TITLE 16. ECONOMIC REGULATION

PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

SUBCHAPTER C. INFRASTRUCTURE AND RELIABILITY

The Public Utility Commission of Texas (commission) proposes new 16 Texas Administrative Code (TAC) §25.58, relating to Contracts for Electric Energy Storage, to implement Public Utility Regulatory Act (PURA) §35.153, as enacted by Senate Bill 415 during the 87th Regular Texas Legislative Session. The proposed rule would establish an avenue for transmission and distribution utilities (TDUs) to contract with power generation companies (PGCs) for electric energy storage facility (EESF) capacity to ensure reliable service to distribution customers.

Growth Impact Statement

The agency provides the following governmental growth impact statement for the proposed rule, as required by Texas Government Code §2001.0221. The agency has determined that for each year of the first five years that the proposed rule is in effect, the following statements will apply:

(1) the proposed rule will not create a government program and will not eliminate a government program;

(2) implementation of the proposed rule will not require the creation of new employee positions and will not require the elimination of existing employee positions;

(3) implementation of the proposed rule will not require an increase and will not require a decrease in future legislative appropriations to the agency;

(4) the proposed rule will not require an increase and will not require a decrease in fees paid to the agency;

(5) the proposed rule will create a new regulation;

(6) the proposed rule will not expand, limit, or repeal an existing regulation;

(7) the proposed rule will not change the number of individuals subject to the rule's applicability; and

(8) the proposed rule will not affect this state's economy.

Fiscal Impact on Small and Micro-Businesses and Rural Communities

There is no adverse economic effect anticipated for small businesses, micro-businesses, or rural communities as a result of implementing the proposed rule. Accordingly, no economic impact statement or regulatory flexibility analysis is required under Texas Government Code §2006.002(c).

Takings Impact Analysis

The commission has determined that the proposed rule will not be a taking of private property as defined in chapter 2007 of the Texas Government Code.

Fiscal Impact on State and Local Government

Zachary Dollar, Power Markets Analyst, Market Analysis Division, has determined that for the first five-year period the proposed rule is in effect, there will be no fiscal implications for the state or for units of local government under Texas Government Code §2001.024(a)(4) as a result of enforcing or administering the sections.

Public Benefits

Mr. Dollar has determined that for each year of the first five years the proposed section is in effect the public benefit anticipated as a result of enforcing the section will be providing greater reliability of electric service to the distribution customers of TDUs operating in the ERCOT region. There will be no probable economic cost to persons required to comply with the rule under Texas Government Code §2001.024(a)(5).

Local Employment Impact Statement

For each year of the first five years the proposed section is in effect, there should be no effect on a local economy; therefore, no local employment impact statement is required under Texas Government Code §2001.022.

Costs to Regulated Persons

Texas Government Code §2001.0045(b) does not apply to this rulemaking because the commission is expressly excluded under subsection §2001.0045(c)(7).

Public Hearing

The commission staff will conduct a public hearing on this rulemaking if requested in accordance with Texas Government Code §2001.029. The request for a public hearing must be received by May 18, 2026. If a request for public hearing is received, commission staff will file in this project a notice of hearing.

Public Comments

Interested persons may file comments electronically through the interchange on the commission's website. Comments must be filed by May 18, 2026. Comments should be organized in a manner consistent with the organization of the proposed rules. The commission invites specific comments regarding the costs associated with, and benefits that will be gained by, implementation of the proposed rule. The commission will consider the costs and benefits in deciding whether to modify the proposed rules on adoption. All comments should refer to Project Number 59523.

To further assist the commission in implementing PURA §35.153, the commission also requests comments on the following issues:

Should a transmission and distribution utility's recovery of costs under these contracts be limited to comprehensive base-rate cases or also be permitted in interim proceedings? If the latter, which interim proceedings are appropriate for recovery of these costs?

Should PURA §35.153(i) be read to require all contracts to satisfy relevant accounting standards for a capital lease or finance lease, or should those criteria only be required if a transmission and distribution utility seeks recovery plus a reasonable return on the payments under the contract?

Each set of comments should include a standalone executive summary as the last page of the filing. This executive summary must be clearly labeled with the submitting entity's name and should include a bulleted list covering each substantive recommendation made in the comments.

Statutory Authority

The new rule is proposed 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 35.153, which authorizes a TDU to, with prior commission approval, contract with a PGC to provide electric energy from an electric energy storage facility to ensure reliable service to distribution customers and directs the commission to adopt rules as necessary to implement the section and establish criteria for approving these contracts.

Cross Reference to Statute: Public Utility Regulatory Act §§14.001; 14.002; and 35.153.

§25.58. Contracts for Electric Energy Storage.

