TITLE 16. ECONOMIC REGULATION

PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 24. SUBSTANTIVE RULES APPLICABLE TO WATER AND SEWER SERVICE PROVIDERS

The Public Utility Commission of Texas (commission) adopts amended 16 Texas Administrative Code (TAC) §24.101, relating to Appeal of Rate-making Decision, Pursuant to the Texas Water Code §13.043; §24.239, relating to Sale, Transfer, Merger, Consolidation, Acquisition, Lease, or Rental; §24.240, relating to Water and Sewer Utility Rates After Acquisition; §24.243, relating to Purchase of Voting Stock or Acquisition of a Controlling Interest in a Utility; §24.357, relating to Operation of a Utility by a Temporary Manager; and §24.363, Temporary Rates for Services Provided for a Nonfunctioning System. The commission adopts these rules with changes to the proposed text as published in the September 5, 2025 issue of the Texas Register (50 TexReg 5824). The rules will be republished.

The amended rules will implement the expedited Sale, Transfer, Merger (STM) proceeding detailed under Texas Water Code §13.301 as revised by Senate Bill (SB) 1965 from the 88th Regular Session and SB 740 from the 89th Regular Session of the Texas Legislature. The amended rules will also implement Texas Water Code §§13.002, 13.412, 13.4132 as revised by SB 740 and new Texas Water Code §13.3021 as enacted by SB 740.

The commission received comments on the proposed rule from the Office of Public Utility Counsel (OPUC) and the Texas Association of Water Companies, Inc. (TAWC).

Clarifying Revisions Applicable to §24.239 and §24.243

Proposed §24.239(o) and §24.243(i) - Approval for the transaction to proceed

Proposed §24.239(o) provides that the commission order allowing the transaction to proceed expires 180 days from the date the order is issued and that if the sale has not been completed within that 180-day time period, the approval to proceed with the transaction is void, unless the commission extends the time period in writing. Proposed §24.239(i) provides that the commission approval of a transaction to proceed expires 180 days after the date of the commission order approving the transaction as proposed. The provision further establishes that if the transaction has not been completed within the 180-day time period, and unless the purchasing utility has requested and received an extension for good cause from the commission, the commission approval of the transaction to proceed is void.

The commission revises both provisions for clarity and mirrors them in each section as follows: "Except as otherwise provided by this section, the commission order granting approval for the transaction to proceed expires 180 days after the date the order is issued. If the transaction has not been completed within the 180-day period, the commission's approval to proceed with the transaction will expire by operation of law unless, prior to the expiration of the 180-day period, the commission in writing extends the period." The revisions ensure consistency with terminology (i.e., "expires") and provides additional flexibility for the 180-day period to be extended.

Proposed §§24.239(v), 24.239(v)(1)(A)(i) and 24.243(j), §24.243(j)(1)(A)(i) - Expedited acquisition of voting stock or controlling interest and eligibility

Proposed §24.239(v) and §24.243(j) respectively authorize an eligible applicant to apply for the expedited acquisition of the assets or voting stock or controlling interest of a utility and, if applicable, the certificated service area of that utility in accordance with the requirements of the applicable subsection. Proposed §24.239(v)(1)(A)(i) and §24.243(j)(1)(A)(i) authorize a person appointed by the commission or TCEQ as a temporary manager to be eligible for an expedited transaction.

The commission revises both proposed §24.239(v)(1)(A)(i) and §24.243(j)(1)(A)(i) to include a supervisor appointed by the commission or TCEQ to be eligible for an expedited transaction under §24.239(v) or §24.243(j). The revisions to Texas Water Code §13.301(l) and the addition of Texas Water Code §13.3021 explicitly authorize a supervisor appointed by the commission or TCEQ under Texas Water Code §13.4131. The commission also makes conforming revisions in other provisions in §24.239 and §24.243 and to the Instructions and Part C of the Expedited STM to reflect the statutory eligibility requirements.

Proposed §§24.239(v)(1)(C), 24.239(v)(1)(C)(ii), 24.243(j)(1)(C), 24.243(j)(1)(C)(ii) - Sufficiency of financial, managerial, and technical capability for areas currently certificated to or served by the applicant

Proposed §24.239(v)(1)(C) and §24.243(j)(1)(C) establish that, for purposes of determining eligibility for an expedited transaction, an applicant's appointment as a temporary manager or receiver of the utility is sufficient to demonstrate adequate financial managerial and technical capability. Proposed §24.239(v)(1)(C)(ii) and §24.243(j)(1)(C)(ii) provide that such financial, managerial, and technical capability is sufficiently established for any areas currently certificated to the applicant or, as applicable, any areas being served by the applicant.

The commission moves proposed §24.239(v)(1)(C) and §24.243(j)(1)(C) into §24.239(v)(2) and §24.243(j)(2) as new §24.239(v)(2)(B) and new §24.243(j)(2)(B), respectively. Given that proposed §24.239(v)(1)(C) and §24.243(j)(1)(C) effectively waive the commission's review of financial, managerial, and technical capability, the provisions are more appropriately situated in §24.239(v)(2) and §24.243(j)(2), which primarily relate to aspects of the standard STM process that are waived for expedited transactions. The commission also makes minor revisions to §24.239(v)(2)(B) and §24.243(j)(2)(B) to ensure the provision applies to supervisors in accordance with the requirements of SB 740 and SB 1965 and to ensure that the applicant's demonstration of adequate financial, managerial, and technical capability for providing continuous and adequate service applies to both sub-provisions (§24.239(v)(2)(B)(i) and (ii) and §24.243(j)(2)(B)(i) and (ii)).

The commission also revises proposed §24.239(v)(1)(C)(ii) and §24.243(j)(1)(C)(ii) (now under new §24.239(v)(2)(B)(ii) and §24.243(j)(2)(B)(ii)) to state: "any areas currently certificated to the applicant, or as applicable to municipally owned utilities or districts, any areas being served by the applicant within its jurisdictional boundaries." Texas Water Code §13.301(l)(3)A) only provided that an eligible acquiring utility's financial, managerial, and technical capability is established for the service area to be acquired and any areas currently certificated to the applicant." The additional language regarding areas being served by the applicant is non-statutory, however was intended to address eligible utilities (i.e., municipally owned utilities and districts) that may provide service without a certificate. Retaining the proposed language as-is could potentially authorize an eligible applicant to automatically acquire areas outside of its certificated area on the sole basis that the applicant is providing service to such areas. The revised provision avoids this result except in circumstances where a municipally owned utility or district is lawfully providing service within its jurisdiction.

Question for Comment

In the event that a STM proceeding involves a nonfunctioning utility with temporary rates - when should the reconciliation of temporary rates occur? At the time the commission gives the order approving the transaction to proceed, final commission approval, or when the temporary rates expire or are terminated by the commission? The commission has previously established the following holdings in [Docket] 50085 (See Commission Order, Item #58, [Docket] 50085), which involved the acquisition of a system with temporary rates and the acquiring entity requested the temporary rates to be continued:

a. Temporary rates may be reconciled in the STM proceeding itself to assist the commission in reviewing the reasonableness of the approved temporary rates and the utility's financial health, which are factors that inform the commission's determination on the appropriate duration of the temporary rates post-acquisition.

b. If the underlying improvements justifying the nonfunctioning system's temporary rates have not been completed at the time of the STM proceeding, the reconciliation may be bifurcated. Specifically, the reconciliation held in the STM proceeding will be an "interim" reconciliation and that a "final" reconciliation for any applicable improvements that remain uncompleted must be performed in the utility's next comprehensive base rate proceeding.

c. Reconciliations or interim reconciliations should be conducted prior to the "interim" commission order approving the transaction to proceed.

d. When a nonfunctioning utility has temporary rates in place, in addition to making a determination of the duration of temporary rates the final order must set a deadline for the utility to file its next comprehensive base rate proceeding.

OPUC recommended that reconciliation of temporary rates should occur at the time the commission issues the order allowing a sale, transfer, or merger (STM) application to proceed if the commission has all necessary information and documentation to conduct a prudence review of the requested rates. OPUC stated that timing reconciliation with the STM application to proceed "ensures immediate rate alignment, avoids delays, and prevents intergenerational inequity."

TAWC recommended that reconciliation of temporary rates should not be required until either the temporary rates expire, or the temporary rates are otherwise terminated by the commission. TAWC noted that an earlier reconciliation, particularly in an expedited STM process, does not allow for sufficient time for actual costs to be incurred by the acquiring entity for the temporarily managed system and is therefore premature.

OPUC further stated that reconciliation should be bifurcated to the extent that any underlying improvements justifying the nonfunctioning system's temporary rates have not been completed at the time of the STM proceeding. OPUC maintained that all investments for which the commission has sufficient information to conduct a prudence review should be reviewed and reconciled in the STM proceeding, and any investments for which there is insufficient information should be reviewed and reconciled in the utility's next comprehensive base rate proceeding. OPUC stated this approach "best aligns with the Commission's broader decision-making framework" and avoids issues associated with potential delays. OPUC commented that reconciling temporary rates in an STM proceeding helps ensure that rates "are immediately aligned with the utility's new management, providing a fair and accurate picture of incomplete and subsequent investments not yet included in temporary rates, and ongoing operations and maintenance expenses." OPUC further commented that, upon reconciliation, ratepayers are "shielded from intergenerational inequity" as they are no longer obliged to pay for a temporary manager that is no longer serving the system. OPUC stated that the temporary manager, acquiring utilities, and ratepayers benefit from the certainty this framework provides by eliminating the necessity for any future refunds, surcharges, or true ups.

OPUC emphasized the need for preserving the ratepayer protections and safeguards under Chapter 13 of the Texas Water Code in expedited STM transactions, particularly those that involve temporary rates. Specifically, OPUC maintained that temporary rates authorized under Texas Water Code §13.046 provide a utility cost recovery mechanism without exposing residents to sudden or excessive charges. OPUC also noted that, under Texas Water Code §13.043, ratepayers have the right to appeal temporary or adjusted rates and ensure their concerns are "formally considered and adjudicated by the Commission." OPUC further indicated that, under Texas Water Code §13.4132, the commission may impose conditions on utilities under supervision to ensure both the financial integrity of the utility and prevent the misuse of customer resources. OPUC stated that, read together, such customer protections prioritize ratepayer interests, including safe and reliable service, while a utility is under temporary management. OPUC maintained that such principles should be upheld to ensure rates are just and reasonable for residential and small commercial customers.

Commission response

The commission declines to implement any change in response to OPUC or TAWC's responses to the question for comment. However, the commission generally agrees with TAWC that "reconciliation of temporary rates should not be required until either the temporary rates expire, or the temporary rates are otherwise terminated by the commission." Consistent with the commission order issued in Docket 50085, the commission should retain flexibility on the timing of reconciliation of temporary rates. However, an acquiring utility needs time to reconcile any temporary rates after they are expired or terminated, which may potentially not occur until the conclusion of an STM proceeding or afterward.

In response to OPUC, the commission agrees that reconciliation and prudence review of temporary rates may be appropriate when the commission order issuing a STM application to proceed is issued if "the commission has all necessary information and documentation to conduct a prudence review of the requested rates." However, the appropriate reconciliation and prudence review could, if necessary, occur later in the STM proceeding or in a separate proceeding. Temporary rate reconciliation may be bifurcated where necessary if the underlying improvements justifying the nonfunctioning system's temporary rates have not been completed at the time of the STM proceeding. In general, the most appropriate time to reconcile temporary rates is when the temporary rates expire or are otherwise terminated by the commission. OPUC's concerns about ratepayer protections and safeguards are addressed elsewhere in this adoption order.

Proposed §24.101. Appeal of Rate-making Decision, Pursuant to the Texas Water Code §13.043.

Proposed §24.101(f) - Appeal by retail public utility of decision of a provider of water or sewer service

Proposed §24.101(f) authorizes a retail public utility that receives water or sewer service from another retail public utility or political subdivision of the state, including an affected county, to appeal to the commission a decision of the water or sewer service provider if that decision affects the amount paid for water or sewer service. The provision further states that such an appeal must be initiated by filing a petition within 90 days after the appellant receives notice of the service provider' decision. The provision does not apply to a decision of a municipality regarding wholesale water or sewer service to another municipality.

OPUC recommended §24.101(f) be revised to include language stating that ratepayers subject to an appeal decision under the subsection "retain the right to challenge rates, charges, or other service decisions before the Commission in accordance with TWC § 13.043(b) - (c), including the right to file complaints or intervene in proceedings that affect their bills or quality of service." OPUC emphasized that clarifying "between wholesale transactions and retail service" is necessary to ensure municipal ratepayers retain their rights to challenge rate decisions and prevent any undue limitation of appeals that are otherwise available to residential and small commercial customers. OPUC provided redlines consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. The statutory right of a ratepayer to appeal rate decisions is codified under §24.101(b) and (c). The revision to §24.101(f) is to implement SB 740, Section 3, which added Texas Water Code §13.043(f-1). As a whole, §24.101(f) effectuates Texas Water Code §13.043 and does not concern ratepayers. The provision only addresses appeals from certain utility-type entities and providers of water or sewer service.

Proposed §24.239. Sale, Transfer, Merger, Consolidation, Acquisition, Lease, or Rental.

Proposed §24.239(g)-(h) - Financial, managerial, and technical capability of acquiring utility to provide continuous and adequate service and financial assurance

Proposed §24.239(g) requires a retail public utility or person that files an STM application under §24.239 to demonstrate adequate financial, managerial, and technical capability to provide continuous and adequate service to the requested area and the transferee's certificated service area as required by §24.227, relating to Criteria for Granting or Amending a Certificate of Convenience and Necessity. Proposed §24.239(h) authorizes the commission to require a transferee that cannot demonstrate adequate financial, managerial, and technical capability to provide financial assurance to ensure continuous and adequate retail water or sewer utility service is provided to both the requested area and any area already being served under the transferee's existing CCN. The provision also requires such financial assurance to meet the requirements of §24.11, relating to Financial Assurance, and specifies that an obligation to obtain financial assurance does not relieve the applicant from any requirements to obtain financial assurance to satisfy another state agency's rules.

TAWC recommended that proposed §24.239(g) and (h) be revised to clarify that "financial assurance" under §24.11, relating to Financial Assurance, is not required for every STM or CCN application. TAWC suggested that the commission should instead authorize the demonstration of the purchasing utilities' financial capability through other evidence. TAWC stated that, for CCN applications, developer financial info should not be required if "the utility receiving new certificated area is ultimately responsible for ensuring that all improvements needed for service are installed pursuant to contract or otherwise."

Commission response

The commission declines to implement the recommended change because it is out of scope. The scope of this rulemaking is to implement the expedited STM process associated with SB 740, which does not address financial assurance. Revisions to §24.11 will be taken up by the commission in a later rulemaking. The commission makes minor clerical revisions to §24.239(g). The commission notes that §24.239(g) (along with §24.239(f), which includes revisions to address redundancy with recent changes §24.238, relating to Fair Market Valuation) was inadvertently omitted by the commission in a previous rulemaking and have been reinstated. (Cf. the proposal for publication in Project 54046 with the adoption order in Project 54046).

Proposed §24.239(j) and §24.239(j)(5) - Commission authority to hold hearing for STM transaction and public interest factors

Proposed §24.239(j) authorizes the commission to determine whether to require a public hearing to determine if the transaction will serve the public interest. The provision establishes that the commission will notify the transferee, the transferor, all intervenors, and OPUC whether a hearing will be held. Proposed §24.239(j)(1)-(5) establish factors that the commission may consider when determining whether a hearing should be held on the STM transaction, including public interest factors under §24.239(j)(5)(A)-(I).

OPUC recommended that proposed §24.239(j)(5) be revised to include rate affordability, service quality, and cost reductions as factors the commission will consider when determining whether to hold a hearing for an STM transaction.

Commission response

The commission declines to implement the recommended change because it is out of scope. SB 740 neither specifies nor requires the commission to review the public interest criteria for holding a hearing on an STM proceeding. The scope of this rulemaking is to implement the expedited STM process associated with SB 740.

Proposed §24.239(p) - Commission issuance of order if no hearing is required on STM transaction

Proposed §24.239(p) authorizes the commission to issue an order approving the transaction to proceed if the commission does not require a hearing and the transaction is completed as proposed.

TAWC recommended the reference to the "order approving the transaction to proceed" to be revised to indicate it is actually the final order approving the STM application transaction. TAWC noted the phrase "to proceed" is incorrect as the order approving the transaction to proceed would have occurred prior to the transaction being completed as proposed. TAWC further recommended that the STM process should be made more concise with a single order approving the transaction to proceed and to be completed for simplicity and to provide regulatory certainty. TAWC acknowledged, however, that such a change would necessitate further revisions to §24.239.

Commission response

The commission agrees with TAWC and implements the recommended change. Specifically, the commission replaces "an order approving the transaction to proceed" with "the final order approving the transaction."

Proposed §24.239(u) - Special requirements for certain transactions

Proposed §24.239(u) specifies that, for a transaction that involves a nonfunctioning system for which a temporary manager has been appointed under §24.357, relating to Temporary Manager Appointment, Powers, and Duties, the temporary manager's appointment and the monthly temporary manager's fee must be terminated upon final commission approval of the transaction.

The commission revises the provision to refer only to "the temporary manager's fee" as the commission is not limited to setting monthly fees for a temporary manager (i.e., a fee may be weekly, bi-weekly, bi-monthly, etc.).

Proposed §24.239(v) - Expedited acquisition of assets

OPUC recommended proposed §24.239(v) should be revised such that the expedited transaction process should include language that would "provide clarity for ratepayers on how they might otherwise review the impact on their bills associated with the application."

Commission response

The commission declines to implement the recommended change because it is out of scope. SB 740 explicitly waives notice for expedited STM transactions. The utility acquiring the system in an expedited transaction is already known to customers as they are already serving as the temporary manager, receiver, or supervisor of the system. Moreover, the utility will have to declare itself after the transaction is completed to inform customers of how to pay their bills and to whom to remit payment. The new bill will effectively serve as notice of the expedited transaction.

Proposed §24.240(c) and §24.240(c)(5) - Initial rates and public interest determination

Proposed §24.240(c) establishes the requirements for initial rates for an STM applicant that requests authorized acquisition rates. Proposed §24.240(c)(5) establishes that the commission will consider, in determining whether to approve a STM transaction under §24.239, whether approving the transferee's request to charge authorized acquisition rates would change whether the proposed transaction would serve the public interest under §24.239(h)(5).

OPUC commented that the revision to §24.240(c)(5) effectively redefines initial acquisition rates to mean "those in effect upon final Commission approval" and clarifies the scope of public interest review when "authorized rates are requested." OPUC noted that the revisions risk the commission adopting "authorized acquisition rates that exceed current rates to such a degree as to create rate shock" which would raise customers' bills without the protections of a full base rate proceeding. OPUC commented that its proposed revisions help ensure ratepayers are aware of the potential for increased rates where there is no immediate improvement in service. OPUC provided redlines consistent with its recommendation.

Commission response

The commission disagrees with OPUC and declines to implement the recommended change because it is unnecessary. The revision to §24.240(c)(5) was a clarifying edit to omit a potentially confining cross-reference to the criteria under §24.239(j)(5) (previously §24.239(h)(5)). Specifically, the revision was to reflect the general potential for the commission to render a public interest determination in each circumstance where authorized acquisition rates are imposed, which could be in a standard STM of assets or an expedited STM of assets under §24.239, a standard STM or an expedited STM of stock or controlling interest under §24.243, etc. Moreover, the public interest factors for a commission determination on authorized acquisition rates under §24.240 may not always be the same as the criteria the commission considers under §24.239(j)(5) in determining whether to hold a public hearing in an STM asset acquisition proceeding. The revision provides latitude for the commission to consider other factors, not just those under §24.239. It is unclear how the revision "risk[s] the commission adopting 'authorized acquisition rates that exceed current rates to such a degree as to create rate shock'" or would otherwise prevent the commission from requiring authorized acquisition rates to be implemented in a manner to mitigate negative impacts such as rate shock.

Proposed §24.243. Purchase of Voting Stock or Acquisition of a Controlling Interest in a Utility.

New §24.243(k) - Notice of expedited proceedings for customers (OPUC Proposal)

OPUC mirrored its recommendation for heightened customer protections in expedited proceedings in §24.239. Specifically, OPUC recommended that new §24.243(k) be added which would, in the same manner as §24.239, require utilities to provide notice to customers of the impacts of the expedited transaction on their bills due to the expedited STM transaction involving the acquisition of stock or a controlling interest. OPUC provided redlines consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is out of scope and for the reasons previously stated. SB 740 explicitly waives notice for expedited STM transactions.

Proposed §24.357. Operation of a Utility by a Temporary Manager.

Proposed §24.357(f) - Return of inventory

Proposed §24.357(f) requires a temporary manager to return to the commission an inventory of all property received within 60 days after appointment.

The commission replaces the term "property received" with "utility property" for clarity.

Proposed §24.357(g) - Temporary manager compensation

Proposed §24.357(g) establishes that compensation for a temporary manager will come from utility revenues and will be set by the commission at the time of appointment. The provision also states that changes to the temporary manager compensation agreement may be approved by the commission.

OPUC recommended proposed §24.357(g) be revised to require commission review of temporary manager proposed compensation agreements, which would be filed confidentially or otherwise designated as highly sensitive filings. OPUC stated that requiring public transparency of such agreements, or at the least confidential disclosure to the commission, is necessary to protect customers from excessive costs attributable to temporary management. Specifically, OPUC recommended that compensation agreements should be reviewed for prudence before recovery is sought in a subsequent rate proceeding. OPUC provided redlines consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is out of scope. SB 740 does not reference the commission review of temporary manager compensation agreements. Moreover, temporary manager compensation is established by the commission in the final order appointing the temporary manager, as indicated by §24.357(g). A temporary manager must apply with the commission and file documentation to support an increase to their compensation. The commission will review the application and the supporting documentation and then issue an order ruling on the application. Moreover, when a temporary manager's fee is charged to a customer, it is not technically part of a customer's rate base, so it is not reviewed for prudence. In lieu of that, temporary managers must file monthly reports which are reviewed by staff through the issuance of memos. The commission notes that temporary managers frequently operate at a deficit. If a temporary manager's fee becomes excessive, commission staff can recommend a fee decrease to the presiding officer. The Texas Commission on Environmental Quality also consults with the commission when appointing a temporary manager and establishing the temporary manager fee to ensure a temporary manager's compensation is just and reasonable. The commission also replaces the sentence "[c]hanges in the compensation agreement may be approved by the commission" with "[t]he commission may adjust the compensation for the temporary manager as it deems necessary" for clarity and consistency. The initial sentence does not refer to a compensation agreement, only the compensation of the temporary manager.

Proposed §24.363. Temporary Rates for Services Provided for a Nonfunctioning System.

