challenges for operation of the transmission system and necessitates greater 
visibility and operational control when providing transmission service to transmission 
customers on behalf of large loads, without which the reliability of the transmission 
system could be at risk.160  For example, we are concerned that CAISO’s Tariff and/or 
the TO Tariffs do not require transmission customers to provide CAISO hourly forecasts, 
telemetry data, and other data to ensure sufficient visibility or specify requirements for 
maintaining communication channels between CAISO and the transmission customer on 
behalf of the large load.  Additionally, we are concerned that the tariffs do not require 
transmission owners to install, and transmission customers to pay for, equipment to 
enable CAISO to monitor large loads for impacts of, for example, fast-ramping load that 
may impact the transmission system too quickly to be captured by conventional data 
acquisition systems (e.g., the need for phasor measurement units or similar equipment).  
We are also concerned that the Tariff does not require the transmission customer to 
enable CAISO to remotely disconnect large loads when necessary to maintain reliability 
of the transmission system, with the costs of such equipment directly assigned to the 
transmission customer, as well as the terms and conditions under which CAISO may 
remotely disconnect the large load (e.g., emergency conditions, so that transmission 
equipment is not harmed).  Further, we are concerned that the tariffs do not specify ramp 
rate or ride-through requirements with which the transmission customer taking 
transmission service on behalf of the large load must comply.  Lastly, we are concerned 
that the Tariff does not specify requirements for necessary control technologies and/or 
protection systems that may be necessary to limit transmission customer’s withdrawals 
 
160 E.g., ATC November 21 ANOPR Comments at 14; CAISO November 21 
ANOPR Comments at 10 (citing NERC Characteristics and Risks of Large Loads); Herb 
Schrayshuen November 21 ANOPR Comments at 2-5.

Docket No. EL26-71-000 
- 43 - 
from the transmission system as appropriate.161  CAISO and/or the Participating 
Transmission Owners should explain whether the tariffs remain just and reasonable 
without these or other ongoing operational requirements as part of the rates, terms, and 
conditions of transmission service or propose tariff revisions establishing necessary 
ongoing operational requirements. 
 
Fourth, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to 
be unjust and unreasonable because they lack pro forma provisions in a transmission 
service agreement, or other applicable agreement, between CAISO and/or the 
Participating Transmission Owner and the transmission customer taking transmission 
service on behalf of a large load to memorialize the above terms (e.g., equipment 
requirements, data requirements, remote disconnect capability).  We are concerned that, 
without such pro forma provisions in a transmission service agreement, or other 
applicable agreement, between CAISO and/or the Participating Transmission Owner and 
the transmission customer, CAISO may be unable to enforce ongoing operational 
requirements for transmission customers taking transmission service on behalf of large 
loads.  CAISO and/or the Participating Transmission Owners should explain whether 
their Tariffs remain just and reasonable without such pro forma provisions in a 
transmission service agreement, or other applicable agreement, or propose revisions to 
include pro forma provisions memorializing the ongoing operational requirements in a 
transmission service agreement between CAISO and/or the Participating Transmission 
Owner and the transmission customer.  
B. 
Cost Shifting Risk Among Transmission Customers 
 
We next preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be 
unjust and unreasonable because they lack adequate mechanisms to mitigate the risk of 
cost shifting among transmission customers, which may result in unjust and unreasonable 
rates for transmission service.  In particular, we are concerned about the apparent lack of 
(1) transparency regarding the assignment of network upgrades, and their associated 
costs, that are needed to provide transmission service to Eligible Customers on behalf of 
large loads; and (2) a pro forma cost recovery agreement between CAISO, the relevant 
transmission owner, and the Eligible Customer taking transmission service on behalf of 
large loads that help ensure that Eligible Customers bear the risk and are ultimately 
responsible for costs incurred to provide transmission service, including the cost of 
network upgrades.  
 
161 Specifically, as discussed below, the Commission has found that such 
necessary control technologies and/or protection schemes may be appropriate where 
Eligible Customers are taking one of the new transmission services.  See infra PP 101, 
105.

Docket No. EL26-71-000 
- 44 - 
 
We direct CAISO and the Participating Transmission Owners, to the extent the 
matters addressed herein implicate aspects of their tariffs, to explain whether the tariffs 
remain just and reasonable without (1) robust, accurate, and systematic provision of data 
on CAISO’s website in a single location, and in an easily accessible format that is 
searchable and allows users to filter the data, regarding the cost for network upgrades 
needed to provide transmission service to Eligible Customers on behalf of large loads; 
and (2) a pro forma cost recovery agreement between CAISO, the relevant transmission 
owner, and the Eligible Customer taking transmission service on behalf of a large load, or 
to propose tariff revisions to provide additional transparency and establish such a pro 
forma cost recovery agreement.  We encourage state regulators responsible for setting 
retail rates to provide input to CAISO regarding their transparency needs.   
1. 
Jurisdiction 
 
The Commission has a duty to address the risk of cost shifting among transmission 
customers that may result in unjust and unreasonable transmission rates.  As explained 
above, the Commission is obligated to ensure that the rates charged for jurisdictional 
transmission service—as well as any practice directly affecting such rates—are just and 
reasonable and not unduly discriminatory or preferential.  With respect to the addition of 
large loads to the transmission system, the Commission has exclusive authority to ensure 
that transmission rates are just and reasonable.  The costs of those upgrades to the 
transmission system (i.e., network upgrades) necessary to provide transmission service to 
Eligible Customers on behalf of large loads are inputs to jurisdictional transmission rates, 
and thus directly affect the Commission-jurisdictional rates paid by transmission 
customers.  To fulfill its responsibility to ensure that transmission rates are just and 
reasonable, the Commission must act to address the risk of cost shifting among 
transmission customers due to (1) the process transmission providers and/or transmission 
owners use to evaluate the facilities needed, and the associated costs, for the provision of 
transmission service to Eligible Customers on behalf of large loads and (2) speculative 
transmission service requests by Eligible Customers on behalf of large loads that could 
result in unjust and unreasonable transmission rates. 
 
In response to the ANOPR, many commenters raise concerns about the impact that 
large load additions can have on retail ratepayers, particularly the concern that other retail 
ratepayers may be forced to subsidize network upgrades needed to add large loads to the 
transmission system.162  While we appreciate and are similarly concerned about this 
issue, the Commission is limited to addressing jurisdictional transmission rates and as 
 
162 See, e.g., Southern California Edison December 5 ANOPR Comments at 3; see 
also CPUC November 21 ANOPR Comments at 16 (noting that it supports ratepayer 
protections and efforts to mitigate risk of cost shifting); State Entities November 21 
ANOPR Comments at 7-8.

Docket No. EL26-71-000 
- 45 - 
such, we do so herein.  As the Commission has explained, states determine how 
Commission-approved rates are collected among the relevant retail consumers along with 
the rates for state-jurisdictional matters.163  Specifically, states have authority over how 
the wholesale costs of providing electricity, including transmission of such electricity, to 
those retail customers are recovered through retail rates.164  We are encouraged by efforts 
taken by states to reform retail tariffs to address the potential for retail cost shifting as 
large loads come online,165 as well as voluntary efforts by transmission owners to protect 
retail ratepayers through cost recovery agreements with large loads.166  We are also 
encouraged by the execution of the President’s Ratepayer Protection Pledge, through 
which data center developers have committed to shield retail ratepayers from increased 
electricity prices.167  We expect that the additional cost transparency measures proposed 
in the following section will give state public utility commissions and other state 
regulators the information necessary to allow them to understand which transmission 
costs are caused by which transmission customers, so that they can sub-allocate these 
costs to the appropriate retail customers.  Indeed, the Commission’s objective in this 
proceeding is to respect the cooperative federalism approach established under the FPA.  
Specifically, one of the benefits of providing transparency on the costs of network 
upgrades necessary to provide transmission service to Eligible Customers on behalf of 
large loads is so that state regulators can use that information to protect residential and 
small commercial customers by incorporating those costs into the retail rates as they see 
fit given their authority to set rates for different classes of retail customers.   
 
We encourage state public utility commissions, state regulators and state consumer 
advocates to submit comments explaining whether this information is sufficient and 
granular enough or to submit comments explaining precisely which additional 
information on transmission cost allocation may be needed to inform proper state-
jurisdictional cost allocation. 
 
163 PJM Show Cause Order, 190 FERC ¶ 61,115 at P 167. 
164 Id. P 68. 
165 See, e.g., CPUC November 21 ANOPR Comments at 2; PG&E November 21 
ANOPR Comments at 1-2. 
166 See, e.g., Commonwealth Edison Co. 194 FERC ¶ 61,106 (2026); 
Commonwealth Edison Co., 194 FERC ¶ 61,109 (2026); Commonwealth Edison Co.,   
194 FERC ¶ 61,110 (2026); Commonwealth Edison Co., 194 FERC ¶ 61,113 (2026); 
PECO Energy Co., 193 FERC ¶ 61,148 (2025); Dayton Power & Light Co., 192 FERC    
¶ 61,103 (2025); Dayton Power & Light Co., 189 FERC ¶ 61,220 (2024). 
167 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026).

Docket No. EL26-71-000 
- 46 - 
2. 
Additional Cost Transparency 
 
We preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be 
unjust and unreasonable or unduly discriminatory or preferential because they do not 
contain provisions requiring the provision of data on CAISO’s website in a single 
location, and in an easily accessible format that is searchable and allows users to filter the 
data, on transmission service provided to Eligible Customers on behalf of large loads, for 
network upgrades evaluated in the local transmission planning process that are needed to 
accommodate transmission service to Eligible Customers on behalf of those large loads, 
and the costs for those network upgrades.  We preliminarily find that cost transparency 
measures are needed to provide stakeholders with sufficient information and visibility 
regarding the network upgrades, and their associated costs, needed to accommodate 
transmission service to Eligible Customers on behalf of large loads.   
 
In its annual Transmission Plan, CAISO publishes the status, costs, and scope of 
projects from prior Transmission Plans that are not yet completed and projects that are 
new to the Transmission Plan.168  The Transmission Plan for 2025-2026 includes a 
section on projects that CAISO reviewed and concurred with for large load 
interconnections that identifies the project, estimated in-service date, and cost.169  Section 
24 of CAISO’s Tariff describes the TPP and inputs required to develop the Transmission 
Plan,170 such as the Unified Planning Assumptions and Study Plan.  However, the Tariff 
does not specify what information the published Transmission Plan should contain, 
leaving the contents of the Transmission Plan to be prescribed in a Business Practice 
Manual.  The Transmission Planning Process Business Practice Manual requires the 
Transmission Plan to contain a description of:  (1) solutions with capital costs of $50 
million or more for which CAISO has completed all necessary studies; (2) solutions with 
capital costs of less than $50 million that have been approved by CAISO management; 
and (3) solutions for which additional studies are required.171   
 
168 See CAISO, Business Practice Manual for the Transmission Planning Process, 
§ 4.9.2 (Transmission Plan Contents). 
169 See CAISO, 2025-2026 Transmission Plan 91-94 (May 12, 2026), 
https://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/2025-2026-
Transmission-planning-process. 
170 CAISO defines the Transmission Plan as:  “The report prepared by the CAISO 
on annual basis pursuant to Section 24, which documents the outcome of the 
Transmission Planning Process as defined in the Study Plan.”  CAISO Tariff, app. A, 
Transmission Plan (0.0.0). 
171 See CAISO, Business Practice Manual for the Transmission Planning Process,

Docket No. EL26-71-000 
- 47 - 
 
However, CAISO’s Tariff and/or the TO Tariffs do not appear to require that 
information identifying the network upgrades needed to accommodate transmission 
service to Eligible Customers on behalf of large loads and the costs of those network 
upgrades determined through the local transmission planning processes be readily 
available on CAISO’s website in a single location, and in an easily accessible format that 
is searchable and allows users to filter the data.  We acknowledge and are encouraged by 
the fact that CAISO has published in its most recent Transmission Plan some of the 
transmission facilities driven by large load additions, but we preliminarily find that it is 
necessary that CAISO’s Tariff and/or the TO Tariffs require such information to be 
transparently and consistently reported in the future.  The speed and scale with which 
Eligible Customers are seeking transmission service on behalf of large loads makes it 
difficult for interested parties, including transmission customers and state regulators, to 
accurately assess which transmission costs are the result of accommodating transmission 
service for Eligible Customers to serve large loads.  We are concerned that the potentially 
speculative nature of accommodating transmission service for Eligible Customers on 
behalf of large loads,172 the speed and scale with which large loads are seeking to be 
added to the transmission system, the projected need for significant network upgrades to 
provide transmission service to Eligible Customers on behalf of large loads, and the lack 
of centralized information on the associated transmission costs in CAISO hamper the 
ability of the Commission and stakeholders (including transmission customers and state 
regulators173) to understand and accurately assess the relationship between the addition of 
large loads to the transmission system and wholesale transmission costs.   
 
We are concerned that without sufficient transparency regarding the network 
upgrades, and their associated costs, needed to provide transmission service to Eligible 
Customers on behalf of large loads, stakeholders may lack information and visibility 
 
§ 4.9.2.1 (Transmission Plan Contents). 
172 See supra P 55. 
173 See Transcript, NARUC Collaborative, Docket No. AD24-7-000, at 16-17 
(Feb. 11, 2026) (Chair Bagot, Virginia) (asserting that additional transparency at the RTO 
level would help the states get the information they need to “identify . . . that bucket of 
costs” related to large load-driven transmission costs), 19 (Commissioner Chattopadhyay, 
New Hampshire) (noting the need for “all parties to be able to see things transparently” 
with respect to wholesale transmission costs), 35-37 (Chair Martz, Iowa) (raising concern 
that currently RTOs/ISOs do not have to clearly explain when a “bucket of costs is 
specifically for this large load” and noting that “if we, at the state level, can’t see the 
driver [of transmission costs], we can’t assign the cost to the causer[,] [a]nd so we need 
that clarity”), 69-70 (Chair Myers, Arizona) (“[B]eing able to allocate the large load costs 
to the correct bucket when it gets to the states is kind of a top priority.”).

Docket No. EL26-71-000 
- 48 - 
regarding the costs driven by large load additions.  We preliminarily find that, for 
network upgrades evaluated in the local transmission planning process174 that are needed 
to accommodate transmission service for Eligible Customers on behalf of large loads are 
evaluated, CAISO must provide clear, timely, and detailed information regarding the 
extent to which accommodating transmission service for Eligible Customers on behalf of 
large loads necessitates network upgrades, as well as the costs of those network upgrades. 
 
We note that centralized information regarding network upgrades needed for 
accommodating transmission service for Eligible Customers on behalf of large loads 
would also help inform stakeholders at the state and local level to address affordability 
and other challenges posed by the integration of large loads.  Indeed, commenters state 
that the opaque nature of accommodating transmission service for Eligible Customers on 
behalf of large loads, and the associated network upgrades required to provide that 
transmission service, prevent wholesale and retail customers, states, and other 
stakeholders from understanding such costs.175        
 
174 Our concern with transparency regarding network upgrades needed to provide 
transmission service to Eligible Customers on behalf of large loads, as well as the costs of 
such upgrades, is limited to network upgrades planned through the local transmission 
planning process.  While we acknowledge that in Order No. 890, the Commission 
adopted requirements for RTOs/ISOs, as well as for transmission owners to the extent 
that they perform transmission planning within an RTO/ISO, to have open and 
transparent transmission planning processes, there are additional requirements that apply 
to regional transmission planning processes (that do not apply to local transmission 
facilities) and thus is relevant to the distinction here.  Specifically, under Order No. 1000, 
public utility transmission providers, including RTOs/ISOs, must evaluate as part of their 
regional transmission planning process whether there are transmission facilities that more 
efficiently or cost-effectively meet the transmission planning region’s identified 
transmission needs.  See Order No. 1000, 136 FERC ¶ 61,051 at P 11. 
175 See OCC November 21 ANOPR Comments at 3 (“Consumers, state advocates 
and state regulatory commissions have a right to know which entities are seeking large-
load interconnections, the nature of the requested service, and how related costs could 
flow through to transmission and distribution rates.”); U.S. House of Representatives 
Committee on Energy and Commerce Ranking Members November 21 ANOPR 
Comments at 2 (urging the Commission to “require sufficient transparency from grid 
operators so it can determine which specific large load facilities are responsible for grid 
upgrade needs”); see also CPUC November 21 ANOPR Reply Comments at 16-17 
(asserting that the public posting of large load cost responsibility determinations would 
improve transparency, to the benefit of businesses and ratepayers).

Docket No. EL26-71-000 
- 49 - 
 
Accordingly, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs 
appear to be unjust and unreasonable because they do not require the provision of data on 
CAISO’s website in a single location, and in an easily accessible format that is searchable 
and allows users to filter the data that identifies the network upgrades that are needed to 
accommodate transmission service for Eligible Customers on behalf of large loads, and 
the costs of those network upgrades.  CAISO and/or the Participating Transmission 
Owners should explain whether their tariffs remain just and reasonable without 
provisions that would require CAISO and the Participating Transmission Owners to 
publicly post and regularly update data that details:  (1) the aggregate amounts of 
proposed large load additions in CAISO’s footprint or the Participating Transmission 
Owner’s service territory, including the aggregate amounts in each transmission pricing 
zone; and (2) the planned network upgrades needed to accommodate transmission service 
for Eligible Customers on behalf of large loads, identified by type of equipment and 
network upgrade (e.g., new substation, reconductoring, a new high-voltage transmission 
line) for each transmission service request; and (3) cost estimates for those network 
upgrades, or propose such tariff revisions.  CAISO and the Participating Transmission 
Owners should also consider what other data related to transmission costs resulting from 
the provision of transmission service to Eligible Customers on behalf of large loads 
would be useful to include on CAISO’s website.  To the extent there are concerns about 
data confidentiality, CAISO and the Participating Transmission Owners should consider 
whether there are ways to mitigate those concerns while still providing the necessary 
transparency. 
3. 
Cost Recovery Agreements 
 
We next preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be 
unjust and unreasonable because they lack adequate mechanisms to mitigate the risk of 
cost shifting among transmission customers, which may result in unjust and unreasonable 
rates for transmission service.  In particular, we are concerned about the apparent lack of 
a pro forma cost recovery agreement between CAISO, the relevant transmission owner, 
and the Eligible Customer taking transmission service on behalf of large loads that help 
ensure that Eligible Customers bear the risk and are ultimately responsible for costs 
incurred to provide transmission service, including the cost of network upgrades. 
 
Several commenters discuss the risk of cost shifting among transmission 
customers that could result from transmission service requests by Eligible Customers on 
behalf of large loads.176  Commenters also argue that retail-level large load tariffs do not 
 
176 See, e.g., Buckeye November 21 ANOPR Comments at 8-13; APPA November 
21 ANOPR Comments at 6 (“Wholesale transmission customers in particular could be 
left shouldering massive costs if new large loads do not ultimately attain or maintain the 
level of electricity demand that is being forecasted.”); NRECA November 21 ANOPR 
Comments at 21 (noting the risk that other transmission customers could bear stranded

Docket No. EL26-71-000 
- 50 - 
protect wholesale transmission customers from cost shifting.177  Specifically, commenters 
in the record contend that, while a retail-level large load tariff protects the load serving 
entity taking wholesale transmission service and its retail customers, it fails “to provide 
any mechanism to protect other wholesale transmission customers” from stranded 
transmission costs.178  The Kansas Commission states that while its Large Load Power 
Services rate plan that requires large loads to make minimum payments toward 
transmission costs protects retail ratepayers from large-load driven transmission costs, it 
cannot protect against cost shifting associated with regional transmission buildout where 
“the large loads that formed the basis for the [regional] transmission plans do not 
materialize, leaving only existing customers to pay for generational expansions of the 
transmission grid.”179  TAPS contends, moreover, that it is not sufficient for the 
Commission to rely on transmission owners to voluntarily file cost recovery agreements 
to protect transmission customers from cost shifting for network upgrades.180   
 
We are likewise concerned that there may be speculative transmission service 
requests by Eligible Customers on behalf of large loads that could result in cost shifting 
among transmission customers, which may lead to unjust and unreasonable increases in 
jurisdictional transmission rates.  When a transmission owner constructs network 
upgrades to accommodate the provision of transmission service to an Eligible Customer 
on behalf of a large load, those transmission costs will be included in the transmission 
owner’s transmission revenue requirement.  If, however, the Eligible Customer takes less 
transmission service than anticipated because the large load operates at a lower demand 
than anticipated or fails to materialize at all, other transmission customers may see an 
increase in transmission rates.  In such a situation, those other transmission customers 
 
upgrade costs caused by large loads that they cannot absorb); TAPS November 21 
ANOPR Comments at 22-24; California DWR November 21 ANOPR Comments at 8. 
177 TAPS November 21 ANOPR Comments at 26 (“[A] number of state 
commissions are moving forward with retail large load tariffs, which provide for varying 
protections, but may not require the revenues and minimum demand levels to be included 
in wholesale transmission rates.”); Buckeye November 21 ANOPR Comments at 14-16; 
Kansas Commission November 21 ANOPR Comments at 15-16. 
178 Buckeye November 21 ANOPR Comments at 14-15; see TAPS November 21 
ANOPR Comments at 26-27 & nn.50-51.  
179 Kansas Commission November 21 ANOPR Comments at 11-12.  
180 TAPS November 21 ANOPR Comments at 25-26 (noting that AES Ohio 
“committed to reflecting the payments it received from the data center in its Commission-
jurisdictional transmission revenue requirement so that other customers are protected,” in 
a Construction Service Agreement with Amazon).