(a) Applicability. This section applies to:

(1) a transmission and distribution utility (TDU) that operates facilities in the Electric Reliability Council of Texas (ERCOT) region to serve distribution customers; and

(2) a power generation company (PGC), as defined under §25.5 of this title (relating to Definitions).

(b) Definition. Electric energy storage facility (EESF)--A piece of equipment or a facility in the ERCOT region that is intended to:

(1) provide energy or ancillary services at wholesale, including an electric energy storage equipment or facility that is listed on a PGC's registration with the commission or, for an exempt wholesale generator, on the generator's registration with the Federal Energy Regulatory Commission; or

(2) provide reliable delivery of electric energy to distribution customers.

(1) The total amount of EESF output capacity reserved by contracts under this section may not exceed 100 megawatts (MWs).

(2) A TDU is allocated a portion of 100 MWs according to its load ratio share on the effective date of this section, as calculated by ERCOT. A TDU may file a petition for the commission to reassess the allocation methodology or update the allocation amount not more than once each year.

(d) Authorization to contract for EESF capacity. A TDU must not enter into, renew, or extend a contract with a PGC for energy and output capacity from an EESF until receiving authorization from the commission under this subsection.

(1) Application. A TDU must file an application to obtain commission authorization.

(A) Contents. The application must include:

(i) If applicable, the TDU's history with EESF, including:

(I) Whether the TDU is currently authorized, or has previously been authorized, by the commission to contract for EESF energy and output capacity, including the details of existing and prior authorizations and each docket number in which the existing and prior authorizations were granted; and

(II) A description of all EESF energy and output capacity the TDU has under contract at the time of the application, including the total energy and output capacity the TDU has under contract, the length of the contract(s), and a description of the contract terms for discharging an EESF's energy capacity.

(ii) The total EESF energy and output capacity the TDU is requesting authorization to contract for and the length of time for which the TDU is requesting authorization. In support of its request, the TDU must include, with any necessary supporting documentation:

(I) Whether the amount of requested EESF energy and output capacity and requested authorization length will ensure reliable service to the TDU's distribution customers;

(II) The location(s) where a need for EESF energy and output capacity exists;

(III) The number of distribution customers, by customer class, that the TDU expects to benefit from a contract for EESF energy and output capacity;

(IV) The conditions in which the TDU would direct a PGC to discharge contracted EESF energy capacity;

(V) A cost-benefit analysis that demonstrates the expected cost savings associated with entering into a contract for EESF energy and output capacity over constructing or modifying a traditional distribution facility; and

(VI) A description of any additional measures being implemented, or scheduled for implementation, that may mitigate the TDU's need for EESF energy and output capacity.

(B) The TDU may provide in its application additional information that it believes will be necessary for the commission's consideration of the TDU's request. Any additional information that the TDU provides must be clearly labeled as supplemental and separate from the information that the TDU is required to provide under subparagraph (A) of this paragraph.

(C) The commission may request additional information from the TDU that it believes is necessary to evaluate the TDU's request.

(D) 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 data.

(2) 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 45 days from the date the application is filed with the commission. The notice must be provided using a reasonable method of notice to:

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

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

(D) the Office of Public Utility Counsel

(3) Commission evaluation and decision.

(A) In reviewing a TDU's application, the commission may consider whether:

(i) the requested amount of EESF energy and output capacity will ensure reliable service to the TDU's distribution customers;

(ii) the requested amount of EESF energy and output capacity exceeds, either by itself or together with existing authorized amounts, the amount allocated to the TDU under subsection (c) of this section; and

(iii) the estimated cost of entering into a contract for the requested amount of EESF energy and output capacity is less than the estimated cost of constructing or modifying a traditional distribution facility.

(B) The commission's final order may:

(i) include the total amount of EESF energy and output capacity the TDU is authorized to contract for;

(ii) include the date the authorization expires; and

(iii) require a contract under this section to comply with Public Utility Regulatory Act (PURA) §35.153.

(e) Contract for EESF capacity. A TDU that has obtained authorization under subsection (d) of this section may enter into one or more contracts with a PGC for EESF energy and output capacity, provided that all contracts comply with the commission's authorization under subsection (d) of this section.

(1) Competitive bidding process.

(A) Prior to entering into a contract under this section, the TDU must conduct a competitive bidding process.

(B) In any proceeding in which the commission is reviewing the reasonableness, necessity, or prudence of the costs associated with a contract, the commission may also consider whether the contract the TDU entered into was reasonable relative to other bids that were available to the TDU, if any.

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

(f) PGC responsibilities. A PGC that owns or operates an EESF subject to a contract under this section:

(1) may offer electric energy or ancillary services from an EESF into the ERCOT wholesale markets, only to the extent that the PGC reserves capacity as required by the contract;

(2) may not discharge energy from an EESF to satisfy the contract's requirements unless directed by the TDU; and

(3) must reimburse the TDU for the cost of an administrative penalty assessed against the TDU for a violation caused by the EESF's failure to meet the contract requirements.

