EL26-68-000 · 2026-06-18 · FERC

SPP show cause order

195 FERC ¶ 61,213 
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. 
 
Southwest Power Pool, Inc. 
AEP Oklahoma Transmission Company, Inc. 
AEP Southwestern Transmission Company, Inc. 
Deseret Generation & Transmission Co-operative, Inc. 
Empire District Electric Company 
Evergy Kansas Central, Inc. 
Evergy Kansas South, Inc. 
Evergy Metro, Inc. 
Evergy Missouri West, Inc. 
GridLiance High Plains LLC 
ITC Great Plains, LLC 
Mountrail-Williams Electric Cooperative 
NextEra Energy Transmission Southwest, LLC 
NorthWestern Energy Public Service Corporation 
Oklahoma Gas and Electric Company 
Prairie Wind Transmission, LLC 
Public Service Company of Oklahoma 
Southwestern Electric Power Company 
Southwestern Public Service Company 
Transource Missouri, LLC 
Transource Oklahoma, LLC 
Tri-State Generation and Transmission Association, Inc. 
Upper Missouri G. & T. Electric Cooperative, Inc. 
Docket No. EL26-68-000 
 
 
ORDER INSTITUTING PROCEEDING  
 
UNDER SECTION 206 OF THE FEDERAL POWER ACT 
 
(Issued June 18, 2026)

Docket No. EL26-68-000 
- 2 - 
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 Processes .............................................................................................. 15. 
3. SPP Conditional High Impact Large Load Service ............................................. 17. 
II. SPP’s Existing Processes ............................................................................................. 19. 
A. Existing Tariff Processes ......................................................................................... 19. 
B. Recent Stakeholder Proceedings in SPP ................................................................. 27. 
III. Discussion ................................................................................................................... 29. 
A. Transmission Service to Eligible Customers on Behalf of Large Loads ................ 35. 
1. Jurisdiction ........................................................................................................... 37. 
2. Tariff Provisions .................................................................................................. 43. 
B. Cost Shifting Risk Among Transmission Customers .............................................. 47. 
1. Jurisdiction ........................................................................................................... 49. 
2. Additional Cost Transparency ............................................................................. 52. 
3. Cost Recovery Agreements ................................................................................. 59. 
C. Co-Location Arrangements and Load with Behind the Meter Generation ............. 67. 
1. Definition ............................................................................................................. 69. 
2. Jurisdiction ........................................................................................................... 73. 
3. Tariff Provisions .................................................................................................. 75. 
D. Extending New Transmission Services to Eligible Customers Taking Service on 
Behalf of Flexible Large Loads ................................................................................... 85. 
E. Informational Report ............................................................................................... 89. 
IV. Briefing Questions ...................................................................................................... 92. 
 
 
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  
 
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).

Docket No. EL26-68-000 
- 3 - 
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 
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 
 
2 For the purposes of this order, we adopt SPP’s definition of high impact large 
load (HILL) for large load.  See infra note 54. 
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 69. 
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. 
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. EL26-68-000.

Docket No. EL26-68-000 
- 4 - 
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.8 
 
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, we directed PJM Interconnection, L.L.C. (PJM) to 
take steps to address the challenges of integrating co-located loads onto the transmission 
system while ensuring that its tariff remains just and reasonable.9  We recognize and 
applaud Southwest Power Pool, Inc. (SPP) for taking critical steps to address the addition 
of large and co-located loads to its transmission system.10  SPP has already enhanced its 
study process for requests from Eligible Customers11 for transmission service to serve 
 
7 As discussed below, under HILLGA, the generating facility and the HILL to be 
served must be located no more than two substations apart.  See infra P 15. 
8 We note that SPP’s Tariff does not have a formal definition of “co-located load” 
or “co-location arrangement.”  As discussed below, for the purposes of HILLGA, the 
generating facility only must be in close electrical proximity.  However, HILLs and the 
generating facility could be co-located.  SPP TOs November 21 ANOPR Comments at 5. 
9 PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order,           
193 FERC ¶ 61,217. 
10 SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC ¶ 
61,196. 
11 SPP defines Eligible Customer, in relevant part, as  
Any electric utility (including the Transmission Owner(s) and 
any power marketer), Federal Power Marketing Agency, or 
any person generating electric energy for sale for resale… 
(ii) Any retail customer or eligible person taking unbundled 
transmission service pursuant to a state requirement that a 
Transmission Owner offer the transmission service, or 
pursuant to a voluntary offer of such service by a 
Transmission Owner, is an Eligible Customer under the 
Tariff.”   
SPP Open Access Transmission Tariff, Sixth Revised Vol. No. 1, pt. I, § 1 (Definitions E) 
(6.1.0) (SPP Tariff).

Docket No. EL26-68-000 
- 5 - 
large loads.  So too has SPP provided a new transmission service that recognizes that 
large loads, including co-located large loads, are flexible and willing to limit withdrawals 
from the transmission system.  We commend SPP’s leadership on these issues and 
appreciate the bold and proactive steps that SPP has taken to address the influx of large 
loads, including co-located large loads.  Given SPP’s enhanced study processes and new 
transmission service for Eligible Customers taking transmission service on behalf of large 
loads, we expect that SPP will be able to demonstrate that it has resolved several of the 
concerns that the Commission has about a lack of clarity and consistency in other 
regions’ tariffs.  That said, SPP has not yet proposed tariff revisions to address all of the 
challenges associated with the integration of large and co-located loads.  
 
As discussed below, we find that SPP’s existing Open Access Transmission Tariff 
(Tariff) appears 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),12 and we direct SPP and the Transmission Owners,13 within 60 days of the date of 
this order, to either:   
 
12 16 U.S.C. § 824e. 
13 Transmission Owners refers to the entities listed in the caption of this order.      
We recognize that SPP’s 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); Sw. Power Pool, Inc., 180 FERC ¶ 61,022, at PP 44-45 
(2022).  Accordingly, the Commission has not included Arkansas Electric Cooperative 
Corporation; Basin Electric Power Cooperative; Central Nebraska Public Power and 
Irrigation District; Central Power Electric Cooperative, Inc.; City of Coffeyville, Kansas; 
City of Independence, Missouri; City Utilities of Springfield, Missouri; Colorado Springs 
Utilities; Corn Belt Power Cooperative; East River Electric Power Cooperative, Inc.;     
East Texas Electric Cooperative, Inc.; Farmington Electric Utility System; Grand River 
Dam Authority; Harlan Municipal Utilities; Heartland Consumers Power District;     
Kansas City Board of Public Utilities; Kansas Power Pool; L and O Power Cooperative; 
Lea County Electric Cooperative, Inc.; Lincoln Electric System; Midwest Energy, Inc.; 
Missouri Joint Municipal Electric Utility Commission; Missouri River Energy Services; 
Mor-Gran-Sou Electric Cooperative, Inc.; Nebraska Public Power District; and Northwest 
Iowa Power Cooperative; Oklahoma Municipal Power Authority; Omaha Public Power 
District; People’s Electric Cooperative; Platte River Power Authority; Roughrider Electric 
Cooperative, Inc.; Southwestern Power Administration; Sunflower Electric Power 
Corporation; Western Area Power Administration-Upper Great Plains Region; Western 
Area Power Administration-Colorado River Storage Project Management Center; Western 
Area Power Administration-Rocky Mountain Region; and Western Farmers Electric 
Cooperative here as Transmission Owners that must respond to this order to show cause.  
Nonetheless, the Commission retains the authority to review each entity’s formula rates as

Docket No. EL26-68-000 
- 6 - 
(1) show cause as to why the Tariff remains just and reasonable and not unduly 
discriminatory or preferential without provisions that:   
(a) require the evaluation of alternative transmission technologies,14 and 
memorialize ongoing operational requirements in a transmission service 
agreement between SPP and the transmission customer taking transmission 
service on behalf of a large load;  
(b) address additional transparency concerning the Network Upgrade15 
costs to provide transmission service to Eligible Customers on behalf of 
large loads, establish a pro forma cost recovery agreement between SPP, 
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 establish 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) address the rates, terms, and conditions of service that apply to           
co-location arrangements; and 
(d) address 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;16 or  
 
a component of SPP’s Tariff in an order to show cause directed towards SPP, and SPP 
must respond to this order regarding the non-public utilities’ SPP Tariff provisions on file 
with the Commission.  See Sw. Power Pool, Inc., 180 FERC ¶ 61,022 at P 40. 
14 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 (GETs). 
15 Capitalized terms not otherwise defined herein have the meanings ascribed to 
them in the Tariff. 
16 As explained below, for purpose of this order, “flexible” large loads are a subset 
of HILLs that are not co-located with generation, but are willing and able to limit their

Docket No. EL26-68-000 
- 7 - 
(2) explain what changes to the Tariff 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.   
 
We are also concerned with SPP’s need to ensure adequate generation to serve 
new large loads.17  We therefore direct SPP to submit, within 30 days of the date of 
issuance of this order, an informational report on how SPP 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 SPP and/or the 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. 
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  
 
energy withdrawals from the transmission system under certain conditions.  See infra 
note 163. 
17 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).