Docket No. EL26-71-000 
- 51 - 
may have to pay for potentially unnecessary network upgrades that they neither caused 
the need for nor benefit commensurately from.  In other words, this introduces the risk 
that costs may be unfairly shifted to other transmission customers, which may result in 
those costs then being passed through to residential customers, among others.  
 
CAISO’s Tariff and/or the TO Tariffs do not require cost recovery agreements 
between CAISO, the relevant transmission owner and the Eligible Customer taking 
transmission service on behalf of a large load.  Such agreements would help ensure that 
the Eligible Customer makes a minimum contribution to the transmission owner’s 
transmission revenue requirement commensurate with the costs incurred to provide the 
requested transmission service, including the costs of any needed network upgrades.  
Absent such cost recovery agreements, we are concerned that there is no mechanism to 
help ensure that Eligible Customers taking transmission service on behalf of large loads 
(as opposed to other transmission customers) bear the risk of, and are ultimately 
responsible for, the costs incurred to provide them with the requested transmission 
service, including the costs of any needed network upgrades.   
 
Accordingly, we preliminarily find that, in order to prevent unjust and 
unreasonable cost shifting among transmission customers, it appears necessary for 
CAISO, the relevant transmission owner, and the Eligible Customer taking transmission 
service on behalf of a large load to enter into a cost recovery agreement that requires the 
Eligible Customer to make a minimum contribution toward the transmission owner’s 
transmission revenue requirement if the Eligible Customer ultimately takes less 
transmission service than anticipated because the large load does not materialize as 
planned or is not developed at all.  We preliminarily find that such cost recovery 
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 incurred to 
provide them with the requested transmission service, including the costs of any needed 
network upgrades) rather than having those costs paid by other transmission customers 
that neither caused the need for nor benefit commensurately from those network 
upgrades.181  Our preliminary finding is not intended to alter or call into question existing 
regional cost allocation methods for network upgrades, but instead is focused on helping 
to prevent cost shifting among transmission customers.   
 
We note that several transmission owners and large load customers have filed cost 
recovery agreements (Transmission Security Agreements or Construction Service 
Agreements) with the Commission that guarantee minimum contributions from a large 
load customer (rather than from the Eligible Customer taking transmission service on 
behalf of the large load customer) to the transmission owner’s transmission revenue 
 
181 See, e.g., Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 
(D.C. Cir. 2004); Ill. Com. Comm’n v. FERC, 576 F.3d 470, 476 (7th Cir. 2009).

Docket No. EL26-71-000 
- 52 - 
requirement.182  Although we decline to preliminarily find that cost recovery agreements 
between the transmission owner and the large load customer (rather than the Eligible 
Customer) are necessary to ensure just and reasonable transmission rates, we continue to 
find that such agreements directly affect Commission-jurisdictional transmission rates.  
Therefore, to the extent a transmission owner and a large load customer enter into a cost 
recovery agreement (whether voluntarily or pursuant to state law) through which the 
large load customer guarantees contributions to the transmission owner’s Commission-
jurisdictional transmission revenue requirement, we find that such an agreement should 
be filed with the Commission.183  To reduce duplicative credit requirements and 
transaction costs, we direct further briefing on whether it would be appropriate for such 
an agreement to substitute for the requirement on the Eligible Customer to enter into a 
cost recovery agreement with the transmission owner, if the agreement with the large 
load customer provided comparable or greater protection against cost shifting among 
transmission customers than an agreement between the transmission owner and the 
Eligible Customer would.   
 
In addition to our preliminary finding that CAISO’s Tariff and/or the TO Tariffs 
are unjust and unreasonable because they lack a pro forma cost recovery agreement of 
this type, we also preliminarily find that the minimum contribution required pursuant to 
such an agreement should be based on the level of jurisdictional transmission service (in 
MW) requested by the Eligible Customer on behalf of the large load.  That figure is in 
turn tied to how CAISO and/or the Participating Transmission Owners will study the 
requested transmission service and determine any necessary network upgrades that must 
be developed to provide the requested transmission service.  We note, however, that there 
may be other just and reasonable methods for determining this minimum contribution, 
including methods that account for potential timing differences between when costs are 
incurred to develop needed Network Upgrades and the pace at which the large load ramps 
toward energizing at its full level of requested service.  We further preliminarily find 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.  We find that a cost recovery agreement with a specified 
minimum financial contribution and financial security sufficient to secure such 
contribution is necessary to mitigate cost shifting if the Eligible Customer ultimately 
takes less transmission service than anticipated because the large load does not 
 
182 See supra note 166. 
183 We emphasize that this finding is in no way intended to preempt or interfere 
with the ability of states to implement ratepayer protection measures designed to mitigate 
cost shifting among retail customers, such as through state-jurisdictional large load 
tariffs.

Docket No. EL26-71-000 
- 53 - 
materialize as planned or is not developed at all.  We preliminarily find that an Eligible 
Customer may include a credit support or other financial security posted by a large load 
as part of a retail agreement to avoid creating duplicative credit support requirements.  
CAISO and/or the Participating Transmission Owners should explain why such a pro 
forma cost recovery agreement is not necessary to ensure just and reasonable rates or 
propose such a pro forma cost recovery agreement.  To the extent that stakeholders 
believe that other mechanisms could address our cost shifting concerns, we seek further 
briefing as discussed below.184 
 
Although the Commission’s concerns surrounding cost shifting described above 
may not present the same in CAISO as in other RTOs/ISOs, we nevertheless remain 
concerned that cost shifting may occur.  We acknowledge that the Participating 
Transmission Owners have wholesale load interconnection processes by which Eligible 
Customers may request interconnection of their wholesale loads.  We note that those 
processes and the related studies may result in network upgrades or transmission 
expansion projects for which the terms and conditions are memorialized in an 
interconnection agreement and the costs directly assigned to the Eligible Customer.  
Nevertheless, we remain concerned that cost shifting may occur through the recovery of 
the Participating Transmission Owners’ transmission revenue requirement through the 
Access Charge due to speculative requests to accommodate transmission service to serve 
large loads, i.e., where large loads do not materialize or where the MW quantity of such 
large loads is lower than proposed, or because of the study process used to evaluate the 
facilities needed, and the associated costs, to accommodate the provision of transmission 
service to Eligible Customers on behalf of large loads.  We are concerned because, as 
explained above, the wholesale load interconnection process in the TO Tariffs only 
applies to a subset of Eligible Customers.185  We understand that transmission projects 
resulting from local transmission planning and regional transmission planning processes 
may be built to accommodate load additions that are not interconnected pursuant to the 
TO Tariff.  While the interconnection of such load may be subject to a process governed 
by the relevant local regulatory authority, the costs of network upgrades built to 
accommodate that load growth that is identified through CAISO’s Transmission Planning 
Process are included in the Participating Transmission Owners’ transmission revenue 
requirements and recovered through the Access Charge.  Further, the Participating 
Transmission Owners should demonstrate whether, and if so, how, existing requirements 
regarding interconnection agreements for wholesale load interconnections protect against 
cost shifting.   
 
184 See infra P 125.  
185 See supra P 25.

Docket No. EL26-71-000 
- 54 - 
 
Lastly, we expect that any payments made by an Eligible Customer to a 
transmission owner pursuant to such a cost recovery agreement (or by a large load to a 
transmission owner pursuant to other voluntary agreement) will be appropriately credited 
toward transmission owners’ transmission revenue requirements consistent with the 
Commission’s cost-of-service regulations.186  We preliminarily find that it appears 
reasonable for filers of formula rates to provide a separate workpaper in the annual 
informational filing describing how any payments made pursuant to a cost recovery 
agreement are reflected in the transmission owner’s transmission formula rate. 
C. 
Co-Location Arrangements and Load with Behind the Meter 
Generation 
 
The Commission recently addressed in the PJM region the need for sufficiently 
clear and consistent tariff provisions addressing the rates, terms, and conditions that apply 
to co-location arrangements and for transmission services that reflect an Eligible 
Customer taking transmission service on behalf of Eligible Load187 that is willing and 
able to limit its energy withdrawals from the transmission system under certain 
conditions.188  As discussed below, CAISO’s Tariff appears to be unjust and 
unreasonable because it lacks such provisions.  
 
We direct CAISO and the Participating Transmission Owners, to the extent the 
matters addressed herein implicate aspects of their TO Tariffs, to explain whether the 
Tariff remains just and reasonable without provisions addressing the rates, terms and 
conditions that apply to interconnection customers serving co-located load and for 
Eligible Customers taking transmission service on behalf of Eligible Load, or propose 
Tariff revisions establishing the rates, terms, and conditions that apply to co-location 
arrangements.189  We recognize that CAISO has begun a stakeholder policy initiative 
which may consider reforms related to co-location arrangements, and we encourage 
 
186 See 18 C.F.R. pt. 101 (2025). 
187 As discussed below, for purposes of this order, we will use the term Eligible 
Load to refer to co-located load and/or load with behind the meter generation.  See infra 
P 90. 
188 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 2; PJM Co-Location 
Rehearing Order, 195 FERC ¶ 61,209 at PP 91, 102.  
189 While this section is directed to both CAISO and the Participating 
Transmission Owners, we believe it will mostly implicate the CAISO Tariff, as it appears 
that only the CAISO Tariff involves matters related to co-location arrangements because 
the CAISO Tariff governs the generator interconnection process and because CAISO is 
the transmission provider.

Docket No. EL26-71-000 
- 55 - 
CAISO to consider whether these efforts would, either fully or in part, address the 
Commission’s concerns that the Tariff appears to be unjust and unreasonable.   
1. 
Definition 
 
The PJM Co-Location Order adopted the following definition of co-located load:  
a “configuration [that] refers to end-use customer load that is physically connected to the 
facilities of an existing or planned Customer Facility on the Interconnection Customer’s 
side of the Point of Interconnection to the PJM Transmission System.”190  The PJM     
Co-Location Order used the term co-location arrangement when referring to both the co-
located load and the associated generator.191   
 
For purposes of this order, it appears that it would be reasonable to define          
co-located load as a configuration that refers to end-use customer load that is physically 
connected to the facilities of an existing or planned generating facility on the generator 
interconnection customer’s side of the point of interconnection to the RTO/ISO’s 
transmission system.  In this order, we will also use the term co-location arrangement 
when referring to both the co-located load and the associated generating facility. 
 
The CAISO Tariff does not define “Behind the Meter Generation.”  For purposes 
of this order, it appears reasonable based upon the record to refer to Behind the Meter 
Generation (BTMG) similarly to how that term is used in the PJM Co-Location Order, as 
a generating facility that delivers energy to load without using the transmission system or 
any distribution facilities.192 
 
For purposes of this order, we will use the term Eligible Load to refer to co-
located load and/or load with BTMG.193 
2. 
Jurisdiction 
 
As explained in the PJM Co-Location Order, the Commission has exclusive 
jurisdiction to oversee the interconnection of generating facilities to the interstate 
transmission system, including where generators serve co-located load.194  The 
 
190 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 164 (alterations in original). 
191 Id. P 3. 
192 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 7 n.19 (citing PJM, 
Intra-PJM Tariffs, OATT, § I.1 (Definitions - A-B) (21.0.0)). 
193 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 91. 
194 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171 (citing 16 U.S.C.

Docket No. EL26-71-000 
- 56 - 
Commission retains exclusive authority to regulate the procedures and agreements that 
apply to the interconnection of a generator that will make wholesale sales, both where the 
generator interconnects directly to the interstate transmission system and where a 
generator interconnects to dual-use distribution facilities.195  Further, the Commission has 
exclusive jurisdiction over the provision of transmission service to an Eligible Customer 
on behalf of Eligible Load, provided that transmission of electricity is in interstate 
commerce.196  As the Commission found in the PJM Co-Location Order, we continue to 
acknowledge that the application of these principles depends on the specific facts and 
circumstances presented in particular situations.197   
 
Additionally, we reiterate that certain other aspects of co-location arrangements 
fall squarely within the jurisdiction of the states.  As we explained in the PJM Co-
Location Order, states retain exclusive authority over the specific terms of retail sales and 
retail rate design, including retail cost allocation to the co-located load; which entities are 
legally permitted to provide electricity to retail customers in co-location arrangements; 
and which generating facilities are sited and allowed to serve co-located load.198 
3. 
Tariff Provisions 
 
We preliminarily find that CAISO’s Tariff appears to be unjust and unreasonable 
or unduly discriminatory or preferential because it does not contain provisions addressing 
with sufficient clarity and consistency the rates, terms, and conditions of service that 
apply to interconnection customers serving co-located load.  We also preliminarily find 
that CAISO’s Tariff appears to be unjust and unreasonable or unduly discriminatory or 
preferential because it does not contain provisions addressing with sufficient clarity and 
consistency transmission services that reflect that an Eligible Customer taking 
transmission service on behalf of Eligible Load is willing and able to limit its energy 
withdrawals from the transmission system under certain conditions.   
 
The absence of such provisions may leave entities unable to determine what steps 
they can or must take to effectuate co-location arrangements of various configurations.  
One step includes determining how interconnection customers serving co-located load 
 
§§ 824d, 824e; EPSA, 577 U.S. at 278). 
195 Id. P 172 (citing Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277, 
1282 (D.C. Cir. 2007)). 
196 Id. P 173. 
197 Id. P 174. 
198 Id. PP 167-169.

Docket No. EL26-71-000 
- 57 - 
may use generator interconnection processes in CAISO’s Tariff to facilitate their          
co-location arrangements.  A further step includes requiring interconnection customers 
serving co-located load to specify the Eligible Customer taking transmission service on 
behalf of the co-located load under the Tariff for purposes of assessing charges, including 
the appropriate charges for wholesale services that should apply to such Eligible 
Customers.  Without such a common and consistent understanding of entities’ 
responsibilities relevant to co-location arrangements, many of which may significantly 
affect rates and are realistically susceptible of specification,199 we are concerned that 
these arrangements may be developed in a manner that is itself unjust and unreasonable 
or that may result in unjust and unreasonable rates for other customers.   
 
Moreover, as discussed further below, we are especially concerned that the 
absence of Tariff provisions addressing transmission and ancillary service rates for 
Eligible Customers taking transmission service on behalf of Eligible Load creates the 
potential that Eligible Customers, on behalf of Eligible Load, may not be required to pay 
for wholesale transmission services that they receive, as required by the cost causation 
principle.  That principle provides that all Commission-jurisdictional rates and charges 
must “reflect to some degree the costs actually caused by the customer who must pay for 
them,”200 and that costs must be allocated in a manner that is at least roughly 
commensurate with the benefits that entity receives.201 
 
We preliminarily find that CAISO’s Tariff appears to be unjust and unreasonable 
because it lacks sufficient clarity and consistency as to the rates, terms, and conditions of 
service that apply to interconnection customers serving co-located load, including the 
scope of the analyses CAISO performs as part of its existing study process to evaluate the 
impacts of co-location arrangements, which may need to account for any potential 
dynamic impacts of co-located load and any potential impacts of requests to modify an 
existing generating facility’s interconnection service level to serve co-located load on 
transmission system reliability.  Additionally, in the PJM Co-Location Order, the 
Commission found that it was necessary to clarify that interconnection customers seeking 
to use new generating facilities to serve co-located load may (1) request interconnection 
service at a level below the generating facility’s maximum facility output; (2) use 
existing procedures to accelerate interconnection requests that satisfy certain tariff 
criteria; and (3) request provisional interconnection service and surplus interconnection 
 
199 Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 F.4th 1307, 1312 (D.C. Cir. 
2023). 
200 Midwest ISO Transmission Owners v. FERC, 373 F.3d at 1368. 
201 See, e.g., Ill. Com. Comm’n v. FERC, 576 F.3d at 476.

Docket No. EL26-71-000 
- 58 - 
service.202  As such, interconnection customers seeking to use their generating facilities 
to serve co-located load have no means of knowing the appropriate mechanism for setting 
forth the terms and conditions of co-location arrangements.  We are concerned that the 
details of such a process—including the existing rules and studies applicable to such 
generator interconnection arrangements—are not sufficiently detailed in the Tariff to 
ensure clarity for how interconnection customers may seek to serve co-located load.  
Moreover, without an Eligible Customer designated to take transmission service on 
behalf of a co-located load, there is no mechanism for CAISO to address situations in 
which a co-located load withdraws energy from the transmission system.   
 
Therefore, we preliminarily find that CAISO’s Tariff appears to be unjust and 
unreasonable because it does not contain provisions addressing with sufficient clarity and 
consistency the rates, terms, and conditions of service that apply to interconnection 
customers serving co-located load.  CAISO should explain whether the Tariff remains 
just and reasonable without such provisions, or propose Tariff revisions. 
 
We have similar concerns regarding CAISO’s existing rate designs for 
transmission and ancillary services that are used by Eligible Customers taking 
transmission service on behalf of Eligible Load.  The Commission has previously found 
that co-located loads that are synchronized with the transmission system use and benefit 
from at least some ancillary services and may be reasonably charged for such benefits.203  
Specifically, the Commission has found that, regardless of whether a co-located load 
withdraws energy from the transmission system, co-located load relies on and benefits 
from regulation service and black start service, and concluded that Eligible Customers 
taking one of the new transmission services (discussed below) on behalf of co-located 
load must pay for these ancillary services on a gross demand basis.204  In the PJM Co-
Location Rehearing Order, the Commission applied these findings to Eligible Customers 
taking transmission service on behalf of load with BTMG.205  However, CAISO’s Tariff 
does not appear to include a mechanism by which an Eligible Customer, on behalf of 
Eligible Load, would be charged for ancillary services commensurate with its usage of 
such services, particularly if such customer did not withdraw energy from the 
transmission system.   
 
202 PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 231-235.  PJM’s 
compliance filing proposing revisions in response to these directives was accepted in part 
on April 16, 2026.  PJM Interconnection, L.L.C., 195 FERC ¶ 61,030.  
203 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 183. 
204 Id. PP 184-185. 
205 See PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 400.