(g) Eligible costs and deferred recovery.

(1) Eligible costs.

(A) Contract costs. Reasonable and necessary costs associated with a contract for EESF capacity, including the present value of future payments required under the contract, are eligible for recovery under this section. A contract for EESF capacity 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.

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

(2) Deferred recovery. A TDU may create a regulatory asset to defer for recovery in a future ratemaking proceeding the return, not otherwise included in any of the TDU's rates.

(h) 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, in 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.

(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 approved rates.

(B) Eligible 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 eligible 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) EESF 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 contract under this section that would reduce the rate of necessary cost recovery, a TDU must submit an application to reflect the reduced rate of necessary cost recovery, by the earlier of three months from the contract amendment or the TDU's next DCRF proceeding.

(F) Eligible 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.

(G) In any proceeding in which eligible costs are reviewed for reasonableness, necessity, or prudence, the TDU's application must also include the contracts associated with the eligible costs being reviewed. The commission will review the contracts to ensure compliance with the final order under subsection (d) of this section, the requirements under subsection (e) of this section, and PURA §35.153.

(2) Notice. The notice for any ratemaking proceeding in which eligible 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 EESF 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 eligible costs, all revenues received associated with EESF programs, including actual rate revenues, must be applied to offset reasonable, necessary, and prudent EESF 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.

(C) As part of the reconciliation of EESF costs, the commission may consider whether the contracted EESF complied with the characteristics required under subsection (d) of this section.

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on April 2, 2026.

TRD-202601459

Katelyn Lewis

Projects Coordinator

Public Utility Commission of Texas

Earliest possible date of adoption: May 17, 2026

For further information, please call: (512) 936-7044

SUBCHAPTER E. CERTIFICATION, LICENSING AND REGISTRATION

16 TAC §25.101

The Public Utility Commission of Texas (commission) proposes amendments to 16 Texas Administrative Code (TAC) §25.101 relating to Certification Criteria. This amendment will implement Public Utility Regulatory Act (PURA) §37.052(c) as revised by House Bill (HB) 3092 during the Texas 89th Regular Legislative Session. The proposed rule will increase the minimum transmission line length that may be constructed without requiring an electric utility to amend its certificate of convenience and necessity, from three miles to five miles when the line connects an existing transmission facility to a load-serving substation or metering point. Additionally, non-substantive clarifying and consistency edits were made to the rule language.

Growth Impact Statement

(1) the proposed rule will not create a government program and will not eliminate a government program;

(2) implementation of the proposed rule will not require the creation of new employee positions and will not require the elimination of existing employee positions;

(3) implementation of the proposed rule will not require an increase and will not require a decrease in future legislative appropriations to the agency;

(4) the proposed rule will not require an increase and will not require a decrease in fees paid to the agency;

(5) the proposed rule will not create a new regulation;

(6) the proposed rule will not expand, limit, or repeal an existing regulation;

(7) the proposed rule will not change the number of individuals subject to the rule's applicability; and

(8) the proposed rule will not affect this state's economy.

Fiscal Impact on Small and Micro-Businesses and Rural Communities

Takings Impact Analysis

The commission has determined that the proposed rule will not be a taking of private property as defined in chapter 2007 of the Texas Government Code.

Fiscal Impact on State and Local Government

Seaver Myers, Project Manager, Rules and Projects, has determined that for the first five-year period the proposed rule is in effect, there will be no fiscal implications for the state or for units of local government under Texas Government Code §2001.024(a)(4) as a result of enforcing or administering the sections.

Public Benefits

Mr. Myers has determined that for each year of the first five years the proposed section is in effect the public benefit anticipated as a result of enforcing the section will be streamlining transmission line construction approval process for certain transmission line construction projects. There will be no probable economic cost to persons required to comply with the rule under Texas Government Code §2001.024(a)(5).

Local Employment Impact Statement

Costs to Regulated Persons

Texas Government Code §2001.0045(b) does not apply to this rulemaking because the commission is expressly excluded under subsection §2001.0045(c)(7).

Public Hearing

The commission staff will conduct a public hearing on this rulemaking if requested in accordance with Texas Government Code §2001.029. The request for a public hearing must be received by May 8, 2026. If a request for public hearing is received, commission staff will file in this project a notice of hearing.