Proposed §§24.363(e), 24.363(e)(1), 24.363(e)(2) - Regulatory asset

Proposed §24.363(e) provides that, in an expedited STM proceeding under §24.239 or §24.243, if a temporary rate is established during the term of a person's temporary management, receivership, or supervision of a utility, the person's used and useful invested capital and just and reasonable operations and maintenance costs that are incurred in excess of the costs covered by the temporary rate are considered to be a regulatory asset. The provision also states that the regulatory asset is eligible for recovery in the person's next comprehensive rate proceeding or system improvement charge application. Proposed §24.363(e)(1) establishes that, if a temporary rate is adopted during the term of a person's temporary management, receivership, or supervision of a utility, then the person's used and useful invested capital and just and reasonable operations and maintenance costs that are incurred by the person during the person's appointment as temporary manager, receiver, or supervisor that are in excess of the costs covered by the temporary rate are considered to be a regulatory asset. Proposed §24.363(e)(2) states that the regulatory assets eligible for recovery in the person's next comprehensive rate proceeding or system improvement charge application

OPUC recommended that §24.363(e) be revised to require prudence review of any regulatory asset established under the provision for a temporary rate adopted during the term of a temporary manager, receiver, or supervisor, regardless of whether the regulatory asset is recovered in a System Improvement Charge (SIC) proceeding or a base rate case. OPUC expressed concern that it would only have 30 days from the date a SIC application is filed to comment on the application given the 75-day timeline imposed by SB 740, reduced from 180 days. OPUC stated this provides only a "limited opportunity for parties to review the types of assets, investments and cost of the investments included in the SIC application." OPUC stated that this limited review concern is heightened given the addition of §24.363(e) "which treats expenditures above the level covered by temporary rates as regulatory assets to be recovered in a future proceeding." OPUC noted that this authorizes recovery through either a SIC or a comprehensive rate proceeding but does not require such costs to be subject to prudence review before recovery. OPUC stated that not requiring prudence review prior to recovery risks imprudent investments or costly activities by temporary managers to be included in rates "without a meaningful prudence evaluation." OPUC noted that a reasonableness standard is already applied to temporary rates under §24.363(d) and therefore, the same principle should apply when similar costs are later considered to be regulatory assets. OPUC stated that its proposed change would protect ratepayers from bearing the costs associated with "a temporary manager's imprudent actions, while still permitting timely recovery for prudent investments." OPUC provided redlines consistent with its recommendation.

Commission response

The commission implements OPUC's recommended language regarding prudence review of the temporary rate-related regulatory asset with revisions. However, the commission declines to implement OPUC's recommended revisions to §24.363(e)(1) and (e)(2)(A). Specifically, the commission revises §24.363(e)(2) to establish that the regulatory asset for temporary rates will be subject to prudence review only in a base rate proceeding. SB 740 only requires the regulatory asset to be recoverable in either a SIC proceeding or a base rate proceeding but is silent as to the timing of the prudence review of that regulatory asset. Given SB 740's reduced timeline of 60 to 75 days in a SIC proceeding, prudence review of any regulatory asset is therefore impractical. Therefore, the only appropriate proceeding to review the prudence of the regulatory asset is the utility's next comprehensive base rate proceeding. Given the implemented change to §24.363(e)(2) regarding prudence review, OPUC's proposed revision to §24.363(e)(1) regarding the same is redundant and therefore unnecessary. Additionally, OPUC's proposed revision to §24.363(e)(2)(A), regarding the recovery of a regulatory asset in a SIC proceeding, is out of scope as revisions to §24.76 to reflect changes made by SB 740, Section 4, will be undertaken in Project 58391. The commission also revises §24.363(e)(1) to specify that "[i]f a temporary rate is adopted during the term of a person's temporary management, receivership, or supervision of a utility, then the person's used and useful invested capital and just and reasonable operations and maintenance costs that are incurred by the person during the person's appointment as temporary manager, receiver, or supervisor that are in excess of the costs covered by the temporary rate are considered t be a regulatory asset." This revision conforms the rule more closely to §13.301(l)(3)(B).

CCN Obtain or Amend Form (Section 22)

Section 22 of the CCN Obtain or Amend Form requires an investor-owned utility applicant that is seeking to obtain a CCN for the first time under the original rate jurisdiction of the commission to attach a proposed tariff to the application. Section 22 also requires the applicant to file a rate filing package with the commission within 18 months from the date service begins to revise the utility's tariff to adjust the rates to a historic test year and true up the new tariff rates to the historic test year. Section 22 requires the applicant to provide, in any future rate proceeding, written evidence and support for the original cost and installation date of all facilities used and useful for providing utility service.

TAWC recommended Section 22 of the proposed CCN Obtain or Amend form be revised to account for the new test year definition under Texas Water Code §13.1831. Specifically, TAWC noted that a test year is no longer restricted to a "historic" test year, given the new definition [established by House Bill 2712 (89R)].

Commission response

The commission declines to implement TAWC's recommended change. Section 22 of the CCN Obtain or Amend Form applies to new utilities which must use a historic test year. The commission's implementation of HB 2712 will be undertaken in a separate, future rulemaking.

Application for STM of a Retail Public Utility Form (Part F)

TAWC recommended that Part F of the STM form be revised to be optional if the STM application does not include a request to change the boundaries of the applicant's CCN.

Commission response

The commission revises Part F to indicate that applicants may skip Questions 25 through Question 29 if no uncertificated area, dual certification, or decertification is being requested (i.e., no CCN boundary changes are being requested). It is otherwise necessary for an applicant utility to provide information about neighboring utilities and capital improvement plans, if any, for the requested area or the uncertificated area.

SUBCHAPTER D. RATE-MAKING APPEALS

16 TAC §24.101

Texas Water Code §13.041(a), 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 the Texas Water Code that is necessary and convenient to the exercise of that power and jurisdiction; Texas Water Code §13.041(b), which provides the commission with the authority to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; Texas Water Code §13.043(f-1) which exempts municipal decisions regarding wholesale water or sewer service provided to another municipality that involve the amount paid for water or sewer service from the commission's appellate jurisdiction; Texas Water Code §13.301, which establishes the requirements and procedures for STM proceedings and expedited STM proceedings before the commission; Texas Water Code §13.3021, which establishes the requirements and procedures for expedited STM proceedings before the commission for certain retail public utilities; Texas Water Code §13.412(g), which establishes the list of entities that may be appointed by a court of competent jurisdiction as a receiver and authorizes a receiver to seek both the acquisition of the utility under supervision and the transfer of the utility's certificate of convenience and necessity (CCN); and Texas Water Code §13.4132(a) and (a-1), which establish the list of entities that may be appointed by the commission or TCEQ as a temporary manager and expands the definition of "person" to incorporate that list of entities for purposes of that section which provides the commission with the authority to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction.

Cross reference to statutes: Texas Water Code §§ 13.041(a) and (b), 13.043(f-1), 13.301, 13.3021, 13.412(g); §13.4132(a) and (a-1).

§24.101. Appeal of Rate-making Decision, Pursuant to the Texas Water Code §13.043.

(a) Any party to a rate proceeding before the governing body of a municipality may appeal the decision of the governing body to the commission. This subsection does not apply to a municipally owned utility, but does include privately owned utilities operating within the corporate limits of a municipality. An appeal under this subsection may be initiated by filing with the commission a petition signed by a responsible official of the party to the rate proceeding or its authorized representative and by serving a copy of the petition on all parties to the original proceeding. The petition should be filed in accordance with Chapter 22 of this title (relating to Procedural Rules). The appeal must be initiated within 90 days after the date of notice of the final decision of the governing body, or within 30 days if the appeal relates to the rates of a Class A utility, by filing a petition for review with the commission and by serving a copy of the petition on all parties to the original rate proceeding.

(b) An appeal under Texas Water Code (TWC) §13.043(b) must be initiated within 90 days after the effective date of the rate change or, if appealing under TWC §13.043(b)(2) or (5), within 90 days after the date on which the governing body of the municipality or affected county makes a final decision. An appeal is initiated by filing a petition for review with the commission and by sending a copy of the petition to the entity providing service and with the governing body whose decision is being appealed if it is not the entity providing service. The petition must be signed by the lesser of 10,000 or 10% of the ratepayers whose rates have been changed and who are eligible to appeal under subsection (c) of this section.

(c) Retail ratepayers of the following entities may appeal the decision of the governing body of the entity affecting their water utility, sewer utility, or drainage rates to the commission:

(1) a nonprofit water supply or sewer service corporation created and operating under TWC, Chapter 67;

(2) a utility under the jurisdiction of a municipality inside the corporate limits of the municipality;

(3) a municipally owned utility, if the ratepayers reside outside the corporate limits of the municipality, including a decision of a governing body that results in an increase in rates when the municipally owned utility takes over the provision of service to ratepayers previously served by another retail public utility;

(A) A municipally owned utility must:

(i) disclose to any person, on request, the number of ratepayer(s) who reside outside the corporate limits of the municipality; and

(ii) subject to subparagraph (B) of this paragraph, provide to any person, on request, a list of the names and addresses of the ratepayers who reside outside the corporate limits of the municipality.

(B) If a ratepayer has requested that a municipally owned utility keep the ratepayer's personal information confidential under Tex. Util. Code §182.052, the municipally owned utility may not disclose the address of the ratepayer under subparagraph (A)(ii) of this paragraph to any person. A municipally owned utility must inform ratepayers of their right to request that their personal information be kept confidential under Tex. Util. Code §182.052 in any notice provided under the requirement of TWC§13.043(i).

(i) may not charge a fee for disclosing the information under subparagraph (A)(i) of this paragraph;

(ii) will provide information requested under subparagraph (A)(i) of this paragraph by telephone or in writing as preferred by the person making the request; and

(iii) may charge a reasonable fee for providing information under subparagraph (A)(ii) of this paragraph.

(D) Paragraph (3) of this subsection does not apply to a municipally owned utility that takes over the provision of service to ratepayers previously served by another retail public utility if the municipally owned utility:

(i) takes over the service at the request of the ratepayer;

(ii) takes over the service in the manner provided by TWC Chapter 13, Subchapter H; or

(iii) is required to take over the service by state law, an order of the Texas Commission on Environmental Quality, or an order of the commission.

(4) a district or authority created under Article III, §52, or Article XVI, §59 of the Texas Constitution, that provides water or sewer service to household users;

(5) a utility owned by an affected county, if the ratepayers' rates are actually or may be adversely affected. For the purposes of this subchapter, ratepayers who reside outside the boundaries of the district or authority will be considered a separate class from ratepayers who reside inside those boundaries; and

(6) in an appeal under this subsection, the retail public utility must provide written notice of hearing to all affected customers in a form prescribed by the commission.

(d) In an appeal under TWC §13.043(b), each person receiving a separate bill is considered a ratepayer, but one person may not be considered more than one ratepayer regardless of the number of bills the person receives. The petition for review is considered properly signed if signed by a person, or the spouse of the person, in whose name utility service is carried.

(e) The commission will hear an appeal under this section de novo and fix in its final order the rates the governing body should have fixed in the action from which the appeal was taken. The commission may:

(1) in an appeal under TWC §13.043(a), include reasonable expenses incurred in the appeal proceedings;

(2) in an appeal under TWC §13.043(b), include reasonable expenses incurred by the retail public utility in the appeal proceedings;

(3) establish the effective date;

(4) order refunds or allow surcharges to recover lost revenues;

(5) consider only the information that was available to the governing body at the time the governing body made its decision and evidence of reasonable expenses incurred in the appeal proceedings; or

(6) establish interim rates to be in effect until a final decision is made.

(f) A retail public utility that receives water or sewer service from another retail public utility or political subdivision of the state, including an affected county, may appeal to the commission, a decision of the provider of water or sewer service affecting the amount paid for water or sewer service. An appeal under this subsection must be initiated within 90 days after notice of the decision is received from the provider of the service by filing a petition by the retail public utility. This subsection does not apply to a decision of a municipality regarding wholesale water or sewer service provided to another municipality.

(g) An applicant requesting service from an affected county or a water supply or sewer service corporation may appeal to the commission a decision of the county or water supply or sewer service corporation affecting the amount to be paid to obtain service other than the regular membership or tap fees. An appeal under TWC §13.043(g) must be initiated within 90 days after written notice of the amount to be paid to obtain service is provided to the service applicant or member of the decision of an affected county or water supply or sewer service corporation affecting the amount to be paid to obtain service as requested in the applicant's initial request for that service.

(1) If the commission finds the amount charged to be clearly unreasonable, it will establish the fee to be paid and will establish conditions for the applicant to pay any amount(s) due to the affected county or water supply or sewer service corporation. Unless otherwise ordered, any portion of the charges paid by the applicant that exceed the amount(s) determined in the commission's order must be refunded to the applicant within 30 days of the date the commission issues the order, at an interest rate determined by the commission.

(2) In an appeal brought under this subsection, the commission will affirm the decision of the water supply or sewer service corporation if the amount paid by the applicant or demanded by the water supply or sewer service corporation is consistent with the tariff of the water supply or sewer service corporation and is reasonably related to the cost of installing on-site and off-site facilities to provide service to that applicant, in addition to the factors specified under subsection (i) of this section.

(3) A determination made by the commission on an appeal from an applicant for service from a water supply or sewer service corporation under this subsection is binding on all similarly situated applicants for service, and the commission may not consider other appeals on the same issue until the applicable provisions of the tariff of the water supply or sewer service corporation are amended.

(h) The commission may, on a motion by the commission staff or by the appellant under subsection (a), (b), or (f) of this section, establish interim rates to be in effect until a final decision is made.

(i) In an appeal under this section, the commission will ensure that every appealed rate is just and reasonable. Rates must not be unreasonably preferential, prejudicial, or discriminatory but must be sufficient, equitable, and consistent in application to each class of customers. The commission will use a methodology that preserves the financial integrity of the retail public utility. To the extent of a conflict between this subsection and TWC §49.2122, TWC §49.2122 prevails.

(j) A customer of a water supply corporation may appeal to the commission a water conservation penalty. The customer must initiate an appeal under TWC §67.011(b) within 90 days after the customer receives written notice of the water conservation penalty amount from the water supply corporation per its tariff. The commission will approve the water supply corporation's water conservation penalty if:

(1) the penalty is clearly stated in the tariff;

(2) the penalty is reasonable and does not exceed six times the minimum monthly bill in the water supply corporation's current tariff; and

(3) the water supply corporation has deposited the penalty in a separate account dedicated to enhancing water supply for the benefit of all of the water supply corporation's customers.

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 December 12, 2025.

TRD-202504617

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 1, 2026

Proposal publication date: September 5, 2025

For further information, please call: (512) 936-7244

SUBCHAPTER H. CERTIFICATES OF CONVENIENCE AND NECESSITY

16 TAC §§24.239, 24.240, 24.243

Cross reference to statutes: Texas Water Code §§ 13.041(a) and (b), 13.043(f-1), 13.301, 13.3021, 13.412(g); §13.4132(a) and (a-1).

§24.239. Sale, Transfer, Merger, Consolidation, Acquisition, Lease, or Rental.

(a) Application. A water supply or sewer service corporation or a water and sewer utility owned by an entity required to possess a certificate of convenience and necessity (CCN) must comply with this section. A municipality, district, or political subdivision may, but is not required to, comply with this section.

(b) Notice and filing requirements for commission approval of the transaction to proceed. No later than 120 days before the effective date of any sale, transfer, merger, consolidation, acquisition, lease, or rental, an applicant must file an application with the commission and give public notice of the transaction in accordance with this section. Notice is considered given under this subsection on the later of:

(1) the last date the applicant mailed the required notice as stated in the applicant's affidavit of notice; or

(2) the last date of the publication of the notice in the newspaper as stated in the affidavit of publication, if required.

(c) Transaction involving a municipal utility system. A transaction involving the sale of a municipal utility system to an entity to which this section applies must comply with this subsection. For purposes of this subsection, a municipal utility system means one or more retail water or sewer utility systems that comprise all or part of the facilities used by a municipally owned utility to provide retail water or sewer utility service. If the municipal utility system being acquired does not include all of the facilities used by the municipally owned utility to provide retail water or sewer utility service, the applicant must provide sufficient detail in its application to identify the specific retail water or utility systems and facilities being acquired.

(1) A water supply or sewer service corporation or a water and sewer utility required to possess a CCN may purchase a municipal utility system if:

(A) the sale has been authorized by a majority vote of the qualified voters of the municipality in an election held by the governing body of the municipality in the manner provided for bond elections in the municipality including, if applicable, Tex. Gov't Code Title 9, Subtitle C, Chapter 1251; or

(B) the Texas Commission on Environmental Quality (TCEQ) has issued a notice of violation to the municipality for one or more of the retail water or sewer systems that comprise the municipal utility system, and the governing body of the municipality finds by official action that the municipality is either financially or technically unable to restore the retail water or sewer system or systems to compliance with the rules or statutes cited in the notice of violation. For purposes of this section, any official written notification from the TCEQ, such as a notice of violation letter, a notice of enforcement letter, or a field citation, that a retail water or sewer system is out of compliance with a rule or statute within the TCEQ's jurisdiction will be considered a notice of violation.

(2) For a sale authorized under paragraph (1)(A) of this subsection, the applicant must include with its application documentation that the sale was authorized by a majority vote in compliance with the requirements of this section.

(3) For a sale authorized under paragraph (1)(B) of this subsection, the applicant must provide notice to the TCEQ of the transaction in writing. For a sale authorized under paragraph (1)(B) of this subsection, the applicant must also include the following information to the commission as a part of its application:

(A) a copy of the notice of violation issued by the TCEQ involving the municipal utility system;

(B) a copy of the written notice provided to the TCEQ as required by this paragraph; and

(C) documentation of the official action taken by the governing body of the municipality finding the municipality is financially or technically unable to restore the municipal utility system to compliance with the rules or statutes cited in the notice of violation.

(d) Intervention period. The intervention period for an application filed under this section must not be less than 30 days. The presiding officer may order a shorter intervention period for good cause shown.

(e) Notice.

(1) Unless notice is waived by the commission, proper notice must be given to affected customers and to other affected parties as required by the commission on the form prescribed by the commission. The notice must include the following:

(A) the name and business address of the utility currently holding the CCN (transferor) and the retail public utility or person that will acquire the facilities or CCN (transferee);

(B) a description of the requested area;

(C) the following statement: "Persons who wish to intervene in the proceeding or comment upon the action sought should contact the Public Utility Commission, P.O. Box 13326, Austin, Texas 78711-3326, or call the Public Utility Commission at (512) 936-7120 or (888) 782-8477. Hearing- and speech-impaired individuals with text telephones (TTY) may contact the commission through Relay Texas at 1-800-735-2989. The deadline for intervention in the proceeding is (date 30 days from the mailing or publication of notice, whichever occurs later, unless otherwise provided by the presiding officer). If you wish to intervene, the commission must receive your letter requesting intervention or motion to intervene by that date; and

(D) if the transferor is a nonfunctioning utility with a temporary rate in effect and the transferee is requesting that the temporary rate remain in effect under TWC §13.046(d), the following information:

(i) the temporary rates currently in effect for the nonfunctioning utility; and

(ii) the duration of time for which the transferee is requesting that the temporary rates remain in effect.

(E) if the transferor is a municipality, the notice must also provide the following information as an attachment, as applicable:

(i) If subsection (c)(1)(A) of this section applies, a statement describing the details of the authorizing election, including the date and outcome of the election and the text of the applicable ballot provision.

(ii) If subsection (c)(1)(B) of this section applies, a statement:

(I) indicating that the TCEQ has issued a notice of violation for one or more systems within the municipal utility system and that the governing board of the municipality has found that it is either financially or technically unable to restore the system to compliance with the applicable rules or statutes;

(II) providing a basic description of the violations cited in the notice of violation, including the systems involved, the nature of the violations, and the rules or statutes cited in the notice of violation; and

(III) describing the details of the official action of the governing board including the date and forum in which the official action was taken and how to locate a transcript or recording of the official action, if available.

(2) The transferee must mail the notice to cities and neighboring retail public utilities providing the same utility service whose corporate limits or certificated service area boundaries are within two miles from the outer boundary of the requested area, and any city with an extraterritorial jurisdiction that overlaps the requested area.

(3) The commission may require the transferee to publish notice once each week for two consecutive weeks in a newspaper of general circulation in each county in which the retail public utility being transferred is located. The commission may allow published notice in lieu of individual notice as required by paragraph (2) of this subsection.

(4) The commission may waive published notice if the requested area does not include unserved area, or for good cause shown.

(f) Fair market valuation. An application filed under this section for approval of a transaction that includes a fair market valuation of the transferee or the transferee's facilities must follow the process established in §24.238 of this title (relating to Fair Market Valuation).

(g) A retail public utility or person that files an application under this section to purchase, transfer, merge, acquire, lease, rent, or consolidate a utility or system must demonstrate adequate financial, managerial, and technical capability for providing continuous and adequate service to the requested area and any area already being lawfully served by the transferee, including the area in the transferee's certificated service area, as required by §24.227(a) of this chapter (relating to Criteria for Granting or Amending a Certificate of Convenience and Necessity).

(h) If the transferee cannot demonstrate adequate financial capability, the commission may require that the transferee provide financial assurance to ensure continuous and adequate retail water or sewer utility service is provided to both the requested area and any area already being served under the transferee's existing CCN. The commission will set the amount of financial assurance. The form of the financial assurance must meet the requirements of §24.11 of this title (relating to Financial Assurance). The obligation to obtain financial assurance under this title does not relieve an applicant from any requirements to obtain financial assurance to satisfy another state agency's rules.

(i) The commission will, with or without a public hearing, investigate the sale, transfer, merger, consolidation, acquisition, lease, or rental to determine whether the transaction will serve the public interest. If the commission decides to hold a hearing, or if the transferee fails either to file the application as required or, except for an expedited application under subsection (u) of this section, to provide public notice, the transaction proposed in the application may not be completed unless the commission determines that the proposed transaction serves the public interest.

(j) Before the expiration of the 120-day period described in subsection (b) of this section, the commission will determine whether to require a public hearing to determine if the transaction will serve the public interest. The commission will notify the transferee, the transferor, all intervenors, and the Office of Public Utility Counsel whether a hearing will be held. The commission may consider the following factors when determining whether a hearing is required:

(1) the application filed with the commission or the public notice was improper;

(2) the transferee has not demonstrated adequate financial, managerial, and technical capability for providing continuous and adequate service to the requested area and any area already being served under the transferee's existing CCN;

(3) the transferee has a history of:

(A) noncompliance with the requirements of the TCEQ, the commission, or the Texas Department of State Health Services; or

(B) continuing mismanagement or misuse of revenues as a utility service provider;

(4) the transferee cannot demonstrate the financial ability to provide the necessary capital investment to ensure the provision of continuous and adequate service to the requested area; or

(5) there are concerns that the transaction does not serve the public interest based on consideration of the following factors:

(A) the adequacy of service currently provided to the requested area;

(B) the need for additional service in the requested area;

(C) the effect of approving the transaction on the transferee, the transferor, and any retail public utility of the same kind already serving the area within two miles of the boundary of the requested area;

(D) the ability of the transferee to provide adequate service;

(E) the feasibility of obtaining service from an adjacent retail public utility;

(F) the financial stability of the transferee, including, if applicable, the adequacy of the debt-equity ratio of the transferee if the transaction is approved;

(G) environmental integrity;

(H) the probable improvement of service or lowering of cost to consumers in the requested area resulting from approving the transaction; and

(I) whether the transferor or the transferee has failed to comply with any commission or TCEQ order. The commission may refuse to approve a sale, transfer, merger, consolidation, acquisition, lease, or rental if conditions of a judicial decree, compliance agreement, or other enforcement order have not been substantially met.

(k) If the commission does not require a public hearing, the sale, transfer, merger, consolidation, acquisition, lease, or rental may be completed as proposed:

(1) at the end of the 120-day period described in subsection (a) of this section; or

(2) at any time after the transferee receives notice from the commission that a hearing will not be required.