Docket No. EL26-71-000 
- 59 - 
 
Therefore, we preliminarily find that CAISO’s Tariff appears to be unjust and 
unreasonable because it does not address whether and how Eligible Customers taking one 
of the new transmission services on behalf of Eligible Loads will be charged for their use 
of regulation and black start services, which introduces the risk that Eligible Load may 
benefit from regulation and black start services without contributing to cost recovery for 
such services.  As noted in the PJM Co-Location Order, this introduces the risk that costs 
may be allocated entirely to other transmission customers and passed through to 
residential customers, among others.206  CAISO should explain whether the Tariff 
remains just and reasonable without requiring Eligible Customers taking one of the new 
transmission services on behalf of Eligible Loads to pay for regulation and black start 
services on a gross demand basis, or propose Tariff revisions that require them to do so. 
 The Commission also found in the PJM Co-Location Order that Eligible 
Customers taking transmission service on behalf of co-located loads are willing and able 
to limit their energy withdrawals from the transmission system under certain conditions.  
As such, the Commission found that Eligible Customers taking transmission service on 
behalf of co-located loads should be allowed to choose a transmission service that aligns 
with their use of the transmission system and therefore aligns the charges for service with 
the benefits received.207  On rehearing, the Commission found that it is just and 
reasonable for these services to be available to Eligible Customers taking transmission 
service on behalf of loads with BTMG.208  We are concerned that CAISO’s Tariff lacks 
transmission services that would reflect the ability of Eligible Customers on behalf of 
Eligible Loads to take transmission services that align with their use of the transmission 
system, which may result in inefficient and costly transmission buildout and costs paid by 
transmission customers.209   
 Therefore, we also preliminarily find that CAISO’s Tariff appears to be unjust and 
unreasonable because it does not include transmission services that reflect Eligible 
Customers taking transmission service on behalf of Eligible Load that are willing and 
able to limit their use of the transmission system under certain conditions.  CAISO should 
 
206 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 159. 
207 Id. P 199. 
208 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 101-103. 
209 See, e.g., PSEG November 21 ANOPR Comments at 20 (“The Commission’s 
long-standing policy is to encourage reduced use of the transmission system, which 
would in turn reduce upgrades to the transmission system, to the benefit of all 
transmission customers.  For instance, if a co-located load’s use of the transmission 
system is limited (or to a lesser degree) than other traditional in front of the meter loads, 
it should be responsible for costs based on its limited use.”).

Docket No. EL26-71-000 
- 60 - 
explain whether the Tariff remains just and reasonable without the transmission services 
described by the Commission in the PJM Co-Location Order, with regional variation as 
appropriate, being available to Eligible Customers taking transmission service on behalf 
of Eligible Load, or propose appropriate Tariff revisions.  Specifically, CAISO should 
explain whether the Tariff remains just and reasonable without (1) an interim non-firm 
network transmission service while network upgrades are being constructed (i.e., interim 
NITS) and (2) permanent firm and non-firm contract demand transmission services 
(transmission service up to a specified MW quantity, i.e., the contract level, on a firm or 
non-firm basis).  In the alternative, CAISO may explain whether, given that CAISO does 
not offer the transmission services required by Order No. 888,210 CAISO’s existing 
transmission service framework addresses the concerns described herein, or explain what 
specific changes to its existing transmission service framework would effectively provide 
the same range of transmission service options for flexible large loads as in the PJM Co-
Location Order.  We note that the Commission has found it just and reasonable that, in 
order for an Eligible Customer to take interim NITS, firm contract demand transmission 
service, and non-firm contract demand transmission service, an Eligible Customer must 
have necessary control technologies and/or protection systems, which may include a 
special protection scheme, to limit its energy withdrawals to its approved level.211 
 Finally, we preliminary find that CAISO’s Tariff is unjust and unreasonable 
because it allows load with BTMG to net its BTMG against its load for purposes of 
calculating Regional Access Charges.212  In the PJM Co-Location Order, the Commission 
found that PJM’s BTMG rules, which allowed load serving entities that provide service 
to loads with qualifying BTMG to reduce their costs by netting output from BTMG in the 
calculation of their peak demand for the purpose of determining NITS charges, were 
unjust and unreasonable.213  The Commission concluded that PJM’s BTMG rules were no 
longer consistent with cost causation principles because large loads configured in a 
BTMG arrangement with significant generation will raise cost shifting concerns 
compared to loads pursuing smaller amounts of netting.214  The Commission also found 
that such rules could lead to reliability and resource adequacy risks because PJM is 
 
210 See supra P 39.  
211 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. 
212 The Regional Access Charge is calculated by summing the Regional 
Transmission Revenue Requirements of all Participating Transmission Owners and 
Approved Project Sponsors and dividing the sum by the gross loads of all Participating 
Transmission Owners.  See CAISO Tariff, app. F (Rate Schedules) (30.0.0), § 5.4. 
213 PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 7, 186. 
214 Id. P 186.

Docket No. EL26-71-000 
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obligated to serve transmission customers using BTMG, but does not consider such 
customers in transmission and resource adequacy planning.215  The Commission directed 
PJM to revise its retail BTMG rules, including establishing a MW threshold for the 
amount of load at a particular electrical location that network customers may net by using 
BTMG.216  We are similarly concerned that CAISO’s Tariff allows Eligible Customers 
that provide service to loads with BTMG to reduce their network service charges because 
the definition of gross load, which is used to calculate the Regional Access Charge, 
excludes load of a retail customer served by its own onsite generating unit or energy 
storage device.217  CAISO should explain whether the Tariff remains just and reasonable 
even though it allows netting of BTMG from gross load for purposes of determining 
Regional Access Charges for loads with BTMG, or propose Tariff revisions.  
Recognizing potential impacts on existing customers, we note that CAISO may explain 
whether current BTMG rules for customers that fall below a new MW materiality 
threshold for the amount of load at a particular electrical location that network customers 
may net using BTMG remain just and reasonable. 
D. 
Extending New Transmission Services to Eligible Customers Taking 
Service on Behalf of Flexible Large Loads 
 In response to the ANOPR, a number of commenters argue that certain large loads 
are able to limit their withdrawals from the transmission system under certain conditions.  
Namely, commenters observe that flexible large loads218 can quickly and verifiably adjust 
their consumption in response to system conditions or price signals.219  Commenters in 
the ANOPR also observe that, where load studies and system planning consider the 
flexible nature of large loads, flexible large loads can potentially defer or reduce the need 
 
215 Id. 
216 Id. P 221. 
217 CAISO Tariff, § 26.1(c); id. app. A, Gross Load (3.0.0). 
218 For purposes of this order, “flexible” large loads are a subset of large loads, as 
used in this order, that are not co-located with generation, but are willing and able to limit 
their energy withdrawals from the transmission system under certain conditions. 
219 See, e.g., AEMA November 21 ANOPR Comments at 1-2; Land Trust Alliance 
November 21 ANOPR Comments at 10; California DWR November 21 ANOPR 
Comments at 5; CEBA November 21 ANOPR Comments at 14-15; ClearPath November 
21 ANOPR Comments at 2-4; Digital Energy Council November 21 ANOPR Comments 
at 1; EDF Power November 21 ANOPR Comments at 4; Emerald November 21 ANOPR 
Comments at 2; Verrus November 21 ANOPR Comments at 4.

Docket No. EL26-71-000 
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for network upgrades, among other potential benefits.220  In recognition of this flexibility, 
many commenters support new transmission services that reflect the operational 
capabilities of flexible large loads, including interim NITS while network upgrades are 
constructed and non-firm transmission service.221   
 We preliminarily find that CAISO’s Tariff appears to be unjust and unreasonable 
because it does not include transmission services that reflect Eligible Customers taking 
transmission service on behalf of flexible large loads that are willing and able to limit 
their use of the transmission system under certain conditions.222  With limited exceptions, 
daily transmission service with all energy treated as “new firm use” is the only type of 
transmission service available in CAISO.223  While this remains a just and reasonable 
option for an Eligible Customer to take on behalf of a flexible large load, based on the 
record before us, we preliminarily find that new transmission services should be available 
to reflect the operational reality that large loads may use the transmission system to 
differing extents and certain large loads are willing and able to limit their use of the 
transmission system under certain conditions.224  As explained above, the Commission 
found that Eligible Customers taking transmission service on behalf of Eligible Load 
should be allowed to choose a transmission service that aligns with their use of the 
transmission system and therefore aligns the charges for service with the benefits 
 
220 See, e.g., AEMA November 21 ANOPR Comments at 5; ELCON November 
21 ANOPR Comments at 9; Emerald November 21 ANOPR Comments at 6-7; Institute 
for Progress November 21 ANOPR Comments at 11; Land Trust Alliance November 21 
ANOPR Comments at 10; California DWR November 21 ANOPR Comments at 5; LS 
Power November 21 ANOPR Comments at 5; Microsoft November 21 ANOPR 
Comments at 10-11; National Grid November 21 ANOPR Comments at 19-20; OMS 
November 21 ANOPR Comments at 13-14; Southeast PIOs November 21 ANOPR 
Comments at 50. 
221 See, e.g., Constellation November 21 ANOPR Comments at 24-25; Calibrant 
November 21 ANOPR Comments at 2-4; Critical Loop November 21 ANOPR 
Comments at 2; Digital Power Network November 21 ANOPR Comments at 3; PIOs 
November 21 ANOPR Comments at 27-28; Splight November 21 ANOPR Comments at 
3-4. 
222 We direct this section only to CAISO because, unlike in other sections of this 
order, it appears that only CAISO’s Tariff is implicated because CAISO is the 
transmission provider. 
223 See supra PP 19-20 (describing existing transmission service in CAISO). 
224 See supra P 103.

Docket No. EL26-71-000 
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received.225  As the record suggests, Eligible Customers taking transmission service on 
behalf of flexible large load also may be willing and able to limit their use of the 
transmission system under certain conditions.  As recognized in the ANOPR record, load 
flexibility can avoid inefficient and costly transmission system build-out.226  In addition, 
transmission services that reflect that flexible large loads are willing and able to limit 
their withdrawals from the transmission system under certain conditions could help 
timely interconnect flexible large loads.227  Entities in the CAISO footprint acknowledge 
the importance of facilitating load flexibility.228 
 Therefore, we are concerned that CAISO’s Tariff does not include transmission 
services that reflect the use of the transmission system by Eligible Customers on behalf of 
flexible large load, on both an interim and permanent basis.  CAISO should explain 
whether the Tariff remains just and reasonable without the transmission services 
described by the Commission in the PJM Co-Location Order, with regional variation as 
appropriate, being available to Eligible Customers taking transmission service on behalf 
of flexible large loads, or propose appropriate Tariff revisions.  Specifically, CAISO 
should explain whether the Tariff remains just and reasonable without (1) an interim   
non-firm network transmission service while network upgrades are being constructed and 
(2) permanent firm and non-firm contract demand transmission services (transmission 
service up to a specified MW quantity, i.e., the contract level, on a firm or non-firm 
basis).  In the alternative, CAISO may explain whether, given that CAISO does not offer 
 
225 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199; PJM Co-Location 
Rehearing Order, 195 FERC ¶ 61,209 at P 103. 
226 See supra P 103; see also PJM Co-Location Order, 193 FERC ¶ 61,217 at      
PP 160, 177, 199 (finding that new transmission service options reflect a co-located 
load’s ability to limit withdrawals from the transmission system and potentially avoid 
costly and inefficient transmission system buildout that may not be necessary).  
227 See supra P 103; see also PJM Co-Location Order, 193 FERC ¶ 61,217 at      
PP 201 (finding that the interim, non-firm transmission service will facilitate the “timely” 
provision of transmission service and that “[t]his willingness to curtail would potentially 
allow them to obtain service more quickly”), 205 (recognizing that parties argue that co-
located loads may be able to receive transmission service faster with use of a new, limited 
transmission service product than they would if they selected NITS, to the extent that 
providing NITS would require network upgrades that the limited transmission service 
would not). 
228 See, e.g., California DWR November 10 ANOPR Comments at 5-7; see also 
CAISO November 21 ANOPR Comments at 15; PG&E November 21 ANOPR 
Comments at 16 (recognizing benefits of large and co-located load flexibility).

Docket No. EL26-71-000 
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the transmission services required by Order No. 888,229 CAISO’s existing transmission 
service framework addresses the concerns described herein, or explain what specific 
changes to its existing transmission service framework would effectively provide 
comparable transmission service options for flexible large loads as in the PJM Co-
Location Order.  Finally, we note that the Commission has found it just and reasonable 
that, in order for an Eligible Customer to take interim NITS, firm contract demand 
transmission service, and non-firm contract demand transmission service, an Eligible 
Customer must have necessary control technologies and/or protection systems, which 
may include a special protection scheme, to limit its energy withdrawals to its approved 
level.230 
E. 
Interconnection Customers Serving Electrically Proximate Large Load 
and Co-Located Load 
 In response to the ANOPR, a number of commenters agree that the ability to study 
new load and new generation together, when physically or electrically proximate, 
presents system benefits and can help address the challenges posed by large load 
additions.231  Commenters argue that studies that consider large load and generation 
together present a more complete picture of the grid and can enable the identification of 
more accurate, efficient, and cost-effective transmission solutions by minimizing system 
impacts.232  As a result, this can speed up the interconnection process for both large loads 
and generation, and shorten energization timelines,233 which commenters contend reduces 
 
229 See supra P 39.  
230 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. 
231 See e.g., DCC November 21 ANOPR Comments at 5-6; DTE November 21 
ANOPR Comments at 11; Google November 21 ANOPR Comments at 7; International 
Energy Credit Association November 21 ANOPR Comments at 10; Terraflux November 
21 ANOPR Comments at 1. 
232 AEU November 21 ANOPR Comments at 13; ClearPath November 21 
ANOPR Comments at 4; DCC November 21 ANOPR Comments at 5; DTE November 
21 ANOPR Comments at 8-11; ENGIE November 21 ANOPR Comments at 6; Entergy 
November 21 ANOPR Comments at 5; Geronimo November 21 ANOPR Comments at 
17-18; Information Technology Industry Council November 21 ANOPR Comments at 2. 
233 DCC November 21 ANOPR Comments at 5; DTE November 21 ANOPR 
Comments at 8-11; Information Technology Industry Council November 21 ANOPR 
Comments at 2; Microsoft November 21 ANOPR Comments at 8-9; Verrus December 5 
ANOPR Comments at 9.

Docket No. EL26-71-000 
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uncertainty for both parties234 and “is necessary to match the pace of AI innovation in the 
United States.”235  CEBA also highlights that cost and timeline factors drive developers 
to submit multiple requests for price and timing discovery, which inflates queue volumes, 
distorts demand and supply forecasts, and causes significant delays when projects 
withdraw late after finding costs or energization timelines uneconomic.236  Other benefits 
to a joint study identified by commenters include improving load forecasting and siting 
decisions237 and reducing the need for critical supply chain components.238   
 Commenters contend that current generator interconnection study processes may 
not adequately capture generation and load, including by failing to model known 
electrically proximate large load in base case assumptions, which may result in inaccurate 
studies and inefficient system build-out.239  For example, Eolian states that in its 
experience developing a project in PJM, the failure of the generator interconnection study 
process to reflect reasonably expected load conditions on the grid models triggered overly 
costly network upgrades and caused the cancellation of generation project that could have 
reliably served adjacent load growth.240   
 Commenters in the ANOPR proceeding argue that the current state of the 
generator interconnection queue is not meeting the expeditious time frame needed to 
match the pace of large load additions and ensure the safe and reliable interconnection of 
these loads.241  For example, Oracle states that one of the most significant and 
 
234 ClearPath November 21 ANOPR Comments at 4; CEBA November 21 
ANOPR Comments at 8. 
235 Microsoft November 21 ANOPR Comments at 8-9. 
236 CEBA November 21 ANOPR Comments at 8. 
237 ELCON November 21 ANOPR Comments at 5; Maryland Commission 
November 21 ANOPR Comments at 6-7.  
238 AEU November 21 ANOPR Comments at 13. 
239 Base Power November 21 ANOPR Comments at 7; Eolian November 21 
ANOPR Comments at 18-19; Eolian May 19 ANOPR Comments at 2; Longroad 
November 21 ANOPR Comments at 8. 
240 Eolian May 19 ANOPR Comments at 10. 
241 See, e.g., AEP December 5 ANOPR Comments at 1; DCC November 21 
ANOPR Comments at 8; esVolta November 21 ANOPR Comments at 11-12; Oracle 
May 1 ANOPR Comments at 4.

Docket No. EL26-71-000 
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widespread delays it encounters when siting data centers in the U.S. is access to sufficient 
energy.242  Similarly, Helion contends that more than half of U.S. developers now 
identify interconnection delays as the single biggest barrier to adding new generation 
capacity.243  Commenters contend that if large load interconnection proceeds more 
quickly than new generation can come online, the result could be price increases for 
consumers.244   
 A number of commenters support expedited interconnection studies for new 
generation paired with load.245  Some commenters argue that one solution to generator 
interconnection delays may be the creation of time-limited or conditional interconnection 
service for generators serving large loads, which could require less time for initial 
generator interconnection studies and improve speed to power.246  For example, several 
commenters express support for SPP’s HILLGA proposal as a model and urge the 
Commission to establish nationwide rules similar to that approach.247  Other commenters 
suggest reforms to expedite studies for new generation paired with large loads at existing 
points of interconnection that have already been studied, arguing it is unjust and 
 
242 Oracle November 21 ANOPR Comments at 1. 
243 Helion November 21 ANOPR Comments at 1 (citing Third Way, Picking Up 
the PACE: A Comprehensive Analysis of Available Pathways to Accelerating Clean 
Energy (PACE) (Nov. 2025)). 
244 AEP December 5 ANOPR Comments at 1-2; OPSI November 21 ANOPR 
Comments at 6-7, 11.  
245 See, e.g., DTE November 21 ANOPR Comments at 8; ENGIE November 21 
ANOPR Comments at 4; International Energy Credit Association November 21 ANOPR 
Comments at 8; Meta November 21 ANOPR Comments at 5-6; Ohio FEA November 21 
ANOPR Comments at 5.  
246 AEP December 5 ANOPR Comments at 12; AEU November 21 ANOPR 
Comments at 13; Google December 5 ANOPR Comments at 15; see also Duke 
November 21 ANOPR Comments at 21-22.  
247 AEP December 5 ANOPR Comments at 4; Crusoe December 5 ANOPR 
Comments at 7; Enchanted Rock November 21 ANOPR Comments at 4; Google 
November 21 ANOPR Comments at 7; GridStor November 21 ANOPR Comments at 5; 
Verrus November 21 ANOPR Comments at 9.

Docket No. EL26-71-000 
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unreasonable not to fully utilize existing infrastructure and proven reliability paths while 
new load waits for service.248   
1. 
Jurisdiction 
 The Commission’s statutory authority includes jurisdiction over the wholesale sale 
and transmission of electricity in interstate commerce, including the facilities used for 
such sale and transmission.249  The Commission also has exclusive jurisdiction to 
regulate the procedures and agreements applicable to generating facilities seeking to 
interconnect to a Commission-jurisdictional distribution facility or transmission 
facility.250  In the PJM Co-Location Order, the Commission observed that a generator’s 
interconnection to the interstate transmission system “does not fall outside of the 
Commission’s jurisdiction merely because there is [c]o-[l]ocated [l]oad behind the 
generator’s point of interconnection.”251  By the same token, the Commission retains 
jurisdiction over a generator’s interconnection even where the generator plans to serve an 
electrically proximate large load.   
 We recognize that states have exclusive authority over resource planning and the 
generation mix within their boundaries.252  Nothing about our preliminary finding here, 
however, intrudes or is intended to intrude on that exclusive authority.  Rather, we 
preliminarily find that it is necessary and appropriate to exercise our exclusive 
jurisdiction over generator interconnection to ensure the availability of generator 
interconnection processes specifically tailored to the unique operational characteristics of 
generating facilities dedicated to serving electrically proximate large loads and co-located 
loads, as defined below.  The Commission has exercised this jurisdiction previously in 
 
248 Constellation June 5 ANOPR Comments at 8-9. 
249 16 U.S.C. § 824(b)(1). 
250 Id.; Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d at 1280-82 
(affirming Order No. 2003 and observing that “interconnections appear to be 
relationships between parties with respect to electricity flowing over facilities. . . . By 
establishing standard agreements [the Commission] has exercised its jurisdiction over 
the terms of those relationships.”); see Pac. Gas & Elec. Co., 115 FERC ¶ 61,193 at P 36 
(“[I]interconnection is part and parcel of transmission of electric energy in interstate 
commerce, and thus interconnection service is part and parcel of jurisdictional 
transmission service.”).  
251 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171. 
252 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th at 238 (citing 
16 U.S.C. § 824(b)(1)).