Public Comments

Interested persons may file comments electronically through the interchange on the commission's website or by submitting a paper copy to Central Records, Public Utility Commission of Texas, 1701 North Congress Avenue, P.O. Box 13326, Austin, Texas 78711-3326. Comments must be filed by May 8, 2026. Comments should be organized in a manner consistent with the organization of the proposed rules. The commission invites specific comments regarding the costs associated with, and benefits that will be gained by, implementation of the proposed rule. The commission will consider the costs and benefits in deciding whether to modify the proposed rules on adoption. All comments should refer to Project Number 59528.

Statutory Authority

The amendment is proposed 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 §37.052, which governs exceptions to certificate requirements for service extension.

Cross Reference to Statute: Public Utility Regulatory Act §§14.001; 14.002; and 37.052.

§25.101. Certification Criteria.

(a) - (b) (No change.)

(c) Projects or activities not requiring a certificate. A certificate, or certificate amendment, is not required for the following:

(1) An extension of facilities as described in PURA §37.052(a) and (b);

(2) A new electric high voltage switching station, or substation;

(3) The repair or reconstruction of a transmission facility due to emergencies. The repair or reconstruction of a transmission facility due to emergencies should proceed without delay or prior approval of the commission and must be reported to the commission in accordance with §25.83 of this title (relating to Transmission Construction Reports);

(4) The construction or upgrading of distribution facilities within the electric utility's service area;

(5) Routine activities associated with transmission facilities that are conducted by transmission service providers. Nothing contained in the following subparagraphs should be construed as a limitation of the commission's authority as set forth in PURA. Any activity described in the following subparagraphs must be reported to the commission in accordance with §25.83 of this title (relating to Transmission Construction Reports). The commission may require additional facts or call a public hearing thereon to determine whether a certificate of convenience and necessity is required. Routine activities are defined as follows:

(A) The modification, construction, or extension of a transmission line that connects existing transmission facilities to a substation or metering point provided that:

(i) the transmission line modification, construction, or extension does not exceed:

(I) five [~~three~~] miles if the line connects to a load-serving substation or metering point; or

(II) two miles if the line connects to a generation substation or metering point; and

(ii) all rights-of-way necessary for the modification, construction, or extension have been acquired, and

(iii) all landowners whose property is directly affected by the transmission line, as defined in §22.52(a)(3) of this title (relating to Notice in Licensing Proceedings), have given written consent for the modification, construction, or extension. If the transmission line modification, construction, or extension does not exceed one mile to provide service to a substation or metering point, written consent is only required by landowners whose property is crossed by the transmission line.

(B) The rebuilding, replacement, or respacing of structures along an existing route of the transmission line; upgrading to a higher voltage not greater than 230 kV; bundling of conductors or reconductoring of an existing transmission facility, provided that:

(i) no additional right-of-way is required; or

(ii) if additional right-of-way is required, all landowners of property crossed by the electric facilities have given prior written consent.

(C) The installation, on an existing transmission line, of an additional circuit not previously certificated, provided that:

(i) the additional circuit is not greater than 230 kV; and

(ii) all landowners whose property is crossed by the transmission facilities have given prior written consent.

(D) The relocation of all or part of an existing transmission facility due to a request for relocation, provided that:

(i) the relocation is to be done at the expense of the requesting party; and

(ii) the relocation is solely on a right-of-way provided by the requesting party.

(E) The relocation or alteration of all or part of an existing transmission facility to avoid or eliminate existing or impending encroachments, provided that all landowners of property crossed by the electric facilities have given prior written consent.

(F) The relocation, alteration, or reconstruction of a transmission facility due to the requirements of any federal, state, county, or municipal governmental body or agency for purposes including, but not limited to, highway transportation, airport construction, public safety, or air and water quality, provided that:

(i) all landowners of property crossed by the electric facilities have given prior written consent; and

(ii) the relocation, alteration, or reconstruction is responsive to the governmental request.

(6) Upgrades to an existing transmission line by an MPE that do not require any additional land, right-of-way, easement, or other property not owned by the MOU;

(7) The construction, installation, or extension of a transmission facility by an MPE that is entirely located not more than 10 miles outside of an MOU's certificated service area that occurs before September 1, 2021; or

(8) A transmission facility by an MOU placed in service after September 1, 2015, that is developed to interconnect a new natural gas generation facility to the ERCOT transmission grid and for which, on or before January 1, 2015, an MOU was contractually obligated to purchase at least 190 megawatts of capacity.

(d) - (h) (No change.)

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on April 2, 2026.

TRD-202601460

Katelyn Lewis

Projects Coordinator

Public Utility Commission of Texas

Earliest possible date of adoption: May 17, 2026

For further information, please call: (512) 936-7044

16 TAC §25.107

The Public Utility Commission of Texas (commission) proposes amendments to 16 Texas Administrative Code (TAC) §25.107 relating to Certification and Obligations of Retail Electric Providers (REPs). The commission also proposed amendments to three commission-prescribed forms: (1) the REP Letter of Credit template; (2) the REP Application and Amendment Form; and (3) the REP Reporting Instructions Form.

