TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 8. PIPELINE SAFETY REGULATIONS

SUBCHAPTER C. REQUIREMENTS FOR GAS PIPELINES ONLY

The Railroad Commission of Texas adopts amendments to §8.201, relating to Pipeline Safety and Regulatory Program Fees, without changes to the proposed text as published in the November 14, 2025, issue of the Texas Register (50 TexReg 7397); the rule text will not be republished. The Commission received no comments on the proposal. The Commission adopts the amendments to implement House Bill 4042, 89th Texas Legislature (Regular Session, 2025). The bill removes the specification that gas must be natural gas with respect to gas distribution pipelines, gas master-metered pipelines, gas distribution systems, and gas master-metered systems whose operators may be subject to annual pipeline safety and regulatory fees.

The Commission adopts amendments throughout the rule to remove the word "natural" from the rule text.

The Commission adopts the amendments under Texas Natural Resources Code, §81.051 and §81.052, which give the Commission jurisdiction over all common carrier pipelines in Texas, persons owning or operating pipelines in Texas, and their pipelines and oil and gas wells, and authorize the Commission to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission; and Texas Utilities Code, §121.201, §121.211, §121.213, and §121.214, which authorize the Commission to adopt and collect pipeline safety and regulatory program fees.

Statutory authority: Texas Natural Resources Code, §81.051, §81.052; and Texas Utilities Code, §121.201, §121.211; §121.213, §121.214.

Cross-reference to statute: Texas Natural Resources Code, Chapter 81; and Texas Utilities Code, Chapter 121.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 5, 2026.

TRD-202600527

Olivia Alland

Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: February 25, 2026

Proposal publication date: November 14, 2025

For further information, please call: (512) 475-1295

PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 22. PROCEDURAL RULES

The Public Utility Commission of Texas (commission) adopts amendments to 19 procedural rules in 16 Texas Administrative Code (TAC) Chapter 22. The commission adopts the following rules with changes to the proposed text as published in the August 15, 2025 issue of the Texas Register (50 TexReg 5269): §22.2, relating to Definitions; §22.3, relating to Standards of Conduct; §22.4, relating to Computation of Time; §22.31, relating to Classification in General; §22.52, relating to Notice in Licensing Proceedings; §22.53, relating to Notice of Regional Hearings; §22.74, relating to Service of Pleadings and Documents; §22.75, relating to Examination and Correction of Pleadings and Documents; §22.77, relating to Motions; §22.78, relating to Responsive Pleadings; §22.79, relating to Continuances; §22.80, relating to Commission Prescribed Forms; §22.101, relating to Representative Appearances; §22.103, relating to Standing to Intervene and §22.104, relating to Motions to Intervene. These rules will be republished.

The commission adopts the following rules with no changes to the proposed text as published in the August 15, 2025 issue of the Texas Register (50 TexReg 5269): §22.21, relating to Meetings; §22.23, relating to Delegation of Authority to Request Representation by the Attorney General; §22.56, relating to Notice of Unclaimed Funds and §22.76, relating to Amended Pleadings. These rules will not be republished.

The commission received comments on the proposed rule from the Lower Colorado River Authority (LCRA); Office of Public Utility Counsel (OPUC); Oncor Electric Delivery Company LLC (Oncor); Southwestern Public Service Company (SPS); Texas Association of Water Companies, Inc. (TAWC); and Vistra Corporation (Vistra).

General Changes

The adopted rules include various clerical and grammatical changes, as well as changes to outdated rules, statutes, or certain terms.

Definitions

Adopted §22.2 is revised to state "[a] written document submitted by a party, a person seeking to intervene, or an amicus curiae in a proceeding." The term "intervene" replaces the previous term "participate." Adopted §22.2 replaces the definitions of "contested case" and "retail public utility" with statutory cross references. Adopted §22.2 omits the definitions of "docket," "hearing day," "PWS" (Public Water System), and "WQ" (Water Quality discharge permit) as those terms are either outdated or unused in the commission's procedural rules.

Standards of Conduct

Adopted §22.3 separates the requirements and prohibitions associated with ex parte communications under §2001.061 of the APA from the records retention of communications by public utilities and their affiliates with the commission and commission employees under PURA §14.153. Adopted §22.3 also separates the standards for recusal or disqualification of an administrative law judge from the standards for recusal of a commissioner. Adopted §22.3 refines the procedures for motions for disqualification or recusal of an administrative law judge.

Computation of Time

Adopted §22.4 is revised for consistency with the defined term "working day" (i.e., replacing the phrase " a day the commission is not open for business)." Adopted §22.4 also adds reference to "5:00 P.M. Central Prevailing Time" for consistency with the commission's filing rules §22.71, relating to Commission Filing Requirements and Procedures and §22.72, relating to Form Requirements for Documents Filed with the Commission, which were updated to include a 5:00 P.M. filing deadline in Project 52059.

Notice in Licensing Proceedings and Regional Hearings

Adopted §22.52 and §22.53 retain newspaper notice for electric and telephone licensing proceedings as well as for regional hearings. Adopted §22.52 also exempts service area exceptions from the notice requirements for electric licensing proceedings; corrects references to the "Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse" or similar entity as designated by the Department of Defense; and revises the proof of notice requirements as they relate to affected landowners for consistency with Senate Bill 1281 (87R). Adopted §22.52 also requires notice for telephone licensing proceedings to identify the commission's docket control number and style assigned to the case by Central Records.

Service of Pleadings and Documents

Adopted §22.74 separates the standard methods of service (i.e., personal service, by e-mail, by mail, by agent or by courier, or in-person delivery) with service by filing, which is an alternative method of service that must be approved by the presiding officer. The provision also specifies the form and manner in which service must be made for each type of service.

Examination and Correction of Pleadings and Documents

Adopted §22.75 is revised to conform with the requirements of §22.72 and remove the exemption for motions for rehearing and replies to motions for rehearing. Adopted §22.75 is also eliminates the requirement for a rate change application or certificate of convenience and necessity (CCN) application to be deemed sufficient if the presiding officer has not issued a written order concluding that material deficiencies exist in the application within 35 days after the filing of the application. Adopted §22.75 also eliminates the 35-day deadline for the presiding officer to issue a written order specifying a time within which an applicant must amend a rate application or CCN application to correct material deficiencies.

Motions and Certificates of Conference

Adopted §22.77 is revised to require movants to attempt to confer with all parties that could be affected by the motion or pleading, but does not require the movant to attempt to confer with all parties to the proceeding. Adopted §22.77 also requires written motions to include a certificate of conference that substantially complies with one of two examples provided by the rule.

Responsive Pleadings

Adopted §22.78 is retitled to exclude reference to emergency action both in the title of the rule and in the text of the rule. Specifically, adopted §22.78 authorizes the presiding officer to generally take action on a pleading before the deadline for filing responsive pleadings, rather than limiting the presiding officer to take such action only in emergencies.

Commission Prescribed Forms

Adopted §22.80 is revised to authorize the immediate implementation of a new commission-prescribed form or a substantive change to an existing form on a temporary basis consistent with the requirements of §2001.034 of the Texas Administrative Procedure Act (APA) concerning emergency rulemaking, including reference in the "in Addition" section of the Texas Register. The adopted rule also omits proposed language authorizing commission staff to make minor updates to commission-approved forms and concerning the correction of minor conflicts between the language of a form and an underlying statute or rule associated with the form. Additionally, language regarding the maintenance of a complete index to and set of all commission prescribed forms is preserved.

Representative Appearances

Adopted §22.101 is revised to omit reference to the filing of multiple copies of notices of a change in authorized representative for consistency with the commission's filing rules §22.71, and §22.72 which were updated to require the filing of only one copy of a pleading or document. Adopted §22.101 is also revised to omit reference to facsimile (fax) numbers and include email as a type of contact information.

Standing to Intervene

Adopted §22.103 is revised to clarify that commission staff represents the public interest and is not required to file a motion to intervene. Adopted §22.103 is also revised to state that a person, not their representative, has standing to intervene if that person has a justiciable interest that may be adversely affected by the outcome of the proceeding.

Motions to Intervene

Adopted §22.104 is restructured for clarity and also requires motions to intervene to include the name and email address of the person requesting to intervene unless the motion is accompanied by a statement of no access under §22.106, relating to Statement of No Access. Adopted §22.104 clarifies that the criteria for granting late intervention include the criteria for standing identified under §22.103(b). Adopted §22.104 extends the deadline from five working days to ten working days for commissioners to place a late motion to intervene after the issuance of a proposal for decision or a proposed order on the agenda of the next scheduled open meeting or other meeting. Adopted §22.104 also omits the three-day deadline for the commission to rule on a late motion to intervene that has been filed after the issuance of a proposal for decision or a proposed order.

General Comments

Internal cross-references to commission rules

OPUC recommended that internal cross-references to other commission rules refer to the applicable chapter of the Texas Administrative Code, rather than the overall title (i.e., "§22.74 of this title" should be revised to "§22.74 of this chapter.") OPUC stated the applicable title for commission rules would be "Title 16, Economic Regulation" and therefore include rules of at least six different State of Texas agencies. OPUC noted that "of this chapter" is the correct reference in most instances, as that would refer to Chapter 22, under Part 2 of Title 16 which is the appropriate reference.

Commission response

The commission declines to implement the recommended change. Across the Texas Administrative Code there may be several instances of a specific chapter. For instance, "Chapter 22" appears in Title 1, Title 4, Tile 13, Title 16, Title 19, Title 28, and Title 43. The reference to "Title 16" is intended to ensure the Chapter 22 that is applicable to the commission rules. For this reason, the usage of "of this title" is common practice among Texas state agencies (e.g., Title 16, Part 1, Chapter 3 of the Texas Railroad Commission's rules and Title 30, Part 1, Chapter 290 of the Texas Commission on Environmental Quality's rules both use the phrase "of this title" over 200 times and "of this chapter" less than five times).

Usage of the terms "shall" vs. "must"

OPUC recommended that the term "shall" be preserved across the Chapter 22 rules, rather than be replaced with specific instances of "must" or "will," unless otherwise appropriate to do so in accordance with the Texas Code Construction Act (TCCA). OPUC maintained that the Legislature intentionally used the term "shall" when drafting the statutes that underpin the commission's rules, even as recently as the last legislative session. Accordingly, if the Legislature had meant to use a different term, then it would have done so explicitly. OPUC further contended that the Texas Code Construction Act provides clear, separate definitions of "shall" and "must" and therefore the terms are not interchangeable. OPUC noted, had the Legislature intended the terms to be interchangeable, then it would have clearly stated that in the same manner that "may not" and "shall not" are. OPUC also commented that "shall" is not an antiquated term, given that other current bodies of law, such as "The Texas Rules of Civil Procedure, Texas Disciplinary Rules of Professional Conduct, and Texas Code of Judicial Conduct" all refer to the term "shall."

Commission response

The commission declines to implement the recommended change. The commission acknowledges the general applicability of the TCCA to the commission's rules. See Texas Government Code §311.002(4) (applying the TCCA to "each rule adopted under a code"). However, forgoing use of the term "shall" or replacing the term with "may," "must," or another contextually relevant term is appropriate and not inconsistent with the TCCA. As indicated by OPUC, the TCCA does separately indicate a specific construction for the terms "may," "shall," "must," and "may not" under Texas Government §311.016(1)-(3) and (5). However, the statute also establishes that: "[t]he following constructions apply unless the context in which the word or phrase appears necessarily requires a different construction or unless a different construction is expressly provided by statute" (emphasis added). This provision indicates a general level of flexibility in usage and interpretation of various modal verbs. More importantly, the TCCA does not require the usage of "shall" as opposed to "must" or "may" when implementing statutes in agency rules. Therefore, the commission is not prohibited by law from utilizing other modal verbs to replace "shall." Lastly, commenters have not identified instances where the usage of a different modal verb has resulted in ambiguity as to the intended meaning.

Project 52059 E-Filing Changes

OPUC recommended language in the Chapter 22 rules be revised to reflect changes to §22.71, relating to Commission Filing Requirements and Procedures, and §22.72, relating to Form Requirements for Documents Filed with the Commission, under Project 52059, to refer to changes being made under those rules to accommodate the commission's electronic filing system.

Commission response

The commission revises the adopted rules to reflect revisions to §22.71 and §22.72 adopted under Project 52059.

Market Competition Rules

OPUC commented that some of the proposed rule changes could impact market competition and therefore be subject to review by the Governor's office in accordance with APA §2001.039.

Commission response

The commission declines to implement the recommended change. Texas Government Code §2001.039 applies only to a state agency's review of existing rules (rule reviews such as Project 56574 and Project 54589) and does not cover market competition rules subject to review by the Governor's office. OPUC is presumably referring to market competition rules under PURA §39.001(e) that are subject to judicial review. The rules amended in Project 58400 govern the standards of practice at the commission, not activities in the competitive electric markets. The commission declines to designate any of the rules in this order as competition rules.

Minor and conforming changes

The commission makes minor and conforming changes across the adopted rules for spelling, grammar, and style. The commission also corrects the term "tariff control proceeding" or "tariff control" to "tariff filing proceeding" and "tariff filing," where applicable in §22.2 and §22.31.

Proposed §22.2- Definitions

Proposed §22.2 establishes the definitions applicable to all procedural rules in Chapter 22.

Proposed §22.2(13)- Definition of "commission filing system"

Proposed §22.2(13) defines "commission filing system" as the "electronic filing system maintained for the archiving and organization of items and materials received by the commission.

The commission omits this definition as the term was intended to correspond with the revisions made to the filing rules §22.71 and §22.72 in Project 52059. However, the term "commission filing system" was omitted in the adopted versions of this rule rendering the inclusion of this term in §22.2 moot. The commission renumbers subsequent definitions accordingly.

Proposed §22.2(26)- Definition of "major rate proceeding"

Proposed §22.2(26) defines "major rate proceeding" as "[a]ny proceeding filed under PURA §§36.101- 36.112, 36.201 - 36.203, 36.205, 51.009, 53.101 - 53.113, 53.201, or 53.202 involving an increase in rates which would increase the aggregate revenues of the applicant more than the greater of $100,000 or 2.5%." The definition also states that "a major rate proceeding is any rate proceeding initiated under PURA §§36.151 - 36.156, 53.151, or 53.152 in which the respondent utility is directed to file a rate filing package" and, "[f]or water and sewer utilities, a rate filing package filed under TWC §13.187 is a major rate proceeding."

OPUC and TAWC recommended that the defined term "major rate proceeding" be revised to include rate proceedings involving Class B water or sewer utilities by referencing 13.1871, or 13.18715. OPUC further recommended the term be revised to include rate proceedings involving certain Class C water or sewer utilities. OPUC commented that Class B utilities could include up to 9,999 taps or connections, which is one less than the Class A category. Moreover, OPUC stated that a Class C utility could serve almost 2,300 taps or connections, which is comparable to a small Class B utility. OPUC and TAWC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change as it is out of scope. The revision may have major consequences as the designation of an application as a major rate proceeding prohibits the application from being eligible for administrative review under §22.32(a), relating to Administrative Review, or for informal disposition under §22.35(a). Moreover, major rate proceedings must comply with additional requirements under §22.51(a), relating to Notice for Public Utility Regulatory Act, Chapter 36, Subchapters C - E; Chapter 51, §51.009; and Chapter 53, Subchapters C - E, Proceedings and §22.225, relating to Written Testimony and Accompanying Exhibits. The commission will consider this revision in a later rulemaking.

Proposed §22.2(28)- Definition of "mediation"

Proposed §22.2(28) defines "mediation at" as a form of dispute resolution in which an impartial person facilitates communication between parties to promote negotiation and settlement of disputed issues.

Commission response

The commission omits the term "voluntary" from the definition of "mediation" to reflect legal practice as some forms of mediation may be involuntary (i.e., required by law or commission order).

Proposed §22.2(31)- Definition of "pleading"

Proposed §22.2(31) defines "pleading" as "[a] written document submitted by a party, or a person seeking to intervene in a proceeding, setting forth allegations of fact, claims, requests for relief, legal argument, and/or other matters relating to a proceeding."

Oncor and OPUC noted that the proposed language for the defined term "pleading" could have unintended consequences. Oncor recommended the defined term "pleading" be revised to refer to a "document submitted by a party, or a person seeking to intervene" rather than "a person seeking to participate." Oncor stated that a utility can sometimes be a necessary participant in a proceeding but might not be an "intervenor." Oncor explained that utilities are often "applicants" in proceedings they initiate, or otherwise initiated by Staff, and frequently file pleadings in such proceedings. In other proceedings, such as complaints, a utility may file pleadings without being an "intervenor." Oncor provided draft language consistent with its recommendation. OPUC opposed implementing the proposed revision to the defined term "pleading."

Commission response

The commission declines to implement the recommended change. Applicants, including utility applicants, are considered parties in commission contested cases matters. Moreover, responses to complaints are "responsive pleadings" under §22.78(b). The revision intends to cover a broader, not narrower scope, of documents that may be considered "pleadings."

As an alternative, OPUC recommended revising the defined term "pleading" to include a written document submitted by an amicus curiae. OPUC stated that the proposed revision to the term to be applicable to intervenors may effectively exclude the public from participation in instances where they have the right or authority to do so. OPUC stated that currently, a person may file an amicus brief with the commission, but that would be precluded under the revised language. OPUC provided draft language consistent with its alternative language.

Commission response

The commission agrees with OPUC and implements the recommended change.

Proposed §22.2(45)- Definition of "working day"

Proposed §22.2(45) defines "working day" as "[a] day on which the commission is open for the conduct of business."

OPUC recommended the defined term "working day" under proposed §22.2(45) be revised to clarify whether any differences in the term exist with the term "business day." OPUC commented that the term "working day" is not used in either PURA or the Texas Water Code but do utilize the term "business day" when establishing deadlines. OPUC noted that Texas Government Code §552.0031 defines the term "business day" to mean "a day other than: (1) a Saturday or Sunday; (2) a national holiday . . . or (3) a state holiday" whereas proposed §22.2(45) defines "working day "as [a] day on which the commission is open for the conduct of business." OPUC stated that there appears to be "little to no difference between the two terms" but averred that "when a statute or rule is subject to litigation, courts or the administrative decisionmaker may scrutinize the terminology used in deciding the issue at hand. OPUC indicated that its recommended revision should therefore be implemented to provide clarity on commission deadlines to the public, courts, and administrative law judges when interpreting commission rules. OPUC noted that their recommended clarification is within the scope of the rulemaking because it is an additional modification that is reasonably related to the proposed changes to the defined term "working day."

Commission response

The commission declines to implement the recommended change. The term "working day" as defined by §22.2(45) has a different scope than the definition of "business day" under Texas Government Code §552.0031. Specifically, the term "working day" refers to "[a] day on which the commission is open for the conduct of business." The commission may not be open for business on a day other than a holiday, such as a storm or other emergency. The current definition of "working day" has proven to be sufficient in commission proceedings and revising it would entail extensive revisions to other provisions for little commensurate benefit.

Proposed §22.3- Standards of Conduct

Proposed §22.3 establishes the standards of conduct for every person appearing in a proceeding before the commission, including guidance for violations, requirements for ex parte communications, and procedures for the recusal or disqualification of an administrative law judge or the recusal of a commissioner.

Proposed §§22.3(b), 22.3(b)(2) and 22.3(b)(3)- Ex Parte Communications

Proposed §22.3(b) establishes the requirements governing ex parte communications in contested cases before the commission. Proposed §22.3(b)(2) authorizes members of the commission or administrative law judges assigned to the case to communicate ex parte with employees of the commission that are not participating in the case to utilize their special skills or knowledge of the commission and its staff in evaluating evidence. Proposed §22.3(b)(3) provides that number running procedures are not impermissible ex parte communications if memoranda "memorializing such procedures are preserved and made available to all parties of record in the proceeding to which the number running procedures relate."

OPUC recommended the existing version of §22.3(b)(1) be reinstated as its repeal, in its view, violates statutory requirements in PURA § 14.153. OPUC stated that the repeal of existing §22.3(b)(1) is unlawful because the commission is statutorily mandated to "adopt rules" for the scenarios expressly set forth in PURA §14.153. Specifically, PURA §14.153(a) requires the commission to "adopt rules governing communications with the regulatory authority or a member or employee of the regulatory authority by a public utility, an affiliate, or a representative of a public utility or affiliate. PURA §14.153(b) requires a record of communication to contain the name of the person contacting the regulatory authority or member or employee of the regulatory authority; the name of the business entity represented; a brief description of the subject matter of the communication; and the action, if any, requested by the public utility, affiliate, or representative. Lastly, PURA §14.153(c) requires communication records compiled under PURA §14.153(b) to be made available monthly. OPUC commented that the existing version of §22.3(b)(1) relates to communications between certain individuals or entities with the commission and is distinct from the provision concerning ex parte communications. OPUC further noted that PURA §14.153 "does not limit communication with the Commission to personal communications." OPUC provided redline language consistent with its recommendation.

Commission response

The commission reinstates existing §22.3(b)(1) with a correct reference to PURA §14.153 as §22.3(c) and renumbers all subsequent provisions. The commission omits the previous list provided under existing §22.3(b) as it is more expansive and burdensome than what is required under PURA §14.153.

SPS recommended proposed §22.3(b)(2) be revised to require the commission to, upon request, maintain and make available to the public and all parties all records of permitted ex parte communications. SPS acknowledged that the proposed language closely tracks that of Texas Government Code §2001.061, but requested this additional language to be added to inform the public regarding communications that concern their proceedings and the decisionmaking process surrounding commission actions that affect the public interest. SPS further recommended that such records "identify the names of people involved in the communication, the control number, the subject matter of communication, the date of the communication, and the special skills or knowledge requested."

Commission response

The commission declines to implement the recommended change because it is not required under the APA. Moreover, the proposal would impose a new documentation requirement that would unnecessarily increase commission staff workload and use agency resources for little commensurate benefit.

OPUC recommended that proposed §22.3(b)(2) and (b)(3) be revised to comply with §2001.090 of the APA. OPUC stated that limited ex parte communications are authorized under §2001.061 and §2001.090 of the APA. However, the proposed rule only incorporates language from §2001.061, not §2001.090. OPUC commented that the §2001.090 requires "each party shall be notified either before or during the hearing, or by reference in a preliminary report or otherwise, of the material officially noticed, including staff memoranda or information" and for each party to be provided an opportunity to contest officially noticed material. In contrast, proposed §22.3(b)(2) and (3) only refer to permissible ex parte communications during contested cases. Specifically, OPUC stated that the number running procedures identified as permissible ex parte communications under §22.3(b)(2) but does not comply with §2001.090 of the APA when describing the rights afforded to parties concerning the communication. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. The taking of official notice is completely unrelated to ex parte communications under §22.3 and Texas Government Code § 2001.090. The official notice requirements of Texas Government Code § 2001.090 are already codified in commission rules under §22.225, relating to Official Notice.

Proposed §22.3(c)- Standards for Recusal or Disqualification of Administrative Law Judges

Proposed §22.3(c) aligns the standards for recusal or disqualification for administrative law judges with Rule 18b of the Texas Rules of Civil Procedure.

OPUC recommended proposed §22.3(c) be revised to authorize a commissioners or SOAH administrative law judges to disqualify themselves in accordance with other applicable law. OPUC commented that the provision does not account for other law that applies to administrative law judges. Specifically, OPUC recommended the provision be revised to reference Texas Government Code Chapter 572, which prescribes standards of conduct for administrative law judges as employees of the State of Texas executive branch. OPUC stated that a general statement of applicability is sufficient to ensure the rule can still apply without amendment in the event Chapter 572 is revised, unless the Legislature directs otherwise. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. Commission administrative law judges frequently and voluntarily recuse themselves from commission proceedings to avoid any appearance of impropriety. Additionally, no part of Texas Government Code Chapter 572 relates to the recusal or disqualification of administrative law judges. Only one section, Texas Government Code § 572.051, imposes ethical standards of conduct on state employees which, by extension, also apply to commission administrative law judges. Such standards of conduct apply regardless of whether Chapter 572 is referenced in §22.3.

Proposed §22.3(d) and §22.3(e)- Motions for Disqualification or Recusal of an Administrative Law Judge and Standards for Recusal of Commissioners

Proposed §22.3(d) establishes the requirements and procedures for filing a motion for disqualification or recusal of an administrative law judge. Proposed §22.3(e) establishes the standards for recusal of a commissioner from a proceeding.

OPUC recommended proposed §22.3(d) be deleted as it is duplicative of proposed §22.3(e), as both provisions refer to standards for recusal of commissioners. Similar to its recommendations for recusal of administrative law judges, OPUC also recommended the addition of new §22.3(e)(4), which would require a commissioner's recusal if other state law requiring the recusal applies. OPUC also recommended minor clarifying edits to proposed §22.3(e) as a whole. OPUC provided draft language consistent with its recommendation.

Commission response

The commission agrees with OPUC and deletes the first initial instance of proposed §22.3(d), which relates to the standards for recusal of commissioners because it is duplicative of §22.3(e), which relates to motions for recusal of a commissioner. However, the commission declines to revise §22.3(e) or add §22.3(e)(4) as OPUC recommends because it is unnecessary. If another law addresses a commissioner's ability to hear a case, then that commissioner should evaluate how the law may apply and whether the commissioner should self-recuse.

Proposed §22.3(d)(1)- Contents of Motion for Disqualification or Recusal of Administrative Law Judge

Proposed §22.3(d)(1) establishes minimum requirements for the contents of motions for the disqualification or recusal of an administrative law judge.

OPUC recommended proposed §22.3(d)(1) be revised to authorize a motion for disqualification or removal of an administrative law judge to include grounds outside of those specified under proposed §22.3(c). OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. As proposed, §22.3(d)(1) does not expressly limit the movant's possible grounds for disqualification or recusal to those listed in proposed §22.3(c). Therefore, it is not necessary to add a provision stating that the movant is not limited to the criteria listed in §22.3(c).

Proposed §§22.3(f), 22.3(f)(2) and 22.3(f)(4)- Standards for Recusal of Commissioners

Proposed §22.3(f) establishes the requirements and procedures for filing a motion for the recusal of a commissioner. Proposed §22.3(f)(1) establishes minimum requirements for motions for the recusal of a commissioner. Proposed §22.3(f)(2) establishes the timing for filing and serving motions for recusal of a commissioner.

For consistency, OPUC recommended the terms "disqualification" and "disqualified" be omitted from §22.3(f)(2) and §22.3(f)(4), which govern the recusal of commissioners. OPUC provided draft language consistent with its recommendation.

Commission response

The commission agrees with OPUC and implements the recommended changes and either deletes the terms "disqualification" and "disqualified" or replaces those terms with "recusal" or "recused" where appropriate.

Proposed §22.4- Computation of Time

Proposed §22.4 establishes the process for computing time under Chapter 22, by commission order, or any applicable statute.

Proposed §22.4(a)- Counting Days

Proposed §22.4(a) states that, for purposes of computing time, "the period begins on the day after the act, event, or default in question. The period concludes on the last day of the designated period unless that day is not a working day, in which event the designated period runs until the end of the next working day."

OPUC recommended proposed §22.4(a) additionally specify the procedure for counting days prior to the occurrence of an act or event. OPUC stated that, in some commission proceedings, deadlines may fall before an event occurs. For clarity, OPUC recommended the rule establish how deadlines occurring prior to a specified event or action. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. The current methodology for counting days under §22.4 is sufficient for commission matters. Furthermore, the addition of a separate methodology for counting days may lead to confusion and errors in scheduling or meeting deadlines for commission staff, stakeholders, and parties to contested cases.

OPUC recommended the filing deadline be 3:00 P.M. as the general public may view 5:00 P.M. as the end of the next working day.

Commission response

The commission declines to implement the recommended change. The revision to the 5:00 P.M. filing deadline is consistent with general filing changes made to §22.71 and §22.72 under Project 52059 and reflected in the Chapter 22 rules in this rule review. However, the commission revises the deadline to align with the "Central Prevailing Time" time zone for consistency with §22.71 and §22.72.

Proposed §22.4(b)- Extensions

Proposed §22.4(a) authorizes the presiding officer to, unless otherwise provided by statute, extend the time to file any documents upon the filing of a motion and prior to the expiration of the applicable period of time on a showing of good cause and that the need for extension is not caused by "the neglect, indifference, or lack of diligence of the party making the motion."

LCRA recommended proposed §22.4(b) be revised to authorize party-agreed extensions of time subject to rejection or modification by the presiding officer. LCRA stated that the proposed rule only authorizes the presiding officer to grant extension of time but noted that there may be instances where parties may independently reach an agreement to extend time amongst each other, therefore rendering the involvement of the presiding officer unnecessary. LCRA provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change. Any party is authorized to seek an extension of time and the agreement between one or more parties improves the odds of approval by the presiding officer. However, as the adjudicator charged with the timely resolution of commission proceedings, the presiding officer retains discretion on whether to grant an extension even if the request is supported by multiple parties.

Proposed §22.21- Meetings

Proposed §22.21 establishes the general procedural and scheduling requirements for open meetings held by the commissioners.

Proposed §22.21(a)- Time and Place of Open Meetings

Proposed §22.21(a) establishes that "[t]he commission will meet at times and places to be determined either by the chairman of the commission or by agreement of a majority of the commissioners."

OPUC recommended proposed §22.21(a) be revised to refer to the chairman's designee rather than by agreement of a majority of the commissioners. OPUC stated the proposed language could result in a "walking quorum" that violates the Texas Open Meetings Act.

Commission response

The commission declines to implement the recommended change. The commissioners do not need to meet and deliberate over matters under the commission's jurisdiction to coordinate suitable dates for open meetings. For example, the commissioners can provide OPDM with available dates for open meetings without conferring with each other on when to schedule open meetings. Therefore, the proposed language poses no risk of violating the Texas Open Meetings Act.

Proposed §22.52 and §22.53- Notice in Licensing Proceedings and Notice of Regional Hearings

Proposed §22.52 establishes the requirements for notice in electric and telephone licensing proceedings held at the commission. Proposed §22.53 establishes the requirements for notices of regional hearings held by the commission.

Proposed §§22.52(a)(1), 22.52(a)(1)(B), 22.52(a)(1)(D) and §22.53- Publication of notice and proof of publication of notice in electric licensing proceedings; Notice requirements for regional hearings

Proposed §22.52(a)(1) requires an applicant for an electric licensing proceedings to publish notice of the applicant's intent to secure or amend a certificate of convenience and necessity "on the applicant's website and through an appropriate medium of communication, such as social media, that is generally available in the county or counties where a certificate of convenience and necessity is being requested" on the day the application is filed. The provision also requires the notice published on the applicant's website to be "easily locatable from the homepage of the applicant's website and published for the duration of the proceeding." Proposed §22.52(a)(1)(B) requires the notice to must describe in clear, precise language the geographic area for which the certificate is being requested and the location of any alternative routes of the proposed facility. Proposed §22.52(a)(1)(D) requires proof of publication of notice to be in the form of an affidavit that specifies "each medium of communication in which the notice was published, the county or counties in which each medium of communication is generally available, the dates upon which the notice was published, and a copy of the notice as published." The provision also requires proof of publication to be submitted to the commission as soon as is available and for proof of notice on a utility's website to be in the form of an affidavit that includes the hyperlink identifying the webpage "on which the notice can be viewed, the date upon which the notice was first published, and a copy of the notice as published."

Oncor recommended that proposed §22.52(a)(1) and proposed §22.53 specify each commission-authorized method for publishing notice for licensing proceedings, as the existing rule does. Oncor stated that the absence of prescribed methods for providing notice risks and encourages unnecessary litigation. Oncor explained that parties to a licensing proceeding may "constantly question whether utilities provided adequate notice or whether a utility incurred excessive costs to provide notice in a particular manner (as in a newspaper) that could have been avoided with a different method of notice." Oncor stated that its comments and recommendations also extend to the proof of publication of notice requirements under proposed §22.52(a)(1)(D). Oncor provided draft language consistent with its recommendation.

Commission response

The commission declines to proceed with its proposed revisions to §22.52 and §22.53 to replace newspaper notice for licensing proceedings and regional hearings with notice by social media or website notice. Therefore, the proposed recommendations are rendered moot. The commission will consider alternatives to notice by newspaper in a later rulemaking. The commission also revises §22.52(a)(1)(B) to specify "the location of any alternative routes of the proposed facility using route segments proposed by the applicant."

Oncor and LCRA opposed social media being included in proposed §22.52 and proposed §22.53 as a method of notice and recommended it be removed. Oncor expressed concern about social media being a prescribed method of notice. Specifically, Oncor indicated that, while it does not oppose notice through social media for proceedings that would broadly impact its end-use customers, there may be practical concerns with using social media to publish notice for proceedings that impact a narrower spectrum of Oncor's customers or proceedings that impact individuals that may not be customers of Oncor, such as individuals affected by minor CCN proceedings that cross distribution territory not covered by Oncor. Similarly, LCRA acknowledged that newspaper or community-specific outreach methods may be more effective in reaching the intended audiences, particularly for utilities with large or rural service territories. LCRA also noted that the information required under §22.52(a)(1)(B) is not easily published or read on social media websites. LCRA stated that, as a political subdivision of the State of Texas, it is prohibited from using certain popular social media platforms "in the interest of protecting its resources and infrastructure, consistent with the directives issued by the State of Texas and the Office of the Governor." Oncor explained that social media or other direct communications to end-use customers concerning matters that do not impact them whatsoever could lead to "notification fatigue" and therefore had the unintended consequence of leading those customers to not follow or ignore Oncor's social media posts. Oncor further noted that notification through social media would "create confusion as to the manner and timing for interested parties to provide feedback to and ask questions of the utility" such as the time period for landowners to notify the utility of any obstructions. Oncor emphasized that the best practice for managing such feedback from interested parties is the current process of direct interaction with utility staff who are appropriately trained to respond and analyze that feedback. Oncor commented that a utility will possess dates by which other information is needed from interested parties, and if a response is received past those dates, it will accordingly be too late to incorporate it into CCN routing decisions. Oncor stated that publication of notice on a social media platform could accordingly "confuse and delay these other important communications."

Commission response

The commission declines to proceed with its proposed revisions to §22.52 to replace newspaper notice for licensing proceedings with notice by social media or website notice. Therefore, the proposed recommendations are rendered moot. The commission will consider alternatives to notice by newspaper in a later rulemaking.

Oncor alternatively recommended that proposed §22.52(a)(1) and proposed §22.53 clarify that, if social media remains a required method of notice for CCN or other licensing proceedings despite the concerns Oncor has raised, then "temporary delays in, and temporary removals of, social media notice publications [be] permitted when necessary to prioritize significant storm- or emergency-related notifications to customers." Oncor commented that another concern with notice through social media is that in emergency situations, such as notifications issued by Oncor before and after a storm occurs, all social media advertisements unrelated to the emergency or safety are temporarily removed from circulation to ensure that only emergency-related communications are issued to customers during the crisis. Oncor stated this practice prevents unrelated communications from interfering with or distracting from any critical or time-sensitive customer communications. Oncor indicated, however, that this practice during emergencies could hinder Oncor's ability to "timely publish initial notice per the timeline required and/or to publish continuous notice for the required length of time."

Commission response

Oncor recommended that proposed §22.52 and proposed §22.53 authorize at least one working day after the filing of licensing application for the applicant to publish notice of the application, particularly if publication through social media remains an authorized method of notice. Oncor agreed that a full week to publish notice of the licensing application is not necessary if one or more internet-based methods of notice are to be used to publish the required notice. However, Oncor indicated that due to the possibility for CCN applications to be filed late in the day, it may be problematic to require the applicant to provide internet notice on the same day of filing.

Commission response

Oncor also recommended that, if newspaper notification continues to be required under proposed §22.52 and proposed §22.53, then the current one-week timeframe to provide such notice be retained.

Commission response

The commission agrees with Oncor and preserves the existing one-week timeframe for newspaper notice.

Oncor recommended that, if proposed §22.52 and proposed §22.53 authorize any internet-based method of notice, then the rule be revised to clarify that it is not necessary to clarify that notice is "generally available in the county or counties where a CCN is being requested." Oncor noted that this requirement may still be appropriate if a non-internet based medium of communication, such as newspaper publication, remains a requirement. However, Oncor indicted that preserving the county-availability requirement even if newspaper notice is retained would "create questions and ambiguities if it also applies to notification provided on an internet website or platform available to anyone who has internet access."

Commission response

Oncor further recommended conforming revisions to proposed §22.52(a)(1)(D) and proposed §22.53. Specifically, Oncor recommended the deletion of the requirement for the affidavit to specify "each medium of communication in which the notice was published, the county or counties in which each medium of communication is generally available."

Commission response

OPUC opposed eliminating the newspaper publication requirement for notice of licensing proceedings in proposed §22.52 and recommended the requirement be preserved with the addition of the term "periodical." OPUC generally opposed website and social media publication replacing a newspaper notice requirement, but did not oppose having website publication as an additional notice requirement. OPUC stated that the elimination of newspaper notice for licensing proceedings would disproportionately impact persons without internet access, which may include persons of low economic status or the elderly that rely primarily on newspapers or periodicals for news. OPUC commented that the proposed rule change would effectively mean individuals without internet access would be unaware of the occurrence of electric licensing proceedings or their procedural rights despite other commission rules, such as §22.106, expressly recognizing that not all persons affected by commission proceedings may have internet access.

Commission response

The commission agrees with OPUC and retains newspaper notice for licensing proceedings. However, the commission declines to extend notice by newspaper to periodicals without further investigation. The commission will consider alternatives to notice by newspaper in a later rulemaking.

OPUC recommended that the publication of notice on the utility's website should be presented in an easily accessible location and require no more than two clicks to locate the notice from the applicant's homepage.

Commission response

The commission declines to proceed with its proposed revisions to §22.52 to replace newspaper notice for licensing proceedings with notice by social media or website notice. Therefore, the proposed recommendation is rendered moot. The commission will consider alternatives to notice by newspaper in a later rulemaking.

OPUC further commented that the terms "appropriate medium of communication," "social media," and "generally available" are ambiguous and therefore are detrimental to the public interest and market participants. OPUC emphasized that the factors or standards for determining accessibility of an appropriate medium are unclear, including who would determine the appropriate medium. OPUC questioned what social media applications or forums would be acceptable under proposed §22.52(a)(1), such as those prohibited for state agencies or employees. OPUC posed other hypothetical questions regarding the accessibility of social media to certain stakeholders such as landowners or other interested parties, as well as the quantifiability of the term "generally available."

Commission response

The commission acknowledges OPUC's concerns regarding the potential ambiguity of language relating to the issuance of notice. Given the commission's decision to retain newspaper notice for licensing proceedings, the commission will take OPUC's recommendations under consideration in a later rulemaking.

OPUC recommended that posting notice to social media under §22.52(a)(1) should be optional, not a requirement. OPUC further recommended that it should not take the place of "other more reliable methods to communicate with consumers who may not have internet or access to social media platforms." OPUC remarked that, due to the constantly changing nature of technology, a social media forum that enjoys widespread use today may not be as popular months later. OPUC stated that utilities may use different social media platforms to communicate with customers. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to proceed with its proposed revisions to §22.52 to replace newspaper notice for licensing proceedings with notice by social media or website notice. Therefore, the proposed recommendation is rendered moot. The commission will consider alternatives to notice by newspaper in a later rulemaking.

Proposed §22.52(a)(1)(D) and 22.52(b)(1)- Publication of notice in telephone licensing proceedings

Proposed §22.52(b)(1) requires an applicant for a telephone licensing proceeding to, on the day the application is filed with the commission, publish notice of the applicant's intent to secure or amend a certificate of convenience and necessity "on the applicant's website and through an appropriate medium of communication, such as social media, that is generally available in the county or counties where a certificate of convenience and necessity is being requested." The provision also requires the notice published on the applicant's website to be easily locatable from the homepage of the applicant's website, published for the duration of the proceeding, and identify the commission's docket number and the style assigned to the case by Central Records.

In conjunction with its recommendations for proposed §22.52(a)(1), OPUC recommended conforming revisions to proposed §22.52(a)(1)(D) and §22.52(b)(1). OPUC also recommended §22.52(b)(1) be split into three provisions, each applying to the notice of the application, the contents of the notice, and the proof of notice. Specifically, OPUC recommended the proof of notice affidavit be clarified as a "publisher's affidavit" that must specify "each newspaper or periodical" in which the notice was published in proposed §22.52(a)(1)(D) and new §22.52(b)(3).

Commission response

The commission declines to implement the restructuring changes recommended by OPUC at this time. The commission may consider reorganizing the provision in a later rulemaking. The commission also revises §22.52(b)(1) to require the notice to identify the commission's docket control number and the style assigned to the case by Central Records to mirror the same requirement under §22.52(a)(1). The commission further revises the template notice language for telephone licensing proceedings under §22.52(b)(1) by replacing the specific telephone numbers for the commission and Relay Texas with a parenthetical for inserting updated telephone information for each notice so that the rule does not require amendment in the event those numbers change. Accordingly, a telephone utility must insert the current commission toll free number and Relay Texas number when issuing notice.

OPUC also recommended proposed §22.52(a)(1)(D) and new §22.52(b)(3) be revised to require the proof of notice affidavit to include the date and time that the copy of the notice was printed from the website. OPUC stated that, to ensure applicants are actually publishing notice of the application the same day the application was filed, the applicant should be required to take a date-stamped screenshot or printed image of the published notice on the applicant's website.