Docket No. EL26-71-000 
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requiring generator interconnection services that allow certain generating facilities to 
interconnect more quickly through the use of provisional interconnection service and 
surplus interconnection service,253 and has approved interconnection processes that allow 
certain generating facilities to interconnect more quickly by replacing a retiring existing 
generating facility.254   
2. 
Definitions 
 For purposes of this order, it appears to be reasonable to use the term “electrically 
proximate large load” to mean a large load, as defined in this order,255 that is sufficiently 
electrically close to the interconnection customer’s requested point of interconnection, 
such that the impact on the transmission system of the combination of the generating 
facility and the load, with the exception of the transmission facilities between the two, 
will be effectively the same as if they were located at the same substation (e.g., large load 
that is located no more than two substations away from the generating facility).  We will 
consider proposed revisions to this definition that ensure it is appropriately tailored to 
CAISO’s transmission system. 
3. 
Tariff Provisions 
 We preliminarily find that CAISO’s Tariff appears to be unjust and unreasonable 
because it does not contain provisions allowing an interconnection customer to seek the 
generator interconnection service(s) that reflects the operational dynamics of serving 
either:  (1) an electrically proximate large load; or (2) a co-located load, as defined in this 
order,256 that has a high peak load (i.e., large co-located loads that are 50 MW or 
greater).257  Specifically, we preliminarily find that CAISO’s Tariff appears to be unjust 
and unreasonable because it lacks a generator interconnection study process and/or 
 
253 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, 
163 FERC ¶ 61,043, at PP 438, 467 (2018), order on reh’g & clarification, Order No. 
845-A, 166 FERC ¶ 61,137, order on reh’g & clarification, Order No. 845-B,        168 
FERC ¶ 61,092 (2019); Order No. 2023, 184 FERC ¶ 61,054 at P 1436; PJM 
Interconnection, L.L.C., 190 FERC ¶ 61,083 (2025). 
254 See, e.g., PJM Interconnection, L.L.C., 194 FERC ¶ 61,079 (2026); 
Midcontinent Indep. Sys. Operator Inc., 167 FERC ¶ 61,146 (2019).  
255 See supra P 57. 
256 See supra P 88. 
257 We note that generator interconnection service in and of itself does not convey 
transmission service.

Docket No. EL26-71-000 
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generator interconnection service to reflect an interconnection customer’s commitment in 
an interconnection agreement to limit the generating facility’s output to minimize the 
impact on the transmission system while serving an electrically proximate large load or 
large co-located load.  We are concerned that CAISO’s Tariff lacks, for example, 
generator interconnection study procedures and generator interconnection services that 
reflect (a) an interconnection customer’s commitment in an interconnection agreement to 
limit a generating facility’s output to match the hourly forecast of an electrically 
proximate large load or large co-located load; and/or (b) a generating facility with 
necessary control technologies and/or protection systems, which may include a special 
protection scheme,258 that ensure that the injection does not exceed the limit in the 
existing or new interconnection agreement.  Where a generating facility’s output is 
matched to the demand of the electrically proximate large load or large co-located load or 
if the generating facility’s output is limited to ensure no new injection, the impacts to the 
transmission system of interconnecting the generating facility to serve that electrically 
proximate large load or large co-located load may be limited,259 thereby potentially 
reducing the need for network upgrades, which can accelerate the generator 
interconnection process.260  In the absence of Tariff provisions accounting for these 
operational dynamics when an interconnection customer’s generating facility is serving 
electrically proximate large loads or large co-located loads, new shovel-ready generating 
 
258 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. 
259 In other words, because the generating facility and load are located so closely 
on the transmission system, if the generating facility’s output matches the load’s demand, 
then the transmission provider would need to study only the local impacts because the 
impact on the transmission system of the combination of the generating facility and the 
load, with the exception of the transmission facilities between the two, will be effectively 
the same as if they were located at the same substation. 
260 See, e.g., AEU November 21 ANOPR Comments at 13 (“To the extent that a 
new large load and new generation or storage resource are geographically and electrically 
proximate, studying them together would reduce network upgrades, lower costs, and 
reduce the need for critical supply chain components.”); DTE November 21 ANOPR 
Comments at 10 (integrating the study of load and its supporting generation “reduces the 
need for network upgrades, optimizes the use of existing infrastructure, and accelerates 
the timeline for bringing both load and generation online”); Eolian November 21 ANOPR 
Comments at 18 (“It is obvious from basic engineering principles that generation located 
near load requires less transmission infrastructure to serve that load than generation 
located distant from load.”); GridStor November 21 ANOPR Comments at 5 (“Siting a 
large load near or at the same point of interconnection as a new generating facility could 
reduce the network upgrades needed to interconnect only the load or only the generating 
facility.”).

Docket No. EL26-71-000 
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facilities may face unnecessary delays in reaching commercial operation under current 
generator interconnection processes and will be unable to serve the immediate demand of 
new large loads or large co-located loads.261   
 As commenters in the ANOPR proceeding have recognized, the status quo may 
result in inefficient and unnecessary development of infrastructure, which leads to 
unnecessarily higher network upgrade costs that may result in unjust and unreasonable 
rates.262  The Commission has already determined in the PJM Co-Location Order that 
without the new transmission services that reflect the operational dynamics of co-location 
arrangements, there could be unnecessary, costly, and inefficient network upgrades, 
increasing network upgrade costs.263  The same result may occur in the absence of new 
generator interconnection study procedures and generator interconnection services 
tailored to a new generating facility coming online for the express purpose of serving an 
electrically proximate large load or large co-located load.264   
 SPP recognized this problem and submitted an FPA section 205 filing to 
implement a new, interim, generator interconnection service and related generator 
 
261 See AEP December 5 ANOPR Comments at 1; Base Power November 21 
ANOPR Comments at 7; CEBA November 21 ANOPR Comments at 8; DCC November 
21 ANOPR Comments at 6 (asserting that a clear framework to study large loads paired 
with generation would resolve development bottlenecks); Eolian November 21 ANOPR 
Comments at 18-19; Eolian May 19 ANOPR Comments at 2; Google November 21 
ANOPR Comments at 7 (calling for nationwide rules enabling proximate load-generation 
interconnection to “accelerate the pace at which new generation comes online”); 
Longroad November 21 ANOPR Comments at 8. 
262 See, e.g., AEU November 21 ANOPR Comments at 13, AEP December 5 
ANOPR Comments at 1-2; Longroad November 21 ANOPR Comments at 8; OPSI 
November 21 ANOPR Comments at 11. 
263 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 177 (“[F]or Eligible 
Customers taking service on behalf of Co-Located Loads that do not reserve 
transmission . . . requiring such Eligible Customers to take NITS on behalf of these     
Co-Located Loads may in some circumstances result in costly and inefficient 
transmission system buildout that may not be necessary if such Eligible Customers are 
willing and able to take a transmission service that requires fewer Network Upgrades to 
provide, and therefore may result in lower Network Upgrade costs, than would NITS.”). 
264 See AEP December 5 ANOPR Comments at 1-2 (stating that current processes 
produce insufficient/inefficient infrastructure and “potentially unsustainable price 
increases”); Eolian May 19 ANOPR Comments at 2, 10 (contending that a lack of 
coordinated study leads to unjust and unreasonable outcomes).

Docket No. EL26-71-000 
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interconnection process, HILLGA, to facilitate the prompt interconnection of generating 
facilities that are specifically identified for and limited to serving a HILL, which the 
Commission accepted.265  The Commission found that HILLGA “reasonably provides a 
flexible, expedited, and separate serial interconnection process that will facilitate the 
prompt interconnection of generating facilities that are limited to serving a HILL in the 
same local area.”266  We do not expect or propose that CAISO adopt an identical process 
to SPP’s HILLGA process, nor do we preliminarily find that the absence of Tariff 
provisions specifically mirroring SPP’s Tariff renders CAISO’s Tariff unjust and 
unreasonable.  Nevertheless, we remain concerned that the Tariff may be unjust and 
unreasonable without any uniquely tailored interconnection study process and/or 
generator interconnection service to recognize the reduced transmission system impacts 
that may result from the interconnection of a generating facility where the 
interconnection customer has committed, in an interconnection agreement, to limit the 
generating facility’s output to match the hourly forecast of an electrically proximate large 
load or large co-located load.267  To the extent that the interconnection customer’s 
generating facility is serving an electrically proximate large load, we believe that the 
generator interconnection service should be of an interim nature until the interconnection 
customer obtains Energy Resource Interconnection Service (ERIS) or Network Resource 
Interconnection Service (NRIS).  To the extent that the interconnection customer’s 
generating facility is serving a large co-located load, it may be reasonable for the 
generator interconnection service to be permanent because there will be no injections 
onto the transmission system and therefore it does not present operational or planning 
risks for reliability.   
 Another potentially reasonable approach to address our concerns could be to 
develop a generator interconnection study process that would allow the use of existing 
ERIS or NRIS of an existing generator to connect a new generating facility and a new 
large load behind the same point of interconnection of the existing generator with 
necessary control technologies and/or protection systems, which may include a special 
 
265 SPP HILL Order, 194 FERC ¶ 61,031. 
266 Id. P 64. 
267 While, as discussed above, we view such a process that permits generation to 
serve electrically proximate loads no more than two substations away from the generators 
to be reasonable, we understand the unique features of CAISO’s transmission system 
may warrant consideration of a more limited definition of electrically proximate.  See 
Duke November 21 ANOPR Comments at 21-22; DTE November 21 ANOPR 
Comments at 8-11 (asserting that studying large loads with electrically proximate 
generation streamlines interconnection and reduces upgrades); AEU November 21 
ANOPR Comments at 13-15.

Docket No. EL26-71-000 
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protection scheme, that ensure that the net injection does not exceed the amount in the 
existing generator interconnection agreement.268  Such an approach could expedite the 
interconnection study process for a generator planning to serve an electrically proximate 
(in this case at the same point of interconnection) large load.269  An additional potentially 
reasonable approach could be a new load-limited generator interconnection service that 
allows a new generating facility and new large co-located load seeking to interconnect 
behind the same new point of interconnection, with necessary control technologies and/or 
protection systems, which may include a special protection scheme, to ensure that there is 
no injection to the transmission system.270  It may be reasonable for such a load-limited 
generator interconnection service to be or not to be of an interim nature.  We invite 
CAISO and/or Participating Transmission Owners, in responding to this order or in an 
FPA section 205 filing, to submit original proposals designed to address the concerns 
expressed herein and tailored to their unique circumstances.   
 We are concerned that the absence of generator interconnection study procedures 
and generator interconnection services facilitating the interconnection of a new 
generating facility that is being brought onto the transmission system in order to serve an 
electrically proximate large load or large co-located load will result in CAISO’s current 
generator interconnection process failing to keep pace with the new large loads seeking to 
be integrated onto CAISO’s transmission system.271  We preliminarily find that this 
outcome may be unjust and unreasonable because reliance on CAISO’s current generator 
interconnection processes for generating facilities serving electrically proximate large 
loads or large co-located loads could result in unnecessary interconnection delays, 
 
268 See Constellation June 5 ANOPR Comments at 1-2, 10-13. 
269 See id. at 5 (explaining that when new generation load pairings “are sited at an 
existing generator’s Point of Interconnection and fall within the same study parameters 
reflected by that existing generator’s interconnection, they benefit from studies and 
upgrades already completed for that existing generator and can come on more rapidly 
without jeopardizing reliability”). 
270 See MISO November 21 ANOPR Comments at 13; see also MISO TOs April 3 
ANOPR Comments at 13-14.   
271 See Helion November 21 ANOPR Comments at 1 (noting interconnection 
delays are the biggest barrier to adding new generation); Oracle November 21 ANOPR 
Comments at 1 (noting significant delays in access to sufficient energy for data centers); 
OPSI November 21 ANOPR Comments at 11 (explaining that expedited study 
encourages loads to bring their own generation); Enchanted Rock November 21 ANOPR 
Comments at 4; Microsoft November 21 ANOPR Comments at 8-9.

Docket No. EL26-71-000 
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unnecessary network upgrades, and an otherwise inefficient expansion of the 
transmission system, imposing unnecessary delays and costs on transmission customers. 
 CAISO should explain whether the Tariff remains just and reasonable without, for 
example, provisions that establish:  (1) a new generator interconnection study process and 
new interim generator interconnection service that reflect an interconnection customer’s 
commitment, in a generator interconnection agreement, to limit a generating facility’s 
output to match the hourly forecast of an electrically proximate large load or large co-
located load; or (2) a generator interconnection study process that allows the use of the 
existing ERIS or NRIS of an existing generator to connect a new generating facility and a 
new large load behind the same point of interconnection of the existing generator with 
necessary control technologies and/or protection systems, which may include a special 
protection scheme, that ensures that the net injection does not exceed the amount in the 
existing generator interconnection agreement; or (3) a new generator interconnection 
service that allows a new generating facility and new large co-located load seeking to 
interconnect behind the same new point of interconnection with necessary control 
technologies and/or protection systems, which may include a special protection scheme, 
to ensure that there is no injection to the transmission system.  We note that, with respect 
to numbers (2) or (3), these approaches could be either interim or permanent.  These 
approaches may not be mutually exclusive. 
 Given that generator interconnection service in and of itself does not convey 
transmission service, we encourage CAISO to consider, in responding to these concerns, 
what type of transmission service an Eligible Customer will need to take on behalf of the 
electrically proximate large load or large co-located load.272  We note that, in the PJM 
Co-Location Order, the Commission found that the Eligible Customer must take 
transmission service on behalf of co-located load that will not withdraw energy from the 
transmission system, even if it is 0 MW.273 
F. 
Informational Report 
 The rapid addition and proliferation of large loads without commensurate 
additions of supply or demand-side resources presents resource adequacy concerns.  As 
discussed above and highlighted in the ANOPR, the growth of demand, and the speed of 
such growth, is driven in large part by the interconnection of large loads.  While not 
expressly contemplated in the ANOPR, commenters highlight the strain rapid demand 
growth is putting on resource adequacy in many regions.274  Indeed, the relative speed 
 
272 See SPP HILL Order, 194 FERC ¶ 61,031 at P 34. 
273 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 206. 
274 See, e.g., Entergy November 21 ANOPR Comments at 29-30; Eolian 
November 21 ANOPR Comments at 16-17; Industrial Customers November 21 ANOPR

Docket No. EL26-71-000 
- 74 - 
and concentration at which large loads are seeking to interconnect appears to be 
outpacing the addition of new generation, which in turn heightens reliability risks and 
drives up costs to ratepayers.275  We are concerned that CAISO and load serving entities 
are unable to plan adequate generation to serve all load at the pace such load seeks to 
connect.   
 We recognize that RTOs/ISOs are engaging in efforts to more rapidly interconnect 
generation that is needed to serve this unprecedented growth in load.  In particular, 
CAISO has made revisions to its Tariff through its Interconnection Process Enhancement 
initiative that have enhanced the coordination of resource procurement and 
interconnection, improved resource planning and transmission planning, and streamlined 
generator interconnection and Deliverability allocation procedures.276  While we are 
encouraged by the implementation of such processes to ensure resource adequacy and 
faster interconnection, and recognize that CAISO continues to engage in Interconnection 
Process Enhancements,277 we remain concerned that these efforts may fall short in light 
of generator retirements and tightening supply conditions. 
 Accordingly, we direct CAISO to submit in Docket No. EL26-71-000, within 30 
days of the date of issuance of this order, a detailed informational report on any proposals 
under consideration in its stakeholder process to address the issue of resource adequacy 
to serve new large loads.  Given that the CPUC has primary responsibility for resource 
adequacy within the CAISO footprint, CAISO should provide information on any 
ongoing initiatives and coordination with the CPUC and other relevant state agencies 
related to ensuring generation adequacy.  We also strongly encourage new proposals to 
 
Comments at 24-26; R Street November 21 ANOPR Comments at 1; South Dakota 
Commission November 13 ANOPR Comments at 5; Talen December 5 ANOPR Reply 
Comments at 7.  
275 See, e.g., Eolian November 21 ANOPR Comments at 16-17; David Gardiner & 
Associates November 21 ANOPR Comments at 1-2; Joint Consumer Advocates 
December 5 ANOPR Comments at 2; PSEG November 21 ANOPR Comments at 8; 
Southern California Edison December 5 ANOPR Comments at 3. 
276 See Cal. Indep. Sys. Operator Corp., 191 FERC ¶ 61,218 (2025); Cal. Indep. 
Sys. Operator Corp., 189 FERC ¶ 61,195 (2024); Cal. Indep. Sys. Operator Corp.,      
184 FERC ¶ 61,069 (2023). 
277 CAISO has developed a final proposal for its Interconnection Process 
Enhancements 5.0 initiative, which was approved by the Board on April 30, 2026.  See 
CAISO, Initiative: Interconnection Process Enhancements 5.0, 
https://stakeholdercenter.caiso.com/StakeholderInitiatives/Interconnection-process-
enhancements-5-0.

Docket No. EL26-71-000 
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the extent necessary to address these concerns.  The informational report must include a 
detailed schedule of key milestones, such as stakeholder or CAISO Board votes, that 
includes the estimated date on which CAISO expects to file any such proposals with the 
Commission.  Additionally, as part of this informational report, we direct CAISO to 
identify any ongoing stakeholder processes that aim to increase the pace of adding 
generating capacity in the CAISO region.  The informational report must include a 
detailed schedule of such initiatives, including timing of the stakeholder process and 
dates of any anticipated filings with the Commission.   
IV. 
Briefing Questions 
 We note that large loads, including data centers, are actively working with 
transmission owners and other relevant entities to interconnect to, and to take 
interconnection and/or transmission service from, the transmission system and may be at 
varying stages of that process.  We appreciate that different large loads are currently at 
different stages of that process.  We also understand that large loads and Eligible 
Customers taking transmission service on behalf of large loads are negotiating, entering 
into, and/or have executed various agreements related to interconnecting to the 
transmission system and/or the provision of transmission service.  We direct further 
briefing regarding how CAISO and the Participating Transmission Owners, in responding 
to the order to show cause, should protect existing commercial arrangements including:  
(1) what would be a reasonable implementation period to ensure minimal disruption to 
such existing commercial arrangements, and (2) how to allow a reasonable amount of 
time to finalize ongoing agreements that are nearing completion as of the date such tariff 
provisions are filed with the Commission.    
 Today’s order proposes, as part of a potential replacement rate, to establish new 
transmission services that recognize flexible large loads’ ability and willingness to limit 
their use of the transmission system under certain conditions.  As we assess this proposal, 
we also consider how these new transmission services might affect other parts of 
CAISO’s Tariff and/or processes.  Specifically, what, if any, potential impacts on 
regional and local transmission planning would arise from the introduction of the new 
transmission services discussed herein?  For example, when planning for load growth, 
how would transmission providers and planners account for flexible large loads’ potential 
preference to take the new transmission services, including potential uncertainties around 
the type, location, and quantity of such expected loads?     
 Today’s order preliminarily finds that CAISO’s Tariff appears to be unjust and 
unreasonable without the inclusion of cost shifting protections.  We find that there may 
be a variety of possible approaches to protect customers from significant cost shifts 
associated with network upgrades triggered by large loads.  To that end, we direct 
respondents to include information regarding potential structures for agreements between 
the transmission owner/provider and an Eligible Customer to prevent unjust and