(l) Within 30 days of the commission order that approves the sale, transfer, merger, consolidation, acquisition, lease, or rental to proceed as proposed, the transferee must provide a written update on the status of the transaction, and every 30 days thereafter, until the transaction is complete. The transferee must inform the commission of any material changes in its financial, managerial, and technical capability to provide continuous and adequate service to the requested area and the transferee's service area.

(m) If there are outstanding customer deposits, within 30 days of the actual effective date of the transaction, the transferor and the transferee must file with the commission, the following information supported by a notarized affidavit:

(1) the names and addresses of all customers who have a deposit on record with the transferor;

(2) the date such deposit was made;

(3) the amount of the deposit; and

(4) the unpaid interest on the deposit. All such deposits must be refunded to the customer or transferred to the transferee, along with all accrued interest.

(n) Within 30 days after the actual effective date of the transaction, the transferee and the transferor must file a signed contract, bill of sale, or other appropriate documents as evidence that the transaction has closed as proposed. The signed contract, bill of sale, or other documents, must be signed by both the transferor and the transferee. If there were outstanding customer deposits, the transferor and the transferee must also file documentation that customer deposits have been transferred or refunded to the customers with interest as required by this section.

(o) Except as otherwise provided by this section, the commission order granting approval for the transaction to proceed expires 180 days after the date the order is issued. If the transaction has not been completed within the 180-day period, the commission's approval to proceed with the transaction will expire by operation of law unless, prior to the expiration of the 180-day period, the commission in writing extends the period.

(p) If the commission does not require a hearing, and the transaction is completed as proposed, the commission may issue the final order approving the transaction.

(q) A sale, transfer, merger, consolidation, acquisition, lease, or rental of any water or sewer system or retail public utility required by law to possess a CCN, or transfer of customers or service area, owned by an entity required by law to possess a CCN that is not completed in accordance with the provisions of TWC §13.301 is void.

(r) The requirements of TWC §13.301 do not apply to:

(1) the purchase of replacement property;

(2) a transaction under TWC §13.255; or

(3) foreclosure on the physical assets of a utility.

(s) This subsection applies if a utility's facility or system is sold and the utility's facility or system was partially or wholly constructed with customer contributions in aid of construction derived from specific surcharges approved by the regulatory authority over and above revenues required for normal operating expenses and return. This subsection does not apply to a utility facility or system sold as part of a transaction where the transferor and transferee elected to use the fair market valuation process set forth in §24.238 of this title (relating to Fair Market Valuation).

(1) The utility may not sell or transfer any of its assets, its CCN, or a controlling interest in an incorporated utility, unless the utility provides a written disclosure relating to the contributions to both the transferee and the commission before the date of the sale or transfer.

(2) The disclosure must contain, at a minimum, the total dollar amount of the contributions and a statement that the contributed property or capital may not be included in invested capital or allowed depreciation expense by the regulatory authority in rate-making proceedings.

(t) For any transaction subject to this section, the retail public utility that proposes to sell, transfer, merge, acquire, lease, rent, or consolidate its facilities, customers, service area, or controlling interest must provide the other party to the transaction a copy of this section before signing an agreement to sell, transfer, merge, acquire, lease, rent, or consolidate its facilities, customers, service area, or controlling interest.

(u) Special requirements for certain transactions. For a transaction under this section that involves a nonfunctioning system to which a temporary manager has been appointed under §24.357 of this title (relating to Temporary Manager Appointment, Powers, and Duties), upon final commission approval of the transaction, the temporary manager's appointment and temporary manager's fee must be terminated.

(v) Expedited acquisition of assets. An eligible applicant may apply for the expedited acquisition of the assets and, if applicable, the certificated service area of a utility in accordance with this subsection.

(1) Eligibility. To be eligible for expedited acquisition under this subsection, an applicant must meet the criteria in subparagraphs (A) and (B) of this paragraph.

(A) Prior to filing an application for expedited acquisition, an applicant must, for the utility being acquired, be either:

(i) a person appointed by the commission or TCEQ as a temporary manager or supervisor; or

(ii) appointed as a receiver at the request of the commission or TCEQ.

(B) In addition to meeting one of the criteria under subparagraph (A) of this paragraph, an applicant must also be either:

(i) a Class A utility;

(ii) a Class B utility;

(iii) a municipally owned utility;

(iv) a county;

(v) a water supply or sewer service corporation;

(vi) a public utility agency; or

(vii) a district or river authority.

(2) Application.

(A) An application filed by an eligible applicant under paragraph (1) of this subsection must comply with the requirements of this section, except that the following are waived:

(i) any public notice requirements required by this chapter, regardless of whether the person elects to charge initial rates in accordance with §24.240 of this title or use a voluntary valuation determined under §24.238 of this title; and

(ii) as applicable, any requirements of this chapter that do not apply to an entity over which the utility commission does not have original rate jurisdiction.

(B) An applicant's appointment as a temporary manager, supervisor, or receiver of the utility subject to the application is sufficient to demonstrate adequate financial, managerial, and technical capability for providing continuous and adequate service to:

(i) the service area to be acquired; and

(ii) any areas currently certificated to the applicant or, as applicable to municipally owned utilities or districts, any areas being served by the applicant within jurisdictional boundaries.

(3) Commission approval and effects of approval.

(A) The commission will approve an application under this subsection if the commission considers the transaction to be in the public interest in accordance with the processes specified under Texas Water Code §13.246 and §13.301, and subsections (i) and (j) of this section. In determining whether the transaction is in the public interest, the commission may also consider whether the applicant is currently in compliance with commission rules, orders, and other applicable laws.

(B) The commission will approve an application under this subsection without the signature of the owner of the utility being acquired that is required by other law if the utility owner has abandoned operation of the facilities that are the subject of the transaction and cannot be located, or does not respond to an application filed under this subsection.

(C) Unless otherwise specified by §24.363 of this title (relating to Temporary Rates for Services Provided for a Nonfunctioning System), the applicant acquiring the utility may seek recovery of all used and useful invested capital and just and reasonable operations and maintenance costs incurred during the applicant's appointment term as a regulatory asset in the applicant's next comprehensive rate proceeding under §24.41 of this title (relating to Cost of Service) or system improvement charge application under §24.76 of this title (relating to System Improvement Charge).

§24.240. Water and Sewer Utility Rates After Acquisition.

(a) Applicability. This section applies to a person who files an application with the commission under Texas Water Code (TWC) §13.301(a) and a request for authorized acquisition rates under TWC §13.3011. For purposes of this section, the term "transaction" is used to align with its usage in the procedural provisions of §24.239 of this title (relating to Sale, Transfer, Merger, Consolidation, Acquisition, Lease, or Rental).

(b) Definitions. In this section, the following definitions apply unless the context indicates otherwise.

(1) Authorized acquisition rates--Initial rates that are in force and shown in a tariff filed with a regulatory authority for the transferee for another water or sewer system owned by the transferee on the date an application is filed for the acquisition of a water or sewer system under §24.239 of this title.

(2) Existing rates--Rates a transferor charged its customers under a tariff filed with a regulatory authority prior to the water system or sewer system being acquired.

(3) Initial rates--Rates charged by a transferee to the customers of an acquired water or sewer system upon final commission approval of the transaction. An initial rate may be an existing rate, an authorized acquisition rate, or a rate authorized by other applicable law.

(1) A transferee must use existing rates as initial rates unless the commission authorizes, under this section or other applicable law, the use of different initial rates.

(2) A transferee may request commission approval to charge authorized acquisition rates to the customers of the water or sewer system for which the transferee seeks approval to acquire as part of an application filed in accordance with §24.239 of this title.

(3) If the transferee has in-force tariffs filed with multiple regulatory authorities, there is a rebuttable presumption that authorized acquisition rates should be based upon an in-force tariff that was approved by the same regulatory authority that has original jurisdiction over the rates charged to the acquired customers.

(4) Phased-in rates. If the in-force tariff contains rates that are phased in over time, the provisions of this paragraph apply.

(A) Unless determined otherwise by the commission, the schedule in the tariff for the effective period of each phase will be applied to the customers of the acquired water or sewer system. To moderate the effects of a rate increase on customers, the commission may approve authorized acquisition rates that start customers of the acquired water or sewer system on an earlier phase than is in place for the customers to which the tariff already applies or establish a different schedule for the effective period of each phase.

(B) The transferee's application must include financial projections, rate schedules, and billing comparisons, consistent with the requirements of subsection (d) of this section, for each phase in the in-force tariff.

(C) The commission's review of whether the authorized acquisition rates are just and reasonable under subsection (f) of this section will include an evaluation of whether the final phase of the requested rates are just and reasonable.

(5) Public interest determination. If a transaction includes a request by the transferee to charge authorized acquisition rates, the commission will consider whether approving such rates would serve the public interest.

(d) Application. In addition to other applicable requirements, a request for authorized acquisition rates in a §24.239 proceeding must include the following:

(1) a rate schedule showing the existing rates and the requested authorized acquisition rates;

(2) financial projections including a comparison of expected revenues under the acquired water or sewer system's existing rates and the requested authorized acquisition rates;

(3) a billing comparison for usage of 5,000 and 10,000 gallons at existing rates and the requested authorized acquisition rates;

(4) documentation from the most recent base rate case in which the rates that the transferee is requesting to use as authorized acquisition rates were approved; this documentation must be sufficient to allow the commission to evaluate what was included in the revenue requirement for the requested rates and, if available online, may consist solely of a web address where the documentation can be located and the applicable docket number or any other information required to locate the documentation;

(5) a disclosure of whether the transferor and transferee are or have been affiliates in the five-year period before the proposed acquisition, and the nature of each applicable affiliate relationship;

(6) additional explanation, including any applicable documentation, supporting the request to charge authorized acquisition rates, including:

(A) that the requested authorized acquisition rates would be just and reasonable rates for the customers of the acquired system and for the transferee;

(B) how approving the requested rates would change how the commission should evaluate whether the proposed transaction would serve the public interest;

(C) if the transferee has multiple eligible in-force tariffs or rate schedules, a list of eligible tariffs or rate schedules and an explanation for the tariff or rate schedules the transferee proposes to use for authorized acquisition rates;

(D) if the transferor and transferee are affiliates or have been affiliates in the five-year period before the proposed acquisition, the application must also include an explanation for why the transferee is requesting to charge authorized acquisition rates instead of using other available ratemaking proceedings.

(e) Notice requirements. Unless the commission waives notice in accordance with other applicable law, a transferee requesting approval to charge authorized acquisition rates under this section must, as part of the notice provided under §24.239 of this title, also provide notice of the information outlined in this subsection. Commission staff must incorporate this information into the notice provided to the transferee for distribution after the application is determined to be administratively complete.

(1) How intervention differs from protesting a rate increase.

(2) A rate schedule showing the existing rates and the authorized acquisition rates.

(3) A billing comparison for usage of 5,000 and 10,000 gallons at existing rates and authorized acquisition rates.

(f) Commission review. The commission will, with or without a public hearing, investigate the request for authorized acquisition rates to determine whether the requested rates are just and reasonable for the acquired customers and the transferee. That a regulatory authority has determined that the requested rates are just and reasonable for a water or sewer system to which the rates already apply is not, in itself, sufficient to conclude that the requested rates are just and reasonable for the acquired water or sewer system.

(1) Public hearing. As part of its determination on whether to require a public hearing on the proposed transaction under §24.239 of this title, the commission will also consider whether a hearing is required to determine if the requested authorized acquisition rates are just and reasonable.

(A) If the commission requires a public hearing under this section or §24.239 of this title, the request to charge authorized acquisition rates will not be approved unless the commission determines that the requested rates are just and reasonable.

(B) If the commission does not require a public hearing under this section or §24.239 of this title, and the transferee has complied with the notice provisions of this section, the request to charge authorized acquisition rates will be approved in the commission's order approving the transaction. This subparagraph does not apply if the commission does not approve the transaction.

(2) Scope of rate review. The commission will determine whether the requested rates are just and reasonable based on the relevant facts and circumstances, subject to the limitations of subparagraph (A) of this paragraph.

(A) The transferee is not required to support its request for authorized acquisition rates by initiating a rate proceeding, establishing the cost of service for the acquired water or sewer system, or establishing substantial similarity between the acquired water or sewer system and the water or sewer system to which the requested rates already apply. The transferee is also not required to defend the reasonableness of the requested rates, or any individual component of those rates, with respect to any water or sewer system to which the rates already apply.

(B) The commission may consider whether any charges or significant components of the requested authorized acquisition rates (e.g., local or system-specific charges, pass throughs, etc.) would be unjust or unreasonable if applied to the acquired water or sewer system. The commission may also consider evidence of whether the customers of the acquired water or sewer system are currently receiving continuous and adequate service. The commission may also consider evidence of whether the requested rates are generally consistent with the rates charged to similar water or sewer systems. The commission's review is not limited to the factors enumerated in this subparagraph.

§24.243. Purchase of Voting Stock or Acquisition of a Controlling Interest in a Utility.

(a) A utility may not purchase voting stock, and a person may not acquire a controlling interest, in a utility doing business in this state unless the utility or person files a written application with the commission no later than the 61st day before the date on which the transaction is to occur. A controlling interest is defined as:

(1) a person or a combination of a person and the person's family members that possess at least 50% of a utility's voting stock; or

(2) a person that controls at least 30% of a utility's voting stock and is the largest stockholder.

(b) A person acquiring a controlling interest in a utility is required to demonstrate adequate financial, managerial, and technical capability for providing continuous and adequate service to the requested area and to the person's certificated service area, if any.

(c) If the person acquiring a controlling interest cannot demonstrate adequate financial capability, the commission may require the person to provide financial assurance to ensure continuous and adequate utility service is provided to the service area. The commission will set the amount of financial assurance. The form of the financial assurance must be as specified in §24.11 of this title relating to Financial Assurance. The obligation to obtain financial assurance under this chapter does not relieve an applicant from any requirements to obtain financial assurance in satisfaction of another state agency's rules.

(d) The commission may require a public hearing on the transaction if a criterion prescribed by §24.239 of this title relating to Sale, Transfer, Merger, Consolidation, Acquisition, Lease, or Rental applies.

(e) Unless the commission requires that a public hearing be held, the purchase or acquisition may be completed as proposed:

(1) at the end of the 60-day period; or

(2) at any time after the commission notifies the person or utility that a hearing will not be required.

(f) If a hearing is required or if the person or utility fails to make the application to the commission as required, the purchase of voting stock or acquisition of a controlling interest may not be completed unless the commission determines that the proposed transaction serves the public interest. A purchase or acquisition that is not completed in accordance with the provisions of this section is void.

(g) The utility or person must notify the commission within 30 days after the date that the transaction is completed.

(h) Within 30 days of the commission order that allows a utility's purchase of voting stock or a person's acquisition of a controlling interest to proceed as proposed, the utility purchasing voting stock or the person acquiring a controlling interest must file a written update on the status of the transaction. A written update must also be filed every 30 days thereafter, until the transaction has been completed.

(i) Except as otherwise provided by this section, the commission order granting approval for the transaction to proceed expires 180 days after the date the order is issued. If the transaction has not been completed within the 180-day period, the commission's approval to proceed with the transaction will expire by operation of law unless, prior to the expiration of the 180-day period, the commission in writing extends the period.

(j) Expedited acquisition of voting stock or controlling interest. An eligible applicant may apply for the expedited acquisition of the voting stock or controlling interest and, if applicable, the certificated service area of a utility in accordance with this subsection.

(1) Eligibility. To be eligible for expedited acquisition under this subsection, an applicant must meet the criteria in subparagraphs (A) and (B) of this paragraph.

(A) Prior to filing an application for expedited acquisition, an applicant must, for the utility being acquired, be either:

(i) a person appointed by the commission or TCEQ as a temporary manager or supervisor; or

(ii) appointed as a receiver at the request of the commission or TCEQ.

(B) In addition to meeting one of the criteria under subparagraph (A) of this paragraph, an applicant must also be either:

(i) a Class A utility;

(ii) a Class B utility;

(iii) a municipally owned utility;

(iv) a county;

(v) a water supply or sewer service corporation;

(vi) a public utility agency; or

(vii) a district or river authority.

(2) Application.

(A) An application filed by an eligible applicant under paragraph (1) of this subsection must comply with the requirements of this section, except that the following are waived:

(i) any public notice requirements required by this chapter, regardless of whether the person elects to charge initial rates in accordance with §24.240 of this title (relating to Water and Sewer Utility Rates After Acquisition) or use a voluntary valuation determined under §24.238 of this title (relating to Fair Market Valuation); and

(ii) as applicable, any requirements of this chapter that do not apply to an entity over which the commission does not have original rate jurisdiction.

(i) the service area to be acquired; and

(ii) any areas currently certificated to the applicant or, as applicable to municipally owned utilities or districts, any areas being served by the applicant.

(3) Commission approval and effects of approval.

(A) The commission will approve an application under this subsection if the commission considers the transaction to be in the public interest in accordance with the processes specified under Texas Water Code §13.246 and §13.301. In determining whether the transaction is in the public interest, the commission may also consider whether the applicant is currently in compliance with commission rules, orders, and other applicable law.

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 December 12, 2025.

TRD-202504618

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 1, 2026

Proposal publication date: September 5, 2025

For further information, please call: (512) 936-7244

SUBCHAPTER K. ENFORCEMENT, SUPERVISION, AND RECEIVERSHIP

16 TAC §24.357, §24.363

Cross reference to statutes: Texas Water Code §§ 13.041(a) and (b), 13.043(f-1), 13.301, 13.3021, 13.412(g); §13.4132(a) and (a-1).

§24.357. Operation of a Utility by a Temporary Manager.

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

(1) Person--a natural person, a partnership of two or more persons having a joint or common interest, a mutual or cooperative association, a water supply or sewer service corporation, a corporation, a municipally owned utility, a county, a public utility agency, or a district or authority created under Section 52, Article III, or Section 59, Article XVI, Texas Constitution.

(2) Temporary manager--a willing person appointed by the commission or the Texas Commission on Environmental Quality to temporarily manage and operate a utility.

(b) The commission may appoint a willing person to temporarily manage and operate a utility that has discontinued or abandoned operations or the provision of service, or which has been or is being referred to the attorney general for the appointment of a receiver under TWC §13.412.

(c) A person appointed under this section has the powers and duties necessary to ensure the continued operation of the utility and the provision of continuous and adequate service to customers, including the power and duty to:

(1) read meters;

(2) bill for utility services;

(3) collect revenues;

(4) disburse funds;

(5) request rate increases if needed;

(6) access all system components;

(7) conduct required sampling;

(8) make necessary repairs; and

(9) perform other acts necessary to assure continuous and adequate utility service as authorized by the commission.

(d) Upon appointment by the commission, the temporary manager will post financial assurance with the commission in an amount and type acceptable to the commission. The temporary manager or the executive director may request waiver of the financial assurance requirements or may request substitution of some other form of collateral as a means of ensuring the continued performance of the temporary manager.

(e) The temporary manager must serve a term of 180 days, unless:

(1) specified otherwise by the commission;

(2) an extension is requested by the commission staff or the temporary manager and granted by the commission;

(3) the temporary manager is discharged from his responsibilities by the commission; or,

(4) a superseding action is taken by an appropriate court on the appointment of a receiver at the request of the attorney general.

(f) Within 60 days after appointment, a temporary manager must return to the commission an inventory of all utility property.

(g) Compensation for the temporary manager will come from utility revenues and will be set by the commission at the time of appointment. The commission may adjust the compensation for the temporary manager as it deems necessary.

(h) The temporary manager must collect the assets and carry on the business of the utility and shall use the revenues and assets of the utility in the best interests of the customers to ensure that continuous and adequate utility service is provided. The temporary manager must give priority to expenses incurred in normal utility operations and for repairs and improvements made since being appointed temporary manager.

(i) The temporary manager shall report to the commission on a monthly basis. This report shall include:

(1) an income statement for the reporting period;

(2) a summary of utility activities such as improvements or major repairs made, number of connections added, and amount of water produced or treated; and

(3) any other information required by the commission.

(j) During the period in which the utility is managed by the temporary manager, the certificate of convenience and necessity shall remain in the name of the utility owner; however, the temporary manager assumes the obligations for operating within all legal requirements.

§24.363. Temporary Rates for Services Provided for a Nonfunctioning System.

(a) Notwithstanding other provisions of this chapter, upon sending written notice to the commission, a retail public utility other than a municipally owned utility or a water and sewer utility subject to the original rate jurisdiction of a municipality that takes over the provision of services for a nonfunctioning retail public water or sewer utility service provider may immediately begin charging the customers of the nonfunctioning system a temporary rate to recover the reasonable costs incurred for interconnection or other costs incurred in making services available and any other reasonable costs incurred to bring the nonfunctioning system into compliance with commission rules.

(b) Notice of the temporary rate must be provided to the customers of the nonfunctioning system no later than the first bill which includes the temporary rates.

(c) Within 90 days of receiving notice of the temporary rate increase, the commission will issue an order regarding the reasonableness of the temporary rates. In making the determination, the commission will consider information submitted by the retail public utility taking over the provision of service, the customers of the nonfunctioning system, or any other affected person.

(d) At the time the commission approves an acquisition of a nonfunctioning retail water or sewer utility service provider under Texas Water Code (TWC) §13.301, the commission must:

(1) determine the duration of the temporary rates to the retail public utility, which must be for a reasonable period; and

(2) rule on the reasonableness of the temporary rates under subsection (a) of this section if the commission did not make a ruling before the application was filed under TWC §13.301.

(e) Regulatory asset. This section applies only to an expedited sale, transfer, or merger application under §24.239 of this title (relating to Sale, Transfer, Merger, Consolidation, Acquisition, Lease, or Rental) or §24.243 of this title (relating to Purchase of Voting Stock or Acquisition of a Controlling Interest in a Utility).

(1) If a temporary rate is adopted during the term of a person's temporary management, receivership, or supervision of a utility, then the person's used and useful invested capital and just and reasonable operations and maintenance costs that are incurred by the person during the person's appointment as temporary manager, receiver, or supervisor that are in excess of the costs covered by the temporary rate are considered to be a regulatory asset.

(2) This regulatory asset is eligible for recovery in the person's next comprehensive rate proceeding or system improvement charge application and will be reviewed for prudence in the utility's next comprehensive base rate proceeding.

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 December 12, 2025.

TRD-202504619

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 1, 2026

Proposal publication date: September 5, 2025

For further information, please call: (512) 936-7244

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

The Public Utility Commission of Texas (commission) adopts amended 16 Texas Administrative Code (TAC) §25.5, relating to Definitions, §25.181, relating to Energy Efficiency Goal, and §25.182, relating to Energy Efficiency Cost Recovery Factor. The commission adopts these rules with changes to the proposed text as published in the September 5, 2025 issue of the Texas Register (50 TexReg 5833). Adopted amendments to §25.181 change ERCOT's calculations of the avoided cost of energy and the deadline by which ERCOT files these calculations with the commission. The amendments also clarify the distinction between a targeted low-income program and a program for hard-to-reach customers. Adopted amendments to §25.182 reduce the maximum utility incentive a utility can receive. Other amendments to these rules include changes to definitions in both §25.5 and §25.181 and minor and conforming changes. The rules will be republished.