Commission response

OPUC further recommended proposed §22.52(a)(1)(D) and new §22.52(b)(3) be revised to explicitly require the proof of notice affidavit to be signed by the utility officer that submitted the application. OPUC provided draft language consistent with its recommendations.

Commission response

The commission declines to implement the recommended change. The utility officer signing the affidavit may not necessarily be the person with personal knowledge regarding all facts contained in the affidavit. A utility should retain discretion to select the affiant who must demonstrate personal knowledge through the affidavit.

SPS and TAWC recommended §22.52(a)(1) be revised to state that "the applicant must [provide] notice of the applicant's intent to secure or amend a certificate of convenience and necessity…" for clarity.

Commission response

The commission agrees with SPS and TAWC and implements the recommended change.

LCRA recommended that proposed §22.52(a)(1) be revised to authorize a utility to issue notice in advance of filing an application in licensing proceedings. Specifically, LCRA recommended a utility be authorized to post notice on its website up to 25 days prior to filing its CCN application with the commission. LCRA stated that limiting the issuance of notice to only the day of filing is overly rigid and limits a utility's flexibility in providing advance notice prior to filing its application. LCRA provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change. The proposed revision would require the active monitoring of the Interchange by interested parties for when the application will be filed. Before application filing, interested persons might wish to intervene, but there would be no contested case to allow for intervention. Moreover, the proposed rule does not prohibit an applicant from making a disclosure or announcement on its website prior to filing the application. The rule only requires publication on the date the application is filed.

LCRA recommended that proposed §22.52(a)(1) be revised to authorize joint applicants in licensing proceedings to share a website for the publication of notice associated with licensing proceedings. As an example, LCRA referenced that the 765 kilovolt transmission line development associated with the Permian Basin infrastructure projects may see efficiencies in providing joint notice on a single website. LCRA provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change as it could bring about potential disputes as to responsibility and liability for the joint notice. The commission will consider investigating joint notice and note it for potential review in a future rulemaking.

SPS recommended proposed §22.52(a)(1)(D) be revised for clarity. Specifically, SPS recommended the provision state: "Proof of publication of notice for notice provided on a utility's website must be in the form of an affidavit that…." SPS stated that the provision, as proposed, is ambiguous because it could be "interpreted to mean that the proof of notice itself is on the website." SPS commented that the language is likely intended to establish additional requirements for the proof of publication for notice published on a utility's website. SPS provided draft language consistent with its recommendation.

Commission response

The commission declines to proceed with its proposed revisions to §22.52 to replace newspaper notice for licensing proceedings with notice by social media or website notice. Therefore, the proposed recommendation is rendered moot. The commission will consider alternatives to notice by newspaper in a later rulemaking.

Proposed §22.52(a)(2) and 22.52(a)(4)- Notice to municipalities, neighboring utilities, and other entities

Proposed §22.52(a)(2) establishes the requirements for an applicant to mail notice of its application to certain entities such as the Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse on the date it files an application. Proposed §22.52(a)(4) requires an applicant to hold a public meeting prior to the filing of its licensing application if 25 or more persons would be entitled to receive direct mail notice of the application. Proposed §22.52(a)(4) also requires that direct mail notice of the public meeting must be sent by first-class mail to certain entities such as the Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse. Proposed §22.52(a)(4) further requires the applicant to provide written notice to "the Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse of the planned filing of an application prior to completion of the routing study" if no public meeting is held.

Oncor recommended proposed §22.52(a)(2) and §22.52(a)(2) (a)(4) be revised to state: "and the Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse or similar entity as designated by the Department of Defense…." Oncor stated that this revision would account for instances where it has been requested or required to issue notice to an entity of the Department of Defense other than that Military Aviation and Installation Assurance Siting Clearinghouse in specific proceedings. Oncor provided draft language consistent with its recommendation.

Commission response

The commission agrees with Oncor and implements the recommended change.

Proposed §22.52(a)(3) and 22.52(a)(3)(D)- Notice to landowners and issuance of notice prior to final approval

Proposed §22.52(a)(3) establishes the requirements for the applicant to mail notice of its application to directly affected landowners within a certain distance of the transmission project on the date it files an application. Proposed §22.52(a)(3)(D) requires an applicant to notify directly affected landowners of any modification to a transmission route prior to final approval. The provision authorizes proof of notice to be established by an affidavit that affirms that the applicant issued notice by first class mail to each directly affected landowner as listed on the current county tax rolls.

OPUC recommended proposed §22.52(a)(3) and §22.52(a)(3)(D) to require notice of a licensing application and notice prior to commission approval, respectively, be issued to landowners in accordance with the most current tax appraisal rolls of the applicable central appraisal district at the time the utility commission received the application for the certificate or amendment. OPUC stated that this requirement is located in Texas Water Code §13.246(a-1), not in PURA. OPUC acknowledged that, while the Texas Water Code is inapplicable, "the statute does establish precedent for protocol the legislature considered adequate for CCN applicants to notify landowners." OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. The commission is not aware of any issues with the current notice process that warrants such a revision. Moreover, the rule provision as proposed entitles directly affected landowners to notice, which more accurately identifies persons with a justiciable interest compared to those landowners on the county tax rolls as of a particular date.

Proposed §22.74- Service of Pleadings and Documents

Proposed §22.74 establishes the requirements and procedures for each authorized method of service of pleadings and documents submitted to the presiding officer that must also be filed with the commission and served on other parties.

Proposed §22.74(b) and 22.74(c)- Methods of service and alternative methods of service

Proposed §22.74(b) establishes the requirements for service of a copy of a pleading or document to "the party's authorized representative or attorney of record by email; in person; by agent; by courier receipted delivery; by first class mail; by certified mail, return receipt requested; or by registered mail to such party's address of record." Proposed §22.74(c) establishes the requirements for alternative methods of service if a person has filed a statement of no access under §22.106 of this title, relating to Statement of No Access. Specifically, the provision requires service on such persons to be "made by delivery of a copy of the pleading or document to the party or the party's authorized representative or attorney of record either by hand delivery; by courier receipted delivery; by first class mail; by certified mail, return receipt requested; or by registered mail to such party's address of record."

SPS recommended the authority for the presiding officer to order "service by filing" under existing §22.74(c) be retained in proposed §22.71(b). SPS stated that the omission of this option renders it unclear as to when such service is authorized.

Commission response

The commission agrees with SPS and implements the recommended change. The commission generally reorganizes §22.74(b) and (c) for clarity. Specifically, the commission revises §22.74(b)(1)-(5) to specify when the standard methods of service are deemed complete. Such standards methods of service are: in-person service; service by e-mail; service by mail; service by agent or courier receipted delivery; or service by in-person delivery. The commission also differentiates the alternative method of service that may be approved by the presiding officer, including service by filing, under §22.74(c). The commission further specifies that service by filing is complete upon acceptance for filing on the Interchange.

Proposed §22.74(b)(1)- Service by e-mail

Proposed §22.74(b)(1) establishes that service by e-mail is complete "upon sending an email message with the pleading or document attached to the message to the email address of record for the party that was provided."

Oncor recommended revising proposed §22.74(b)(1) to state that service by e-mail is deemed complete upon e-mailing the link to the document where it is hosted on the Commission's Interchange. Oncor commented that this revision would mirror language in proposed §22.74(b)(2) that authorizes the same for service with notice. Oncor stated that the ability to effectuate service in this manner is extremely useful, particularly when the filing party may be serving voluminous filings on several other parties that may otherwise be too large to attach to e-mail. Oncor provided draft language consistent with its recommendation.

Commission response

The commission agrees with Oncor and implements the recommended change. As stated previously, the commission generally reorganizes §22.74(b) and (c) for clarity.

OPUC recommended revising proposed §22.74(b)(1) to qualify service by e-mail being deemed complete once received by the person being served. OPUC indicated that, in some instances, a person may send an e-mail message, but the e-mail has not left the sender's outbox. Accordingly, OPUC recommends that an e-mail be considered served when the sent e-mail leaves the sender's sent or outbox folder, not when the person clicks "send." OPUC provided draft language consistent with its recommendation: "Service by email is complete upon sending an email message with the pleading or document attached to the message to the email address of record for the party that was provided by the person being served."

Commission response

The commission declines to implement the recommended change. The revision would change the point in time when service is deemed to have been issued to the time of receipt by the person being served. This would invite disputes involving if and when the recipient actually received the e-mail. Additionally, such a change is inconsistent with the commission's current practice. The commission notes that the time an e-mail is actually sent should be the time of issuance for purposes of service, not when the email is placed in an outbox or something similar.

Proposed §§22.74(b), 22.74(c)(1), and 22.74(c)(2)- Service by mail and service by agent or by courier receipted delivery

Proposed §22.74(c)(1) establishes that service by mail is complete "upon deposit of the document, enclosed in a wrapper properly addressed, stamped and sealed, in a post office or official depository of the United States Postal Service, except for state agencies. For state agencies, mailing will be complete upon deposit of the document with the General Services Commission." Proposed §22.74(c)(1) establishes that service by agent or by courier receipted delivery is complete upon delivery to the agent or courier.

SPS recommended the directions as to when alternative methods of service, such as mail and courier service, be moved from proposed §22.74(c)(1) and §22.74(c)(2) back into proposed §22.71(b). SPS stated that since §22.71(b) refers to the available options for service, each provision governing the directions for such service should therefore be in the same provision.

Commission response

The commission agrees with SPS and implements the recommended change. As stated previously, the commission generally reorganizes §22.74(b) and (c) for clarity.

Proposed §22.74(b)(3)- Service by filing without notice

Proposed §22.74(b)(3) establishes that service without notice is complete upon filing with Central Records. The provision further establishes that, if service without notice is required, "the presiding officer may encourage parties to sign up with the commission's Filings Notification System on its website to receive automatic notifications of filings in the docket."

OPUC strongly opposed the addition of proposed §22.74(b)(3) on the basis that service by filing without notice should never be permissible. OPUC emphasized that parties and residential intervenors require notices since they are unfamiliar with commission rules or procedures, particularly in rate cases. OPUC commented that the commission is obligated to protect "the public interest inherent in the rates and service of public utilities" and that serving a party or intervenor without notice directly conflicts with that obligation and should therefore be removed as an option.

Commission response

The commission declines to implement the recommended change. The commission agrees that service by filing should not be the default form of permissible service, however extraordinary circumstances may warrant a presiding officer finding good cause exists to permit service by filing on a case-by-case basis. (e.g., when the service list has hundreds of parties). The commission also generally reorganizes §22.74(b) and (c) for clarity.

Proposed §22.74(c)(1)- Service by mail

OPUC recommended that proposed §22.74(c)(1) be revised to state that service by mail or commercial delivery service is complete upon deposit of the document, postpaid and properly addressed, in the mail or with a commercial delivery service. OPUC stated this language mirrors the Rule §21(b)(1) of the Texas Rules of Civil Procedure.

Commission response

The commission agrees with OPUC and implements the recommended change.

Proposed §22.74(c)(2)- Service by agent or by courier receipted delivery

OPUC recommended that the reference to the General Services Commission should be removed from §22.74(c)(2) because that agency was abolished in 2001 by Senate Bill 311, which was passed in the 77th Legislative session.

Commission response

The commission agrees with OPUC and implements the recommended change. Specifically, the commission omits the reference to the General Services Commission in the reorganized provision.

Proposed §22.75- Examination and Correction of Pleadings and Documents

Proposed §22.75 establishes the requirements for the examination and correction of pleadings and documents filed with the commission.

Proposed §22.75(a)- Construction of pleadings and documents

Proposed §22.75(a) requires all pleadings and documents to be construed so as to do substantial justice.

OPUC and TAWC recommended reinserting the word "be" in §22.75 as it appears to have been inadvertently deleted: "All pleadings and documents must be construed so as to do substantial justice."

Commission response

The commission agrees with OPUC and TAWC and implements the recommended change.

Proposed §§22.75(c), 22.75(c)(1)-(3), 22.75(d), and 22.75(d)(2)-(3)- Notice of material deficiencies in rate change applications and applications for certificates of convenience and necessity for electric transmission lines

Proposed §22.75(c) establishes the requirements for notices of material deficiencies in rate change applications filed under PURA Chapter 36, Subchapter C, or Chapter 53, Subchapter C. Proposed §22.75(c)(1) authorizes the presiding officer to require a document that does not comply with §22.72 of this title to be re-filed. Proposed §22.75(c)(1) further states that a motion for rehearing or a reply to a motion for rehearing that is required to be re-filed will retain the original filing date. Proposed §22.75(c)(2) establishes that, if the presiding officer determines that a material deficiency exists in the rate change application the presiding officer must issue a written order specifying a time within which the applicant must amend its application and correct the application. Proposed §22.75(d) establishes the requirements for notices of material deficiencies applications for certificates of convenience and necessity for electric transmission lines. Proposed §22.75(d)(2) establishes that, if the presiding officer determines that a material deficiency exists in the certificate application the presiding officer must issue a written order specifying a time within which the applicant must amend its application and correct the application.

OPUC recommended that the applicability of §22.75(c) regarding notice of material deficiencies be revised to extend to rate change applications under Texas Water Code Chapter 13, Subchapter F and the applicable subsequent proceedings under Subchapter E. OPUC stated that extending the requirements to water rate proceedings would create uniformity in commission procedures in rate proceedings.

Commission response

The commission declines to implement the recommended change because it is out of scope. Substantive changes to this provision were not proposed that would extend the applicability of this provision to another industry. The commission also deletes the sentence "a motion for rehearing or a reply for a motion for rehearing that is required to be re-filed will retain the original filing date" from §22.75(b)(1) to ensure consistency with the filing rules.

Oncor, SPS, and LCRA opposed the deletion of existing §22.75(c)(2) and §22.75(d)(2) which respectively require the automatic determination of sufficiency for rate applications and CCN proceedings where the presiding officer has not issued a written order concluding that material deficiencies exist within 35 days of the filing of the application. Oncor, SPS, and LCRA also opposed the deletion of the requirement for the presiding officer to issue a written order within 35 days of the filing of the rate or CCN application if the presiding officer determines a material deficiency exists under §22.75(c)(3) and §22.75(d)(3), respectively. Oncor and SPS emphasized the need for certainty among applicants and other parties that late determinations will not be made regarding material deficiencies in rate proceedings or CCN applications. Oncor stated that the proposed revisions not only remove the potential for applications to be automatically deemed sufficient if the presiding officer has not made a finding of material deficiency within the 35-day deadline, but also authorizes the presiding officer to determine that a rate or CCN application is materially deficient at any point in time. Oncor also observed that, because §22.75(c)(3) and §22.75(d)(3) still require statutory deadlines to be calculated based on the date of filing a sufficient application, the deletion of the 35-day timeline under makes it difficult for an applicant or other parties to a rate or CCN proceeding to calculate such deadlines due to the constant risk of an application being deemed insufficient months after filing and after a procedural schedule has been issued by the presiding officer. SPS and LCRA remarked that the existing 35-day timeline appropriately balances the need for the presiding officer to have sufficient time to review rate and CCN applications while providing the requisite certainty among applicants and preventing unnecessary delays in processing the applications. LCRA noted that the proposed revisions have a high likelihood of risking the indefinite delay of rate and CCN applications which undermine efficiency and predictability of the commission's processes surrounding these proceedings and therefore would result in additional regulatory lag. As an alternative, Oncor recommended that the final sentence of §22.75(c)(3) be revised to state that statutory deadlines "will be calculated based on the date of filing the application" instead of the "date of filing the sufficient application," with additional language authorizing the tolling or extension of a statutory deadline if the presiding officer later determines a material deficiency in the rate application. Oncor provided draft language consistent with its recommendations. Oncor also opposed the deletion of the requirement for the presiding officer to issue a written order regarding a material deficiency in a CCN application filed under PURA §39.203(e) within the 28-day deadline from the date an application is filed for similar reasons.

Commission response

The commission disagrees with commenters and declines to implement the recommended change. A determination that an application is sufficient by commission inaction does not serve the public interest and is an extraordinary outcome that is inconsistent with commission standard practice. The only instances in which the commission complies with such a practice is when required by statute.

Proposed §22.76- Amended Pleadings

Proposed §22.76 establishes the requirements for amending pleadings in proceedings before the commission.

New §22.76(a)(5)

Oncor recommended new §22.76(a)(5) be added which would authorize a pleading amendment that was either unanimously agreed upon by the parties or unopposed by other parties without a showing of good cause and regardless of whether the amendment is made within seven days of the hearing date. Oncor stated that the existing rule requires a party to show good cause for amending a pleading within seven days of a hearing yet still provides the presiding officer with discretion to deny such a request. Oncor indicated, however, that if all parties agree to permit a pleading amendment, then the amendment is therefore not adverse to any party and therefore should not require a showing of good cause. Oncor provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. If good cause exists for a late pleading amendment, the presiding officer may grant it. If the pleading amendment is not granted by the presiding officer, it will not matter that all of the parties are unopposed to the amendment. The purpose of the seven-day requirement is, in part, to provide sufficient time for the presiding officer and the parties to the proceeding to adequately prepare for a hearing.

Proposed §22.77- Motions

Proposed §22.77 establishes the requirements for motions filed in proceedings before the commission.

Proposed §§22.77(a), 22.77(a)(3) and new §22.77(a)(4)- General requirements and certificate of conference

Proposed §22.77(a) establishes the general requirements for motions, including a requirement that the motion must be in writing unless the motion is made on the record at a prehearing conference or hearing and that the motion must state the relief sought and the specific grounds supporting a grant of relief.

Proposed §22.77(a)(3) requires a written motion to include a certificate of conference that substantially complies with either of the examples provided under §22.77(a)(3)(A) or (B).

TAWC and LCRA recommended the requirement for a certificate of conference should be limited only to certain types of motions, such as schedule or discovery-related motions. TAWC stated that a conference should not be required in instances where there will likely be no agreed resolution, such as when a party believes a request to intervene should be denied, a pleading be struck, or sanctions imposed. LCRA stated that universally requiring all motions to include a certificate of conference would be burdensome and that limiting the requirement to discovery, procedural, and scheduling motions is consistent with current commission practice. LCRA provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change. A certificate of conference is necessary for the presiding officer to know whether the motion is opposed. Moreover, the certificate of conference also requires parties to speak with opposing parties to attempt to reach agreement before involving other parties and the presiding officer.

New §22.77(a)(3)(D)-(E)

Oncor recommended the requirement for all motions to include a certificate of conference under proposed §22.7(a)(3) should either be eliminated or substantially narrowed. Oncor stated the proposed requirement poses difficulties in certain proceedings, such as in multi-party proceedings like rate cases or CCN proceedings where there may be dozens of parties. Oncor remarked that the proposed change would require the moving party to "attempt to confer with each respective party and to document each conference or attempt to confer in this certificate." Oncor indicated that in such proceedings, attempting to confer with every other party "could take hours or even days" and therefore prevent the obligated party to file motions close to the deadline despite the need for relief becoming apparent around that time. Oncor commented that there are circumstances where the moving party may be seeking relief that may only potentially negatively impact one or several parties but would not impact every other party. By way of example, Oncor stated that an obligation to confer with "party X regarding the movant' s request to strike testimony filed by party Y" would be unnecessary. Similar to Oncor, SPS commented that parties should only be required to confer with those directly affected by the motion in multi-party cases. Oncor alternatively recommended exemptions to the certificate of conference requirement be added as new §22.71(a)(3)(C)-(E) if the requirement for a certificate of conference is retained. Oncor commented that the exemptions would authorize the movant to not provide a certificate of conference in the following circumstances: (1) when there is insufficient time to confer with other parties due to the urgent nature of the relief sought and the time necessary to seek such relief; (2) when the relief sought only impacts the rights of one or more specific parties, but not all other parties - only those parties whose rights were impacted were conferred with; and (3) the movant offered to hold a conference with all parties, but no other parties elected to confer.

Commission response

The commission modifies the provision to narrow the certificate of conference requirement. Specifically, the commission revises the provision such that a movant is required to confer with all parties that could be affected by the motion or pleading, but not all parties to the proceeding (e.g., a motion to compel should require conference with the party who would be compelled, but not all other parties in the proceeding).

Proposed §22.78- Responsive Pleadings and Emergency Action

Proposed §22.78 establishes the general requirements for responsive pleadings and emergency action by the presiding officer.

Proposed §22.78(c)- Action by the presiding officer

Proposed §22.78(c) authorizes the presiding officer to take action on a pleading before the deadline for filing responsive pleadings unless otherwise precluded by law or Chapter 22. The provision also establishes that such action may be subject to modification based on a timely responsive pleading.

SPS opposed the revision to §22.78(c) that presumes all pleadings are received on the date of filing, regardless of the method of service used. SPS commented that the presumption that all pleadings are received on the filing should only apply if e-mail is the required method of service. Vistra similarly recommended proposed §22.78(c) retain the five-day presumption of receipt of a pleading prior to the beginning of the five-working day window to file a responsive pleading. Vistra noted that the proposed language establishes a presumption that all pleadings are received as of the filing date, unless the presiding officer is advised otherwise. Vistra commented that, in addition to preserving the five-day period for receiving a pleading, the five-working day window to file a responsive pleading should begin once the pleading to which the response is made is received, which may not necessarily be the filing date. Vistra provided redline language consistent with its recommendation.

Commission response

The commission declines to implement the recommended changes as they are unnecessary. All pleadings served by e-mail should be presumed to be received on the filing date. All other forms of service should have a presumption that the pleading was received within three days.

OPUC, Oncor, Vistra, SPS, and TAWC recommended that the presiding officer should withhold ruling on a pleading until all arguments from other parties have been presented. OPUC, Oncor, Vistra, and TAWC opposed the removal of language in proposed §22.78(c) that would limit a presiding officer to act on a pleading prior to the responsive pleading deadline only "when necessary to prevent or mitigate imminent harm or injury to persons or to real or personal property." OPUC commented that the removal of this language would broadly expand the presiding officer's ability to rule on initial pleading without providing other parties an opportunity to respond. OPUC stated that the importance of conducting efficient proceedings should not sacrifice a consumer's due process and representation rights before the commission. OPUC noted that this may have unique impacts on ratepayer intervenors and consumers that are already unfamiliar with commission rules and SOAH processes. OPUC noted that the general deadline to file a response to a pleading is five working days under §22.78(a) and 21 days under §22.78(b) to respond to complaints. OPUC remarked that the average consumer is unfamiliar with the commission's filing deadlines and, in effect, is very likely to have less time to respond. OPUC noted that, in turn, it would undermine the public interest by limiting ratepayer participation in most commission and SOAH proceedings. OPUC further commented that the proposed change could "have the same implications as ex parte communications" as the presiding officer would potentially only be hearing the position of the filer of the pleading and not the positions of other parties to the proceeding that may respond. OPUC provided redline language consistent with its recommendation. Similar to OPUC, Oncor commented that the proposed revision to §22.78(c) would negate the five-working day responsive pleading deadline under §22.78(a) unless otherwise specified by statute. Oncor explained that if a presiding officer rules on a motion prior to the responsive pleading deadline, the presiding officer would effectively negate a party's ability to respond within five working days. Like OPUC, Oncor noted that such a ruling by the presiding officer would be premature because it does not afford all other parties an opportunity to respond and the presiding officer would only hear one side of the argument before issuing an order. Oncor further recommended that, regardless of whether the provision is amended to allow premature rulings prior to the deadline for responsive pleadings outside of emergency situations, the rule should "continue to require the presiding officer to consider the potential need to modify the premature action on the pleading once a timely responsive pleading is subsequently filed." Oncor provided redline language consistent with its recommendation. Vistra commented that retaining the existing language would "preserve the rights of parties who file responsive pleadings and would retain the effective function of a responsive pleading deadline." Vistra provided redline language consistent with its recommendation. SPS remarked that the presiding officer waiting to rule on such pleadings until the responsive pleading deadline has passed is both fairer and more efficient. SPS commented that the proposed language risks the presiding officer issuing multiple orders on the same motion due to all arguments not having been presented when the presiding officer initially rules on the motion. SPS further noted that waiting until the responsive pleading deadline has passed before issuing an order prevents parties from filing pleadings that only state the filer intends to respond, which has occurred infrequently in recent years. TAWC commented that the proposed revision is unnecessary and would undermine utilities' due process rights to be heard before a presiding officer acts. OPUC also opposed the revision of the subtitle of proposed §22.78(c) from "Emergency action" to "Action by the Presiding Officer" and recommended the original title be preserved.

Commission response

The commission declines to implement the recommended change. However, the commission retitles the provision to "Responsive Pleadings" for consistency with the proposed revisions. The proposed changes expanded the presiding officer's ability to act on a pleading before the responsive pleading deadline when not otherwise precluded by law. Under the existing language, the presiding officer could only act before the responsive pleading deadline "when necessary to prevent or mitigate imminent harm or injury to persons or to real or personal property." This language sometimes resulted in inefficiencies where parties felt obligated to incur the expense of responding to a frivolous motion and the presiding officer was unable to save the parties such time and expense by denying the motion earlier. If the proposed language were to be adopted, in practice the presiding officer would usually wait until the period for any responses are due and would likely only act if no additional information from the respondent is necessary to act on the motion. Moreover, if a party is aggrieved by the action of a presiding officer, whether rendered before or after the deadline for response, that party may file a motion for rehearing and appeal to the commission, as applicable. Additionally, the corresponding changes to certificates of conference under §22.77 will assist the presiding officer in knowing before the response deadline whether a pleading is opposed. The proposed changes to both this rule and §22.77 will empower the presiding officer to act more expediently on unopposed motions. To OPUC's specific point regarding ex parte communications, acting on a motion, even before the response deadline has passed, is not at all like an ex parte communication. Unlike an ex parte communication, all parties receive the communication contemporaneously to the presiding officer; the communication is filed and therefore available for any person to review; and even if the presiding officer acts before the response deadline, all parties have the opportunity to respond to the communication.

Proposed §22.78(d)- PURA, Chapter 36, Subchapter D or Chapter 53, Subchapter D Investigations or Complaints

Proposed §22.78(d) authorizes the presiding officer to determine the scope of a response that an electric or telecommunication utility is required to file in a complaint proceeding filed under PURA, Chapter 36, Subchapter D or Chapter 53, Subchapter D which may be "up to and including the filing of a full rate filing package." The provision also requires the presiding officer to set an appropriate deadline for the utility to respond.

OPUC recommended proposed §22.78(d) be revised to apply to water-related complaints. OPUC stated that since commission has jurisdiction over providers of water and sewer service, the same complaint procedures should apply, to the extent authorized by statute. OPUC provided draft language consistent with its recommendation.

Commission response

Proposed §22.79- Continuances

Proposed §22.79 establishes the requirements for motions for continuance filed in certain commission proceedings.

Proposed §22.79(c) and §22.79(c)(2)- Requirements for granting motions for continuance

Proposed §22.79(c) establishes the requirements for granting motions for continuance. Proposed §22.72(c)(2) authorizes the presiding officer to grant continuances in a manner consistent with any applicable statutory deadline.

Oncor recommended preserving existing language in §22.79(c)(2) that would require the presiding officer to grant continuances agreed to by all parties. Oncor noted that a motion for continuance that has been unanimously agreed upon by all parties is therefore not adverse to any party. Oncor stated that such language is beneficial as it allows parties to postpone a hearing that all parties agree should not be held yet and provides additional time for settlement and categorically avoids a hearing. In turn, this would save the commission and the parties to a contested case time and resources.

Commission response

The commission declines to implement the recommended change. Many commission proceedings have statutory deadlines and state leadership has expressed the importance of regularly meeting such deadlines. Despite this, parties frequently propose procedural schedules or requests extensions, stays, or abatements that would render it impossible for the commission to meet these statutory deadlines. The proposed revision permits the presiding officer to consider a motion for continuance and restores discretion to the presiding officer that had previously been omitted from the rule.

Proposed §22.80- Commission Prescribed Forms

Proposed §22.80 generally authorizes the commission to prescribe forms for use by the public and by regulated entities.

Oncor and OPUC recommended preserving language from existing §22.80 that would require the commission filing clerk to maintain a complete index of all commission forms along with a set of all commission forms. OPUC and Oncor emphasized the need for a public-facing central repository or index of commission-prescribed forms on the commission website for the benefit of stakeholders and filers. Oncor noted that a utility or other entity may require a form that it has not filed before or has not been used for years. In that event, the potential filer needs to know whether a commission form exists for that type of filing. Oncor further stated that even among routine filers, there is a need for certainty that the most up-to-date version of a commission-prescribed form is being used. Oncor and OPUC commented that intervenors, complainants, and other stakeholders may also want to confirm that a utility or applicant is using the most current version of a commission-prescribed form. OPUC noted that there are several older variants of commission-prescribed forms circulating in the general public, therefore highlighting the benefit of having a central repository of up to date-forms.

Commission response

The commission agrees with Oncor and OPUC that maintaining a complete index of commission-prescribed forms provides value to stakeholders and other members of the public seeking to access a current commission-prescribed form. The commission modifies the rule to include a provision codifying the commission's current practice of maintaining an index of commission-prescribed forms. However, the commission removes the reference to the index being maintained by the commission filing clerk for operational flexibility.

Proposed §22.80(a) and §22.80(a)(2)- Usage of commission-prescribed forms

Proposed §22.80(a) authorizes the commission to require that certain reports and applications be submitted on commission-prescribed forms. Proposed §22.80(a)(2) establishes that any significant change in a commission-prescribed form or a new form will be published in the "In Addition" section of the Texas Register for public comment prior to the implementation of the new form or significant change. The provision also establishes that new forms or significant changes to existing forms may be implemented without publication on an interim basis for a period not to exceed 180 days for good cause.

OPUC recommended deleting language from proposed §22.80(a)(2) that authorizes the implementation of new forms or significant changes to existing forms be implemented for 180 days without publication in the Texas Register. OPUC instead recommended adding language that would authorize the adoption of a new form or significant change to an existing form with less than 30 days' notice using emergency rulemaking procedures under §2001.034 of the APA due to imminent peril to the public, health, safety, or welfare, or a requirement of state or federal law. OPUC stated that it is unclear what the legal basis is of the proposed language that would allow a state agency to create new forms or make significant changes to existing forms without a rulemaking process is unclear. OPUC commented that allowing changes to commission-prescribed forms without formal rulemaking processes and public participation is contrary to the spirit of the APA, if not the actual legal requirements of it. OPUC noted that there are provisions for an emergency rulemaking in the APA but are not reflected in the proposed language. OPUC remarked that the provision does not define "good cause" and recommended the provision be revised to account for emergency rulemaking under §2001.034 if the intention was to use that process. OPUC expressed concern over the 180-day interim effective period for new forms or significant changes to existing forms implemented without publication. OPUC stated that the APA allows a rule to be "effective for not longer than 120 days and may be renewed once for not longer than 60 days," but with certain prerequisites that are not provided in the proposed language.

Commission response

The commission declines to implement OPUC's recommended change. The commission modifies the proposed rule to remove the existing rule language that permits the temporary implementation of a new form or a substantive change to an existing form for good cause because it is unnecessary. Section 2001.034 of the APA provides the commission with emergency rulemaking authority, and the commission can implement a temporary form as part of an emergency rulemaking using that authority, if required to address an imminent peril to the public or a statutory requirement.

LCRA recommended that new forms or significant changes to forms should be posted on the commission's website and posted in a commission project dedicated to this purpose. LCRA also informally recommended a 30-day comment period be authorized for such changes. LCRA commented that, despite the APA not requiring notice and comment for "forms, instructions, applications, and guidance documents," there are significant efficiencies by providing some form of notice beyond what the amended rule proposes. Therefore, notice and an opportunity for comment for the publication of new forms or the significant amendment of existing forms prior to implementation should be considered. LCRA stated that a 30-day comment period may not be necessary for minor changes to commission-prescribed forms, but for new forms or significant changes to existing forms, it may help preserve staff time in managing and facilitating feedback from frustrated stakeholders. LCRA explained that enhanced notice and opportunity for comment would be beneficial to all stakeholders given the volume of commission-prescribed forms and the limited benefit of providing notice solely through the Texas Register. To this point, LCRA noted that the commission currently has over 100 forms on the electric forms page alone, with several more to be added such as the report on dispatchable and non-dispatchable generation and the template for the executive summary of emergency operations plans.

Commission response

The commission declines to modify the rule to require notice-and-comment for new forms and significant modification to existing forms because it is unnecessary. The proposed rule already treats such form changes as formal rule changes and provides a full comment period. The commission will also continue its current practice of publishing proposed substantive form changes to the filing interchange on its website, as requested by LCRA, but declines to modify the rule to state this explicitly, to preserve operational flexibility as the commission continues to update its website and related systems.

Proposed §22.80(a)(3)- Minor or nonsubstantive updates to commission-prescribed forms

Proposed §22.80(a)(3) generally authorizes commission staff to make minor or nonsubstantive updates to commission-approved forms or change the method of form submission such as typos, updates to contact information or citation, accessibility changes, and the resolution of minor conflicts between the form language and the underlying statute or rule associated with the form.

OPUC recommended deleting language from proposed §22.80(a)(3) that would authorize commission staff to update or add citations to a form and correct minor conflicts between the language of a form and an underlying statute or rule associated with a form. OPUC stated that such revisions are substantive, as it could result in significant changes to the content or meaning of a relevant sentence or paragraph in the form depending on the citations or the language corrected to refer to a statute or rule. OPUC further recommended that commission staff should not be authorized to make "minor" changes to a commission form as the public may perceive such a change as "major." OPUC stated its proposed changes would minimize confusion and eliminate differing standards. OPUC provided draft language consistent with its recommendation.

Commission response

The commission generally agrees with OPUC that the primary determining factor with regards to whether a formal commission notice-and-comment period is required for a form change is whether the change is substantive or ministerial, not the magnitude of the change. Accordingly, the commission modifies the rule to remove the references to commission staff's ability to make "minor" form changes. The commission does not agree, however, that merely adding or correcting a statutory or rule reference to a form constitutes a substantive change to the form. Statutory and rule language is authoritative over the language of a form, so providing the public with a direct reference to the relevant language ensures that the individual filling out the form can easily access the applicable legal standards.

Proposed §22.80(b)- Conflict between commission-prescribed form and statute or rule

Proposed §22.80(b) establishes that, in the event of a conflict "between the requirements of a commission-prescribed form and the requirements of the underlying statute or rule associated with that form, the statute or rule prevails."

OPUC recommended revising proposed §22.80(b) to state: "In the event of a conflict between the requirements of a commission-prescribed form and the requirements of the underlying statute or rule associated with that form, the statute or rule prevails to the extent the rule complies with the statute." OPUC characterized this revision as a clarification.

Commission response

The commission declines to implement the recommended change because it is unnecessary. The provision concerns discrepancies between a form and a rule or a form and a statute. Each commission rule should be construed as harmonious with the statutes authorizing its adoption.

Proposed §22.103- Standing to Intervene

Proposed §22.103 establishes the minimum requirements for a person to intervene in a proceeding before the commission.

Proposed §22.103(b) and §22.103(b)(2)- Standing to intervene

Proposed §22.103(b) establishes the criteria by which a person has standing to intervene and the requirements associated with filing a motion to intervene under §22.104 of this title, relating to Motions to Intervene. Proposed §22.103(b)(2) establishes that a person has standing to intervene if that person has a justiciable interest which may be adversely affected by the outcome of the proceeding.

OPUC opposed the deletion of language in §22.103(b)(2) that would exclude representatives of persons with a justiciable interest from having to standing to intervene in a commission proceeding. OPUC stated that the proposed revision limits persons with a justiciable interest that are adversely affected by the outcome of the proceeding from their right to representation. Specifically, the revision would preclude such persons from having an "authorized representative" file a motion to intervene or appear on their behalf regarding such motions.

Commission response

The commission disagrees with OPUC and declines to implement the recommended change. The deletion was intentional because a person may have a justiciable interest and that person may also have a designated or authorized representative, but that representative does not have their own right to intervene. The revision is intended to clearly delineate who is the intervenor (i.e., the person with the justiciable interest) and whose justiciable interest is affected (i.e., again, the intervening person). For example, a landowner that may be adversely affected by a water CCN amendment. That landowner may intervene and retain a law firm as the landowner's authorized representative. The law firm being retained as counsel does not give the law firm itself the right to be an intervenor. Rather, the law firm represents the landowner intervenor and it is the landowner intervenor's interests that are at stake. Moreover, OPUC has statutory standing in commission proceedings in accordance with PURA §13.003. The inquiry is always whether the party being represented has standing (i.e., a justiciable interest); not the authorized representative. The revision does not preclude parties from being represented by an attorney nor does it preclude OPUC from performing its statutory duties.

Proposed §22.104- Motions to Intervene

Proposed §22.104 establishes the general requirements for filing a motion to intervene, the timing of filing such motions, the rights of persons with pending motions to intervene, and seeking later interventions.

Proposed §22.104(b)- Time for filing motion

Proposed §22.104(b) establishes that a motion to intervene "must be filed within 45 days from the date an application is filed with the commission, unless otherwise provided by statute, commission rule, or order of the presiding officer." The provision also establishes a 30-day deadline from the date the application is filed for CCN applications filed under PURA §39.203(e) or transmission facilities subject to PURA §37.057. The provision further requires motions to include "the email address of the person requesting to intervene unless the motion is accompanied by a statement of no access" under §22.106 and "be served upon all parties to the proceeding and upon all persons that have pending motions to intervene" in accordance with §22.74.

OPUC recommended that proposed §22.104(b) be revised to grant a person filing a motion to intervene a reasonable time frame after filing to notify the commission they have no internet access before action is taken on the motion. OPUC explained that, if a person has no internet access, they may also be unaware of the requirement to file a statement of no access to be exempted from service by e-mail under §22.103(d) or to respond in the event of an adverse ruling against their motion to intervene.

Commission response

The commission declines to implement the recommended change because it is unnecessary. Specifically, the provision already provides specific timelines for filing a motion for intervene generally and for CCN proceedings. Moreover, am e-mail address or, if applicable, a statement of no access is necessary for inclusion in the motion to intervene. Such information is essential for other parties to a proceeding and the commission to ensure proper service. However, the commission subdivides §22.104(b) into §22.104(b)(1) and (2) for clarity.

OPUC recommended that proposed §22.104(b) be revised to replace the requirement for a person filing a motion to intervene to serve the motion upon all persons that have pending motions to intervene with a requirement for the person to file the motion and the presiding officer notify all parties of the motion and, for parties with no access to the internet, the procedures to notify such parties of the motion. OPUC stated that the existing requirement is overly burdensome, particularly when such persons with a pending motion to intervene are numerous and because noncompliance risks an adverse ruling on a motion to intervene.

Commission response

The commission declines to implement the recommended change. A person who has presented a motion to intervene may have a justiciable interest even if the presiding officer has not ruled on the motion. The existing rule and proposed rule appropriately afford such persons with pending motions to intervene with the same rights as parties, including the receipt of all pleadings by service.

OPUC recommended §22.104(b) be revised to require the presiding officer to advise ratepayer intervenors about the requirement to serve subsequent pleadings or documents on all parties to the proceeding and provide the procedures for providing non-electronic notice for intervenors with no internet access in each order granting a motion to intervene.

Commission response

The commission declines to implement the recommended change. All parties to a commission proceeding or other commission matter are required to comply with commission rules. Such compliance is not contingent on reminders or admonishments in orders ruling on intervention.

OPUC recommended the deadline for motions to intervene be revised from "45 days from the date an application is filed with the commission" to "45 days from the date an application is filed with the commission [and] deemed administratively complete by commission staff and notice is given to all affected persons including customers of the utility." OPUC also recommended, for CCN applications filed under PURA §39.203(e) or an application for a CCN for a transmission facility subject to PURA §37.057, the deadline for motions to intervene be revised from "within 30 days from the date the application filed with the commission" to within 30 days from the date the application is filed with the commission is deemed administratively complete by commission staff and notice given to affected persons."

Commission response

The commission declines to implement the recommended change because it is contrary to statute. CCN proceedings have statutory deadlines that are tied to the date a CCN application is filed (e.g., PURA §37.057 has a 180-day timeline from the date the application is filed), not tied to dates associated with administrative completeness or notice.

Proposed §22.104(c)- Time for filing motion

Proposed §22.104(c) provides that a person who has filed a motion to intervene has all the rights and obligations of a party pending the presiding officer's ruling on the motion to intervene.

TAWC commented that the right to participate in a proceeding should not be granted to a person that has filed a motion to intervene if the presiding officer has not granted intervention. TAWC stated that this may lead to instances where a person may file a motion to intervene and then immediately request voluminous discovery from a utility by a date prior to the presiding officer ruling on the motion.

Commission response

The commission declines to implement the recommended change. The proposed revision is only a grammatical change to a long-standing provision. The existing and proposed version of the provision effectively provide that any person that has not intervened in a proceeding, or who has been denied permission to intervene, is not considered to be a party. The commission has interpreted §22.104(b) and the rest of §22.104 as a whole to provide that a person whose motion to intervene has not yet been ruled on by the presiding officer has the rights of a party until the motion to intervene has been denied. This entitles the movant to things like service and discovery rights. This provisional allowance is essential to full and fair participation in a commission matter, particularly in commission proceedings with short discovery and testimony deadlines. To the extent a party believes a person who does not have a justiciable interest is therefore improperly propounding discovery, the party subject to the discovery may raise an objection for the presiding officer's consideration.