Docket No. EL26-71-000 
- 76 - 
unreasonable cost shifts among transmission customers related to network upgrade costs 
required for large loads.  Further, please include information on what an appropriate 
minimum level of cost recovery and financial security from an Eligible Customer would 
be under any such agreements. 
 Today’s order preliminarily finds that CAISO’s Tariff appears to be unjust and 
unreasonable because it lacks clear and consistent provisions requiring the evaluation of 
alternative transmission technologies.  The order directs CAISO to explain whether the 
Tariff remains just and reasonable without provisions that (1) require the evaluation of 
alternative transmission technologies in studies for the provision of transmission service, 
using models that are capable of evaluating the transmission system to accurately account 
for advanced transmission technologies, in all instances, without the need for a request 
from the Eligible Customer seeking transmission service on behalf of large load; and (2) 
if traditional network upgrades are selected instead of alternative transmission 
technologies, inclusion in the study report to the Eligible Customer seeking transmission 
service on behalf of large load of a sufficiently clear demonstration of why alternative 
transmission technologies are not feasible (i.e., would not resolve reliability violations 
identified or meet the relevant planning criteria) or would not result in lower costs or a 
faster timeline for accommodating the transmission service request.  As noted above, to 
the extent stakeholders believe that specific characteristics of providing transmission 
service to Eligible Customers on behalf of large loads warrant requirements beyond those 
contemplated here, we seek further briefing.  
 Today’s order preliminarily finds that CAISO’s Tariff appears to be unjust and 
unreasonable because it does not contain provisions allowing an interconnection 
customer serving electrically proximate large load or large co-located load to seek 
generator interconnection service(s) that reflects the operational dynamics of serving such 
loads.  Any filings or tariff changes submitted in response to this order should address the 
following questions:  
a. To what extent would CAISO allow an interconnection customer’s 
generating facility serving electrically proximate large load or large co-
located load to participate in CAISO’s energy and ancillary services 
market, and if CAISO were to allow them to participate, what restrictions 
or mitigation would CAISO apply? 
b. To the extent that CAISO plans for the electrically proximate large load or 
large co-located load associated with an interconnection customer’s 
generating facility for resource adequacy purposes, would CAISO account 
for the generating facilities serving electrically proximate large load or 
large co-located load in the resource adequacy construct?  If applicable, 
would CAISO allow the generating facilities serving electrically proximate

Docket No. EL26-71-000 
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large load or large co-located load to participate in CAISO’s capacity 
market?  If so, would CAISO accredit these generating facilities using the 
same method as other CAISO generating facilities? 
The Commission orders: 
 
(A) 
Pursuant to the authority contained in and subject to the jurisdiction 
conferred upon the Federal Energy Regulatory Commission by section 402(a) of the 
Department of Energy Organization Act and by the FPA, particularly section 206 thereof, 
and pursuant to the Commission’s Rules of Practice and Procedure and the regulations 
under the FPA (18 C.F.R. Chapter I), the Commission hereby institutes a proceeding in 
Docket No. EL26-71-000 as discussed in the body of this order. 
(B) 
CAISO and the Participating Transmission Owners are hereby directed, 
within 60 days of the date of the order, either:  (1) to show cause as to why the Tariff 
remains just and reasonable and not unduly discriminatory or preferential; or (2) to 
explain what changes to the Tariff it believes would remedy the identified concerns if the 
Commission were to determine that the Tariff has in fact become unjust and unreasonable 
or unduly discriminatory or preferential and, therefore, proceeds to establish a 
replacement Tariff. 
(C) 
CAISO is directed to submit an informational report within 30 days of the 
date of issuance of this order, as discussed in the body of this order. 
(D) 
Any interested person desiring to be heard in Docket No. EL26-71-000 
must file a notice of intervention or motion to intervene, as appropriate, with the Federal 
Energy Regulatory Commission, 888 First Street, NE, Washington, DC  20426, in 
accordance with Rule 214 of the Commission’s Rules of Practice and Procedure,           
18 C.F.R. § 385.214 (2025), within 21 days of the date of issuance of this order.  The 
Commission encourages electronic submission of interventions in lieu of paper using the 
“eFiling” link at http://www.ferc.gov.  Persons unable to file electronically may file by 
U.S. mail addressed to Federal Energy Regulatory Commission, Secretary of the 
Commission, 888 First Street, N.E., Washington, DC  20426, or by hand (including 
courier) delivery to Federal Energy Regulatory Commission, 12225 Wilkins Avenue, 
Rockville, MD  20852. 
(E) 
Interested entities may respond within 30 days of CAISO’s and the 
Participating Transmission Owners’ filing, addressing either or both of:  (1) whether the 
Tariff remains just and reasonable and not unduly discriminatory or preferential; and (2) 
if not, what changes to the Tariff should be implemented as a replacement rate. 
(F) 
The Secretary shall promptly publish in the Federal Register a notice of the 
Commission’s initiation of the proceeding under section 206 of the FPA in Docket No.

Docket No. EL26-71-000 
- 78 - 
EL26-71-000. 
 
 
(G) 
The refund effective date in Docket No. EL26-71-000 pursuant to section 
206 of the FPA shall be the date of publication in the Federal Register of the notice 
discussed in Ordering Paragraph (F) above. 
By the Commission.  Chairman Swett is concurring with a separate statement attached. 
 
 
 
  Commissioner Rosner is concurring with a separate statement 
  attached. 
  Commissioner See is concurring with a separate statement attached. 
  Commissioner Chang is concurring with a separate statement 
  attached. 
  Commissioner LaCerte is concurring with a separate statement 
  attached. 
 
( S E A L ) 
 
 
 
 
Carlos D. Clay, 
Deputy Secretary.

Docket No. EL26-71-000 
- 79 - 
Appendix - Commenters in Docket No. RM26-4-000 
 
Advanced Energy Management Alliance (AEMA) 
Advanced Energy United (AEU) 
Advancing Modern Powerlines Coalition (together with Working for Advanced 
Transmission Technologies Coalition, WATT and Advancing Modern Powerlines) 
Advocates for Consumer Regulated Electricity 
AES Corporation 
AI Supply Chain Alliance 
Alexandre Figueras, on behalf of Monza Tech 
Alliance for Tribal Clean Energy 
Alliant Energy Corporate Services, Inc.  
Amazon Energy LLC (Amazon) 
America’s Power  
American Chemistry Council  
American Clean Power Association  
American Conservation Coalition 
American Council on Renewable Energy (ACORE) 
American Electric Power Service Corporation278 
American Public Gas Association 
American Public Power Association (APPA) 
American Terawatt, Inc. (American Terawatt) 
American Transmission Company LLC (ATC)279 
Americans for a Clean Energy Grid  
Antora Energy, Inc. 
Arevia Power 
Arizona Public Service Company 
Arkansas Public Service Commission 
Attorney General of the State of Oklahoma 
 
278 American Electric Power Service Corporation submitted comments on behalf 
of its affiliates Appalachian Power Company, Indiana Michigan Power Company, 
Kentucky Power Company, Kingsport Power Company, Ohio Power Company, 
Wheeling Power Company, Public Service Company of Oklahoma, Southwestern 
Electric Power Company, AEP Appalachian Transmission Company, Inc., AEP Indiana 
Michigan Transmission Company, Inc., AEP Kentucky Transmission Company, Inc., 
AEP Ohio Transmission Company, Inc., AEP West Virginia Transmission Company, 
Inc., AEP Oklahoma Transmission Company, Inc., and AEP Southwestern Transmission 
Company, Inc. 
279 ATC submitted comments on behalf of itself and its corporate manager ATC 
Management Inc.

Docket No. EL26-71-000 
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Base Power Company, Inc. (Base Power) 
Bloom Energy Corporation 
Buckeye Power, Inc. (Buckeye) 
Calibrant Energy Holdings, LLC (Calibrant) 
California Department of Water Resources State Water Project (California DWR) 
California Independent System Operator Corporation (CAISO) 
California Public Utilities Commission (CPUC) 
Center for Biological Diversity 
Chevron U.S.A., Inc. 
Clean Energy Buyers Association (CEBA) 
ClearPath, Inc. (ClearPath) 
Confederated Tribes and Bands of the Yakama Nation 
Constellation Energy Generation, LLC (Constellation) 
Consumer Energy Alliance 
Consumers Energy Company 
Critical Loop, Inc. (Critical Loop) 
Crusoe Energy Systems, Inc. (Crusoe) 
CTC Global Corporation 
Data Center Coalition (DCC) 
David Gardiner & Associates  
Delaware Division of the Public Advocate (together with Pennsylvania Office of  
Consumer Advocate, Joint Consumer Advocates)280 
Digital Energy Council  
Digital Power Network 
Distributed Capacity Parties281 
DTE Electric Company (DTE) 
Dr. Elisa Nelson 
Duke Energy Corporation (Duke) 
EDF Power Solutions, Inc. (EDF Power) 
Edison Electric Institute (EEI) 
Electricity Consumers Resource Council (ELCON) 
Electricity Customers Alliance (ECA) 
Electric Power Supply Association (EPSA) 
Emerald AI (Emerald) 
Enchanted Rock, LLC 
Energy New England, LLC 
 
280 The Illinois Attorney General joined the Joint Consumer Advocates in filing 
reply comments. 
281 Distributed Capacity Parties include:  Clovereleaf Infrastructure; Spark 
Community Investment d/b/a Sparkfund; and Voltus, Inc.

Docket No. EL26-71-000 
- 81 - 
Energy Trading Institute 
ENGIE North America, Inc. (ENGIE) 
Entergy Services, LLC (Entergy)282 
Environmental Law & Policy Center 
Eolian L.P. (Eolian) 
Equinix, Inc. 
esVolta, LP 
ETX Upstream, LLC 
Eversource Energy283 
Exelon Corporation (Exelon)284 
Fervo Energy Company (Fervo) 
FirstEnergy Service Company285 
Fluence 
Front Door Technologies LLC 
FuelCell Energy, Inc. 
Georgia Public Service Commission  
Geronimo Power, LLC (Geronimo) 
Google LLC (Google) 
Governors Josh Shapiro and Glenn Youngkin 
GridCARE 
GridStor LLC (GridStor) 
Harvard Electricity Law Initiative 
 
282 Entergy submitted comments on behalf of the Entergy Operating Companies, 
which include Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, 
LLC, Entergy New Orleans, LLC, and Entergy Texas, Inc. 
283 Eversource Energy submitted comments on behalf of its affiliates The 
Connecticut Light and Power Company, NSTAR Electric Company, and Public Service 
Company of New Hampshire, and through its agent Eversource Energy Service 
Company. 
284 Exelon submitted comments on behalf of itself and its affiliates Atlantic City 
Electric Company, Baltimore Gas and Electric Company, Commonwealth Edison 
Company, Commonwealth Edison Company of Indiana, Inc., Delmarva Power and Light 
Company, PECO Energy Company, and Potomac Electric Power Company. 
285 FirstEnergy Service Company submitted comments on behalf of itself and its 
affiliates American Transmission Systems, Inc., Jersey Central Power & Light Company, 
Mid-Atlantic Interstate Transmission LLC, Keystone Appalachian Transmission 
Company, The Potomac Edison Company, Monongahela Power Company, and Trans-
Allegheny Interstate Line Company.

Docket No. EL26-71-000 
- 82 - 
Helion Energy (Helion) 
Herbert Schrayschuen 
Heron Power Electronics Company 
 
Indiana Energy Association 
Indicated PJM Transmission Owners286 
Industrial Customer Organizations (Industrial Customers)287 
Information Technology Industry Council 
Infrastructure Masons, Inc. (Infrastructure Masons) 
Institute for Progress 
International Energy Credit Association 
Invenergy288 
 
286 Indicated PJM Transmission Owners include:  AEP on behalf of Appalachian 
Power Company, Indiana Michigan Power Company, Kentucky Power Company, 
Kingsport Power Company, Ohio Power Company, Wheeling Power Company, AEP 
Appalachian Transmission Company, Inc., AEP Indiana Michigan Transmission 
Company, Inc., AEP Kentucky Transmission Company, Inc., AEP Ohio Transmission 
Company, Inc., and AEP West Virginia Transmission Company, Inc.; AMP 
Transmission, LLC; City of Cleveland, Department of Public Utilities, Division of 
Cleveland Public Power; City of Hamilton, OH; Dominion Energy Services, Inc. on 
behalf of Virginia Electric and Power Company d/b/a Dominion Energy Virginia; Duke 
Energy Corporation on behalf of its affiliates Duke Energy Ohio, Inc., Duke Energy 
Kentucky, Inc., and Duke Energy Business Services LLC; Duquesne Light Company; 
East Kentucky Power Cooperative; Exelon Corporation, on behalf of Atlantic City 
Electric Company, Baltimore Gas and Electric Company, Commonwealth Edison 
Company, Commonwealth Edison Company of Indiana, Inc., Delmarva Power & Light 
Company, PECO Energy Company, and Potomac Electric Power Company; FirstEnergy 
Service Company, as agent for its affiliates American Transmission Systems, 
Incorporated, Jersey Central Power & Light Company, Mid-Atlantic Interstate 
Transmission LLC, Keystone Appalachian Transmission Company, The Potomac Edison 
Company, Monongahela Power Company and Trans-Allegheny Interstate Line 
Company; Old Dominion Electric Cooperative; PPL Electric Utilities Corporation; 
Rockland Electric Company; Southern Maryland Electric Cooperative, Inc.; UGI Utilities 
Inc; and Wabash Valley Power Association, Inc. 
287 Industrial Customers include:  the Industrial Energy Consumers of America, 
the American Forest & Paper Association, the PJM Industrial Customer Coalition, and 
the Coalition of MISO Transmission Customers 
288 Invenergy includes:  Invenergy Wind Development North America LLC, 
Invenergy Solar Development North America LLC, and Invenergy Thermal Development 
Holdings LLC.

Docket No. EL26-71-000 
- 83 - 
Iron Mountain Data Centers, LLC 
ISO New England, Inc. 
ITC Holdings Corp. (ITC) 
Jason Miller, on behalf of VEIR Inc. 
Kansas Corporation Commission (Kansas Commission) 
L. Lynne Kiesling  
L.M. Marlowe 
Land Trust Alliance 
Large Public Power Council 
Lauren Hopkins 
LEAN Energy US 
Load Flexibility Parties289 
Long Island Power Authority 
Longroad Energy Holdings, LLC (Longroad) 
Louisiana Public Service Commission 
LS Power Development, LLC (LS Power) 
Maine Office of the Public Advocate 
Maryland Energy Administration  
Maryland Public Service Commission  
Maven Solutions 
MCC Economics and Finance 
Meta Platforms, Inc. 
Michigan Attorney General Dana Nessel 
Microsoft, Inc. (Microsoft) 
Midcontinent Independent System Operator, Inc. 
MISO Transmission Owners (MISO TOs)290  
 
289 Load Flexibility Parties include:  Enerwise Global Technologies, LLC d/b/a 
CPower, Enel North America, Inc., and Voltus, Inc. 
290 MISO TOs include:  Ameren Services Company, as agent for Union Electric 
Company d/b/a Ameren Missouri, Ameren Illinois Company d/b/a Ameren Illinois and 
Ameren Transmission Company of Illinois; American Transmission Company LLC; Big 
Rivers Electric Corporation; Central Minnesota Municipal Power Agency; Citizens 
Electric Corporation; City Water, Light & Power (Springfield, IL); Cleco Power LLC; 
Cooperative Energy; Dairyland Power Cooperative; Duke Energy Business Services, 
LLC for Duke Energy Indiana, LLC; East Texas Electric Cooperative; Entergy Arkansas, 
LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy New Orleans, LLC; 
Entergy Texas, Inc.; Great River Energy; GridLiance Heartland LLC; Hoosier Energy 
Rural Electric Cooperative, Inc.; Indiana Municipal Power Agency; Indianapolis Power 
& Light Company d/b/a AES Indiana; Lafayette Utilities System; MidAmerican Energy 
Company; Minnesota Power (and its subsidiary Superior Water, L&P); Montana-Dakota 
Utilities Co.; Northern Indiana Public Service Company LLC; Northern States Power

Docket No. EL26-71-000 
- 84 - 
Mississippi Public Service Commission 
Missouri Public Service Commission 
Monitoring Analytics, LLC, acting in its capacity as the Independent Market Monitor for 
PJM 
Nathan Peterson 
National Association of Regulatory Utility Commissioners 
National Association of State Utility Consumer Advocates 
National Conference of State Legislatures (NCSL) 
National Congress of American Indians 
National Grid PLC (National Grid)291 
National Rural Electric Cooperative Association (NRECA) 
Nebraska Power Review Board (Nebraska Board) 
New England States Committee on Electricity 
New England Conference of Public Utility Commissioners 
New England Consumer-Owned Systems292  
New England Public Systems293 
 
Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin 
corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric 
Company; Otter Tail Power Company; Prairie Power, Inc.; Republic Transmission, LLC; 
Southern Illinois Power Cooperative; Southern Indiana Gas & Electric Company (d/b/a 
CenterPoint Energy Indiana South); Southern Minnesota Municipal Power Agency; 
Wabash Valley Power Association, Inc.; and Wolverine Power Supply Cooperative, Inc 
291 National Grid submitted comments behalf of its affiliates Niagara Mohawk 
Power Corporation; New England Power Company; New England Electric Transmission 
Corporation; New England Hydro-Transmission Corporation; New England Hydro-
Transmission Electric Company, Inc.; and Massachusetts Electric Company. 
292 New England Consumer-Owned Systems include:  Belmont Municipal Light 
Department, Block Island Utility District, Braintree Electric Light Department, Concord 
Municipal Light Plant, Danvers Electric Division, Georgetown Municipal Light 
Department, Groveland Electric Light Department, Hingham Municipal Lighting Plant, 
Hudson Light & Power Department, Littleton Electric Light & Water Department, 
Merrimac Municipal Light Department, Middleborough Gas & Electric Department, 
Middleton Electric Light Department, North Attleborough Electric Department, Norwood 
Municipal Light Department, Clear River Electric & Water District, Rowley Municipal 
Lighting Plant, Stowe Electric Department, Taunton Municipal Lighting Plant, Town of 
Wallingford, Connecticut Department of Public Utilities Electric Division, Westfield Gas 
and Electric Light Department, and Mid-Coast Regional Redevelopment Authority. 
293 New England Public Systems include:  Connecticut Municipal Electric 
Cooperative, Massachusetts Municipal Wholesale Electric Company, and Vermont

Docket No. EL26-71-000 
- 85 - 
New Mexico Public Regulation Commission (New Mexico Commission) 
New York Independent System Operator, Inc. 
New York State Department of State Utility Intervention Unit (NY UIU) 
New York Public Service Commission 
New York State Reliability Council 
New York Transmission Owners294 
North American Electric Reliability Corporation  
North Carolina Utilities Commission 
North Carolina Utilities Commission Public Staff 
North Dakota Public Service Commission 
Northeastern Rural Electric Membership Corporation 
NRG Energy, Inc. 
Office of the Illinois Attorney General (Illinois AG) 
Office of the Ohio Consumers’ Counsel (OCC) 
Oklahoma Corporation Commission 
Oklo Inc. (Oklo) 
Old Dominion Electric Cooperative (ODEC) 
Oncor Electric Delivery Company LLC 
ON Energy Storage, Inc. 
OpenAI Inc. 
Oracle America, Inc. (Oracle) 
Organization of MISO States, Inc. (OMS) 
Organization of PJM States, Inc. (OPSI) 
Paces AI Inc. 
Pacific Gas & Electric Company (PG&E) 
Paige Lambermont, on behalf of Competitive Enterprise Institute 
Paul Statchen 
Pennsylvania Office of Consumer Advocate 
Pennsylvania Public Utility Commission 
Pew Charitable Trusts Energy Modernization Project 
PJM Interconnection, LLC  
Power for Tomorrow 
PPL Corporation295 
 
Public Power Supply Authority. 
294 New York Transmission Owners include:  Central Hudson Gas & Electric 
Corporation, Consolidated Edison Company of New York, Inc., New York Power 
Authority, New York State Electric & Gas Corporation, Niagara Mohawk Power Corp. 
(d/b/a National Grid), Orange and Rockland Utilities, Inc., Long Island Power Authority, 
and Rochester Gas and Electric Corporation. 
295 PPL Corporation submitted comments on behalf of the PPL Companies, which

Docket No. EL26-71-000 
- 86 - 
Prime Mover Institute 
PSEG Companies296 
Public Citizen, Inc. 
Public Interest Organizations (PIOs)297 
Public Utilities Commission of Ohio’s Office of the Federal Energy Advocate (Ohio  
FEA) 
R Street Institute (R Street) 
Rewiring America 
MCC Economics Ltd. 
RWE Clean Energy, LLC 
Sarah McKinley 
Shell Energy North America (US), L.P. 
Sierra Club 
SMA Solar Technology AG 
Solar Energy Industries Association 
South Carolina Office of Regulatory Staff 
South Dakota Public Utilities Commission (South Dakota Commission) 
Southeast Public Interest Organizations (Southeast PIOs)298 
Southern California Edison Company (Southern California Edison) 
Southern Companies299 
Southern Maryland Electric Cooperative, Inc. 
Southwest Power Pool, Inc.  
 
include PPL Electric Utilities Corporation, Louisville Gas & Electric Company and 
Kentucky Utilities, and The Narragansett Electric Company d/b/a Rhode Island Energy. 
296 PSEG Companies include:  Public Service and Gas Company, PSEG Power 
LLC, and PSEG Energy Resources & Trade LLC, which are each wholly-owned, direct 
or indirect subsidiaries of Public Service Enterprise Group Incorporated. 
297 PIOs include:  Clean Air Task Force, Inc., Coalition for Affordable Utility 
Services and Energy Efficiency in Pennsylvania, Earthjustice, Environmental Defense 
Fund, Montana Environmental Information Center, Natural Resources Defense Council, 
Sustainable FERC Project, Sierra Club, and Southern Environmental Law Center. 
298 Southeast PIOs include:  Southern Environmental Law Center, Appalachian 
Voices, North Carolina Sustainable Energy Association, South Carolina Coastal 
Conservation League, and Southern Alliance for Clean Energy. 
299 Southern Companies include:  Georgia Power Company, Alabama Power 
Company, and Mississippi Power Company.