The amended rule will implement the new electronic filing requirements applicable to REP letters of credit (LoCs) adopted in 2025 under Project 52059 which revised §22.71, relating to Commission Filing Requirements and Procedures, and §22.72, relating to Form Standards for Documents Filed with the Commission in Chapter 22 of the commission's procedural rules. Specifically, §22.71(d)(1)(A) requires a REP with a physical letter of credit on file with the commission as of the effective date of the section to file an original letter of credit electronically on or before March 5, 2027. The amended rule will accordingly detail the specific procedures and requirements for filing REP LoCs electronically with the commission. The amended rule will also revise the definition of "affiliate" to more appropriately conform with the disclosure and financial requirements of §25.107. The amended rule also makes minor clarifying changes to requirements applicable to Option 2 REPs and to the financial documentation requirements of segregated cash accounts and escrow accounts. Amendments to the REP Letter of Credit template include conforming revisions to reflect electronic filing, including the prohibition on amending a LoC without commission approval and the authorization for the commission to present or terminate a LoC by electronic transmission. Amendments to the REP Application and Amendment Form and REP Reporting Instructions Form are conforming changes to reflect the amended rule and LoC requirements, as well as the revised definition of "affiliate."

Growth Impact Statement

(1) the proposed rule will not create a government program and will not eliminate a government program;

(2) implementation of the proposed rule will not require the creation of new employee positions and will not require the elimination of existing employee positions;

(3) implementation of the proposed rule will not require an increase and will not require a decrease in future legislative appropriations to the agency;

(4) the proposed rule will not require an increase and will not require a decrease in fees paid to the agency;

(5) the proposed rule will not create a new regulation;

(6) the proposed rule will expand an existing regulation;

(7) the proposed rule will not change the number of individuals subject to the rule's applicability; and

(8) the proposed rule will not affect this state's economy.

Fiscal Impact on Small and Micro-Businesses and Rural Communities

Takings Impact Analysis

The commission has determined that the proposed rule will not be a taking of private property as defined in chapter 2007 of the Texas Government Code.

Fiscal Impact on State and Local Government

Lucy Considine, Power Markets Analyst, Market Analysis, has determined that for the first five-year period the proposed rule is in effect, there will be no fiscal implications for the state or for units of local government under Texas Government Code §2001.024(a)(4) as a result of enforcing or administering the sections.

Public Benefits

Ms. Considine has determined that for each year of the first five years the proposed section is in effect the public benefit anticipated as a result of enforcing the section will be more efficient processing and handling of REP LoCs and greater clarification on certain REP certification obligations. There will be probable economic costs to persons required to comply with the rule under Texas Government Code §2001.024(a)(5).

Local Employment Impact Statement

Costs to Regulated Persons

Texas Government Code §2001.0045(b) does not apply to this rulemaking because the commission is expressly excluded under subsection §2001.0045(c)(7).

Public Hearing

The commission will conduct a public hearing on this rulemaking if requested in accordance with Texas Government Code §2001.029. The request for a public hearing must be received by May 21, 2026. If a request for public hearing is received, commission staff will file in this project a notice of hearing.

Public Comments

Interested persons may file comments electronically through the interchange on the commission's website. Comments must be filed by May 21, 2026. Comments should be organized in a manner consistent with the organization of the proposed rules. The commission invites specific comments regarding the effects of the proposed rule, including the costs associated with, and benefits that will be gained by, implementation of the proposed rule. The commission also requests any data, research, or analysis from any person required to comply with the proposed rule or any other interested person. The commission will consider the information submitted by commenters and the costs and benefits of implementation in deciding whether to modify the proposed rules on adoption. All comments should refer to Project Number 59288.

In addition to comments on the proposed rule text, the commission requests comments on the following questions concerning the proposed rule and forms. Questions for comment should be interpreted broadly and understood to potentially entail future revision to any underlying rule language. Any provision or concept explored in a question for comment indicates that provision or concept is specifically noticed for consideration and review in the rulemaking. Responses to questions for comment, including draft language provided by commenters, are within the scope of such consideration and review. The inclusion of additional analysis, research, or other relevant information is encouraged when responding to questions for comment.

Should additional means or methods of financial assurance be added and made available to REPs to meet the access to capital requirements under §25.107(f)(1) or customer deposit and prepayment requirements under §25.107(f)(2)? (e.g., surety bonds, insurance, etc.)

Should the financial documentation or verification requirements for segregated cash accounts or escrow accounts under §25.107(f)(4)(D) be modified (i.e., expanded, reduced, clarified, etc.)?