The commission received comments on the proposed rule from AEP Texas Inc. (AEP Texas), the American Council for an Energy-Efficient Economy (ACEEE), CenterPoint Energy Houston Electric, LLC (CenterPoint), the City of Houston (Houston), El Paso Electric Company, Entergy Texas, Inc., Southwestern Electric Power Company, and Southwestern Public Service Company (collectively, Joint Utilities), the Lone Star Chapter of the Sierra Club (Sierra Club), the Office of Public Utility Counsel (OPUC), Oncor Electric Delivery Company, LLC (Oncor), the South-Central Partnership for Energy Efficiency as a Resource (SPEER), the Steering Committee of Cities Served by Oncor (OCSC), Texas-New Mexico Power Company (TNMP), and Vistra Corporate Service Company, LLC (Vistra).

General Comments

Sierra Club filed general comments urging the commission to undertake a more comprehensive rulemaking. Several hundred Sierra Club members signed this petition. In addition, approximately 250 Sierra Club members submitted individual comments in connection with this petition. The individual commenters raised concerns about energy costs, climate change, and electric utilities in general, and supported use of renewable sources of electricity and protect the environment.

Commission Response

Comments requesting that the commission undertake a comprehensive rulemaking are beyond the scope of the current rulemaking. The current rulemaking's scope is limited to consideration of the proposed rule amendments, additional modifications to the rules that are reasonably related to the proposed changes, and other minor and nonsubstantive amendments. However, the commission will begin a comprehensive rulemaking process after these amendments are adopted.

In addition, comments concerning energy costs, climate change, electric utilities in general, renewable sources of electricity, and environmental protection are beyond the scope of the rules included in this rulemaking.

Changes in commission's approach to low-income and hard-to-reach customers

Proposed §§25.181(c)(17) and 25.181(e)(3)(F)- Definition of "hard-to-reach" and demand reduction requirement for hard-to-reach customers

Proposed §25.181(c)(17) defines "hard-to-reach" as a customer that either has a primary residence in an area with fewer than 2,000 housing units or a total population of 5,000 or less; or has a primary residence or owns a small business in an area where the utility is unable to effectively administer an energy efficiency program due to energy efficiency market barriers. Proposed §25.181(e)(3)(F) requires a utility to achieve at least five percent of its demand reduction goal through savings achieved through programs for hard-to-reach customers; in addition, a utility that operates in an area in which customer choice is not offered may achieve this requirement through a program designed for low-income customers.

OPUC, Sierra Club, SPEER, ACEEE, and OCSC supported the proposed definition, and AEP Texas, CenterPoint, Oncor, TNMP, and Joint Utilities commented that low-income customers should continue to be included in the definition of "hard-to-reach." Specifically, the utilities commented that they have based their hard-to-reach programs on serving low-income customers since the inception of the hard-to-reach concept in the commission's energy efficiency rule, and that a policy shift such as the one in the proposed rule will have a drastic negative effect on their ability to achieve their hard-to-reach goals.

AEP Texas suggested that the commission clarify the term "area" because this term is vague. Vistra commented that "limited access to an energy efficiency contractor or energy efficiency service provider" in §25.181(c)(17)(B) is too vague, subjective, and challenging to verify and recommended deleting the entire subparagraph. OCSC also noted that "area" and "effectively administer an energy efficiency program" are ambiguous and would be difficult for utilities and commission staff to verify and recommended that the proposed rule be modified to require a utility to provide evidence in its energy efficiency cost recovery factor (EECRF) application as to why an area is hard to reach.

Vistra argued that the change from an income-based definition to a definition based on demographic restrictions or limited access to a service provider could include unintended customers. Specifically, Vistra argued that the amended definition will likely include a large, rural landowner who, under the existing definition, would have been excluded from eligibility as a hard-to-reach customer.

Oncor suggested that if the commission adopts the proposed revision, it should phase in the change over time to allow utilities sufficient time to design new programs, identify new program delivery channels, and implement this change.

The utilities provided redlines consistent with their comments.

Commission Response

The commission agrees that low-income customers, who have historically been served by hard-to-reach programs, should continue to be included as potential hard-to-reach customers. Therefore, the commission modifies the definition of "hard-to-reach" in adopted §25.181(c)(17) to include low-income as a category of hard-to-reach. However, the adopted rule also maintains the expanded proposed definition of "hard-to-reach" so that utilities can expand their programs beyond the traditionally served low-income customers to those that may not have been served historically. Under the modified definition, a large, rural landowner could be a hard-to-reach customer, and this outcome is intended.

The commission also agrees with comments regarding the clarity of the term "area" in the proposed definition and modifies the definition to describe a "county, city, or unincorporated area." For clarity, the commission further modifies the definition to describe a hard-to-reach customer as one that the utility has been unable to serve in at least one of the past five years due to lack of available energy efficiency contractors or energy efficiency service providers.

Lastly, the commission modifies the definition to replace the term "small business" with "a commercial customer with a peak load less than 50 kW that is not a government entity and not a subsidiary of a corporation." Section 25.181 defines "commercial customer" as "a non-residential customer taking service at a point of delivery at a distribution voltage under an electric utility's tariff during the prior program year or a non-profit customer or government entity, including an educational institution." The modified definition of "hard-to-reach" limits the hard-to-reach commercial customer to non-government entities. In addition, the commission agrees with commenters that recommended that a small business be identified by its peak load. However, the adopted rule limits a hard-to-reach commercial customer to a peak load less than 50 kW because under §25.181, 50 kW is the minimum load for a commercial customer to be its own energy efficiency service provider.

With these modifications to the proposed definition, a phase-in period for the changes to take effect is unnecessary.

Proposed §25.181(c)(25)- Definition of "low-income"

Proposed §25.181(c)(25) defines "low-income" as describing a customer that either meets the criteria for low-income based on a calculation of 80% of the area median income, or resides in a household in which at least one person receives economic assistance through a program listed in the Texas technical reference manual (TRM) for the applicable program year. Existing §25.5 also includes a definition for "low-income customer" that is based on whether the customer qualifies for the Supplemental Nutrition Assistance Program or medical assistance from a state agency.

OPUC, Sierra Club, and SPEER supported the proposal. OCSC and Vistra commented that there should be consistency between the definitions in §25.5 and §25.181. TNMP commented that the proposed definition is overly restrictive and suggested that the definition be more inclusive of different types of low-income households. AEP Texas, Joint Utilities and Oncor were unopposed to changing from a low-income standard set by the United States Department of Health and Human Services (HHS)--200% of the federal poverty level--to the low-income standard set by the United States Department of Housing and Urban Development (HUD)--80% of area median income. However, AEP Texas and Joint Utilities suggested that the commission retain the ability for a utility to identify a low-income customer through a geographic indicator, such as location in a HUD-qualifying low-income census tract or block. This geographic qualifier already exists in the TRM as a way to identify a low-income customer. CenterPoint recommended that the commission provide a 12-month transition period to allow utilities to update program design, tracking, and reporting systems.

ACEEE recommended that the definition provide categorical eligibility to customers who qualify as low income through assistance programs, such as the Low-Income Home Energy Assistance Program, Supplemental Nutrition Assistance Program, Supplemental Security Income, and others.

AEP Texas, Joint Utilities, Oncor, and TNMP provided redlines consistent with their comments.

Commission Response

The commission agrees that the adopted rules should clearly delineate the difference between the two similar, though not identical, terms. The term "low-income customer," defined in §25.5, is used exclusively in §25.45, relating to Low-Income List Administrator. The customers qualified for programs under §25.45 are a subset of the customers qualified for programs described in §25.181. The definition of "low-income" in §25.181 is intentionally more expansive than the definition of a "low-income customer" in §25.5, so that a utility can reach more customers through a targeted low-income energy efficiency program or a hard-to-reach program. Therefore, the commission declines to modify the proposed definition for consistency between the two sections. In addition, the commission declines to modify the rule to adopt ACEEE's suggestion because the adopted rule refers to programs mentioned by ACEEE in paragraph (B).

However, the commission agrees that the rule should allow a low-income customer to be identified through residence in a HUD-qualifying low-income census tract or block and modifies the definition accordingly.

With these modifications to the proposed definition, a phase-in period for the changes to take effect is unnecessary.

Proposed §25.181(p)--Targeted low-income energy efficiency program

Proposed §25.181(p) describes the requirements for a targeted low-income energy efficiency program. Existing §25.181 requires an ERCOT utility, and allows a non-ERCOT utility, to provide a targeted low-income energy efficiency program. Annual expenditures for the targeted low-income energy efficiency program must be at least 10% of a utility's energy efficiency budget for the program year.

In conjunction with edits to the definitions of a low-income customer and a hard-to-reach customer in §25.181(c), the commission modifies this subsection to clarify requirements for a targeted low-income energy efficiency program. First, paragraph (1) and its subparagraphs apply to all utilities that offer a targeted low-income energy efficiency program. Paragraph (2) and its subparagraphs apply only to ERCOT utilities, and requirements from PURA §39.905 are described in this paragraph. Second, the commission clarifies in paragraph (1)(C) that, although a utility may shift funds from a targeted low-income energy efficiency program to a hard-to-reach program after July of a program year, such funds may not be used to satisfy the requirement for a utility to spend 10% of its budget on a targeted low-income energy efficiency program. Third, the commission adds paragraph (1)(D) to clarify that demand reduction achieved through a targeted low-income energy efficiency program may not be used to satisfy the hard-to-reach demand reduction requirement in §25.181(e)(3)(F).

Definitions

Existing §25.181(c)(17) and §25.5(46)- Definition of "energy efficiency service provider"

The proposed rule strikes existing §25.181(c)(17), the definition of "energy efficiency service provider (EESP)," because this term is already defined at §25.5(46). However, the definitions in the two sections differ; specifically, in §25.181, the struck definition states that a commercial customer that serves as an energy efficiency service provider must have a peak load equal to or greater than 50 kW, and that an energy efficiency service provider may also be a governmental entity or a non-profit organization, but may not be an electric utility.

TNMP, Oncor, Joint Utilities, and AEP Texas suggested that the commission retain the definition of EESP because it is frequently used throughout §25.181 and for clarity and ease of reference. Specifically, Oncor noted that §25.181(s) indicates that a commercial customer with a peak load exceeding 50 kW can itself be an energy efficiency provider, a provision that is also included in the definition of EESP. However, Oncor stated that having this provision in a definition, rather than in §25.181(s), would be helpful, and that the current definition also includes other categories of entities. OCSC commented that EESP is also defined in §25.5, but that the differences between the two definitions are significant enough that the parts that had been included in §25.181 should be retained, either in §25.5 or in §25.181.

Commission Response

The commission agrees that the definition of "energy efficiency service provider" in existing §25.181 is necessary and helpful and modifies §25.181(c) to restore this definition. In addition, the commission removes the same definition from §25.5 because it is superfluous.

Proposed §25.5(124)- Definition of "small business"

Proposed §25.5(124) defines "small business" as a legal entity, including a corporation, partnership, or sole proprietorship, that: (A) is formed for the purpose of making a profit; (B) is independently owned and operated; and (C) has fewer than 100 employees or less than $6 million in annual gross receipts.

AEP Texas, CenterPoint, and Joint Utilities suggested striking proposed §25.5(124)(A) and (B) because they asserted that this information would be difficult for a utility, program implementer, or program participant to verify. Similarly, TNMP suggested striking (A), (B), and (C) of the proposed definition. On the other hand, Oncor suggested connecting proposed (A), (B), and (C) with "or" instead of "and." Each utility also suggested adding a new paragraph defining a small business based on average monthly demand. AEP Texas, CenterPoint, Joint Utilities and Oncor recommended 100 kW as the maximum average monthly demand, and TNMP recommended 200 kW as the maximum.

TNMP also suggested that the commission not limit the definition of small business to for-profit companies.

Commission Response

The commission has modified the definition of "hard-to-reach" to eliminate the use of the term "small business." For this reason, the term "small business" does not need to be defined and is removed.

Proposed §25.5(78)- Definition of "new on-site generation"

Proposed §25.5(78) includes a reference to the Texas Natural Resource Conservation Commission (TNRCC).

Sierra Club included a clerical edit to change TNRCC to the Texas Commission on Environmental Quality because that is the current name of the commission that fulfills the function in this definition.

Commission Response

The commission agrees and modifies the rule accordingly.

Proposed §25.181(c)(32)- Definition of "peak demand"

Proposed §25.181(c)(32) strikes the following sentence from the definition of "peak demand": "Peak demand refers to Texas retail peak demand and, therefore, does not include demand of retail customers in other states or wholesale customers."

Joint Utilities and OCSC recommended that the definition continue to include the struck sentence. Joint Utilities cited clarity for this edit, and OCSC cited certainty.

Commission Response

The commission disagrees that the sentence should be reinstated for clarity. The limitation is already addressed in §25.181(e)(3)(A).

Proposed §25.181(c)(33)- Definition of "peak period"

Proposed §25.181(c)(33) strikes the exclusion of weekends and Federal holidays in the definition of "peak period."

TNMP, Oncor, Joint Utilities, and AEP Texas opposed this proposed revision. TNMP stated that the change could have a wide-ranging impact on calculation of savings and require costly recalculations for evaluation, measurement, and verification (EM&V) and suggested that this change be considered at length. Oncor, Joint Utilities, and AEP Texas stated that the proposed revision directly conflicts with the Texas Technical Reference Manual (TRM)'s calculation method for demand savings--Oncor specifically cited Volume 1, Section 4 of the TRM. Joint Utilities also stated that the proposed revision is contrary to known industry standard practice.

Commission Response

The commission declines to modify the proposed rule. However, the schedule for implementation of this amendment will account for necessary changes to the TRM in 2026. The commission modifies subsection (o)(6)(F) of the proposed rule to state that for program year (PY) 2026, a utility must use the peak period calculation method outlined in the TRM adopted in 2025. The commission also modifies the same provision to state that, starting with PY2027, a utility must use the peak period calculation method outlined in the most recently adopted TRM.

Existing §25.181(c)(35)- Definition of "load control"

The proposed rule strikes existing §25.181(c)(35), the definition of "load control," because the only place in the rule where the term appears is in the definition of "load management."

OCSC opposed removal of this definition because load control is a type of load management, and utilities may still include load control programs in their energy efficiency plans.

Commission Response

The commission declines to modify the proposed rule. The adopted rule does not preclude a utility from including a load control program in its energy efficiency plan.

Proposed §25.181(c)(35)- Definition of "projected savings"

Proposed §25.181(c)(35) defines "projected savings" as the "estimated program or portfolio savings reported by an electric utility for planning purposes."

OCSC recommended adding "energy or demand" before "savings" because, it asserted, the term "savings" is too broad and could mean a multitude of things.

Commission Response

The commission agrees and adds "demand reduction or energy" to modify "savings" in the definition.

Proposed §25.181(c)(7)- Definition of "deemed savings value"

Proposed §25.181(c)(7) uses the phrase "energy or demand savings" in the first sentence and "energy and peak demand savings" in the second sentence.

OCSC suggested a clerical edit to change "and" to "or" in the second sentence for consistency with the first sentence and with the definition of "deemed savings calculation."

Commission Response

The commission agrees and modifies the rule accordingly.

Proposed §25.181(c)(24)- Definition of "load management"

Proposed §25.181(c)(24) defines "load management" as "Activities that result in a reduction in peak demand, or a shifting of energy usage from a peak to an off-peak period or from high-price periods to lower price periods."

OCSC recommended adding "temporary" to the definition, so that the definition would read, "Activities that result in a temporary reduction in peak demand. . . ." OCSC reasoned that reductions in peak demand from load management are temporary, not a permanent reduction, and that the definition should reflect the temporary result.

Commission Response

Although the commission agrees that adding "temporary" to the definition would reflect reality, this provision was not substantively edited in the proposal, and substantive modifications, such as OCSC's suggestion, are beyond the scope of the proposal.

Proposed §25.181(d)(2)- Avoided cost of capacity

Proposed §25.181(d)(2) requires the avoided cost of capacity to be established as described in the subparagraphs and clauses within (d)(2) of the proposed rule.

Vistra commented that the avoided cost of capacity should be removed from the rule as part of the cost-effectiveness standard because customers who save energy through demand reduction and other energy efficiency activities avoid energy costs but not capacity costs, and this is because the current ERCOT market design does not ascribe value to generation capacity.

Commission Response

The commission declines to adopt the recommended modification because it is beyond the scope of this rulemaking.

Proposed §25.181(d)(2)(A)- Filing date of avoided cost of capacity

Proposed §25.181(d)(2)(A) requires the avoided cost of capacity to be filed by November 1 of each year.

Joint Utilities suggested that the avoided cost of capacity be filed at the same time of year that the proposed rule requires that the avoided cost of energy be filed, April 1.

Commission Response

The commission declines to adopt the recommended modification because it is beyond the scope of this rulemaking.

Proposed §25.181(d)(3)(A)- Avoided cost of energy

Proposed §25.181(d)(3)(A) requires ERCOT to file its calculation of the avoided cost of energy for the upcoming calendar year by April 1 of each year. Subsection (d)(3)(A) of the proposed rule also requires ERCOT to use seven years of data in its calculation.

Filing date

ACEEE, Sierra Club, SPEER, and Houston supported the proposed revision to the filing date. CenterPoint, Joint Utilities, TNMP, and Oncor suggested moving the effective date of the avoided cost of energy rather than the filing date. Those parties recommended making the avoided cost of energy effective the January 1 that falls 14 months after its filing date.

Commission Response

The commission agrees that additional time between the filing date and effective date for avoided cost of energy would be beneficial. An additional seven months is sufficient to realize this benefit. Commenters were not persuasive that extending what is currently a two-month process to fourteen months is reasonable. The commission therefore declines to modify the proposed rule.

Avoided cost of energy calculations

CenterPoint, OPUC, Sierra Club, SPEER, and Houston, and OCSC supported the proposed revision to use seven years of data, although OCSC recommended explicitly excluding data from Winter Storm Uri. Joint Utilities did not oppose the proposed revision but recommended using five years of data instead. AEP Texas and TNMP also recommended using five years of data. Commenters recommending five years reasoned that the avoided cost of energy calculation should align with the five-year requirement in §25.181(e)(3)(A) for calculation of the demand reduction goal.

Commission Response

The commission declines to modify the proposed rule to require ERCOT to use five years of data to calculate the avoided cost of energy.

The concept of avoided cost of energy differs from the concept of estimating load growth that occurred strictly in the past. The avoided cost of energy is calculated as a lookback on what the utility, or the customer, might have spent on energy costs but for the energy efficiency programs that the utility offers to its customers. However, the benefits to the customer do not end with the purchase or installation of an energy efficiency measure. The benefits extend to the estimated useful life of the measure, which in some cases is ten or 15 years into the future. Because ERCOT's data retention is only seven years in the past, it can only approximate the avoided cost to the customer, but it is the best approximation the commission has access to at this time. Furthermore, the more years that are used to calculate the avoided cost of energy, the less it will fluctuate from year to year, providing more certainty for the year-over-year cost-benefit ratio calculations and for a utility planning its programs for the year ahead.

The commission also agrees with OCSC that any data associated with Winter Storm Uri should be excluded from the calculation of the avoided cost of energy. The commission found in Docket Number 52871, Commission Staff's Petition for a Good Cause Exception to 16 Texas Administrative Code §25.181(d)(3)(A) and to Set the Avoided Cost of Energy under §25.181(d)(3)(A) for 2022 Electric Utility Energy Efficiency Programs, that the unique circumstances caused by Winter Storm Uri constituted good cause to reduce the avoided cost of energy for the 2022 program year. Consistent with that finding, the commission modifies the proposed rule language.

Proposed §25.181(e)(3)(F)- Hard-to-reach goal and non-ERCOT utilities

Proposed §25.181(e)(3)(F) allows a utility that operates in an area in which customer choice is not offered to achieve the hard-to-reach goal through a program designed for low-income customers.

Sierra Club stated that it supported giving flexibility to utilities that operate in the ERCOT competitive market.

Commission Response

Proposed §25.181(e)(3)(F) does not apply to utilities that operate in the ERCOT market.

However, because the commission modifies the definition of "hard-to-reach" in adopted §25.181(c)(17) to include a low-income customer, the commission strikes the provision in (e)(3)(F) of the proposed rule that would allow a non-ERCOT utility to achieve its hard-to-reach requirement through a program designed for low-income customers.

Proposed §§25.181(e)(3)(F) and 25.181(p)(1)- Hard-to-reach and low-income goals

Proposed §25.181(e)(3)(F) requires a utility to achieve at least 5.0% of its total demand reduction goal through savings achieved through programs for hard-to-reach customers. Proposed §25.181(p)(1) requires a utility to spend at least 10% of its annual budget on a targeted low-income energy efficiency program.

Sierra Club recommended increasing the low-income budget requirement from 10% to 20% of a utility's annual budget.

Commission Response

The commission declines to adopt the recommended modification because it is beyond the scope of this rulemaking.

Proposed §25.181(l)- Commission-prescribed Excel form

Proposed §25.181(l) requires a utility's energy efficiency plan and report (EEPR) to include a completed attachment based on the commission-prescribed Excel template in addition to the EEPR content already required by the rule.

Joint Utilities and TNMP filed an Excel template for all EEPR tables that they recommended the commission adopt in place of the proposed summary Excel tables, and AEP Texas supported the adoption of this Excel template. CenterPoint and Sierra Club supported the proposed template and filing requirements.

Commission Response

The commission declines to adopt the recommended template. Development of a full EEPR template is outside the scope of this rulemaking. The Excel template in the adopted rule is an additional summary of the information in the annual EEPR filings, not a replacement of what the existing rule requires.

Proposed §25.182(d)- Cost effectiveness at the program or portfolio level

Proposed §25.182(d) requires a utility to provide a portfolio of cost-effective energy efficiency programs.

TNMP stated that the commission should require a utility to provide a cost-effective portfolio of energy efficiency programs, not a portfolio of cost-effective energy efficiency programs.

Commission Response

The commission declines to adopt the suggested modification because it is a substantive change that is not reasonably related to the proposed changes.

Proposed §25.182(d)(7)- Historical cost caps

The proposed rule strikes §25.182(d)(7)(A), which was the residential cost cap for program year 2018, and (d)(7)(B), which was the commercial cost cap for program year 2018.

TNMP and Oncor recommended that the commission maintain §25.182(d)(7)(A) and (B) for historical lookback purposes.

Commission Response

The commission agrees that the historical cost caps should be maintained and modifies the rule accordingly.

Proposed §§25.181 and 25.182- Shareholder bonus or utility incentive

Throughout proposed §§25.181 and 25.182, the proposal replaces the term "shareholder bonus" with the term "utility incentive."

TNMP recommended that the commission maintain the term "shareholder bonus" where it appears in the existing rule because "shareholder bonus" is consistent with PURA §39.905(b)(4).

Commission Response

The commission disagrees with the recommendation. The term "shareholder bonus" appears in PURA §39.905(b)(4); however, PURA §39.905(b)(2) requires the commission to "adopt rules and procedures to ensure that the utilities can achieve the goal of this section, including establishing an incentive . . . to reward utilities . . . that exceed the minimum goals established by this section" (emphasis added). The commission finds the term "utility incentive" to be better aligned with the statute's mandate to the commission.

In addition, the commission modifies §25.181(u) to correct one instance where "shareholder bonus" appears in the proposal.

Proposed §25.182(e)(3)- Utility incentive

Proposed §25.182(e)(3) states that a utility that exceeds 100% of its demand and energy reduction goals may receive a utility incentive, reduces the maximum utility incentive a utility may receive to 5% of net benefits, rather than 10%, and allows the commission to further limit the maximum utility incentive a utility may receive for good cause.