Docket No. EL26-71-000 
- 87 - 
Southwest Power Pool Transmission Owner Group300 
Splight Inc. (Splight) 
State Entities301 
Steel Manufacturers Association 
Switch, Ltd. (Switch) 
Talen Energy Corporation (Talen) 
Terraflux LLC (Terraflux) 
Tesla, Inc. 
Texas Blockchain Council 
Thermal Battery Alliance 
Tract Holding Company I, LLC (Tract) 
Transmission Access Policy Study Group (TAPS) 
Tri-State Generation and Transmission Association, Inc. (Tri-State) 
Travis Fisher, on behalf of Cato Institute 
U.S. Chamber of Commerce (Chamber of Commerce) 
U.S. Energy Storage Coalition 
U.S. House of Representatives Committee on Energy and Commerce Ranking  
Members302 
U.S. Representatives303 
U.S. Senate Committee on Energy and Natural Resources 
U.S. Senators304 
 
300 Southwest Power Pool Transmission Owner Group includes:  American 
Electric Power Service Corporation, Evergy Kansas Central, Inc., Evergy Metro, Inc., 
Evergy Missouri West, Inc., Oklahoma Gas and Electric Company, and Xcel Energy 
Services Inc., on behalf of Southwestern Public Service Company. 
301 State Entities include:  Massachusetts Attorney General’s Office, the Arizona 
Attorney General’s Office, the Colorado Attorney General’s Office, the Connecticut 
Office of Consumer Counsel, the Maryland Office of People’s Counsel, the Minnesota 
Attorney General’s Office, the Office of the Nevada Attorney General, Bureau of 
Consumer Protection, the New Hampshire Office of the Consumer Advocate, the Oregon 
Attorney General, and the Rhode Island Division of Public Utilities and Carriers. 
302 Submitted by Frank Pallone, Jr. (Ranking Member) and Kathy Castor (Ranking 
Member, Subcommittee on Energy). 
303 The U.S. Representatives that submitted comments include:  Suhas 
Subramanyam, John W. Mannion, Mike Quigley, and Donald S. Beyer Jr. 
304 The U.S. Senators that submitted comments include:  Edward J. Markey, Chris 
Van Hollen, Elizabeth Warren, Peter Welch, Raphael Warnock, Richard Blumenthal, and

Docket No. EL26-71-000 
- 88 - 
U.S. Senator Jon Ossoff 
Union of Concerned Scientists (UCS) 
Vantage Data Centers (Vantage) 
Verrus 
Virginia State Corporation Commission 
Vistra Corp. (Vistra) 
Washington Utilities and Transportation Commission 
Wisconsin Electric Company 
Wisconsin Public Service Corporation  
 
 
Adam B. Schiff.

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
California Independent System Operator Corporation 
Citizen S-Line Transmission LLC  
Citizens Sunrise Transmission LLC  
Citizens Sycamore-Penasquitos Transmission LLC  
City of Anaheim, California  
City of Azusa, California  
City of Banning, California  
City of Colton, California  
City of Pasadena, California  
City of Riverside, California 
DCR Transmission, L.L.C.  
DesertLink, LLC  
GridLiance West LLC  
Horizon West Transmission, LLC 
LS Power Grid California, LLC  
Morongo Transmission LLC  
Pacific Gas and Electric Company  
San Diego Gas & Electric Company  
Southern California Edison Company  
Startrans IO, L.L.C.  
SunZia Transmission, LLC  
Trans Bay Cable LLC  
Valley Electric Association, Inc.  
Viridon Path 15, LLC  
Western Area Power Administration 
Docket No. EL26-71-000 
 
 
(Issued June 18, 2026) 
 
SWETT, Chairman, concurring: 
 
 
Today, we take historic action to push our country’s electric markets and economy 
into the future—a future of fair cost allocation, unprecedented transparency for the 
American ratepayer, respect for states’ rights, efficient markets and speed to power.  Last 
October, Secretary Wright articulated the monumental, generational and “urgent” 
challenge FERC must solve for our country when he directed us to develop “reforms to

Docket No. EL26-71-000 
 
- 2 - 
 
ensure the timely and orderly interconnection of large loads to the transmission system.”1  
I strongly agree.  And now, through this suite of six orders, we deliver.     
 
Simply put, the show cause orders the Commission issues today to each of the six 
electric markets subject to its jurisdiction find that the status quo across much of the 
country is not good enough.2  Nowhere close.  The record prompted by the Secretary’s 
ANOPR leaves no doubt that most of the markets (and their existing rules) are inherently 
slow and prohibitive of the dexterity necessary to adapt to and power societal evolution—
whether brought about by technological innovation or sustaining the great industrial 
economy that anchors America.     
 
I wholeheartedly, fully concur with these orders, which we carefully crafted to 
execute upon the problems the Secretary identified in a manner that is quick, efficient, 
and legally durable.  I write separately to highlight certain considerations underlying the 
Commission’s procedural approach to delivering on the ANOPR and to today’s orders.   
 
Based on my analysis of the extensive record and numerous ongoing substantive 
stakeholder interactions, I have determined that the most productive way to “build upon 
the[] principles”3 in the ANOPR and “work expeditiously”4 towards a solution is to issue 
individualized orders to show cause to each market.5  That is so for two main reasons. 
 
1 Advance notice of proposed rulemaking (ANOPR) Interconnection of Large 
Loads to the Interstate Transmission System, Advance Notice of Proposed Rulemaking 
(Oct. 23, 2025) (ANOPR); see Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy 
(Oct. 23, 2025) (Secretary’s Letter). 
2 Cal. Indep. Sys. Operator Corp., 195 FERC ¶ 61,214 (2026) (CAISO); ISO New 
Eng. Inc., 195 FERC ¶ 61,215 (2026) (ISO-NE); Midcontinent Indep. Sys. Operator, Inc., 
195 FERC ¶ 61,212 (2026) (MISO); N.Y. Indep. Sys. Operator, Inc., 195 FERC ¶ 61,216 
(2026) (NYISO); PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 (2026) (PJM); Sw. 
Power Pool, Inc., 195 FERC ¶ 61,213 (2026) (SPP) (collectively, Orders to Show 
Cause). 
3 Secretary’s Letter at 2. 
4 Id. 
5 See SEC v. Chenery Corp., 332 U.S. 194, 202-03 (1947) (“[A]n administrative 
agency must be equipped to act either by general rule or individual order.  To insist upon 
one form of action to the exclusion of the other is to exalt form over necessity. . . . [T]he 
choice made between proceeding by general rule or by individual, ad hoc litigation is one 
that lies primarily in the informed discretion of the administrative agency.”); Wis. Gas 
Co. v. FERC, 770 F.2d 1144, 1166 (D.C. Cir. 1985) (“It is a well-settled principle of

Docket No. EL26-71-000 
 
- 3 - 
 
 
First, the record the Commission collected in response to the challenges identified 
in the ANOPR and subsequent resulting developments indicate that an approach that 
honors the ANOPR principles but accounts for widening regional variation may now be 
more efficient than a one-size-fits-all rule.6  The world has changed a great deal since last 
October.  The ANOPR itself, including the articulated principles, appears to have shifted 
the playing field and prompted great progress across several electric markets.  This 
change (and the Commission’s alignment with the Secretary) is well illustrated by a 
number of landmark orders approving several market new constructs that we issued since 
October, which together operationalize the Secretary’s principles and laid groundwork 
for meaningful reform and today’s actions.7  While working to develop those orders, the 
Commission has simultaneously devoted significant attention to evaluating the various 
procedural paths through which we might comprehensively deliver. 
 
Individual show cause proceedings will allow the Commission to ensure that 
solutions to the problems the Secretary identified are tailored to the specific, varied 
circumstances and market constructs of each region.  Indeed, a careful review of today’s 
six orders reveals the many ways in which those orders are customized for each market’s 
unique circumstances and progress (or lack thereof) towards serving large load.  To name 
just a few examples, the orders recognize ongoing stakeholder processes in various 
regions and are adapted to existing tariff provisions concerning large and co-located 
loads; account for regional variances in allocating rights and responsibilities among 
RTOs/ISOs and the transmission owners; leave room for each market to tailor operational 
requirements for large loads that are particular to their region; and otherwise account for 
incumbent regional differences on topics such as cost allocation and cost transparency, 
study processes, and network upgrade procedures. 
 
Proceeding via show cause proceedings will also allow the markets (and their 
respective transmission owners) to explain, in the first instance, how to address the 
Commission’s concerns.  These entities have the deepest understanding of their 
 
administrative law that the decision whether to proceed by rulemaking or adjudication 
lies within the broad discretion of the agency.”). 
6 “[T]he Commission may rely on ‘generic’ or ‘general’ findings of a systemic 
problem to support imposition of an industry-wide solution.”  Interstate Nat. Gas Ass’n 
of Am. v. FERC, 285 F.3d 18, 37 (D.C. Cir. 2002) (internal citations omitted).  However, 
the Commission “has long allowed different regional transmission organizations to 
follow different rules, in recognition of regional variations including potential differences 
in ‘geographic size and location.’”  Cent. Hudson Gas & Elec. Corp. v. FERC, 138 F.4th 
531, 539 (D.C. Cir. 2025) (internal citations omitted). 
7 See id. P 2 & nn.6-11.

Docket No. EL26-71-000 
 
- 4 - 
 
respective regions and are best positioned to implement solutions we identified, in the 
most expeditious manner.  The Commission will promptly evaluate their responses to 
today’s orders, and, with input from stakeholders, swiftly establish appropriate reforms.   
 
Second, proceeding via individual show cause orders will allow the Commission 
to act more quickly than through traditional rulemaking.  Notice-and-comment 
rulemaking may not capitalize upon individual market progress prompted since October 
and would be unduly time-consuming,8 as it also inevitably would require the additional 
steps of accommodating the regional variations of the approach we take today.  
Rulemaking efforts can be particularly inefficient when, as here, they risk incubating 
uncertainty after progress has begun, and diverting scarce stakeholder resources away 
from other endeavors, such as the development of market-specific reforms submitted to 
the Commission under section 205 of the Federal Power Act (FPA).  (To be clear, we 
very much encourage 205 submissions encapsulating the principles we articulate in the 
206s, and with all due deliberate haste.) 
 
Furthermore, rulemaking requires a lengthy series of steps before the proposed 
reforms would actually take effect—e.g., a NOPR, then a final rule, then potential orders 
on rehearing, and then a “compliance” process in which affected parties make filings (or, 
more likely, multiple rounds of filings) explaining how they intend to implement the rule. 
By their nature, these procedures take time.  For example, the compliance process for the 
Commission’s Order No. 20239 (which matured out of an ANOPR issued in July 2021 
and a NOPR issued in June 2022) still is not fully complete as of June 2026.  The 
compliance process for Order No. 222210 (NOPR issued in November 2016) could be 
considered completed in May 2026; however, even with that timing, not all of the 
RTOs/ISOs have yet fully implemented their Commission-accepted market rules.  I 
provide these examples not to suggest that the completion of a rulemaking process on the 
interconnection of large loads would take this long,11 but rather to make clear the scope 
 
8 See, e.g., Comments of Talen Energy Corporation, Docket No. RM26-4, at 5-6 
(filed Nov. 21, 2025).  
9 Improvements to Generator Interconnection Procs. & Agreements, Order No. 
2023, 184 FERC ¶ 61,054, order on reh’g, 185 FERC ¶ 61,063 (2023), order on reh’g, 
Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC ¶ 61,134 (2024). 
10 Participation of Distributed Energy Res. Aggregations in Mkts. Operated by 
Reg’l Transmission Orgs. & Indep. Sys. Operators, Order No. 2222, 172 FERC ¶ 61,247 
(2020), order on reh’g, Order No. 2222-A, 174 FERC ¶ 61,197, order on reh’g, Order 
No. 2222-B, 175 FERC ¶ 61,227 (2021). 
11 I do not mean to suggest that the public utilities subject to compliance under 
these rulemakings—or the Commission itself—have been derelict.  The time-consuming

Docket No. EL26-71-000 
 
- 5 - 
 
of the years-long delays in implementation that might be expected if the Commission 
elected to proceed via a NOPR.  By contrast, we expect that individual show cause 
proceedings for each of the RTO/ISOs will enable the Commission to spearhead lasting 
reform much more expeditiously.   
 
The six markets together cover nearly two-thirds of load subject to Commission-
jurisdictional rates, and therefore focusing initially on those regions is a prudent first step.  
But I am under no illusion that the challenges discussed in today’s orders are somehow 
unique to the RTO/ISO regions.  Our actions today do not foreclose the possibility of a 
future rulemaking, and nor do they prevent us from acting on filings made under sections 
205 and 206 of the FPA.  I encourage transmission providers and other stakeholders 
outside RTO/ISO regions to make individual filings to address the issues we discuss 
today. 
 
FERC is no longer the sleepy, responsive agency of the past—our country cannot 
afford for it to be.  This is a time for the best thinkers we have to collaborate on solving 
our biggest problems, and thus it is my great honor to deliver a solution that honors the 
Secretary’s goals.  For these reasons, I respectfully concur.   
 
 
________________________ 
Laura V. Swett 
Chairman 
 
 
nature of the compliance process is a natural consequence of complex, nuanced efforts 
toward tariff reform.  As Chairman, I will continue to evaluate Commission directives to 
ensure that obligations on regulated entities are not unduly burdensome and to make 
certain that Commission action during the compliance process is as timely as possible.

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
California Independent System Operator Corporation 
Citizen S-Line Transmission LLC  
Citizens Sunrise Transmission LLC  
Citizens Sycamore-Penasquitos Transmission LLC  
City of Anaheim, California  
City of Azusa, California  
City of Banning, California  
City of Colton, California  
City of Pasadena, California  
City of Riverside, California 
DCR Transmission, L.L.C.  
DesertLink, LLC  
GridLiance West LLC  
Horizon West Transmission, LLC 
LS Power Grid California, LLC  
Morongo Transmission LLC  
Pacific Gas and Electric Company  
San Diego Gas & Electric Company  
Southern California Edison Company  
Startrans IO, L.L.C.  
SunZia Transmission, LLC  
Trans Bay Cable LLC  
Valley Electric Association, Inc.  
Viridon Path 15, LLC  
Western Area Power Administration 
Docket No. EL26-71-000 
 
 
(Issued June 18, 2026) 
 
ROSNER, Commissioner, concurring:  
 
 
The electric industry is in the midst of changes not seen in a generation.  
Compared to more traditional load growth, the large loads seeking to connect to the grid 
today are larger, sometimes by orders of magnitude, and more concentrated.  They also 
exhibit different operational characteristics, such as the ability to quickly change their 
energy consumption, sometimes in seconds.  Often, these large loads seek to connect to 
the grid as quickly as possible.  And because of these dynamics, large loads are rapidly 
driving the need for new transmission infrastructure and energy supply.  This creates new 
challenges that, if unaddressed, could jeopardize the reliability and affordability of the 
grid on which we all depend.

Docket No. EL26-71-000  
- 2 - 
 
Today, we are taking an important step toward addressing these challenges.  We 
are opening a dialogue with each of the six RTO/ISOs on a series of reforms that are 
tailored to address the unique reliability and affordability challenges posed by large load 
growth and the infrastructure buildout needed to serve dramatically growing demand.  
Informed by the record developed in response to the Secretary of Energy’s October 2025 
ANOPR,1 and by innovative proposals that stakeholders have filed with the Commission 
under FPA section 205, today’s orders are aimed at ensuring that the grid remains reliable 
and affordable for all customers, especially residential customers.  It is also crucial that 
we unlock the immense economic opportunity that once-in-a-generation growth 
represents.  While each order’s specific focus varies according to the progress that each 
RTO/ISO has made, our actions today fit broadly into four key pillars that, taken 
together, provide a foundation for durable reform.  Today, we are: (1) Protecting 
Consumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering 
Innovation (see Figure 1).  I write separately to explain how. 
***** 
 
Protecting Consumers:  Today’s orders include key protections that promote 
affordability.  First, today’s orders require “Cost Recovery Agreements”, which are 
designed to ensure that large loads pay their fair share of the costs incurred to serve them, 
regardless of whether the large load comes online as planned.  Thus, if new infrastructure 
is built to accommodate a data center, and that data center doesn’t show up, residential 
customers are not left on the hook to pay the costs.  Cost Recovery Agreements prevent 
those costs from being shifted to residential customers.  Depending on how they are 
structured, Cost Recovery Agreements can also address the potentially uneven pacing of 
new infrastructure costs, where grid upgrade costs may hit customer bills before the large 
load is fully online and energized.  Data centers have committed to paying their own 
way.2  Today, with “Cost Recovery Agreements,” we are taking steps to ensure that those 
commitments are honored.  I note, however, that the door remains open to other creative, 
regionally-specific ideas to protect consumers.  If there are other ways to accomplish that 
goal, I welcome those proposals. 
 
Another win for consumers is requiring RTO/ISOs to consider grid enhancing 
technologies (GETs), including dynamic line ratings, when adding new large loads to the 
grid.  GETs are technologies that squeeze more juice out of the existing grid, reducing the 
need for expensive upgrades and speeding up the time connect.  Ensuring that RTO/ISOs 
 
1 U.S. Dep’t of Energy, Secretary of Energy Chris Wright, Direction that the 
Commission Initiate Rulemaking Procedures and Proposal Regarding the Interconnection 
of Large Loads Pursuant to the Secretary’s Authority Under Section 403 of the 
Department of Energy Organization Act (Oct. 23, 2025). 
2 See Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026).

Docket No. EL26-71-000  
- 3 - 
consider GETs in the planning process—and if GETs are not used, explain why—not 
only helps new large loads get connected more quickly, but is also a commonsense step 
towards saving all consumers money.  Put differently, today’s orders will help us 
understand if we are leaving efficiencies on the table, an outcome we cannot afford. 
 
Safeguarding Reliability:  Today’s orders safeguard reliability.  They help ensure 
that RTO/ISOs use study procedures and operational requirements that reflect large 
loads’ unique characteristics and the reliability impacts of connecting them to the grid.  
Those novel characteristics and reliability impacts are well-documented, and it is not 
clear if existing study procedures or operational requirements account for them.  Clear, 
comprehensive, and specifically tailored study procedures and operational requirements 
are needed, such as enhanced data reporting and telemetry to increase visibility into how 
these loads interact with the grid, and today’s orders represent progress towards this goal. 
 
Finally, although not part of today’s orders, I want to highlight NERC’s ongoing 
efforts to establish registration criteria for large computational loads and to develop 
reliability standards.3  NERC’s goal is to finish the first phase of this critical work this 
year.  It is essential that NERC meet this deadline.  I encourage all stakeholders to 
participate in NERC’s process. 
 