Docket No. EL26-68-000 
- 8 - 
growth of large loads.18  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.19  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.20 
 
On April 16, 2026, the Commission issued an order regarding its intent to act with 
respect to the ANOPR docket.21  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 
non-discriminatory manner.’”22  After recognizing the Commission’s recent actions in 
proceedings involving issues associated with large loads,23 the Commission concluded 
 
18 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). 
19 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%20Term%20Reliability%20Assessment_2024.pdf). 
20 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. 
21 Interconnection of Large Loads to the Interstate Transmission Sys., 195 FERC ¶ 
61,045 (2026) (Order Regarding Intent to Act). 
22 Id. P 2. 
23 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 (2025)).

Docket No. EL26-68-000 
- 9 - 
that it was clear that additional “action is warranted to support further progress where it is 
needed.”24 
 
In response to the ANOPR, SPP states that it is facing significant operational, 
planning, and market challenges in response to unprecedented growth in large and non-
traditional load interconnection requests.25  SPP has elsewhere explained that large loads 
interconnected to the transmission system can stress both real-time operational reliability 
and resource adequacy planning, particularly in areas with constrained transmission 
capacity.26  SPP also acknowledges that the scale and speed with which large loads seek 
to interconnect to the transmission system, and the operational inflexibility of these loads, 
strain existing transmission planning processes, real-time operational tools, and market 
mechanisms originally designed for gradual and geographically distributed load growth.27  
A number of large load projects are underway in the SPP footprint.28  SPP has previously 
noted that large load interconnection request submissions peaked in SPP in 2022 at nearly 
11 GW, but have since dropped to approximately 6 GW in 2024; according to SPP, this 
trend could be due in part to SPP’s inability to study and interconnect large loads quickly 
enough to meet their commercial needs.29  As explained in detail below, SPP has taken 
steps to address these challenges in a number of recent proceedings.30    
 
While some commenters in the ANOPR proceeding assert that SPP’s existing 
processes and recent efforts are sufficient to address the challenges presented by large 
 
24 Id. PP 3-4. 
25 SPP November 21 ANOPR Comments at 2. 
26 See, e.g., Sw. Power Pool, Inc., Docket No. ER26-1323-000, Transmittal at 2 
(filed Feb. 10, 2026) (SPP CHILLS Transmittal).  
27 Id. 
28 EEI March 12 ANOPR Comments, attach. 1, at 1-8 (listing publicly announced 
large load projects, including in the SPP footprint). 
29 Sw. Power Pool, Inc., Docket No. ER26-247-000, Transmittal at 8-9, figs. 2, 3 
(filed Oct. 24, 2025) (SPP HILL Transmittal). 
30 See infra PP 15-18.

Docket No. EL26-68-000 
- 10 - 
and co-located loads,31 other entities in the SPP footprint support additional reforms.32  In 
particular, many entities seek additional transparency from SPP and believe that further 
action is needed to protect ratepayers from cost shifts caused by large and co-located 
loads.33  Others stakeholders argue the Commission should provide mechanisms for 
additional load flexibility.34  The Missouri Commission also supports efficient and 
comprehensive study procedures for co-location arrangements.35  Antora asserts that SPP 
should offer a permanent non-firm transmission service option.36  
 
Moreover, many commenters in the ANOPR proceeding filed persuasive 
comments documenting, generally, the need for clear and consistent tariff provisions to 
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.37  
 
31 See, e.g., Arkansas Commission November 21 ANOPR Comments at 2-3;  
North Dakota Commission November 21 ANOPR Comments at 5; Louisiana and 
Mississippi Commissions November 21 ANOPR Comments at 6; Nebraska Board 
November 21 ANOPR Comments at 1-2; South Dakota Commission November 21 
ANOPR Comments at 5; SPP TOs April 6 ANOPR Comments at 2. 
32 Kansas Commission November 21 ANOPR Comments at 11-12; Missouri 
Commission November 21 ANOPR Comments at 14; Oklahoma State Entities November 21 
ANOPR Comments at 3, 9; State Entities November 21 ANOPR Comments at 7-8. 
33 Kansas Commission November 21 ANOPR Comments at 12; Missouri 
Commission November 21 ANOPR Comments at 14; Oklahoma State Entities November 21 
ANOPR Comments at 3; State Entities November 21 ANOPR Comments at 7-8. 
34 Oklahoma State Entities November 21 ANOPR Comments at 9; State Entities 
November 21 ANOPR Comments at 8. 
35 Missouri Commission November 21 ANOPR Comments at 14. 
36 Antora May 18 ANOPR Comments at 6-7. 
37 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.

Docket No. EL26-68-000 
- 11 - 
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.38  In addition, many ANOPR 
commenters highlighted the need to efficiently integrate large loads, particularly data 
centers, to support national security priorities and economic development.39   
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 20540 filings, the growing use of co-location 
arrangements.41  The Commission’s orders in those proceedings have addressed the need 
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 
 
38 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 at 12; NCSL November 21 ANOPR Comments at 1; 
NRECA November 21 ANOPR Comments at 8-9; NY UIU November 21 ANOPR 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. 
39 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. 
40 16 U.S.C. § 824d. 
41 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 ¶ 
61,209 (2026); SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC ¶ 
61,196.

Docket No. EL26-68-000 
- 12 - 
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, and in 
recognition of SPP’s recent reforms to implement a new process for studying requests  
for Eligible Customers taking transmission service on behalf of large loads and a new 
conditional, non-firm transmission service for Eligible Customers taking transmission 
service on behalf of large loads, that the Commission now considers whether SPP’s Tariff 
remains just and reasonable. 
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.42  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.43  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 co-located load and Eligible Customers taking transmission service on 
behalf of co-located load.44   
 
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.45  
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 
 
42 See PJM Show Cause Order, 190 FERC ¶ 61,115. 
43 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.   
44 PJM Co-Location Order, 193 FERC ¶ 61,217. 
45 Id. P 176.

Docket No. EL26-68-000 
- 13 - 
withdrawals from the transmission system under certain conditions.46  Additionally,        
the Commission found that PJM’s behind the meter generation rules were no longer just 
and reasonable.47  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;48 (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;49 (3) to revise the behind the meter generation rules and implement a 
transition process for existing behind the meter generation participants;50 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.51   
 
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).52 
 
46 Id. P 177. 
47 Id. P 179. 
48 Id. PP 187-192, 225-230. 
49 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 219-20. 
50 Id. PP 221-224.  
51 Id. PP 161, 231-236. 
52 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).

Docket No. EL26-68-000 
- 14 - 
2. 
SPP High Impact Large Load and High Impact Large Load 
Generation Assessment Processes  
 
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.53  SPP’s Tariff revisions established HILLs as a new 
category of load;54 imposed enhanced study requirements to enable SPP to assess the 
HILL’s reliability impacts on the transmission system;55 and created additional, ongoing 
operational requirements for transmission customers serving HILLs to ensure continued 
reliability of the transmission system.56  The Tariff revisions also established the 
 
53 SPP HILL Order, 194 FERC ¶ 61,031 at PP 61, 64.   
54 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 Tariff, pt. I, § 1 (Definitions H) (1.0.0). 
55 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 
connection study, and potential supplemental Electromagnetic Transient study). 
56 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).

Docket No. EL26-68-000 
- 15 - 
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.57 
 
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.”58  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.59  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 
point of interconnection.60  In addition, the Commission found that the proposed study 
deposits would discourage speculative HILL study requests.61  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.62  In 
accepting HILLGA, the Commission found that “SPP’s HILLGA process reasonably 
 
57 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).  
58 Id. P 60. 
59 Id. P 61. 
60 Id. P 62. 
61 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. 
62 Id. P 63.

Docket No. EL26-68-000 
- 16 - 
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.”63   
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).64  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.65  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.66  
CHILLS has a maximum term of seven years, which is intended to incentivize 
transmission customers seeking CHILLS to obtain the designated resources and/or 
complete the network upgrades needed to procure long-term firm transmission service 
through existing Tariff processes.67   
 
The Commission found that SPP had shown that unprecedented growth in       
large loads presents significant and unique operational and planning challenges.68  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.69  The Commission concluded that CHILLS is a just and reasonable and not 
unduly discriminatory or preferential approach to addressing the need to expeditiously 
 
63 Id. P 64. 
64 SPP CHILLS Order, 195 FERC ¶ 61,196 at P 1. 
65 Id. P 7.  
66 Id. PP 9-10. 
67 Id. P 9. 
68 Id. P 84. 
69 Id.