SUBCHAPTER A. GENERAL PROVISIONS AND DEFINITIONS

16 TAC §§22.2 - 22.4

These amended rules are adopted under the following provisions of PURA: §14.001, which provides the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by PURA that is necessary and convenient to the exercise of that power and jurisdiction; §14.002 and Texas Water Code §13.041(b), which provides the commission with the authority to make adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules governing practice and procedure before the commission and, as applicable, practice and procedure before the State Office of Administrative Hearings. The amended rules are also adopted under PURA §12.202, which requires the commission to develop and implement policies that provide the public with a reasonable opportunity to appear before the commission and to speak on any issue under the jurisdiction of the commission; PURA §14.153, which requires the regulatory authority to adopt rules governing communications, including records retention of such communications, with the regulatory authority or a member or employee of the regulatory authority by a public utility, an affiliate, or a representative of a public utility or affiliate; PURA §37.054, which requires the commission to provide notice of an application for a certificate to interested parties and to the Office of Public Utility Counsel and set a time and place for a hearing and give notice of the hearing; PURA §37.057, which requires the commission to approve or deny an application for a certificate for a new transmission facility not later than the 180th day after the date the application is filed; Texas Government Code §2001.051, which entitles each party in a contested case to a hearing and an opportunity to respond and to present evidence and argument on each issue involved in the case; and Texas Government Code §2001.052, which specifies the requirements for the contents of a notice of a hearing in a contested case.

Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.002, 14.052 and Texas Water Code §13.041(b); PURA §§12.202, 14.153, 37.054 and 37.057; and Texas Government Code §2001.051 and 2001.052.

§22.2. Definitions.

The following terms, when used in this chapter, have the following meanings, unless the context or specific language of a section clearly indicates otherwise:

(1) Administrative law judge--The person designated to preside over a proceeding.

(2) APA--The Texas Administrative Procedure Act, codified at Chapter 2001, Texas Government Code.

(3) Administrative review--The process under which an application submitted to the commission may be decided without a formal hearing.

(4) Affected person--For a matter involving an entity that provides electric or telecommunications service, the definition of affected person has the meaning provided by PURA §11.003(1). For a matter involving an entity that provides water or sewer service, the definition of affected person has the meaning provided by TWC §13.002(1).

(5) Applicant--A person, including commission staff, who seeks action from the commission by written application, petition, complaint, notice of intent, appeal, or other pleading that initiates a proceeding.

(6) Application--A written application, petition, complaint, notice of intent, appeal, or other pleading that initiates a proceeding.

(7) Arbitration--A form of dispute resolution in which each party presents its position on any unresolved issues to an impartial third person who renders a decision on the basis of the information and arguments submitted.

(8) Arbitration hearing--The hearing conducted by an arbitrator to resolve any issue submitted to the arbitrator. An arbitration hearing is not a contested case under the APA.

(9) Arbitrator--The commission, any commissioner, any commission employee, or any SOAH administrative law judge selected to serve as the presiding officer in a compulsory arbitration hearing.

(10) Authorized representative--A person who enters an appearance on behalf of a party, or on behalf of a person seeking to be a party or otherwise to participate in a proceeding. The appearance may be entered in person or by subscribing the representative's name upon any pleading filed on behalf of the party or person seeking to be a party or otherwise to participate in the proceeding. The authorized representative is considered to remain a representative of record unless a statement or pleading to the contrary is filed or stated in the record.

(11) Chairman--The commissioner designated by the Governor of the State of Texas to serve as chairman of the commission.

(12) Commission--The Public Utility Commission of Texas.

(13) Commissioner--One of the members of the Public Utility Commission of Texas.

(14) Complainant--A person, including commission staff or the Office of Public Utility Counsel, who files a complaint intended to initiate a proceeding with the commission regarding any act or omission by any person subject to the commission's jurisdiction.

(15) Compulsory arbitration--The arbitration proceeding conducted by the commission or its designated arbitrator in accordance with the commission's authority under FTA96 §252.

(16) Contested case--A proceeding as defined by APA §2001.003(1).

(17) Control number--The number assigned by Central Records to a docket, project, or tariff filing proceeding.

(18) Days--Calendar days, not working days, unless otherwise specified by this chapter or the commission's substantive rules.

(19) FTA96--The federal Telecommunications Act of 1996, codified under Title 47, United States Code §§151 et seq.

(20) Final order--The final disposition, in whole or in part, by the commission of the issues before the commission in a proceeding, rendered in accordance with §22.263 of this title (relating to Final Orders).

(21) Financial interest--Any legal or equitable interest, or any relationship as officer, director, trustee, advisor, or other active participant in the affairs of a party. An interest as a taxpayer, utility ratepayer, or cooperative member is not a financial interest. An interest a person holds indirectly by ownership of an interest in a retirement system, institution, or fund which in the normal course of business invests in diverse securities independently of that person's control is not a financial interest.

(22) Hearing--Any proceeding at which evidence is taken on the merits of the matters at issue, not including prehearing conferences.

(23) Intervenor--A person, other than the applicant, respondent, or commission staff representing the public interest, who is permitted by law or by ruling of the presiding officer, to become a party to a proceeding.

(24) Licensing proceeding--Any proceeding involving the granting, denial, renewal, revocation, suspension, annulment, withdrawal, or amendment of a license, including a proceeding regarding a notice of intent to build a new electric generating unit.

(25) Major rate proceeding--Any proceeding filed under PURA §§36.101- 36.112, 36.201 - 36.203, 36.205, 51.009, 53.101 - 53.113, 53.201, or 53.202 involving an increase in rates which would increase the aggregate revenues of the applicant more than the greater of $100,000 or 2.5%. In addition, a major rate proceeding is any rate proceeding initiated under PURA §§36.151 - 36.156, 53.151, or 53.152 in which the respondent utility is directed to file a rate filing package. For water and sewer utilities, a rate filing package filed under TWC §13.187 is a major rate proceeding.

(26) Mediation--A form of dispute resolution in which an impartial person facilitates communication between parties to promote negotiation and settlement of disputed issues.

(27) Municipality--A city, incorporated village, or town, existing, created, or organized under the general, home-rule, or special laws of Texas. A municipality is a person as defined in this section.

(28) Party--A party under subchapter F of this chapter (relating to Parties).

(29) Person--An individual, partnership, corporation, association, governmental subdivision, entity, or public or private organization.

(30) Pleading--A written document submitted by a party, a person seeking to intervene, or an amicus curiae, in a proceeding, setting forth allegations of fact, claims, requests for relief, legal argument, or other matters relating to a proceeding.

(31) Prehearing conference--Any conference or meeting of the parties, prior to the hearing on the merits, on the record and presided over by the presiding officer.

(32) Presiding officer--The commission, any commissioner, or any hearings examiner or administrative law judge presiding over a proceeding or any portion thereof.

(33) Proceeding--Any hearing, investigation, inquiry or other fact-finding or decision-making procedure, including the denial of relief or the dismissal of a complaint, conducted by the commission or SOAH.

(34) Project--A rulemaking or other proceeding that is not a docket or a tariff filing proceeding.

(35) Protestor--A person who is not a party to the case who submits oral or written comments. A person classified as a protestor does not have rights to participate in a proceeding other than by providing oral or written comments.

(36) PURA--The Public Utility Regulatory Act, Texas Utilities Code, Title 2, as amended.

(37) Relative--An individual, or spouse of an individual, who is related to the individual in issue, or the spouse of the individual in issue, within the second degree of consanguinity or relationship according to the civil law system.

(38) Respondent--A person under the commission's jurisdiction against whom any complaint or appeal has been filed or who is under formal investigation by the commission.

(39) Retail Public Utility--Has the meaning as defined by Texas Water Code §13.002(19).

(40) Rulemaking--A proceeding under the APA, Texas Government Code, Chapter 2001, subchapter B, conducted to adopt, amend, or repeal a commission rule.

(41) SOAH--The State Office of Administrative Hearings.

(42) TCEQ--The Texas Commission on Environmental Quality.

(43) TWC--The Texas Water Code, as amended.

(44) Working day--A day on which the commission is open for the conduct of business.

§22.3. Standards of Conduct.

(a) Standards of Conduct.

(1) Every person appearing in any proceeding must comport himself or herself with dignity, courtesy, and respect for the commission, the presiding officer, and all other persons participating in the proceeding. Professional representatives must observe and practice the standard of ethical and professional conduct prescribed for their professions.

(2) Upon a finding of a violation of paragraph (1) of this subsection, any party, witness, attorney, or other representative may be excluded by the presiding officer from any proceeding for such period and upon such conditions as are just, or may be subject to other just, reasonable, and lawful disciplinary action as the commission may prescribe.

(b) Ex parte communications. Ex parte communications are governed by § 2001.061 of the APA.

(1) Unless required for the disposition of an ex parte matter authorized by law, members of the commission or administrative law judges assigned to render a decision or to make findings of fact and conclusions of law in a contested case may not communicate, directly or indirectly, in connection with any issue of law or fact with any agency, person, party, or their representatives, except on notice and opportunity for all parties to participate.

(2) Members of the commission or administrative law judges assigned to render a decision or to make findings of fact or conclusions of law in a contested case may communicate ex parte with employees of the commission who have not participated in the case for the purpose of utilizing the special skills or knowledge of the commission and its staff in evaluating the evidence.

(3) Number running procedures do not constitute impermissible ex parte communications if memoranda memorializing such procedures are preserved and made available to all parties of record in the proceeding to which the number running procedures relate.

(c) Communications. Communications by public utilities, their affiliates or representatives, or any person with the commission or any employee of the commission are governed by §14.153 of PURA. Records will be kept of all such communications and will be available to the public on a monthly basis.

(d) Standards for Recusal or Disqualification of Administrative Law Judges. An administrative law judge must disqualify himself or herself or must recuse himself or herself on the same grounds and under the same circumstances as specified in Rule 18b of the Texas Rules of Civil Procedure.

(e) Motions for Disqualification or Recusal of an Administrative Law Judge.

(1) Any party may move for disqualification or recusal of an administrative law judge stating with particularity the grounds why the administrative law judge should not sit. The motion must:

(A) be made on personal knowledge;

(B) set forth such facts as would be admissible in evidence; and

(2) The motion must be filed within ten working days after the facts that are the basis of the motion become known to the party, or within 15 working days of the commencement of the proceeding, whichever is later. The motion must be served on all parties in accordance with §22.74 of this title (relating to Service of Pleadings and Documents).

(3) A party's response to a motion for disqualification or recusal must be in writing and filed within three working days after the filing of the motion. The administrative law judge may require that responses be made orally at a prehearing conference or hearing.

(4) The administrative law judge must rule on the motion for disqualification or recusal within ten working days of the filing of the motion. No hearing will be held on a motion for disqualification or recusal unless ordered by the presiding officer.

(A) If the administrative law judge who is the subject of the motion disqualifies or recuses himself or herself, the director of docket management must assign a different administrative law judge to the case.

(B) If the administrative law judge who is the subject of the motion declines to disqualify or recuse himself or herself, the director of docket management must assign another administrative law judge to consider and rule on the motion.

(i) At the discretion of the assigned administrative law judge, a hearing may be held on the motion.

(ii) If the assigned judge finds that the presiding administrative law judge is disqualified or should be recused, the director of docket management must assign a different presiding administrative law judge to the case.

(5) The administrative law judge must not rule on any other issues in the proceeding while a motion for disqualification or recusal is pending. In a case that has been referred to SOAH, SOAH must appoint another administrative law judge to preside on all matters that are the subject of the motion for recusal until the issue of disqualification is resolved.

(6) The parties to a proceeding may waive any ground for recusal or disqualification after it is fully disclosed on the record, either expressly or by their failure to take action on a timely basis.

(7) If the administrative law judge determines that a motion for disqualification or recusal was frivolous or capricious, or filed for purposes of delaying the proceeding, the movant may be sanctioned in accordance with §22.161 of this title (relating to Sanctions).

(8) Disqualification or recusal of an administrative law judge, in and of itself, has no effect upon the validity of rulings made or orders issued prior to the time the motion for recusal or disqualification was filed.

(f) Standards for Recusal of Commissioners. A commissioner must recuse himself or herself from sitting in a proceeding, or from deciding one or more issues in a proceeding, in which any one or more of the following circumstances exist:

(1) the commissioner in fact lacks impartiality or the commissioner's impartiality has been reasonably questioned;

(2) the commissioner, or any relative of the commissioner, is a party or has a financial interest in the subject matter of the issue or in one of the parties, or the commissioner has any other interest that could be substantially affected by the determination of the issue; or

(3) the commissioner or a relative of the commissioner has participated as counsel, advisor, or witness in the proceeding or matter in controversy.

(g) Motion for Recusal of a Commissioner.

(1) Any party may move for recusal of a commissioner stating with particularity grounds why the commissioner should not sit. Such a motion must be filed prior to the date the commission is scheduled to consider the matter unless the information upon which the motion is based was not known or discoverable with reasonable effort prior to that time. The motion must:

(A) be made on personal knowledge,

(B) set forth such facts as would be admissible in evidence, and

(2) Subject to the provisions of paragraph (1) of this subsection the motion must be filed within ten working days after the facts that are the basis of the motion become known to the party or within 15 days of the commencement of the proceeding, whichever is later. The motion must be served on all parties and the commissioner for whom recusal is sought in accordance with §22.74 of this title.

(3) Parties may file written responses to the motion within seven working days from the date of filing the motion. The commission may require that responses be made orally at an open meeting.

(4) The commissioner sought to be recused must issue a decision as to whether he or she agrees that recusal is appropriate or required before the commission is scheduled to act on the matter for which recusal is sought, or within 15 days after filing of the motion, whichever occurs first.

(5) The parties to a proceeding may waive any ground for recusal after it is fully disclosed on the record, either expressly or by their failure to take action on a timely basis.

(6) Recusal of a commissioner, in and of itself, has no effect upon the validity of rulings made or orders issued prior to the time the motion for recusal was filed.

§22.4. Computation of Time.

(a) Counting Days. In computing any period of time prescribed or allowed by this chapter, by order of the commission or any administrative law judge, or by any applicable statute, the period begins on the day after the act, event, or default in question. The period concludes on the last day of the designated period unless that day is not a working day, in which event the designated period runs until 5:00 P.M. Central Prevailing Time of the next working day.

(b) Extensions. Unless otherwise provided by statute, the time for filing any documents may be extended by the presiding officer, upon the filing of a motion, prior to the expiration of the applicable period of time, showing that there is good cause for such extension of time and that the need for the extension is not caused by the neglect, indifference, or lack of diligence of the party making the motion.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 5, 2026.

TRD-202600529

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: February 25, 2026

Proposal publication date: August 15, 2025

For further information, please call: (512) 936-7433

SUBCHAPTER B. THE ORGANIZATION OF THE COMMISSION

16 TAC §22.21, §22.23

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 5, 2026.

TRD-202600530

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: February 25, 2026

Proposal publication date: August 15, 2025

For further information, please call: (512) 936-7433

SUBCHAPTER C. CLASSIFICATION OF APPLICATIONS OR OTHER DOCUMENTS INITIATING A PROCEEDING

16 TAC §22.31

§22.31. Classification in General.

(a) Classification and assignment of control number. Central Records will determine whether an application or other document initiating a proceeding should be designated as a docket, tariff filing, or project. Central Records will assign an appropriate control number to each docket, tariff filing, or project.

(b) Control numbering system. Central Records will establish and maintain a control numbering system.

(c) Control number log. Central Records will maintain a record or log of all applications or other documents assigned a control number, which will include the style, the date the application or other document was filed or the proceeding initiated, the nature of the proceeding, and the presiding officer assigned to the proceeding, if any. The log will be accessible to the public.

(d) Control number assignment. A control number will be assigned to a proceeding only at the time of filing an application unless otherwise required by rule or on approval of the Office of Policy and Docket Management or the director's designee.

(e) Closing unused control numbers. Any control number assigned before the filing of an application may be closed by the presiding officer if the application is not filed within 25 days of assignment of the control number.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 5, 2026.

TRD-202600531

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: February 25, 2026

Proposal publication date: August 15, 2025

For further information, please call: (512) 936-7433

SUBCHAPTER D. NOTICE

16 TAC §§22.52, 22.53, 22.56

§22.52. Notice in Licensing Proceedings.

(a) Notice in electric licensing proceedings. In all electric licensing proceedings, except minor boundary changes and service area exceptions, the applicant must give notice in the following ways:

(1) An applicant must publish notice of the applicant's intent to secure or amend a certificate of convenience and necessity in a newspaper having general circulation in the county or counties where a certificate of convenience and necessity is being requested, no later than the week after the application is filed with the commission. This notice must identify the commission's docket control number and the style assigned to the case by Central Records. In electric transmission line cases, the applicant must obtain the docket control number and style no earlier than 25 days prior to making the application by filing a preliminary pleading requesting a docket assignment. The notice must identify in general terms the type of facility if applicable, and the estimated expense associated with the project. The notice must describe all routes without designating a preferred route or otherwise suggesting that a particular route is more or less likely to be selected than one of the other routes.

(A) The notice must include all the information required by the standard format established by the commission for published notice in electric licensing proceedings. The notice must state the date established for the deadline for intervention in the proceeding (date 45 days after the date the formal application was filed with the commission; or date 30 days after the date the formal application was filed with the commission for an application for certificate of convenience and necessity filed under PURA §39.203(e) or an application for a certificate of convenience and necessity for a new transmission facility subject to PURA §37.057) and that a letter requesting intervention should be received by the commission by that date.

(B) The notice must describe in clear, precise language the geographic area for which the certificate is being requested and the location of any alternative routes of the proposed facility using route segments proposed by the applicant. This description must refer to area landmarks, including geographic landmarks, municipal and county boundary lines, streets, roads, highways, railroad tracks, and any other readily identifiable points of reference, unless no such references exist for the geographic area. In addition, the notice must include a map that identifies any of the alternative locations of the proposed routes and all major roads, transmission lines, and other features of significance to the areas that are used in the utility's written notice description.

(C) The notice must state a location where a detailed routing map may be reviewed. The map must clearly and conspicuously illustrate the location of the area for which the certificate is being requested including all the alternative locations of the proposed routes, and must reflect area landmarks, including geographic landmarks, municipal and county boundary lines, streets, roads, highways, railroad tracks, and any other readily identifiable points of reference, unless no such references exist for the geographic area.

(D) Proof of publication of notice must be in the form of a publisher's affidavit which must specify each newspaper in which the notice was published, the county or counties in which each newspaper is of general circulation, the dates upon which the notice was published, and a copy of the notice as published. Proof of publication must be submitted to the commission as soon as available.

(E) The applicant must provide a copy of each environmental impact study or assessment for the project to the Texas Parks and Wildlife Department (TPWD) for its review within seven days of filing the application. Proof of submission of the information to TPWD must be provided in the form of an affidavit to the commission, which must specify the date the information was mailed or otherwise provided to TPWD, and must provide a copy of the cover letter or other documentation that confirms that the information was provided to TPWD.

(2) The applicant must, on the date it files an application, mail notice of its application to municipalities within five miles of the requested territory or facility, neighboring utilities providing the same utility service within five miles of the requested territory or facility, each county government for all counties in which any portion of the proposed facility or requested territory is located, and the Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse or similar entity as designated by the Department of Defense. In addition, the applicant must, upon filing the application, serve the notice on the Office of Public Utility Counsel using a method specified in §22.74(b) of this title (relating to Service of Pleadings and Documents). The notice must contain the information as set out in paragraph (1) of this subsection and a map as described in paragraph (1)(C) of this subsection. An affidavit attesting to the provision of notice to municipalities, utilities, counties, the Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse or similar entity as designated by the Department of Defense, and the Office of Public Utility Counsel must specify the dates of the provision of notice and the identity of the individual municipalities, utilities, and counties to which such notice was provided. Before final approval of any modification to the applicant's proposed route, applicant must provide notice as required under this paragraph to municipalities, utilities, and counties affected by the modification which have not previously received notice. The notice of modification must state such entities will have 20 days to intervene.

(3) The applicant must, on the date it files an application, mail notice of its application to the owners of land, as stated on the current county tax rolls, who would be directly affected by the requested certificate. For purposes of this paragraph, land is directly affected if an easement or other property interest would be obtained over all or any portion of it, or if it contains a habitable structure that would be within 300 feet of the centerline of a transmission project of 230kV or less, or within 500 feet of the centerline of a transmission project greater than 230kV. For purposes of this paragraph, land is also directly affected if it is adjacent to a property on which a substation proposed to be authorized by the certificate of convenience and necessity will be located or is directly across a highway, road, or street that is adjacent to a property on which such a substation will be located.

(A) Required contents of notice. The notice must contain all information required in paragraph (1) of this subsection and must include all the information required by the standard notice letter to landowners prescribed by the commission. The commission's docket control number pertaining to the application must be stated in all notices. The notice must also include a copy of the "Landowners and Transmission Line Cases at the PUC" brochure prescribed by the commission.

(B) Map of route. The notice must include a map as described in paragraph (1)(C) of this subsection.

(C) Notice of proposed substations. Notice of each substation proposed to be authorized by a certificate of convenience and necessity to each owner of:

(i) property adjacent to the property on which the proposed substation will be located; and

(ii) property located directly across a highway, road, or street that is adjacent to the property on which the proposed substation will be located.

(D) Issuance of notice prior to final approval. Before final approval of any modification in the applicant's proposed route, applicant must provide notice as required under subparagraphs (A) through (C) of this paragraph to all landowners directly affected by the modification who have not already received notice. Proof of notice of the modification may be established by an affidavit affirming that the applicant sent notice by first-class mail to each landowner directly affected by the modification as listed on the current county tax rolls.

(E) Proof of notice. Proof of notice may be established by an affidavit affirming that the applicant sent notice by first-class mail to each of the persons listed as an owner of directly affected land on the current county tax rolls. The proof of notice must include a list of all landowners to whom notice was sent and a statement of whether any formal contact related to the proceeding between the utility and the landowner other than the notice has occurred. This proof of notice must be filed with the commission no later than 20 days after the filing of the application.

(F) Cure of insufficient notice. Upon the filing of proof of notice as described in subparagraph (E) of this paragraph, the lack of actual notice to any individual landowner will not in and of itself support a finding that the requirements of this paragraph have not been satisfied. If, however, the utility finds that an owner of directly affected land has not received notice, it must immediately advise the commission by written pleading and must provide notice to such landowners by priority mail, with delivery confirmation, in the same form described in subparagraphs (A) through (C) of this paragraph, except that the notice must state that the person has fifteen days from the date of delivery to intervene. The utility must immediately file a supplemental affidavit of notice with the commission.

(4) The utility must hold at least one public meeting prior to the filing of its licensing application if 25 or more persons would be entitled to receive direct mail notice of the application. Direct mail notice of the public meeting must be sent by first-class mail to each of the persons listed on the current county tax rolls as an owner of land within 300 feet of the centerline of a transmission project of 230kV or less, an owner of land within 500 feet of the centerline of a transmission project greater than 230kV, an owner of land adjacent to a property on which a substation proposed to be authorized by the certificate of convenience and necessity will be located, or an owner of land directly across a highway, road, or street that is adjacent to such a substation. The utility must also provide written notice of the public meeting to the Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse or similar entity as designated by the Department of Defense . In the notice for the public meeting, at the public meeting, and in other communications with a potentially affected person, the utility must not describe routes as preferred routes or otherwise suggest that a particular route is more or less likely to be selected than one of the other routes. If no public meeting is held, the utility must provide written notice of the planned filing of an application to the Department of Defense Military Aviation and Installation Assurance Siting Clearinghouse or similar entity as designated by the Department of Defense prior to completion of the routing study.

(5) Failure to provide notice in accordance with this section will be cause for day-for-day extension of deadlines for intervention and for commission action on the application.

(6) Upon entry of a final, appealable order by the commission approving an application, the utility must provide notice to all owners of land who previously received direct notice. Proof of notice under this subsection must be provided to the commission's staff.

(A) If the owner's land is directly affected by the approved route, the notice must consist of a copy of the final order.

(B) If the owner's land is not directly affected by the approved route, the notice must consist of a brief statement that the land is no longer the subject of a pending proceeding and will not be directly affected by the facility.

(7) All notices of an applicant's intent to secure a certificate of convenience and necessity whether provided by publication or direct mail must include the following language: "All routes and route segments included in this notice are available for selection and approval by the Public Utility Commission of Texas."

(b) Notice in telephone licensing proceedings. In all telephone licensing proceedings, except minor boundary changes, applications for a certificate of operating authority, or applications for a service provider certificate of operating authority, the applicant must give notice in the following ways:

(1) Applicants must publish in a newspaper having general circulation in the county or counties where a certificate of convenience and necessity is being requested, once each week for two consecutive weeks, beginning the week after the application is filed, notice of the applicant's intent to secure a certificate of convenience and necessity This notice must identify the commission's docket control number and the style assigned to the case by Central Records. This notice must identify in general terms the types of facilities, if applicable, the area for which the certificate is being requested, and the estimated expense associated with the project. The notice must state the established intervention deadline. The notice must also include the following statement: "Persons with questions about this project should contact (name of utility contact) at (utility contact telephone number). Persons who wish to intervene in the proceeding or comment upon action sought, should contact the Public Utility Commission, P.O. Box 13326, Austin, Texas 78711-3326, or call the Public Utility Commission at (Commission local and toll-free telephone numbers). Hearing- and speech-impaired individuals may contact the commission through Relay Texas at (Relay Texas telephone number). The deadline for intervention in the proceeding is (date 70 days after the date the application was filed with the commission) and you must request intervention to the commission by that date." Proof of publication of notice must be in the form of a publisher's affidavit, which must specify the newspaper or newspapers in which the notice was published; the county or counties in which the newspaper or newspapers is or are of general circulation; the dates upon which the notice was published and a copy of the notice as published. Proof of publication must be submitted to the commission as soon as available.

(2) Applicant must also mail notice of its application, which must contain the information as set out in paragraph (1) of this subsection, to cities and to neighboring utilities providing the same service within five miles of the requested territory or facility. Applicant must also provide notice to the county government of all counties in which any portion of the proposed facility or territory is located. The notice provided to county governments must be identical to that provided to cities and to neighboring utilities. An affidavit attesting to the provision of notice to counties must specify the dates of the provision of notice and the identity of the individual counties to which such notice was provided.

(3) Failure to provide notice in accordance with this section will be cause for day-for-day extension of deadlines for intervention.

§22.53. Notice of Regional Hearings.

The presiding officer may require the utility that is the subject of a proceeding to publish conspicuous notice of a regional hearing in newspapers of general circulation in the general area of the hearing and to provide other reasonable notice to customers and affected municipalities.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 5, 2026.

TRD-202600532

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: February 25, 2026

Proposal publication date: August 15, 2025

For further information, please call: (512) 936-7433

SUBCHAPTER E. PLEADINGS AND OTHER DOCUMENTS

16 TAC §§22.74 - 22.80

§22.74. Service of Pleadings and Documents.

(a) Pleadings and Documents submitted to a presiding officer. At or before the time any document or pleading regarding a proceeding is submitted by a party to a presiding officer, a copy of such document or pleading must be filed and served on all parties. These requirements do not apply to documents that are offered into evidence during a hearing or that are submitted to a presiding officer for in camera inspection; provided, however, that the party submitting documents for in camera inspection must file and serve notice of the submission upon the other parties to the proceeding. Pleadings and documents submitted to a presiding officer during a hearing, prehearing conference, or open meeting must be filed with Central Records as soon as is practicable.

(b) Methods of service. Except as otherwise expressly provided by order, rule, or other applicable law, service on a party may be made by delivery of a copy of the pleading or document to the party's authorized representative or attorney of record by email; in person; by agent; by courier receipted delivery; by first class mail; by certified mail, return receipt requested; or by registered mail to such party's address of record. If a person has filed a statement of no access under §22.106 of this title (relating to Statement of No Access), service on such a person must be made by delivery of a copy of the pleading or document to the party's authorized representative or attorney of record; in person; by agent; by courier receipted delivery; by first class mail; by certified mail, return receipt requested; or by registered mail to such party's address of record.

(1) Service in person is complete upon in-person delivery to the party or the party's authorized representative or attorney of record.

(2) Service by email is complete upon sending an email that provides a link to the filing on the Interchange in an email message or providing the filing itself attached to the message to the email address of record for the party that was provided.

(3) Service by mail is complete upon deposit of the document, postpaid and properly addressed, in the mail.

(4) Service by agent or by courier receipted delivery is complete upon delivery to the agent or courier.

(c) Alternative methods of service. In response to the motion of a party or on the presiding officer's own motion, the presiding officer may require service by filing, by any method specified in subsection (b) of this section, or any combination of those methods. Service by filing is complete upon acceptance for filing on the Interchange.

(d) Evidence of service. A return receipt or affidavit of any person having personal knowledge of the facts is prima facie evidence of the facts shown thereon relating to service. A party may present other evidence to demonstrate facts relating to service.

(e) Certificate of service. Every document required to be served on all parties must contain the following or similar certificate of service: "I, (name) (title) certify that a copy of this document was served on all parties of record in this proceeding on (date) in the following manner: (specify each method). Signed, (signature)." The list of the names and email addresses of the parties on whom the document was served should not be appended to the document.

§22.75. Examination and Correction of Pleadings and Documents.

(a) Construction of pleadings and documents. All pleadings and documents must be construed so as to do substantial justice.

(b) Procedural sufficiency of pleadings and documents.

(1) Except for a motion for rehearing or a reply to a motion for rehearing, the presiding officer may require a pleading or document that does not comply with the applicable requirements of §22.72 of this title (relating to Form Requirements for Documents Filed with the Commission) to be re-filed.

(2) Upon notification by the presiding officer of a deficiency in a pleading or document, the responsible party must correct or complete the pleading or document in accordance with the notification. If the responsible party fails to correct the deficiency, the pleading or document may be stricken from the record.

(c) Notice of material deficiencies in rate change applications. This subsection applies to applications for rate changes filed under PURA, chapter 36, subchapter C or chapter 53, subchapter C.

(1) Motions to find a rate change application materially deficient must be filed no later than 21 days after an application is filed. Such motions must specify the nature of the deficiency and the relevant portions of the application, and cite the particular requirement with which the application is alleged not to comply. The applicant's response to a motion to find a rate change application materially deficient must be filed no later than five working days after such motion is received.

(2) If the presiding officer determines that material deficiencies exist in an application, the presiding officer must issue a written order specifying a time within which the applicant must amend its application and correct the deficiency. The effective date of the proposed rate change will be 35 days after the filing of a sufficient application. The statutory deadlines will be calculated based on the date of filing the sufficient application.

(d) Notice of material deficiencies in applications for certificates of convenience and necessity for electric transmission lines.

(1) Motions to find an application for certificate of convenience and necessity for electric transmission line materially deficient must be filed no later than 21 days after an application is filed. Such motions must specify the nature of the deficiency and the relevant portions of the application, and cite the particular requirement with which the application is alleged not to comply. The applicant's response to a motion to find an application for certificate of convenience and necessity for electric transmission line materially deficient must be filed no later than five working days after such motion is received.

(2) If the presiding officer determines that a material deficiency exists in an application, the presiding officer must issue a written order specifying a time within which the applicant must amend its application and correct the deficiency.

(3) For an application for certificate of convenience and necessity filed under PURA §39.203(e), a pleading alleging a material deficiency in the application must be filed no later than 14 days after the application is filed, and must be served on the applicant in accordance with §22.74 of this title (relating to Service of Pleadings and Documents). The applicant must reply to a pleading alleging a material deficiency no later than seven days after it is received. If the presiding officer determines that a material deficiency exists in an application, the presiding officer must issue a written order ordering the applicant to amend its application and correct the deficiency within seven days.

§22.77. Motions.

(a) General requirements. A motion must be in writing, unless the motion is made on the record at a prehearing conference or hearing and must state the relief sought and the specific grounds supporting a grant of relief.

(1) If the motion is based upon alleged facts that are not a matter of record, the motion must be supported by an affidavit.

(2) Written motions must be served on all parties in accordance with §22.74 of this title (relating to Service of Pleadings and Documents).

(3) A movant is required to attempt to confer with all parties that could be affected by the motion or pleading, but is not required to attempt to confer with all parties to the proceeding. Written motions must include a certificate of conference that complies substantially with one of the following examples:

(A) Example one: "Certificate of Conference: I certify that I conferred with {name of other party or other party's authorized representative} on {date} about this motion. {Succinct statement of other party's position on the action sought and/or a statement that the parties negotiated in good faith but were unable to resolve their dispute before submitting it to the judge for resolution.} Signature."

(B) Example two: "Certificate of Conference: I certify that I made reasonable but unsuccessful attempts to confer with {name of other party or other party's authorized representative} on {date or dates} about this motion. {Succinctly describe these attempts.} Signature."

(b) Time for response. The time for responding to motions is governed by §22.78 of this title (relating to Responsive Pleadings and Emergency Action), unless otherwise provided by the presiding officer, commission rule, or statute.

(c) Rulings on motions. The presiding officer must serve orders ruling on motions upon all parties, unless the ruling is made on the record in a hearing or prehearing conference open to the public.

§22.78. Responsive Pleadings.

(a) General rule. Unless otherwise specified by statute, by this chapter, or by order of the presiding officer, a responsive pleading, if made, must be filed by a party within five working days after receipt of the pleading to which the response is made. Responsive pleadings must state the date of receipt of the pleading to which response is made. Unless the presiding officer is advised otherwise, it is presumed that all pleadings are received on the filing date.

(b) Responses to complaints. Unless otherwise specified by statute, by this chapter, or by order of the presiding officer, responsive pleadings to complaints filed to initiate a proceeding must be filed within 21 days of the receipt of the complaint. This subsection does not apply to complaints filed under PURA, chapter 36, subchapter D or chapter 53, subchapter D, or for a complaint filed under TWC §13.004 (relating to Jurisdiction of Utility Commission Over Certain Water Supply or Sewer Service Corporations).

(c) Action by the Presiding Officer. Unless otherwise precluded by law or this chapter, the presiding officer may take action on a pleading before the deadline for filing responsive pleadings. Action taken under this subsection may be subject to modification based on a timely responsive pleading.

(d) PURA, Chapter 36, Subchapter D or Chapter 53, Subchapter D Investigations or Complaints. In a complaint proceeding filed under PURA, chapter 36, subchapter D or chapter 53, subchapter D, the presiding officer must determine the scope of the response that the electric or telecommunications utility is required to file, up to and including the filing of a full rate filing package. The presiding officer will also set an appropriate deadline for the electric or telecommunications utility's response.

§22.79. Continuances.

(a) Requirements for motions for continuance.

(1) Unless otherwise ordered by the presiding officer, motions for continuance of the hearing on the merits must be in writing and must be filed not less than five days prior to the hearing.

(2) Motions for continuance must:

(A) set forth the specific grounds for which the moving party seeks continuance; and

(B) refer to all other motions for continuance filed by the moving party in the proceeding.

(3) The moving party must attempt to contact all other parties and must state in the motion each party that was contacted and whether that party objects to the relief requested.

(b) Burden of proof. The moving party has the burden of proof with respect to the need for the continuance at issue.

(1) A continuance will not be granted based on the need for discovery if the party seeking the continuance previously had the opportunity to obtain discovery from the person from whom discovery is sought, except when necessary due to surprise or discovery of facts or evidence which could not have been discovered previously through reasonably diligent effort by the moving party.

(2) The presiding officer may grant continuances provided that any continuance is consistent with any applicable statutory deadline.

(3) A motion for continuance agreed to by all parties may be filed within five days of the hearing on the merits, and must state suggested dates for rescheduling of the hearing.

§22.80. Commission Prescribed Forms.

(a) The commission may require that certain reports and applications be submitted on commission-prescribed forms.

(1) All documents that are the subject of a commission-prescribed form must contain all matters designated in the form and must conform substantially to the form.

(2) Prior to the implementation of any new commission-prescribed form or substantive change to an existing form, the change or new form will be referenced in the "In Addition" section of the Texas Register for public comment.

(3) Commission staff may make nonsubstantive updates to commission-approved forms or change the method of form submission (e.g., transitioning to an online portal for submission) provided the updates or changes do not conflict with the underlying statute or rule associated with the form. The types of changes that are authorized under this paragraph include changes such as correcting typographical errors, updating or adding relevant phone numbers or citations, and making nonsubstantive modifications to a form to improve accessibility across different submission platforms.

(4) The commission will maintain a complete index to and set of all commission-prescribed forms.

(b) In the event of a conflict between the requirements of a commission-prescribed form and the requirements of the underlying statute or rule associated with that form, the statute or rule prevails.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 5, 2026.

TRD-202600533

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: February 25, 2026

Proposal publication date: August 15, 2025

For further information, please call: (512) 936-7433

SUBCHAPTER F. PARTIES

16 TAC §§22.101, 22.103, 22.104

§22.103. Standing to Intervene.

(a) Commission staff representing the public interest. Commission staff represents the public interest, and has standing in all proceedings before the commission. Commission staff is not required to file a motion to intervene.

(b) Standing to intervene. A person desiring to intervene must file a motion to intervene and be recognized as a party under §22.104 of this title (relating to Motions to Intervene) to participate as a party in a proceeding. Any association or organized group must include in its motion to intervene a list of the members of the association or group that are persons other than individuals that will be represented by the association or organized group in the proceedings. The group or association must supplement the list of members represented in the motion at any time a member is added or deleted from the list of members represented. A person has standing to intervene if that person:

(1) has a right to participate that is expressly conferred by statute, commission rule or order or other law; or

(2) has a justiciable interest that may be adversely affected by the outcome of the proceeding.

(c) Dispute resolution under the Federal Telecommunications Act of 1996 (FTA96). Standing to intervene in proceedings concerning dispute resolution and approval of agreements under the commission's authority under FTA96 is subject to the requirements of subchapter D of chapter 21 of this title (relating to Dispute Resolution).

(d) By requesting to intervene in a proceeding, a person agrees to accept delivery by email any motions for rehearing and replies to motions for rehearing in accordance with §22.74 of this title (relating to Service of Pleadings and Documents), unless he or she has filed a statement under §22.106 of this title (relating to Statement of No Access).

§22.104. Motions to Intervene.

(a) Necessity for filing motion to intervene. Applicants, complainants, and respondents, as defined in §22.2 of this title (relating to Definitions), are necessary parties to proceedings which they have initiated or which have been initiated against them and need not file motions to intervene to participate as parties in such proceedings.

(b) Time, content, and procedure for filing motion. Motions to intervene must be filed within 45 days from the date an application is filed with the commission, unless otherwise provided by statute, commission rule, or order of the presiding officer.

(1) For an application for a certificate of convenience and necessity (CCN) filed under PURA §39.203(e) or an application for a CCN for a transmission facility subject to PURA §37.057, motions to intervene must be filed within 30 days from the date the application is filed with the commission.

(2) The motion must include the name and email address of the person requesting to intervene unless the motion is accompanied by a statement of no access under §22.106 of this title (relating to Statement of No Access) and be served upon all parties to the proceeding and upon all persons that have pending motions to intervene in accordance with §22.74 of this title (relating to Service of Pleadings and Documents).

(c) Rights of persons with pending motions to intervene. A person who has filed a motion to intervene has all the rights and obligations of a party pending the presiding officer's ruling on the motion to intervene.

(d) Late intervention.

(1) Criteria for granting late intervention. A motion to intervene that was not timely filed may be granted by the presiding officer. In acting on a late filed motion to intervene, the presiding officer will consider, in addition to the criteria for standing identified in §22.103(b) of this title (relating to Standing to Intervene):

(A) any objections that are filed;

(B) whether the movant had good cause for failing to file the motion within the time prescribed;

(C) whether any prejudice to, or additional burdens upon, the existing parties might result from permitting the late intervention;

(D) whether any disruption of the proceeding might result from permitting late intervention; and

(E) whether the public interest is likely to be served by allowing the intervention.

(2) Limitations on intervention. The presiding officer may impose limitations on the participation of an intervenor to avoid delay and prejudice to the other parties.

(3) Record and procedural schedule. Except as otherwise ordered, an intervenor must accept the procedural schedule and the record of the proceeding as it existed at the time of filing the motion to intervene.

(4) Intervention as a matter of right. In an electric licensing proceeding in which a utility did not provide direct notice to an owner of land directly affected by the requested certificate, late intervention will be granted as a matter of right to such a person, provided that the person files a motion to intervene within 15 days of actually receiving the notice. Such a person should be afforded sufficient time to prepare for and participate in the proceeding.

(5) Late intervention after proposal for decision (PFD) or proposed order (PO) issued. For late interventions, other than those allowed by paragraph (4) of this subsection, the procedures in subparagraphs (A) and (B) of this paragraph apply:

(A) Agenda ballot. Upon receipt of a motion to intervene after the PFD or PO has been issued, the commission's Office of Policy and Docket Management (OPDM) will send separate ballots to each commissioner to determine whether the motion to intervene will be considered at an open meeting. An affirmative vote by one commissioner is required for consideration of a motion to intervene at an open meeting. OPDM will notify the parties by letter whether a commissioner by individual ballot has added the motion to intervene to an open meeting agenda, but will not identify the requesting commissioner.