Enhancing Transparency:  Today’s orders provide regulators—the Commission 
and, critically, our state partners—and customers with data on how connecting large 
loads to the grid affects bills.  Today’s orders embody a commonsense approach: if a  
Network Upgrade is built to connect a large load to the grid, consumers should know who 
that upgrade was built for and what it cost. 
 
Transparency is important because “who pays?” has been and continues to be a 
fraught and contentious question for large load interconnection.  Stakeholders, including 
state regulators and the ratepayers that they represent, must know the costs, for whom 
they are being incurred, and how they are being allocated, to know that everyone is 
paying their fair share.  Today’s orders ensure that this information is public, accessible, 
and clear.  State regulators in more than half of the country have enacted large load 
tariffs.4  Our action today helps them as they continue their critically important work. 
 
3 NERC, Large Loads Action Plan Q1 2026 Update (Apr. 2026), 
https://www.nerc.com/globalassets/initiatives/large-loads-action-plan/llap-quarterly-
update-q1-2026.pdf. 
4 See, e.g., National Association of Regulatory Utility Commissioners 
Supplemental Comments at 2-6; Edison Electric Institute Supplemental Comments at 
App. 9-13.

Docket No. EL26-71-000  
- 4 - 
 
The Commission’s action today also addresses speculative load interconnection 
requests, which clog up load interconnection queues, divert resources, and distort 
forecasts.  Under current rules, data centers can (and are incentivized to) “shop around” 
their prospective projects with different utilities to identify the fastest and cheapest 
location to connect.  This wastes time and resources studying projects that are not real.  
Worse yet, it can inflate expected load growth by modeling projects that do not 
materialize, leading to double counting, inaccurate market signals, and unnecessarily high 
prices for consumers.  Today, we target speculative projects by establishing escalating 
readiness requirements for distinct phases of the study process to deter duplicative or 
speculative requests for transmission service.  I strongly encourage RTO/ISOs to pursue 
other improvements to load forecasts, such as using objective screening criteria like 
physical site control, to ensure that the data used to plan the grid is as accurate as 
possible.5   
 
Fostering Innovation:  As I have said, to meet the moment, “a business-as-usual 
approach . . . will not suffice.”6  Building new infrastructure is difficult and costly, which 
delays efforts to connect large loads to the grid quickly, reliably, and cost effectively.  
This is doubly true when generation and load are planned and studied separately.  
Today’s orders push beyond this status quo. 
 
First, today’s orders promote flexible transmission services—that is, non-firm 
service to a co-located load that is willing and able to limit withdrawals from the grid—in 
every RTO/ISO (see Figure 2).  As we explained when we first created these 
transmission services in PJM for co-located loads, customers willing to embrace 
flexibility can reduce the need for Network Upgrades and generating capacity to serve a 
co-located load, which speeds up connecting to the grid and reduces costs for the co-
located load as well as other retail customers. 
 
Second, today’s orders recognize that extending these same transmission services 
to large loads that are not co-located but that may also be willing to limit their 
withdrawals from the grid can unlock even more efficiency.  Just as for co-located loads, 
legalizing flexible transmission service options for more large load customers can speed 
interconnection, avoid constructing unnecessary transmission upgrades, reduce strain on 
the grid, and make power bills cheaper for everyone. 
 
5 See Comm’r David Rosner, Letter to the RTOs/ISOs on Large Load Forecasting 
(Sept. 18, 2025), https://www.ferc.gov/news-events/news/chairman-rosners-letter-
rtosisos-large-load-forecasting.  
6 PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2026), (Rosner, Comm’r, 
concurring) at P 3.

Docket No. EL26-71-000  
- 5 - 
 
Finally, today’s orders embrace yet another innovation.  Load and generation need 
not be co-located to reduce the number of Network Upgrades; in other words, literal co-
location is not the only way to facilitate faster, more efficient, and more cost-effective 
connections to the grid.  Rather, where a large load and an associated generator are 
electrically proximate (i.e., close together) and studied together, the reliability impacts on 
the grid may be more limited than if the load and generator are studied separately.  Just 
like with co-location, more limited impacts on the grid mean, all else equal, fewer 
Network Upgrades, which makes connecting to the grid faster, more efficient, and 
cheaper for both the large load and the associated generator.  That last point is key.  To 
add new supply to the grid, we must create incentives for “Bring Your Own New 
Generation.”  Today’s orders make BYONG faster and more efficient.  
 
SPP has been a leader in showing how to push beyond the status quo.  With its 
innovative HILLGA proposal, approved by the Commission in January,7 SPP leveraged 
the opportunity for speed and efficiency by studying load and generation together, and by 
creating a limited, expedited interconnection service to connect faster.  By matching the 
generator’s output to the electrically proximate large load’s demand, the impacts to the 
grid are less than they otherwise would be, minimizing the need for time-consuming and 
costly Network Upgrades needed to connect.  HILLGA is one solution that works for 
SPP, but today’s orders direct other regions to follow SPP’s lead in ways that work for 
them.  Today’s orders add a key tool by ensuring that all RTO/ISOs can study load and 
generation together.  
***** 
 
The Commission’s action today is an important step forward, but the Commission 
cannot accomplish this work alone.  States are essential partners in this work.  The 
Commission’s actions here respect the long-standing jurisdictional line between federal 
and state authority provided by Congress and repeatedly affirmed by the Supreme Court.  
States retain exclusive jurisdiction to allocate the costs of FERC-jurisdictional 
transmission charges among their retail ratepayers, including co-located loads.  States 
also hold the keys to energy infrastructure permits, so we rely on their decisions to ensure 
that needed transmission and generation get built.  At a time when some large loads are 
retail customers that can consume as much energy as a small city, it is imperative that we 
work within our respective jurisdictions, but that we collaborate. I look forward to 
continued collaboration. 
 
Today’s orders begin an important dialogue with RTO/ISOs.  As a potential next 
step, today’s orders invite RTO/ISOs to respond by submitting proposals under FPA 
section 205.  I cannot encourage this enough.  I also encourage public utilities outside of 
RTO/ISOs across the country to do the same.  The electric industry is rapidly evolving 
 
7 See Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026).

Docket No. EL26-71-000  
- 6 - 
with regions experiencing and addressing these challenges in different ways.  Many of 
the examples on which the actions in today’s orders are based on stakeholders thinking 
creatively to develop solutions, and I welcome other new, innovative, and regionally 
tailored proposals that build on the four key pillars set forth today:  (1) Protecting 
Consumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering 
Innovation.  Only by working together can we rise to the occasion and meet this once-in-
a-generation moment to deliver the reliable and affordable energy on which we all 
depend.  It will not be easy, but I remain optimistic and look forward to the path ahead. 
For these reasons, I respectfully concur. 
 
 
 
________________________ 
David Rosner 
Commissioner

Figure 1

Figure 2

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
California Independent System Operator Corporation 
Citizen S-Line Transmission LLC  
Citizens Sunrise Transmission LLC  
Citizens Sycamore-Penasquitos Transmission LLC  
City of Anaheim, California  
City of Azusa, California  
City of Banning, California  
City of Colton, California  
City of Pasadena, California  
City of Riverside, California 
DCR Transmission, L.L.C.  
DesertLink, LLC  
GridLiance West LLC  
Horizon West Transmission, LLC 
LS Power Grid California, LLC  
Morongo Transmission LLC  
Pacific Gas and Electric Company  
San Diego Gas & Electric Company  
Southern California Edison Company  
Startrans IO, L.L.C.  
SunZia Transmission, LLC  
Trans Bay Cable LLC  
Valley Electric Association, Inc.  
Viridon Path 15, LLC  
Western Area Power Administration 
Docket No. EL26-71-000 
 
 
 
(Issued June 18, 2026) 
 
SEE, Commissioner, concurring:  
 
 
Growing electricity demand underscores America’s economic strength and the 
opportunities that come with it.  And with new opportunities come new challenges.  The 
pace and scale of emerging large loads create new circumstances that require us to adapt 
in how we build and manage the grid.  Large and flexible loads can materially change 
system operations, for instance, as well as near-term planning needs, upgrade 
requirements, and how we allocate costs.  Most existing systems were not designed to 
accommodate those changes—especially not at the pace needed to support AI growth and 
advanced manufacturing that are central to America’s economic competitiveness.  As a

Docket No. EL26-71-000 
- 2 - 
 
result, uncertainty over the operative rules and delays in interconnecting large loads can 
undermine reliability and investment and add unacceptable and avoidable costs.  
 
Today, the Commission takes strong action within our jurisdictional sweep to 
address these and other challenges that large load growth poses to the interstate 
transmission system.  Today’s orders support both just and reasonable rates and speed to 
(reliable) power.  I’m deeply grateful for the many commenters who shared their insight 
and ideas in this action.  They let us build a record that highlights the need for clearer 
processes, better information, and faster analysis while our country moves new large load 
additions online.  As we press forward in these dockets, I will be looking to continue 
building on the momentum already underway across the country to craft more practical, 
region-specific solutions that support timely action while protecting consumers.  Our 
continued ability to deliver reliable and affordable electricity requires nothing less.   
 
Today’s orders speak for themselves.  I write separately to briefly highlight two 
principles baked throughout them and that I believe must remain central as the 
Commission evaluates further steps.   
 
First, these issues extend beyond the Commission.  Creating efficient, predictable 
large load interconnection processes is a joint and overlapping task for us, other federal 
agencies, the States, and the RTOs/ISOs and utilities.  My animating principle here is that 
we must use FERC’s statutory authority to bring clarity to the parts of this national issue 
we own, and to complement and aid others as they tackle theirs.  The very procedure the 
Commission deploys today reflects that goal: Recognizing the value in region-specific 
approaches, we are directing individual action in each of the RTO/ISO regions and 
encouraging—strongly—proposals under section 205 of the Federal Power Act from 
transmission providers or other entities that are molded to their unique system needs. 
 
Most critically, exercising our authority fully without hamstringing our regulatory 
and industry partners means respecting the States.  States make many of the key decisions 
that affect how we manage large loads.  States bring indispensable expertise over local 
conditions, siting needs, retail structures, and the resource decisions within their borders.  
And they have been hard at work pursuing the retail implications and other State-specific 
concerns that large load interconnection presents.1  All this effort flows from the States’ 
statutorily preserved role in regulating the power system.  Today’s order understands that 
limit—our power “extend[s] only to those matters which are not subject to regulation by 
the States.”2  It also embraces the value in a statutory lens that views large load issues as 
an area of shared federal-State responsibility.  As we require clear study and operational 
 
1 See EEI Supplemental Comments at Appendix 9 – 13 (listing pending and 
approved State large load tariffs).  
2 16 U.S.C. § 824(a).

Docket No. EL26-71-000 
- 3 - 
 
parameters for large load interconnection, we should remember that the nation’s energy 
landscape is not monolithic.  State and regional diversity is a strength, and today’s orders 
know that the best solutions reflect differing system characteristics.  Our action today is 
designed to support further State efforts in this urgent and fast-moving space, not 
override them. 
 
Second, affordability must be at the forefront as we protect consumers from 
unnecessary costs in a time of rising demand.  True, the Commission lacks authority over 
all the factors that drive electricity costs at the retail level.  Today’s orders recognize that.  
In response, the orders strive to aid the States in their front-line affordability duties by 
getting into their hands all relevant information about Commission-jurisdictional costs.  
As these matters move forward, I am particularly interested in continued feedback from 
the States on what information they most need to assess cost implications as new loads 
come online.  Are the cost transparency measures we identify today sufficient, or are 
additional or more granular data needed for States to appropriately suballocate 
transmission costs among retail customers?  Tools like alternative cost allocation 
structures, greater clarity in transmission service agreements, accounting for States’ 
large-load-specific tariffs, and direct assignment in appropriate cases may help States 
ensure that retail consumers do not bear costs incommensurate with the benefits they 
receive. 
 
Moving to areas where the Commission has a more direct role in ensuring cost 
responsibility, we need to pull all the levers we have to keep rates fair and transparent.  
Today we reaffirm our responsibility to assign jurisdictional costs to the customers who 
drive or benefit from grid upgrades, not shift them onto families and small businesses.  
For instance, today’s orders seek to reduce large-load driven network upgrade costs 
through alternative transmission technologies, or ATTs (also commonly called Grid 
Enhancing Technologies).  In determining how best to meet the needs of this historic 
large load growth, technologies that can improve system capability faster than traditional 
upgrades and at lower costs deserve a hard look.  ATTs may not be the best tool in every 
circumstance, but where they are they can support timely interconnections and avoid 
potentially tens or hundreds of millions of dollars in unnecessary network upgrade costs 
that would otherwise flow into transmission customers’ bills.    
 
So our approach today supports continuing the Commission’s policy to roll most 
network upgrade costs—including those in the large load space—into the embedded-cost 
rate most transmission customers pay.  But it includes an asterisk that this policy works 
for ratepayers only so long as we remain committed to pursuing technological 
innovations that keep those costs at a responsible and accountable level.  Today’s order 
thus calls for transmission providers to sufficiently evaluate ATTs to assess if and how 
they can meet large loads’ interconnection needs.  The answer may be yes or no in a 
given case.  But if the transmission provider opts for traditional network upgrades, they 
must demonstrate why ATTs are not feasible or would not result in lower costs or a faster

Docket No. EL26-71-000 
- 4 - 
 
timeline for the large load interconnection customer.  In short, the goal is to respect 
transmission providers’ engineering judgments while protecting against upgrade costs 
when ATTs could solve transmission needs faster and with a lower bill.    
 
I am also sensitive to novel questions about cost shifting that interconnecting large 
load may present.  Today’s findings on cost recovery agreements between transmission 
owners and Eligible Customers are an important step in mitigating the risks of stranded 
assets if large loads prove speculative.  We are also reducing unnecessary redundancy by 
allowing an Eligible Customer to meet its financial security requirements by relying on 
credit support or other financial security a large load customer may have posted under a 
retail agreement.  As we gain more experience studying transmission service requests on 
behalf of large loads, it may become appropriate to further streamline financial security 
arrangements.  Perhaps, for instance, cost -recovery agreements between a transmission 
owner and a large load customer itself could satisfy an Eligible Customer’s financial 
security requirements.  As we move forward, I’ll be looking to ensure cost-recovery 
agreements contain fair and transparent measures to ensure the right costs get on the right 
bills.  (Relatedly, the discussion about the full nature of transmission-related charges in 
our concurrent PJM Order on Rehearing, Clarification, Compliance, and Paper Hearing3 
may prove relevant here: Real-world experience with new transmission services for co-
located load may clarify if future action becomes needed to address potential cost shifts 
as Eligible Customers take new transmission services on behalf of large loads.4)   
 
More generally, as we gain more experience as an industry and a country in 
getting large loads connected to the grid, I welcome bold proposals to keep affordability 
central.  Large load growth presents a real opportunity to build a stronger, more capable, 
and more reliable electric system that can benefit all ratepayers.  Meeting that opportunity 
at the pace we need and at an acceptable cost requires innovative thinking and fast action.  
I commend the States in their continued work in these areas.  I urge the RTOs and ISOs 
to continue their good work as they respond quickly to today’s orders.  I also remain 
committed to moving forward within the Commission’s statutory zone with clarity and 
decisiveness.  I am proud to support the Commission’s important steps today.  And we all 
have more work ahead.    
For these reasons, I respectfully concur.  
 
 
 
3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026). 
4 See id. P 456.

Docket No. EL26-71-000 
- 5 - 
 
 
______________________________ 
Lindsay S. See 
Commissioner

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
 
California Independent System Operator Corporation 
Citizen S-Line Transmission LLC  
Citizens Sunrise Transmission LLC  
Citizens Sycamore-Penasquitos Transmission LLC  
City of Anaheim, California  
City of Azusa, California  
City of Banning, California  
City of Colton, California  
City of Pasadena, California  
City of Riverside, California 
DCR Transmission, L.L.C.  
DesertLink, LLC  
GridLiance West LLC  
Horizon West Transmission, LLC 
LS Power Grid California, LLC  
Morongo Transmission LLC  
Pacific Gas and Electric Company  
San Diego Gas & Electric Company  
Southern California Edison Company  
Startrans IO, L.L.C.  
SunZia Transmission, LLC  
Trans Bay Cable LLC  
Valley Electric Association, Inc.  
Viridon Path 15, LLC  
Western Area Power Administration 
Docket No. EL26-71-000 
 
 
 
(Issued June 18, 2026) 
 
CHANG, Commissioner, concurring: 
 
 
In a series of orders today, the Commission initiates separate proceedings under 
Federal Power Act (FPA) section 206 to explore the impact of the increasing growth of 
large loads in Regional Transmission Organization (RTO) and Independent System 
Operator (ISO) regions.  The preliminary findings in these orders, and the associated 
proposed reforms to RTO/ISO and transmission owner tariffs, could significantly change 
how loads procure, use, and pay for transmission service, with ramifications for 
RTO/ISO operations, planning, and markets.  I write separately to emphasize the

Docket No. EL26-71-000 
- 2 - 
 
importance of building actionable records in these proceedings, particularly with respect 
to our consideration of customer protection, transmission service, and alternative 
transmission technology reforms. 
I. 
Overview of Today’s Orders 
 
In each of today’s orders to show cause, the Commission identifies a series of 
issues raised by the ongoing growth of large loads, directs briefing on whether existing 
tariffs remain just and reasonable in light of those developments, and describes possible 
solutions to those issues if the Commission ultimately concludes that the relevant tariffs 
are unjust and unreasonable.  Each order is directed to a specific RTO/ISO and relevant 
transmission owners that play a role in interconnecting large loads to the Commission-
jurisdictional transmission system.  The Commission does not pursue the broad assertion 
of jurisdictional authority contemplated in the Advanced Notice of Proposed 
Rulemaking, which I hope assuages concerns raised by our state colleagues that the 
Commission ought not encroach upon matters properly left to their jurisdiction.1   
 
Broadly summarized, each order seeks regional input on a specific list of issues: 
(1) the clarity and consistency of existing rules governing how each RTO/ISO and its 
relevant transmission owners analyze the impact of providing transmission service to 
Eligible Customers on behalf of large loads; (2) whether each RTO/ISO tariff requires 
reforms to mitigate the risk of cost shifting among wholesale transmission customers; (3) 
whether each RTO/ISO tariff (other than PJM) requires additional clarity regarding the 
provisions addressing co-located generation and load arrangements; (4) the potential 
extension of new firm and non-firm transmission services to co-located load, load with 
behind the meter generation, and other flexible loads; and (5) the need for reforms, 
modeled on Southwest Power Pool, Inc.’s High Impact Large Load Generation 
Assessment concept, to facilitate a process through which a generator may temporarily 
serve a co-located or electrically proximate load until interconnection and transmission 
service is available.  The Commission also invites each region to submit FPA section 205 
filings that can address each issue identified in the orders, thereby resolving the 
Commission’s concerns.   
II. 
The Commission Needs Good Records to Ensure Reasoned Decision-Making   
 
I first want to emphasize that the Commission needs active participation from 
interested stakeholders to develop thorough records in each region.  The Commission 
 
1 I will do my part to ensure that the Commission continues to be a collaborative 
partner to our state counterparts, other federal agencies, and the industry as we seek to 
address this wide-ranging challenge.  Accordingly, I welcome feedback from our state 
colleagues and others if they believe the Commission’s preliminary findings raise 
jurisdictional concerns.

Docket No. EL26-71-000 
- 3 - 
 
cannot make reasoned decisions about whether reforms might be needed without an 
accurate understanding of the existing processes, which differ by region.  Because the 
Commission is acting via FPA section 206 rather than generically through a rulemaking, 
the issues addressed by these orders will be subject to ex parte restrictions across the 
RTOs/ISO regions, including with our state colleagues whose regulation can and will 
directly affect the individual transmission owners that need to comply with the orders 
issued today.  This will limit the Commission’s ability to engage in informal fact-finding 
and discussions with regional stakeholders, and thus, it is even more essential that the 
record in each region fully reflects the views of all interested parties.   
 