Docket No. EL26-68-000 
- 17 - 
interconnect and provide transmission service to new HILLs, while maintaining the 
reliable operation of SPP’s transmission system.70 
II. 
SPP’s Existing Processes 
A. 
Existing Tariff Processes 
 
SPP evaluates new Long-Term Firm Point-to-Point Transmission Service and new 
NITS requests by Eligible Customers through Attachment Z1 (Aggregate Transmission 
Service Study Procedures and Cost Allocation and Recovery for Service Upgrades),71  
and existing transmission customers’ requests to add or modify delivery point facilities 
associated with load additions under Attachments AQ (Delivery Point Assessment 
Process) and AX (Provisional Load Process) of SPP’s Tariff.72  SPP studies the impacts 
of requested delivery point additions or modifications on the transmission system and 
determines what, if any, Network Upgrades are required to accommodate the requests.73  
Network Upgrades identified in the Attachment AQ process are Base Plan Funded, 
meaning that the costs of these Network Upgrades are allocated through rolled-in rates 
among all SPP transmission customers pursuant to the criteria in Attachment J of the 
Tariff.74   
 
70 Id. 
71 SPP Tariff, attach. Z1 (Aggregate Transmission Service Study) (0.0.0). 
72 Id. attach. AQ (Delivery Point Assessment Process) (1.0.0); id. attach. AX 
(Provisional Load Process) (0.0.0). 
73 A transmission customer can use a combination of the Attachment AQ and 
Attachment AX processes if it has neither sufficient designated resources nor planned 
generation to serve both its existing load and a new HILL.  Id. attach. BA (High Impact 
Large Load (0.0.0), § 2.1.2 (0.1.0). 
74 SPP Tariff, attach. J (Recovery of Costs Associated with New Facilities), § III.A 
(21.0.0); Sw. Power Pool, Inc., 193 FERC ¶ 61,244 (2025).  Specifically, using SPP’s 
Highway/Byway cost allocation method, SPP allocates the costs of Base Plan Upgrades 
to transmission customers in individual SPP pricing zones, subregions, the entire SPP 
region, or a combination thereof, based on the voltage level and location of the specific 
facility.  Specifically, SPP allocates costs for transmission facilities as follows:  (1) for 
facilities at 300 kV or above (Highway facilities), 100% of the costs are allocated on a 
regional, postage stamp basis based on load ratio share; (2) for facilities above 100 kV 
and below 300 kV (Byway facilities), SPP allocates 33% of the costs on a regional, 
postage stamp basis and 67% of the costs to the subregion in which the facilities are

Docket No. EL26-68-000 
- 18 - 
 
Attachment AX of SPP’s Tariff includes a Provisional Load Process to allow 
transmission customers to request studies of new load interconnection requests when 
transmission customers do not have sufficient Designated Resources to serve their load, 
provided that the transmission customer has planned generation to serve the load additions.75  
Network Upgrades identified in the Provisional Load Process will be directly assigned to   
the transmission customer until the transmission customer’s transmission service agreement 
includes a generating facility designated to serve the load, at which point the remaining cost 
of the Network Upgrades will be Base Plan Funded.76 
 
As described above, SPP’s Tariff has been amended to address the integration of 
large loads through the HILL study process, which includes enhanced study requirements 
beyond what is required under the Attachments AQ and AX processes.77  SPP also 
established a HILLGA process that allows for expedited review of generating facilities 
that are designated to serve a HILL and interconnected in the same local area as the HILL 
(i.e., within a certain number of substations and transmission line segments from the 
HILL).78  As SPP TOs explain, the HILL and HILLGA processes will treat large loads 
and any co-located generation79 as distinct for tariff and metering purposes, assess 
transmission service based on the large load’s gross withdrawals, and ensure that the 
transmission system is planned and paid for to meet a large load’s full reliability needs.80 
 
Neither the HILL nor HILLGA process will result in transmission service for a 
new generating facility to the HILL.  Eligible Customers (including Eligible Customers 
 
located; and (3) for facilities at 100 kV or below, SPP allocates all costs to the zone 
where the facilities are located. 
75 See Sw. Power Pool Inc., 193 FERC ¶ 61,018 (2025); see also SPP Tariff, 
attach. AX. 
76 SPP Tariff, attach. J, § V(F) (6.0.0). 
77 See supra PP 15-16.  SPP TOs explain that under the HILL proposal, the load 
and generating facility may be located at the same point of interconnection.  SPP TOs 
November 21 ANOPR Comments at 5. 
78 See SPP HILL Order, 194 FERC ¶ 61,031 at PP 26, 64-66; see also SPP Tariff, 
attach. BB (High Impact Large Load Generation Assessment) (0.0.0), § 3.1.3(5)(a).   
79 We reiterate that SPP’s Tariff does not have a formal definition of “co-located 
load” or “co-location arrangement.”  As noted, for the purposes of HILLGA, the 
generating facility only must be in close electrical proximity.   
80 SPP TOs November 21 ANOPR Comments at 7.

Docket No. EL26-68-000 
- 19 - 
that are also HILLGA interconnection customers) must request transmission service, 
which may be short-term or long-term Firm Point-to-Point Transmission Service,      
Non-Firm Point-to-Point Transmission Service, or NITS.81  Additionally, as discussed 
above, the Commission recently accepted SPP’s CHILLS, a new conditional, non-firm 
transmission service option for Eligible Customers taking transmission service on behalf 
of large loads, including co-located large loads, that may be taken for up to seven years 
until the Eligible Customer obtains sufficient Designated Resources to support NITS or 
Firm Point-to-Point Transmission Service or the required Network Upgrades for NITS or 
Point-to-Point Transmission Service are completed.82   
 
For long-term Firm Point-to-Point Transmission Service requests or requests for 
new NITS, SPP conducts an Aggregate Transmission Service Study under Attachment Z1 
of the Tariff to determine any necessary transmission facility additions, expansions, or 
upgrades the relevant transmission customer seeking transmission service is responsible 
for funding to ensure that the transmission system and transmission service to existing 
customers is not degraded or impaired.83    
 
Network Upgrades identified through the Attachment AQ, AX,84 and Z1 processes 
are evaluated in SPP’s transmission planning process and included in SPP’s Transmission 
Expansion Plan.85  SPP explains that as it relates to the cost responsibility of Network 
Upgrades, section 7.2 of the SPP Bylaws delegate primary responsibility for determining 
regional proposals for cost allocation to the SPP Regional State Committee.86   
 
81 See SPP Tariff, pt. II, §§ 17.1 (Application) (1.0.0), 18.1 (Application) (0.0.0); 
id. pt. III, § 29.1 (Condition Precedent for Receiving Service) (0.0.0). 
82 SPP CHILLS Order, 195 FERC ¶ 61,196 at PP 7, 9; see SPP Tariff, pt. VII 
(Conditional High Impact Large Load Transmission Service) (0.0.0); id. schedule 15 
(Conditional High Impact Large Load Service) (0.0.0). 
83 SPP Tariff, attach. Z1, § 1 (Introduction) (1.0.0).  
84 Specifically, Network Upgrades are included in SPP’s Transmission Expansion 
Plan once the loads seeking Provisional Load Services in Attachment AX have a 
generating facility designated to serve the load. 
85 See SPP Tariff, attach. O, §§ III (The Integrated Transmission Planning 
Assessment) (14.0.0), II.5.b (Roles and Responsibilities), V (The SPP Transmission 
Expansion Plan Report) (10.0.0), V.3.c. 
86 SPP November 21 ANOPR Comments at 15.

Docket No. EL26-68-000 
- 20 - 
 
SPP processes generator interconnection requests under Attachment V (Generator 
Interconnection Procedures (GIP)) of its Tariff.87  SPP’s generator interconnection study 
process, the Definitive Interconnection System Impact Study (DISIS), is divided into a 
two-phased system impact study in DISIS Phase One and DISIS Phase Two, which is 
followed by an interconnection facilities study.88  The system impact study is a cluster 
study that evaluates the impact of each proposed interconnection request on the reliability 
of SPP’s transmission system.  DISIS Phase One involves a cluster study consisting of a 
steady-state powerflow analysis and calculation of the short-circuit ratio.  DISIS Phase 
Two involves a cluster study consisting of a short circuit analysis, stability analysis, short 
circuit ratio critical clearing time screening, and steady state powerflow analysis.   
 
Pursuant to the Tariff, an interconnection customer may request, and SPP         
may provide, interim interconnection service prior to the completion of requisite 
Interconnection Facilities, Network Upgrades, Distribution Upgrades, or System 
Protection Facilities.89  The scope of the interim availability interconnection system 
impact study maintains the scope and procedures of the DISIS with the exception that 
certain previous queued interconnection requests may not be included in the interim 
availability interconnection system impact study.90  Under the Tariff, an interconnection 
customer may also request surplus interconnection service for an unneeded portion         
of interconnection service capacity at an existing point of interconnection substation.91  
The surplus interconnection service impact study consists of reactive power, short 
circuit/fault duty, stability analyses, and any other appropriate studies, and steady-state 
(thermal/voltage) analyses may be performed by SPP as necessary to ensure that all 
required reliability conditions are studied.   
B. 
Recent Stakeholder Proceedings in SPP 
 
SPP is also developing another transmission service, known as Price Adaptive 
Load Service (PALS), to provide transmission service that will enable the connection of 
 
87 SPP Tariff, attach. V (Generator Interconnection Procedures (GIP)) (12.0.0). 
88 Id. § 8 (28.0.0), §§ 8.4 (Scope of Definitive Interconnection System Impact 
Study and Priority System Impact Stud, 8.10 (Scope of Interconnection Facilities Study), 
8.11 (Interconnection Facilities Study Procedures).   
89 Id. § 11 (Generator Interconnection Agreement) (9.0.0), § 11.A (Interim 
Generator Interconnection Agreement (Interim GIA)). 
90 Id. § 11 (Generator Interconnection Agreement) (9.0.0), § 11A.2.4.1. 
91 Id. § 3.3 (Utilization of Surplus Interconnection Service) (30.0.0).