(B) Denial. If after ten working days of the filing of a motion to intervene, which has been filed after the PFD or PO has been issued, no commissioner has by agenda ballot, placed the motion on the agenda of an open meeting, the motion is deemed denied. If any commissioner has balloted in favor of considering the motion, it will be placed on the agenda of the next regularly scheduled open meeting or such other meeting as the commissioners may direct by the agenda ballot. In the event two or more commissioners vote to consider the motion, but differ as to the date the motion will be heard, the motion will be placed on the latest of the dates specified by the ballots.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 5, 2026.

TRD-202600535

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: February 25, 2026

Proposal publication date: August 15, 2025

For further information, please call: (512) 936-7433

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

SUBCHAPTER C. INFRASTRUCTURE AND RELIABILITY

16 TAC §25.56

The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §25.56, relating to Temporary Emergency Electric Energy Facilities (TEEEF), with changes to the proposed text as published in the August 15, 2025, issue of the Texas Register (50 TexReg 5284). 16 TAC §25.56 will be republished.

The amendments to §25.56 implement Public Utility Regulatory Act (PURA) §39.918, as revised by Senate Bill (SB) 231 during the 89th Regular Texas Legislative Session, by establishing additional technical requirements for TEEEF units--including around mobility, boot-up time, and maximum generating capacity per unit--and providing that transmission and distribution utilities (TDUs) may enter into a lease for TEEEF without prior commission approval if the lease includes a provision that allows alteration of the lease based on commission order or rule.

The amendments to §25.56 are adopted under Project Number 58392.

The commission received initial written comments on the amendments to §25.56 from AEP Texas Inc. (AEP), CenterPoint Energy Electric Houston, LLC. (CenterPoint), City of Houston (Houston), Office of Public Utility Counsel (OPUC), Oncor Electric Delivery Company, LLC. (Oncor), Steering Committee of Cities Served by Oncor (OCSC), and Texas Energy Association for Marketers (TEAM).

Comments on questions for comment

Question 1.a

Houston and OPUC asserted that the proposed rule language is insufficient and recommended modifying the language to: 1) prohibit large alteration penalties from being included in leases subject to commission alteration; 2) limit the capacity of TEEEF that can be leased without prior commission approval to the larger of either 10 percent of total approved TEEEF capacity or 10 MW; and 3) require an informational filing from TDUs upon entering into a TEEEF lease without prior commission authorization. Oncor, CenterPoint, and AEP all disagreed with the first recommendation, the second recommendation, or both, arguing that there is a lack of statutory support. Oncor and CenterPoint further argued, in reference to the first recommendation, that a prohibition on alteration penalties would further limit the already small pool of TEEEF lessors, increase TEEEF lease costs, and hamper a TDU's ability to negotiate favorable lease terms. AEP further argued, in reference to the second recommendation, that the concept of "approved TEEEF fleet capacity" does not exist and that, because a TDU is most likely to enter a TEEEF lease under emergency conditions, it may not be prudent to impose a blanket limitation on the TEEEF capacity a TDU may lease without prior commission authorization.

Commission response

The commission declines to modify the proposed rule to prohibit large alteration penalties or limit the capacity of TEEEF that can be leased under PURA §39.918(f-1)(2) as recommended by Houston and OPUC because such a prohibition and limitation, respectively, are not provided for in PURA §39.918.

The commission agrees with Houston and OPUC that a TDU that enters into a TEEEF lease under PURA §39.918(f-1)(2) should be required to make an informational filing on the lease. Accordingly, the commission adopts a public notice requirement under §25.56(d)(2)(A)(ii).

CenterPoint asserted that, in addition to the proposed rule language, the rule should: 1) describe the type of language that an alteration provision should contain, and 2) authorize the lease parties to either terminate the lease--if unable to agree on a required alteration--or alter other provisions of the lease, including the lease rate, as consideration for agreeing to the required alteration language. Houston disagreed with CenterPoint's second recommendation and argued that, if a lease is terminated without the consent of the commission, the associated costs should not be recovered from ratepayers without a prudence review. OPUC also disagreed with CenterPoint's second recommendation, opposing any lease alteration provision that would result in an increase in the lease rate from the one that was originally agreed to by the lessor and the TDU. OPUC argued that, if the TDU and lessor are authorized to increase the lease rate, then the TDU's increased recovery should be subject to review in a subsequent rate proceeding.

Commission response

The commission declines to modify the proposed rule to describe the language that a TEEEF lease alteration provision should contain or authorize specific considerations to be included in a TEEEF lease as recommended by CenterPoint. Provided that a lease complies with the requirements of adopted §25.56(d)(2)(A), the lease terms and conditions, including the specific language of the alteration provision, or considerations for a lease amendment are subject to negotiation and agreement between the parties executing the lease.

OPUC and Houston asserted that the proposed rule language should be further modified to require an alteration provision to be included in all TEEEF leases that were entered into before SB 231, specifically upon renewal or extension of these leases.

Commission response

The commission declines to modify the proposed rule to require all TEEEF leases entered into before SB 231 to include an alteration provision upon renewal or extension as recommended by OPUC and Houston because it is unnecessary. Adopted §25.56(d)(2)(A) specifies that, if a TDU enters into, renews, or extends a lease involving a TEEEF without prior commission authorization, the lease must include an alteration provision.

OCSC and OPUC recommended in its initial comments that any modifications be focused on establishing a standard lease alteration process and ensuring active commission oversight in TEEEF leasing and deployment.

OCSC additionally recommended that, while it believes the instances in which a TDU leases TEEEF without prior commission authorization should be limited, the procedural process for alteration of these leases should be limited to eliciting comments. Oncor agreed with OCSC that a lease alteration proceeding should not equate to a complete contested case and additionally recommended that interested parties and the TDU have the opportunity to provide input on the original lease terms and any impacts of lease term alterations.

Commission response

The commission agrees with OCSC and OPUC that the rule should include language specifying how the commission will review a TEEEF lease for alteration and adopts §25.56(f) to provide that commission review of a TEEEF lease will entail a contested case proceeding.

The commission agrees with Oncor that interested parties and the TDU should have the opportunity to participate in these proceedings and specifies in adopted §25.56(f)(1)(A) that commission staff, the TDU, OPUC, any other parties to the lease, and anyone granted intervenor status by the proceeding's presiding officer may participate in these proceedings as parties.

AEP asserted that the proposed rule language should be modified to: 1) limit commission alteration of a lease to the first time the lease is reviewed for prudence, and 2) only allow the commission to alter a lease once. OPUC opposed the first recommendation, arguing that it lacks statutory support and is contrary to the legislative intent.

Commission response

The commission declines to modify the proposed rule to limit the commission's ability to alter a TEEEF lease as recommended by AEP because such limitations are not established by PURA §39.918. The manner in which a TDU leases and deploys TEEEF can have significant consequences for public safety, regulated rates, and the health of the competitive market. The commission will not, by rule, limit its ability to intervene when required to protect the public interest.

AEP recommended that TDUs be able to recover costs associated with a lease alteration and provided redlines consistent with its recommendation. While OPUC expressed openness to this recommendation, Houston argued both that the commission already has discretion to review and consider a TDU's lease costs and that costs associated with leases entered under PURA §39.918(f-1)(2) should be fully borne by the TDU.

Commission response

The commission declines to modify the proposed rule to specify that lease alteration costs are recoverable as recommended by AEP because it is unnecessary. Adopted §25.56(i) provides that reasonable and necessary costs of leasing and operating a TEEEF, including the present value of future payments required under the lease, are eligible for recovery under §25.56. However, the commission also emphasizes that imprudently incurred alteration costs may be disallowed during the TDU's base rate case.

Question 1.b.i

AEP asserted that PURA §39.918(f-1)(2) should be limited to emergency TEEEF leases under proposed §25.56(d).

Houston, CenterPoint, Oncor, OPUC, and OCSC asserted that PURA §39.918(f-1)(2) should not be limited to emergency TEEEF leases under proposed §25.56(d). However, OCSC additionally asserted that the instances in which TDUs enter into TEEEF leases without prior commission authorization should be limited.

Commission response

The commission agrees with Houston, CenterPoint, OPUC, and OCSC that the language of PURA §39.918(f-1)(2) does not apply only to emergency TEEEF leases under proposed §25.56(d). Accordingly, the commission adopts §25.56(d)(2)(A) and (B) to govern, respectively, leases entered into under PURA §39.918(f-1)(2) and emergency TEEEF leases.

Question 1.b.ii

Houston, OCSC, CenterPoint, and OPUC asserted that the rule should not provide that the grounds for lease alteration under PURA §39.918(f-1)(2) are limited to when the commission deems expenses imprudent in a ratemaking proceeding because PURA §39.918(f-1)(2) provides no such limitation.

AEP asserted that the rule should provide that the grounds for lease alteration under PURA §39.918(f-1)(2) are limited to only when the commission deems expenses imprudent in a ratemaking proceeding. AEP reasoned that "The risk that the Commission can initiate an action at any time to require a utility to alter a lease would serve to increase risks to both contracting parties." Further, AEP requested that, if the commission determines it can alter a lease on grounds beyond an imprudence determination, the commission identify specific circumstances under which lease alterations may occur.

Commission response

The commission agrees with Houston, OCSC, CenterPoint, and OPUC that PURA §39.918(f-1)(2) does not limit the grounds upon which the commission may alter a lease to an imprudence finding in a ratemaking proceeding. Under PURA 39.918(f-1)(2) a TDU is not required to obtain commission authorization before entering into a TEEEF lease if the lease "includes a provision that allows alteration of the lease based on commission order or rule." The narrowest interpretation of this provision, as recommended by AEP, is that this language only functions to ensure that TEEEF leases allow for the lease terms to be altered if the commission determines that the costs associated with the lease are imprudent. The commission rejects this interpretation because it would render the statutory provision virtually meaningless. The parties to a TEEEF lease are already capable of negotiating lease terms that protect the TDU and TEEEF vendor from having to remain in contracts that face regulatory scrutiny or renegotiating a TEEEF lease if mutually beneficial to the two parties. Moreover, there are no instances in which a TDU is legally required by the commission to enter into or retain TEEEF leases, and the commission is already capable of protecting ratepayers from imprudent lease costs through prudence reviews in rate cases.

Taking into account the broad statutory language, the legitimate policy concerns surrounding TEEEF leases, and the political context in which this language was adopted--following the events of Hurricane Beryl, multiple legislative hearings, reports, and statements that contained concerns over costs, procurement practices, operational characteristics, lease terms, etc.--it is clear that the Legislature intended for the commission to have the authority to intervene in TEEEF leases before the prudence review. In addition to protecting both TDUs and ratepayers from incurring unreasonable costs, this also ensures the commission has tools to protect the public from unreliable technology during emergencies, safeguard the competitive market from incursion by regulated entities, and unwind contractual agreements that resulted from fraudulent procurement practices.

Question 1.b.iii

Houston, OCSC, and OPUC asserted that the rule should provide that the commission can initiate an action to alter a lease under PURA §39.918(f-1)(2) at any time.

CenterPoint asserted that it is unnecessary for the rule to provide that the commission is able to initiate an action to alter a lease under PURA §39.918(f-1)(2) at any time. However, CenterPoint recommended that, if such a provision is included in the rule, it should specify that only those leases that did not receive prior commission authorization under proposed §25.56(d) are subject to alteration. CenterPoint provided redlines consistent with its recommendation.

AEP asserted that the commission should only be able to initiate an action to alter a lease under PURA §39.918(f-1)(2) during the lease's initial prudency review. AEP argued that "The risk that the Commission can initiate an action at any time…would serve to increase costs to enter the lease to balance the risk the counterparty would be assuming for entering such an agreement." OPUC disagreed with AEP's argument and contended that such a limitation to the commission's ability to alter a lease could result in ratepayer harm.

Commission response

The commission agrees with Houston, OCSC, and OPUC that the commission can initiate an action to alter a lease at any time and adopts language to that effect in §25.56(f).

Question 1.b.iii.1

Under new PURA § 39.918(f-1)(2), a TDU can enter into a lease for TEEEF without receiving prior approval from the commission if "the lease includes a provision that allows alteration of the lease based on commission order or rule." Should the proposed rule provide that the commission can initiate an action at any time to require a TDU to alter a lease entered into under PURA § 39.918(f-1)(2)? If yes: Under what circumstances should the commission initiate a proceeding to order a TDU to alter a TEEEF lease? What types of alterations might the commission consider ordering in response to these circumstances? Does this include early termination of the lease?

Houston asserted that the commission should be able to initiate a proceeding to alter a TEEEF lease in two scenarios: 1) upon a determination that TEEEF units are likely incapable of, or are unlikely to be, used and useful in the TDU's service territory; and 2) when the lease cost or expenses appear to be excessive, lacking cost-benefit, or otherwise imprudent. OPUC agreed with Houston's recommended alteration scenarios. AEP expressed openness to Houston's second alteration scenario, provided the commission's review is limited to instances where the leases have been found imprudent. CenterPoint opposed Houston's second alteration scenario, noting that assessing costs for reasonableness is the purpose of a ratemaking proceeding.

OCSC asserted that the commission should be able to initiate a proceeding to alter a lease entered into without prior commission authorization if a TDU fails to demonstrate that: 1) the TDU lacked the necessary leased TEEEF generating capacity to restore power; 2) the amount of TEEEF generating capacity leased without prior commission authorization did not exceed the necessary megawatts to restore power; or 3) the lease term did not exceed the time necessary to restore power. OPUC agreed with OCSC's recommendations.

CenterPoint asserted that the commission should only initiate a lease alteration proceeding if necessary to: 1) ensure compliance with PURA §39.918(d); 2) impose changes to TEEEF units' capacity or functionality; or 3) amend the lease term. OPUC agreed with CenterPoint's recommendations. CenterPoint further urged the commission to exercise its authority to alter leases infrequently, lest TEEEF vendors charge higher premiums for a lease alteration provision due to regulatory uncertainty. CenterPoint provided redlines consistent with its recommendation.

OPUC asserted that the commission should be able to initiate a proceeding based on: 1) non-compliance with PURA §39.918(d)(3) or (d)(4); 2) imprudence during emergency conditions, including for not deploying TEEEF; 3) after-action report findings; 4) non-compliance with competitive bidding requirements; and 5) non-compliance with ERCOT directives.

Commission response

Instead of enumerating specific circumstances that will trigger commission review of a lease, the commission specifies in adopted §25.56(f) that, on its own motion or on the motion of commission staff, the commission may initiate a contested case proceeding to review a lease entered into under adopted §25.56(d)(2)(A) to determine whether the public interest requires the alteration or termination of the lease.

Houston asserted that the commission may alter a lease agreement by reducing the lease term, ordering an early termination of the lease, or altering the lease agreement terms. OPUC asserted that commission alteration of a TEEEF lease may include early termination of the lease, modification of the lease term or number of leased TEEEF, and assignment of the lease.

Commission response

The commission agrees with Houston and OPUC that, under PURA §39.918(f-1)(2), the commission has permissive authority to order a TDU to alter a TEEEF lease, including by ordering the TDU to terminate the lease, and incorporates language to that effect throughout the adopted rule. However, the commission also recognizes that the alteration or termination of a lease is a relatively extreme remedy that should not be taken lightly. Further, the commission acknowledges that it must proceed with caution and deliberation when requiring the alteration or termination of a TEEEF lease because such a decision is not isolated in impact and may result in externalities like increased TEEEF lease costs due to regulatory uncertainty.

Question 1.b.iii.2

Houston asserted that the commission should use the same standards and criteria it would use in a ratemaking proceeding or separate contested case hearing to determine the appropriate capacity, function, or prudent expense of a TEEEF lease. OPUC agreed with Houston's recommendation.

CenterPoint asserted that the commission should use different criteria as grounds for lease alterations, depending on how the lease is executed. For leases executed under PURA §39.918(f-1)(2), CenterPoint recommended the alteration be consistent with the requirements of PURA §39.918(d). For leases executed under PURA §39.918(f-1)(2) that come after an authorization under PURA §39.918(f-1)(1), CenterPoint recommended the alteration be consistent with the capacity and functionality restrictions established in the commission's prior authorization. OPUC agreed with CenterPoint's recommendations.

OPUC asserted that the commission should evaluate TEEEF leases for imprudence of a lease itself and the costs associated with the lease, use patterns of leased TEEEF, and non-compliance with regulatory requirements, including the TEEEF specifications under PURA §39.918(d)(3) and (d)(4), the competitive bidding requirements under proposed §25.56(c)(5), and ERCOT directives.

AEP asserted that the commission's evaluation standard for lease alteration should be "whether the TDU acted as a prudent operator of a utility based on the information available at the time of the decision was made to enter the lease and that the lease terms comport with that standard." OPUC agreed with AEP's recommendation.

Commission response

The commission adopts a public interest standard under §25.56(f) and specifies in adopted §25.56(f)(2) that, in evaluating the public interest of a lease, the commission may consider any factors it deems appropriate, including compliance with the requirements of PURA, §25.56, and any other applicable law; operational failures; deployment history; and the size, characteristics, and deployment history of the TDU's leased TEEEF fleet.

Question 1.b.iii.3

Under new PURA § 39.918(f-1)(2), a TDU can enter into a lease for TEEEF without receiving prior approval from the commission if "the lease includes a provision that allows alteration of the lease based on commission order or rule." Should the proposed rule provide that the commission can initiate an action at any time to require a TDU to alter a lease entered into under PURA § 39.918(f-1)(2)? If yes: Should the proposed rule include procedural language governing a contested case proceeding to evaluate whether a TDU should be ordered to alter its lease? What should that procedural language look like?

Houston asserted that the rule should include language that resembles the procedural language for an application processed in a contested case proceeding. Further, Houston asserted that the procedural language should require justification for initiating the proceeding that demonstrates why the lease is not in the public interest. Oncor disagreed with Houston's recommendation that the rule should include procedural language akin to a contested case proceeding.

OCSC asserted that procedural language no more robust than eliciting comments should be added to the rule. CenterPoint agreed with OCSC's recommendation.

CenterPoint asserted that §25.56(c)(2) should provide that the procedure for governing a lease alteration proceeding will be governed by 16 TAC §22.241, relating to Investigations, under an expedited procedural schedule that requires a final order in the proceeding to be issued within 60 days of the proceeding's initiation. CenterPoint provided redlines consistent with its recommendation. OCSC and OPUC opposed CenterPoint's recommendation.

OPUC asserted that the rule should include broad procedural language that imposes no additional limitations to the timeline or scope of a lease alteration proceeding but grants OPUC the right to intervene.

AEP asserted that the rule should include procedural language mirroring that of the Distribution Cost Recovery Factor (DCRF) proceeding. OCSC and OPUC opposed AEP's recommendation.

Commission response

The commission agrees with Houston and provides under adopted §25.56(f) that, on its own motion or on the motion of commission staff, the commission may initiate a contested case proceeding to review a lease entered into under adopted §25.56(d)(2)(A) to determine whether the public interest requires the alteration or termination of the lease. Further, adopted §25.56(f)(1) specifies that commission staff, the TDU, OPUC, any other parties to the lease, and anyone granted intervenor status by the presiding officer may participate in the proceeding as parties and that commission staff is responsible for providing notice of the proceeding to those parties.

Question 1.c

Under new PURA § 39.918(f-1)(2), a TDU can enter into a lease for TEEEF without receiving prior approval from the commission if "the lease includes a provision that allows alteration of the lease based on commission order or rule." Should the proposed rule provide standard language for leases entered into under PURA §39.918(f-1)(2)? If so, what should that standard language include? (i.e., language that authorizes commission alteration of a TEEEF lease based on commission order or rule, commission-specific termination clause, etc.)

Houston and OCSC expressed general support for including standard lease alteration language in the rule. Houston recommended that the standard lease language require an acknowledgement that the lease may be subject to alteration under PURA §39.918(f-1)(2). OCSC reasoned that a standardized language requirement would streamline compliance with regulatory requirements, ensure consistent language across all TEEEF leases under PURA §39.918(f-1)(2), and put all parties to a lease on notice that the lease has not be previously authorized by the commission and is therefore subject to potential review and alteration.

Oncor and OPUC expressed support for including standard lease alteration language in the rule, provided that the language is broad or provided as an example of acceptable language. Oncor expressed concern that the imposition of mandatory, specific language would limit TDUs' TEEEF vendor options or push TDUs to only utilize the other statutorily provided leasing avenues. OPUC expressed concern that specific language requirements could cause contention during lease negotiations and hinder TDUs from securing TEEEF leasing arrangements.

CenterPoint and AEP asserted that the rule should not include standard lease alteration language. CenterPoint argued that, because vendors often have their own standard lease language, vendors may be reluctant to utilize language mandated by the commission. AEP argued that, because each utility has different characteristics, the language requirements should remain flexible.

Commission response

The commission declines to provide specific mandatory or example lease alteration language in the adopted rule because lease terms and conditions, including the specific language used in a lease agreement, are subject to negotiation and agreement between the parties executing the lease. Instead, the commission adopts §25.56(d)(2)(A)(i) to specify that a TDU's lease must include the following general provisions: 1) a provision that allows alteration or termination of the lease based on commission order or rule; 2) a provision in which the parties of the lease acknowledge that the commission may, at any time, initiate a proceeding to order alteration or termination of the lease; 3) a provision stating that the commission retains, without restriction, the right to investigate, request access to, and review the lease, including the subject matter and parties of the lease, at any time; and 4) a provision stating that any party to the lease agrees to the terms described in the prior provisions and consents to the commission's jurisdiction in any investigation or proceeding to alter or terminate the lease.

Question 1.d

Houston, OCSC, CenterPoint, and OPUC supported--and Oncor conditionally supported--a notice requirement for leases entered into under PURA §39.918(f-1)(2). Oncor specified that it was supportive of such a requirement only if the notice is limited to basic lease information--such as the number of leased TEEEF, the generating capacity of leased TEEEF, and the lease term--and entities have a minimum of seven days to file the notice. OCSC and OPUC supported Oncor's minimum filing timeline recommendation but asserted that notices should be filed no later than 15 days after lease execution.

AEP asserted that a notice requirement is unnecessary and argued that, because TDUs often enter into a TEEEF lease and file to recover the associated costs in the same year, all relevant parties will be noticed to the TEEEF lease in that cost recovery proceeding. Houston and OCSC disagreed with AEP and argued that a notice requirement is important for both public transparency and ensuring the commission's ability to timely review leases entered into under PURA §39.918(f-1)(2).

Commission response

The commission adopts §25.56(d)(2)(A)(ii) to require a TDU to file, not later than 14 days after entering into the lease and in a control number designated for this purpose by commission staff, a public notice that contains a high-level description of the lease and leased TEEEF and a statement of compliance with adopted §25.56(d)(2)(A)(i).

Question 1.d.i

Houston, OCSC, and OPUC supported--and CenterPoint and Oncor conditionally supported--a public notice requirement. CenterPoint and Oncor specified that they were willing to file notice publicly if the commission designates a project for that purpose and the notice is not required to include confidential or commercially sensitive information. OPUC agreed that the commission should open a dedicated project for these notices.

AEP asserted that a notice requirement is unnecessary.

Commission response

Question 1.d.ii

Under new PURA § 39.918(f-1)(2), a TDU can enter into a lease for TEEEF without receiving prior approval from the commission if "the lease includes a provision that allows alteration of the lease based on commission order or rule." Should the proposed rule require TDUs to provide notice to the commission upon entering into a lease under PURA § 39.918(f-1)(2)? If yes: Should the notice include: 1. the lease itself; 2. a description of the leased TEEEF, including the size, quantity, and characteristics of the leased units, the functions the units were leased to perform, the length of the lease, the cost of the units, etc.; or 3. an attestation from the TDU that the lease includes alteration language as required by PURA § 39.918(f-1)(2)?

Houston, OCSC, and OPUC asserted that a TDU's notice should include the lease itself, a description of the leased TEEEF, and an attestation from the TDU that the lease includes language permitting alteration. Houston additionally asserted that a TDU's notice should include a discussion of the need and prudence of the lease. OPUC additionally asserted that a TDU's notice should disclose the process used to obtain the lease and that the attestation should be signed by the TDU's chief executive officer.

CenterPoint and Oncor asserted that a TDU's notice should not be required to include the lease itself because leases contain highly sensitive or confidential information. However, Oncor requested that, if leases are a required part of the notice, TDUs be allowed to file the leases as highly sensitive confidential material. OCSC and OPUC supported Oncor's recommendation, provided that the notice includes a protective order certification and interested parties can obtain access to the confidential or highly sensitive components of the notice. Oncor opposed OCSC's and OPUC's recommendation that confidentially filed leases be made accessible via protective order and asserted that no interested parties, except for the commission, commission staff, and perhaps OPUC, should be able to access the commercially sensitive details of these leases.

CenterPoint and Oncor were willing to provide a high-level description of the lease in the public notice--including the number of leased TEEEF, the generating capacity of the leased TEEEF, the lease term, and overall costs--provided that the disclosure of commercially sensitive and detailed cost information is not required. Oncor requested that TDUs not be required to list the specific functions TEEEF were leased to perform. Houston opposed Oncor's request and asserted that disclosure of the leased TEEEF's intended functions is important for public transparency and commission oversight.

Oncor was willing to provide an attestation as part of the notice, provided that any company officer can make the attestation. CenterPoint opposed such a requirement--calling it unnecessary--but expressed willingness to instead provide a "statement of compliance."

AEP asserted that a notice requirement is unnecessary.

Commission response

Question 1.d.iii

Houston asserted that, after a TDU's notice is filed, the commission need only review the notice and issue a response that either affirms the rule requirements are met or directs the TDU to submit an application under proposed §25.60(d).

OCSC asserted that, if the commission can initiate a lease alteration action at any time, no action in response to a notice is necessary. However, OCSC recommended that the rule authorize the commission to request any additional information deemed necessary after a notice is filed. OPUC supported OCSC's recommendation that the rule should authorize the commission to request any additional information necessary in response to a notice.

CenterPoint and Oncor asserted that no commission action is needed in response to a notice. CenterPoint noted that proposed §25.60(c)(6) allows the commission and commission staff to request a copy of the lease on a confidential basis if desired. Oncor asserted that the notice should serve as an informational filing only and, if desired, the commission can open an inquiry into the lease. However, Oncor recommended that the rule specify that the commission can only require a lease alteration if the commission initiates an inquiry into the lease within 180 days of receiving notice from the utility. OPUC opposed Oncor's recommendation to impose a 180-day deadline on the commission's initiation of an inquiry.

OPUC asserted that the commission should initiate a proceeding to alter a lease if the notice alerts the commission to non-compliance with rule requirements.

AEP asserted that a notice requirement is unnecessary.

Commission response

The commission agrees with Houston, OCSC, CenterPoint, and Oncor that a TDU's notice does not require responsive commission action.

Question 2

New PURA § 39.918(f-2) provides that "the commission may limit the period during which an authorization issued under Subsection (f-1) is valid." Proposed 16 TAC § 25.56(c)(4) provides that "the commission's final order will include... the date or dates the authorization expires (i.e., TEEEF leases must not extend past this date)." Should the proposed rule maintain this case-by-case authorization approach, or establish a uniform time limit on authorizations for TEEEF leases under proposed 16 TAC § 25.56(c)? If advocating for the latter, what should that uniform limit be?

Houston, CenterPoint, Oncor, and OPUC recommended that a case-by-case authorization approach continue to be used.

OCSC and AEP recommended that the commission establish a uniform time limit on TEEEF authorizations. Specifically, OCSC recommended implementing a tiered, uniform time limit approach based on the length of TEEEF leases. OCSC reasoned that TDUs with longer TEEEF leases should be required to seek reauthorization to ensure the commission can evaluate whether the lease terms are appropriate, and that the usage of such facilities remains effective. Oncor recommended that, if implemented, any uniform time limit allow a minimum five-year lease term length.

Commission response

The commission declines to adopt a uniform time limit on TEEEF authorizations and instead retains a case-by-case authorization approach in adopted §25.56(e)(3)(B).

Question 3

What else should the commission consider in implementing the changes made to PURA §39.918 by SB 231?

Houston recommended that proposed §25.56(c)(4)(B) establish a mandatory TEEEF dispatch and connection timeframe. OPUC supported Houston's recommendation. Oncor, CenterPoint, and AEP disagreed with Houston's recommendation, reasoning that PURA §39.918 does not provide a timeframe for TEEEF dispatch and that the specification of such a timeframe would be impracticable due to the operational and situational considerations a TDU must make when dispatching a TEEEF.

Commission response

The commission declines to modify the proposed rule to establish a mandatory TEEEF dispatch and connection timeframe as recommended by Houston because such a requirement is not provided for in PURA §39.918.

CenterPoint urged the commission to include rule language that reduces the risk of TEEEF expenses associated with leases that received prior authorization being deemed imprudent in a ratemaking proceeding. OCSC and OPUC disagreed with CenterPoint's recommendation, arguing that full commission review of the reasonableness, necessity, and prudence of TEEEF lease expenses in a ratemaking proceeding is necessary to reduce the risk of harm to all parties, including ratepayers.

Commission response

The commission declines to modify the proposed rule to include language that reduces the risk of TEEEF lease expenses being deemed imprudent in a ratemaking proceeding as recommended by CenterPoint because such a modification is outside of the noticed scope of this rulemaking.

OPUC recommended that the commission add a penalty provision to the adopted rule, applicable to TDUs that do not deploy their TEEEF in qualifying situations. Oncor, CenterPoint, and AEP opposed OPUC's recommendation. Oncor and AEP argued that the introduction of such penalty language would ignore the variety of operational and situational factors that a TDU must consider during an emergency situation. Further, Oncor argued that, if any penalty is assessed against a TDU, it should happen only after a robust analysis is conducted by the commission. CenterPoint argued that OPUC's recommendation goes beyond the noticed rulemaking scope of changes required to implement SB 231.

Commission response

The commission declines to modify the proposed rule to add a penalty provision for non-deployment of TEEEF as recommended by OPUC because such a modification is outside of the noticed scope of this rulemaking.

Comments on proposed §25.56

General comments

Emergency TEEEF leases

Oncor recommended that the phrase "without prior commission authorization" be restored and added, respectively, to the emergency TEEEF lease provisions in proposed §25.56(e)(1) and (c)(3) to clarify that a TDU may enter into an emergency TEEEF lease without prior commission authorization.

Commission response

The commission deletes proposed §25.56(c)(3) and (e)(1) and adopts a single provision--§25.56(d)(2)(B)--to govern emergency TEEEF leases. Further, the commission specifies in adopted §25.56(d)(2)(B) that, contingent on meeting the provision's requirements, a TDU may enter into a lease involving a TEEEF without prior authorization from the commission and without complying with the requirements of adopted §25.56(d)(2)(A).

Proposed §25.56(c)(5)

Proposed §25.56(c)(5) requires, with an exception for emergency TEEEF leases, TDUs to use a competitive bidding process to lease TEEEF.

Oncor asserted that, despite attempts to procure TEEEF competitively, there may be situations in which there is only one qualified vendor willing and able to lease the particular TEEEF needed. Accordingly, Oncor recommended adding language to proposed §25.56(c)(5) to clarify that, even if only one vendor submits a bid, a TDU will be considered to have used a competitive bidding process if it solicited bids from multiple vendors.

Commission response

The commission declines to modify proposed §25.56(c)(5) to clarify that, regardless of the volume of vendor bids received, a TDU will be considered to have used a competitive bidding process if it solicited bids from multiple vendors as recommended by Oncor because it is unnecessary. The competitive bidding process requirements under adopted §25.56(d)(3) govern a TDU's bid solicitation process, not the volume of responsive bids received.

Proposed §25.56(c)(6)

Proposed §25.56(c)(6) establishes that a TDU must allow for the inspection of any TEEEF lease if requested by a commissioner or commission staff and that, if the commissioner or commission staff retains a copy of a TEEEF lease, the lease will be treated as a confidential document if so requested by the TDU.

AEP recommended that proposed §25.56(c)(6) be revised to provide that, if a commissioner or a member of commission staff retains a copy of a TEEEF lease, the lease will be treated as highly sensitive protected material instead of confidential material. AEP also asserted that, because PURA §39.918 requires TDUs to use a competitive bidding process to lease TEEEF, the lease terms and pricing should, at minimum, be considered competitively information and trade secrets of the lessees.

Commission response

The commission declines to modify proposed §25.56(c)(6) as recommended by AEP because such a modification is outside the noticed scope of this rulemaking.

The amendment is adopted under Public Utility Regulatory Act (PURA) §§ 14.001, which grants the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by this title that is necessary and convenient to the exercise of that power and jurisdiction; 14.002, which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; and 39.918, which directs the commission to allow TDUs to lease, operate, and recover costs for TEEEF to aid in restoring power to a utility's distribution customers during a significant power outage.

Cross Reference to Statute: Public Utility Regulatory Act §§ 14.001; 14.002; and 39.918.

§25.56. Temporary Emergency Electric Energy Facilities (TEEEF).

(a) Purpose and applicability. This section establishes the requirements for a transmission and distribution utility (TDU) to lease, operate, and recover costs associated with a temporary emergency electric energy facility (TEEEF). This section applies to a TDU that operates facilities in the Electric Reliability Council of Texas (ERCOT) region to serve distribution customers.

(b) Definitions. The following terms, when used in this section, have the following meanings unless the context indicates otherwise.

(1) Affected generator or load resource--a generator or load resource that:

(A) is registered with ERCOT for purposes of settlement; and

(B) is located within the portion of the grid that is isolated from the bulk power system and where a TEEEF is energized to restore power.

(2) Significant power outage--an event that:

(A) causes ERCOT to order a TDU to shed load;

(B) the Texas Division of Emergency Management, ERCOT, or the executive director of the commission determines is a significant power outage; or

(i) affects a significant number of a TDU's distribution customers, and has lasted, or is expected to last, for at least six hours;

(ii) affects distribution customers of a TDU in an area for which the governor has issued a disaster or emergency declaration;

(iii) affects distribution customers served by a radial transmission or distribution facility, creates a risk to public health or safety, and has lasted, or is expected to last for, at least 12 hours; or

(iv) creates a risk to public health or safety because it affects a critical infrastructure facility that serves the public such as a hospital, health care facility, law enforcement facility, fire station, or water or wastewater facility.

(3) Temporary emergency electric energy facility (TEEEF)--a facility that provides electric energy to distribution customers on a temporary basis.

(1) has a maximum generation capacity of five megawatts or less;

(2) is mobile;

(3) is capable of being moved from its staged location in less than 12 hours; and

(4) is capable of generating electric energy within three hours after being connected to a demand source.

(d) Lease requirements. A TDU must not enter into, renew, or extend any lease involving a TEEEF, except as provided in this subsection.

(1) With prior authorization. After receiving authorization under subsection (e) of this section, a TDU may enter into, renew, or extend one or more leases for TEEEF, simultaneously or consecutively, provided that the capacity and characteristics of the entire portion of the TDU's leased TEEEF fleet that is authorized under subsection (e) of this section complies with the authorization provided at all times.

(2) Without prior authorization.

(A) Lease with alteration provision. Notwithstanding an emergency lease under subparagraph (B) of this paragraph, a TDU may only enter into, renew, or extend a lease involving a TEEEF without prior authorization from the commission if:

(i) the lease contains:

(I) a provision that allows alteration or termination of the lease based on commission order or rule;

(II) a provision in which the parties of the lease acknowledge that the commission may, at any time, initiate a proceeding to order alteration or termination of the lease;

(III) a provision stating that the commission retains, without restriction, the right to investigate, request access to, and review the lease, including the subject matter and parties of the lease, at any time; and

(IV) a provision stating that any party to the lease agrees to the terms described in this clause and consents to the commission's jurisdiction in any investigation or proceeding to alter or terminate the lease.

(ii) Not later than 14 days after entering into the lease, the TDU files, in a control number designated for this purpose by commission staff, a public notice that:

(I) discloses the number of leased TEEEF, the generating capacity and intended function of each leased TEEEF, and the lease term; and

(II) includes a statement that affirms the lease contains the provisions required under clause (i) of this subparagraph.

(B) Emergency lease.

(i) A TDU may enter into a lease involving a TEEEF without prior authorization from the commission and without complying with the requirements of subparagraph (A) of this paragraph if:

(I) the TDU lacks the leased TEEEF generating capacity necessary to aid in restoring power to its distribution customers, consistent with subsection (g) of this section;

(II) the leased amount of TEEEF generating capacity does not exceed the amount of megawatts necessary to restore electric service to its distribution customers by more than a reasonable amount; and

(III) the lease term does not exceed the length of time necessary to restore electric service to its distribution customers by more than a reasonable amount.

(ii) A TDU that enters into a lease under this subparagraph must provide during its next base-rate proceeding sufficient documentation to support the reasonableness, necessity, and prudence of the leased TEEEF generating capacity and any costs associated with the lease.

(3) Competitive bidding process. Except for an emergency lease entered into under paragraph (2)(B) of this subsection, a TDU must use a competitive bidding process to lease a TEEEF.

(A) In any proceeding in which the commission is reviewing the reasonableness, necessity, or prudence of the costs associated with leasing a TEEEF under this section, the commission may also consider whether the contracts the TDU entered into to lease TEEEF were reasonable relative to other bids that were available to the TDU, if any.

(B) In any proceeding in which a TDU is requesting recovery of costs associated with a TEEEF that was leased without using a competitive bidding process, the TDU must demonstrate that the TEEEF was leased under paragraph (2)(B) of this subsection.

(C) A TDU may not enter into a lease for TEEEF with a competitive affiliate of the TDU unless that lease was subject to a competitive bidding process.

(4) If requested by a commissioner or commission staff, a TDU must allow for the inspection of any lease entered into under this section. If the commissioner or commission staff retains a copy of the lease, the lease will be treated as a confidential document if so requested by the TDU.

(e) Prior authorization to lease TEEEF. A TDU may apply for commission authorization to lease a TEEEF in accordance with this subsection.

(1) Application. An application must include:

(A) The TDU's history with TEEEF, including:

(i) Whether the TDU is currently or has previously been authorized by the commission to lease TEEEF, the details of existing or prior authorizations, and each docket number in which the authorization was granted;

(ii) A description of all TEEEF the TDU has under lease at the time of the application, including the total capacity the TDU has under lease, the length of the lease or leases, a description of the capacity, intended functions, and relevant characteristics of each leased unit, and whether each leased unit has been energized to aid in restoring power during a significant power outage;

(iii) A description of any previous emergency leases of TEEEF or prior use of another TDU's TEEEF under a mutual assistance agreement or program. A TDU must include an explanation for the necessity of each use of TEEEF under an emergency lease or mutual assistance agreement or program;

(iv) A copy of every after-action report submitted by the TDU to the commission under this section during the five years prior to the date on which the application was filed, including a cover page with summary statistics on significant power outages and TEEEF energizations in the TDU's service territory; and

(v) The interchange item number of the TDU's most recently filed emergency operations plan filed in project no. 53385.

(B) The total capacity of TEEEF the TDU is requesting authorization to lease, each function the requested TEEEF will serve (e.g. to restore power to individual facilities, to restore power to feeders to assist in load rotation, etc.) and how much of the requested capacity is requested for each function, and the length of time for which the TDU is requesting authorization. In support of its request, the TDU must include the following:

(i) A description of any necessary characteristics a TEEEF unit must have to perform each of the functions for which authorization is requested. These characteristics should be identified with enough specificity to allow the commission to evaluate, in a subsequent proceeding, whether the TDU's leased TEEEF fleet complies with the commission's authorization. These characteristics should include, as applicable, the capacity or range of capacities of individual units, the mobility of individual units, the types of connections the units must be compatible with, such as mid-span or point-of-use, fuel type, and whether the units can fulfill the function individually or with multiple units working in tandem;

(ii) An explanation with any necessary supporting documentation that the functions the TEEEF is being requested to perform are reasonable and necessary to aid in the restoration of power under this section. This supporting documentation must include, at minimum, historical data on significant power outages that occurred in the TDU's service territory and would have qualified for TEEEF deployment for the five-year period preceding the date of the application, including:

(I) the start and end date of the outage and information on how long customers were affected by the outage;

(II) a description of the events that caused the outage;

(III) the number of affected distribution customers and amount of load, in megawatts, that were affected by the outage; and

(IV) the number and type of critical load, critical care customers, or other critical infrastructure facilities as defined in §25.497 of this title (relating to Critical Load Industrial Customers, Critical Load Public Safety Customers, Critical Care Residential Customers, and Chronic Condition Residential Customers) affected by the outage.

(iii) A description of any additional measures being implemented or scheduled for implementation that may mitigate the need for TEEEF, such as the TDU's implementation of a resiliency plan measure under §25.62 of this chapter, relating to Transmission and Distribution System Resiliency Plans.

(C) As appropriate, data provided under this section must be filed in a format native to Microsoft Excel and must permit basic data manipulation functions, such as copying and pasting of data.

(2) Commission processing. An application will be processed in a contested case proceeding as follows.

(A) Sufficiency. An application is sufficient if it includes the information required by paragraph (1) of this subsection and the TDU has filed proof that notice has been provided in accordance with this subsection.

(i) Within 30 calendar days of the TDU filing its application, commission staff must file a recommendation on sufficiency of the application. If commission staff recommends the application be found deficient, commission staff must identify the deficiencies in its recommendation. The TDU will have five working days to file a response, which may include an amendment to the application to attempt to cure the deficiency.

(ii) If the presiding officer determines the application is deficient, the presiding officer will file a notice of deficiency and cite the particular requirements with which the application does not comply. The presiding officer must provide the TDU an opportunity to amend its application. Commission staff must file a recommendation on sufficiency within 10 working days after the filing of an amended application, when the amendment is filed in response to a notice of deficiency.