Amendment of "shall" to "may"

AEP Texas, CenterPoint, Joint Utilities, TNMP, and Oncor opposed changing "shall" to "may" in the proposed rule. The utilities reasoned that PURA §39.905(b)(2) requires the commission "to establish an incentive . . . to reward utilities administering programs under this section that exceed the minimum goals established by this section," and that this language gives the commission no discretion whether to award an incentive to a utility that has earned one.

ACEEE supported the proposed rule language.

Commission Response

The intent of that proposed revision was concision and clarity, not to change the meaning of the rule. Therefore, the commission modifies the provision to state that if a utility exceeds its demand reduction goal, it will receive a utility incentive.

Reduction of maximum utility incentive from 10% to 5% of net benefits

AEP Texas, CenterPoint, Joint Utilities, TNMP, and Oncor opposed reducing the maximum utility incentive to 5% of net benefits, preferring instead to maintain the existing 10% maximum. Generally, the utilities were concerned that a change from 10% to 5% is an unreasonable and drastic cut that reduces the incentive's effectiveness as a policy tool. AEP Texas stated that the proposed change would decrease a utility's motivation to exceed its minimum goals and reduce the financial justification for investing in additional measures, technologies, and partnerships that drive performance beyond compliance. Oncor, Joint Utilities, and AEP Texas believed that the change in the number of years of data included in the avoided cost of energy calculation in proposed §25.181(d)(3)(A) would reduce the maximum utility incentive a utility can collect by an amount significant enough that the reduction from 10% to 5% of net benefits would not be needed. TNMP and Oncor stated that a reduction to 8% would be acceptable; Oncor noted that, under the proposed revision, a utility's incentive would be reduced by more than it would have under commission staff's proposal in Docket Number 57172. Oncor additionally argued that such a significant reduction to the maximum utility incentive would be more appropriately addressed in a future rulemaking, in which a fact-based and policy-based discussion can be held.

Joint Utilities specifically argued that the incentive serves as a "mechanism for utilities to recover lost revenue resulting from energy efficiency programs." In addition, it argued that "because the incentive cap is already structured as a share of the net benefits,' customers will inherently receive net benefits stemming from the utility's energy efficiency achievements," and that "the incentive is never a net cost to customers."

OPUC, SPEER, OCSC, and Houston supported the reduction in the maximum utility incentive to 5% of net benefits. Sierra Club proposed an alternative cap of 20% of total spending, with a 20% secondary cap. Sierra Club reasoned that utility incentives for energy efficiency programs have been extremely high, especially this year, given the high avoided cost of energy, and that this is an unstable and unfair outcome for ratepayers. Sierra Club was concerned that the proposed limitation could disincentivize utilities to perform beyond minimum requirements. Houston noted that incentive payments are a tool to drive changes in behavior or participation in programs that may not be performing at targeted levels, and that energy efficiency programs have historically performed well above targeted levels and therefore do not need incentivizing. Houston pointed out that utilities routinely exceed their demand and energy reduction goals in Texas, and that this has led to total EECRF expenses being driven by the performance bonus.

Commission Response

PURA §39.905 gives the commission discretion in setting the utility incentive amount, and the proposed reduction is an exercise of the commission's discretion in the public interest. The commission disagrees with Sierra Club's proposed alternative incentive structure because there is a more direct connection between net benefits and a utility incentive than between total program spending and a utility incentive. The commission disagrees with the characterization of the utility incentive as a mechanism to recover lost revenue.

The commission also disagrees that the incentive is never a net cost to customers. Cost recovery and the utility incentive are imposed on all customers in a utility's rate classes, other than industrial customers that opt out under §25.181(u), regardless of whether those customers directly benefit from an energy efficiency program.

Good cause limitation

AEP Texas, CenterPoint, TNMP, and Oncor opposed the proposed amendment that would allow the commission to further limit a utility's utility incentive for good cause. Oncor argued that the amendment would frustrate a utility's expectations for an earned incentive and introduce unpredictability into whether a utility would receive an incentive or how much the incentive would be. TNMP stated that the commission not only did not propose any language to determine what circumstances may give rise to good cause, but also did not propose any language to quantify by what percentage it may reduce an incentive.

Joint Utilities stated that the commission should add language to clarify the proposed revision. It argued that the purpose of a good cause exception is to recognize circumstances beyond a party's reasonable control or justified deviations from standard expectations, and that penalizing performance in these situations would undermine the intent of the good cause exception and discourage transparency and accountability. CenterPoint argued that the amendment introduced unnecessary ambiguity and conflicted with PURA §39.905(g), which, it asserted, only allows the commission to relieve utilities from penalties or sanctions for factors beyond their control, not to reduce earned incentives.

Commission Response

The commission agrees that regulatory certainty is needed in the administration of the utility incentive under §25.182 and removes the proposed amendment. The adjustment to the avoided cost of energy calculation in §25.181(d)(3)(A) and the amended utility incentive calculation in this subparagraph provide sufficient certainty to a utility in the calculation and amount of its utility incentive.

Proposed §25.182(e)(2)- Inclusion of utility incentive in net benefits

Proposed §25.182(e)(2) describes the calculation of net benefits and includes the utility incentive in program costs.

ACEEE, SPEER, and TNMP suggested that the utility incentive not be included in program costs.

Commission Response

The commission declines to adopt the recommended modification because it is a substantive change that is not reasonably related to the proposed changes.

Proposed §25.182(e)(1) and (3)- Basis for utility incentive calculation

Proposed §25.182(e)(1) states that a utility may receive a share of the net benefits realized in exceeding its demand reduction goal. The provision does not base the utility incentive on the amount by which a utility exceeds its energy savings goal. Proposed §25.182(e)(3) calculates the utility incentive using only the demand reduction goal, not the energy savings goal.

Sierra Club filed redlines recommending that the commission base the utility incentive on the amount by which a utility exceeds its demand reduction goal and its energy savings goal.

Commission Response

The commission declines to adopt Sierra Club's recommendation. The energy savings goal is not based in statute, and moreover, the recommended modification is beyond the scope of the proposal.

Proposed §§25.181 and 25.182- Effective date of rules

The proposed rules do not include any language related to the date that the changes take effect.

AEP Texas recommended that the proposed rule changes not take effect until program year PY2027. It asserted that the proposed rule changes will disrupt planning for PY2026, which is already well underway, and undermine program effectiveness.

Commission Response

The commission opened the instant rulemaking with the express goal of effectuating the contemplated amendments as quickly as practicable and therefore declines to defer the effective date. For a utility's EEPR filing in April 2026, the utility must submit the additional EEPR summary tables. The utility's EECRF application filed in May or June 2026 must meet all requirements as set out in adopted §§25.181 and 25.182, including appropriate categorization of low-income and hard-to-reach customers, and the utility incentive for PY2025 will be calculated as set forth in adopted §25.182. The avoided cost of energy that ERCOT filed in November 2025 will be applicable to PY2026, and the avoided cost of energy that ERCOT will file in April 2026 will be applicable to PY2027. However, the commission modifies subsection (o)(6)(F) of the proposed rule as discussed above to state that, for PY2026, a utility must use the peak period calculation method outlined in the TRM adopted in 2025, and starting with PY2027, a utility must use the peak period calculation method outlined in the most recently adopted TRM.

SUBCHAPTER A. GENERAL PROVISIONS

16 TAC §25.5

The 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; and §14.002, which provides the commission with the authority to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; §36.204, which authorizes the commission to establish rates for an electric utility that allow timely recovery of the reasonable costs for conservation and load management, including additional incentives for conservation and load management; and §39.905, which requires the commission to establish an incentive to reward utilities administering energy efficiency programs that exceed the minimum goals established by PURA §39.905.

Cross reference to statutes: Public Utility Regulatory Act §§14.001 and 14.002, §36.204, and §39.905.

§25.5. Definitions.

In this chapter, the following definitions apply unless the context indicates otherwise:

(1) Above-market purchased power costs--Wholesale demand and energy costs that a utility is obligated to pay under an existing purchased power contract to the extent the costs are greater than the purchased power market value.

(2) Affected person--means:

(A) a public utility or electric cooperative affected by an action of a regulatory authority;

(B) a person whose utility service or rates are affected by a proceeding before a regulatory authority; or

(i) is a competitor of a public utility with respect to a service performed by the utility; or

(ii) wants to enter into competition with a public utility.

(3) Affiliate--means:

(A) a person who directly or indirectly owns or holds at least 5.0% of the voting securities of a public utility;

(B) a person in a chain of successive ownership of at least 5.0% of the voting securities of a public utility;

(C) a corporation that has at least 5.0% of its voting securities owned or controlled, directly or indirectly, by a public utility;

(D) a corporation that has at least 5.0% of its voting securities owned or controlled, directly or indirectly, by:

(i) a person who directly or indirectly owns or controls at least 5.0% of the voting securities of a public utility; or

(ii) a person in a chain of successive ownership of at least 5.0% of the voting securities of a public utility;

(E) a person who is an officer or director of a public utility or of a corporation in a chain of successive ownership of at least 5.0% of the voting securities of a public utility; or

(F) a person determined to be an affiliate under Public Utility Regulatory Act (PURA) §11.006.

(4) Affiliated electric utility--The electric utility from which an affiliated retail electric provider was unbundled in accordance with PURA §39.051.

(5) Affiliated power generation company (APGC)--A power generation company that is affiliated with or the successor in interest of an electric utility certificated to serve an area.

(6) Affiliated retail electric provider (AREP)--A retail electric provider that is affiliated with or the successor in interest of an electric utility certificated to serve an area.

(7) Aggregation--Includes the following:

(A) the purchase of electricity from a retail electric provider, a municipally owned utility, or an electric cooperative by an electricity customer for its own use in multiple locations, provided that an electricity customer may not avoid any non-bypassable charges or fees as a result of aggregating its load; or

(B) the purchase of electricity by an electricity customer as part of a voluntary association of electricity customers, provided that an electricity customer may not avoid any non-bypassable charges or fees as a result of aggregating its load.

(8) Aggregator--A person joining two or more customers, other than municipalities and political subdivision corporations, into a single purchasing unit to negotiate the purchase of electricity from retail electric providers. Aggregators may not sell or take title to electricity. Retail electric providers are not aggregators.

(9) Ancillary service--A service necessary to facilitate the transmission of electric energy including load following, standby power, backup power, reactive power, and any other services the commission may determine by rule.

(10) Base rate--Generally, a rate designed to recover the cost of service other than certain costs separately identified and recovered through a rider, rate schedule, or other schedule. For bundled utilities, these separately identified costs may include items such as a fuel factor, power cost recovery factor, and surcharge. Distribution service providers may have separately identified costs such as transition costs, the excess mitigation charge, transmission cost recovery factors, and the competition transition charge.

(11) Bundled Municipally Owned Utilities/Electric Cooperatives (MOU/COOP)--A municipally owned utility/electric cooperative that is conducting both transmission and distribution activities and competitive energy-related activities on a bundled basis without structural or functional separation of transmission and distribution functions from competitive energy-related activities and that makes a written declaration of its status as a bundled municipally owned utility/electric cooperative pursuant to §25.275(o)(3)(A) of this title (relating to Code of Conduct for Municipally Owned Utilities and Electric Cooperatives Engaged in Competitive Activities).

(12) Calendar year--January 1 through December 31.

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

(14) Competition transition charge (CTC)--Any non-bypassable charge that recovers the positive excess of the net book value of generation assets over the market value of the assets, taking into account all of the electric utility's generation assets, any above market purchased power costs, and any deferred debit related to a utility's discontinuance of the application of Statement of Financial Accounting Standards Number 71 ("Accounting for the Effects of Certain Types of Regulation") for generation-related assets if required by the provisions of PURA chapter 39. For purposes of PURA §39.262, book value shall be established as of December 31, 2001, or the date a market value is established through a market valuation method under PURA §39.262(h), whichever is earlier, and shall include stranded costs incurred under PURA §39.263. Competition transition charges also include the transition charges established pursuant to PURA §39.302(7) unless the context indicates otherwise.

(15) Competitive affiliate--An affiliate of a utility that provides services or sells products in a competitive energy-related market in this state, including telecommunications services, to the extent those services are energy-related.

(16) Competitive energy efficiency services--Energy efficiency services that are defined as competitive energy services under §25.341 of this title (relating to Definitions).

(17) Competitive retailer--A retail electric provider; or a municipally owned utility or electric cooperative, that has the right to offer electric energy and related services at unregulated prices directly to retail customers who have customer choice, without regard to geographic location.

(18) Congestion zone--An area of the transmission network that is bounded by commercially significant transmission constraints or otherwise identified as a zone that is subject to transmission constraints, as defined by an independent organization.

(19) Control area--An electric power system or combination of electric power systems to which a common automatic generation control scheme is applied in order to:

(A) match, at all times, the power output of the generators within the electric power system(s) and capacity and energy purchased from entities outside the electric power system(s), with the load within the electric power system(s);

(B) maintain, within the limits of good utility practice, scheduled interchange with other control areas;

(C) maintain the frequency of the electric power system(s) within reasonable limits in accordance with good utility practice; and

(D) obtain sufficient generating capacity to maintain operating reserves in accordance with good utility practice.

(20) Corporation--A domestic or foreign corporation, joint-stock company, or association, and each lessee, assignee, trustee, receiver, or other successor in interest of the corporation, company, or association, that has any of the powers or privileges of a corporation not possessed by an individual or partnership. The term does not include a municipal corporation or electric cooperative, except as expressly provided by PURA.

(21) Critical loads--Loads for which electric service is considered crucial for the protection or maintenance of public health and safety; including but not limited to hospitals, police stations, fire stations, critical water and wastewater facilities, and customers with special in-house life-sustaining equipment.

(22) Customer choice--The freedom of a retail customer to purchase electric services, either individually or through voluntary aggregation with other retail customers, from the provider or providers of the customer's choice and to choose among various fuel types, energy efficiency programs, and renewable power suppliers.

(23) Customer class--A group of customers with similar electric-service characteristics (e.g., residential, commercial, industrial, sales for resale) taking service under one or more rate schedules. Qualified businesses as defined by the Texas Enterprise Zone Act, Texas Government Code, title 10, chapter 2303 may be considered to be a separate customer class of electric utilities.

(24) Day-ahead--The day preceding the operating day.

(25) Deemed savings--A pre-determined, validated estimate of energy savings and demand reduction attributable to an energy efficiency measure in a particular type of application that a utility may use instead of energy savings and demand reduction determined through measurement and verification activities.

(26) Demand--The rate at which electric energy is delivered to or by a system at a given instant, or averaged over a designated period, usually expressed in kilowatts (kW) or megawatts (MW).

(27) Demand savings--A quantifiable reduction in the rate at which energy is delivered to or by a system at a given instance, or averaged over a designated period, usually expressed in kilowatts (kW) or megawatts (MW).

(28) Demand-side management (DSM)--Activities that affect the magnitude or timing of customer electrical usage, or both.

(29) Demand-side resource or demand-side management--Equipment, materials, and activities that result in reductions in electric generation, transmission, or distribution capacity needs or reductions in energy usage or both.

(30) Disconnection of service--Interruption of a customer's supply of electric service at the customer's point of delivery by an electric utility, a transmission and distribution utility, a municipally owned utility or an electric cooperative.

(31) Distribution line--A power line operated below 60,000 volts, when measured phase-to-phase, that is owned by an electric utility, transmission and distribution utility, municipally owned utility, or electric cooperative.

(32) Distributed resource--A generation, energy storage, or targeted demand-side resource, generally between one kilowatt and ten megawatts, located at a customer's site or near a load center, which may be connected at the distribution voltage level (below 60,000 volts), that provides advantages to the system, such as deferring the need for upgrading local distribution facilities.

(33) Distribution service provider (DSP)--An electric utility, municipally-owned utility, or electric cooperative that owns or operates for compensation in this state equipment or facilities that are used for the distribution of electricity to retail customers including retail customers served at transmission voltage levels.

(34) Economically distressed geographic area--Zip-code area in which the average household income is less than or equal to 60% of the statewide median income as reported in the most recently available United States Census data.

(35) Electric cooperative--

(A) a corporation organized under the Texas Utilities Code, Chapter 161 or a predecessor statute to Chapter 161 and operating under that chapter;

(B) a corporation organized as an electric cooperative in a state other than Texas that has obtained a certificate of authority to conduct affairs in the State of Texas; or

(C) a successor to an electric cooperative created before June 1, 1999, in accordance with a conversion plan approved by a vote of the members of the electric cooperative, regardless of whether the successor later purchases, acquires, merges with, or consolidates with other electric cooperatives.

(36) Electric generating facility--A facility that generates electric energy for compensation and that is owned or operated by a person in this state, including a municipal corporation, electric cooperative, or river authority.

(37) Electric generation equipment lessor or operator--A person who rents to, or operates for compensation on behalf of, a third party electric generation equipment that:

(A) is used on a site of the third party until the third party is able to obtain sufficient electricity service;

(B) produces electricity on site to be consumed by the third party and not resold; and

(38) Electricity facts label--Information in a standardized format, as described in §25.475(f) of this title (relating to Information Disclosures to Residential and Small Commercial Customers), that summarizes the price, contract terms, fuel sources, and environmental impact associated with an electricity product.

(39) Electricity product--A specific type of retail electricity service developed and identified by a REP, the specific terms and conditions of which are summarized in an electricity facts label that is specific to that electricity product.

(40) Electric Reliability Council of Texas (ERCOT)--Refers to the independent organization and, in a geographic sense, refers to the area served by electric utilities, municipally owned utilities, and electric cooperatives that are not synchronously interconnected with electric utilities outside of the State of Texas.

(41) Electric service identifier (ESI ID)--The basic identifier assigned to each point of delivery used in the registration system and settlement system managed by ERCOT or another independent organization.

(42) Electric utility--Except as otherwise provided in this chapter, an electric utility is a person or river authority that owns or operates for compensation in this state equipment or facilities to produce, generate, transmit, distribute, sell, or furnish electricity in this state. The term includes a lessee, trustee, or receiver of an electric utility and a recreational vehicle park owner who does not comply with Texas Utilities Code, subchapter C, chapter 184, with regard to the metered sale of electricity at the recreational vehicle park. The term does not include:

(A) a municipal corporation;

(B) a qualifying facility;

(D) an exempt wholesale generator;

(E) a power marketer;

(F) a corporation described by PURA §32.053 to the extent the corporation sells electricity exclusively at wholesale and not to the ultimate consumer;

(G) an electric cooperative;

(H) a retail electric provider;

(I) the state of Texas or an agency of the state; or

(J) a person not otherwise an electric utility who:

(i) furnishes an electric service or commodity only to itself, its employees, or its tenants as an incident of employment or tenancy, if that service or commodity is not resold to or used by others;

(ii) owns or operates in this state equipment or facilities to produce, generate, transmit, distribute, sell or furnish electric energy to an electric utility, if the equipment or facilities are used primarily to produce and generate electric energy for consumption by that person;

(iii) owns or operates in this state a recreational vehicle park that provides metered electric service in accordance with Texas Utilities Code, subchapter C, chapter 184;

(iv) is an electric generation equipment lessor or operator; or

(v) owns or operates in this state equipment used solely to provide electricity charging service for consumption by an alternatively fueled vehicle, as defined by section 502.004 of the Transportation Code.

(43) Energy efficiency--Programs that are aimed at reducing the rate at which electric energy is used by equipment or processes. Reduction in the rate of energy used may be obtained by substituting technically more advanced equipment to produce the same level of end-use services with less electricity; adoption of technologies and processes that reduce heat or other energy losses; or reorganization of processes to make use of waste heat. Efficient use of energy by customer-owned end-use devices implies that existing comfort levels, convenience, and productivity are maintained or improved at a lower customer cost.

(44) Energy efficiency measures--Equipment, materials, and practices that when installed and used at a customer site result in a measurable and verifiable reduction in either purchased electric energy consumption, measured in kilowatt-hours (kWh), or peak demand, measured in kW, or both.

(45) Energy efficiency project--An energy efficiency measure or combination of measures installed under a standard offer contract or a market transformation contract that results in both a reduction in customers' electric energy consumption and peak demand, and energy costs.

(46) Energy savings--A quantifiable reduction in a customer's consumption of energy.

(47) ERCOT protocols--Body of procedures developed by ERCOT to maintain the reliability of the regional electric network and account for the production and delivery of electricity among resources and market participants.

(48) ERCOT region--The geographic area under the jurisdiction of the commission that is served by transmission service providers that are not synchronously interconnected with transmission service providers outside of the state of Texas.

(49) Exempt wholesale generator--A person who is engaged directly or indirectly through one or more affiliates exclusively in the business of owning or operating all or part of a facility for generating electric energy and selling electric energy at wholesale who does not own a facility for the transmission of electricity, other than an essential interconnecting transmission facility necessary to effect a sale of electric energy at wholesale.

(50) Existing purchased power contract--A purchased power contract in effect on January 1, 1999, including any amendments and revisions to that contract resulting from litigation initiated before January 1, 1999.

(51) Facilities--All the plant and equipment of an electric utility, including all tangible and intangible property, without limitation, owned, operated, leased, licensed, used, controlled, or supplied for, by, or in connection with the business of an electric utility.

(52) Financing order--An order of the commission adopted under PURA §39.201 or §39.262 approving the issuance of transition bonds and the creation of transition charges for the recovery of qualified costs.

(53) Freeze period--The period beginning on January 1, 1999, and ending on December 31, 2001.

(54) Generation assets--All assets associated with the production of electricity, including generation plants, electrical interconnections of the generation plant to the transmission system, fuel contracts, fuel transportation contracts, water contracts, lands, surface or subsurface water rights, emissions-related allowances, and gas pipeline interconnections.

(55) Generation service--The production and purchase of electricity for retail customers and the production, purchase, and sale of electricity in the wholesale power market.

(56) Good utility practice--Any of the practices, methods, or acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods, or acts that, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, and expedition. Good utility practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather is intended to include acceptable practices, methods, and acts generally accepted in the region.

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

(58) Independent organization--An independent system operator or other person that is sufficiently independent of any producer or seller of electricity that its decisions will not be unduly influenced by any producer or seller.

(59) Independent system operator--An entity supervising the collective transmission facilities of a power region that is charged with non-discriminatory coordination of market transactions, systemwide transmission planning, and network reliability.

(60) Installed generation capacity--All potentially marketable electric generation capacity, including the capacity of:

(A) generating facilities that are connected with a transmission or distribution system;

(B) generating facilities used to generate electricity for consumption by the person owning or controlling the facility; and

(C) generating facilities that will be connected with a transmission or distribution system and operating within 12 months.

(61) Interconnection agreement--The standard form of agreement that has been approved by the commission. The interconnection agreement sets forth the contractual conditions under which a company and a customer agree that one or more facilities may be interconnected with the company's utility system.

(62) Licensing--The commission process for granting, denial, renewal, revocation, suspension, annulment, withdrawal, or amendment of a license.

(63) Load factor--The ratio of average load to peak load during a specific period of time, expressed as a percent. The load factor indicates to what degree energy has been consumed compared to maximum demand or utilization of units relative to total system capability.

(64) Low-income customer--An electric customer who receives assistance under the Supplemental Nutrition Assistance Program (SNAP) from Texas Health and Human Services Commission (HHSC) or medical assistance from a state agency administering a part of the medical assistance program.

(65) Low-Income List Administrator (LILA)--A third-party administrator contracted by the commission to administer aspects of the low-income customer identification process established under PURA §17.007.