Docket No. EL26-68-000 
- 21 - 
new loads.92  SPP states that PALS is a flexible, non-firm transmission service option that 
will allow loads that are price sensitive and flexible (i.e., do not need to be served from 
the transmission system on a firm basis) to vary their participation based on the price of 
energy.   
 
We are encouraged by SPP’s stakeholder efforts, and the proactive steps that SPP 
has already taken to enhance its study processes and develop a new transmission service.  
However, we conclude that this FPA section 206 proceeding is necessary to generate 
additional reforms in SPP 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 SPP promptly proposes revisions to ensure that its Tariff remains 
just and reasonable. 
III. 
Discussion 
 
Based on the discussion below, pursuant section 206 of the FPA, we direct SPP 
and the Transmission Owners, within 60 days of the date of this order, to either: 
(1) show cause as to why the Tariff remains just and reasonable and not unduly 
discriminatory or preferential without provisions that:   
(a) require the evaluation of alternative transmission technologies, and 
memorialize ongoing operational requirements in a transmission service 
agreement between SPP and the transmission customer taking transmission 
service on behalf of a large load;  
(b) address additional transparency concerning the Network Upgrade costs 
to provide transmission service to Eligible Customers on behalf of large 
loads, establish a pro forma cost recovery agreement between SPP, 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 establish 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) address the rates, terms, and conditions of service that apply to           
co-location arrangements; and 
 
92 SPP November 21 ANOPR Comments at 6-7.

Docket No. EL26-68-000 
- 22 - 
(d) address 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; or  
(2) explain what changes to the Tariff 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.   
 
We also direct SPP to submit, within 30 days of the date of issuance of this order, 
an informational report on how SPP intends to ensure that adequate generation will be 
available to serve existing and new large loads.   
 
Interested entities may respond within 30 days of SPP’s and the Transmission 
Owners’ filings, addressing either or both of:  (1) whether the existing Tariff remains just 
and reasonable and not unduly discriminatory or preferential; and (2) if not, what changes 
to the Tariff should be implemented as replacement rates.   
 
We recognize that SPP and/or the Transmission Owners (to the extent the matters 
addressed herein implicate aspects of the Tariff over which they have the filing rights) 
may elect to address some or all of the issues discussed in this order by proposing 
revisions to the Tariff 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,93 
no such filings were received from SPP by the Commission prior to the issuance of      
this order.  Should SPP and/or the 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 SPP and/or the 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 SPP and/or the 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 SPP and 
the Transmission Owners time while they work through the stakeholder processes to 
develop FPA section 205 filings to revise the Tariff to address the issues raised in this 
 
93 See ANOPR at P 32; Order Regarding Intent to Act, 195 FERC ¶ 61,045 at P 5.

Docket No. EL26-68-000 
- 23 - 
order.  Requests for a full or partial abeyance94 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 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.95  That date is the date of publication of notice of initiation of this proceeding in 
the Federal Register. 
A. 
Transmission Service to Eligible Customers on Behalf of Large Loads 
 
As noted above, the Commission recently approved revisions to SPP’s Tariff that 
established an enhanced process for SPP to study the provision of transmission service to 
Eligible Customers on behalf of HILLs and help to ensure that integration of HILLs onto 
the transmission system does not impair reliability.  In that order, the Commission found 
that the HILL process was a just and reasonable approach for integrating transmission 
customers’ new large loads onto SPP’s transmission system in a reliable manner.96  
However, we preliminarily find that SPP’s Tariff appears to be unjust and unreasonable 
because it lacks (1) clear and consistent provisions requiring the evaluation of alternative 
transmission technologies, and (2) pro forma provisions in a transmission service 
agreement between SPP and the transmission customer taking transmission service on 
behalf of the HILL to memorialize ongoing operational requirements in the Tariff.   
 
94 A partial abeyance may be appropriate to the extent SPP is 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.  
95 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). 
96 SPP HILL Order, 194 FERC ¶ 61,031 at P 61.

Docket No. EL26-68-000 
- 24 - 
 
We direct SPP and the Transmission Owners, to the extent the matters addressed 
herein implicate aspects of the Tariff over which they have the filing rights, to explain 
whether the Tariff remains just and reasonable without provisions requiring the 
evaluation of alternative transmission technologies and pro forma provisions in a 
transmission service agreement memorializing ongoing operational requirements in a 
transmission service agreement between SPP and the transmission customer, or propose 
Tariff revisions to address these concerns. 
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.97   
 
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.98 
 
97 See generally NARUC April 14 ANOPR Comments (highlighting action taken 
by state public utility commissions related to large loads). 
98 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 SPP Tariff, pt. I, § 1 (Definitions E) (6.1.0).

Docket No. EL26-68-000 
- 25 - 
 
The Commission is a creature of statute and has jurisdiction over only             
those matters that Congress has given it the authority to regulate.99  That authority 
includes jurisdiction over the wholesale sale and transmission of electricity in interstate 
commerce, including all facilities used for such sale and transmission.100  As relevant 
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.101  
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.102  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,103 including the 
interconnection of wholesale load to the transmission system.104  
 
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 
 
99 Atl. City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002). 
100 16 U.S.C. § 824(b)(1). 
101 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)).    
102 New York v. FERC, 535 U.S. 1, 17, 19-20 (2002) (upholding the Commission’s 
exercise of jurisdiction over unbundled retail transmission service). 
103 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). 
104 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).

Docket No. EL26-68-000 
- 26 - 
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.105  The Commission has exclusive authority to ensure that the process 
to study the 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.106  As such, we recognize that states will continue to 
regulate:  (1) the specific terms of retail sales to large load;107 (2) which entities may 
make retail sales within their borders, including which entities are legally permitted to 
provide electricity to retail large load customers;108 and (3) any siting decisions and 
construction associated with the large load project.109  Nothing in this order is intended to 
intrude upon state authority over retail service to large loads.   
 
105 Cf. Transmission Plan. & Cost Allocation by Transmission Owning & 
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.”). 
106 16 U.S.C. § 824(b)(1); see Dayton Power & Light Co. v. FERC, 126 F.4th 1107, 
1129 (6th Cir. 2025). 
107 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). 
108 PJM Show Cause Order, 190 FERC ¶ 61,115 at PP 68-69. 
109 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,

Docket No. EL26-68-000 
- 27 - 
 
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 or   
a public utility’s voluntary offer of such service, an end-use large load seeks unbundled 
retail transmission service, is just and reasonable and not unduly discriminatory or 
preferential.  Pursuant to that authority, we find that SPP’s Tariff appears to be unjust  
and unreasonable or unduly discriminatory or preferential because it lacks 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 
 
As explained above, the HILL process addresses how SPP and/or the 
Transmission Owners will study the provision of transmission service to Eligible 
Customers on behalf of large loads.  In accepting the HILL process, the Commission 
found that SPP’s study requirements would ensure the reliable integration of the 
transmission customer’s HILL onto SPP’s transmission system and would provide      
SPP with information about its impact on SPP’s transmission system, including the 
transmission system’s ability to withstand and control disturbances by the HILL at        
the point of interconnection.110  However, the HILL process lacks two components, 
provisions requiring the evaluation of alternative transmission technologies and            
pro forma provisions in a transmission service agreement memorializing ongoing 
operational requirements, without which we are concerned that SPP’s Tariff may be 
unjust and unreasonable, or unduly discriminatory or preferential. 
 
First, we preliminarily find that SPP’s Tariff appears to be unjust and unreasonable 
because it 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.  Alternative transmission 
technologies can add more capacity on existing transmission lines quickly, often within 
one to three years.111  Unlike with traditional load growth,112 large load customers often 
 
136 FERC ¶ 61,051 at P 107 (acknowledging state authority over siting, permitting, and 
construction of transmission facilities). 
110 SPP HILL Order, 194 FERC ¶ 61,031 at P 62. 
111 WATT and Advancing Modern Powerlines November 21 ANOPR Comments 
at 5-6. 
112 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at P 7 (explaining that the

Docket No. EL26-68-000 
- 28 - 
have development timelines requiring 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.113  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.114  Further, to 
 
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 
unlike more traditional loads [including] size, strong desire for faster interconnection, and 
potential flexibility.”). 
113 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). 
114 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,

Docket No. EL26-68-000 
- 29 - 
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 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. 
 
SPP should explain whether the Tariff remains just and reasonable without 
provisions that (1) require the evaluation of alternative transmission technologies in 
transmission service request studies, 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. 
 