The proposed REP Letter of Credit Template incorporates language from the LoC template used for the Texas Energy Fund (TEF) (See Project 56896, Item #79) and the ERCOT LoC template (See https://www.ercot.com/services/rq/credit).

Should additional language from the TEF or ERCOT LoC templates be added to the REP Letter of Credit Template?

Should any other revisions be made to the REP Letter of Credit Template?

Statutory Authority

The amendment is proposed 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 PURA §39.352, which stipulates the requirements to certify a REP.

Cross Reference to Statute: Public Utility Regulatory Act §§14.001, 14.002, and §39.052.

§25.107. Certification and Obligations of Retail Electric Providers (REPs).

(a) (No change.)

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

(1) Affiliate--means any company that is related by common control with another company. Any company in the immediate corporate family or a company in the direct or indirect chain of corporate ownership up to the ultimate parent company is an affiliate unless the context indicates otherwise. [~~As defined in §25.5 of this title (relating to Definitions).~~]

(2) - (16) (No change.)

(1) - (6) (No change.)

(7) Filing requirements for irrevocable stand-by letters of credit.

(A) To meet the financial requirements under subsection (f) of this section, an irrevocable stand-by letter of credit must be filed electronically with the commission in accordance with §22.71 of this title (relating to Commission Filing Requirements and Procedures).

(B) An irrevocable stand-by letter of credit that does not comply with the filing requirements of §22.71 of this title for REP letters of credit will be rejected and securely and confidentially disposed of in accordance with §22.71 of this title.

(d) Basic requirements.

(1) (No change.)

(2) An applicant must provide the following information to the commission to certify as a REP under this section.

(A) - (H) (No change.)

(I) An applicant for an Option 2 REP certificate must include a signed, notarized affidavit stating that it will only contract with customers to provide one megawatt or more of capacity [~~energy~~]. Within 30 days of conditional commission approval of the application and before an Option 2 REP begins serving a customer, the Option 2 REP must file with the commission a signed, notarized affidavit from each customer with which it has contracted to provide one megawatt or more of capacity [~~energy~~]. The affidavit may be submitted by the applicant while the application for an Option 2 REP certificate is pending. Each customer affidavit must state that the customer understands and accepts the REP's ability to provide continuous and reliable electric service based on the applicant's financial, managerial, and technical resources.

(J) (No change.)

(e) (No change.)

(f) Financial requirements. An Option 1 REP must, on an ongoing basis, maintain compliance with paragraph (1) of this subsection and, as applicable, paragraph (2) and (3) of this subsection. This subsection does not apply to an Option 2 or Option 3 REP.

(1) - (3) (No change.)

(4) Financial documentation requirements. The following must be provided by an applicant to demonstrate compliance with the financial requirements under paragraphs (1), (2), and (3) of this subsection, as applicable. Additionally, the applicant must provide the month and last day of the applicant's reporting fiscal year or, if the applicant has a guarantor, the guarantor's reporting fiscal year. The applicant must also provide a summary of any history of insolvency, bankruptcy, dissolution, merger, or acquisition of the applicant or any predecessors in interest during the 60 calendar months immediately preceding the filing of the application.

(A) Investment-grade credit ratings must be documented by reports from a credit reporting agency. The report the applicant provides must be the most recently released report by the credit reporting agency.

(B) Tangible net worth, current ratio, and debt to capitalization ratio calculations must be supported by a signed, notarized affidavit from an executive officer of the guarantor that attests to the accuracy of the calculations and be documented by audited or unaudited financial statements of the guarantor for the most recently completed quarter.

(i) Audited financial statements must include the independent auditor's report and accompanying notes.

(ii) Unaudited financial statements must include a signed, notarized affidavit, in addition to any other provided affidavits, which attests to the accuracy, in all material respects, of the information provided in the unaudited financial statements.

(iii) Three consecutive months of monthly statements may be submitted in lieu of quarterly statements, if quarterly statements are not available.

(iv) The requirement for financial statements may be satisfied by filing a copy of, or providing an electronic link, to the guarantor's most recent financial statements filed with any agency of the federal government, including the U.S. Securities and Exchange Commission.

(C) Shareholders' equity must be documented by the audited or unaudited financial statements of the applicant for the most recently completed quarter.

(i) Audited financial statements must include the independent auditor's report and accompanying notes.

(iii) Three consecutive months of monthly statements may be submitted in lieu of quarterly statements, if quarterly statements are not available.

(iv) The requirement for financial statements may be satisfied by filing a copy of, or providing an electronic link, to the REP's most recent financial statements filed with any agency of the federal government, including the U.S. Securities and Exchange Commission.

(D) Segregated cash accounts must be documented by a current account statement and the executed agreement with an unaffiliated person that controls the segregated cash account.