(66) Market power mitigation plan--A written proposal by an electric utility or a power generation company for reducing its ownership and control of installed generation capacity as required by PURA §39.154.

(67) Market value--For nonnuclear assets and certain nuclear assets, the value the assets would have if bought and sold in a bona fide third-party transaction or transactions on the open market under PURA §39.262(h) or, for certain nuclear assets, as described by PURA §39.262(i), the value determined under the method provided by that subsection.

(68) Master meter--A meter used to measure, for billing purposes, all electric usage of an apartment house or mobile home park, including common areas, common facilities, and dwelling units.

(69) Municipality--A city, incorporated village, or town, existing, created, or organized under the general, home rule, or special laws of the state.

(70) Municipally-owned utility (MOU)--Any utility owned, operated, and controlled by a municipality or by a nonprofit corporation whose directors are appointed by one or more municipalities.

(71) Nameplate rating--The full-load continuous rating of a generator under specified conditions as designated by the manufacturer.

(72) Native load customer--A wholesale or retail customer on whose behalf an electric utility, electric cooperative, or municipally-owned utility, by statute, franchise, regulatory requirement, or contract, has an obligation to construct and operate its system to meet in a reliable manner the electric needs of the customer.

(73) Natural gas energy credit (NGEC)--A tradable instrument representing each megawatt of new generating capacity fueled by natural gas, as authorized by PURA §39.9044 and implemented under §25.172 of this title (relating to Goal for Natural Gas).

(74) Net book value--The original cost of an asset less accumulated depreciation.

(75) Net dependable capability--The maximum load in megawatts, net of station use, that a generating unit or generating station can carry under specified conditions for a given period of time without exceeding approved limits of temperature and stress.

(76) Net-to-gross--A factor that is applied to convert gross program impacts into net program impacts. The factor is calculated by dividing net program savings by gross program savings and may account for variables that create differences between gross and net savings, such as free riders and spillover.

(77) New on-site generation--Electric generation with capacity greater than ten megawatts capable of being lawfully delivered to the site without use of utility distribution or transmission facilities, which was not, on or before December 31, 1999, either:

(A) A fully operational facility; or

(B) A project supported by substantially complete filings for all necessary site-specific environmental permits under the rules of the Texas Commission on Environmental Quality (TCEQ) in effect at the time of filing.

(78) Off-grid renewable generation--The generation of renewable energy in an application that is not interconnected to a utility transmission or distribution system.

(79) Other generation sources--A competitive retailer's or affiliated retail electric provider's supply of generated electricity that is not accounted for by a direct supply contract with an owner of generation assets.

(80) Person--Includes an individual, a partnership of two or more persons having a joint or common interest, a mutual or cooperative association, and a corporation, but does not include an electric cooperative.

(81) Power cost recovery factor (PCRF)--A charge or credit that reflects an increase or decrease in purchased power costs not in base rates.

(82) Power generation company (PGC)--A person that:

(A) generates electricity that is intended to be sold at wholesale, including the owner or operator of electric energy storage equipment or facilities to which the Public Utility Regulatory Act, chapter 35, subchapter E applies;

(B) does not own a transmission or distribution facility in this state, other than an essential interconnecting facility, a facility not dedicated to public use, or a facility otherwise excluded from the definition of "electric utility" under this section; and

(C) does not have a certificated service area, although its affiliated electric utility or transmission and distribution utility may have a certificated service area.

(83) Power marketer--A person who becomes an owner of electric energy in this state for the purpose of selling the electric energy at wholesale; does not own generation, transmission, or distribution facilities in this state and does not have a certificated service area.

(84) Power region--A contiguous geographical area that is a distinct region of the North American Electric Reliability Council.

(85) Pre-interconnection study--A study or studies that may be undertaken by a utility in response to its receipt of a completed application for interconnection and parallel operation with the utility system at distribution voltage. Pre-interconnection studies may include, but are not limited to, service studies, coordination studies, and utility system impact studies.

(86) Premises--A tract of land or real estate or related commonly used tracts including buildings and other appurtenances thereon.

(87) Price to beat (PTB)--A price for electricity, as determined under PURA §39.202, charged by an affiliated retail electric provider to eligible residential and small commercial customers in its service area.

(88) Proceeding--A hearing, investigation, inquiry, or other procedure for finding facts or making a decision, including adopting, amending, or repealing a rule or setting a rate. The term includes a denial of relief or dismissal of a complaint.

(89) Proprietary customer information--Any information obtained by a retail electric provider, an electric utility, or a transmission and distribution business unit as defined in §25.275(c)(16) of this title, on a customer in the course of providing electric service or by an aggregator on a customer in the course of aggregating electric service that makes possible the identification of any individual customer by matching such information with the customer's name, address, account number, type or classification of service, historical electricity usage, expected patterns of use, types of facilities used in providing service, individual contract terms and conditions, price, current charges, billing records, or any information that the customer has expressly requested not be disclosed. Information that is redacted or organized in such a way as to make it impossible to identify the customer to whom the information relates does not constitute proprietary customer information.

(90) Provider of last resort (POLR)--A retail electric provider (REP) certified in Texas that has been designated by the commission to provide a basic, standard retail service package in accordance with §25.43 of this title (relating to Provider of Last Resort (POLR)).

(91) Public retail customer--A retail customer that is an agency of this state, a state institution of higher education, a public school district, or a political subdivision of this state.

(92) Public utility or utility--An electric utility as that term is defined in this section, or a public utility or utility as those terms are defined in PURA §51.002.

(93) Public Utility Regulatory Act (PURA)--The enabling statute for the Public Utility Commission of Texas, located in the Texas Utilities Code Annotated, §§11.001 et. seq.

(94) Purchased power market value--The value of demand and energy bought and sold in a bona fide third-party transaction or transactions on the open market and determined by using the weighted average costs of the highest three offers from the market for purchase of the demand and energy available under the existing purchased power contracts.

(95) Qualified scheduling entity--A market participant that is qualified by ERCOT in accordance with section 16, Registration and Qualification of Market Participants of ERCOT's protocols, to submit balanced schedules and ancillary services bids and settle payments with ERCOT.

(96) Qualifying cogenerator- As defined by 16 U.S.C. §796(18)(C). A qualifying cogenerator that provides electricity to the purchaser of the cogenerator's thermal output is not for that reason considered to be a retail electric provider or a power generation company.

(97) Qualifying facility--A qualifying cogenerator or qualifying small power producer.

(98) Qualifying small power producer- As defined by 16 U.S.C. §796(17)(D).

(99) Rate--A compensation, tariff, charge, fare, toll, rental, or classification that is directly or indirectly demanded, observed, charged, or collected by an electric utility for a service, product, or commodity described in the definition of electric utility in this section and a rule, practice, or contract affecting the compensation, tariff, charge, fare, toll, rental, or classification that must be approved by a regulatory authority.

(100) Rate class--A group of customers taking electric service under the same rate schedule.

(101) Rate year--The 12-month period beginning with the first date that rates become effective. The first date that rates become effective may include, but is not limited to, the effective date for bonded rates or the effective date for interim or temporary rates.

(102) Ratemaking proceeding--A proceeding in which a rate may be changed.

(103) Registration agent--Entity designated by the commission to administer registration and settlement, premise data, and other processes concerning a customer's choice of retail electric provider in the competitive electric market in Texas.

(104) Regulatory authority--In accordance with the context where it is found, either the commission or the governing body of a municipality.

(105) Renewable demand side management (DSM) technologies--Equipment that uses a renewable energy resource (renewable resource) as defined in this section, that, when installed at a customer site, reduces the customer's net purchases of energy (kWh), electrical demand (kW), or both.

(106) Renewable energy--Energy derived from renewable energy technologies.

(107) Renewable energy credit (REC)--A tradable instrument representing the generation attributes of one MWh of electricity from renewable energy sources, as authorized by the PURA §39.904 and implemented under §25.173(e) of this title (relating to Goal for Renewable Energy).

(108) Renewable energy credit account (REC account)--An account maintained by the renewable energy credits trading program administrator for the purpose of tracking the production, sale, transfer, purchase, and retirement of RECs by a program participant.

(109) Renewable energy resource (renewable resource)--A resource that produces energy derived from renewable energy technologies.

(110) Renewable energy technology--Any technology that exclusively relies on an energy source that is naturally regenerated over a short time and derived directly from the sun, indirectly from the sun, or from moving water or other natural movements and mechanisms of the environment. Renewable energy technologies include those that rely on energy derived directly from the sun, on wind, geothermal, hydroelectric, wave, or tidal energy, or on biomass or biomass-based waste products, including landfill gas. A renewable energy technology does not rely on energy resources derived from fossil fuels, waste products from fossil fuels, or waste products from inorganic sources.

(111) Repowering--Modernizing or upgrading an existing facility in order to increase its capacity or efficiency.

(112) Residential customer--Retail customers classified as residential by the applicable bundled utility tariff, unbundled transmission and distribution utility tariff or, in the absence of classification under a residential rate class, those retail customers that are primarily end users consuming electricity at the customer's place of residence for personal, family or household purposes and who are not resellers of electricity.

(113) Retail customer--The separately metered end-use customer who purchases and ultimately consumes electricity.

(114) Retail electric provider (REP)--A person that sells electric energy to retail customers in this state. A retail electric provider may not own or operate generation assets. The term does not include a person not otherwise a retail electric provider who owns or operates equipment used solely to provide electricity charging service for consumption by an alternatively fueled vehicle, as defined by Section 502.004, Transportation Code.

(115) Retail electric provider (REP) of record--The REP assigned to the electric service identifier (ESI ID) in ERCOT's database. There can be no more than one REP of record assigned to an ESI ID at any specific point in time.

(116) Retail stranded costs--That part of net stranded cost associated with the provision of retail service.

(117) Retrofit--The installation of control technology on an electric generating facility to reduce the emissions of nitrogen oxide, sulfur dioxide, or both.

(118) River authority--A conservation and reclamation district created under the Texas Constitution, article 16, section 59, including any nonprofit corporation created by such a district pursuant to the Texas Water Code, chapter 152, that is an electric utility.

(119) Rule--A statement of general applicability that implements, interprets, or prescribes law or policy, or describes the procedure or practice requirements of the commission. The term includes the amendment or repeal of a prior rule, but does not include statements concerning only the internal management or organization of the commission and not affecting private rights or procedures.

(120) Savings-to-investment ratio (SIR)--The ratio of the present value of a customer's estimated lifetime electricity cost savings from energy efficiency measures to the present value of the installation costs of those energy efficiency measures, which include the cost of any incidental repairs.

(121) Separately metered--Metered by an individual meter that is used to measure electric energy consumption by a retail customer and for which the customer is directly billed by a utility, retail electric provider, electric cooperative, or municipally owned utility.

(122) Service--Has its broadest and most inclusive meaning. The term includes any act performed, anything supplied, and any facilities used or supplied by an electric utility in the performance of its duties under PURA to its patrons, employees, other public utilities or electric utilities, an electric cooperative, and the public. The term also includes the interchange of facilities between two or more public utilities or electric utilities.

(123) Spanish-speaking person--A person who speaks any dialect of the Spanish language exclusively or as their primary language.

(124) Standard meter--The minimum metering device necessary to obtain the billing determinants required by the transmission and distribution utility's tariff schedule to determine an end-use customer's charges for transmission and distribution service.

(125) Stranded cost--The positive excess of the net book value of generation assets over the market value of the assets, taking into account all of the electric utility's generation assets, any above-market purchased-power costs, and any deferred debit related to a utility's discontinuance of the application of Statement of Financial Accounting Standards Number 71 ("Accounting for the Effect of Certain Types of Regulation") for generation-related assets if required by the provisions of PURA Chapter 39. For purposes of PURA §39.262, book value shall be established as of December 31, 2001, or the date a market value is established through a market valuation method under PURA §39.262(h), whichever is earlier, and shall include stranded costs incurred under PURA §39.263.

(126) Submetering--Metering of electricity consumption on the customer side of the point at which the electric utility measures electricity consumption for billing purposes.

(127) Summer net dependable capability--The net capability of a generating unit in megawatts (MW) for daily planning and operational purposes during the summer peak season, as determined in accordance with requirements of the reliability council or independent organization in which the unit operates.

(128) Supply-side resource--A resource, including a storage device, that provides electricity from fuels or renewable resources.

(129) System emergency--A condition on a utility's system that is likely to result in imminent, significant disruption of service to customers or is imminently likely to endanger life or property.

(130) Tariff--The schedule of a utility, municipally-owned utility, or electric cooperative containing all rates and charges stated separately by type of service, the rules and regulations of the utility, and any contracts that affect rates, charges, terms or conditions of service.

(131) Termination of service--The cancellation or expiration of a sales agreement or contract by a retail electric provider by notification to the customer and the registration agent.

(132) Tenant--A person who is entitled to occupy a dwelling unit to the exclusion of others and who is obligated to pay for the occupancy under a written or oral rental agreement.

(133) Test year--The most recent 12 months for which operating data for an electric utility, electric cooperative, or municipally-owned utility are available and shall commence with a calendar quarter or a fiscal year quarter.

(134) Texas jurisdictional installed generation capacity--The amount of an affiliated power generation company's installed generation capacity properly allocable to the Texas jurisdiction. Such allocation shall be calculated pursuant to an existing commission-approved allocation study, or other such commission-approved methodology, and may be adjusted as approved by the commission to reflect the effects of divestiture or the installation of new generation facilities.

(135) Transition bonds--Bonds, debentures, notes, certificates, of participation or of beneficial interest, or other evidences of indebtedness or ownership that are issued by an electric utility, its successors, or an assignee under a financing order, that have a term not longer than 15 years, and that are secured or payable from transition property.

(136) Transition charges--Non-bypassable amounts to be charged for the use or availability of electric services, approved by the commission under a financing order to recover qualified costs, that shall be collected by an electric utility, its successors, an assignee, or other collection agents as provided for in a financing order.

(137) Transmission and distribution business unit (TDBU)--The business unit of a municipally owned utility/electric cooperative, whether structurally unbundled as a separate legal entity or functionally unbundled as a division, that owns or operates for compensation in this state equipment or facilities to transmit or distribute electricity at retail, except for facilities necessary to interconnect a generation facility with the transmission or distribution network, a facility not dedicated to public use, or a facility otherwise excluded from the definition of electric utility in a qualifying power region certified under PURA §39.152. Transmission and distribution business unit does not include a municipally owned utility/electric cooperative that owns, controls, or is an affiliate of the transmission and distribution business unit if the transmission and distribution business unit is organized as a separate corporation or other legally distinct entity. Except as specifically authorized by statute, a transmission and distribution business unit shall not provide competitive energy-related activities.

(138) Transmission and distribution utility (TDU)--A person or river authority that owns, or operates for compensation in this state equipment or facilities to transmit or distribute electricity, except for facilities necessary to interconnect a generation facility with the transmission or distribution network, a facility not dedicated to public use, or a facility otherwise excluded from the definition of "electric utility", in a qualifying power region certified under PURA §39.152, but does not include a municipally owned utility or an electric cooperative. The TDU may be a single utility or may be separate transmission and distribution utilities.

(139) Transmission line--A power line that is operated at 60 kilovolts (kV) or above, when measured phase-to-phase.

(140) Transmission service--Service that allows a transmission service customer to use the transmission and distribution facilities of electric utilities, electric cooperatives and municipally owned utilities to efficiently and economically utilize generation resources to reliably serve its loads and to deliver power to another transmission service customer. Includes construction or enlargement of facilities, transmission over distribution facilities, control area services, scheduling resources, regulation services, reactive power support, voltage control, provision of operating reserves, and any other associated electrical service the commission determines appropriate, except that, on and after the implementation of customer choice in any portion of the ERCOT region, control area services, scheduling resources, regulation services, provision of operating reserves, and reactive power support, voltage control and other services provided by generation resources are not transmission service.

(141) Transmission service customer--A transmission service provider, distribution service provider, river authority, municipally-owned utility, electric cooperative, power generation company, retail electric provider, federal power marketing agency, exempt wholesale generator, qualifying facility, power marketer, or other person whom the commission has determined to be eligible to be a transmission service customer. A retail customer, as defined in this section, may not be a transmission service customer.

(142) Transmission service provider (TSP)--An electric utility, municipally-owned utility, or electric cooperative that owns or operates facilities used for the transmission of electricity.

(143) Transmission system--The transmission facilities at or above 60 kilovolts (kV) owned, controlled, operated, or supported by a transmission service provider or transmission service customer that are used to provide transmission service.

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 December 12, 2025.

TRD-202504614

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 1, 2026

Proposal publication date: September 5, 2025

For further information, please call: (512) 936-7244

SUBCHAPTER H. ELECTRICAL PLANNING

DIVISION 2. ENERGY EFFICIENCY AND CUSTOMER-OWNED RESOURCES

16 TAC §25.181, §25.182

Cross reference to statutes: Public Utility Regulatory Act §§14.001 and 14.002, §36.204, and §39.905.

§25.181. Energy Efficiency Goal.

(a) Purpose. The purpose of this section is to ensure that:

(1) electric utilities administer energy efficiency incentive programs in a market-neutral, nondiscriminatory manner and do not offer competitive services, except as permitted in §25.343 of this title (relating to Competitive Energy Services) or this section;

(2) all customers, in all eligible customer classes and all areas of an electric utility's service area, have a choice of and access to the utility's portfolio of energy efficiency programs that allow each customer to reduce energy consumption, summer and winter peak demand, or energy costs; and

(3) each electric utility annually provides, through market-based standard offer programs, targeted market-transformation programs, or utility self-delivered programs, program incentive payments sufficient for residential and commercial customers, retail electric providers, and energy efficiency service providers to acquire additional cost-effective energy efficiency, subject to EECRF caps established in §25.182(d)(7) of this title (relating to Energy Efficiency Cost Recovery Factor), for the utility to achieve the goals in subsection (e) of this section.

(b) Application. This section applies to electric utilities and the Electric Reliability Council of Texas, Inc. (ERCOT).

(c) Definitions. The following terms, when used in this section and in §25.182 of this title, have the following meanings unless the context indicates otherwise:

(1) Affiliate --

(A) A person who directly or indirectly owns or holds at least 5.0% of the voting securities of an energy efficiency service provider;

(B) A person in a chain of successive ownership of at least 5.0% of the voting securities of an energy efficiency service provider;

(C) A corporation that has at least 5.0% of its voting securities owned or controlled, directly or indirectly, by an energy efficiency service provider;

(D) A corporation that has at least 5.0% of its voting securities owned or controlled, directly or indirectly, by:

(i) a person who directly or indirectly owns or controls at least 5.0% of the voting securities of an energy efficiency service provider; or

(ii) a person in a chain of successive ownership of at least 5.0% of the voting securities of an energy efficiency service provider; or

(E) A person who is an officer or director of an energy efficiency service provider or of a corporation in a chain of successive ownership of at least 5.0% of the voting securities of an energy efficiency service provider;

(F) A person who actually exercises substantial influence or control over the policies and actions of an energy efficiency service provider;

(G) A person over which the energy efficiency service provider exercises the control described in subparagraph (F) of this paragraph;

(H) A person who exercises common control over an energy efficiency service provider, where "exercising common control over an energy efficiency service provider" means having the power, either directly or indirectly, to direct or cause the direction of the management or policies of an energy efficiency service provider, without regard to whether that power is established through ownership or voting of securities or any other direct or indirect means; or

(I) A person who, together with one or more persons with whom the person is related by ownership, marriage or blood relationship, or by action in concert, actually exercises substantial influence over the policies and actions of an energy efficiency service provider even though neither person may qualify as an affiliate individually.

(2) Baseline--A relevant condition that would have existed in the absence of the energy efficiency project or program being implemented, including energy consumption that would have occurred. Baselines are used to calculate program-related demand and energy savings. Baselines can be defined as either project-specific baselines or performance standard baselines (e.g., building codes).

(3) Claimed savings--Values reported by an electric utility after the energy efficiency activities have been completed, but prior to the time an independent, third-party evaluation of the savings is performed. As with projected savings estimates, these values may utilize results of prior evaluations or values in technical reference manuals. However, they are adjusted from projected savings estimates by correcting for any known data errors and actual installation rates and may also be adjusted with revised values for factors such as per-unit savings values, operating hours, and savings persistence rates. Can be indicated as first year, annual demand or energy savings, or lifetime energy or demand savings values. Can be indicated as gross savings or net savings values.

(4) Commercial customer--A non-residential customer taking service at a point of delivery at a distribution voltage under an electric utility's tariff during the prior program year or a non-profit customer or government entity, including an educational institution. For purposes of this section, each point of delivery must be considered a separate customer.

(5) Conservation load factor--The ratio of the annual energy savings goal, in kilowatt hours (kWh), to the peak demand goal for the year, measured in kilowatts (kW) and multiplied by the number of hours in the year.

(6) Deemed savings calculation--An industry-wide engineering algorithm used to calculate energy or demand savings of the installed energy efficiency measure that has been developed from common practice that is widely considered acceptable for the measure and purpose, and is applicable to the situation being evaluated. May include stipulated assumptions for one or more parameters in the algorithm, but typically requires some data associated with actual installed measure. An electric utility may use the calculation with documented measure-specific assumptions, instead of energy and peak demand savings determined through measurement and verification activities or the use of deemed savings.

(7) Deemed savings value--An estimate of energy or demand savings for a single unit of an installed energy efficiency measure that has been developed from data sources and analytical methods that are widely considered acceptable for the measure and purpose, and is applicable to the situation being evaluated. An electric utility may use deemed savings values instead of energy or peak demand savings determined through measurement and verification activities.

(8) Eligible customers--Residential and commercial customers. In addition, to the extent that they meet the criteria for participation in load management standard offer programs developed for industrial customers and implemented prior to May 1, 2007, industrial customers are eligible customers solely for the purpose of participating in such programs.

(9) Energy efficiency program--The aggregate of the energy efficiency activities carried out by an electric utility under this section or a set of energy efficiency projects carried out by an electric utility under the same name and operating rules.

(10) Energy efficiency service provider- A person or other entity that installs energy efficiency measures or performs other energy efficiency services under this section. An energy efficiency service provider may be a retail electric provider or commercial customer, provided that the commercial customer has a peak load equal to or greater than 50 kW. An energy efficiency service provider may also be a governmental entity or a non-profit organization, but may not be an electric utility.

(11) Estimated useful life (EUL)--The number of years until 50% of installed measures are still operable and providing savings, and is used interchangeably with the term "measure life". The EUL determines the period of time over which the benefits of the energy efficiency measure are expected to accrue.

(12) Evaluated savings--Savings estimates reported by the evaluation, measurement and verification (EM&V) contractor after the energy efficiency activities and an impact evaluation have been completed. Differs from claimed savings in that the EM&V contractor has conducted some of the evaluation or verification activities. These values may rely on claimed savings for factors such as installation rates and the Technical Reference Manual for values such as per unit savings values and operating hours. These savings estimates may also include adjustments to claimed savings for data errors, per unit savings values, operating hours, installation rates, savings persistence rates, or other considerations. Can be indicated as first year, annual demand or energy savings, or lifetime energy or demand savings values. Can be indicated as gross savings or net savings values.

(13) Evaluation--The conduct of any of a wide range of assessment studies and other activities aimed at determining the effects of a program; or aimed at understanding or documenting program performance, program or program-related markets and market operations, program-induced changes in energy efficiency markets, levels of demand or energy savings, or program cost-effectiveness. Market assessment, monitoring, and evaluation, and measurement and verification (M&V) are aspects of evaluation.