Second, the HILL process does not include pro forma provisions in a    
transmission service agreement between SPP and the transmission customer taking 
transmission service on behalf of a HILL that memorialize ongoing operational 
requirements.  While these requirements are included in the Tariff, we are concerned  
that, without such pro forma provisions in a transmission service agreement between  
SPP and the transmission customer, SPP may be unable to enforce ongoing operational 
requirements for transmission customers taking transmission service on behalf of HILLs.  
We therefore preliminarily find that SPP’s Tariff appears to be unjust and unreasonable 
because it lacks pro forma provisions in a transmission service agreement between SPP 
and the transmission customer memorializing ongoing operational requirements for 
transmission customers taking transmission service on behalf of HILLs.  SPP should 
 
Order No. 1920-A, 189 FERC ¶ 61,126 (2024), order on reh’g, Order No. 1920-B,       
191 FERC ¶ 61,026 (2025).

Docket No. EL26-68-000 
- 30 - 
explain whether the Tariff remains just and reasonable without such pro forma provisions 
in a transmission service agreement, or propose revisions to include pro forma provisions 
memorializing the ongoing operational requirements in a transmission service agreement 
between SPP and the transmission customer. 
B. 
Cost Shifting Risk Among Transmission Customers 
 
We next preliminarily find that SPP’s Tariff appears to be unjust and  
unreasonable because it lacks 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 SPP, 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.  
 
We direct SPP and the Transmission Owners, to the extent the matters addressed 
herein implicate aspects of the Tariff over which they have the filing rights, to explain 
whether the Tariff remains just and reasonable without (1) robust, accurate, and 
systematic provision of data on SPP’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 SPP, 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 SPP 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

Docket No. EL26-68-000 
- 31 - 
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.115  While we appreciate and are similarly concerned about 
this issue, the Commission is limited to addressing jurisdictional transmission rates and 
as 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.116  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.117  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,118 as well as voluntary efforts by transmission owners to protect 
retail ratepayers through cost recovery agreements with large loads.119  We are also 
encouraged by the execution of the President’s Ratepayer Protection Pledge, through 
 
115 See, e.g., Kansas Commission November 21 ANOPR Comments at 12; 
Missouri Commission November 21 ANOPR Comments at 11; Nebraska Board 
November 21 ANOPR Comments at 3; Tri-State November 21 ANOPR Comments at 8. 
116 PJM Show Cause Order, 190 FERC ¶ 61,115 at P 167. 
117 Id. P 68. 
118 See, e.g., Kansas Commission November 21 ANOPR Comments at 9-10; 
Missouri Commission November 21 ANOPR Comments at 3-4; Oklahoma State Entities 
November 21 ANOPR Comments at 7-8. 
119 See, e.g., Commonwealth Edison Co. 194 FERC ¶ 61,106; Commonwealth 
Edison Co., 194 FERC ¶ 61,109; Commonwealth Edison Co., 194 FERC ¶ 61,110; 
Commonwealth Edison Co., 194 FERC ¶ 61,113 (2026); PECO Energy Co., 193 FERC ¶ 
61,148 (2025); Dayton Power & Light Co., 192 FERC ¶ 61,103; Dayton Power & Light 
Co., 189 FERC ¶ 61,220 (2024).

Docket No. EL26-68-000 
- 32 - 
which data center developers have committed to shield retail ratepayers from increased 
electricity prices.120   
 
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.  
2. 
Additional Cost Transparency 
 
We preliminarily find that SPP’s Tariff appears to be unjust and unreasonable or 
unduly discriminatory or preferential because it does not contain provisions requiring the 
provision of data on SPP’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 requested   
by Eligible Customers on behalf of large loads, for Network Upgrades evaluated in       
the local transmission planning process that are needed to provide 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 provide transmission service to Eligible Customers 
on behalf of large loads.   
 
As an initial matter, we note that SPP has taken numerous steps to connect large 
loads to the transmission system in a reliable and expeditious manner and to enhance     
its study and operational requirements related to provision of transmission service to 
Eligible Customers on behalf of large loads.121  SPP’s Tariff contains a process for 
identifying Network Upgrades for new transmission service requests, including for 
Eligible Customers requesting transmission service on behalf of large loads.  As 
 
120 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026). 
121 See supra PP 21-22.

Docket No. EL26-68-000 
- 33 - 
discussed above, Eligible Customers must satisfy several initial requirements within     
the timeframe outlined in SPP’s Tariff before taking CHILLS, Firm Point-to-Point 
Transmission Service, or NITS on behalf of large loads.  Should the studies associated 
with such a request identify the need for Network Upgrades, those upgrades will be 
further evaluated in SPP’s transmission planning process and included in SPP’s 
Transmission Expansion Plan, and the costs will be allocated to transmission customers 
in certain pricing zones, subregions, the entire SPP region, or a combination thereof, 
based on the voltage level and location of the specific Network Upgrade in accordance 
with section III of Attachment J.  However, if an Eligible Customer does not yet have 
enough existing Designated Resources to serve new load, then the cost of any Network 
Upgrades associated with the new load will be directly assigned to the Eligible Customer 
until the Eligible Customer designates a generating facility to serve the load, at which 
point the remaining cost of the Network Upgrades will be allocated to transmission 
customers in accordance with section III of Attachment J.    
 
However, SPP’s Tariff does not appear to require that information identifying    
the Network Upgrades needed to provide transmission service to Eligible Customers     
on behalf of large loads and the costs of those Network Upgrades determined through 
local transmission planning processes be readily available on SPP’s website in a single 
location, and in an easily accessible format that is searchable and allows users to filter  
the data.  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 driven by requests for transmission service by Eligible Customers to serve   
large loads.  As SPP itself acknowledges, it is facing “unprecedented growth in large, 
often non-traditional, load interconnection requests.”122  The SPP TOs, for their part,  
note the “risk of inappropriate cost-shift to non-large load customers” associated with 
large-load driven Network Upgrades.123  Although SPP has taken significant steps to  
curb speculative requests for transmission service by Eligible Customers on behalf of 
large loads through its HILL process, we are nonetheless concerned that 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 SPP hamper the ability of the Commission and 
stakeholders (including transmission customers and state regulators124) to understand and 
 
122 SPP November 21 ANOPR Comments at 2.  
123 See SPP TOs November 21 ANOPR Comments at 3, 6, 8.  
124 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

Docket No. EL26-68-000 
- 34 - 
accurately assess the relationship between the addition of large loads to the transmission 
system and wholesale transmission costs. 
 
We acknowledge that SPP provides some information to stakeholders regarding 
the cost of Network Upgrades generally.  For instance, SPP publishes an annual report 
detailing the region’s holistic transmission needs over the next 10 years.125  But such 
reporting primarily presents aggregate transmission need and transmission project      
cost-benefit projections across the region, not detailed cost estimates for large-load driven 
Network Upgrades.  Moreover, SPP’s Tariff does not contain provisions that require SPP 
to publicly post cost estimates for Network Upgrades necessary to provide transmission 
service to Eligible Customers on behalf of large loads.    
 
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 regarding the costs driven by large load additions.  We preliminarily find that, 
for Network Upgrades evaluated in the local transmission planning process126 that are 
 
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.”).   
125 SPP, Integrated Transmission Planning, 
https://www.spp.org/engineering/transmission-planning/integrated-transmission-
planning/.  
126 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

Docket No. EL26-68-000 
- 35 - 
needed to provide transmission service to Eligible Customers on behalf of large loads, 
SPP must provide clear, timely, and detailed information regarding the extent to which 
requests for transmission service by Eligible Customers on behalf of large loads 
necessitate Network Upgrades to accommodate the transmission service to Eligible 
Customers on behalf of large loads, as well as the costs of those Network Upgrades. 
 
We note that centralized information regarding Network Upgrades needed to 
accommodate requests for transmission service by 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 requests for transmission service by     
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.127 
 
Accordingly, we preliminarily find that SPP’s Tariff appears to be unjust and 
unreasonable because it does not require the provision of data on SPP’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 
requests for transmission service by Eligible Customers on behalf of large loads, and the 
costs of those Network Upgrades.  SPP should explain whether the Tariff remains just 
and reasonable without provisions that would require SPP and the Transmission Owners 
to publicly post and regularly update data that details:  (1) the aggregate amounts of 
proposed large load additions in SPP’s footprint, including the aggregate amounts in each 
 
efficiently or cost-effectively meet the transmission planning region’s identified 
transmission needs.  See Order No. 1000, 136 FERC ¶ 61,051 at P 11. 
127 See Kansas Commission November 21 ANOPR Comments at 11-13 (noting the 
risk of cost shifts at the wholesale transmission level due to large-load driven regional 
transmission costs); Missouri Commission November 21 ANOPR Comments at 14 
(urging requirements that enhance transparency); see also 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”); CPUC November 21 
ANOPR 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. EL26-68-000 
- 36 - 
transmission pricing zone; (2) the planned Network Upgrades needed to provide 
transmission service to 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.  SPP and the 
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 SPP’s website.  To the extent there are concerns 
about data confidentiality, SPP and the 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 SPP’s Tariff appears to be unjust and  
unreasonable because it lacks 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 SPP, 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.128  Commenters also argue that retail-level large load tariffs do not 
protect wholesale transmission customers from cost shifting.129  Specifically, commenters 
in the record contend that, while a retail-level large load tariff protects the load serving 
 
128 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 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. 
129 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.