(iii) If the presiding officer has not filed a written order concluding that the application is deficient within 10 working days after a deadline for a recommendation on sufficiency, the application is deemed sufficient.

(B) Notice and intervention. Within one working day after the TDU files its application, the TDU must provide notice of its filed application, including the docket number assigned to the application and the deadline for intervention in accordance with this paragraph. The intervention deadline is 30 days from the date service of notice is complete. The notice must be provided using a reasonable method of notice to:

(i) all municipalities in the TDU's service area that have retained original jurisdiction;

(ii) all parties in the TDU's last base-rate proceeding;

(iii) each retail electric provider that provides service in the TDU's service area; and

(iv) the Office of Public Utility Counsel.

(3) Commission evaluation and decision.

(A) The commission will authorize a TDU to lease TEEEF under this subsection if it determines that leasing the requested TEEEF is reasonable and necessary to aid in restoring power to the TDU's distribution customers during a significant power outage that qualifies for TEEEF energization.

(B) The commission's final order will include the total TEEEF capacity the TDU is authorized to lease, the capacity of TEEEF the TDU is authorized to lease for each function the TEEEF fleet will perform, and the date or dates the authorization expires (i.e., TEEEF leases must not extend past this date). The commission may include additional requirements related to the characteristics of the TEEEF the TDU is authorized to lease.

(f) Alteration or termination of a TEEEF lease. The commission, on its own motion or on the motion of commission staff, may initiate a contested case proceeding to review a lease entered into under subsection (d)(2)(A) of this section to determine whether the public interest requires the alteration or termination of the lease.

(1) Parties and notice.

(A) Commission staff, the TDU, OPUC, any other parties to the lease, and anyone granted intervenor status by the presiding officer may participate in the proceeding as parties.

(B) Commission staff must provide notice, using a reasonable method of notice, of the proceeding to the TDU, OPUC, and any other parties to the lease. The TDU must facilitate the provision of notice to other parties to the lease by assisting commission staff in identifying and contacting these parties, as requested. The notice must include the docket number of the proceeding, identify the lease and TEEEF at issue, and state the factual and legal basis for initiating the proceeding.

(2) Commission evaluation and decision. If the commission determines the lease is not in the public interest, the commission may order the alteration or termination of the lease. In evaluating the public interest, the commission may consider any factors it deems appropriate, including compliance with the requirements of PURA, this section, and any other applicable law; operational failures; deployment history; and the size, characteristics, and deployment history of the TDU's leased TEEEF fleet.

(A) As appropriate, the commission will provide the TDU a reasonable amount of time to renegotiate the lease. The commission may open a compliance docket for this purpose.

(B) The commission's decision on whether to order the alteration or termination of a TEEEF lease is not, in itself, a determination on the prudence of the TDU entering into the lease.

(3) Nothing in this subsection prevents the parties to a lease from terminating a lease the commission orders altered in accordance with applicable law.

(g) Energization of TEEEF.

(1) A TDU may energize TEEEF to aid in restoring power to its distribution customers during an event that a TDU reasonably determines is a significant power outage in which:

(A) ERCOT has ordered the TDU to shed load; or

(B) the TDU's distribution facilities are not being fully served by the bulk power system under normal operations.

(2) A TDU may loan its leased TEEEF to other TDUs or otherwise utilize its leased TEEEF in another TDU's service territory under a mutual assistance agreement or program, provided that all costs and reimbursements associated with such a loan or utilization are properly accounted for and reconciled.

(3) A TDU that leases a TEEEF must not sell energy or ancillary services from the facility.

(4) A TEEEF must:

(A) be operated in isolation from the bulk power system; and

(B) not be included in locational marginal price calculations, pricing, or reliability models developed by ERCOT.

(5) Notice. A TDU must issue notices under subparagraphs (A), (B), (C), and (D) of this paragraph to ERCOT and all operators of affected generators or load resources. Notice under this paragraph is not required if the area isolated from the bulk power system does not contain any affected generators or load resources.

(A) Prior to isolation. For an isolation from the bulk power system due to circumstances within a TDU's control in which TEEEF will be energized, a TDU must issue notice at least 10 minutes prior to isolation of an affected area from the bulk power system. For an isolation from the bulk power system due to circumstances beyond a TDU's control in which TEEEF will be energized, a TDU must issue notice as soon as is reasonably practicable. Notices prior to isolation of an affected area from the bulk power system must include:

(i) identification of each substation and modeled load associated with customer load that will be served by TEEEF;

(ii) the total amount of load expected to be served by TEEEF;

(iii) the time the affected area is anticipated to be isolated from the bulk power system;

(iv) the time the affected area is anticipated to be reconnected to the bulk power system;

(v) identification of each generator or load resource that will be an affected generator or load resource following the energization of TEEEF; and

(vi) a statement that any energy produced by an affected generator during the time it is isolated from the bulk power system will not be settled through ERCOT.

(B) Upon isolation. For an isolation from the bulk power grid due to circumstances within a TDU's control in which TEEEF will be energized, a TDU must issue notice immediately upon isolation of an affected area from the bulk power system. For an isolation from the bulk power system due to circumstances beyond a TDU's control in which TEEEF will be energized, a TDU must issue notice as soon as is reasonably practicable. A notice issued under this subparagraph must state the time an affected area's isolation from the bulk power system was completed.

(C) Prior to reconnection. A TDU must issue notice at least 10 minutes prior to the reconnection of an affected area to the bulk power system. A notice issued under this subparagraph must state the anticipated time that an affected area will be reconnected to the bulk power system.

(D) Upon reconnection. A TDU must issue notice immediately after the reconnection of an affected area to the bulk power system has been completed. A notice issued under this subparagraph must state the time the reconnection of an affected area to the bulk power system was completed.

(E) If a TDU has issued notice under subparagraphs (A) or (C) of this paragraph, and coordination with ERCOT under paragraph (6) of this subsection results in a delay in the anticipated time of isolation or reconnection, the TDU must notify operators of affected generators and load resources of such delay.

(6) Coordination with ERCOT.

(A) TDUs. The requirements of this subparagraph apply only to energizations of TEEEF that occur outside of an energy emergency declared by ERCOT. A TDU's isolation or reconnection of load associated with an energization of TEEEF must be coordinated with ERCOT according to the following timeframes if the total amount of load at any single substation that would be isolated or reconnected exceeds 20 megawatts.

(i) For isolations of load from the bulk power system due to circumstances within a TDU's control, a TDU should coordinate with ERCOT within a period of 10 minutes.

(ii) For isolations of load from the bulk power system due to circumstances beyond a TDU's control, a TDU should coordinate with ERCOT as soon as is reasonably practicable.

(B) Affected generators and load resources.

(i) Upon receiving notice from a TDU that an affected area will be isolated from the bulk power system, an operator of an affected generator or load resource that is required by ERCOT protocols to provide status telemetry to ERCOT must, at the expected time of isolation as indicated in the TDU's notice, update its real-time status telemetry and current operating plan information to reflect that the affected generator or load resource is disconnected from the ERCOT system, is unavailable for dispatch by ERCOT, and will be unavailable for dispatch by ERCOT for the time period specified by the TDU in its notice.

(ii) Upon receiving notice from a TDU that an affected area has been reconnected to the bulk power system, the operator of any affected generator or load resource must update its real-time status telemetry and current operating plan information to reflect the appropriate status of the affected generator or load resource.

(7) A TDU's liability related to the provision of service using a TEEEF is governed by §25.214 of this title, relating to Terms and Conditions of Retail Delivery Service Provided by Investor-Owned Transmission and Distribution Utilities.

(8) A TDU will ensure, to the extent reasonably practicable, that:

(A) A retail distribution customer's usage during the TDU's operation of a TEEEF is excluded or removed from the electric usage reported to ERCOT for final settlement and to retail electric providers (REPs) for customer billing; and

(B) Energy generated in an area isolated from the bulk power system in accordance with this section, including any energy generated by an affected generator, is excluded or removed from the generation reported to ERCOT for final settlement purposes.

(9) During an energy emergency declared by ERCOT, the amount of any load shed by a TDU for the area operated in isolation from the bulk power system during TEEEF energization must be accounted for net of any generation in the affected area that was online and producing before the area was isolated from the bulk power system.

(10) After-action report. After each significant power outage in a TDU's service territory that meets the criteria for TEEEF energization under paragraph (1) of this subsection, a TDU that has leased TEEEF must file an after-action report with the commission. The report must be filed within 30 days from the last day of the significant power outage. The report must include, as applicable:

(A) A description of the events that resulted in the significant power outage within the TDU's service territory, including the dates and times the significant power outage began and ended;

(B) The estimated number of affected distribution customers and estimated amount of load, in megawatts, that were affected by the significant power outage in the TDU's service territory and the estimated number of which that were served by TEEEF;

(C) The estimated number and type of critical load, critical care customers or other critical infrastructure facilities as defined in §25.497 of this title, affected by the significant power outage and the estimated number that were served by TEEEF. A TDU must also include available details on the duration of service interruptions for these customers;

(D) The total nameplate generating capacity in megawatts and the total number of affected generators or load resources that were isolated from the bulk power system for TEEEF energization;

(E) A description of any TEEEF energizations, including the capacity, fuel type, connection configuration, mobile capability, and lease type (i.e., with prior commission authorization or without prior commission authorization) of each TEEEF unit that was energized, the function each TEEEF unit was performing, the date and time each TEEEF unit was energized, and the duration that the affected area was isolated from the bulk power system;

(F) A list of TEEEF that was not energized, including the capacity, fuel type, connection configuration, mobile capability, and lease type (i.e., with prior commission authorization or without prior commission authorization) of each TEEEF unit that was not energized and a brief summary explaining why each TEEEF unit was not energized; and

(G) A description of any TEEEF units leased under subsection (d)(2)(B) of this section or utilized under a mutual assistance agreement or program. A TDU must include an explanation for the necessity of entering into the emergency lease or utilizing the mutual assistance agreement or program.

(h) Emergency operations annex. A TDU that leases TEEEF under this section must include a detailed plan on the use of the TDU's leased TEEEF in the TDU's emergency operations plan filed with the commission, as required by §25.53 of this title, relating to Electric Service Emergency Operations Plans, that is updated, as necessary, on an ongoing basis.

(i) Eligible costs.

(1) Costs to obtain and operate a TEEEF. Reasonable and necessary costs of leasing and operating a TEEEF, including the present value of future payments required under the lease, are eligible for recovery under this section. A lease involving a TEEEF must be treated as a capital lease or finance lease for ratemaking purposes, regardless of its classification under generally accepted accounting principles or other accounting frameworks.

(2) Return. Reasonable and necessary costs under this section include a return on investment, including the present value of future payments required under the lease, using the rate of return on investment established in the commission's final order in a TDU's most recent comprehensive base-rate proceeding.

(j) Deferred recovery of certain eligible costs. A TDU may create a regulatory asset to defer the following for recovery in a future ratemaking proceeding:

(1) The reasonable and necessary incremental operations and maintenance expenses, not otherwise included in any of the TDU's rates; and

(2) The return, not otherwise included in any of the TDU's rates.

(k) Cost recovery. Eligible costs under this section may be recovered as follows.

(1) Ratemaking proceedings. A TDU may request recovery of eligible costs, including any deferred expenses, through a standalone TEEEF rider proceeding, a proceeding under §25.243 of this title, relating to Distribution Cost Recovery Factor (DCRF), or in another ratemaking proceeding where it is appropriate to recover distribution invested capital and associated costs. A river authority may request recovery of eligible costs, including any deferred expenses, through a ratemaking proceeding where it is appropriate to recover distribution invested capital and associated costs or through a standalone TEEEF rider proceeding.

(A) A TDU must provide notice to REPs of the approved rates not later than the 45th day prior to the effective date of the approval.

(B) TEEEF costs must not be allocated to, or collected from, retail transmission service customers or wholesale transmission service at transmission voltage customers.

(C) Notwithstanding the provisions of §25.243 of this title, an allocation of TEEEF costs among distribution-level rate classes, based on substation-level class non-coincident peak demand, regardless of the time at which the class demand occurs, from the TDU's current or most recent base-rate proceeding, is presumed to be reasonable.

(D) TEEEF rates may not be established on a per-kilowatt-hour basis for any customer class that includes demand charges.

(E) Upon any amendment to a lease under this section that would reduce the rate of cost recovery necessary for a TEEEF, a TDU must submit an application to reflect the reduced rate of cost recovery necessary, by the earlier of three months from the lease amendment or the TDU's next DCRF proceeding.

(F) TEEEF costs must not be included in base rates. All TEEEF costs must be recovered through a single rider associated with TEEEF. A TDU with a previously established TEEEF rider may recover additional TEEEF costs by updating the existing TEEEF rider.

(G) TEEEF costs will not be reviewed for reasonableness, necessity, or prudence in a proceeding other than a base-rate proceeding, unless the presiding officer finds good cause to review them in another proceeding.

(H) In any proceeding in which TEEEF costs are reviewed for reasonableness, necessity, or prudence, the application must include the after-action reports for significant power outages during the period for which costs are being reviewed. The application must also include the leases, filed confidentially, for any leased TEEEF for which costs are being reviewed.

(I) A TDU that, prior to the effective date of this rule, received commission approval in a contested case proceeding for an amount of TEEEF generating capacity may request approval of reductions of that capacity through a subsequent standalone TEEEF rider proceeding made in accordance with this paragraph.

(2) Notice. The notice for any ratemaking proceeding in which eligible TEEEF costs are sought must specifically identify those eligible costs.

(3) Affiliate contracts. For any contract between a TDU and an affiliate, the TDU bears the burden of proof to show that the terms to the TDU were reasonable and necessary and did not exceed the prices charged by the supplying affiliate to its other affiliates or divisions or to unaffiliated persons within the same market area or having the same market conditions. In addition, all affiliate payments must comply with the requirements of PURA §36.058.

(4) Reconciliation. If TEEEF rates include any eligible costs that have not been reviewed for reasonableness, necessity, and prudence, any rates to recover any portion of those costs are temporary rates that must be reconciled in the TDU's next base-rate proceeding, including to determine whether the costs are reasonable, necessary, and prudent.

(A) In reconciling TEEEF costs, all revenues received associated with TEEEF programs, including actual rate revenues and mutual assistance reimbursements, must be applied to offset reasonable, necessary, and prudent TEEEF costs as these costs and revenues were incurred and received.

(B) A TDU must provide comprehensive testimony and workpapers supporting the reconciliation of all eligible costs and associated rate revenues as part of any base-rate proceeding application. Any amounts recovered through rates approved under this subsection that are found to have been unreasonable, unnecessary, or imprudent, plus the corresponding return, taxes, and carrying costs, must either be refunded or applied as an offset to any outstanding regulatory asset associated with eligible costs. In any proceeding in which the commission determines that a TDU has included in rates any amounts deemed unreasonable, unnecessary, or imprudent, or that the TDU has otherwise over-recovered costs, the commission may order a compliance proceeding to determine the amounts and manner of any necessary refunds to ratepayers or the proper accounting of over-recovered amounts as an offset to any outstanding regulatory assets associated with eligible costs. Carrying costs will be determined as follows:

(i) For the time period beginning with the date on which over-recovery is determined to have begun to the effective date of the TDU's base rates set in the base-rate proceeding in which the costs are reconciled, carrying costs will accrue monthly and will be calculated using an effective monthly interest rate based on the same rate of return that was applied to the TDU's rate base included in base rates in effect when the over-recovery began.

(ii) For the time period beginning with the effective date of the TDU's rates set in the base-rate proceeding in which the costs are reconciled, carrying costs will accrue monthly and will be calculated using an effective monthly interest rate based on the TDU's rate of return authorized in that base-rate proceeding.

(5) As part of the reconciliation of TEEEF costs, the commission may consider whether the leased TEEEF had the characteristics required to perform the functions authorized by the commission, whether the TEEEF was properly utilized to restore power during significant power outages, including appropriate pre-outage preparations such as positioning and securing fuel or the units, or any other factor relevant to the prudence or reasonableness of the TDU's procurement or operation of TEEEF.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 9, 2026.

TRD-202600558

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: March 1, 2026

Proposal publication date: August 15, 2025

For further information, please call: (512) 936-7433

SUBCHAPTER O. UNBUNDLING AND MARKET POWER

DIVISION 2. INDEPENDENT ORGANIZATIONS

16 TAC §25.370

The Public Utility Commission of Texas (commission) adopts new 16 Texas Administrative Code (TAC) §25.370, relating to ERCOT Large Load Forecasting Criteria, with changes to the proposed text as published in the October 3, 2025 issue of the Texas Register (50 TexReg 6414). The new rule implements Public Utility Regulatory Act (PURA) §37.0561(m) as enacted by Senate Bill (SB) 6 during the Texas 89th Regular Session. The new rule identifies the criteria that a large load customer must meet for inclusion in the load data that a distribution service provider (DSP) submits to ERCOT for purposes of developing the load forecasts that ERCOT uses to identify transmission planning needs and performing resource adequacy assessments. The new rule also requires ERCOT to develop a compliance plan for the 2026 Regional Transmission Plan (RTP). This section is adopted under Project Number 58480. The rule will be republished.

The commission received written initial comments on the proposed section from AEP Texas Inc. (AEP Texas); CenterPoint Energy Houston Electric, LLC (CenterPoint); City of Red Oak; Electric Reliability Council of Texas, Inc. (ERCOT); Environmental Defense Fund (EDF); ERCOT Steel Mills; Data Center Coalition (DCC); Lone Star Chapter of Sierra Club (Sierra Club); Lower Colorado River Authority and LCRA Transmission Services Corporation (LCRA); NRG Energy, Inc. (NRG); Office of Public Utility Counsel (OPUC); Oncor Electric Delivery Company (Oncor); Schaper Energy Consulting LLC (Schaper Energy); Sharyland Utilities, L.L.C (Sharyland); Steering Committee of Cities Served by Oncor (OCSC) and Texas Coalition for Affordable Power (TCAP); Targa Resources LLC (Targa); Texas Competitive Power Advocates (TCPA); Texas Electric Cooperatives, Inc. (TEC); Texas Energy Buyers Alliance (TEBA); Texas Industrial Energy Consumers (TIEC); Texas-New Mexico Power Company (TNMP); Texas Oil & Gas Association (TXOGA); Texas Public Power Association (TPPA); and Texas Public Policy Foundation (TPPF).

The commission received written reply comments on the proposed section from AEP; CenterPoint; Crusoe Energy System LLC; DCC; Eolian, LP; ERCOT; LCRA; OCSC and TCAP; Oncor; OPUC; Rowan Digital Infrastructure LLC; Sierra Club; TCPA; TIEC; and Wind Energy Transmission Texas, LLC, Cross Texas Transmission, LLC, and Lone Star Transmission, LLC (Joint Transmission Commenters).

General Comments

Assignment of a probability score

The City of Red Oak recommended using a quantitative approach to evaluate projects by assigning a probability score where the higher the projects score, the higher they go in the queue. The City of Red Oak recommended that the probability score be comprised of: (1) a letter of support for the project from the local governing entity; (2) a deposit of a significant sum of money; (3) proof of site control; (4) the large load customer's portfolio of work; (5) audited financials showing that the large load customer has the capital required to build the project or a commitment from the capital markets; and (6) the large load customer's backup generation capabilities.

Commission Response

The commission declines to adopt the City of Red Oak's recommendation to use a quantitative approach to evaluate projects by assigning a probability score where the higher the projects score, the higher they go in the queue because it is outside the scope of this rulemaking and is more appropriately addressed in 16 TAC §25.194 (relating to Large Load Interconnection Standards), which is currently pending in Project No. 58481, Rulemaking to Implement Large Load Interconnection Standards Under PURA §37.0561.

Insert "large" before "load" and "load forecasting"

CenterPoint recommended the term "large" be inserted before all references to "load" and "load forecasting" in the proposed rule to clarify that the proposed rule applies only to large load customers and not ERCOT's load forecasting in general.

Commission Response

The commission declines to adopt CenterPoint's recommendation to insert the term "large" before all references to "load" and "load forecasting" because the term "large" is not an applicable qualifier in all instances that "load" or "load forecasting" are used in the adopted rule.

Additional criteria- on-site backup generating facilities

OPUC recommended adding a new subsection that requires each interconnected large load customer to disclose to the interconnecting transmission and/or distribution service provider (TDSP) information about the customer's on-site backup generating facilities, and requires the interconnecting TDSP to provide the information to ERCOT, as required under PURA §37.0561(e) and the applicable commission rule for net metering arrangements involving a large load customer co-located with an existing generation resource.

Commission Response

The commission declines to adopt OPUC's recommendation to add a new subsection that requires each interconnected large load customer to disclose to the interconnecting TDSP information about the customer's on-site backup generating facilities and requires the interconnecting TDSP to provide the information to ERCOT because it is outside the scope of this rulemaking and is more appropriately addressed in the pending rule in Project No. 58481.

Additional criteria- operational information

EDF recommended adding a new subsection requiring a large load customer to provide to ERCOT (1) the average amount of energy consumption used during a normal set of circumstances; (2) any factors or events that would cause the large load customer or flexible large load customer to increase or decrease the energy consumption or demand; (3) real or reactive power consumption changes and recovery time; (4) how long the customer remains connected to the grid during a given voltage and/or frequency disturbance; (5) grid connection level; (6) request for firm or flexible load, and how much; (7) backup generation schemes, including on-site generation; (8) behind-the-meter co-location, if applicable; and (9) the name and contact information of at least two individuals with decision-making authority for ERCOT to have a direct open line of communication in the event of an energy emergency alert or grid disturbance.

TPPF recommended adding a new subsection that requires ERCOT to document the degree to which a large load customer may be expected to curtail or utilize onsite generation during emergency or near-emergency conditions and estimate the cumulative impact of flexible loads on systemwide peak demand. Additionally, TPPF recommended explicitly stating in the proposed rule that ERCOT is not required to account for the maximum demand of every load when using its load forecasts for the purposes of transmission planning and resource adequacy assessments. TPPF reasoned that these changes would help to more accurately forecast peak demand by reflecting the certainty of non-firm load curtailment.

Sierra Club supported recommendations to require reporting about the ability of large load customers to flexibly control their demand by registering as controllable load resources.

Commission Response

The commission declines to adopt EDF, TPPF, and Sierra Club's recommendation to add a new subsection requiring a large load customer to disclose operational information because it is outside the scope of this rulemaking and is more appropriately addressed in the pending rule in Project No. 58481. The commission also declines to adopt TPPF's recommendation to explicitly state in the adopted rule that ERCOT is not required to account for the maximum demand of every load when using its load forecasts for the purposes of transmission planning and resource adequacy assessments because it is unnecessary. The adopted rule focuses on what criteria a large load customer must meet for inclusion in ERCOT's load forecast. Moreover, the commission makes clarifying changes to adopted §25.370(e)(3) to maintain an appropriate level of flexibility for ERCOT to develop forecasts based on the different purposes of transmission planning and resource adequacy.

Additional criteria- end-use customer

TIEC recommended adding a new subsection that requires a large load customer to disclose whether the entity seeking interconnection intends to be the ultimate end-use customer. TIEC noted that due to the lead time and value of a large interconnection, many third-party developers are pursuing interconnections that they intend to later transfer or assign to an end-use customer. Additionally, some third-party developers are pursuing interconnections where the end-use customers will use the interconnection as a tenant. For example, many data center developers will obtain interconnection and build out facilities that end-use computing companies will ultimately lease. Additional disclosures and situational awareness around this activity would be helpful in refining the load forecast over time.

Commission Response

The commission declines to adopt TIEC's recommendation to add a new subsection requiring a large load customer to disclose whether the entity seeking interconnection intends to be the ultimate end-use customer because it is outside the scope of this rulemaking and is more appropriately addressed in the pending rule in Project No. 58481.

Independent third-party forecast

CenterPoint recommended adding a new subsection that allows for the use of an independent, third-party forecast to validate and substantiate the utility's forecasted demand. CenterPoint reasoned that an independent third-party forecast, such as the one that ERCOT relied on for the Permian Basin Reliability Plan, provides ERCOT a more holistic perspective on forecasted load growth.

AEP and OPUC opposed CenterPoint's recommendation because SB 6 does not contemplate the use of third-party load forecasts as part of the requirements for large load customers wanting to interconnect to the ERCOT grid.

Commission Response

The commission declines to adopt CenterPoint's recommendation to add a new subsection that allows for the use of an independent, third-party forecast to validate and substantiate the utility's forecasted demand because it does not align with the purpose of PURA §37.0561 and the adopted rule, which is to establish criteria for a large load customer to be included in ERCOT's load forecasts for transmission planning studies and resource adequacy assessments.

Load interconnection report

TCPA recommended adding a subsection requiring ERCOT to publish an aggregated report of megawatts (MW) by county level that meet the criteria under proposed §25.370(c) for inclusion in the load forecast. TCPA also recommended that for loads that have requested interconnection but have not met all the criteria under proposed §25.370(c), ERCOT should publish the aggregated MW by county level that have met each of the different sub criteria under proposed §25.370(c). TCPA noted that confidentiality of information will remain protected as only aggregate MW for each county level will be reported. TCPA also noted that Nodal Protocol Revision Request (NPRR) 1267 was introduced to create such a report for large load customers to provide transparency and while NPRR 1267 was approved by the commission on July 31, 2025, it has not yet been implemented. TCPA would support the commission directing ERCOT to prioritize implementation of NPRR 1267 as part of the order on this rulemaking.

Eolian agreed aggregate forecast data is important but recommended clarifying that the information ERCOT obtains pursuant to its access rights set forth in PURA §37.0561(k) is to be used by ERCOT internally for validation purposes and must not be published.

Commission Response

The commission declines to adopt TCPA's recommendation to add a new subsection requiring ERCOT to publish an aggregated report of MW by county level that meet the criteria under adopted §25.370(c) for inclusion in the load forecast because it is unnecessary. As TCPA noted, NPRR 1267 already requires such a report.

The commission also declines to adopt Eolian's recommendation to modify the adopted rule to clarify that the information ERCOT obtains pursuant to its access rights set forth in PURA §37.0561(k) is to be used by ERCOT internally for validation purposes and must not be published because there may be instances, such as for purposes of compliance with NPRR 1267, when it is appropriate for ERCOT to use the information in a public report provided action is taken to protect any confidential information.

Readiness-based forecasting framework

Eolian recommended that whether a large load customer should be included in ERCOT's load forecasts should depend on demonstrated and verifiable project readiness and system impact, a concept that Eolian describes in greater detail in its comments filed on October 10, 2025 in Project No. 58481. In essence, Eolian recommended that the commission adopt a two-track structure consisting of: (1) a streamlined advanced readiness/critical infrastructure track for projects that demonstrated substantial progress toward site control, environmental permitting, and financing or that serve critical industrial, infrastructure, or manufacturing functions; and (2) an expedited deployment/early-state verification track for large load projects (such as digital infrastructure, high-performance computing, and technology-driven facilities) that operate under compressed commercial timelines where speed to market is essential to project viability. To align with its recommendation in Project No. 58481, Eolian recommended that proposed §25.370 be modified to include a cross-reference to the two-track structure in the rule under development in Project No. 58481.

Commission Response

The commission declines to adopt Eolian's recommendation to modify the adopted rule to include a cross-reference to the two-track structure in the rule under development in Project No. 58481 because it is unnecessary. The adopted rule is sufficiently flexible in identifying the criteria for a large load customer's inclusion in ERCOT's load forecasts that, if the commission ultimately adopts Eolian's recommendation in Project No. 58481, the adopted rule will align with that decision.

Coordinated evaluation of paired load and generation resources

Eolian recommended modifying proposed §25.370 to include a requirement for ERCOT to evaluate paired large load customers and generation resources in a coordinated manner. Eolian reasoned that the absence of a defined mechanism for coordinated study of paired load and generation resources or energy storage resources results in duplicative or inconsistent analyses, conflicting upgrade requirements, and inefficient use of transmission planning resources. A unified analytical framework ensures accurate modeling and timely interconnection.

Commission Response

The commission declines to adopt Eolian's recommendation to include a requirement for ERCOT to evaluate paired large load customers and generation resources in a coordinated manner because it is outside the scope of this rulemaking, which is to establish criteria for a large load customer's inclusion in ERCOT's load forecasts.

Governance of large load interconnection request queue and processing

Eolian recommended modifying proposed §25.370 to establish a framework by which the commission can adequately govern the large load interconnection request queue and the processing and evaluation of requests. Because both the steep increase in large load interconnection requests and the corresponding challenges is relatively new, current TDSP processes tend to be insufficiently clear and, to the extent they can be ascertained, inconsistent. In Eolian's experience, TDSPs vary widely in the type of readiness demonstration they seek from large load customers and their responsiveness to load developers' initial requests and submission of documentation. Without regularization of the large load interconnection request process, TDSPs may exercise undue preference as to which projects have the opportunity to demonstrate such viability and the order in which projects' demonstrations are accepted and thereby included in studies and forecasts.

Commission Response

The commission declines to adopt Eolian's recommendation to modify adopted §25.370 to establish a framework by which the commission governs the large load interconnection request queue and the processing and evaluation of requests because it is outside the scope of this rulemaking and is more appropriately addressed through other avenues. The commission notes that commission staff has opened Project No. 58481 to standardize the interconnection standards for large load customers and ERCOT is currently developing a batch study process, which is expected to address the concerns raised by Eolian.

Regular forecast review and backcasting analysis

DCC recommended that ERCOT conduct annual assessments comparing past forecasts to actual outcomes (i.e., backcasting) to identify any sources of error and opportunities to improve future forecasts. According to DCC, this backcasting should confirm whether the load that was removed from the forecast is still pending review in the queue, and if so, determine the total aggregated amount of load pending review in the queue. DCC recommended requiring ERCOT to publicly post these assessments and obtain stakeholder comments and recommendations.

Commission Response

The commission agrees with DCC that identifying any sources of error and opportunities to improve future forecasts could be useful to both the commission and stakeholders to assess the effectiveness of the criteria developed for large load customers to be included in ERCOT's load forecast. Moreover, ERCOT should track this data and provide periodic updates to the commission without compromising confidentiality of the underlying data. Accordingly, the commission modifies the adopted rule to add new §25.370(e)(4) to implement this reporting requirement. The commission also adds language requiring ERCOT to identify sources of error and provide recommendations for improvement in the forecasting process.

Related pending rulemaking

Oncor recommended either waiting to adopt the rule in Project No. 58481 so that the criteria in that rule could be copied and pasted in this proposed rule; or to cite directly to the pending rule in Project No. 58481.

Commission Response

The commission agrees with Oncor's recommendation to cite directly to the pending rule in Project No. 58481 and modifies the adopted rule accordingly.

Proposed §25.370(b)(1)- Definition for large load customer

Proposed §25.370(b)(1) defines a large load customer as an entity seeking interconnection of one or more facilities at a single site with an aggregate new load or load addition greater than or equal to 25 megawatts (MW) behind one or more common points of interconnection or service delivery points.

Demand threshold

AEP, CenterPoint, DCC, ERCOT Steel Mills, LCRA, NRG, OPUC, Oncor, Schaper Energy, Targa, TCPA, TEC, TEBA, TIEC, TXOGA, and TPPA recommended that the threshold for determining whether a customer is a large load customer be increased from 25 MW to 75 MW.

EDF, ERCOT, and Sierra Club supported proposed §25.370(b)(1)'s use of a 25 MW demand threshold for defining a large load customer.

Commission Response

The commission agrees with AEP, CenterPoint, DCC, ERCOT Steel Mills, LCRA, NRG, OPUC, Oncor, Schaper Energy, Targa, TCPA, TEC, TEBA, TIEC, TXOGA, and TPPA that the demand threshold in the definition for a large load customer should be set to 75 MW to align with other rules implementing SB 6. However, the commission shares ERCOT's concerns that there may be a significant amount of interconnection requests for loads between 25 MW and 75 MW that may impact system upgrades. The commission expects to address the appropriate criteria for including these loads in ERCOT's forecasts in a future rulemaking. The commission further notes that the adopted rule does not change ERCOT's existing authority to gather information about and validate loads that are below 75 MW.

Voltage level at point of interconnection

OPUC recommended modifying proposed §25.370(b)(1) to specify that a large load customer is an entity seeking interconnection behind one or more common points of interconnection or service delivery points where the point of interconnection or service delivery point is at transmission-level voltage.

CenterPoint Energy countered that adding qualifications, specifically distinguishing between large load customers seeking to interconnect at transmission voltage from large load customers seeking to interconnect at distribution voltage would frustrate PURA §37.0561(c)'s mandate that all large load customers be included in ERCOT's large load forecasts. CenterPoint has experienced large industrial loads with a demand threshold of 75 MW and greater, such as data centers and manufacturing facilities, interconnecting or seeking to interconnect at distribution voltage. It is the size of the load, and not whether such load is interconnected at transmission voltage, that causes transmission system impacts.

Commission response

The commission declines to adopt OPUC's recommendation to modify proposed §25.370(b)(1) to specify that a large load customer is an entity seeking interconnection behind one or more common points of interconnection or delivery service points where the point of interconnection or service delivery point is at transmission-level voltage. The commission agrees with CenterPoint that the size of the load, and not whether such load is interconnected at transmission voltage, is the relevant factor for defining a large load customer.

Clarify that any load exceeding the threshold is a large load customer and exclude energy storage resources and their associated charging loads

TPPA recommended clarifying that the definition for a large load customer to specify that any load exceeding the commission's threshold should be considered a large load customer. TPPA reasoned that proposed §25.370(b)(1) could be read such that an entity could initially interconnect with a demand that is one MW below the commission's threshold and not be considered a large load customer. After the initial interconnection, the entity could request the interconnection of additional demand, and as long as the additional amount is at least one MW below the threshold, it would still not be classified as a large load customer. To the extent this is not the intent, TPPA recommended clarifying the definition.

TPPA also recommended clarifying that the definition for a large load customer excludes energy storage resources and their associated charging loads.

Commission Response

The commission adopts TPPA's recommendation to modify adopted §25.370(b)(2) to clarify that any load exceeding the 75 MW threshold is a large load customer. The commission declines to adopt TPPA's recommendation to modify proposed §25.370(b)(1) to clarify that the definition for a large load customer excludes energy storage resources and their associated charge loads because it is unnecessary. Energy storage resources have their own interconnection process within the generation interconnection queue and ERCOT's load forecast does not currently include energy storage resource's charging load.

Proposed §25.370(b)(1) and (2)- Definitions for large load customer and load

Proposed §25.370(b)(1) defines a large load customer and proposed §25.370(b)(2) defines load.

ERCOT Steel Mills recommended consolidating the definitions in proposed §25.370(b)(1) and (2) into a single definition to ensure that the term "load" is interpreted solely within the context of criteria defining a large load customer. As drafted, proposed §25.370(b)(2) defines "load" as "non-coincident peak demand in MW" and is structured as a standalone definition that could possibly be referenced or applied outside the intent of proposed §25.370(b). ERCOT Steel Mills reasoned that this approach would be unreasonable because ERCOT forecasts various load measures, not only non-coincident peak. Either eliminating the definition of "load" from the rule or clarifying within the definition of a "large load customer" that the commission will use the non-coincident peak demand for the purpose of determining whether the load qualifies as a "large load customer" will provide greater clarity to stakeholders as compared to placing them in separate definitions.

Commission Response

The commission adopts ERCOT Steel Mills' recommendation to consolidate the definitions in proposed §25.370(b)(1) and (2) into a single definition and modifies the adopted rule accordingly.

Proposed §25.370(b)(3)- Definition for TDSP

Proposed §25.370(b)(3) defines a TDSP as the electric utility, municipally owned utility, or electric cooperative that is certificated to provide retail electric service at the site that a large load customer seeks to interconnect or the transmission service provider (TSP) delegated authority by the electric utility, municipally owned utility, or electric cooperative to act on its behalf for purposes of providing information to ERCOT.

Reference to "distribution"

OPUC recommended modifying proposed §25.370(b)(3) to remove the reference to "distribution" to align with OPUC's recommendation that the definition for a large load customer should be tied to interconnection at transmission-level voltage.

Commission Response

The commission declines to adopt OPUC's recommendation to modify proposed §25.370(b)(3) because it is unnecessary. The commission removes the definition for TDSP in the adopted rule. The terms transmission service provider and distribution service provider are already separately defined in §25.5 of this Title (relating to Definitions) for purposes of Chapter 25 and those definitions are appropriate in the context of the adopted rule. Therefore, it is unnecessary to define the terms in the adopted rule.

Entities authorized to submit load data to ERCOT

Crusoe, Eolian, Joint Transmission Commenters, Schaper Energy and Sharyland recommended modifying proposed §25.370(b)(3) to allow TSPs to submit load data to ERCOT. Sharyland reasoned that large load customers must provide complete interconnection information to the TSP as part of the interconnection process, regardless of how they plan to structure their retail service arrangements. This makes TSPs a comprehensive and reliable source for reporting large load customers interconnecting at transmission voltage, even if such a TSP is ultimately not the retail TDSP. Moreover, by requiring that TDSPs submit load data, the proposed rule may have the unintended consequence of large load customers avoiding working with TSPs, which could create additional backlog in moving large load customers through the interconnection queue. Moreover, in response to ERCOT staff's statements at the public workshop held on September 2, 2025 that ERCOT needs to have a single source of information to avoid duplicative reporting, Sharyland suggested there are at least three more efficient solutions to address that concern: (1) ERCOT can use large load interconnection numbers assigned during the interconnection process to quickly filter duplicative submissions; (2) the notarized attestations in proposed §25.370(d) could themselves be backed by customer attestations to the TSP to confirm that the load data has been provided to only the reporting TSP; or (3) TSPs and TDSPs will continue collaborating with one another and with ERCOT to reconcile data sets.

Commission Response

The commission declines to adopt Crusoe, Eolian, Joint Transmission Commenters, Schaper Energy, and Sharyland's recommendation to modify proposed §25.370(b)(3) to allow TSPs to submit load data to ERCOT because the commission removes the definition for TDSP from the adopted rule. Moreover, the commission determines that the DSP, which has the retail relationship with the large load customer irrespective of the voltage at which that large load customer receives service, is the more appropriate entity to submit the load data to ERCOT to avoid confusion and unintended consequences in areas that are served by municipally owned utilities and electric cooperatives. Therefore, the commission declines to make the change elsewhere in the adopted rule.

Split definition for TSP and distribution service provider

Crusoe recommended splitting the definition of TDSP into separate definitions for TSP and distribution service provider. The TSP is the interconnecting utility that conducts the large load interconnection studies, but it might not be the utility with the obligation to provide retail electric delivery service to the large load customer.

Commission Response

The commission agrees with Crusoe's recommendation to split the definition of TDSP into separate definitions for TSP and distribution service provider. However, the commission notes that §25.5 of this Title already defines TSP and DSP. Therefore, the inclusion of these definitions is not necessary. The commission modifies the adopted rule to remove the definition for TDSP and replace references to "TDSP" with "TSP" and "DSP" as applicable.

Definition for TDSP is unnecessary

OCSC and TCAP recommended modifying proposed §25.370(b)(3) to remove the definition for TDSP because it is unnecessary. OCSC and TCAP reasoned that the definition is unnecessary because the term TDSP has been in common parlance in ERCOT for decades. Alternatively, OCSC and TCAP recommended modifying proposed §25.370(b)(3) to align the definition with the definition for TDSP in the ERCOT protocols.

Commission Response

The commission agrees with OCSC and TCAP that the definition for TDSP is unnecessary because §25.5 of this Title already defines TSP and DSP. Therefore, the commission modifies the adopted rule to remove the definition for TDSP and to replace references to "TDSP" with "TSP" and "DSP" as appropriate.

Proposed §25.370(c)- Criteria for inclusion in ERCOT load forecast

Proposed §25.370(c) prohibits inclusion of a large load customer's forecasted demand unless the large load customer executed and securitized an interconnection agreement or meets specific criteria.

ERCOT determination versus TDSP determination

Eolian recommended modifying proposed §25.370(c) to state that ERCOT, not the TDSP, determines whether to include a large load customer in ERCOT's load forecast used for transmission planning and resource adequacy models and reports. As drafted, Eolian had concerns that proposed §25.370(c) relies on TDSP determinations, such as demonstrated financial commitment and site control, when the TDSPs' role in the planning process is limited to supporting ERCOT's role by providing necessary data and verifying certain information. Eolian's recommended changes to proposed §25.370(c) would clarify that TDSPs may not withhold information from ERCOT or unilaterally make the determination to exclude or condition the inclusion of specific large load customers in the load forecast.

Commission Response

The commission declines to adopt Eolian's recommendation to modify adopted §25.370(c) to state that ERCOT, not the TDSP, determines whether to include a large load customer in ERCOT's load forecast used for transmission planning studies and resource adequacy assessments. Although the TDSP's role is to provide necessary data and verify certain information, that step necessarily requires that the TDSP make a preliminary determination that a large load customer has met the criteria and should be included.