(i) The account statement must clearly identify:

(I) the name of the financial institution where the applicant has established the account;

(II) the account number; and

(III) the account name, which must clearly indicate the account is designated for containing only customer deposits, prepayments, or both.

(ii) The account must be maintained at a financial institution that is supervised or examined by the Board of Governors of the Federal Reserve System, the Office of the Comptroller of the Currency, or a state banking department and is a:

(I) U.S. domestic bank; or

(II) a domestic office of a foreign bank with an investment-grade credit rating.

(iii) If applicable, a [A] REP must provide the [an] executed agreement it has with the [a] provider of credit that governs the control and management of the account. The provider of credit must not be affiliated with the applicant or the applicant's corporate parent. [If the segregated cash account contains customer deposits, the agreement must specify that the customer deposits are not the property of the REP or in the REP's control, unless, if allowed by the REP's terms of service, the customer deposits are applied to a final bill or to satisfy unpaid amounts.]

(E) Escrow accounts must be documented by a current account statement and the executed escrow account agreement.

(i) The account statement must clearly identify:

(I) the name of the financial institution where the applicant has established the account;

(II) the account number; and

(III) the account name, which must clearly indicate the account is designated for containing only customer deposits, prepayments, or both.

(I) U.S. domestic bank; or

(II) a domestic office of a foreign bank with an investment-grade credit rating.

(iii) The escrow account agreement must provide that the account holds only customer deposits, prepayments, or both, and that the customer deposits will be held in trust by the escrow agent [~~and will not be the property of the REP or in the REP's control, unless, if allowed by the REP's terms of service, the customer deposits are applied to a final bill or to satisfy unpaid amounts~~].

(F) Except as otherwise provided for amendments or cancellations under clause (v) or (vi) of this subparagraph, respectively, irrevocable [~~Irrevocable~~] stand-by letters of credit provided under paragraphs (1) and (2) of this subsection must use the standard form irrevocable stand-by letter of credit template approved by the commission. The original [~~document of the~~] irrevocable stand-by letter of credit must be filed electronically in accordance with §22.71 of this title [~~provided in a manner established by the commission~~].

(i) The irrevocable stand-by letter of credit must be maintained at a financial institution that is supervised or examined by the Board of Governors of the Federal Reserve System, the Office of the Comptroller of the Currency, or a state banking department and is a:

(I) U.S. domestic bank; or

(II) a domestic office of a foreign bank with an investment-grade credit rating.

(ii) The irrevocable stand-by letter of credit must:

(I) be an original document;

(II) [~~(I)~~] be irrevocable for a period not less than twelve months;

(III) [~~(II)~~] automatically renew, and only expire if prior notice is provided to the commission at least 90 days before the expiration and commission staff signs the notice of non-renewal to acknowledge that the notice was received 90 days before the expiration;

(IV) [~~(III)~~] be payable to the commission;

(V) [~~(IV)~~] permit a draw to be made in part or in full;

(VI) [~~(V)~~] permit a draw to be made with the return of the original document or a photocopy;

(VII) [~~(VI)~~] permit a draw to be made by first class certified and registered mail, overnight mail and electronic mail [~~,among other ways, through over-night mail~~];

(VIII) permit notification and approval of the termination or amendment of the irrevocable stand-by letter of credit to be performed through electronic mail.

(IX) [~~(VII)~~] permit the commission's executive director or the executive director's designee to draw on the irrevocable stand-by letter of credit and terminate the irrevocable stand-by letter of credit; [~~and~~]

(X) [~~(VIII)~~] comply with clause (v) of this subparagraph for amendments to an irrevocable, stand-by letter of credit; and [require commission staff approve all amendment requests to decrease the value of the irrevocable stand-by letter of credit prior the value of the irrevocable stand-by letter of credit decreasing. Amendments to decrease the value of the irrevocable stand-by letter of credit must be accompanied by a notarized affidavit signed by an executive officer of the REP and include, as applicable, the current number of ESI IDs the REP serves, the value of customer deposits and prepayments the REP is liable for.]

(XI) contain a verifiable electronic signature or other means of authentication acceptable to the commission in accordance with clauses (iii) and (iv) of this subparagraph.

(iii) For purposes of an irrevocable stand-by letter of credit, a verifiable electronic signature must include:

(I) a signature from an executive officer of the issuing bank with a digital identifier (e.g. a public-key certificate or self-signed certificate); and

(II) the date the irrevocable stand-by letter of credit was signed.

(iv) An irrevocable stand-by letter of credit without a verifiable electronic signature must include other means of authentication. Other means of authentication must consist of, at a minimum, an affidavit attesting to the authenticity of the irrevocable stand-by letter of credit. If a REP utilizes multiple letters of credit, a single affidavit may be used. The affidavit must:

(I) use the form-prescribed by the commission;

(II) be sworn;

(III) be signed by an executive officer of the REP;

(IV) include the date the affidavit was signed.