Docket No. EL26-68-000 
- 37 - 
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.130  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.”131  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.132   
 
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 an Eligible Customer’s request for transmission service 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 
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. 
 
SPP’s Tariff does not require cost recovery agreements between SPP, 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, 
 
130 Buckeye November 21 ANOPR Comments at 14-15; see TAPS November 21 
ANOPR Comments at 26-27 & nn.50-51.  
131 Kansas Commission November 21 ANOPR Comments at 11-12.  
132 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. EL26-68-000 
- 38 - 
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     
SPP, 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.133  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 
requirement.134  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 
 
133 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). 
134 See supra note 119.

Docket No. EL26-68-000 
- 39 - 
be filed with the Commission.135  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 SPP’s Tariff is unjust and unreasonable 
because it lacks 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 SPP 
and/or 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 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.  SPP 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.136 
 
135 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. 
136 See infra P 94.

Docket No. EL26-68-000 
- 40 - 
 
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.137  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 Load138 that is willing        
and able to limit its energy withdrawals from the transmission system under certain 
conditions.139  Although SPP recently established the HILLGA process to allow for 
expedited review of generating facilities that are designated to serve a large load and 
interconnected in the same local area as the large load (i.e., within a certain number of 
substations and transmission line segments from the HILL), we remain concerned, as 
discussed below, that SPP’s Tariff appears to be unjust and unreasonable because it lacks 
such provisions.140   
 
We direct SPP and the Transmission Owners, to the extent the matters addressed 
herein implicate aspects of the Tariff over which they have the filing rights, 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 
 
137 See 18 C.F.R. pt. 101 (2025). 
138 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 72. 
139 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 2; PJM Co-Location 
Rehearing Order, 195 FERC ¶ 61,209 at PP 91, 102. 
140 We note that SPP does not allow Eligible Customers taking transmission 
service on behalf of loads with behind the meter generation to reduce their transmission 
service charges by netting output from the behind the meter generation in determining 
NITS charges.  We therefore need not address behind the meter generation netting rules 
in this order.

Docket No. EL26-68-000 
- 41 - 
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.  We recognize that SPP is currently considering reforms related to new 
transmission services, which might also be available to Eligible Customers taking 
transmission service on behalf of co-located load, in its stakeholder process, and we 
encourage SPP 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.”141  The PJM     
Co-Location Order used the term co-location arrangement when referring to both the    
co-located load and the associated generator.142   
 
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. 
 
SPP defines Behind-The-Meter-Generation (BTMG) as “A generation unit that is 
connected on the load side of a load Meter Settlement Location and is used by the load 
Market Participant that is the registered owner for the Meter Settlement Location to serve 
all or part of its capacity, Energy or Ancillary Service needs.”143 
 
For purposes of this order, we will use the term Eligible Load to refer to co-located 
load and/or load with BTMG.144 
 
141 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 164 (alterations in original). 
142 Id. P 3. 
143 SPP Tariff, attach. AE (MPL), § 1.1B (3.0.0).  While we believe this definition 
is sufficient for purposes of this order, responses may explain whether changes to the 
definition of BTMG may be needed in order to comply with any future directives, should 
the Commission find that the Tariff has in fact become unjust and unreasonable. 
144 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 91.

Docket No. EL26-68-000 
- 42 - 
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.145  The 
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.146  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.147  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.148   
 
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.149 
3. 
Tariff Provisions 
 
We preliminarily find that SPP’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 SPP’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 
 
145 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171 (citing 16 U.S.C. §§ 824d, 
824e; EPSA, 577 U.S. at 278). 
146 Id. P 172 (citing Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277, 
1282 (D.C. Cir. 2007)). 
147 Id. P 173. 
148 Id. P 174. 
149 Id. PP 167-169.

Docket No. EL26-68-000 
- 43 - 
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 
may use generator interconnection processes in SPP’s Tariff to facilitate their co-location 
arrangements.  We encourage SPP to explain how its existing HILLGA process either 
may already clarify some of these requirements or may be modified to provide such 
clarity.  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,150 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,”151 and that costs must be allocated in a manner that is at least roughly 
commensurate with the benefits that entity receives.152 
 
We preliminarily find that SPP’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 SPP 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 
 
150 Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 F.4th 1307, 1312             
(D.C. Cir. 2023). 
151 Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361 at 1368. 
152 See, e.g., Ill. Com. Comm’n v. FERC, 576 F.3d 470 at 476.

Docket No. EL26-68-000 
- 44 - 
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 
service.153  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 the existing rules and studies applicable to co-location 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 SPP 
to address situations in which a co-located load withdraws energy from the transmission 
system.   
 
Therefore, we preliminarily find that SPP’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.  SPP should explain whether the Tariff remains just 
and reasonable without such provisions, or propose Tariff revisions. 
 
We have similar concerns regarding SPP’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.154  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.155  In the PJM Co-Location Rehearing 
Order, the Commission applied these findings to Eligible Customers taking transmission 
 
153 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.  
154 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 183. 
155 Id. PP 184-185.

Docket No. EL26-68-000 
- 45 - 
service on behalf of load with BTMG.156  However, SPP’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.   
 
Therefore, we preliminarily find that SPP’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.157  SPP 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.158  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.159  We are concerned that SPP’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.160   
 
156 See PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 400. 
157 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 159. 
158 Id. P 199. 
159 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 101-103. 
160 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

Docket No. EL26-68-000 
- 46 - 
 
Therefore, we also preliminarily find that SPP’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.  SPP 
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 Eligible Load, or propose appropriate Tariff revisions.  Specifically, 
SPP 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).  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.161 
 
While we recognize that SPP’s Tariff now provides CHILLS for HILLs, including 
HILLs with behind the meter generation, our concern regarding the lack of interim NITS 
that Eligible Customers may take on behalf of Eligible Load remains because CHILLS 
differs from the interim NITS that the Commission required in the PJM Co-Location 
Order.  In response to this order, SPP may explain why CHILLS is sufficient to address 
our concerns regarding the lack of an interim NITS that Eligible Customers may take on 
behalf of Eligible Load, propose revisions to CHILLS, or propose other Tariff revisions.  
We further note that SPP’s PALS proposal is currently under development in its 
stakeholder process, and we encourage SPP to consider whether PALS would address  
our concern that SPP’s Tariff may be unjust and unreasonable because it does not  
include transmission services that reflect the use of the transmission system by      
Eligible Customers on behalf of flexible large load, on both a temporary and permanent 
basis.162   
 
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.”). 
161 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. 
162 See supra P 27.

Docket No. EL26-68-000 
- 47 - 
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 loads163 can quickly and verifiably adjust 
their consumption in response to system conditions or price signals.164  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 for Network Upgrades, among other potential benefits.165  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.166   
 
We preliminarily find that SPP’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.  The transmission services 
 
163 For our purposes of this order, “flexible” large loads are a subset of HILLs that 
are not co-located with generation, but are willing and able to limit their energy 
withdrawals from the transmission system under certain conditions. 
164 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. 
165 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; 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. 
166 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.

Docket No. EL26-68-000 
- 48 - 
available to Eligible Customers, including on behalf of flexible large loads, in SPP are 
NITS, firm and non-firm Point-to-Point Transmission Service, and CHILLS.167  While 
these remain just and reasonable options 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.168  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 received.169  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.170  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.171  Entities in the SPP 
footprint acknowledge the importance of facilitating load flexibility.172 
 
167 See supra P 22 (describing existing transmission services in SPP). 
168 See supra P 85. 
169 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199; PJM Co-Location 
Rehearing Order, 195 FERC ¶ 61,209 at P 103. 
170 See supra P 85; 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).  
171 See supra P 85; 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). 
172 See, e.g., Oklahoma State Entities December 5 ANOPR Comments at 3;      
State Entities November 21 ANOPR Comments at 8-9.

Docket No. EL26-68-000 
- 49 - 
 
Therefore, we are concerned that SPP’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.  SPP 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, SPP 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).  
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.173 
 
Similar to the discussion above, while SPP’s Tariff now provides CHILLS for 
HILLs, our concern regarding the lack of interim NITS that Eligible Customers may take 
on behalf of flexible large loads remains because CHILLS differs from the interim NITS 
that the Commission required in the PJM Co-Location Order.  In response to this order, 
SPP may explain why CHILLS is sufficient to address our concerns regarding the lack of 
interim NITS that Eligible Customers may take on behalf of flexible large loads, propose 
revisions to CHILLS, or propose other Tariff revisions.  We also note that SPP’s PALS 
proposal is currently under development in its stakeholder process, and we encourage 
SPP to consider whether PALS would address our concern that SPP’s Tariff may be 
unjust and unreasonable because it does not include transmission services that reflect the 
use of the transmission system by Eligible Customers on behalf of flexible large load, on 
both a temporary and permanent basis.174   
E. 
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 
 
173 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. 
174 See supra P 27.