Analysis of scenarios

ERCOT recommended modifying proposed §25.370(c) to clarify that ERCOT can perform analysis of scenarios. For example, the Long-Term System Assessment (LTSA) is used to inform which of various transmission options to recommend in the Regional Transmission Plan (RTP) or Regional Planning Group (RPG) process but the load development scenarios included in the LTSA would not meet the criteria specified in proposed §25.370(c) because the LTSA is based on a 10 to 15 year planning horizon (well before a large load customer would secure land rights or undertake financial commitments). ERCOT was concerned that proposed §25.370(c) could be read to prohibit the analysis that it conducts for the LTSA. Therefore, ERCOT recommended specifying that a large load customer's forecasted demand must not be included in ERCOT load forecast used for identifying transmission planning needs or performing resource adequacy assessments unless the large load customer executed and signed an interconnection agreement or meets specific criteria.

OPUC supported ERCOT's recommended changes. However, to ensure the statutory floor is not circumvented by the new language, OPUC recommended the following modification to ERCOT's recommendation: Criteria for inclusion in ERCOT load forecast. A large load customer's forecasted demand must not be included in an ERCOT load forecast used for identifying transmission planning needs or performing resource adequacy assessments unless the large load customer meets the following criteria or has executed and securitized an interconnection agreement that at a minimum includes the criteria set forth below. If an interconnection agreement fails to include all of the criteria established in the following subparagraphs, then the load shall not be included in ERCOT's load forecast used for transmission planning or resource adequacy.

Commission Response

The commission adopts ERCOT's recommendation to modify adopted §25.370(c) to clarify that ERCOT can perform analysis of scenarios and makes conforming changes throughout the adopted rule. The commission declines to adopt OPUC's recommendation to further modify adopted §25.370(c) to state that a large load customer must meet the criteria set forth and that, if an interconnection agreement fails to include all the criteria set forth, then the load must not be included in ERCOT's load forecast used for transmission planning or resource adequacy. Instead, the commission modifies adopted §25.370(c) to state that a large load customer must execute an interconnection agreement that meets the requirements under §25.194 (relating to Large Load Interconnection Standards) to be included in ERCOT's load forecast.

Amount of security posted

ERCOT recommended adding a new subsection to clarify that the amount of security posted by a large load customer that is counted in the load data based on an executed and securitized interconnection agreement must be equal to or greater than the amount of security that is required for the financial commitments under proposed §25.370(c)(4). Otherwise, it is possible that the amount of security required could vary across TDSPs and become an avenue for large load customers to circumvent the requirements of the interconnection standards.

TIEC opposed ERCOT's recommendation, reasoning that the dollar per MW financial security should be viewed as a generic proxy that will allow loads to demonstrate sufficient financial commitment to be studied. Once the studies have been completed, the financial requirements under an actual service agreement for a large load customer will be based on the actual costs of the interconnection and will typically be much greater than any reasonable "proxy" security requirement that is applied on a dollar per MW basis. However, in the rare instance where that is not true, there is no reason to require a level of financial commitment above the TSP's actual costs or the potential risks to the system of the large load not materializing. If the actual cost happens to be less than the proxy after the load has been studied, the actual cost should be used. TIEC further explains that PURA §37.0561(h) allows proof of financial commitment to include: (a) the interim dollar per MW security; (b) security (or cash) provided under a discretionary services agreement for significant equipment or services; or (c) the contribution in aid of construction (CIAC) or security provided under a facilities extension agreement (FEA). Under this framework, the commission should make it clear that once an FEA is in place, the project-specific FEA financial requirements should be sufficient to protect against stranded costs and should supersede all generic dollar per MW security requirements, even if this results in a lower level of security in some scenarios.

Commission Response

The commission declines to adopt ERCOT's recommendation because the commission determines that the appropriate rule to address the specific criteria is in §25.194 (relating to Large Load Interconnection Standards). Therefore, the commission modifies adopted §25.370(c) to simply cite to the interconnection agreement that may be required under §25.194.

Option to execute and securitize an interconnection agreement

OPUC recommended modifying proposed §25.370(c) to remove the option to execute and securitize an interconnection agreement for a large load customer to be captured in a TDSP's load data submitted to ERCOT if the interconnection agreement fails to include the standards described in PURA §37.0561. OPUC reasoned that PURA §37.0561 sets forth certain standards the Texas Legislature required be met before a large load customer could interconnect to the grid and that it naturally follows that these standards should also be required before a large load customer is included in ERCOT's load forecast. OPUC concluded that the statute does not give the commission the option to offer an alternative path (i.e., executing and securitizing an interconnection agreement) in lieu of the statutorily outlined criteria.

Oncor and Rowan opposed OPUC's recommendation. Oncor reasoned that OPUC's recommendation is in direct opposition to the Texas Legislature's longstanding direction for ERCOT to focus on including more loads seeking interconnection in its forecasts, not less. Interconnection agreements themselves establish sufficient certainty to include a large load in ERCOT's forecasts whereas the added requirements that OPUC recommended would leave loads that are certain to interconnect out of ERCOT forecasts.

Rowan reasoned that PURA §37.0561(m) does not compel the commission to determine that a large load may only be included in an ERCOT load forecast if the large load has met all of the requirements for large load interconnection under PURA §37.0561(a)-(k). Rowan recommended that proposed §25.370(c) creates appropriate pathways for large load customers to demonstrate legitimacy consistent with what is allowed under the statute, while also ensuring that a legitimate large load is not excluded from ERCOT's load forecasts simply because it has not yet satisfied all of the interconnection standards in the rule. Moreover, the proposed rule should provide additional pathways for a large load to qualify for inclusion in an ERCOT load forecast, which would more accurately reflect the agreements and documentation that a large load customer is actually able to provide to demonstrate legitimacy. An FEA or equivalent agreement establishes the contractual relationship between a large load customer and the TDSP to develop and commit to paying for the necessary infrastructure in these circumstances. Accordingly, Rowan recommended modifying proposed §25.370(c) to add language stating that a large load customer must be included in ERCOT load forecasts if the large load customer executes and securitizes an FEA or an agreement equivalent to an interconnection agreement or an FEA.

Commission Response

The commission declines to adopt OPUC's recommendation to remove the option to execute and securitize an interconnection agreement for a large load customer to be captured in a TDSP's load data submitted to ERCOT if the interconnection agreement fails to include the standards described in PURA §37.0561. Instead, the commission modifies adopted §25.370(c) to require that a large load customer execute an interconnection agreement that meets the requirements under §25.194, which is intended to implement the specific requirements of PURA §37.0561 and thus addresses OPUC's concern.

Previously approved large load customer requests

TEBA recommended modifying proposed §25.370(c) to incorporate previously approved large load customer requests that require transmission upgrades but have not yet posted their security so that a large load customer will only be included in the RPG forecast once it has both posted the required security and demonstrated site control. TEBA reasoned that this would help filter out speculative projects and ensure that only committed loads are reflected in ERCOT's transmission planning forecasts.

Commission Response

The commission agrees with TEBA that the adopted rule's applicability to projects that have already progressed through the large load interconnection process but have not completed system upgrades through the RPG process, should be clearly defined. The commission acknowledges that the same criteria imposed on large load customers to be included in the load forecast should also extend to projects going through the RPG process because those projects are considered transmission studies. Therefore, all projects which have not been submitted for RPG review as of the effective date of the adopted rule, are subject to this requirement. The commission modifies adopted §25.370(e)(3) accordingly.

Proposed §25.370(c)(1)- Separate request for electric service

Proposed §25.370(c)(1) requires a large load customer to disclose to the TDSP whether the large load customer is pursuing a separate request for electric service, the approval of which would result in the customer materially changing, delaying, or withdrawing the interconnection request, and if so, the location, size, and anticipated timing of energization associated with such request.

Disclosure of location, size, and anticipated timing of energization

AEP recommended modifying proposed §25.370(c)(1) to remove the requirement that the large load customer disclose the location, size, and anticipated timing of energization associated with a separate request for electric service because this could result in the disclosure of sensitive information. AEP reasoned that disclosure of the separate request is adequate to achieve the goals of the proposed rule.

OPUC countered that AEP's concern about the potential, not certain, disclosure of sensitive information is covered by both PURA §37.0561(k) and proposed §25.370(g). Overbuilding transmission or risking grid reliability should not be compromised for the sake of a potential disclosure of sensitive information-especially when the state legislature already accounted for that fact and specifically addressed it.

Commission Response

The commission declines to adopt AEP's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(1). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(1) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

ERCOT jurisdiction and communication

DCC recommended modifying proposed §25.370(c)(1) to clarify that the disclosures only pertain to areas within ERCOT's jurisdiction. DCC reasoned that the data center industry is an extremely dynamic and competitive industry so there must be confidentiality protections in place to ensure commercially sensitive information is not exposed. DCC also noted that while a project may appear duplicative, a company may be building out data centers to serve Texas's multiple markets. Therefore, establishing a process by which large load customers could directly communicate with ERCOT on adjusting demand projects would streamline the flow of information to provide a more accurate and transparent picture of requested capacity in the large load interconnection study queue.

OPUC countered that DCC's recommended change is inconsistent with the statute. PURA §37.5671(d) requires large load customers to disclose another "request for electric service in this state." If a request outside of the ERCOT service area is real, but the request inside is speculative, then the non-ERCOT area request is necessary to help determine whether transmission truly needs to be built for the less committed ERCOT area request. In addition, the Texas Legislature is very familiar with ERCOT's service areas. If it had intended for a request to be disclosed only for ERCOT's jurisdiction, it would have stated such. With respect to DCC's comments related to the ability of large load customers to communicate directly with ERCOT, OPUC recommend that is not necessary to address this issue in the proposed rule because ERCOT has anticipated this need and is already working to address it.

TCPA recommended that if disclosure of requests in areas outside of ERCOT is a concern, this could be remedied in the pending interconnection standard rulemaking by setting adequate financial security requirements and conditioning refunds on the load materializing in ERCOT.

Commission Response

The commission declines to adopt DCC and TCPA's recommendations because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(1). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(1) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Additional engineering and design information

CenterPoint recommended modifying proposed §25.370(c)(1) to permit a utility to require additional engineering and design information from a large load customer.

Commission Response

The commission declines to adopt CenterPoint's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(1). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(1) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Not pursuing a separate request for interconnection

TPPA recommended modifying proposed §25.370(c)(1) to require a large load customer to disclose to the TDSP that it is not pursuing a separate request for interconnection. TPPA reasoned that this change would sufficiently avoid duplicative counting of projects between TDSPs.

Commission Response

The commission declines to adopt TPPA's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(1). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(1) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Attestation

TPPA recommended modifying proposed §25.370(c)(1) to require an attestation from the large load customer.

Commission Response

Proposed §25.370(c)(2)- Demonstration of site control

Proposed §25.370(c)(2) requires a large load customer to demonstrate site control for the proposed load location through an ownership interest, lease, or other means accepted in the applicable commission rule for large load interconnection standards.

Purchase option

Crusoe, LCRA, Rowan, Schaper Energy, and TIEC recommended modifying proposed §25.370(c)(2) to allow a large load customer to demonstrate site control through a purchase option. Additionally, LCRA recommended that the large load customer be required to provide documentation to the interconnecting TDSP and to submit updated documentation in the case of any duration-limited option or lease agreement in order to satisfy the statutory requirement to demonstrate continued site control for the duration of the interconnection study period. Crusoe recommended that requiring fee simple ownership or a fully executed lease at the early stages of project development is commercially unrealistic and would create unnecessary barriers to investment and economic growth in Texas. Most developers cannot responsibly acquire property outright or enter into long-term leases before confirming the availability of electric service and completing necessary interconnection studies. If the rule were to require only actual ownership or leasehold interests, many viable projects would be stalled or abandoned due to the unacceptable financial exposure this would create. Rowan noted that it may not be appropriate for a large load customer to purchase a property if interconnection is not certain in a reasonable timeframe, which is why a large load customer often enters into a binding letter of intent to purchase a property or an exclusivity agreement as a means of obtaining site control. Schaper Energy noted that the current interconnection procedural delays prevent developers from responsibly acquiring property in fee without first confirming the availability of electric service. Similarly, Targa recommended modifying proposed §25.370(c)(2) to expressly recognize options to lease or purchase as acceptable forms of site control, provided the option runs with the land or is otherwise enforceable.

In contrast, CenterPoint, Oncor, and TNMP recommended that the commission accept only actual ownership interests or leasehold interests as sufficient to demonstrate site control for a proposed large load location. CenterPoint recommended that a purchase option is insufficient evidence of site control because the holder of the purchase option (1) is not obligated to purchase the underlying property, and (2) does not have a possessory interest in the underlying property. If the commission determines that future ownership interests should be included, TNMP recommended that the commission limit recognition of future interests to exclusive options to purchase or lease that are supported by significant consideration. Speculative future interests such as life estates or executory interests should not be considered sufficient to demonstrate required site control. Similarly, if the commission elects to allow contractual rights to establish proof of site control, Oncor recommended requiring that non-refundable financial deposits be in place under those contracts to substantiate that an interconnecting large load is sufficiently invested in the chose site location. The interconnecting large load should be required to provide either a copy of the purchase contract or an attestation that this requirement has been met.

Commission Response

The commission declines to adopt Crusoe, LCRA, Rowan, Schaper Energy, and TIEC's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(2). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(2) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Acreage, geography, and zoning requirements

OPUC recommended modifying proposed §25.730(c)(2) to require a large load customer to confirm that its site has sufficient acreage and no less than one MW per acre, geography, and zoning requirements to support the large load customer's interconnection request. Additionally, OPUC recommended replacing reference to "other means" with "another legal interest" to better align with PURA §37.0561.

Oncor supported OPUC's recommendation to require validation of property interests on the basis of potential for power consumption. Confirming that the project property is large enough to hold a facility that would consume the amount of requested capacity prevents a developer from entering the interconnection queue and ERCOT load forecasts with an inexpensive, undersized property, which the developer may walk away from or only expand once it is certain that it wants to proceed with construction.

Commission Response

The commission declines to adopt Oncor and OPUC's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(2). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(2) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Attestation

TPPA recommended modifying proposed §25.370(c)(2) to require an attestation from the large load customer.

Commission Response

The commission declines to adopt TPPA's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(2). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(2) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Proposed §25.370(c)(3)- Study fee

Proposed §25.370(c)(3) requires a large load customer to pay a study fee that is the greater of $100,000 or an amount that is set by the applicable commission rule for large load interconnection standards.

Study fee amount

AEP recommended modifying proposed §25.370(c)(3) to state that a large load customer must pay a study fee that is at least $100,000 instead of the greater of $100,000 or an amount that is set by the applicable commission rule for large load interconnection standards. TNMP recommended setting the study fee to at least $100,000 but also allowing for additional study cost factors to be applied to permit individual utilities to evaluate project-specific costs and calculate total study fee costs accordingly. CenterPoint recommended modifying proposed §25.370(c)(3) to increase the minimum study fee to $150,000.

Crusoe opposed TNMP's recommendation to establish a minimum study fee with allowance for additional, undefined project-specific charges. Crusoe asserted that TNMP's proposal lacks clear limits and transparency, creating uncertainty for large load customers and potentially resulting in unpredictable and excessive costs.

Rowan recommended modifying proposed §25.370(c)(3) to state that a large load customer must pay the lesser of $100,000 or an amount that is set by the applicable commission rule for large load interconnection standards based on the TDSP's verifiable study costs, which shall be the only study fee payment required for a period of five years from the date of payment, and thereafter the study fee amount may increase annually based on the TDSP's verifiable costs to conduct studies. Rowan reasoned that these changes provide additional clarity for TDSPs and large load customers.

TIEC recommended that the proposed rule should simply refer to the standards adopted in Project No. 58481.

Commission response

The commission declines to adopt AEP, TNMP, CenterPoint, and Rowan's recommendations because the commission agrees with TIEC's recommendation to simply refer to the criteria set forth in the pending rule in Project No. 58481. Because Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(3), the commission modifies adopted §25.370(c) to remove proposed §25.370(c)(3).

Request for additional capacity

OPUC recommended modifying proposed §25.370(c)(3) to include a statement consistent with PURA §37.0561(f): a large load customer that requests additional capacity following an initial screening must pay an additional study fee that is the greater of $100,000 or other amount that is set by the applicable commission rules for large load interconnection standards.

Commission Response

The commission declines to adopt OPUC's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(3). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(3) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

ERCOT costs

TEBA recommended modifying proposed §25.370(c)(3) to state that a portion of the $100,000 study fee should be given to ERCOT to offset costs. TEBA reasoned that providing ERCOT with dedicated funding will increase its bandwidth to assess and approve the abundance of capacity currently in the queue in an efficient manner.

In reply comments, LCRA opposed TEBA's recommendation because the main purpose of the study fee is to ensure that TDSPs are able to recover the cost of conducting interconnection studies. ERCOT established a large load interconnection fee of $14,000 in its NPRR 1234 for recovery of ERCOT's costs, and the amount should be updated through a subsequent revision request if it is deemed to be inadequate.

Commission Response

The commission declines to adopt TEBA's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(3). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(3) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Proposed §25.370(c)(4)- Financial commitment

Proposed §25.370(c)(4) requires a large load customer to demonstrate commitment to the TDSP by means of (A) payment of security on a dollar per megawatt basis as set by the applicable commission rule for large load interconnection standards; (B) payment of CIAC; or (C) payment of security provided under an agreement that requires the large load customer to pay for significant equipment or services in advance of signing an agreement to establish electric delivery service; or (D) payment of security provided under an agreement that requires the large load customer to pay for significant equipment or services in advance of signing an agreement to establish electric delivery service.

Mirror financial and collateral requirements in Project No. 58481

DCC recommended that the financial commitment requirements outlined for inclusion in the proposed rule mirror the financial and collateral requirements that will be implemented by the commission in Project No. 58481.

TIEC recommended that the proposed rule should simply refer to the standards adopted in Project No. 58481.

Commission Response

The commission declines to adopt DCC's recommendations because the commission agrees with TIEC's recommendation to simply refer to the criteria set forth in the pending rule in Project No. 58481. Because Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(4), the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(4) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

TDSP exclusive right to determine the form of financial security

LCRA recommended modifying proposed §25.370(c)(4) to: (1) recognize the sole and exclusive right of the TDSP to determine the form of financial security that is required; (2) require that the CIAC is an amount equal to the estimated cost of the Transmission Interconnection Facilities, subject to refund if the large load customer does not execute a final agreement to establish electric delivery service; and (3) permit the payment of security for significant equipment or services to include the estimated cost of the Transmission Interconnection Facilities as determined by the TDSP.

Eolian countered that allowing TDSPs to control the inclusion of specific large loads in ERCOT's forecasts risks inconsistent regional criteria thereby undermining accuracy and increasing confusion. Accordingly, Eolian recommended modifying proposed §25.370(c) or (e) to add language stating that ERCOT retains the ultimate authority to determine whether to include a large load in its forecasts, based on the criteria established by the commission.

OPUC recommended that if the commission adopts LCRA's recommendation to modify proposed §25.370(c)(4), the term "Transmission Interconnection Facilities" should be defined.

Commission Response

The commission declines to adopt LCRA, Eolian, and OPUC's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(4). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(4) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Fixed dollar per MW security

TNMP recommended replacing the fixed dollar per MW security requirement with a percentage-based security requirement relative to total project development to ensure fairness across large load interconnection projects, aligning securitization requirements with actual system and grid impacts. TNMP reasoned that the purpose of financial requirements is to demonstrate a large load customer's ability to meet its CIAC for direct service facilities and, in theory, to provide assurance of its financial capacity to support necessary network system improvements. Because large load customers vary significantly in terms of project size, specifications, site location, engineering design, and the extent to which system upgrades are required, a uniform dollar per MW value may be unnecessarily strict and inequitable to both large load customers and other market participants.

Rowan agreed with TNMP that the dollar per MW security requirement could fail to reflect the unique system impacts of each individual large load customer. A fairer way to demonstrate financial commitment is through payment of security based on the large load customer's pro-rata share of network upgrades to establish service. Accordingly, Rowan recommended modifying proposed §25.370(c)(4)(A) to replace the dollar per MW security requirement with a security requirement based on the project's pro-rata share of network upgrades required to establish electric delivery service.

Commission Response

The commission declines to adopt TNMP and Rowan's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(4). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(4) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

A form of financial commitment acceptable to the commission

DCC and OPUC recommended modifying proposed §25.370(c)(4) to include a statement consistent with PURA §37.0561(h), requiring the large load customer to demonstrate financial commitment by means acceptable to the commission as set forth in the applicable commission rules for large load interconnection standards.

Commission Response

The commission declines to adopt DCC and OPUC's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(4). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(4) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Inclusion after satisfying one of the interim security options

Schaper Energy recommended modifying proposed §25.370(c)(4) to specify that a load may be included in ERCOT's forecast only after the customer satisfies one of the interim security options established in Project No. 58481.

Commission Response

The commission declines to adopt Schaper Energy's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(4). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(4). However, the commission agrees that the adopted rule should cite to the pending rule in Project No. 58481 and modifies the adopted rule accordingly.

Refundable security for significant equipment or services

Targa recommended modifying proposed §25.370(c)(4)(C) to state, "Customer security provided under this subsection (4) is refundable upon withdrawal or cancellation of the interconnection request, less the TDSP's actual, reasonable, and verifiable costs or upon achievement of required customer milestones, including but not limited to specified demand level milestones." Targa reasoned that explicitly stating that security for significant equipment or services is refundable aligns incentives, reduces unnecessary risk premiums, and maintains fairness across functionally similar commitment instruments.

Crusoe supported Targa's recommendation to make refundability explicit, which aligns incentives, reduces unnecessary risk premiums, and ensures fairness for all parties.

OPUC recommended that if the commission addresses this concept in the proposed rule, then the language added should be limited to stating: "Any security provided under subparagraph (4)(A) is refundable, in whole or in part, pursuant to the conditions set forth in PURA Section 37.0561(i) and the Commission's applicable rule on large load interconnection standards."

Commission Response

The commission declines to adopt Crusoe, Targa, and OPUC's recommendations because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(4). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(4). and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards)

Proposed §25.370(c)(5)- Load ramping schedule

Proposed §25.370(c)(5) requires a large load customer to provide a load ramping schedule to the TDSP, if applicable.

LCRA recommended modifying proposed §25.370(c)(5) to clarify that the load ramping schedule will be expressed in MW and megavolt-ampere reactive (MVAr) units (i.e., real power and reactive power). LCRA also recommended modifying proposed §25.370(c)(5) to require large load customers to provide dynamic load models. LCRA reasoned that dynamic models are necessary for planning studies that analyze the behavior of large loads under varying system conditions and will be mandatory for the large load interconnection study upon implementation of Planning Guide Revision Request (PGRR) 115. In reply comments, CenterPoint made similar recommendations.

OPUC recommended modifying proposed §25.370(c)(5) to specify that the load ramp schedule includes the customer's expected total demand at the proposed load location, starting at the time of expected initial interconnection and any subsequent expected demand growth, including the timing of expected demand growth.

Rowan recommended modifying proposed §25.370(c)(5) to reflect that the submitted load ramps are subject to change at the large load customer's discretion. Load ramps may be impacted by potential construction acceleration or delays, changes to the large load's use case (for example, a change in a planned data center from cloud computing to artificial intelligence), or the type of computing equipment being used (which is rapidly evolving).

Commission Response

The commission declines to adopt LCRA, OPUC, and Rowan's recommendations because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(5). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(5) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Proposed §25.370(c)(6)- Site-related studies and engineering services

Proposed §25.370(c)(6) requires a large load customer to submit an attestation to the TDSP that attests significant, verifiable progress toward completion of site-related studies and engineering services required for project development before energization (e.g., water, wastewater, or gas).

Remove the requirement for site-related studies and engineering services

CenterPoint, Crusoe, DCC, LCRA, Oncor, Schaper Energy, Targa, and TEBA recommended modifying proposed §25.370(c) to remove the requirement for a large load customer to submit an attestation to the TDSP that attests significant, verifiable progress toward completion of site-related studies and engineering services requirement for project development before energization. DCC reasoned that the timing of these activities varies considerably among large load customers. Moreover, many large load customers are considered non-speculative before a number of site-related studies and engineering services would be required. Therefore, by requiring these attestations before a large load customer can be part of the forecast, the commission and ERCOT risk underreporting these large load customers in the forecast.

Schaper Energy reasoned that ERCOT lacks the institutional or technical expertise to evaluate progress in areas of real estate development, environmental permitting, or municipal approvals that are wholly outside the scope of electrical interconnection. Similarly, Targa reasoned that ERCOT does not possess the subject matter expertise to determine when it is commercially reasonable for non-electric studies to be complete; non-electric studies can have materially shorter lead times and critical paths than major electric interconnection facilities and transmission upgrades, which can take four to seven years to build; and the proposed rule already contains more tailored, indicators of seriousness and viability that are relevant to the electric system. TEBA asserted that requiring the submission of an attestation related to site-related studies and engineering services exceeds the statutory requirements and could impose an unnecessary administrative burden, creating barriers for legitimate large load customers seeking to interconnect.

OPUC countered that requiring large load customers to submit attestations to TSPs regarding information relevant to the customer's project development before the project is fully operational and ready for energization helps separate the projects that will materialize from those that will not. Consequently, the underlying basis for proposed §25.370(c)(6) is within the confines and intent of SB 6.

Commission Response

The commission adopts CenterPoint, Crusoe, DCC, LCRA, Oncor, Schaper Energy, Targa, and TEBA's recommendation to modify adopted §25.370(c) to remove proposed §25.370(c)(6). However, the commission does so because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(6).

Plans and progress

OPUC recommended modifying proposed §25.370(c)(6) to require TDSPs to request from each potential new large load customer its project status and plan for completion, including the following uniform milestones: (1) determination of the site development contractor; (2) purchase orders for major equipment; (3) initiation of onsite work; (4) construction initiation and completion dates; and (5) building occupation information. OPUC also recommended the plan for completion should be accompanied by an attestation signed by a representative of the large load customer with binding decision making and legal authority that states at the time of signing the attestation, the information contained within the plan is complete and accurate. Finally, OPUC recommended that, upon the TDSP's request, a large load customer be required to provide a project status update that has a comprehensive summary describing the customer's completion of or progress towards each milestone.

Oncor countered that OPUC's recommendation to modify proposed §25.370(c)(6) to require a large load to submit a plan of completion would increase delays in the modeling of loads that otherwise comply with the large load interconnection standards. Site-related services and engineering services often occur only months before interconnection while the electrical loads seeking inclusion in ERCOT forecasts are commonly electrically planning six or more years in advance. Similarly, TIEC noted that OPUC's suggestions conflict with comments filed by multiple utilities that the Commission, ERCOT, and utilities are not in a position to make an independent determination on the progress of these requirements. Moreover, embedding such judgments in interconnection and forecasting criteria invites inconsistent, subjective determinations and potential disputes.

TIEC recommended modifying proposed §25.370(c)(6) to require disclosures around the customer's plans and progress but not using it as a gating item. TIEC reasoned that while each project has a different timeline, industrial loads do not typically expend significant resources on those studies until after signing an interconnection agreement. Moreover, by requiring large loads to achieve certain development milestones that do not occur until later in the development process, or after the load signs an interconnection agreement, proposed §25.370(c)(6) could recreate the timing issues that House Bill 5066, as enacted by the 88th Texas Legislature, Regular Session, addressed.

NRG supported the inclusion of proposed §25.370(c)(6) to vet projects but recommended that "significant, verifiable progress" should be weighed relative to the planned energization date and, depending on how far in the future that date is, the large load customer should be able to meet this criterion by showing site-related studies have commenced and services agreements are in negotiation rather than requiring them to be completed. NRG reasoned that site-related studies and services agreements are often lengthy to complete and excluding loads from the forecast on this basis would hinder visibility into future load growth, as loads would only be included in the forecast at the last stages of development.

Commission Response

The commission declines to adopt OPUC, TIEC, and NRG's recommendations because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(6). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(6) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Attestation

TCPA recommended modifying proposed §25.370(c)(6) to require an attestation for significant, verifiable progress, as appropriate for the current stage of development. TCPA reasoned that different stages of development require different progress toward applicable studies and there may be studies that have not been completed or obtained or the process begun because it is too early in the development cycle to warrant any action. TCPA cautioned that without the added modifying language, the unintended consequence is under counting load coming to ERCOT and not having enough transmission infrastructure or generation to serve real load that is being developed but has not reached a stage to warrant certain studies. Adding the language "as appropriate for the current stage of development" would allow for loads to present evidence that they are undertaking the tasks they will need to complete in order to energize by their planned date, without excluding them from the forecast in later years based on them not having completed tasks that would not be expected at their stage of development.

Commission Response

The commission declines to adopt TCPA's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(6). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(6) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Collection of data

EDF recommended modifying proposed §25.370(c)(6) to clearly authorize the TDSP to collect data reasonably needed to validate large load customers' "verifiable progress" attestations, to ensure that the TDSP and ERCOT will be able to effectively enforce such a requirement.

Commission Response

The commission declines to adopt EDF's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(6). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(6) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

TDSP obligation

LCRA recommended clarifying that the only obligation for the TDSP under proposed §25.370(c)(6) is to confirm the provision of the applicable attestation because TDSPs are not positioned to make an independent determination on the progress of site studies and engineering services.

Rowan agreed with LCRA that TDSPs are not positioned to make an independent determination on the progress of site studies, engineering services, or state and local regulatory approvals. Whether a project has made significant progress is adequately reflected in the load ramp, as a large load customer is not able to agree to a load ramp until it has committed to a project development schedule. Accordingly, Rowan recommended modifying proposed §25.370(c)(6) to require attestation to reasonable progress toward realization of the load ramp schedule instead of significant, verifiable progress toward completion of site-related studies and engineering services.

Commission Response

The commission declines to adopt LCRA and Rowan's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(6). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(6) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Proposed §25.370(c)(7)- State and local regulatory approvals

Proposed §25.370(c)(7) requires a large load customer to submit an attestation to the TDSP that attests significant, verifiable progress toward obtaining state and local regulatory approvals required for project development before energization (e.g., water, air, or backup generation permits, or city or county building permits).

Remove the requirement for state and local regulatory approvals

CenterPoint, Crusoe, DCC, LCRA, Oncor, Rowan, Schaper Energy, and TEBA recommended modifying proposed §25.370(c) to remove the requirement for a large load customer to submit an attestation to the TDSP that attests significant, verifiable progress toward obtaining state and local regulatory approvals required for project development before energization. CenterPoint, DCC, and Oncor reasoned that the requirement for attestation of significant, verifiable progress toward obtaining state and local regulatory approvals could lead to large load customers being underreported in the forecast because the necessary approvals and permits occur much later during the project timelines. TEBA asserted that requiring the submission of an attestation related to state and local regulatory approvals exceeds the statutory requirements and could impose an unnecessary administrative burden, creating barriers for legitimate large load customers seeking to interconnect.

Schaper Energy reasoned that ERCOT lacks the institutional or technical expertise to evaluate progress in areas of real estate development, environmental permitting, or municipal approvals that are wholly outside the scope of electrical interconnection. Similarly, Targa reasoned that ERCOT does not possess the subject matter expertise to determine when it is commercially reasonable for non-electric permits to be complete; non-electric permits can have materially shorter lead times and critical paths than major electric interconnection facilities and transmission upgrades, which can take four to seven years to build; and the proposed rule already contains more tailored, indicators of seriousness and viability that are relevant to the electric system.

Commission Response

The commission adopts CenterPoint, Crusoe, DCC, LCRA, Oncor, Rowan, Schaper Energy, and TEBA's recommendation to modify adopted §25.370(c) to remove proposed §25.370(c)(7). However, the commission does so because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(7).

Plans and progress

OPUC recommended modifying proposed §25.370(c)(7) to require a large load customer to identify all known permits required before the customer can be operational; a description of the customer's efforts to obtain the respective permit approval; and an attestation signed by a high-level representative that the information contained in the document is complete and accurate at the time of signature.

Oncor countered that OPUC's recommendation to modify proposed §25.370(c)(7) to require a large load to submit a list of all currently known federal, state, and local regulatory permits and approvals would increase delays in the modeling of loads that otherwise comply with the large load interconnection standards. These permits and approvals are often obtained only months before interconnection while the electrical loads seeking inclusion in ERCOT forecasts are commonly electrically planning six or more years in advance. Similarly, TIEC noted that OPUC's suggestions conflict with comments filed by multiple utilities that the Commission, ERCOT, and utilities are not in a position to make an independent determination on the progress of these requirements. Moreover, embedding such judgments in interconnection and forecasting criteria invites inconsistent, subjective determinations and potential disputes

Sierra club recommended modifying proposed §25.370(c)(7) to add "or a timeline for obtaining state and local regulatory approvals required for project development if progress has not begun."

TIEC recommended modifying proposed §25.370(c)(7) to require disclosures around the customer's plans and progress but not using it as a gating item. TIEC reasoned that while each project has a different timeline, industrial loads do not typically expend significant resources on those permits until after signing an interconnection agreement. Moreover, as a practical matter proposed §25.370(c)(7) could recreate the timing issues that House Bill 5066 addressed by requiring large loads to achieve certain development milestones that do not occur until later in the development process, or after the load signs an interconnection agreement.

NRG supported the inclusion of proposed §25.370(c)(7) to vet projects but recommended that "significant, verifiable progress" should be weighed relative to the planned energization date and, depending on how far in the future that date is, the large load customer should be able to meet this criterion by showing that the requests, applications, or filing for such regulatory approvals and permits have been submitted rather than requiring them to be completed. NRG reasoned that excluding loads from the forecast on the basis that they have not yet completed state and local regulatory approvals would hinder visibility into future load growth, as loads would only be included in the forecast at the last stages of development.

Commission Response

The commission declines to adopt OPUC, Sierra Club, TIEC, and NRG's recommendations because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(7). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(7) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Attestation

TCPA recommended modifying proposed §25.370(c)(7) to require an attestation for significant, verifiable progress, as appropriate for the current stage of development. TCPA reasoned that different stages of development require different progress toward applicable permits and there may be permits that have not been completed or obtained or the process begun because it is too early in the development cycle to warrant any action. TCPA cautioned that without the added modifying language, the unintended consequence is under counting load coming to ERCOT and not having enough transmission infrastructure or generation to serve real load that is being developed but has not reached a stage to warrant certain permits. Adding the language "as appropriate for the current stage of development" would allow for loads to present evidence that they are undertaking the tasks they will need to complete in order to energize by their planned date, without excluding them from the forecast in later years based on them not having completed tasks that would not be expected at their stage of development.

Commission Response

The commission declines to adopt TCPA's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(7). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(7) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Collection of data

EDF recommended modifying proposed §25.370(c)(7) to clearly authorize the TDSP to collect data reasonably needed to validate large load customers' "verifiable progress" attestations, to ensure that the TDSP and ERCOT will be able to effectively enforce such a requirement.

Commission Response

The commission declines to adopt EDF's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(7). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(7) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

TDSP obligation

LCRA recommended clarifying that the only obligation for the TDSP under proposed §25.370(c)(7) is to confirm the provision of the applicable attestation because TDSPs are not positioned to make an independent determination on the progress of state and local regulatory approvals.

Commission Response

The commission declines to LCRA's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(7). Therefore, the commission modifies adopted §25.370(c) to remove the requirement set forth in proposed §25.370(c)(7) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Proposed §25.370(c)(6) and (7)- Site-related studies and engineering services and state and local regulatory approvals

If the commission does not adopt the recommendation to remove proposed §25.370(c)(6) and (7), Oncor recommended consolidating proposed §25.370(c)(6) and (7) into a single attestation that features a negative, reading that the large load "is not experiencing material issues conducting studies, obtaining needed engineering services or state and local regulatory approvals that will delay the planned interconnection timeline."

Commission Response

The commission declines to Oncor's recommendation because the commission determines that the pending rule in Project No. 58481 is the appropriate place to address the criteria set forth in proposed §25.370(c)(6) and (7). Therefore, the commission modifies adopted §25.370(c) to remove the requirements set forth in proposed §25.370(c)(6) and (7) and replaces it with a requirement to execute an interconnection agreement that meets the requirements under §25.194 of this Title (relating to Large Load Interconnection Standards).

Proposed §25.370(d)- Submission of load data to ERCOT

Proposed §25.370(d) requires that a TDSP submit a notarized attestation sworn to by the TDSP's highest-ranking representative, official, or officer with binding authority over the TDSP, attesting that each large load customer included in the TDSP's load data meets the criteria set forth in proposed §25.370(c). Proposed §25.370(d) also requires a TDSP to report a change to ERCOT by updating its load data not later than 10 working days after the TDSP reasonably determines there is a change in the load data that the TDSP submitted to ERCOT.

Remove proposed subsection (d)

AEP, Oncor, and TPPA recommended striking the requirement for a TDSP to report a change in load data not later than 10 working days after the TDSP reasonably determines there is a change in the load data that the TDSP submitted to ERCOT because the 10 working day timeline would be administratively burdensome. TPPA reasoned that forecasts inherently include some degree of inaccuracy and requiring TDSPs to routinely report changes would create an onerous obligation, effectively requiring them to continuously reconcile past submissions with ever-changing forecasts. AEP recommended considering an alternative such as a threshold to the forecasted load data that would be considered substantive enough to require updating or requiring an update to the load forecasts on a twice annual basis so that all numbers are updated more frequently. Similarly, Oncor recommended that an update to load data should not be required more frequently than every six months.

Commission Response

The commission adopts AEP, Oncor, and TPPA's recommendation because the commission determines that the processes and timelines for updating load data submitted to ERCOT should be developed in the ERCOT protocols, which receive stakeholder input and must be approved by the commission. This approach allows for greater coordination based on ERCOT's other processes and procedures relating to load forecasts. Therefore, the commission modifies adopted §25.370(d) to remove the requirement to report a change in load data not later than ten working days after a TDSP reasonably determines there is a change in the load data.

Defining what constitutes a "change" and timeline for reporting

LCRA recommended modifying proposed §25.70(d) to better define the level of load data "change" that would obligate a TDSP to report an update to ERCOT. LCRA reasoned that forecasts are an exercise in estimation and minor modification in input will not necessarily produce considerable or even noticeable changes in output. Therefore, it is necessary to establish reasonable bounds to mitigate this reporting burden on TDSPs. LCRA recommended either (1) defining a "material change" for purposes of proposed §25.70(d) as an increase or decrease to the 75 MW demand threshold and using this value to trigger reporting to ERCOT; or (2) to align the reporting requirement with Steady State Working Group updates or RTP case builds during the year (i.e., annually or semi-annually).

If Oncor's recommendation to remove the reporting requirement altogether is not adopted, then Oncor recommended, in the alternative, modifying proposed §25.370(d) to include a materiality qualifier to the language requiring TDSPs to report a change in load data and define what constitutes a material change (e.g., a 6-month change in load ramp or a 75 MW change in peak load) because small deviations in peak loads should not automatically require update. ERCOT needs to be able to move forward and study without being continually asked to modify loads due to marginal customer modifications. In reply comments, OPUC supported Oncor's alternative recommendation.

CenterPoint recommended changing the process by which a TDSP provides updated load data to ERCOT. Because forecasted load data frequently changes, depending on the status of proposed load to be interconnected, CenterPoint recommended that it is more efficient for a TDSP to provide updated load data to ERCOT when requested instead of 10 working days after a change is reasonably determined to have occurred.

Sierra Club supported recommendations to require TDSPs to provide information upon request by ERCOT instead of 10 working days after a change is reasonably determined to have occurred.

Commission Response

The commission declines to adopt LCRA's recommendation, Oncor's alternative recommendation, and CenterPoint's recommendation because the commission modifies adopted §25.370(d) to remove the requirement to report a change in load data not later than ten working days after a TDSP reasonably determines there is a change in the load data. Therefore, the changes recommended by LCRA, Oncor, and CenterPoint are unnecessary.

Access to updated system models

To improve accuracy and coordination, DCC recommended that TDSPs should have access to updated system models and be actively involved in their review. DCC reasoned that forecasting challenges often arise because TDSPs face difficulties in obtaining information about loads interconnecting within other TDSP service territories.

Commission Response

The commission agrees with DCC that TDSP access to updated system models could improve accuracy and coordination. However, the commission notes that ERCOT is currently developing a communication system for large load customers. Therefore, the commission determines accuracy, and coordination will improve without the need for changes to the adopted rule.

Attestation

OPUC recommended modifying proposed §25.370(d) to state that the TDSP must attest that each large load customer included in the TDSP's load data meets all of the criteria set forth in proposed §25.370(c) and if applicable, any executed and securitized interconnection agreements in place satisfy the conditions identified in proposed §25.370(c).

Oncor recommended modifying proposed §25.370(d) to authorize a representative, official, officer, or other authorized person with binding authority to execute the attestation instead of requiring the highest-ranking representative, official, or officer with binding authority over the TDSP. This change mirrors other attestation and affidavit requirements in other commission rules, such as the power generation company registration affidavit requirement found in §25.109(c)(5). Oncor also recommended clarifying whether "load data" includes all of the information submitted to ERCOT to support a given load's inclusion in ERCOT load forecasts or simply includes peak demand and load ramp data for loads that meet the ERCOT load forecast inclusion criteria. In reply comments, CenterPoint also recommended modifying proposed §25.370(d) to allow an officer of a TDSP, rather than the highest-ranking officer to submit the attestation.

Schaper Energy recommended modifying proposed §25.370(d) to state that the interconnecting TSP performing the large load interconnection study may attest directly to ERCOT that the load meets the criteria set forth in proposed §25.370(c). Schaper Energy reasoned that this approach maintains proper roles, avoids procedural bottlenecks, and ensures that the entity provides the attestation with firsthand technical knowledge of the interconnection. In reply comments, Cruose supported Schaper Energy's recommendation.