Second, I highlight three issues below that will be especially important to the 
success of this effort, and I hope that interested parties will take particular care in helping 
the Commission address those issues.  Importantly, I recognize that the record established 
in each RTO/ISO region will (and should) differ, which will allow the Commission to 
ensure any required changes to an RTO/ISO’s tariff are appropriately tailored to that 
region’s needs. 
III. 
The Commission Needs to Pursue Meaningful Customer Protection  
 
The FPA is fundamentally a customer protection statute,2 and the Commission has 
an obligation to ensure that the rates that wholesale and transmission customers pay are 
just and reasonable.  Rapid large load growth has strained planning and resource 
procurement processes around the country, as transmission owners, load serving entities, 
and generators accelerate the building of new infrastructure needed to serve these new 
loads.  As we develop the new infrastructure, many have raised concerns about whether 
these costs are being fairly assigned to new and existing customers, whose benefits must 
be commensurate with the costs they pay.  While individual states have been exploring or 
using various approaches to protect retail customers against unjustified cost shifts, the 
Commission to date has not initiated any proactive exploration of how to protect 
wholesale customers against unjustified cost shifts. I am laser-focused on this issue 
because we should not create unjustified costs for consumers in our efforts to connect and 
serve large loads.  
 
In today’s orders, the Commission launches an inquiry into whether existing 
RTO/ISO tariffs include adequate mechanisms to mitigate the risk of undue cost shifting 
among transmission customers.  To address this risk, the Commission preliminarily 
identifies a two-part solution: (1) that each RTO/ISO post public information about the 
amount of new large loads seeking to connect to the RTO’s/ISO’s transmission system, 
 
2 See, e.g., Mun. Light Bds. Of Reading and Wakefield v. FPC, 450 F.2d 1341, 
1348 (D.C. Cir. 1971) (stating that the FPA’s “primary aim is the protection of 
consumers from excessive rates and charges”).

Docket No. EL26-71-000 
- 4 - 
 
any Network Upgrades identified in the local transmission planning process to serve 
those loads, and the costs of those Network Upgrades; and (2) that each RTO/ISO adopt a 
pro forma cost recovery agreement to help ensure that Eligible Customers serving large 
loads bear the risk and are ultimately responsible for costs incurred to provide 
transmission service.  I strongly support this effort to provide additional transparency 
regarding jurisdictional transmission service requests and the costs associated with 
providing transmission service to the requesting parties, as the Commission cannot 
effectively execute its statutory responsibilities without sufficient understanding of the 
costs that feed into jurisdictional rates.   
 
Exploring how agreements between transmission owners and Eligible Customers 
can protect wholesale customers against cost shifts is important.  However, as I have 
previously explained, bilateral agreements that simply provide 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.3  It is therefore important that the resulting 
regulatory and rate design are not limited to a pre-defined solution set, and that parties 
provide the Commission with comprehensive records outlining various and innovative 
approaches to protect customers.  I am encouraged by the continued development of the 
ANOPR record on this subject,4 innovative solutions being developed at the state level,5 
and a growing body of thoughtful analyses and proposed approaches to provide customer 
protection for costs driven by large load growth.6  Without prejudging any particular 
 
3 E.g., PECO Energy Co., 193 FERC ¶ 61,148 (2025) (Comm’r 
Chang, concurring); Commonwealth Edison Co., 194 FERC ¶ 61,109 (2026) (Comm’r 
Chang, concurring). 
4 E.g., Interconnection of Large Loads to the Interstate Trans. Sys., Supplemental 
Comments of FirstEnergy Svc. Co., Docket No. RM26-4-000 (filed June 5, 2026); id., 
Comment of the Harvard Electricity Law Initiative, Docket No. RM26-4-000 (Apr. 15, 
2026); id., Supplemental Comments of WIRES, Docket No. RM26-4-000 (Mar. 30, 
2026). 
5 E.g., Utility Dive, Microsoft seeks Nevada tariff to shield ratepayers from data 
center costs (June 8, 2026), available at https://www.utilitydive.com/news/microsoft-
seeks-nevada-tariff-to-shield-ratepayers-from-data-center-costs/822250/. 
6 E.g., Travis Kavulla, How Will Data Centers Pay for Power?, American Affairs 
(may 2026), available at https://americanaffairsjournal.org/2026/05/how-will-data-
centers-pay-for-power/ ; Electricity Customer Alliance, A Customer-Centric Agenda for 
the Federal Energy Reg. Comm’n (Jan. 2026), available at https://lnkd.in/em-apfuQ; 
Grid Strategies, Federal Transmission Pricing Vol. 2, Options for Ensuring Affordability 
in an Era of High Load Growth (June 2026), available at

Docket No. EL26-71-000 
- 5 - 
 
proposed solution, the Commission needs a robust record in each docket and each region 
to ensure we establish the right cost shift protections for wholesale customers, including 
but not limited to the commitments outlined in the Ratepayer Protection Pledge.7   
 
I support initiating our own review of customer protection approaches, rather than 
simply relying on voluntary commitments that may fall short of optimal protection, 
because the Commission has the opportunity and obligation to get this issue right.  I 
therefore encourage interested parties to assist the Commission in that effort by clearly 
and comprehensively explaining the benefits and tradeoffs of alternative customer 
protection approaches.  How power infrastructure costs will be assigned across Eligible 
Customers that serve large loads and other customers is at the core of the efforts we 
initiate today.       
IV. 
The Commission Needs to Understand the Implications of Extending New 
Transmission Services to Additional Loads and Regions 
 
The orders also preliminarily find that the Commission should extend the 
transmission services developed in the PJM co-location proceeding – Interim NITS, Firm 
Contract Demand, and Non-Firm Contract Demand – to new types of load and new 
regions.  These new transmission services represent a fundamental paradigm shift from 
the traditional network service and point-to-point transmission service models established 
in Order No. 888 that have been used across the country for the last three decades.8  
While these services have the potential to facilitate more efficient use and build out of the 
transmission system, they also contemplate running the system “tighter” than we have 
done in the past, potentially with more loads on the system served by co-located or 
behind-the-meter generation, and potentially more use of batteries, load control systems, 
and backup resources to manage demand during system peaks or other stressed 
conditions.  While it is important to identify innovative solutions that can adapt to the 
needs of the system, the Commission and grid operators must also be careful not to 
implement changes that create unforeseen reliability risks.  Ultimately, we must find the 
proper balance (and I would argue we are exploring a new balance) between costs of 
investments versus reliability.   
 
The Commission’s experience in the PJM co-location proceeding highlights the 
complexities and challenges of introducing these new transmission services, which have 
significant ramifications for system operations, transmission planning, grid reliability, 
 
https://gridstrategiesllc.com/project/federal-transmission-pricing.  
7 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026). 
8 This is particularly true in CAISO, which does not rely upon the Order No. 888 
NITS framework.

Docket No. EL26-71-000 
- 6 - 
 
market dispatch, resource adequacy, and cost allocation.  As the Commission considers 
whether to expand these transmission services to new types of load and new regions, I 
encourage commenters to address what impacts the introduction of new firm and non-
firm transmission products would have in their regions, as well as any relevant 
characteristics that might distinguish their regions from the Commission’s findings in the 
PJM co-location docket.  Ultimately, this topic will have direct long-term impacts on how 
future transmission systems will be planned and configured, how efficiently future power 
markets will operate, and how customers will respond to prices and system needs.  
Therefore, I am specifically interested in understanding how extending the new 
transmission services might affect individual suppliers or customers, as well as how 
existing systems or processes might be affected by these new services.  I am open to 
understanding how these services might be helpful to a region or that they may create 
problems not yet anticipated.   
V. 
The Orders Recognize the Importance of Evaluating Advanced Transmission 
Technologies 
 
Lastly, today we preliminarily find that each RTO/ISO’s tariff is unjust and 
unreasonable because the tariff lacks clear and consistent provisions requiring the 
evaluation of alternative transmission technologies as potential solutions to accommodate 
an Eligible Customer’s request for transmission service on behalf of a large load.  
Specifically, it is important for RTO/ISOs and transmission owners to evaluate whether 
alternative transmission technologies are feasible in reducing the cost of transmission 
system upgrades or allow for a faster timeline for accommodating the transmission 
service request.  As many transmission owners have explored various alternative 
technologies in pilot projects,9 it is time to roll out all available technologies to reduce 
 
9 See, e.g., Increasing Mkt. and Planning Efficiency Through Improved Software, 
Effective Congestion Mitigation with Transmission Topology Optimization at Alliant 
Energy and ATC, Docket No. AD10-12-016, available at 
https://www.ferc.gov/media/effective-congestion-mitigation-transmission-topology-
optimization-alliant-energy-and-atc (Alliant and ATC were able to save customers 
approximately $24 million over a 12-month period through the use of topology 
optimization); Pablo Ruiz and Derek Brown, “Reliable and Efficient Congestion 
Mitigation Using Transmission Reconfigurations,” NewGrid and Evergy presentation 
(Oct. 2022)¸ available at https://www.spp.org/Documents/67968/SAG%20Meeting%20 
Materials%2020221007.zip (identifying reconfigurations, had they been implemented, 
which could eliminate 98% of overloads and reduce congestion costs by 85% for 
congestion patterns associated with 10 significant constraints on Evergy’s system); 
Pacific Gas & Electric Press Release, PG&E and Smart Wires Enhance Grid Reliability, 
Capacity for Data Centers in San Jose (May 28, 2025), available at 
https://investor.pgecorp.com/news-events/press-releases/press-release-details/2025/PGE-
and-Smart-Wires-Enhance-Grid-Reliability-Capacity-for-Data-Centers-in-San-

Docket No. EL26-71-000 
- 7 - 
 
risks and costs for customers, as well as help the industry continue to develop new 
technologies that can increase the robustness of our transmission system while protecting 
customers from higher costs. 
VI. 
Conclusion 
 
Today’s orders address some of the most consequential issues currently in the 
industry and before the Commission.  I hope that these proceedings provide vehicles 
through which the Commission can provide much-needed clarity and direction, and it is 
imperative that we build strong and comprehensive records on each issue in each region 
to inform our decision-making.  I therefore encourage all interested parties to fully 
engage and help the Commission navigate these complex, multi-faceted challenges.  Our 
success will ultimately be measured by our shared ability to deliver reliable and 
affordable power to all customers, to ensure new loads can interconnect in a timely 
fashion while paying their fair share of system costs, and to protect existing customers 
against adverse reliability or economic impacts.   
For these reasons, I respectfully concur.  
 
 
________________________ 
Judy W. Chang 
Commissioner 
 
 
Jose/default.aspx (describing PG&E’s deployment of advanced power flow control 
devices were able to mitigate thermal overloads by up to 34%, enabling an additional 100 
MW of firm power delivery over existing lines at a congested substation).

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
California Independent System Operator Corporation 
Citizen S-Line Transmission LLC  
Citizens Sunrise Transmission LLC  
Citizens Sycamore-Penasquitos Transmission LLC  
City of Anaheim, California  
City of Azusa, California  
City of Banning, California  
City of Colton, California  
City of Pasadena, California  
City of Riverside, California 
DCR Transmission, L.L.C.  
DesertLink, LLC  
GridLiance West LLC  
Horizon West Transmission, LLC 
LS Power Grid California, LLC  
Morongo Transmission LLC  
Pacific Gas and Electric Company  
San Diego Gas & Electric Company  
Southern California Edison Company  
Startrans IO, L.L.C.  
SunZia Transmission, LLC  
Trans Bay Cable LLC  
Valley Electric Association, Inc.  
Viridon Path 15, LLC  
Western Area Power Administration 
Docket No. EL26-71-000 
 
(Issued June 18, 2026) 
 
LACERTE, Commissioner, concurring: 
 
 
I support today’s fleet of show cause orders.  We are at an inflection point in the 
history of American energy infrastructure.  The extraordinary and rapid growth of large 
loads in RTOs and ISOs is faster than the current system can handle.  This order charts a 
course for addressing the potential gaps and shortcomings in CAISO’s Tariff and/or the 
Transmission Owner Tariffs (TO Tariffs) that need to be resolved to appropriately 
respond to this growth, as informed by careful review of the thousands of pages of 
comments received in response to the advance notice of proposed rulemaking (ANOPR).1  
 
1 Interconnection of Large Loads to the Interstate Transmission System, Advance 
Notice of Proposed Rulemaking, Docket No. RM26-4-000, (Oct. 23, 2025) (ANOPR);

Docket No. EL26-71-000 
- 2 - 
 
I write separately to underscore my expectation for RTOs and ISOs, including CAISO 
and/or the Participating Transmission Owners, to timely submit their robust, thoughtful, 
and region-specific proposals to address the concerns that we have preliminarily 
identified in their respective tariffs and agreements.  By harnessing your region-specific 
expertise and creativity to bring tailored solutions to the table, together we can 
efficiently, reliably, and affordably integrate large load, co-located load and generation 
and/or storage, as well as electrically proximate large load onto the transmission system.  
I also support the use of alternative transmission technologies to unlock every megawatt 
of existing capacity from our current transmission system.  We have the technology.  We 
should use it now to enable faster interconnection of large loads, lower costs to 
customers, and help prevent cost shifting. 
 
To that end, and in light of our action in today’s orders, I also ask the state public 
utility commissions—whether they have already approved large load retail tariffs, are in 
the process of crafting large load retail tariffs, or have yet to embark on this essential 
tariff design process—to take a hard look and ensure their large load retail tariff 
provisions insulate ratepayers from the negative impacts of data center growth.  
Additionally, I expect CAISO and/or the Participating Transmission Owners to design 
proposals in response to this show cause order that dovetail with the efforts on the retail 
side to implement the Ratepayer Protection Pledge, protect customers, and ensure that 
large loads cover the costs they incur to integrate with the grid.   
 
The stakes here could not be higher and every gambler knows that the secret to 
surviving is knowing what to throw away and knowing what to keep.2  Today’s orders do 
exactly that—adopting thoughtful proposals that position our nation for success, driving 
meaningful change, and rejecting the gridlock, half-measures, and failure to plan that 
have gone on for far too long.  The data center odyssey that we embarked upon first with 
PJM, then SPP, we now aggressively extend to all the RTO/ISO regions.3  Enabling the 
swift and efficient interconnection of large loads to the transmission system while 
maintaining affordability, reliability, commitment to open access, competitive principles 
and cooperative federalism, will only be achieved through consistent, coordinated action 
 
see also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy (Oct. 23, 2025) 
(Secretary’s Letter). 
2 Kenny Rogers, The Gambler (United Artists Records 1978). 
3 Interconnection of Large Loads to the Interstate Transmission System, 195 
FERC ¶ 61,045 at P 2 (2026) (Order Regarding Intent to Act) (citing PJM Co-Location 
Order, 193 FERC ¶ 61,217; SPP HILL Order, 194 FERC ¶ 61,031; Commonwealth 
Edison Co., 194 FERC ¶ 61,181 (2026); Tri-State Generation and Transmission Ass’n, 
193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025)).

Docket No. EL26-71-000 
- 3 - 
 
and persistence.  But without that first step,4 there is no direction, no forward momentum, 
no journey, and no way to arrive at our future destination.  In the show cause orders we 
issue today, the Commission takes a series of long strides towards our ultimate large load 
interconnection destination:  we make preliminary findings that the RTO/ISO tariffs, 
including CAISO’s and/or the TO Tariff(s), may be unjust and unreasonable and/or 
unduly discriminatory or preferential because they lack features necessary to timely, 
reliably, and safely interconnect and serve new large loads in a way that produces just 
and reasonable rates. 
 
I commend each commentor for their robust and ongoing responses to the 
concerns that Secretary Wright and the Commission raised in the ANOPR proceeding.  
The comments helped us identify the common issues, common solutions, and individual 
differences among the RTOs/ISOs.  We heard a plea for broad flexibility and regionally 
tailored solutions.  And we will strive to work towards those solutions, not through top-
down, one-size-fits-all mandates, but through consideration of region-specific proposals.  
And we endeavor to support an appeal for federal policies that build upon rather than 
disrupt current and planned developments, reflecting state and local processes and 
stakeholder efforts.  Through these individually tailored and region-specific show cause 
orders, we are delivering to ensure that our transmission system can accommodate new 
large loads in a timely, safe, and reliable manner.  And, importantly, in a manner that 
ensures benefits and protection for all customers.  Affordability remains a top concern as 
we proceed forward.   
 
The collective voices in the ANOPR comments have shaped our decision to issue 
six separate individually tailored and region-specific show cause orders, rather than a 
proposed final rule at this time.  But the success of the next phase of this journey rests 
with you, CAISO, and/or your Participating Transmission Owners, and your 
stakeholders.  We are directing you to expeditiously bring forward for our consideration 
your novel, region-specific solution(s).  Time is of the essence.  By inviting you to 
proceed under FPA section 205, we are giving you significant perks:  the benefits of first 
wielder of the pen and the relatively capacious standard under FPA section 205 that 
allows us to accept a potentially broad range of proposals provided they are shown to be 
just and reasonable and not unduly discriminatory or preferential.5  We are even giving 
 
4 Admittedly, we are further down the road in some regions as compared with 
others. 
5 See, e.g., NRG Power Mktg, LLC v. FERC, 862 FERC 108, 105 (D.C. Cir. 2017) 
(FERC may not employ a rate design that follows “a completely different strategy” than, 
or is “methodologically distinct” from, a proposed rate) (internal quotations omitted); 
Oxy USA, Inc. v. FERC, 64 F.3d 679, 692 (D.C. Cir. 1995) (stating that a proposal under 
FPA section 205 “need not be the only reasonable methodology, or even the most 
accurate”); City of Winnfield v. FERC, 744 F.2d 871, at 874-875 (D.C. Cir. 1984)

Docket No. EL26-71-000 
- 4 - 
 
you flexibility to propose the implementation date for your innovative proposals.  But 
such freedom comes with great and concomitant responsibility.   
 
This is not a time to be cavalier and dodge the urgent need to meet the moment.  
While this is a long journey, even so, we must continue to move at breakneck pace to win  
the AI race.  So let me be direct.  If you choose not to submit timely, reasonable, non-
discriminatory or preferential, comprehensive, and substantiated proposal(s), as directed 
and as required under our applicable statutes, your deficient response will not go 
unnoticed.  I am prepared to play jurisdictional hardball, if needed.6  This Commission 
has appropriately exercised considerable restraint in asserting the full scope of our 
jurisdiction in these orders.  However, the Commission has very broad jurisdiction over 
transmission that we will not hesitate to utilize as necessary to ensure that we meet our 
objectives in all show cause proceedings, including this CAISO and/or the Participating 
Transmission Owners proceeding we initiate here.  If we find your Tariff is in fact unjust 
and unreasonable and unduly discriminatory or preferential, any failure on your end to 
provide a sufficient FPA filing or filings to address the large-load-related concerns that 
we have identified will result in the Commission dictating the solutions for you.  I say 
this not as a threat, but as a statement of duty.  While you may not like our remedies—I 
have often said that the federal government generally does not come up with the best 
solutions—this is an outcome we are prepared to pursue given the gravity of the moment 
and our statutory obligation.  Notwithstanding our readiness to step in, it greatly benefits 
everyone for you to come up with an approach tailored to your region.  
 
I will end my concurrence where I began:  We have heard your concerns, and, let 
me underscore, now is the time for you to heed ours.  This is an extraordinarily 
consequential proceeding.  The stakes for reliability, for affordability, and for the 
American ratepayer could not be higher.  We owe it to the public to get this right.  I look 
forward to reviewing and acting as expeditiously as possible on your responses to this 
show cause order, which I expect will include an FPA section 205 proposal or proposals. 
 
For these reasons, I respectfully concur. 
 
(comparing the respective authorities of the Commission and public utilities under 
sections 205 and 206). 
 
6  16 U.S.C. § 824(b); New York v. FERC, 535 U.S. 17 (2002) (“There is no 
language in the statute limiting FERC’s transmission jurisdiction to the wholesale 
market[.]”)) (emphasis in original); id. at 20 (stating that “the FPA authorizes FERC's 
jurisdiction over interstate transmissions, without regard to whether the transmissions are 
sold to a reseller or directly to a consumer[.]”).

Docket No. EL26-71-000 
- 5 - 
 
 
 
______________________________ 
David LaCerte 
Commissioner