Docket No. EL26-68-000 
- 50 - 
growth is putting on resource adequacy in many regions.175  Indeed, the relative        
speed 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.176  We are concerned about whether SPP and load serving 
entities are planning 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, SPP’s 
HILLGA process and Expedited Resource Adequacy Study (ERAS) process provide 
generator interconnection customers the opportunity to be studied and interconnect to 
SPP’s transmission system more quickly in order to help ensure load serving entities     
are able to meet resource adequacy requirements.177  While we are encouraged by the 
implementation of such processes to ensure resource adequacy and faster interconnection, 
we remain concerned that these efforts may fall short in light of generator retirements and 
tightening supply conditions. 
 
Accordingly, we direct SPP to submit in Docket No. EL26-68-000, 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 or, to the extent that SPP is not considering such proposals, 
providing information regarding how their existing processes, such as HILLGA and 
ERAS, are working.  We also encourage new proposals to the extent necessary to address 
this concern.  To the extent new proposals are being considered, the informational report 
must include a detailed schedule of key milestones, such as stakeholder or SPP Board 
votes, that includes the estimated date on which SPP expects to file any such proposals 
with the Commission.   
 
175 See, e.g., Entergy November 21 ANOPR Comments at 29-30; Eolian 
November 21 ANOPR Comments at 16-17; Industrial Customers November 21 ANOPR 
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.  
176 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. 
177 See SPP HILL Order, 194 FERC ¶ 61,031 at PP 64, 67; Sw. Power Pool, Inc., 
192 FERC ¶ 61,062, at PP 104, 156 (2025).

Docket No. EL26-68-000 
- 51 - 
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 SPP and the 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 SPP’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 SPP’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 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 SPP’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 SPP to explain whether the 
Tariff remains just and reasonable without provisions that (1) require the evaluation of

Docket No. EL26-68-000 
- 52 - 
alternative transmission technologies in transmission service request studies, 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.  
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. EL26-68-000 as discussed in the body of this order. 
(B) 
SPP and the 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 they believe 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) 
SPP 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. EL26-68-000 
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

Docket No. EL26-68-000 
- 53 - 
(including courier) delivery to Federal Energy Regulatory Commission, 12225 Wilkins 
Avenue, Rockville, MD  20852. 
(E) 
Interested entities may respond within 30 days of SPP’s and the 
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. EL26-68-000. 
(G) 
The refund effective date in Docket No. EL26-68-000 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 ) 
 
 
 
 
 
 
 
 
 
 
Debbie-Anne A. Reese, 
Secretary.

Docket No. EL26-68-000 
- 54 - 
Appendix - Commenters in Docket No. RM26-4-000 
 
Advanced Energy Management Alliance (AEMA) 
Advanced Energy United 
Advancing Modern Powerlines Coalition 
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 
America’s Power  
American Chemistry Council  
American Clean Power Association  
American Conservation Coalition 
American Council on Renewable Energy 
American Electric Power Service Corporation178 
American Public Gas Association 
American Public Power Association (APPA) 
American Terawatt, Inc.  
American Transmission Company LLC179 
Americans for a Clean Energy Grid  
Antora Energy, Inc. (Antora) 
Arevia Power 
Arizona Public Service Company 
Arkansas Public Service Commission (Arkansas Commission) 
Attorney General of the State of Oklahoma 
Base Power Company, Inc. 
 
178 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. 
179 American Transmission Company LLC submitted comments on behalf of itself 
and its corporate manager ATC Management Inc.

Docket No. EL26-68-000 
- 55 - 
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 
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. 
CTC Global Corporation 
Data Center Coalition (DCC) 
David Gardiner & Associates  
Delaware Division of the Public Advocate  
Digital Energy Council  
Digital Power Network 
Distributed Capacity Parties180 
Dr. Elisa Nelson 
DTE Electric Company 
Duke Energy Corporation 
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 
Energy Trading Institute 
ENGIE North America, Inc.  
Entergy Services, LLC181 
 
180 Distributed Capacity Parties include:  Clovereleaf Infrastructure; Spark 
Community Investment d/b/a Sparkfund; and Voltus, Inc. 
181 Entergy Services, LLC submitted comments on behalf of the Entergy Operating 
Companies, which include Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy

Docket No. EL26-68-000 
- 56 - 
Environmental Law & Policy Center 
Eolian L.P. 
Equinix, Inc. 
esVolta, LP 
ETX Upstream, LLC 
Eversource Energy182 
Exelon Corporation (Exelon)183 
Fervo Energy Company 
FirstEnergy Service Company184 
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 
Harvard Electricity Law Initiative 
Helion Energy 
Herbert Schrayschuen 
Heron Power Electronics Company 
Indiana Energy Association 
 
Mississippi, LLC, Entergy New Orleans, LLC, and Entergy Texas, Inc. 
182 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. 
183 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. 
184 FirstEnergy 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. EL26-68-000 
- 57 - 
Indicated PJM Transmission Owners185 
Industrial Customer Organizations186 
Information Technology Industry Council 
Infrastructure Masons, Inc. (Infrastructure Masons) 
Institute for Progress 
International Energy Credit Association 
Invenergy187 
Iron Mountain Data Centers, LLC 
ISO New England, Inc. 
ITC Holdings Corp. 
Jason Miller, on behalf of VEIR Inc. 
Kansas Corporation Commission (Kansas Commission) 
 
185 PJM TOs 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. 
186 Industrial Customer Organizations include:  The Industrial Energy Consumers 
of America, the American Forest & Paper Association, the PJM Industrial Customer 
Coalition, and the Coalition of MISO Transmission Customers. 
187 Invenergy includes:  Invenergy Wind Development North America LLC, 
Invenergy Solar Development North America LLC, and Invenergy Thermal Development 
Holdings LLC.

Docket No. EL26-68-000 
- 58 - 
L. Lynne Kiesling 
L.M. Marlowe 
Land Trust Alliance 
Large Public Power Council 
Lauren Hopkins 
LEAN Energy US 
Load Flexibility Parties188 
Long Island Power Authority 
Longroad Energy Holdings, LLC 
Louisiana Public Service Commission (together with the Mississippi Public Service  
Commission, Louisiana and Mississippi Commissions)  
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 Owners189  
 
188 Load Flexibility Parties include:  Enerwise Global Technologies, LLC d/b/a 
CPower, Enel North America, Inc., and Voltus, Inc. 
189 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 
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

Docket No. EL26-68-000 
- 59 - 
Missouri Public Service Commission (Missouri 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)190 
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 Systems191  
New England Public Systems192 
New Mexico Public Regulation Commission 
New York Independent System Operator, Inc. 
New York State Department of State Utility Intervention Unit (NY UIU) 
 
CenterPoint Energy Indiana South); Southern Minnesota Municipal Power Agency; 
Wabash Valley Power Association, Inc.; and Wolverine Power Supply Cooperative, Inc. 
190 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. 
191 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. 
192 New England Public Systems include:  Connecticut Municipal Electric 
Cooperative, Massachusetts Municipal Wholesale Electric Company, and Vermont 
Public Power Supply Authority.

Docket No. EL26-68-000 
- 60 - 
New York Public Service Commission 
New York State Reliability Council 
New York Transmission Owners193 
North American Electric Reliability Corporation 
North Carolina Utilities Commission 
North Carolina Utilities Commission Public Staff 
North Dakota Public Service Commission (North Dakota Commission) 
Northeastern Rural Electric Membership Corporation 
NRG Energy, Inc. 
Office of the Illinois Attorney General  
Office of the Ohio Consumers’ Counsel (OCC) 
Oklahoma Corporation Commission (together with Attorney General of the State of 
Oklahoma, Oklahoma State Entities) 
Oklo Inc. (Oklo) 
Old Dominion Electric Cooperative (ODEC) 
Oncor Electric Delivery Company LLC 
ON Energy Storage Inc.  
OpenAI Inc. 
Oracle America, Inc. 
Organization of MISO States, Inc. (OMS) 
Organization of PJM States, Inc. 
Paces AI Inc. 
Pacific Gas & Electric Company 
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 Corporation194 
Prime Mover Institute 
 
193 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. 
194 PPL Corporation submitted comments on behalf of the PPL Companies, which 
include PPL Electric Utilities Corporation, Louisville Gas & Electric Company and 
Kentucky Utilities, and The Narragansett Electric Company d/b/a Rhode Island Energy.

Docket No. EL26-68-000 
- 61 - 
PSEG Companies195 
Public Citizen, Inc. 
Public Interest Organizations (PIOs)196 
Public Utilities Commission of Ohio’s Office of the Federal Energy Advocate  
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)197 
Southern California Edison Company 
Southern Companies198 
Southern Maryland Electric Cooperative, Inc. 
Southwest Power Pool, Inc. (SPP) 
Southwest Power Pool Transmission Owner Group (SPP TOs)199 
 
195 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. 
196 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. 
197 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. 
198 Southern Companies include:  Georgia Power Company, Alabama Power 
Company, and Mississippi Power Company. 
199 SPP TOs include:  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.