Commission Response

The commission declines to adopt OPUC's recommendation to modify proposed §25.370(d) to state that the TDSP must attest that each large load customer included in the TDSP's load data meets all of the criteria set forth in proposed §25.370(c) and if applicable, any executed and securitized interconnection agreements in place satisfy the conditions identified in proposed §25.370(c) because it is unnecessary. Instead, the commission modifies adopted §25.370(c) to require that a large load customer execute an interconnection agreement that meets the requirements under §25.194, thereby requiring large load customers meet the criteria that was set forth in proposed §25.370(c). Additionally, the commission modifies adopted §25.370(d) to require that a DSP submit a notarized attestation sworn to by the DSP's representative, official, or officer with binding authority over the DSP, attesting that each large load customer included in the DSP's load data meets the criteria for an interconnection agreement, as may be set forth in §25.194.

The commission adopts Oncor's recommendation to modify adopted §25.370(d) to authorize a representative, official, officer or other authorized person with binding authority to execute the attestation instead of requiring the highest-ranking representative, official, or officer with binding authority over the TDSP.

The commission declines to adopt Schaper Energy's recommendation to modify proposed §25.370(d) to state that the interconnecting TSP performing the large load interconnection study may attest directly to ERCOT that the load meets the criteria set forth in proposed §25.370(c). The commission determines that the DSP with the retail relationship with the large load customer is the appropriate entity to submit the load data.

Required inclusion of load data submitted by TSP

If Sharyland's recommendation to modify proposed §25.370(b)(3) is not adopted, then Sharyland recommended modifying proposed §25.370(d) to state that if a TDSP that is certificated to provide retail electric service at the site that a large load customer seeks to interconnect receives a large load customer's forecasted demand that otherwise meets the requirements of the proposed rule from an affected transmission service provider, the TDSP must include that forecasted demand in its load data submitted to ERCOT unless the TDSP reasonably determines the forecasted demand is not valid.

Joint Transmission Commenters supported Sharyland's alternative recommendation if its primary recommendation to modify proposed §25.370(b)(3) is not adopted. Additionally, Joint Transmission Commenters recommended that the TDSP should also be required communicate with large load customers and the TSP regarding any issues with the load data received, and the parties should coordinate to address these issues. Finally, Joint Transmission Commenters recommended requiring TDSPs to provide notice to the party that provided the load data when the data is submitted to ERCOT.

Commission Response

The commission substantively adopts Sharyland and Joint Transmission Commenters' recommendation to modify adopted §25.370(d) to state that if a DSP receives a large load customer's forecasted demand from a TSP, the DSP must include that load data in its submission of load data to ERCOT unless the DSP determines that the load data from the TSP is not valid or is duplicative. The commission modifies adopted §25.370(d) accordingly and also modifies §25.370(d) to impose the same attestation requirements on a TSP submitting load data to a DSP. The commission substantively adopts Joint Transmission Commenters' recommendation to modify adopted §25.370(d) to require a DSP to communicate with the TSP regarding any issues with the load data received and to provide notice to the TSP when the load data is submitted to ERCOT. The commission modifies adopted §25.370(d) accordingly.

Proposed §25.370(e)- ERCOT forecast

Proposed §25.370(e) requires ERCOT to develop load forecasts for the ERCOT region using the load data provided by TDSPs.

ERCOT recommended modifying the proposed rule to remove the language in proposed §25.370(e) and renumber proposed §25.370(e)(1) and (2) or rephrase proposed §25.370(e) to state that "ERCOT's forecasts of large load customer demand used for identifying transmission planning needs or performing resource adequacy assessments may not include load data that does not meet the criteria in subsection (c)." ERCOT reasoned that to the extent the purpose of the proposed rule is to create criteria for ERCOT to use when forecasting large load customers' demand, and not to impose an additional requirement for ERCOT to conduct any one or more particular load forecasts, this purpose is already served by proposed §25.370(c).

TEBA recommended modifying proposed §25.370(e) to remove paragraphs (1) and (2) relating to validating load data and making adjustments to load data. TEBA reasoned that adding an additional validation step is unnecessary and introduces risk and further delays for projects that have met all legal requirements. Moreover, excluding a load that has met all the requirements set forth in SB 6 could lead to inaccurate transmission planning and misrepresentation of future demand.

If the commission does not modify proposed §25.370(e) to remove paragraphs (1) and (2), then TEBA recommended modifying proposed §25.370(e)(1) to make the exclusion of load data discretionary instead of mandatory because the proposed rule does not describe what validation is, how it will be done, or how transparently it will be done.

Commission Response

The commission declines to adopt ERCOT's recommendation to remove the language in adopted §25.370(e) requiring ERCOT to develop load forecasts for the ERCOT region using the load data submitted by DSPs. However, the commission modifies adopted §25.370(e) to state that ERCOT must use the load data submitted by DSPs to develop load forecasts for the ERCOT region, rather than require ERCOT to develop load forecasts using the load data submitted by DSPs. The commission declines to adopt TEBA's recommendation to modify adopted §25.370(e) to remove subsections (e)(1) and (2) because a mechanism for adjusting load data is necessary if an error is identified or if a large load customer's interconnection request is withdrawn or cancelled prior to energization. Additionally, a mechanism should exist for ERCOT to adjust the load data in a scenario where the load data suggests more load growth in the ERCOT region than is expected in the entire country based on an independent, national survey. However, the commission modifies adopted §25.370(e)(2) to more clearly articulate the expectations for load adjustments consistent with the recommendations of other commenters.

Proposed §25.370(e)(1)- Validation of load data

Proposed §25.370(e)(1) authorizes ERCOT and commission staff to access information collected by a DSP to ensure compliance with the proposed rule and validate load data submitted by a TDSP. Additionally, proposed §25.370(e)(1) requires load data to be excluded from ERCOT's load forecast if the load data cannot be validated.

DCC recommended modifying proposed §25.370(e)(1) to provide TDSPs an avenue to correct issues with load data before ERCOT excludes data from the load forecast.

Commission Response

The commission declines to adopt DCC's recommendation to modify adopted §25.370(e)(1) to provide TDSPs an avenue to correct issues with load data before ERCOT excludes data from the load forecast because ERCOT already has an established process that serves this purpose. Therefore, the change is unnecessary. However, the commission modifies adopted §25.370(e)(2) to state that ERCOT may make certain adjustments to load data if the adjustment is agreed to by the DSP.

TCPA recommended modifying proposed §25.370(e)(1) to state that if load data submitted by a TDSP cannot be validated, including the use of other objective, credible, independent information, the data must be excluded from the load forecast developed by ERCOT. TCPA reasoned that if load forecasts yield an expected load that is outside of the expectations for all markets across the country or some other type of benchmarking data point that renders it impossible for the amount expected for ERCOT alone to materialize, then it is appropriate to make changes to ensure a forecast within the bounds of realistic potential.

TPPA recommended modifying proposed §25.370(e)(1) to state that ERCOT and commission staff must request the information, rather than having presumptive access, consistent with best practices for cybersecurity and data integrity.

Commission Response

The commission declines to adopt TCPA's recommendation to modify adopted §25.370(e)(1) to state if load data submitted by a TDSP cannot be validated, including the use of other objective, credible, independent information, the data must be excluded from the load forecast developed by ERCOT because it is unnecessary. Adopted §25.370(e)(2) authorizes ERCOT to make adjustments to the load data based on objective, credible, independent information. The commission declines to adopt TPPA's recommendation to modify adopted §25.370(e)(1) to state that ERCOT and commission staff must request the information, rather than having presumptive access because it is unnecessary. The adopted rule addresses the authority to access the information not the physical capability to access the information.

Proposed §25.370(e)(2)- Adjustments to load data

Proposed §25.370(e)(2) authorizes ERCOT, in consultation with commission staff, to adjust the load data provided by a TDSP based on actual historical realization rates or other objective, credible, independent information. Additionally, proposed §25.370(e)(2) requires ERCOT to provide the TDSP with the data and calculations used to adjust the forecasted load.

Remove proposed subsection (e)(2)

AEP and Oncor recommended removing proposed §25.370(e)(2). AEP reasoned that the TDSPs are the entities that have the relationship with the loads and can provide the most accurate information for use in forecasting. Moreover, permitting ERCOT or commission staff to adjust load data would inject unnecessary uncertainty into the load forecasting process. Additionally, AEP recommended that proposed §25.370(e)(1), which provides ERCOT with the ability to exclude load data that cannot be validated from the load forecast is sufficient to mitigate the risk of inaccurate load data. Oncor reasoned that PURA §37.0561(m) makes clear that ERCOT has no discretion to reduce peak demand load levels because this provision of PURA states the commission must establish criteria by which ERCOT includes forecasted large load of any peak demand.

OCSC and TCAP disagreed with Oncor's interpretation of SB 6 as restricting ERCOT's validation of peak demand load levels. In OCSC and TCAP's view, SB 6 only sets the floor for mandatory minimum validation.

Commission Response

The commission declines to adopt AEP and Oncor's recommendation to modify adopted §25.370(e) to remove proposed §25.370(e)(2) because a mechanism for adjusting load data is necessary if an error is identified or if a large load customer's interconnection request is withdrawn or cancelled prior to energization. Additionally, a mechanism should exist for ERCOT to adjust the load data in a scenario where the load data suggests more load growth in the ERCOT region than is expected in the entire country based on an independent, national survey. Accordingly, the commission modifies adopted §25.370(e)(2) to more clearly articulate the expectations for load adjustments.

Holistic review of load data submitted by all TDSPs and standardized criteria

LCRA recommended that if proposed §25.370(e)(2) is ultimately adopted by the commission in its final rule, then the commission should give clear direction that ERCOT should look holistically at load data submitted by all the TDSPs prior to making any adjustments, rather than singling out an individual TDSP. Additionally, LCRA recommended that ERCOT establish standardized criteria to identify and adjust the load forecast after consultation with the appropriate stakeholder groups.

Eolian and OCSC and TCAP supported LCRA's recommendation that any proposed load forecast adjustment methodology should be vetted in the ERCOT stakeholder process.

CenterPoint recommended modifying proposed §25.370(e)(2) to require ERCOT to establish a process for the adjustment of load data submitted by a TDSP.

Commission Response

The commission declines to adopt LCRA's recommendation to direct ERCOT to look holistically at load data submitted by all TDSPs prior to making adjustments because a holistic review may not always be appropriate. The commission also declines to adopt Eolian, OCSC and TCAP, and LCRA's recommendation to require vetting in the ERCOT stakeholder process and declines to adopt CenterPoint's recommendation to require ERCOT to establish a process for load data adjustments. The commission determines that adjustments to correct errors or account for withdrawal or cancellation of a large load customer's request for interconnection should be made with the DSP's agreement but otherwise does not need to be approved by stakeholders. However, for other types of adjustments, the commission determines that the adjustment should be reviewed for approval by the commission consistent with the recommendations of other commenters. The commission modifies adopted §25.370(e)(2) accordingly and includes a deadline for public comment at the commission.

TDSP, stakeholder and market participant engagement

DCC, OCSC and TCAP, Sierra Club, TCPA, TXOGA, and TPPA recommended modifying proposed §25.370(e)(2) to require engagement with some combination of TDSPs, stakeholders, and market participants before adjusting load data. Specifically, OCSC and TCAP and TPPA recommended modifying proposed §25.370(e)(2) to allow a TDSP to participate in any adjustments to load data, considering a TDSP is best positioned to adjust its own load data and ultimately it is the TDSP's responsibility to ensure service to a customer requesting interconnection, not ERCOT. In reply comments, CenterPoint also recommended that TDSPs be provided an opportunity to provide input on any adjustments to the load data that they submit to ERCOT.

Additionally, OCSC and TCAP recommended modifying proposed §25.370(e)(2) to require ERCOT to consult with market participants and stakeholders before making adjustments to its large load forecasting methodology. Similarly, TXOGA recommended requiring an opportunity for stakeholder comment.

TCPA recommended modifying proposed §25.370(e)(2) to state that ERCOT must provide a market notice to market participants with the data and calculations used to adjust the forecasted load if directed to make adjustments by the commission.

Commission Response

The commission declines to adopt DCC, OCSC and TCAP, Sierra Club, TCPA, TXOGA, and TPPA's recommendation to modify adopted §25.370(e)(2) to require engagement with some combination of TDSPs, stakeholders, and market participants before adjusting load data. The commission also declines to adopt OCSC and TCAP's recommendation to modify adopted §25.370(e)(2) to require ERCOT to consult with market participants and stakeholders before making adjustments to its large load forecasting methodology. However, the commission agrees that TDSPs, stakeholders, and market participants should have an opportunity for engagement prior to an adjustment to load data. Therefore, the commission modifies adopted §25.370(e)(2) to require the DSP's agreement for adjustments that are made to correct an error or account for the withdrawal or cancellation of a large load's interconnection request. The commission also modifies adopted §25.370(e)(2) to require commission approval for other types of adjustments and adopts TXOGA's recommendation to provide an opportunity for public comment. The commission modifies the adopted rule accordingly. The commission declines to adopt TCPA's recommendation to modify adopted §25.370(e)(2) to require ERCOT to provide a market notice to market participants with the data and calculations used to adjust the forecasted load if directed to make adjustments by the commission and instead requires ERCOT to publish a market notice if requesting commission approval of an adjustment to load data.

Historical realization rates and scope of an adjustment

TEC, TCPA, TIEC, and TXOGA recommended modifying proposed §25.370(e)(2) to narrow the scope of adjustments to the load forecast.

TEC recommended that until new realization rates can be observed and quantified, ERCOT should refrain from relying on historical realization rates that are no longer applicable with the stricter and uniform inclusion standards. TEC reasoned that the proposed tightening of forecast projections is already likely to yield a more accurate forecast, and utilizing historical realization rates on top of these new stricter standards may place ERCOT in a position of under forecasting load growth. TCPA noted that the load forecast projections for the next five to 10 years are at a pace not seen in recent history so actual historical realization rates likely have less bearing on the veracity of current load forecasts projecting growth over the next decade than during more steady growth periods. Therefore, those should not be the sole basis for adjusting the load forecasts, particularly after the forecasts are determined using the commission-prescribed standard process this rulemaking will yield.

TIEC recommended modifying proposed §25.370(e)(2) to limit the applicability of ERCOT's adjustments to load data to resource adequacy models and reports. TIEC reasoned that unlike transmission planning, resource adequacy analyses do not have a series of "back-end" checks where the load can later be removed or restudied before any costs are imposed on the system. Rather, the resource adequacy forecasts and resulting analyses provide a one-time snapshot that can be used to advocate for costly market design changes. Resource adequacy analyses are also used by the public and policymakers to evaluate the overall reliability of the grid. As a result, the goal should be to come up with a realistic forecast of expected peak demand.

Commission Response

The commission declines to adopt TEC, TCPA, TIEC, and TXOGA's recommendation to modify adopted §25.370(e)(2) to narrow the scope of adjustments to the load forecast. The commission agrees that recent historical data may not be an appropriate basis for making adjustments to the load forecast given the unprecedented load growth. However, the rule applies prospectively and as time goes on, the historical data should evolve with the load growth on the ERCOT system. The commission declines to adopt TIEC's recommendation to modify adopted §25.370(e)(2) to limit the applicability of ERCOT's adjustments to load data to resource adequacy assessments. Adjustments to load data used in transmission planning may be appropriate to correct errors in the load data or to account for an interconnection request that is withdrawn or cancelled. Moreover, given the unprecedented load growth that TCPA highlighted, the commission determines that some level of flexibility is appropriate to make reasonable adjustments.

Reason for adjustment

OCSC and TCAP and TPPA recommended modifying proposed §25.370(e)(2) to require ERCOT to provide not only the data and calculation supporting an adjustment but also the specific reasoning behind the adjustment.

Commission Response

The commission adopts OCSC and TCAP and TPPA's recommendation to modify adopted §25.370(e)(2) to require ERCOT to provide not only the data and calculation supporting an adjustment but also the specific reasoning behind the adjustment. Additionally, the commission modifies adopted §25.370(e)(2) to more specifically require ERCOT to provide in detail the data, calculations, and methodology supporting a requested adjustment.

Commission review

TCPA, TXOGA, and TPPA recommended modifying proposed §25.370(e)(2) to require commission review and approval of adjustments.

CenterPoint, DCC, OPUC, and TXOGA recommended that any future modifications by ERCOT to the customer-specific load data provided a TDSP should require commission review and approval. TXOGA reasoned that to allow ERCOT discretion to adjust the customer-specific TDSP forecasts risks a continuation of inadequate transmission planning. OPUC recommended the ERCOT board of directors also approve the adjustment before it goes into effect and that this adjustment authority sunset after five years if not sooner.

TCPA recommended modifying proposed §25.370(e)(2) to state that the commission may direct ERCOT to adjust the load data provided by a TDSP based on objective, credible, independent information (i.e., not actual historical realization rates).

Commission Response

The commission declines to adopt TCPA, TXOGA, and TPPA's recommendation to modify adopted §25.370(e)(2) to require commission review and approval of adjustments. The commission also declines to adopt CenterPoint, DCC, OPUC, and TXOGA's recommendation to require commission review and approval of adjustments to customer-specific load data provided by a TDSP. Finally, the commission declines to adopt TCPA's recommendation to modify adopted §25.370(e)(2) to state that the commission may direct ERCOT to adjust the load data provided by a TDSP based on objective, credible, independent information (i.e., not historical realization rates). The commission determines that not all adjustments rise to the level of needing commission review. For example, the commission does not need to approve an adjustment agreed to by a DSP to correct an error or account for the withdrawal or cancellation of a large load customer's interconnection request. However, the commission does agree that other adjustments should be subject to commission review and modifies the adopted rule accordingly. With respect to historical realization rates, the commission determines that some level of flexibility to make reasonable adjustments is appropriate in light of the unprecedented load growth in the ERCOT region. Moreover, as time goes on, the historical data should evolve with the load growth on the ERCOT system and become a more valuable data point. Therefore, the commission declines to remove historical realization rates as a potential basis for adjusting the load data.

Proposed §25.370(e)(3)- Use of load forecasts

Proposed §25.370(e)(3) requires ERCOT to use the load data provided by TDSPs in its transmission planning and resource adequacy models and reports. Additionally, proposed §25.370(e)(3) permits applicable adjustments to the load forecast to accommodate differences in study scope, time horizons, and modeling details.

AEP recommended modifying proposed §25.370(e)(3) to add a statement requiring ERCOT to recognize the different purposes of the load forecasts used in transmission planning and resource adequacy and make applicable adjustments to account for the different purposes.

DCC recommended that ERCOT be required to obtain stakeholder input before adjusting load forecasts for transmission planning and resource adequacy models due to "differences in study scope, time horizons, and modeling details." DCC reasoned that an opportunity for stakeholder review and input would improve the accuracy of load forecasts and result in greater transparence to enable companies to plan their projects accordingly.

ERCOT recommended modifying proposed §25.370(e)(3) to remove the first sentence which appears to serve only as a restatement of ERCOT's obligations to develop forecasts. This modification avoids potential confusion about whether ERCOT's duty to rely on TDSP forecasts is subject to ERCOT's authority to adjust described in proposed §25.370(e)(2). ERCOT also recommended modifying proposed §25.370(e)(3) to align with the fact that ERCOT does not simply use a single load forecast but instead develops multiple load forecasts for different purposes. The reference in proposed §25.370(e)(3) to "study scope, time horizon, and modeling details" appears to contemplate factors that ERCOT believes would be more relevant to the development of a different forecast instead of adjustments to a single standard load forecast. Accordingly, ERCOT recommended modifying proposed §25.370(e)(3) to state "ERCOT may use different load forecasts to reflect different study scopes, time horizons, scenarios, and modeling details in developing its transmission planning and resource adequacy reports."

TCPA recommended modifying proposed §25.370(e)(3) to state applicable adjustments to the load forecast may be made to accommodate differences in use cases. TCPA reasoned that while the data may have different use cases and it is appropriate to make adjustments based on the use case, the actual, final load forecast should be the same regardless of whether it is used for transmission planning purposes or resource adequacy. If loads are coming to ERCOT, they will need transmission infrastructure, as well as generation. Therefore, the actual load expected in determining what transmission needs to be built should be the same as the load expected in determining the regions' resource adequacy needs.

TIEC recommended modifying proposed §25.370(e)(3) to state that ERCOT must recognize the different purposes of the load forecasts used in transmission planning and resource adequacy and make applicable adjustments to the underlying data to account for the different uses. Transmission forecasts are often required to allow a utility to offer a service agreement to a customer. However, based on the results of the study, the customer may or may not move forward. The study process is just one of many steps in transmission planning, and load may fall off at each step. Resource adequacy, by contrast, must try to predict how much load will actually materialize, and how it will behave during peak conditions. Further, transmission planning must provide sufficient interconnectivity to serve the maximum end-state of the project the highest expected level of demand. However, a load may ramp up to that maximum demand over time. This is often not reflected, if at all, in transmission planning studies because it is more efficient to build out the full connection up front. Transmission cannot be built "granularly" as a load ramps up in most instances. For all of these reasons, TIEC recommended that the forecasts and modeling techniques used for transmission planning and resource adequacy are not the same, and the rule should not promote that outcome.

TXOGA noted that while ERCOT should include the large load customer demand data as defined in the proposed rule in both transmission planning and resource adequacy forecasts, the actual resulting forecasts used by ERCOT should not be the same. Rather, these forecasts should continue to reflect the different requirements of the analyses being conducted.

TPPA recommended modifying proposed §25.370(e)(3) to clarify whether "applicable adjustments" applies more broadly to the ERCOT load data and forecasts used for transmission planning versus resource adequacy, and not to the underlying TDSP load data. If so, TPPA recommended requiring commission approval of such adjustments to the transmission planning load forecast and the resource adequacy load forecast. Alternatively, TPPA recommended requiring these adjustments be discussed through the ERCOT stakeholder process and codified in the ERCOT protocols to truly determine what adjustments are appropriate for use in transmission planning reporting versus resource adequacy reporting.

In reply comments, TIEC noted that while ERCOT's recommendation to modify proposed §25.370(e)(3) seems consistent with TIEC's position, ERCOT's proposed modifications to the language are not explicit enough. Specifically, ERCOT suggests the provision say, "ERCOT may use different load forecasts to reflect the different study scopes, time horizons, scenarios, and modeling details in developing its transmission planning and resource adequacy reports." TIEC asserted, however, that stakeholders would benefit from the rule definitively stating that resource adequacy forecasts will require more substantial adjustments. Moreover, contrary to TCPA's position, TIEC reiterated that the resource adequacy forecast should always be lower than the transmission planning forecast. Transmission planning and resource adequacy studies are fundamentally different with different purposes and goals. Transmission studies are meant to ensure the grid can serve customer needs under extreme loading and contingency conditions (i.e., n-1 contingencies). Conversely, load forecasts for resource adequacy must identify the outcome with the highest probability of occurrence and contingencies are managed through a reserve margin. Transmission forecasts also need to reflect the ultimate interconnection capacity, whereas resource adequacy forecasts should reflect how a load plans to ramp up over time. Using a transmission forecast for resource adequacy analyses would therefore be fundamentally wrong and essentially require double coverage for contingencies. It would also undoubtedly lead to unrealistic and alarmist resource adequacy forecasts. To avoid this result, TIEC recommended the proposed rule make it clear that ERCOT's resource adequacy and transmission planning analyses are subject to different adjustments.

Commission Response

The commission adopts ERCOT's recommendation to remove the first sentence of proposed §25.370(e)(3) and modifies the adopted rule language to clarify that ERCOT's forecasts must be developed using the data provided by DSPs, subject to any adjustments made in accordance with adopted §25.370(e)(1) and (2).

The commission agrees with comments by AEP, ERCOT, TCPA, TIEC, and TXOGA describing differences in load forecasts for different scenarios or use cases. As such, the commission adopts ERCOT's recommendation to modify adopted §25.370(e)(3) to reflect that the reference to applicable adjustments is more relevant to the development of different forecasts rather than as adjustments to a single, standard forecast. Differences in the underlying assumptions or methodologies used to develop different forecasts, using the same underlying data, recognize the unique nature of the use cases to which these forecasts are applied. However, the Commission declines to adopt related comments by TIEC which would stipulate specific language around how different forecasts are developed or require a specific, presupposed outcome.

Proposed §25.370(f)- Confidential information

Proposed §25.370(f) states that customer-specific information or competitively sensitive information is confidential and not subject to disclosure under Chapter 552 of the Texas Government Code.

Eolian recommended modifying proposed §25.370(f) to include language that mirrors PURA §37.0561(k), which provides that standards adopted by the commission must establish a procedure to allow ERCOT to access any information collected by the interconnecting electric utility or municipally owned utility to ensure compliance with the standards for transmission planning analysis.

Commission response

The commission declines to adopt Eolian's recommendation to modify adopted §25.370(f) because the suggested change is best addressed in the pending rule in Project No. 58481.

Proposed §25.370(g)- ERCOT compliance

Proposed §25.370(g) requires ERCOT to develop the necessary protocols to ensure its 2026 RTP complies with the proposed rule. Additionally, if ERCOT cannot timely implement the protocols to ensure the 2026 RTP complies with the proposed rule, then proposed §25.370(g) requires ERCOT, in consultation with commission staff, to submit a compliance plan to the commission, detailing how it will ensure the 2026 RTP complies with the proposed rule.

TPPA recommended modifying proposed §25.370(g) to require ERCOT to develop protocols for implementing the proposed rule more broadly, rather than limiting the development of protocols to the RTP. TPPA reasoned that ERCOT will need to revise several of its protocols to effectuate portions of the proposed rule not related to the 2026 RTP, and the proposed language could be read to limit ERCOT only to updating its protocols related to the 2026 RTP.

Commission Response

The commission adopts TPPA's recommendation to modify adopted §25.370(g) to require ERCOT to develop protocols for implementing the rule more broadly, rather than limiting the development of protocols to the RTP. Additionally, the commission adds adopted §25.370(h) to provide additional clarity that ERCOT must use the load data submitted for the 2026 RTP in its transmission planning studies and resource adequacy assessments until new load data is submitted by DSPs using the criteria in adopted §25.370(c).

In adopting this section, the commission makes other minor modifications for the purpose of clarifying its intent.

This section is adopted under the following provisions of Public Utility Regulatory Act (PURA): §14.001, which grants the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by this title that is necessary and convenient to the exercise of that power and jurisdiction; §14.002, which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; §37.056, which requires the commission to consider historical load, forecasted load growth, and additional load currently seeking interconnection, including load for which the electric utility has yet to sign an interconnection agreement, as determined by the electric utility with the responsibility for serving the load, when considering need for additional service; §37.0561, which requires the commission by rule to establish criteria by which ERCOT includes forecasted large load of any peak demand in the organization's transmission planning and resource adequacy models and reports; §39.151, which grants the commission authority to oversee ERCOT; and §39.166, which requires ERCOT to use forecasted electrical load, as reasonably determined by the certificated transmission service provider, to identify each region in which transmission capacity is insufficient to meet the region's existing and forecasted electrical load.

Cross Reference to Statutes: Public Utility Regulatory Act §14.001; §14.002; §37.056; §37.0561; §39.151; and §39.166.

§25.370. ERCOT Large Load Forecasting Criteria.

(a) Purpose. The purpose of this section is to establish criteria for including the load of a large load customer in ERCOT's load forecasts used for identifying transmission planning needs and performing resource adequacy assessments.

(b) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise:

(1) Contracted peak demand--The total peak demand that a large load customer requests be served at a site as stated in an agreement.

(2) Large load customer--An entity requesting a new or expanded interconnection where the customer's total expected non-coincident peak demand at a single site is equal to or greater than 75 megawatts (MW).

(c) Criteria for inclusion in ERCOT load forecast. A DSP must not submit a large load customer's forecasted demand for purposes of inclusion in an ERCOT load forecast used for identifying transmission planning needs or performing resource adequacy assessments unless the large load customer executed an interconnection agreement as required under §25.194 of this Title (relating to Large Load Interconnection Standards) and provided all of the disclosures and financial commitments required for such an agreement under §25.194 of this Title. ERCOT must not include a large load customer's forecasted demand in a load forecast used for identifying transmission planning needs or performing resource adequacy assessments unless the large load customer executed an interconnection agreement as required under §25.194 of this Title and provided all of the disclosures and financial commitments required for such an agreement under §25.194 of this Title.

(d) Submission of forecasted load data to ERCOT. A DSP may submit load data to ERCOT only for a large load customer that is located or seeks interconnection at a location that is in the DSP's certificated service area. At the time that a DSP submits its load data to ERCOT through a mechanism designated by ERCOT, the DSP must also submit to ERCOT a notarized attestation sworn to by the DSP's representative, official, officer, or other authorized person with binding authority over the DSP, attesting that each large load customer included in the DSP's load data meets the criteria for an interconnection agreement as set forth in §25.194 of this Title.

(1) In its submission to ERCOT, a DSP must include load data that is received from a transmission service provider (TSP) and is associated with a large load customer that is located or seeks interconnection at a location that is in the DSP's certificated service area unless the DSP reasonably determines that the load data is not valid or is duplicative. The DSP must notify the TSP when the load data that was submitted by the TSP is provided to ERCOT, whether any load data submitted by the TSP is excluded, and the basis for exclusion, if applicable.

(2) A TSP that submits load data to a DSP under this section must submit to the DSP a notarized attestation sworn to by the TSP's representative, official, officer, or other authorized representative with binding authority over the TSP, attesting that each large load customer included in the load data submitted by the TSP meets the criteria for an interconnection agreement as set forth in §25.194 of this Title and provided all of the disclosures and financial commitments required for such an agreement under §25.194 of this Title.

(3) A DSP may designate another electric utility, municipally owned utility, or electric cooperative to submit the load data to ERCOT on its behalf.

(e) ERCOT load forecast. ERCOT must use the load data provided by DSPs under this section, subject to any adjustments made in accordance with this subsection, to develop load forecasts used in transmission planning studies and resource adequacy assessments for the ERCOT region, including Regional Planning Group project submissions after the effective date of this section.

(1) Validation of load data. ERCOT and commission staff may access information collected by a DSP or TSP to ensure compliance with this section and validate the accuracy of load data submitted by a DSP. If the accuracy of load data submitted by a DSP cannot be validated, ERCOT may exclude the data from the load forecast developed by ERCOT in accordance with subsection (e)(2) of this section.

(2) Adjustments to load data.

(A) ERCOT may make adjustments to the load data provided by the DSP under this section to correct errors in load data or to account for the withdrawal or cancellation of a large load customer's request for interconnection if the DSP agrees with the adjustments. Commission approval is not required for any mutually agreed adjustment to correct errors in load data or to account for the withdrawal or cancellation of a large load customer's request for interconnection. For any adjustment that a DSP does not agree to, ERCOT must request commission approval under subsection (e)(2)(B) of this section.

(B) ERCOT, in consultation with commission staff, must request commission approval to adjust the load data provided by DSPs under this section for any adjustment not made under subsection (e)(2)(A) of this section. The commission may approve ERCOT's request to adjust the load data if the adjustment is supported by actual historical realization rates or other objective, credible, independent information. ERCOT must file its request with the commission and publish market notice of the requested adjustment not less than 30 days before the commission's consideration at an open meeting. The commission may, at its discretion, consider the matter at an earlier open meeting. ERCOT's filed request must provide in detail the data, methodology, and calculations used for the recommended adjustment to the load data, and the specific reasoning behind the requested adjustment. Public comment related to the requested adjustment must be filed not later than 14 days after ERCOT's filed request, unless the commission establishes a different deadline.

(3) Use of load forecasts. ERCOT may use different forecasts to accommodate differences in study scope, time horizon, scenarios, and modeling details in developing its transmission planning and resource adequacy reports.

(4) Annual assessment. ERCOT must file an annual assessment with the commission that:

(A) compares past forecasts to actual outcomes;

(B) identifies sources of error; and

(f) Confidential information. Customer-specific or competitively sensitive information obtained under this section is confidential and not subject to disclosure under Chapter 552 of the Texas Government Code.

(g) ERCOT compliance. ERCOT must develop the necessary protocols to ensure its transmission planning studies and resource adequacy assessments comply with this section. If ERCOT cannot timely implement the protocols to ensure the 2026 Regional Transmission Plan (RTP) complies with this section, then ERCOT, in consultation with commission staff, must submit a compliance plan to the commission, detailing how it will ensure the 2026 RTP substantially complies with this section. The 2026 RTP compliance plan must ensure that load data is submitted to ERCOT not later than April 1, 2026 and that a large load customer included in the load data has executed an agreement that meets the criteria described below.

(1) A large load customer must disclose whether the large load customer is pursuing a separate request for electric service, the approval of which would result in the customer materially changing, delaying, or withdrawing the interconnection request; and if so, the location, size, anticipated timing of energization, and the electric utility, municipally owned utility, or electric cooperative associated with such request.

(2) A large load customer must demonstrate site control for the proposed load location through one of the following interests:

(A) a signed and executed lease agreement for the proposed load location for a duration of at least five years from the date the large load customer is expected to reach the contracted peak demand; or

(B) a deed for the proposed load location.

(3) A large load customer must provide a load ramping schedule, if applicable;

(4) A large load customer must demonstrate financial commitment by means of one of the following:

(A) posting of security in the amount of $100,000 per MW of contracted peak demand;

(B) posting of financial security to the DSP or TSP in an amount equal to the DSP and TSP's expected costs for equipment with a lead time of at least six months and services necessary to interconnect the large load; or

(C) payment of contribution in aid of construction (CIAC) in an amount that is equal to the DSP and TSP's expected costs to interconnect the large load customer that are directly attributable to interconnecting the large load customer. The costs for CIAC must be remitted through a direct cash payment and include the following:

(i) costs associated with one or more new transmission lines built to interconnect the large load customer to the existing transmission network, including substation upgrades necessary to interconnect the new large load customer; and

(ii) costs associated with system upgrades that would not be required but for the interconnecting large load customer.

(5) Security posted under this subsection must be remitted in one of the following forms:

(A) cash collateral;

(B) a letter of credit issued by a major U.S. commercial bank, or a U.S. branch office of a major foreign commercial bank, with a credit rating of at least "A-" by Standard & Poor's or "A3" by Moody's Investor Service; or

(C) corporate or parental guaranty, only if the corporation or parent has a credit rating equivalent of BBB-/Baa3 or higher from Standard & Poor's or Moody's.

(h) Effective date. ERCOT must use load data submitted for the 2026 RTP in its transmission planning studies or resource adequacy assessments, including Regional Planning Group project submissions until ERCOT constructs new planning cases with the load data submitted by DSPs using the criteria in subsection (c) of this section. For all transmission planning studies and resource adequacy assessments that are conducted before the implementation of any protocols or compliance plan adopted under subsection (g) of this section, ERCOT must continue to use its load forecast practices in effect immediately prior to the effective date of this section.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 9, 2026.

TRD-202600556

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: March 1, 2026

Proposal publication date: October 3, 2025

For further information, please call: (512) 936-7433

SUBCHAPTER S. WHOLESALE MARKETS

16 TAC §25.520

The Public Utility Commission of Texas (commission) adopts new 16 Texas Administrative Code (TAC) §25.520, relating to Firm Fuel Supply Service (FFSS), with changes to the proposed text as published in the November 7, 2025 issue of the Texas Register (50 TexReg 7197). The new rule implements Public Utility Regulatory Act (PURA) §39.159 as enacted by Senate Bill (SB) 3 during the Texas 87th Regular Legislative Session. The new rule will establish the criteria for a resource to participate in the Firm Fuel Supply Service (FFSS) program and the requirements for ERCOT to implement the FFSS program. This section is adopted under Project Number 58434. This rule will be republished.

The commission received written comments on the proposed section from the Electric Reliability Council of Texas, Inc. (ERCOT); Lower Colorado River Authority (LCRA); NRG Energy, Inc. (NRG); Office of Public Utility Counsel (OPUC); Potomac Economics (Potomac); Steering Committee of Cities Served by Oncor (OCSC) and Texas Coalition for Affordable Power (TCAP); Texas Electric Cooperatives, Inc. (TEC); Texas Industrial Energy Consumers (TIEC); Texas Public Power Association (TPPA); and Vistra Corporate Service Company (Vistra).

The commission invited interested persons to address two questions related to various provisions of the proposed rule.

1. If the offers submitted by resources under proposed subsections (c)(1) and (2) are insufficient for ERCOT to allocate 70% of the budget to those resources, as required by proposed subsection (d)(2), how should the awards be allocated?

ERCOT, NRG, TEC, and TIEC recommended that if the offers submitted by resources under proposed subsections (c)(1) and (2) are insufficient to allocate 70% of the budget to those resources, then the remaining portion of the budget (after all resources under proposed subsections (c)(1) and (2) are procured) should be reallocated to resources under proposed subsection (c)(3). Similarly, Vistra recommended ERCOT be given discretion to short fill with resources under proposed subsection (c)(3).

TPPA recommended that reallocation is unnecessary if the language in the proposed rule is revised to instead state that no more than 30% of the budget can be used to procure resources under proposed subsection (c)(3).

LCRA recommended that load should avoid uplifted settlement costs proportional to the unspent budget. Additionally, LCRA and OPUC recommended that such circumstances are an indicator that the budget, offer caps, or targeted procurement of megawatts (MW) should be reevaluated to attract new investment.

Potomac recommended replacing the bifurcated budget with a single budget.

Commission Response

The commission disagrees with TPPA that if the language in the rule is revised to instead state that no more than 30% of the budget can be used to procure resources under adopted §25.520(c)(2), then reallocation is unnecessary. This is simply stating the inverse and still does not address a scenario where only 60% of the budget is captured by offers from resources under adopted §25.520(c)(1) and (2) and 30% of the budget is captured by offers from resources under adopted §25.520(c)(3), leaving ambiguity as to whether the remaining 10% of the budget may be reallocated.

The commission declines to adopt Potomac's recommendation to replace the bifurcated budget with a single budget because a single budget is likely to result in resources under adopted §25.520(c)(3) crowding out resources under adopted §25.520(c)(1) and (2). The commission notes that a single clearing price would likely eliminate oil-fired resource participation because gas-fired resources have lower heat rates and can offer more competitively (i.e., at lower prices). The bifurcated budget preserves space for oil-fired resources while allowing limited opportunity for participation by gas-fired resources, maintaining incentives for oil-fired resources to submit competitive offers.

The commission agrees with ERCOT, NRG, TEC, TIEC, and Vistra that if the offers submitted by resources under adopted §25.520(c)(1) are insufficient to allocate 70% of the budget to those resources, then the remaining portion of the budget (after all resources under adopted §25.520(c)(1) are procured) should be reallocated to resources under adopted §25.520(c)(2). The commission also agrees with LCRA that load should avoid uplifted settlement costs proportional to the unspent budget. Accordingly, the commission modifies the rule to specify that if the offers submitted by resources under adopted §25.520(c)(1) are insufficient to allocate 70% of the budget to those resources, then ERCOT may reallocate the remaining portion of the budget, after all resources under adopted §25.520(c)(1) are procured, to resources under adopted §25.520(c)(2). This approach maintains flexibility in procuring additional resources to provide the service if appropriate while also acknowledging that ERCOT is not required to spend the entirety of the budget and thus, load should avoid uplifted settlement costs proportional to the unspent budget.

2. What process should be used to establish the heat rate and offer cap described in subsection (e)?

For purposes of developing the fuel prices for resources that burn fuel oil, ERCOT recommended calculating the offer cap using the four-month forecasted price of natural gas reflected in dollars per Million British Thermal Units (MMBtu). Then, adding 50 cents per MMBtu to account for fuel storage and transportation costs. This value of 50 cents would reflect the value established as the default for use in other processes by the ERCOT Verifiable Cost Manual §3.4(1). Subsequently, ERCOT converts the total fuel price value from units of dollars per gallon to units of dollars per MMBtu. With respect to the heat rate, ERCOT recommended that the use of multiple heat rates is appropriate to differentiate among categories of resources eligible to provide FFSS. To develop an average heat rate for each resource category that is then used in the calculation of the updated offer caps each year, ERCOT recommended using a combination of information from its comprehensive database of resource-specific parameters and the U.S. Environmental Protection Agency's (EPA) database. ERCOT proposed using this information as follows:

1. use resource-specific parameters and EPA data to calculate heat rates for each existing generation resource that operated using fuel oil or natural gas during the winter in the past three years;

2. compare the heat rate values derived from the ERCOT and EPA data and if the difference is less than 10%, assume both sources are similar and use either source. Otherwise, select the source (ERCOT or EPA) that better reflects the resource's heat rate based on ERCOT's experience and historical data;

3. for each resource, find heat rates for output levels within ±20% of the midpoint of the range between the resource's low sustained limit (LSL) and high sustained limit (HSL) over the last three years; and

4. average the heat rates by fuel type and resource category.

NRG recommended using the same 12 MMBtu heat rate to calculate the offer caps. OPUC recommended using the same heat rate but different fuel price to calculate the offer caps.

TEC recommended the same 15 MMBtu heat rate for all resources and the price of fuel oil to establish a single clearing price. TEC reasoned that the use of a single heat rate across resources creates a market efficiency by comparing the costs of operation on the same playing field and ultimately rewarding the lowest cost and most efficient resources. At a minimum, TEC recommended that the heat rates for on-site natural gas should be the same as line-fed natural gas plants with firm contracts. TEC reasoned that the underlying fuel is the same. The nature of acquisition should not impact the heat rate assessment. Moreover, allowing for the creation of a separate heat rate could allow line-fed plants with firm contracts to benefit as compared to the on-site resources that have a firmer fuel supply and should be considered as the superior resource for purposes of the FFSS.