(14) Free driver--Customers who do not directly participate in an energy efficiency program, but who undertake energy efficiency actions in response to program activity.

(15) Free rider--A program participant who would have implemented the program measure or practice in the absence of the program. Free riders can be total, in which the participant's activity would have completely replicated the program measure; partial, in which the participant's activity would have partially replicated the program measure; or deferred, in which the participant's activity would have completely replicated the program measure, but at a time after the time the program measure was implemented.

(16) Growth in demand--The annual increase in demand in the Texas portion of an electric utility's service area at time of peak demand, as measured in accordance with this section.

(17) Gross savings--The change in energy consumption or demand that results directly from program-related actions taken by participants in an efficiency program, regardless of why they participated.

(18) Hard-to-reach- A customer that meets one of the following criteria:

(A) is located in a county, city, or unincorporated area with fewer than 2,000 housing units or a total population of 5,000 or less; or

(B) is a residential or commercial customer that the utility has been unable to serve in at least one of the past five years due to lack of available energy efficiency contractors or energy efficiency service providers--the commercial customer must have a peak load less than 50 kW, not be a government entity, and not be a subsidiary of a corporation; or

(19) Impact evaluation--An evaluation of the program-specific, directly induced changes (e.g., energy or demand reduction) attributable to an energy efficiency program.

(20) Industrial customer--A for-profit entity engaged in an industrial process taking electric service at transmission voltage, or a for-profit entity engaged in an industrial process taking electric service at distribution voltage that qualifies for a tax exemption under Tax Code §151.317 and has submitted an identification notice under subsection (u) of this section.

(21) Inspection--Examination of a project to verify that an energy efficiency measure has been installed, is capable of performing its intended function, and is producing an energy savings or demand reduction equivalent to the energy savings or demand reduction reported towards meeting the energy efficiency goals of this section.

(22) Installation rate--The percentage of measures that receive a program incentive payment under an energy efficiency program that are actually installed in a defined period of time. The installation rate is calculated by dividing the number of measures installed by the number of measures that receive a program incentive payment under an efficiency program in a defined period of time.

(23) Lifetime energy (demand) savings--The energy (demand) savings over the lifetime of an installed measure, project, or program. May include consideration of measure estimated useful life, technical degradation, and other factors. Can be gross or net savings.

(24) Load management--Activities that result in a reduction in peak demand, or a shifting of energy usage from a peak to an off-peak period or from high-price periods to lower price periods.

(25) Low-income--A customer who:

(A) meets the criteria for "low-income" as determined by the United States Department of Housing and Urban Development (HUD) or the United States Department of Health and Human Services (HHS) (i.e., resides in a household with an income level at or under 80% of the area median income based on family size, as calculated by HUD, or resides in a household with an income at or under 200% of the federal poverty guidelines based on family size, as calculated by HHS); or

(B) resides in a household in which at least one person receives economic assistance through a program listed in the Texas technical reference manual for the applicable program year; or

(26) Market transformation program--Strategic programs intended to induce lasting structural or behavioral changes in the market that result in increased adoption of energy efficient technologies, services, and practices, as described in this section.

(27) Measurement and verification (M&V)--A subset of program impact evaluation that is associated with the documentation of energy or demand savings at individual sites or projects using one or more methods that can involve measurements, engineering calculations, statistical analyses, or computer simulation modeling. M&V approaches are defined in the International Performance Measurement and Verification Protocol.

(28) Net savings--The total change in load that is attributable to an energy efficiency program. This change in energy or demand use must include, implicitly or explicitly, consideration of appropriate factors. These factors may include free ridership, participant and non-participant spillover, induced market effects, changes in the level of energy service, or other non-program causes of changes in energy use or demand.

(29) Non-participant spillover--Energy savings that occur when a program non-participant installs energy efficiency measures or applies energy savings practices as a result of a program's influence.

(30) Off-peak period--Period during which the demand on an electric utility system is not at or near its maximum. For the purpose of this section, the off-peak period includes all hours that are not in the peak period.

(31) Participant spillover--The additional energy savings that occur when a program participant independently installs incremental energy efficiency measures or applies energy savings practices after having participated in the efficiency program as a result of the program's influence.

(32) Peak demand--A distribution utility's highest annual retail demand at the source, used to determine the utility's annual energy efficiency goal.

(33) Peak period--For the purpose of this section, the peak period consists of the hours from one p.m. to seven p.m. during the months of June, July, August, and September, and the hours of six a.m. to ten a.m. and six p.m. to ten p.m. during the months of December, January, and February.

(34) Program incentive payment--Payment made by a utility to an energy efficiency service provider, an end-use customer, or third-party contractor to implement or attract customers to energy efficiency programs, including standard offer, market transformation and self-delivered programs.

(35) Program year--A year in which an energy efficiency incentive program is implemented, beginning January 1 and ending December 31.

(36) Projected savings--Estimated program demand reduction or energy savings reported by an electric utility for planning purposes.

(37) Self-delivered program--A program developed by a utility in an area in which customer choice is not offered that provides incentives directly to customers. The utility may use internal or external resources to design and administer the program.

(38) Spillover--Reductions in energy consumption or demand caused by the presence of an energy efficiency program, beyond the program-related gross savings of the participants and without financial or technical assistance from the program. There can be participant or non-participant spillover.

(39) Spillover rate--Estimate of energy savings attributable to spillover expressed as a percent of savings installed by participants through an energy efficiency program.

(40) Standard offer contract--A contract between an energy efficiency service provider and a participating utility or between a participating utility and a commercial customer specifying standard payments based upon the amount of energy and peak demand savings achieved through energy efficiency measures, the measurement and verification protocols, and other terms and conditions, consistent with this section.

(41) Standard offer program--A program under which a utility administers standard offer contracts between the utility and energy efficiency service providers.

(42) Technical reference manual (TRM)--A resource document compiled by the commission's EM&V contractor that includes information used in program planning and reporting of energy efficiency programs. It can include savings values for measures, engineering algorithms to calculate savings, impact factors to be applied to calculated savings (e.g., net-to-gross values), protocols, source documentation, specified assumptions, and other relevant material to support the calculation of measure and program savings.

(43) Verification--An independent assessment that a program has been implemented in accordance with the program design. The objectives of measure installation verification are to confirm the installation rate, that the installation meets reasonable quality standards, and that the measures are operating correctly and have the potential to generate the predicted savings. Verification activities are generally conducted during on-site surveys of a sample of projects. Project site inspections, participant phone and mail surveys or implementer and participant documentation review are typical activities associated with verification. Verification is also a subset of evaluation.

(d) Cost-effectiveness standard. An energy efficiency program is deemed to be cost-effective if the cost of the program to the utility is less than or equal to the benefits of the program. Utilities are encouraged to achieve demand reduction and energy savings through a portfolio of cost-effective programs that exceed each utility's energy efficiency goals while staying within the cost caps established in §25.182(d)(7) of this title.

(1) The cost of a program includes the cost of program incentive payments, EM&V contractor costs, utility incentive, and actual or allocated research and development and administrative costs. The benefits of the program consist of the value of the demand reductions and energy savings, measured in accordance with the avoided costs prescribed in this subsection. The present value of the program benefits must be calculated over the projected life of the measures installed or implemented under the program.

(2) The avoided cost of capacity must be established in accordance with this paragraph.

(A) By November 1 of each year, commission staff must file the avoided cost of capacity for the upcoming year, including supporting data, in the commission's central records under the control number for the energy efficiency implementation project.

(i) Staff must calculate the avoided cost of capacity from the base overnight cost using the lower of a new conventional combustion turbine or a new advanced combustion turbine, as reported by the United States Department of Energy's Energy Information Administration's (EIA) Cost and Performance Characteristics of New Central Station Electricity Generating Technologies associated with EIA's Annual Energy Outlook. If EIA cost data that reflects current conditions in the industry does not exist, staff may establish an avoided cost of capacity using another data source.

(ii) If the EIA base overnight cost of a new conventional or an advanced combustion turbine, whichever is lower, is less than $700 per kW, the avoided cost of capacity will be $80 per kW-year. If the base overnight cost of a new conventional or advanced combustion turbine, whichever is lower, is at or between $700 and $1,000 per kW, the avoided cost of capacity will be $100 per kW-year. If the base overnight cost of a new conventional or advanced combustion turbine, whichever is lower, is greater than $1,000 per kW, the avoided cost of capacity will be $120 per kW-year.

(iii) The avoided cost of capacity calculated by staff may be challenged only by the filing of a petition within 45 days of the date the avoided cost of capacity is filed in the commission's central records under the control number for the energy efficiency implementation project described by paragraph (2)(A) of this subsection. The petition must clearly describe the reasons commission's staff's avoided cost calculation is incorrect, include supporting data and calculations, and state the relief sought.

(B) A utility in an area in which customer choice is not offered may petition the commission for authorization to use an avoided cost of capacity different from the avoided cost determined according to subparagraph (A) of this paragraph by filing a petition no later than 45 days after the date the avoided cost of capacity calculated by staff is filed in the commission's central records under the control number for the energy efficiency implementation project described by paragraph (2)(A) of this subsection. The petition must clearly describe the reasons a different avoided cost should be used, include supporting data and calculations, and state the relief sought. The avoided cost of capacity proposed by the utility must be based on a generating resource or purchase in the utility's resource acquisition plan and the terms of the purchase or the cost of the resource must be disclosed in the filing.

(3) The avoided cost of energy must be established in accordance with this paragraph.

(A) By April 1 of each year, ERCOT must file its calculation of the avoided cost of energy for the upcoming calendar year for the ERCOT region under the control number for the energy efficiency implementation project. ERCOT must calculate the avoided cost of energy by determining the load-weighted average of the competitive load zone settlement point prices for the peak periods covering the seven previous winter and summer peaks, except for the winter peak period from December 2020 through February 2021. The avoided cost of energy calculated by ERCOT may be challenged only by the filing of a petition within 45 days of the date the avoided cost of capacity is filed by ERCOT in the commission's central records under the control number for the energy efficiency implementation project described by paragraph (2)(A) of this subsection. The petition must clearly describe the reasons ERCOT's avoided cost of energy calculation is incorrect, include supporting data and calculations, and state the relief sought.

(B) A utility in an area in which customer choice is not offered may petition the commission for authorization to use an avoided cost of energy other than that otherwise determined according to this paragraph. The avoided cost of energy may be based on peak period energy prices in an energy market operated by a regional transmission organization if the utility participates in that market and the prices are reported publicly. If the utility does not participate in such a market, the avoided cost of energy may be based on the expected heat rate of the gas-turbine generating technology specified in this subsection, multiplied by a publicly reported cost of natural gas.

(e) Annual energy efficiency goals.

(1) An electric utility must administer a portfolio of energy efficiency programs to acquire, at a minimum, the following:

(A) Until the trigger described in subparagraph (B) of this paragraph is reached, the utility must acquire a 30% reduction of its annual growth in demand of residential and commercial customers.

(B) If the demand reduction goal to be acquired by a utility under subparagraph (A) of this paragraph is equivalent to at least four-tenths of 1% of its summer weather-adjusted peak demand for the combined residential and commercial customers for the previous program year, the utility must meet the energy efficiency goal described in subparagraph (C) of this paragraph for each subsequent program year.

(C) Once the trigger described in subparagraph (B) of this paragraph is reached, the utility must acquire four-tenths of 1% of its summer weather-adjusted peak demand for the combined residential and commercial customers for the previous program year.

(D) Except as adjusted in accordance with subsection (u) of this section, a utility's demand reduction goal in any year must not be lower than its goal for the prior year, unless the commission establishes a goal for a utility under paragraph (2) of this subsection.

(2) The commission may establish for a utility a lower goal than the goal specified in paragraph (1) of this subsection, a higher administrative spending cap than the cap specified under subsection (g) of this section, or an EECRF greater than the cap specified in §25.182(d)(7) of this title if the utility demonstrates that compliance with that goal, administrative spending cap, or EECRF cost cap is not reasonably possible and that good cause supports the lower goal, higher administrative spending cap, or higher EECRF cost cap. To be eligible for a lower goal, higher administrative spending cap, or a higher EECRF cost cap, the utility must request a good cause exception as part of its EECRF application under §25.182 of this title. If approved, the good cause exception is limited to the program year associated with the EECRF application.

(3) Each utility's demand-reduction goal must be calculated as follows:

(A) Each year's historical demand for residential and commercial customers must be adjusted for weather fluctuations, using weather data for the most recent ten years. The utility's growth in residential and commercial demand is based on the average growth in retail load in the Texas portion of the utility's service area, measured at the utility's annual system peak. The utility must calculate the average growth rate for the prior five years.

(B) The demand goal for energy-efficiency savings for a year under paragraph (1)(A) of this subsection is calculated by applying the percentage goal to the average growth in peak demand, calculated in accordance with subparagraph (A) of this paragraph. The annual demand goal for energy efficiency savings under paragraph (1)(C) of this subsection is calculated by applying the percentage goal to the utility's summer weather-adjusted five-year average peak demand for the combined residential and commercial customers. This annual peak demand goal at the source is then converted to an equivalent goal at the meter by applying reasonable line loss factors.

(C) A utility may submit for commission approval an alternative method to calculate its growth in demand, for good cause.

(D) If a utility's prior five-year average load growth, calculated under subparagraph (A) of this paragraph, is negative, the utility must use the demand reduction goal calculated using the alternative method approved by the commission beginning with the 2013 program year or, if the commission has not approved an alternative method, the utility must use the previous year's demand reduction goal.

(E) A utility must not claim savings obtained from energy efficiency measures funded through settlement orders or count towards the utility incentive any savings obtained from grant funds that have been awarded directly to the utility for energy efficiency programs.

(F) Demand reduction achieved through programs for hard-to-reach customers must be no less than 5.0% of the utility's total demand reduction goal.

(G) Utilities may apply demand reduction and energy savings on a per project basis to summer or winter peak, but not to both summer and winter peaks.

(4) An electric utility must administer a portfolio of energy efficiency programs designed to meet an energy savings goal calculated from its demand savings goal, using a 20% conservation load factor.

(5) Electric utilities must administer a portfolio of energy efficiency programs to effectively and efficiently achieve the goals set out in this section.

(A) Program incentive payments may be made under standard offer contracts, market transformation contracts, or as part of a self-delivered program for energy savings and demand reductions. Each electric utility must establish standard program incentive payments to achieve the objectives of this section.

(B) Projects or measures under a standard offer, market transformation, or self-delivered program are not eligible for program incentive payments or compensation if:

(i) A project would achieve demand or energy reduction by eliminating an existing function, shutting down a facility or operation, or would result in building vacancies or the re-location of existing operations to a location outside of the area served by the utility conducting the program, except for an appliance recycling program consistent with this section.

(ii) A measure would be adopted even in the absence of the energy efficiency service provider's proposed energy efficiency project, except in special cases, such as hard-to-reach and weatherization programs, or where free riders are accounted for using a net to gross adjustment of the avoided costs, or another method that achieves the same result.

(iii) A project results in negative environmental or health effects, including effects that result from improper disposal of equipment and materials.

(C) Ineligibility under subparagraph (B) of this paragraph does not apply to standard offer, market transformation, and self-delivered programs aimed at energy code adoption, implementation, compliance, and enforcement under subsection (k) of this section, nor does it preclude standard offer, market transformation, or self-delivered programs promoting energy efficiency measures also required by energy codes to the degree such codes do not achieve full compliance rates.

(D) A utility in an area in which customer choice is not offered may achieve the goals of paragraphs (1) and (2) of this subsection by:

(i) providing a rebate or program incentive payment directly to eligible residential and commercial customers for programs implemented under this section; or

(ii) developing, subject to commission approval, new programs other than standard offer programs and market transformation programs, to the extent that the new programs satisfy the same cost-effectiveness standard as standard offer programs and market transformation programs using the process outlined in subsection (q) of this section.

(E) For a utility in an area in which customer choice is offered, the utility may achieve the goal of this section in rural areas by providing a rebate or program incentive payment directly to customers after demonstrating to the commission in a contested case hearing that the goal requirement cannot be met through the implementation of programs by retail electric providers or energy efficiency service providers in the rural areas.

(f) Program incentive payments. The program incentive payments for each customer class must not exceed 100% of avoided cost, as determined in accordance with this section. The program incentive payments must be set by each utility with the objective of achieving its energy and demand savings goals at the lowest reasonable cost per program. Different program incentive levels may be established for areas that have historically been underserved by the utility's energy efficiency programs or for other appropriate reasons. Utilities may adjust program incentive payments during the program year, but such adjustments must be clearly publicized in the materials used by the utility to set out the program rules and describe the programs to participating energy efficiency service providers.

(g) Utility administration. The cost of administration in a program year must not exceed 15% of a utility's total program costs for that program year. The cost of research and development in a program year must not exceed 10% of a utility's total program costs for that program year. The cumulative cost of administration and research and development must not exceed 20% of a utility's total program costs, unless a good cause exception filed under subsection (e)(2) of this section is granted. Any portion of these costs that is not directly assignable to a specific program must be allocated among the programs in proportion to the program incentive costs. Any utility incentive awarded by the commission must not be included in program costs for the purpose of applying these limits.

(1) Administrative costs include all reasonable and necessary costs incurred by a utility in carrying out its responsibilities under this section, including:

(A) conducting informational activities designed to explain the standard offer programs and market transformation programs to energy efficiency service providers, retail electric providers, and vendors;

(B) for a utility offering self-delivered programs, internal utility costs to conduct outreach activities to customers and energy efficiency service providers will be considered administration;

(D) reviewing and selecting energy efficiency programs in accordance with this section;

(E) providing regular and special reports to the commission, including reports of energy and demand savings;

(F) a utility's costs for an EECRF proceeding conducted under §25.182(d) of this title;

(G) the costs paid by a utility pursuant to PURA §33.023(b) for an EECRF proceeding conducted under §25.182(d) of this title; however, these costs are not included in the administrative caps applied in this paragraph; and

(H) any other activities that are necessary and appropriate for successful program implementation.

(2) A utility must adopt measures to foster competition among energy efficiency service providers for standard offer, market transformation, and self-delivered programs, such as limiting the number of projects or level of program incentive payments that a single energy efficiency service provider and its affiliates is eligible for and establishing funding set-asides for small projects.

(3) A utility may establish funding set-asides or other program rules to foster participation in energy efficiency programs by municipalities and other governmental entities.

(4) Electric utilities offering standard offer, market transformation, and self-delivered programs must use standardized forms, procedures, and program templates. The electric utility must file any standardized materials, or any change to it, with the commission at least 60 days prior to its use. In filing such materials, the utility must provide an explanation of changes from the version of the materials that was previously used. For standard offer, market transformation, and self-delivered programs, the utility must provide relevant documents to retail electric providers and energy efficiency service providers and work collaboratively with them when it changes program documents, to the extent that such changes are not considered in the energy efficiency implementation project described in subsection (q) of this section.

(5) Each electric utility in an area in which customer choice is offered must conduct programs to encourage and facilitate the participation of retail electric providers and energy efficiency service providers in the delivery of efficiency and demand response programs, including:

(A) Coordinating program rules, contracts, and program incentive payments to facilitate the statewide marketing and delivery of the same or similar programs by retail electric providers;

(B) Setting aside amounts for programs to be delivered to customers by retail electric providers and establishing program rules and schedules that will give retail electric providers sufficient time to plan, advertise, and conduct energy efficiency programs, while preserving the utility's ability to meet the goals in this section; and

(C) Working with retail electric providers and energy efficiency service providers to evaluate the demand reductions and energy savings resulting from time-of-use prices; home-area network devices, such as in-home displays; and other programs facilitated by advanced meters to determine the demand and energy savings from such programs.

(h) Standard offer programs. A utility's standard offer program must be implemented through program rules and standard offer contracts that are consistent with this section. Standard offer contracts will be available to any energy efficiency service provider that satisfies the contract requirements prescribed by the utility under this section and demonstrates that it is capable of managing energy efficiency projects under an electric utility's energy efficiency program.

(i) Market transformation programs. Market transformation programs are strategic efforts, including, but not limited to, program incentive payments and education designed to reduce market barriers for energy efficient technologies and practices. Market transformation programs may be designed to obtain energy savings or peak demand reductions beyond savings that are reasonably expected to be achieved as a result of current compliance levels with existing building codes applicable to new buildings and equipment efficiency standards or standard offer programs. Market transformation programs may also be specifically designed to express support for early adoption, implementation, and enforcement of the most recent version of the International Energy Conservation Code for residential or commercial buildings by local jurisdictions, express support for more effective implementation and enforcement of the state energy code and compliance with the state energy code, and encourage utilization of the types of building components, products, and services required to comply with such energy codes. The existence of federal, state, or local governmental funding for, or encouragement to utilize, the types of building components, products, and services required to comply with such energy codes does not prevent utilities from offering programs to supplement governmental spending and encouragement. Utilities should cooperate with the retail electric providers, and, where possible, leverage existing industry-recognized programs that have the potential to reduce demand and energy consumption in Texas and consider statewide administration where appropriate. Market transformation programs may operate over a period of more than one year and may demonstrate cost-effectiveness over a period longer than one year.

(j) Self-delivered programs. A utility may use internal or external resources to design, administer, and deliver self-delivered programs. The programs must be tailored to the unique characteristics of the utility's service area in order to attract customer and energy efficiency service provider participation. The programs must meet the same cost effectiveness requirements as standard offer and market transformation programs.

(k) Requirements for standard offer, market transformation, and self-delivered programs. A utility's standard offer, market transformation, and self-delivered programs must meet the requirements of this subsection. A utility may conduct information and advertising campaigns to foster participation in standard offer, market transformation, and self-delivered programs.

(1) Standard offer, market transformation, and self-delivered programs:

(A) must describe the eligible customer classes and allocate funding among the classes on an equitable basis;

(B) may offer standard program incentive payments and specify a schedule of payments that are sufficient to meet the goals of the program, which must be consistent with this section, or any revised payment formula adopted by the commission. The program incentive payments may include both payments for energy and demand savings, as appropriate;

(C) must not permit the provision of any product, service, pricing benefit, or alternative terms or conditions to be conditioned upon the purchase of any other good or service from the utility, except that only customers taking transmission and distribution services from a utility can participate in its energy efficiency programs;

(D) must provide for a complaint process that allows:

(i) an energy efficiency service provider to file a complaint with the commission against a utility; and

(ii) a customer to file a complaint with the utility against an energy efficiency service provider;

(E) may permit the use of distributed renewable generation, geothermal, heat pump, solar water heater and combined heat and power technologies, involving installations of ten megawatts or less;

(F) may factor in the estimated level of enforcement and compliance with existing energy codes in determining energy and peak demand savings; and

(G) may require energy efficiency service providers to provide the following:

(i) a description of how the value of any program incentive payment will be passed on to customers;

(ii) evidence of experience and good credit rating;

(iii) a list of references;

(iv) all applicable licenses required under state law and local building codes;

(v) evidence of all building permits required by governing jurisdictions; and

(vi) evidence of all necessary insurance.