Docket No. EL26-68-000 
- 62 - 
Splight Inc. (Splight) 
State Entities200 
Steel Manufacturers Association 
Switch, Ltd. (Switch) 
Talen Energy Corporation 
Terraflux LLC 
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 
U.S. Energy Storage Coalition 
U.S. House of Representatives Committee on Energy and Commerce Ranking  
Members201 
U.S. Representatives202 
U.S. Senate Committee on Energy and Natural Resources 
U.S. Senators203 
U.S. Senator Jon Ossoff 
Union of Concerned Scientists (UCS) 
Vantage Data Centers (Vantage) 
Verrus 
Virginia State Corporation Commission 
 
200 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. 
201 Submitted by Frank Pallone, Jr. (Ranking Member) and Kathy Castor (Ranking 
Member, Subcommittee on Energy). 
202 The U.S. Representatives that submitted comments include:  Suhas 
Subramanyam, John W. Mannion, Mike Quigley, and Donald S. Beyer Jr. 
203 The U.S. Senators that submitted comments include:  Edward J. Markey, Chris 
Van Hollen, Elizabeth Warren, Peter Welch, Raphael Warnock, Richard Blumenthal, and 
Adam B. Schiff.

Docket No. EL26-68-000 
- 63 - 
Vistra Corp. (Vistra) 
Washington Utilities and Transportation Commission 
Working for Advanced Transmission Technologies Coalition  
WIRES 
Wisconsin Electric Company  
Wisconsin Public Service Corporation

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
Southwest Power Pool, Inc., AEP Oklahoma 
Transmission Company, Inc., AEP Southwestern 
Transmission Company, Inc., Deseret Generation & 
Transmission Co-operative, Inc., Empire District 
Electric Company, Evergy Kansas Central, Inc., Evergy 
Kansas South, Inc., Evergy Metro, Inc., Evergy 
Missouri West, Inc., GridLiance High Plains LLC, ITC 
Great Plains, LLC, Mountrail-Williams Electric 
Cooperative, NextEra Energy Transmission Southwest, 
LLC, NorthWestern Energy Public Service Corporation, 
Oklahoma Gas and Electric Company, Prairie Wind 
Transmission, LLC, Public Service Company of 
Oklahoma, Southwestern Electric Power Company, 
Southwestern Public Service Company, Transource 
Missouri, LLC, Transource Oklahoma, LLC, Tri-State 
Generation and Transmission Association, Inc., and 
Upper Missouri G. & T. Electric Cooperative, Inc. 
Docket No. EL26-68-000 
 
(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 
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 
 
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

Docket No. EL26-68-000 
 
- - 2 - - 
 
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. 
 
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 
 
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 
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

Docket No. EL26-68-000 
 
- - 3 - - 
 
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 
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 
 
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. 
8 See, e.g., Comments of Talen Energy Corporation, Docket No. RM26-4, at 5-6 
(filed Nov. 21, 2025).

Docket No. EL26-68-000 
 
- - 4 - - 
 
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 
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 
 
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 
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.

Docket No. EL26-68-000 
 
- - 5 - - 
 
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

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
Southwest Power Pool, Inc., AEP Oklahoma 
Transmission Company, Inc., AEP Southwestern 
Transmission Company, Inc., Deseret Generation & 
Transmission Co-operative, Inc., Empire District 
Electric Company, Evergy Kansas Central, Inc., Evergy 
Kansas South, Inc., Evergy Metro, Inc., Evergy Missouri 
West, Inc., GridLiance High Plains LLC, ITC Great 
Plains, LLC, Mountrail-Williams Electric Cooperative, 
NextEra Energy Transmission Southwest, LLC, 
NorthWestern Energy Public Service Corporation, 
Oklahoma Gas and Electric Company, Prairie Wind 
Transmission, LLC, Public Service Company of 
Oklahoma, Southwestern Electric Power Company, 
Southwestern Public Service Company, Transource 
Missouri, LLC, Transource Oklahoma, LLC, Tri-State 
Generation and Transmission Association, Inc., and 
Upper Missouri G. & T. Electric Cooperative, Inc. 
Docket No. EL26-68-000 
 
(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. 
 
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

Docket No. EL26-70-000  
- 2 - 
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 
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. 
 
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. EL26-70-000  
- 3 - 
 
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. 
 
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 
 
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. EL26-70-000  
- 4 - 
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. 
 
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 
 
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. EL26-70-000  
- 5 - 
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 
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-
 
7 See Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026).

Docket No. EL26-70-000  
- 6 - 
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 
 
Southwest Power Pool, Inc., AEP Oklahoma 
Transmission Company, Inc., AEP Southwestern 
Transmission Company, Inc., Deseret Generation & 
Transmission Co-operative, Inc., Empire District 
Electric Company, Evergy Kansas Central, Inc., Evergy 
Kansas South, Inc., Evergy Metro, Inc., Evergy Missouri 
West, Inc., GridLiance High Plains LLC, ITC Great 
Plains, LLC, Mountrail-Williams Electric Cooperative, 
NextEra Energy Transmission Southwest, LLC, 
NorthWestern Energy Public Service Corporation, 
Oklahoma Gas and Electric Company, Prairie Wind 
Transmission, LLC, Public Service Company of 
Oklahoma, Southwestern Electric Power Company, 
Southwestern Public Service Company, Transource 
Missouri, LLC, Transource Oklahoma, LLC, Tri-State 
Generation and Transmission Association, Inc., and 
Upper Missouri G. & T. Electric Cooperative, Inc. 
Docket No. EL26-68-000 
 
 
(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 
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

Docket No. EL26-68-000 
- 2 - 
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 
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 
 
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. EL26-68-000 
- 3 - 
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 
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

Docket No. EL26-68-000 
- 4 - 
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.  
 
 
 
______________________________ 
Lindsay S. See 
Commissioner 
 
3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026). 
4 See id. P 456.

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
Southwest Power Pool, Inc., AEP Oklahoma 
Transmission Company, Inc., AEP Southwestern 
Transmission Company, Inc., Deseret Generation & 
Transmission Co-operative, Inc., Empire District 
Electric Company, Evergy Kansas Central, Inc., Evergy 
Kansas South, Inc., Evergy Metro, Inc., Evergy Missouri 
West, Inc., GridLiance High Plains LLC, ITC Great 
Plains, LLC, Mountrail-Williams Electric Cooperative, 
NextEra Energy Transmission Southwest, LLC, 
NorthWestern Energy Public Service Corporation, 
Oklahoma Gas and Electric Company, Prairie Wind 
Transmission, LLC, Public Service Company of 
Oklahoma, Southwestern Electric Power Company, 
Southwestern Public Service Company, Transource 
Missouri, LLC, Transource Oklahoma, LLC, Tri-State 
Generation and Transmission Association, Inc., and 
Upper Missouri G. & T. Electric Cooperative, Inc. 
Docket Nos. EL26-68-000 
 
 
(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 
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

Docket No. EL26-68-000 
- 2 - 
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 
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.   
 
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. EL26-68-000 
- 3 - 
 
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, 
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.   
 
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. EL26-68-000 
- 4 - 
 
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 
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 
 
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 
https://gridstrategiesllc.com/project/federal-transmission-pricing.  
7 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026).

Docket No. EL26-68-000 
- 5 - 
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.  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, 
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.

Docket No. EL26-68-000 
- 6 - 
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,8 it is time to roll out all available technologies to reduce 
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 
 
8 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-
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).

Docket No. EL26-68-000 
- 7 - 
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.

Docket No. EL26-68-000 
- 8 - 
For these reasons, I respectfully concur.  
 
 
________________________ 
Judy W. Chang 
Commissioner

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
 
Southwest Power Pool, Inc., AEP Oklahoma 
Transmission Company, Inc., AEP Southwestern 
Transmission Company, Inc., Deseret Generation & 
Transmission Co-operative, Inc., Empire District 
Electric Company, Evergy Kansas Central, Inc., Evergy 
Kansas South, Inc., Evergy Metro, Inc., Evergy Missouri 
West, Inc., GridLiance High Plains LLC, ITC Great 
Plains, LLC, Mountrail-Williams Electric Cooperative, 
NextEra Energy Transmission Southwest, LLC, 
NorthWestern Energy Public Service Corporation, 
Oklahoma Gas and Electric Company, Prairie Wind 
Transmission, LLC, Public Service Company of 
Oklahoma, Southwestern Electric Power Company, 
Southwestern Public Service Company, Transource 
Missouri, LLC, Transource Oklahoma, LLC, Tri-State 
Generation and Transmission Association, Inc., and 
Upper Missouri G. & T. Electric Cooperative, Inc. 
Docket No. EL26-68-000 
 
 
(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 SPP’s Tariff 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  I write separately to underscore my expectation for RTOs and 
ISOs, including SPP, 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 
 
1 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 (Oct. 23, 2025) 
(Secretary’s Letter).

Docket No. EL26-68-000 
- 2 - 
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 SPP 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 
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 SPP, 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. 
 
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)). 
4 Admittedly, we are further down the road in some regions as compared with 
others.

Docket No. EL26-68-000 
- 3 - 
 
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, SPP, 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 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 
 
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) 
(comparing the respective authorities of the Commission and public utilities under 
sections 205 and 206).

Docket No. EL26-68-000 
- 4 - 
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 SPP 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. 
 
 
______________________________ 
David LaCerte 
Commissioner 
 
 
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[.]”).