Potomac recommended using a resource-specific heat rate and offer cap. Potomac reasoned that a resource-specific offer cap mitigates market power concerns given that each resource's historical heat rate is well known. Since the resources described in proposed §25.520(c)(2) may contain either oil-fired or gas-fired resources, the offer cap would need to be set to accommodate oil-fired resources, in which case gas-fired resources will have an opportunity to offer materially above their cost and still outcompete the oil-fired resources in this category.

Vistra recommended using historical fuel prices.

LCRA cautioned against overly conservative generic values as unit efficiencies and fuel prices may vary considerably from season to season. OCSC and TCAP recommended that procurement should be for a target quantity based on reliability criteria instead of based on a price cap.

Commission Response

The commission agrees with ERCOT that the offer cap should be calculated using the forecasted price of natural gas reflected in dollars per MMBtu that is forecasted for the four months comprising the FFSS obligation period. Then, adding 50 cents per MMBtu to account for fuel storage and transportation costs. Moreover, the commission agrees with ERCOT that the use of multiple heat rates is appropriate to differentiate among categories of resources eligible to provide FFSS. To develop an average heat rate for each resource category that is then used in the calculation of the updated offer caps each year, ERCOT should use a combination of information from its comprehensive database of resource-specific parameters and the U.S. Environmental Protection Agency's (EPA) database. This approach accounts for the fact that heat rates are dynamic rather than static. As technology improves, generation resources may become more efficient and have lower heat rates. Heat rates can also slowly degrade as a generation resource ages. Therefore, the commission declines to include a specific heat rate in the adopted rule for each resource category.

The commission declines to adopt Potomac's recommendation to use a resource-specific heat rate and offer cap because the category-level heat rates and offer caps in the adopted rule already account for differences in fuel type and resource characteristics, balancing simplicity and fairness.

The commission declines to adopt Vistra's recommendation to use historical fuel prices because projected fuel prices account for both historical fuel prices and the future state of fuel prices thus yielding a more accurate estimate in this context.

The commission agrees with OCSC and TCAP that procurement should be for a target quantity based on reliability criteria instead of based on a price cap. However, a price cap is a necessary ceiling to evaluate reasonable offers and ERCOT is best positioned to evaluate the appropriate target quantity based on each FFSS obligation period. Therefore, the commission declines to specify a target quantity in the adopted rule.

General Comments

Participation of gas-fired resources

Potomac recommended against allowing gas-fired resources with off-site storage to participate in the FFSS program because the FFSS program is intended to incentivize resources that can store their fuel, i.e., oil-fired resource or dual fuel capable resources, to do so in case these resources need to be called on for a longer deployment. Potomac reasoned that gas-fired resources do not store their fuel, are already incentivized to maintain firm supply, and will outcompete and displace oil-fired resources.

Similarly, OCSC and TCAP urged the commission to establish a "discrete" service, which will result in more reliability and promote a competitive market. OCSC and TCAP contended that the proposed rule conflicts with the reliability and security goals sought by the Texas Legislature following Winter Storm Uri. The addition of gas-fired resources with off-site storage arrangements in the proposed rule subject the grid to what are widely considered "riskier" resources that will displace more reliable on-site fuel in the FFSS procurement process, considering the proposed rule allows ERCOT to spend a maximum of $54 million in standby payments during a single winter season. OCSC and TCAP also asserted that the proposed rule conflicts with PURA §39.001 and ERCOT's competitive market design because the proposed rule does not include any defined competitive bid process and instead allows ERCOT to unilaterally procure FFSS ahead of each winter season, while spending a maximum of $54 million in standby payments. OCSC and TCAP concluded that the proposed expanded FFSS eligibility and procurement provisions result in excessive out-of-market costs that are passed through to consumers.

Relatedly, TPPA recommended clarifying the purpose of FFSS, i.e., whether the purpose is to incentivize new investments in dual-fuel capability and on-site fuel storage or to compensate generators who were already providing this additional reliability without payment. If the intent is to drive greater investment in enhanced reliability through dual-fuel capability or fuel storage, the program would need to offer significantly more lucrative incentives. Allowing generation resources that rely on firm intrastate gas contracts with third parties to qualify for the service undermines the core reliability value it is supposed to provide. These types of fuel arrangements were unreliable during Winter Storm Uri, leading to system wide generation disruptions which prompted the creation of FSS. Furthermore, expanding eligibility to include generators with off-site storage reduces the incentive to invest in on-site or dual fuel storage.

Commission Response

The commission declines to adopt Potomac and OCSC and TCAP's recommendation to modify the rule to disallow gas-fired resources with off-site storage from participating in the FFSS program. PURA §39.159(c)(2) requires the commission to ensure an FFSS resource include on-site storage, dual fuel capability, or fuel supply arrangements. Thus, the statute contemplates the inclusion of gas-fired resources, and it is appropriate to allow those resources to participate in the FFSS program. Moreover, the commission disagrees that the gas-fired resources will outcompete and displace oil-fired resources. The FFSS program as set forth in the adopted rule recognizes the different attributes of gas-fired resources and oil-fired resources by requiring that ERCOT establish different heat rates and fuel prices for these different types of resources. The heat rate and fuel price for gas-fired and oil-fired resources is then used as part of the calculation for setting an offer cap that is unique to gas-fired resources and an offer cap that is unique to oil-fired resources.

By designing the offer caps for each set of unique resources in a manner that accounts for their different attributes and allocating a percentage of the budget for each category of resources, the adopted rule ensures that gas-fired resources will not outcompete and displace oil-fired resources while also encouraging greater competition, which is expected to result in ERCOT procuring a greater number of MW at a lower price per MW thus incurring a greater reliability benefit at a lower cost. The commission also disagrees with OCSC and TCAP's assertion that the adopted rule does not include a competitive bid process. The adopted rule requires ERCOT to solicit, evaluate, select, and award offers submitted by a qualified scheduling entity (QSE) on behalf of a resource based on specific criteria and authorizes ERCOT to reject offers that are non-compliant or unreasonable.

The commission also declines to adopt TPPA's recommendation to modify the adopted rule to clarify the purpose of the FFSS by specifying whether the purpose is to incentivize new investments in dual-fuel capability and on-site fuel storage or to compensate generators who were already providing this additional reliability without payment because it is unnecessary. The purpose is already clearly stated in adopted §25.520(a).

Clearing price mechanism

Potomac recommended using a single price clearing mechanism. Potomac reasoned that FFSS resources provide a single reliability benefit, and resources participating in the FFSS program should all compete within a single price clearing mechanism to offer that benefit. The clearing structure in the proposed rule amplifies the distortion to price formation.

Commission Response

The commission declines to adopt Potomac's recommendation to use a single clearing price mechanism. A single clearing price mechanism would result in the gas-fired resources outcompeting and displacing oil-fired resources, thereby creating the problematic issues that Potomac has identified. The distinct clearing price mechanisms mitigate the concerns raised by Potomac and are expected to result in a greater reliability benefit by enabling ERCOT to procure more MW at a lower cost per MW, which benefits consumers.

Lack of replacement charge

Potomac recommended including a replacement charge to ensure that an adverse price impact that is created by an FFSS resource's absence falls on the FFSS resource that failed to perform rather than on consumers who paid for the service. Although the proposed claw back addresses the concern that the market paid for a service it did not receive when a FFSS resource fails to perform, Potomac noted that the proposed claw back does not address the fact that prices increase when a FFSS resource fails to perform because the expected and paid-for capacity is absent at the moment it is needed. According to Potomac, a replacement charge addresses this gap in the proposed rule.

Commission Response

The commission declines to adopt Potomac's recommendation to include a replacement charge. The commission determines that a replacement charge is better suited to evaluation in the development of ERCOT protocols which receive stakeholder input and are reviewed by the commission for approval.

Additional market power mitigation tools

TIEC recommended clarifying that the independent market monitor (IMM) and ERCOT have the ability to impose additional market power mitigation tools as needed. TIEC noted that there is potential for market power for the existing set of FFSS resources, who will continue to provide 70% of the expanded service and will likely set the clearing price. Under the current formulation of FFSS, prices have consistently cleared at the offer cap. Therefore, the commission may want to consider other market power mitigation tools for FFSS. Today, offer caps are determined based on a uniform $17/MMBtu and heat rate of 15. Instead of using the same offer cap for all resources, the proposed rule directs ERCOT to establish separate offer caps for each category of resources by multiplying the projected fuel price of fuel oil and a heat rate (MMBtu/MWh) for each category of eligible resources. The resulting offer cap will likely be similar for existing resources providing FFSS through on-site fuel, which will leave the market power issues more or less unchanged if all existing FFSS resources continue to bid in the cap.

Commission Response

The commission declines to adopt TIEC's recommendation to modify the adopted rule to clarify that the IMM and ERCOT have the ability to impose additional market power mitigation tools as needed because it is unnecessary. The adopted rule does not limit the IMM or ERCOT's authority to address market power abuse.

Use cases

TPPA recommended providing use cases which define times when it is appropriate for ERCOT to dispatch FFSS. TPPA reasoned that expanding eligibility to include resources that continue to rely on pipeline-delivered gas would undermine the rationale ERCOT has cited for the program's use to date. Specifically, ERCOT deploys FFSS so that generation resources with non-pipeline fuel sources are dispatched, thereby freeing up pipeline capacity and gas availability for other generators, even on days with relatively normal weather while non-dispatchable power production was not usually low.

Commission Response

The commission declines to adopt TPPA's recommendation to provide use cases, which define times when it is appropriate for ERCOT to dispatch FFSS. The adopted rule strikes the appropriate balance of providing parameters for ERCOT's dispatch of FFSS while also maintaining flexibility for ERCOT to determine in real-time whether dispatch of FFSS is needed to maintain system reliability. Moreover, the commission notes that ERCOT deploys FFSS if: (1) the event is within the FFSS obligation period; (2) there is evidence of an impending or actual fuel supply disruption affecting a FFSS resource; (3) system conditions require a FFSS resource to be manually dispatched online; and (4) ERCOT has issued a Watch for extreme cold weather.

Costs and payments

TPPA recommended modifying the proposed rule to clearly define and distinguish between "standby payments" and "payments." TPPA also recommended clarifying how payments will be calculated and potentially "reduced" or "clawed back" under proposed §25.520(h).

Commission Response

The commission declines to adopt TPPA's recommendation to modify the proposed rule to define "standby payments" and "payments." However, the commission modifies the adopted rule to replace references to "standby payments" with "procurement costs" and adds definitions for "procurement costs" and "non-procurement costs." The commission declines to adopt TPPA's recommendation to clarify how payments will be calculated and potentially "reduced" or "clawed back" because it is unnecessary. The adopted rule requires ERCOT to develop these details in ERCOT protocols, which receive stakeholder input and must be approved by the commission.

Reporting and implementation

Vistra recommended clarifying whether ERCOT intends to formalize the existing RFP process or to establish new, additional requirements for FFSS agreements and performance standards. The performance standards, Vistra claimed, should also include a detailed description of how ERCOT will inspect resource-controlled FFSS and contractual off-site resources. The inspection should extend beyond the generation plant to ensure that the resources and the fuel facilities (off-site storage) are prepared to participate during the FFSS obligation period.

Commission Response

The commission declines to adopt Vistra's recommendation to clarify whether ERCOT intends to formalize the existing RFP process or to establish new, additional requirements for FFSS agreements and performance standards. Whether the existing RFP process or new, additional requirements for FFSS agreements and performance standards will be used should be addressed in the ERCOT protocols, which receive stakeholder input, are approved by the ERCOT Board of Directors, and must be approved by the commission to be implemented. The commission also declines to adopt Vistra's recommendation to modify the proposed rule to include a detailed description of how ERCOT will inspect FFSS resources because these details are more appropriately addressed through the ERCOT protocols, which receive stakeholder input, are approved by the ERCOT Board of Directors, and must be approved by the commission to be implemented.

Proposed §25.520(a) -- Purpose

Proposed §25.520(a) states the purpose of the proposed rule is to promote reliability through the procurement of FFSS for deployment during the winter season.

Vistra recommended modifying proposed §25.520(a) to state that the purpose is to promote reliability through the procurement of FFSS to maintain system reliability during a natural gas curtailment or other fuel supply disruption during the winter season.

Commission Response

The commission substantively adopts Vistra's recommendation to modify adopted §25.520(a) to state that the purpose is to promote reliability through the procurement of FFSS to maintain system reliability during a natural gas curtailment or other fuel supply disruption during the winter season. The commission modifies adopted §25.520(a)to state the purpose is to promote reliability through the procurement of FFSS for deployment during, or in preparation for, a natural gas curtailment or other fuel supply disruption during extreme cold weather conditions.

Proposed §25.520(b)(1) -- Definition for FFSS obligation period

Proposed §25.520(b)(1) defines an FFSS obligation period as a period that coincides with the winter season for which a resource is obligated to provide FFSS.

ERCOT recommended modifying proposed §25.520(b)(1) by adding "procured" in front of "resource" to clarify which resource is so obligated.

Vistra recommended modifying proposed §25.520(b)(1) to define an FFSS obligation period as a period that overlaps with the winter season for which a resource is obligated to provide FFSS, ranging from December 1 through February 28. Vistra reasoned that this would align the FFSS obligation period with the winter season for the commission's emergency preparedness rule and would allow additional opportunities for both resource-controlled FFSS and contractual off-site FFSS resources to complete (or start) critical outages and repairs to ensure reliability of the units. Currently. ERCOT Nodal Protocols Section 3.14.4.3(3) prohibits an FFSS resource from scheduling or requesting a Planned Outage that would occur between December 1 to March 1. However, an FFSS resource remains prohibited from taking a maintenance outage, including a scenario where a transmission outage nearby results in a resource outage.

Commission Response

The commission adopts ERCOT's recommendation to modify adopted §25.520(b)(1) by adding "procured" in front of "resource" to clarify which resource is so obligated. The commission declines to adopt Vistra's recommendation to modify adopted §25.520(b)(2) to overlap with the winter season for which a resource is obligated to provide FFSS, ranging from December 1 through February 28 because outlier events can occur within the tails of the current November 15 through March 15 FFSS obligation period.

Proposed §25.520(b)(4) -- Definition for offer cap

Proposed §25.520(b)(4) defines an offer cap as the maximum dollar amount per megawatt (MW) that a QSE representing a resource may offer into the FFSS program.

ERCOT recommended modifying proposed §25.520(b)(4) to clarify that the offer cap is specific to the resource category established under proposed §25.520(c) by adding "for that category of resource" to the end of the sentence.

Commission Response

The commission agrees with ERCOT's recommendation to modify adopted §25.520(b)(4) to clarify that the offer cap is specific to the resource category established under adopted §25.520(c). Accordingly, the commission adds "for that FFSS category" to the end of the sentence.

Proposed §25.520(b)(5) -- Definition for winter season

Proposed §25.520(b)(5) defines a winter season as November 15 through March 15.

Vistra recommended striking the definition for winter season and replacing references to winter season in the proposed rule with "FFSS obligation period" to streamline the proposed rule.

Commission Response

The commission adopts Vistra's recommendation to modify adopted §25.520(b) by removing the definition for winter season and replacing references to winter season with "FFSS obligation period" to streamline the adopted rule. The commission also makes conforming changes to adopted §25.520(b)(1), which defines an FFSS obligation period, to state that an FFSS obligation period includes the period from November 15 through March 15.

Proposed §25.520(c) -- Resource requirements for FFSS eligibility

Proposed §25.520(c) states that a resource is eligible to be selected by ERCOT in the procurement process to provide FFSS if: (1) has dual fuel capability, the ability to establish and burn an alternative on-site stored fuel, and has on-site fuel storage capability; (2) the resource has on-site natural gas or fuel oil storage capability or off-site natural gas storage where the resource or QSE owns and controls the natural gas storage and pipeline to deliver the required amount of reserve natural gas to the resource from the storage facility; or (3) has a transportation contract with a natural gas pipeline that is a critical natural gas facility, as defined in §25.52 (relating to Reliability and Continuity of Service), and: (A) is subject to the Federal Energy Regulatory Commission's (FERC) jurisdiction; (B) is an intrastate natural gas pipeline that is not operated by a gas utility; or (C) is an intrastate pipeline that is owned or operated by a gas utility that meets certain additional criteria..

Vistra recommended modifying proposed §25.520(c) to more clearly distinguish between different types of resources that are eligible to provide FFSS by creating a category for resource-controlled FFSS and a category for contractual off-site FFSS.

ERCOT recommended modifying §25.520(c)(2) by inserting "transportation" in front of pipeline for clarity.

ERCOT recommended modifying proposed §25.520(c)(3) to add language that requires a resource contracting for transportation also contract for fuel storage. Additionally, ERCOT recommended modifying proposed §25.520(c)(3) to incorporate language from the definition of "Firm Gas Storage Agreement" under ERCOT Protocol §2.1.

Commission Response

The commission adopts Vistra's recommendation to modify adopted §25.520(c) to more clearly distinguish between different types of resources that are eligible to provide FFSS but declines to consolidate the resources in adopted §25.520(c)(1) and (2) into a single category. Instead, the commission labels the three separate categories on-site FFSS, resource-controlled FFSS, and contractual off-site FFSS to more clearly distinguish between the different types of resources that are eligible to provide FFSS. The commission declines to adopt ERCOT's recommendation to modify adopted §25.520(c)(1)(B) to include "transportation" in front of pipeline because it is unnecessary. The commission adopts ERCOT's recommendation to modify adopted §25.520(c)(2) to require an FFSS resource that contracts for transportation of natural gas to also contract for storage of that natural gas. The commission also adds a definition for firm gas storage agreement.

Proposed §25.520(d) -- Budget for standby payments

Proposed §25.520(d)(1) establishes a maximum budget of $54 million in standby payments for ERCOT to procure FFSS during a single winter season and lists circumstances in which ERCOT may reject an offer that a QSE submits on behalf of a resource. Proposed §25.520(d)(2) requires that at least 70% of the $54 million budget be used for procurement costs allocated to eligible resources described in proposed §25.520(c)(1) and (2).

LCRA and NRG recommended modifying proposed §25.520(d)(1) to increase the overall budget of $54 million. NRG recommended increasing the overall budget to $65 million to provide room for future changes in fuel prices. LCRA recommended increasing the overall budget to $70 million and modifying proposed §25.520(d)(2) to reserve $54 million of the overall budget for resources that currently participate in the FFSS program and reserving $16 million of the increased budget for the new category of resources introduced by the proposed rule.

LCRA reasoned that physical fuel security under extreme weather and bulk fuel system shortages requires resource owners to invest in infrastructure above and beyond normal operations. The costs associated with maintaining dual-fuel capabilities or off-site natural gas storage have not decreased since Winter Storm Uri. Weakening the only in-market investment signal to maintain or expand these attributes diminishes the likelihood of new market entrants improving fuel security for the region.

NRG recommended modifying proposed §25.520(d)(2) to include a transition mechanism where the budget allocation for resources described in proposed §25.520(c)(1) and (2) decreases from 70% to 50% after three winter seasons. NRG noted that while dual-fuel resources have been the primary source of FFSS since the program's inception and have historically been a standard technology for fuel resiliency in power generation, the proliferation of natural gas production and availability has significantly increased the potential to expand off-site gas storage and firm transport capability to generation resources in ERCOT.

Vistra recommended modifying proposed §25.520(d)(1) to remove the reference to a specific budget amount and replace it with authority for ERCOT to set a maximum budget. Vistra reasoned that this approach would provide the commission with flexibility during major fuel-supply shocks, such as that experienced in 2022 when events between Russia and the Ukraine resulted in an 85% increase to the produce price index for natural gas.

Vistra also recommended modifying proposed §25.520(d)(2) to increase the amount of the budget allocated to resource-controlled FFSS from 70% to 75%.

Potomac recommended replacing the $54 million budget with a dynamic budget. Potomac reasoned that PURA §39.159(b)(2) requires the commission and ERCOT to evaluate, on annual basis, the quantity of reliability services that ERCOT should procure, including FFSS. Therefore, the annual budget for the FFSS program should be based on risk criteria used to evaluate the grid's preparedness for winter events.

TEC recommended modifying proposed §25.520(d)(1)(B) to clearly identify whether ERCOT may reject an offer because the offer does not meet the requirements for an acceptable FFSS offer or because the offer is an outlier as compared to other acceptable offers submitted.

Commission Response

The commission declines to adopt LCRA and NRG's recommendation to increase the overall budget to procure FFSS. Increasing the budget is likely to magnify the concern that resources have consistently cleared at the offer cap during the last two years. The commission declines to adopt NRG's recommendation to modify adopted §25.520(d)(2) to include a transition mechanism where the budget allocation for resources described in adopted §25.520(c)(1) and (2) decreases from 70% to 50% after three winter seasons. The commission may reevaluate the budget allocation in the future but is not persuaded at this time that a different allocation is justified three years from now. The commission declines to adopt Vistra's recommendation to give ERCOT unilateral discretion to set the budget because such policy decisions should remain within the purview of the commission.

While the commission agrees that FFSS procurement should be for a target quantity based on reliability criteria, the commission declines to adopt Potomac's recommendation to implement a dynamic budget based on risk criteria. Adopted §25.520(d)(1) establishes a maximum budget for each FFSS obligation period but does not require that the full amount be spent in every period. ERCOT is best positioned to evaluate the appropriate target quantity (and corresponding budget necessary to procure this amount) in each FFSS obligation period.

The commission declines to adopt TEC's recommendation to modify adopted §25.520(d)(1)(B) to clearly identify whether ERCOT may reject an offer because the offer does not meet the requirements for an acceptable FFSS offer or because the offer is an outlier as compared to other acceptable offers submitted because it is unnecessary. The adopted rule permits ERCOT to reject an offer for either of those reasons.

Proposed §25.520(e) -- Offer cap

Proposed §25.520(e) establishes how an offer cap is calculated.

ERCOT recommended modifying proposed §25.520(e) to more explicitly recognize that there will be three offer caps, one for each of the resource categories established in proposed §25.520(c).

LCRA recommended clarifying the heat rate and offer cap calculations to maximize transparency and regulatory certainty because proposed §25.520(e)(3) could be interpreted to require a unique heat rate (and therefore a unique offer cap) for each resource based upon that resource's "specific characteristics."

NRG recommended modifying proposed §25.520(e)(1)-(3) to use a heat rate in the calculation of the offer cap that is above the average heat rate of the ERCOT gas fleet of generation at a minimum of 12 MMBtu/MWh and apply a 3X multiplier to the projected cost of natural gas. NRG reasoned that the costs of providing FFSS for a resource described in proposed §25.520(c)(3) encompasses more than just the purchase of fuel. Resources utilizing off-site storage facilities with firm transport from natural gas suppliers must pay storage facility reservation fees and firm delivery charges, which are comparable to the cost of the fuel in storage over the course of a winter.

TPPA recommended modifying proposed §25.520(e) to clarify that QSEs submitting offers on behalf of resources may not exceed the offer cap, and that each offer cap will be administratively set by ERCOT in advance of an FFSS procurement period.

TPPA also recommended modifying proposed §25.520(e)(3) and proposed §25.520(i) to clarify the distinction between "category" and "type."

Vistra recommended modifying proposed §25.520(e) to use a six-month lookback period to determine the amount at which fuel oil is trading for the winter season and to clarify that a separate heat rate will be established for resource-controlled FFSS and contractual off-site FFSS.

Commission Response

The commission adopts ERCOT's recommendation to modify adopted §25.520(e) to more explicitly recognize that there will be three offer caps, one for each of the resource categories established in proposed §25.520(c). The commission adopts LCRA's recommendation to modify adopted §25.520(e)(3) to more clearly articulate that a single heat rate must be used for each category of resources instead of a different heat rate for each resource.

The commission declines to adopt NRG's recommendation to modify proposed §25.520(e)(1)-(3) to use a heat rate in the calculation of the offer cap that is above the average heat rate of the ERCOT gas fleet of generation at a minimum of 12 MMBtu/MWh and apply a 3X multiplier to the projected cost of natural gas. ERCOT currently includes an appropriate fuel adder in its evaluation of the projected price of fuel oil. Therefore, the recommended change is unnecessary.

The commission declines to adopt TPPA's recommendation to modify adopted §25.520(e) to state that QSEs submitting offers on behalf of resources may not exceed the offer cap. Instead, the commission modifies adopted §25.520(d) to state that ERCOT may reject an offer that a QSE submits on behalf of a resource if ERCOT determines that the offer exceeds the applicable offer cap. The commission substantively adopts TPPA's recommendation to modify adopted §25.520(e) to state that each offer cap will be administratively set by ERCOT in advance of an FFSS procurement period and modifies adopted §25.520(e) accordingly. The commission adopts TPPA's recommendation to modify adopted §25.520(i) to clarify that the category of FFSS resources providing FFSS must be reported.

The commission declines to adopt Vistra's recommendation to modify proposed §25.520(e) to use a six-month lookback period to determine the amount at which fuel oil is trading for the winter season because projected fuel prices account for both historical fuel prices and the future state of fuel prices thus yielding a more accurate estimate in this context.

Proposed §25.520(f) -- FFSS program requirements

Proposed §25.520(f) states that in addition to program requirements established by ERCOT, the following requirements apply to the FFSS program: (1) An FFSS resource must be represented by a QSE; (2) ERCOT must establish qualification for a QSE to represent an FFSS resource; (3) ERCOT must establish performance criteria for an FFSS resource and a QSE representing an FFSS resource; (4) An FFSS resource's offer must be submitted to ERCOT through a QSE representing the FFSS resource; (5) ERCOT may deploy FFSS as necessary throughout the FFSS obligation period; (6) when deployed by ERCOT, an FFSS resource must deploy consistent with its obligations; (7) ERCOT may limit the restocking of fuel to manage the overall cost of the service or for reliability needs; and (8) ERCOT must establish procedures for testing an FFSS resource.

ERCOT recommended modifying proposed §25.520(f) to add "at least the following requirements apply to the FFSS program" and to delete the specific requirements delineated in proposed §25.520(f)(1)-(4). ERCOT reasoned that the additional language would maintain flexibility for ERCOT and stakeholders to propose additional, more granular requirements for the FFSS program in the ERCOT Protocols and Other Binding Documents as necessary without the potentially circular reference to existing ERCOT requirements. With respect to proposed §25.520(f)(1)-(4), ERCOT reasoned that all resources that participate in the ERCOT market must be represented by QSEs and the necessity of that relationship and related aspects, such as QSE qualification, are sufficiently established by the current overarching regulatory framework.

TEC recommended modifying proposed §25.520(f)(8) to add "in consultation with a resource owner" to the end of the sentence. TEC reasoned that this addition ensures coordination between ERCOT and resource owners regarding vital testing procedures.

TPPA recommended modifying proposed §25.520(f)(6) to remove the statement in proposed §25.520(f)(6)(B) that an FFSS resource must stay deployed until "the fuel supply disruption no longer exists" because it is unclear when this provision would be met and that proposed §25.520(f)(6)(C) would not also be met.

Commission Response

The commission adopts ERCOT's recommendations to modify adopted §25.520(f) in part. The commission modifies adopted §25.520(f) to clarify that the listed requirements are minimum requirements. The commission declines to adopt ERCOT's recommendation to delete the specific requirements delineated in adopted §25.520(f)(1)-(4). Although the requirements specified in adopted §25.520(f)(1)-(4) are already established by the current overarching regulatory framework, the commission determines that the identification of those specific requirements in the adopted rule provides additional clarity and transparency for stakeholders and the public. The commission declines to adopt TEC's recommendation to modify adopted §25.520(f)(8) to include "in consultation with a resource owner" at the end of the sentence. Instead, the commission modifies adopted §25.520(f)(8) to require ERCOT to develop protocols to establish procedures for testing FFSS resources so that stakeholders have an opportunity to provide input and to ensure that any testing procedures involve the resource owner, as appropriate. The commission declines to adopt TPPA's recommendation to modify adopted §25.520(f)(6) to remove the statement that an FFSS resource must stay deployed until the "fuel supply disruption no longer exists" because the statement makes transparent the commission's FFSS policy intention.

Proposed §25.520(g) -- FFSS payment and charges

Proposed §25.520(g) requires ERCOT to (1) make a payment to each QSE representing an FFSS resource based on a market clearing price mechanism, subject to modifications determined by ERCOT based on the FFSS resource's availability during an FFSS obligation period and the FFSS resource's performance in a deployment event; and (2) charge each load serving entity (LSE) for FFSS procurement costs based upon the LSE's load ratio share during the relevant FFSS obligation period. Additionally, proposed §25.520(g)(3) states that non-procurement costs may be charged to an LSE based on the LSE's load ratio share during the FFSS resource's deployment.

LCRA recommended modifying proposed §25.520(g) to more clearly formalize a single clearing price for physical FFSSRs (described in proposed §25.520(c)(1) and (2)) and a single clearing price for contractual FFSSRs (described in proposed §25.520(c)(3)).

TPPA recommended clarifying the purpose of proposed §25.520(g)(3) and why these charges would be allocated based on FFSS resource deployments rather than obligation periods.

Commission Response

The commission adopts LCRA's recommendation to modify adopted §25.520(g) to more clearly formalize a single clearing price for resources that are eligible to provide resource-controlled FFSS under adopted §25.520(c)(1) and a single clearing price for resources that are eligible to provide contractual off-site FFSS under adopted §25.520(c)(2). The commission modifies adopted §25.520(g) accordingly.

The commission declines to adopt TPPA's recommendation to state the purpose of proposed §25.520(g)(3) and why these charges would be allocated based on FFSS deployments rather than obligation periods. However, the commission adds definitions for procurement costs and non-procurement costs, which serves to provide the clarity that TPPA seeks.

Proposed §25.520(h) -- Compliance

Proposed §25.520(h) requires ERCOT to (1) establish criteria to reduce a QSE's payment, claw back a QSE's payment, suspend a QSE from participation for failure to meet its FFSS obligation; (2) establish criteria to suspend an FFSS resource based on noncompliance; (3) notify the commission of all alleged instances of noncompliance; and (4) maintain records relating to any alleged noncompliance.

OPUC recommended modifying proposed §25.520(h) to incorporate stronger monetary penalties or a suspension for at least three years in the proposed rule. OPUC reasoned that there are instances where a FFSS resource could receive payment for FFSS without providing the called upon reliability service. As such, the current claw back system does not incentivize supply resources to provide reliable FFSS.

TEC recommended modifying proposed §25.520(h) to remove reference to "or a related ERCOT protocol." TEC reasoned that compliance, and associated repercussions should be related to the service being offered. If a resource has met its obligations and performed as needed for FFSS, they should not be punished for failures under another protocol. Rather, that punishment should relate specifically to the violated protocol. For example, if a resource participates in both the ERCOT Contingency Reserve Service (ECRS) and FFSS, and the resource fails to meet its ECRS obligation but does perform under FFSS, the resource should face compliance penalties related to ECRS, not FFSS. The resource may have unique characteristics that allow it to perform better under one service versus another. To bar a resource from participation altogether may inadvertently reduce the pool of eligible dispatchable resources entirely.

Commission Response

The commission declines to adopt OPUC's recommendation to modify adopted §25.520(h) to incorporate stronger monetary penalties or a suspension of at least three years because it is unnecessary. The adopted rule mirrors the commission's usual compliance-focused approach as it relates to underperforming resources by first, enabling ERCOT to reduce or claw back payments made; second, enabling ERCOT to suspend a resource from future participation in the FFSS program; and third, relying on its own authority to seek enforcement for violations of its rules or ERCOT protocols. Furthermore, the commission finds it is appropriate for the ERCOT stakeholder community to establish the specific claw back and suspension provisions for the FFSS program, both of which will be subject to the commission's future review once protocol language is developed.

The commission declines to adopt TEC's recommendation to modify adopted §25.520(h) to remove references to "or a related ERCOT protocol" because the change is unnecessary. A related ERCOT protocol would necessarily have to be one that is related to FFSS.

In adopting this section, the commission makes other minor modifications for the purpose of clarifying its intent.

This section is adopted under the following provisions of Public Utility Regulatory Act (PURA): §39.151, which grants the commission authority to oversee ERCOT; and §39.159, which requires the commission to ensure that ERCOT procures ancillary or reliability services on a competitive basis to increase reliability during extreme code weather conditions and during times of low non-dispatchable power produced in the ERCOT region.

Cross Reference to Statutes: PURA §39.151 and §39.159.

§25.520. Firm Fuel Supply Service (FFSS).

(a) Purpose. The purpose of this section is to promote reliability through the procurement of FFSS for deployment during, or in preparation for, a natural gas curtailment or other fuel supply disruption during extreme cold weather conditions.

(b) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise:

(1) Firm gas storage agreement--An agreement for firm off-site storage of natural gas, as the term is defined in ERCOT protocols.

(2) Firm transportation agreement--An agreement for firm transportation of natural gas to a resource from an off-site storage facility, as the term is defined in ERCOT protocols.

(3) FFSS obligation period--The period from November 15 through March 15 for which a procured resource is obligated to provide FFSS.

(4) FFSS resource--A generation resource that ERCOT procures for FFSS.

(5) Market clearing price--The dollar amount per megawatt (MW) that is awarded for an FFSS resource that ERCOT procures for an FFSS obligation period.

(6) Non-procurement costs--The fuel restocking payments to FFSS resources following a deployment during the FFSS obligation period.

(7) Offer cap--The maximum dollar amount per MW that a qualified scheduling entity (QSE) representing a resource may offer into the FFSS program for the applicable FFSS category.

(8) Procurement costs--The standby payments to FFSS resources for an FFSS obligation period.

(c) Resource requirements for FFSS eligibility. A resource that meets the requirements for one of the three FFSS categories under this subsection is eligible and may be selected by ERCOT in the procurement process to provide FFSS for an FFSS obligation period.

(1) On-site FFSS category. An FFSS resource that provides on-site FFSS must successfully demonstrate dual fuel capability, have the ability to establish and burn an alternative on-site stored fuel, and have on-site fuel storage capability.

(2) Resource-controlled FFSS category. An FFSS resource that provides resource-controlled FFSS must have an on-site natural gas or fuel oil storage capability or off-site natural gas storage where the resource or QSE owns and controls both the natural gas storage facility and the pipeline to deliver the required amount of reserved natural gas to the resource from the storage facility.

(3) Contractual off-site FFSS category. An FFSS resource that provides contractual off-site FFSS must have a firm gas storage agreement with a storage provider for firm storage of the natural gas at the storage facility and have a firm transportation agreement with a natural gas pipeline that is a critical natural gas facility, as defined in §25.52 of this title (relating to Reliability and Continuity of Service) for firm transportation of the natural gas from the storage facility to the FFSS resource. The natural gas pipeline providing firm transportation of the natural gas from the storage facility to the FFSS resource must be:

(A) subject to the jurisdiction of the Federal Energy Regulatory Commission under the Natural Gas Act (15 U.S.C. §717 et seq);

(B) an intrastate natural gas pipeline that is not operated by a gas utility, as defined in Title 3 of the Texas Utilities Code; or

(C) an intrastate natural gas pipeline that is owned or operated by a gas utility, as defined in Title 3 of the Texas Utilities Code. An intrastate natural gas pipeline that is owned or operated by a gas utility must:

(i) provide only transmission service in accordance with its gas utility tariff;

(ii) certify that, if the gas utility reduces firm deliveries to customers pursuant to §7.455 of this title (relating to Curtailment Standards), the intrastate pipeline will have sufficient operational capacity, including sufficient pipeline pressure, to provide the volume of gas required for the transportation path between the storage facility and FFSS resource to provide continuous service in the event of a curtailment; and

(iii) certify that the pipeline has not curtailed deliveries of gas, under §7.455 of this title or an order issued by the Railroad Commission of Texas, to a resource that was subject to a firm transportation agreement during a curtailment event that occurred after January 1, 2021.

(d) FFSS procurement. ERCOT must procure FFSS ahead of each FFSS obligation period to help maintain reliability during, or in preparation for, a natural gas curtailment or other fuel supply disruption.

(1) ERCOT may spend a maximum of $54 million in procurement costs during a single FFSS obligation period. ERCOT may reject an offer that a QSE submits on behalf of a resource if ERCOT determines that:

(A) the offer is unreasonable;

(B) the offer is an outlier when evaluating the parameters of an acceptable offer;

(D) ERCOT lacks a sufficient basis to verify whether the resource complied with ERCOT established performance standards in an event in which the resource was deployed by ERCOT during the preceding FFSS obligation period;

(E) the QSE representing the resource fails to reserve sufficient fuel for the first deployment for the FFSS obligation period; or

(F) the QSE representing the resource fails to reserve sufficient emissions allowances or credits to meet at least three deployments for the FFSS obligation period.

(2) ERCOT must allocate a combined amount of at least 70% of the $54 million budget to procure resources under the on-site FFSS category and the resource-controlled FFSS category, unless insufficient offers were submitted for resources under those categories. If insufficient offers were submitted for resources under the on-site FFSS category and the resource-controlled FFSS category to allocate 70% of the budget to those resources, then ERCOT may reallocate the remainder of that portion of the budget to resources under the contractual off-site FFSS category.

(e) Offer caps. Before the start of an FFSS obligation period, ERCOT must administratively set the offer cap for each category of eligible resources. The offer cap must be calculated as a function of maximum hours per deployment (hours), heat rate (MMBtu/MWh), and fuel price ($/MMBtu), using the following equation: Offer cap ($/MW) = hours * heat rate * fuel price

(1) The fuel price for resources eligible to provide FFSS under the on-site FFSS category and the resource-controlled FFSS category must be based on the projected price of fuel oil for the upcoming FFSS obligation period.

(2) The fuel price for resources eligible to provide FFSS under the contractual off-site FFSS category must be based on the projected price of natural gas for the upcoming FFSS obligation period.

(3) ERCOT must establish a heat rate for each of the three categories of resources that are eligible to provide FFSS under subsection (c) of this section. The heat rate for each category must be based on the characteristics of the resources that are eligible to provide FFSS under that category.

(f) FFSS program requirements. The following minimum requirements apply to the FFSS program.

(1) An FFSS resource must be represented by a QSE.

(2) ERCOT must establish qualifications for a QSE to represent an FFSS resource.

(3) ERCOT must establish performance criteria for an FFSS resource and a QSE representing an FFSS resource.

(4) An FFSS resource's offer must be submitted to ERCOT through a QSE representing the FFSS resource.

(5) ERCOT may deploy FFSS as necessary throughout the FFSS obligation period.

(6) When deployed by ERCOT, an FFSS resource must deploy consistent with its obligations and must remain deployed until the earlier of:

(A) exhaustion of the fuel reserved to generate at the MW level and for the specified duration associated with the FFSS award, including any fuel that was restocked following approval or instruction by ERCOT;

(B) the fuel supply disruption no longer exists; or

(7) ERCOT may limit the restocking of fuel to manage the overall cost of the service or for reliability needs.

(8) ERCOT must develop protocols to establish procedures for testing FFSS resources.

(g) FFSS payment and charges.

(1) ERCOT must establish a single market clearing price mechanism for resources eligible to provide FFSS under the on-site FFSS category and the resource-controlled FFSS category. ERCOT must establish a separate market clearing price mechanism for resources eligible to provide FFSS under the contractual off-site FFSS category.

(2) ERCOT must make a payment to each QSE representing an FFSS resource based on the appropriate market clearing price mechanism, subject to modifications determined by ERCOT based on the FFSS resource's availability during an FFSS obligation period and the FFSS resource's performance in a deployment event.

(3) ERCOT must charge each load serving entity (LSE) for FFSS procurement costs based upon the LSE's load ratio share during the relevant FFSS obligation period.

(4) Non-procurement costs may be charged to an LSE based on the LSE's load ratio share during the FFSS resource's deployment.

(h) Compliance.

(1) ERCOT must establish criteria to reduce a QSE's payment, claw back a QSE's payment, suspend a QSE from participation in FFSS, or any combination thereof, based on the QSE's failure to meet its FFSS obligation under this section or a related ERCOT protocol. ERCOT must also establish criteria for subsequent reinstatement.

(2) ERCOT must establish criteria to suspend an FFSS resource based on noncompliance with this section or a related ERCOT protocol. ERCOT must also establish criteria for subsequent reinstatement.

(3) ERCOT must notify the commission of all alleged instances of noncompliance with this section or a related ERCOT protocol.

(4) ERCOT must maintain records relating to any alleged noncompliance with this section or a related ERCOT protocol.

(i) Reporting. Prior to the start of each FFSS obligation period, ERCOT must publicly report the number and category of FFSS resources providing the service, the market clearing prices, the amount of reserved fuel associated with each FFSS award, the highest and lowest offers, the number of MW associated with each FFSS award, and the projected total cost to procure FFSS for that obligation period.

(j) Implementation. ERCOT must develop, in consultation with commission staff, additional procedures, guides, technical requirements, protocols, or other standards that are consistent with this section and that ERCOT finds necessary to implement FFSS, including development of a standard FFSS agreement and specific performance guidelines.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on February 5, 2026.

TRD-202600528

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: February 25, 2026

Proposal publication date: November 7, 2025

For further information, please call: (512) 936-7433