(v) An amendment to an irrevocable stand-by letter of credit must comply with this clause.

(I) An amendment to an irrevocable stand-by letter of credit involving an increase to the stated amount or a non-material change to the irrevocable stand-by letter of credit (e.g., address, contact information, etc.) is only effective upon the filing of written confirmation of the change by the issuing financial institution. The written confirmation must be filed in Project 37919 or by any other means prescribed by the commission.

(II) An amendment to an irrevocable stand-by letter of credit involving a request to decrease the value of the irrevocable stand-by letter of credit is only effective upon the execution of a written agreement by the executive director or his or her designee approving the change. Additionally, an amendment to decrease the value of the irrevocable stand-by letter of credit must be accompanied by an affidavit that:

(-a-) is sworn;

(-b-) is signed by an executive officer of the REP;

(-c-) includes the date the affidavit was signed; and

(-d-) includes a written statement indicating, as applicable, either the current number of ESI IDs the REP serves or the value of customer deposits and prepayments the REP is liable for.

(III) In addition to the applicable requirements of subclause (I) or (II) of this clause, as applicable, an amendment to an irrevocable stand-by letter of credit must substantially comply with and conform to the commission-prescribed form for such amendments and must, at a minimum, include:

(-a-) the number or identifier applicable to the irrevocable stand-by letter of credit being amended;

(-b-) the previous effective date of the irrevocable stand-by letter of credit being amended;

(-c-) the name and contact information of the issuing financial institution;

(-d-) the stated amount of the previously effective irrevocable stand-by letter of credit immediately followed by the new amount of the irrevocable stand-by letter of credit;

(-e-) the effective date of the amendment, as applicable under subclause (I) or (II) of this clause;

(-f-) the following language: "All other terms and conditions of the Irrevocable Stand-By Letter of Credit remain unchanged; and

(-g-) the signature of a representative of the issuing financial institution and their corresponding contact information.

(vi) Termination of an irrevocable stand-by letter of credit may be effectuated through one of the following methods under subclause (I) or (II) of this clause.

(I) Cancellation. The cancellation of an irrevocable stand-by letter of credit is effective only upon:

(-a-) the filing of a written statement with the commission that substantially adheres to the commission-prescribed form for cancellations and complies with the requirements of subclause (III) of this clause; and

(-b-) the signature or written approval of the executive director or his or her designee.

(II) Non-renewal. The non-renewal of an irrevocable stand-by letter of credit is effective only upon:

(-a-) the filing of a written statement with the commission, provided at least 90 days prior to the expiry date of the irrevocable stand-by letter of credit that substantially adheres to the commission-prescribed form for non-renewals and complies with the requirements of subclause (III) of this clause; and

(-b-) the signature of the executive director or his or her designee acknowledging the statement of non-renewal.

(III) A statement terminating an irrevocable stand-by letter of credit must, at a minimum, include:

(-a-) the number or identifier of the irrevocable stand-by letter of credit used by the financial institution;

(-b-) the date the irrevocable stand-by letter of credit was effective and the date the written statement was filed;

(-c-) the face value of the irrevocable stand-by letter of credit;

(-d-) the name of the applicant associated with the irrevocable stand-by letter of credit; and

(-e-) as applicable, the expiry date of the irrevocable stand-by letter of credit.

(G) Irrevocable guaranty agreements must be executed on the commission approved standard form irrevocable guaranty agreement and must obligate the guarantor to meet commission's demands on behalf of the applicant. A copy of the executed irrevocable guaranty agreement must be provided in the manner established by the commission.

(i) The guarantor's obligation to satisfy a commission demand for payment must be in an amount not less than $1,500,000 and must be absolute, and the guarantor may not avoid its obligation for any reason.

(ii) The irrevocable guaranty agreement must automatically renew and only expire if prior notice is provided to the commission at least 90 days before expiration. Commission staff must sign a notice of non-renewal to acknowledge that the notice was received at least 90 days prior to the date of expiration. Any notices or amendments must be provided to the commission in a commission approved method. Until the 90 days' [~~days~~] advance notice has elapsed or until an amendment to the REP's financial qualifications is approved, whichever occurs first, the guarantor must remain completely and absolutely liable to the extent provided by the terms of the agreement.

(H) A power purchase agreement must be documented by providing a copy of the executed agreement between the applicant and the guarantor.

(5) - (6) (No change.)

(g) - (l) (No change.)

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on April 2, 2026.

TRD-202601458

Katelyn Lewis

Projects Coordinator

Public Utility Commission of Texas

Earliest possible date of adoption: May 17, 2026

For further information, please call: (512) 936-7044