(2) Standard offer and self-delivered programs:

(A) must require energy efficiency service providers to identify peak demand and energy savings for each project in the proposals they submit to the utility;

(B) must be neutral with respect to specific technologies, equipment, or fuels. Energy efficiency projects may lead to switching from electricity to another energy source, provided that the energy efficiency project results in overall lower energy costs, lower energy consumption, and the installation of high efficiency equipment. Utilities may not issue program incentive payments for a customer to switch from gas appliances to electric appliances except in connection with the installation of high efficiency combined heating and air conditioning systems;

(C) must require that all projects result in a reduction in purchased energy consumption, or peak demand, or a reduction in energy costs for the end-use customer;

(D) must encourage comprehensive projects incorporating more than one energy efficiency measure;

(E) must be limited to projects that result in consistent and predictable energy or peak demand savings over an appropriate period of time based on the life of the measure; and

(F) may permit a utility to use poor performance, including customer complaints, as a criterion to limit or disqualify an energy efficiency service provider or its affiliate from participating in a program.

(3) A market transformation program must identify:

(A) program goals;

(B) market barriers the program is designed to overcome;

(D) estimated costs and projected energy and capacity savings;

(E) a baseline study that is appropriate in time and geographic region. In establishing a baseline, the study must consider the level of regional implementation and enforcement of any applicable energy code;

(F) program implementation timeline and milestones;

(G) a description of how the program will achieve the transition from extensive market intervention activities toward a largely self-sustaining market;

(H) a method for measuring and verifying savings; and

(I) the period over which savings must be considered to accrue, including a projected date by which the market will be sufficiently transformed so that the program should be discontinued.

(4) A market transformation program must be designed to achieve energy or peak demand savings, or both, and lasting changes in the way energy efficient goods or services are distributed, purchased, installed, or used over a defined period of time. A utility must use fair competitive procedures to select energy efficiency service providers to conduct a market transformation program, and must include in its annual report the justification for the selection of an energy efficiency service provider to conduct a market transformation program on a sole-source basis.

(5) A load-control standard-offer program must not permit an energy efficiency service provider to receive program incentive payments under the program for the same demand reduction benefit for which it is compensated under a capacity-based demand response program conducted by an independent organization, independent system operator, or regional transmission operator. The qualified scheduling entity representing an energy efficiency service provider is not prohibited from receiving revenues from energy sold in ERCOT markets in addition to any program incentive payment for demand reduction offered under a utility load-control standard offer program.

(6) Utilities offering load management programs must work with ERCOT and energy efficiency service providers to identify eligible loads and must integrate such loads into the ERCOT markets to the extent feasible. Such integration must not preclude the continued operation of utility load management programs that cannot be feasibly integrated into the ERCOT markets or that continue to provide separate and distinct benefits.

(l) Energy efficiency plans and reports (EEPR). Each electric utility must file by April 1 of each year an energy efficiency plan and report in a project annually designated for this purpose, as described in this subsection and §25.183(d) of this title. The plan and report must be filed as a searchable pdf document and in Excel format for all included tables, with formulas intact, according to the commission's file format standards in §22.72 of this title (relating to Formal Requisites of Pleadings and Documents to be Filed with the Commission). The utility's plan and report must include a completed attachment based on the commission-prescribed Excel template.

(1) Each electric utility's energy efficiency plan and report must describe how the utility intends to achieve the goals set forth in this section and comply with the other requirements of this section. The plan and report must be based on program years. The plan and report must propose an annual budget sufficient to reach the goals specified in this section.

(2) Each electric utility's plan and report must include:

(A) the utility's total actual and weather-adjusted peak demand and actual and weather-adjusted peak demand for residential and commercial customers for the previous five years, measured at the source;

(B) the demand goal calculated in accordance with this section for the current year and the following year, including documentation of the demand, weather adjustments, and the calculation of the goal;

(C) the utility's customers' total actual and weather-adjusted energy consumption and actual and weather-adjusted energy consumption for residential and commercial customers for the previous five years;

(D) the energy goal calculated in accordance with this section, including documentation of the energy consumption, weather adjustments, and the calculation of the goal;

(E) a description of existing energy efficiency programs and an explanation of the extent to which these programs will be used to meet the utility's energy efficiency goals;

(F) a description of each of the utility's energy efficiency programs that were not included in the previous year's plan, including measurement and verification plans if appropriate, and any baseline studies and research reports or analyses supporting the value of the new programs;

(G) an estimate of the energy and peak demand savings to be obtained through each separate energy efficiency program;

(H) a description of the customer classes targeted by the utility's energy efficiency programs, specifying the size of the hard-to-reach, residential, and commercial classes, and the methodology used for estimating the size of each customer class;

(I) the proposed annual budget required to implement the utility's energy efficiency programs, broken out by program for each customer class, including hard-to-reach customers, and any set-asides or budget restrictions adopted or proposed in accordance with this section. The proposed budget must detail the program incentive payments and utility administrative costs, including specific items for research and information and outreach to energy efficiency service providers, and other major administrative costs, and the basis for estimating the proposed expenditures;

(J) a discussion of the types of informational activities the utility plans to use to encourage participation by customers, energy efficiency service providers, and retail electric providers to participate in energy efficiency programs, including the manner in which the utility will provide notice of energy efficiency programs, and any other facts that may be considered when evaluating a program;

(K) the utility's performance in achieving its energy goal and demand goal for the prior five years, as reported in annual energy efficiency reports filed in accordance with this section;

(L) a comparison of projected savings (energy and demand), reported savings, and verified savings for each of the utility's energy efficiency programs for the prior two years;

(M) a description of the results of any market transformation program, including a comparison of the baseline and actual results and any adjustments to the milestones for a market transformation program;

(N) a description of self-delivered programs;

(O) expenditures for the prior five years for energy and demand program incentive payments and program administration, by program and customer class;

(P) funds that were committed but not spent during the prior year, by program;

(Q) a comparison of actual and budgeted program costs, including an explanation of any increase or decreases of more than 10% in the cost of a program;

(R) information relating to energy and demand savings achieved and the number of customers served by each program by customer class;

(S) the utility's most recent EECRF, the revenue collected through the EECRF, the utility's forecasted annual energy efficiency program expenditures in excess of the actual energy efficiency revenues collected from base rates as described in §25.182(d)(2) of this title, and the control number under which the most recent EECRF was established;

(T) the amount of any over- or under-recovery of energy efficiency program costs whether collected through base rates or the EECRF;

(U) a list of any counties that in the prior year were under-served by the energy efficiency program;

(V) a description of new or discontinued programs, including pilot programs that are planned to be continued as full programs. For programs that are to be introduced or pilot programs that are to be continued as full programs, the description must include the budget and projected demand and energy savings;

(W) a link to the program manuals for the current program year; and

(X) the calculations supporting the adjustments to restate the demand goal from the source to the meter and to restate the energy efficiency savings from the meter to the source.

(m) Review of programs. Commission staff may initiate a proceeding to review a utility's energy efficiency programs. In addition, an interested entity may request that the commission initiate a proceeding to review a utility's energy efficiency programs.

(n) Inspection, measurement and verification. Each standard offer, market transformation, and self-delivered program must include use of an industry-accepted evaluation or measurement and verification protocol, such as the International Performance Measurement and Verification Protocol or a protocol approved by the commission, to document and verify energy and peak demand savings to ensure that the goals of this section are achieved. A utility must not provide an energy efficiency service provider final compensation until the provider establishes that the work is complete and evaluation or measurement and verification in accordance with the protocol verifies that the savings will be achieved. However, a utility may provide an energy efficiency service provider that offers behavioral programs incremental compensation as work is performed. If inspection of one or more measures is a part of the protocol, a utility must not provide an energy efficiency service provider final compensation until the utility has conducted its inspection on at least a sample of measures and the inspections confirm that the work has been done. A utility must provide inspection reports to commission staff within 20 days of staff's request.

(1) The energy efficiency service provider, or for self-delivered programs, the utility, is responsible for the determination and documentation of energy and peak demand savings using the approved evaluation and/or measurement and verification protocol, and may utilize the services of an independent third party for such purposes.

(2) Commission-approved deemed energy and peak demand savings may be used in lieu of the energy efficiency service provider's measurement and verification, where applicable. The deemed savings approved by the commission before December 31, 2007 are continued in effect, unless superseded by commission action.

(3) Where installed measures are employed, an energy efficiency service provider must verify that the measures contracted for were installed before final payment is made to the energy efficiency service provider, by obtaining the customer's signature certifying that the measures were installed, or by other reasonably reliable means approved by the utility.

(4) For projects involving over 30 installations, a statistically significant sample of installations will be subject to on-site inspection in accordance with the protocol for the project to verify that measures are installed and capable of performing their intended function. Inspection must occur within 30 days of notification of measure installation.

(5) Projects of less than 30 installations may be aggregated and a statistically significant sample of the aggregate installations will be subject to on-site inspection in accordance with the protocol for the projects to ensure that measures are installed and capable of performing their intended function. Inspection must occur within 30 days of notification of measure installation.

(6) Where installed measures are employed, the sample size for on-site inspections may be adjusted for an energy efficiency service provider under a particular contract, based on the results of prior inspections.

(o) Evaluation, measurement, and verification (EM&V). The following defines the evaluation, measurement, and verification (EM&V) framework. The goal of this framework is to ensure that the programs are evaluated, measured, and verified using a consistent process that allows for accurate estimation of energy and demand impacts.

(1) EM&V objectives include:

(A) Documenting the impacts of the utilities' individual energy efficiency and load management portfolios, comparing their performance with established goals, and determining cost-effectiveness;

(B) Providing feedback for the commission, commission staff, utilities, and other stakeholders on program portfolio performance; and

(2) The principles that guide the EM&V activities in meeting the primary EM&V objectives are:

(A) Evaluators follow ethical guidelines.

(B) Important and relevant assumptions used by program planners and administrators are reviewed as part of the EM&V efforts.

(C) All important and relevant EM&V assumptions and calculations are documented and the reliability of results is indicated in evaluation reports.

(D) The majority of evaluation expenditures and efforts are in areas of greatest importance or uncertainty.

(3) The commission must select an entity to act as the commission's EM&V contractor and conduct evaluation activities. The EM&V contractor must operate under the commission's supervision and oversight, and the EM&V contractor must offer independent analysis to the commission in order to assist in making decisions in the public interest.

(A) Under the oversight of the commission staff and with the assistance of utilities and other parties, the EM&V contractor will evaluate specific programs and the portfolio of programs for each utility.

(B) The EM&V contractor must have the authority to request data it considers necessary to fulfill its evaluation, measurements, and verification responsibilities from the utilities. A utility must make good faith efforts to provide complete, accurate, and timely responses to all EM&V contractor requests for documents, data, information and other materials. The commission may on its own volition or upon recommendation by staff require that a utility provide the EM&V contractor with specific information.

(4) Evaluation activities will be conducted by the EM&V contractor to meet the evaluation objectives defined in this section. Activities must include, but are not limited to:

(A) Providing appropriate planning documents.

(B) Impact evaluations to determine and document appropriate metrics for each utility's individual evaluated programs and portfolio of all programs, annual portfolio evaluation reports, and additional reports and services as defined by commission staff to meet the EM&V objectives.

(C) Preparation of a statewide technical reference manual (TRM), including updates to such manual as defined in this subsection.

(5) The impact evaluation activities may include the use of one or more evaluation approaches. Evaluation activities may also include, or just include, verification activities on a census or sample of projects implemented by the utilities. Evaluations may also include the use of due-diligence on utility-provided documentation as well as surveys of program participants, non-participants, contractors, vendors, and other market actors.

(6) The following apply to the development of a statewide TRM by the EM&V contractor.

(A) The EM&V contractor must use existing Texas, or other state, deemed savings manual(s), protocols, and the work papers used to develop the values in the manual(s), as a foundation for developing the TRM. The TRM must include applicability requirements for each deemed savings value or deemed savings calculation. The TRM may also include standardized EM&V protocols for determining or verifying energy and demand savings for particular measures or programs. Utilities may apply TRM deemed savings values or deemed savings calculations to a measure or program if the applicability criteria are met.

(B) The TRM must be reviewed by the EM&V contractor at least annually, under a schedule determined by commission staff, with the intention of preparing an updated TRM, if needed. In addition, any utility or other stakeholder may request additions to or modifications to the TRM at any time with the provision of documentation for the basis of such an addition or modification. At the discretion of commission staff, the EM&V contractor may review such documentation to prepare a recommendation with respect to the addition or modification.

(C) Commission staff must approve any updated TRMs through the energy efficiency implementation project. The approval process for any TRM additions or modifications, not made during the regular review schedule determined by commission staff, must include a review by commission staff to determine if an addition or modification is appropriate before an annual update. TRM changes approved by staff may be challenged only by the filing of a petition within 45 days of the date that staff's approval is filed in the commission's central records under the control number for the energy efficiency implementation project described by subsection (d)(2)(A) of this section. The petition must clearly describe the reasons commission staff should not have approved the TRM changes, include supporting data and calculations, and state the relief sought.

(D) Any changes to the TRM must be applied prospectively to programs offered in the appropriate program year.

(E) The TRM must be publicly available.

(F) Utilities must utilize the values contained in the TRM, unless the commission indicates otherwise.

(i) For program year 2026, a utility must estimate a peak period using the calculation method contained in the TRM adopted in November 2025.

(ii) Starting with program year 2027, a utility must estimate a peak period using the calculation method contained in the most recently adopted TRM.

(7) The utilities must prepare projected savings estimates and claimed savings estimates. The utilities must conduct their own EM&V activities for purposes such as confirming any program incentive payments to customers or contractors and preparing documentation for internal and external reporting, including providing documentation to the EM&V contractor. The EM&V contractor must prepare evaluated savings for preparation of its evaluation reports and a realization rate comparing evaluated savings with projected savings estimates or claimed savings estimates.

(8) Baselines for preparation of TRM deemed savings values or deemed savings calculations or for other evaluation activities must be defined by the EM&V contractor and commission staff must review and approve them. When common practice baselines are defined for determining gross energy or demand savings for a measure or program, common practice may be documented by market studies. Baselines must be defined by measure category as follows (deviations from these specifications may be made with justification and approval of commission staff):

(A) Baseline is existing conditions for the estimated remaining lifetime of existing equipment for early replacement of functional equipment still within its current useful life. Baseline is applicable code, standard or common practice for remaining lifetime of the measure past the estimated remaining lifetime of existing equipment;

(B) Baseline is applicable code, standard or common practice for replacement of functional equipment beyond its current useful life;

(D) Baseline is applicable code, standard or common practice for new construction or major tenant improvements.

(9) Relevant recommendations of the EM&V contractor related to program design and reporting should be addressed in the Energy Efficiency Implementation Project (EEIP) and considered for implementation in future program years. The commission may require a utility to implement the EM&V contractor's recommendations in a future program year.

(10) The utilities must be assigned the EM&V costs in proportion to their annual program costs and must pay the invoices approved by the commission. The commission must at least biennially review the EM&V contractor's costs and establish a budget for its services sufficient to pay for those services that it determines are economic and beneficial to be performed.

(A) The funding of the EM&V contractor must be sufficient to ensure the selection of an EM&V contractor in accordance with the scope of EM&V activities outlined in this subsection.

(B) EM&V costs must be itemized in the utilities' annual reports to the commission as a separate line item. The EM&V costs must not count against the utility's cost caps or administration spending caps.

(11) For the purpose of analysis, the utility must grant the EM&V contractor access to data maintained in the utilities' data tracking systems, including, but not limited to, the following proprietary customer information: customer identifying information, individual customer contracts, and load and usage data in accordance with §25.272(g)(1)(A) of this title (relating to Code of Conduct for Electric Utilities and Their Affiliates). Such information must be treated as confidential information.

(A) The utility must maintain records for three years that include the date, time, and nature of proprietary customer information released to the EM&V contractor.

(B) The EM&V contractor must aggregate data in such a way as to protect customer, retail electric provider, and energy efficiency service provider proprietary information in any non-confidential reports or filings the EM&V contractor prepares.

(C) The EM&V contractor must not utilize data provided or received under commission authority for any purposes outside the authorized scope of work the EM&V contractor performs for the commission.

(D) The EM&V contractor providing services under this section must not release any information it receives related to the work performed unless directed to do so by the commission.

(p) Targeted low-income energy efficiency program.

(1) Each unbundled transmission and distribution utility must include at least one targeted low-income energy efficiency program in its energy efficiency plan, and a utility in an area in which customer choice is not offered may include a targeted low-income energy efficiency program in its energy efficiency plan.

(A) Savings achieved by the program must count toward the utility's energy efficiency goal.

(B) A utility's targeted low-income program must incorporate a whole-house assessment that will evaluate all applicable energy efficiency measures for which there are commission-approved deemed savings. The cost-effectiveness of measures eligible to be installed and the overall program must be evaluated using the Savings-to-Investment ratio.

(C) Any funds that are not obligated after July of a program year may be made available for use in a hard-to-reach program. However, such funds may not be used to satisfy the expenditure requirement under paragraph (2)(A) of this subsection.

(D) Demand reduction achieved through a targeted low-income energy efficiency program may not be used to satisfy the hard-to-reach demand reduction requirement under subsection (e)(3)(F) of this section.

(2) Elements of the targeted low-income energy efficiency program required only for unbundled transmission and distribution utilities.

(A) Annual expenditures for a targeted low-income energy efficiency program must be at least 10% of the utility's energy efficiency budget for the program year.

(B) The targeted low-income energy efficiency program must comply with requirements listed in PURA §39.905(f):

(i) a targeted low-income energy efficiency program must comply with the same audit requirements that apply to federal weatherization subrecipients;

(ii) the Texas Department of Housing and Community Affairs must participate in an energy efficiency cost recovery factor proceeding related to expenditures under this subsection to ensure that a targeted low-income energy efficiency program is consistent with federal weatherization programs and adequately funded; and

(ii) in an energy efficiency cost recovery factor proceeding related to expenditures under this subsection, the commission will make findings of fact regarding whether the utility meets requirements as described in this subsection.

(q) Energy Efficiency Implementation Project - EEIP. The commission will use the EEIP to develop best practices in standard offer market transformation, self-directed, pilot, or other programs, modifications to programs, standardized forms and procedures, protocols, deemed savings estimates, program templates, and the overall direction of the energy efficiency program established by this section. Utilities must provide timely responses to questions posed by other participants relevant to the tasks of the EEIP. Any recommendations from the EEIP process must relate to future years as described in this subsection.

(1) The following functions may also be undertaken in the EEIP:

(A) development, discussion, and review of new statewide standard offer programs;

(B) identification, discussion, design, and review of new market transformation programs;

(C) determination of measures for which deemed savings are appropriate and participation in the development of deemed savings estimates for those measures;

(D) review of and recommendations on the commission EM&V contractor's reports;

(E) review of and recommendations on program incentive payment levels and their adequacy to induce the desired level of participation by energy efficiency service providers and customers;

(F) review of and recommendations on a utility's annual energy efficiency plans and reports;

(G) utility program portfolios and proposed energy efficiency spending levels for future program years;

(H) periodic reviews of the cost-effectiveness methodology; and

(I) other activities as identified by commission staff.

(2) The EEIP projects must be conducted by commission staff. The commission's EM&V contractor's reports must be filed in the project at a date determined by commission staff.

(3) A utility that intends to launch a program that is substantially different from other programs previously implemented by any utility affected by this section must file a program template and must provide notice of such to EEIP participants. Notice to EEIP participants need not be provided if a program description or program template for the new program is provided through the utility's annual energy efficiency report. Following the first year in which a program was implemented, the utility must include the program results in the utility's annual energy efficiency report.

(4) Participants in the EEIP may submit comments and reply comments in the EEIP on dates established by commission staff.

(5) Any new programs or program redesigns must be submitted to the commission in a petition in a separate proceeding. The approved changes must be available for use in the utilities' next EEPR and EECRF filings. If the changes are not approved by the commission by November 1 in a particular year, the first time that the changes must be available for use is the second EEPR and EECRF filings made after commission approval.

(6) Any interested entity that participates in the EEIP may file a petition to the commission for consideration regarding changes to programs.

(r) Retail providers. Each utility in an area in which customer choice is offered must conduct outreach and information programs and otherwise use its best efforts to encourage and facilitate the involvement of retail electric providers as energy efficiency service companies in the delivery of efficiency and demand response programs.

(s) Customer protection. Each energy efficiency service provider that provides energy efficiency services to end-use customers under this section must provide the disclosures and include the contractual provisions required by this subsection, except for commercial customers with a peak load exceeding 50 kW. Paragraph (1) of this subsection does not apply to behavioral energy efficiency programs that do not require a contract with a customer.

(1) Clear disclosure to the customer must be made of the following:

(A) the customer's right to a cooling-off period of three business days, in which the contract may be canceled, if applicable under law;

(B) the name, telephone number, and street address of the energy efficiency service provider and any subcontractor that will be performing services at the customer's home or business;

(C) the fact that program incentive payments are made to the energy efficiency services provider through a program funded by utility customers, manufacturers or other entities and the amount of any program incentives provided by the utility;

(D) the amount of any program incentive payment that will be provided to the customer;

(E) notice of provisions that will be included in the customer's contract, including warranties;

(F) the fact that the energy efficiency service provider must measure and report to the utility the energy and peak demand savings from installed energy efficiency measures;

(G) the liability insurance to cover property damage carried by the energy efficiency service provider and any subcontractor;

(H) the financial arrangement between the energy efficiency service provider and customer, including an explanation of the total customer payments, the total expected interest charged, all possible penalties for non-payment, and whether the customer's installment sales agreement may be sold;

(I) the fact that the energy efficiency service provider is not part of or endorsed by the commission or the utility; and

(J) a description of the complaint procedure established by the utility under this section, and toll-free numbers for the Consumer Protection Division of the Public Utility Commission of Texas, and the Office of Attorney General's Consumer Protection Hotline.

(2) The energy efficiency service provider's contract with the customer, where such a contract is employed, must include:

(A) work activities, completion dates, and the terms and conditions that protect residential customers in the event of non-performance by the energy efficiency service provider;

(B) provisions prohibiting the waiver of consumer protection statutes, performance warranties, false claims of energy savings and reductions in energy costs;

(C) a disclosure notifying the customer that consumption data may be disclosed to the EM&V contractor for evaluation purposes; and

(D) a complaint procedure to address performance issues by the energy efficiency service provider or a subcontractor.

(3) When an energy efficiency service provider completes the installation of measures for a customer, it must provide the customer an "All Bills Paid" affidavit to protect against claims of subcontractors.

(t) Grandfathered programs. An electric utility that offered a load management standard offer program for industrial customers prior to May 1, 2007 must continue to make the program available, at 2007 funding and participation levels, and may include additional customers in the program to maintain these funding and participation levels.

(u) Industrial customer opt-out. An industrial customer taking electric service at distribution voltage may submit a notice identifying the distribution accounts for which it qualifies under subsection (c)(20) of this section. The identification notice must be submitted directly to the customer's utility. An identification notice submitted under this section must be renewed every three years. Each identification notice must include the name of the industrial customer, a copy of the customer's Texas Sales and Use Tax Exemption Certification (under Tax Code §151.317), a description of the industrial process taking place at the consuming facilities, and the customer's applicable account number or ESID number. The identification notice is limited solely to the metered point of delivery of the industrial process taking place at the consuming facilities. The account number or ESID number identified by the industrial customer under this section must not be charged for any costs associated with programs provided under this section, including any utility incentive awarded; nor must the identified facilities be eligible to participate in utility-administered energy efficiency programs during the term. Notices must be submitted not later than February 1 to be effective for the following program year. A utility's demand reduction goal must be adjusted to remove any load that is lost as a result of this subsection.

(v) Administrative penalty. The commission may impose an administrative penalty or other sanction if the utility fails to meet a goal for energy efficiency under this section. Factors, to the extent they are outside of the utility's control, that may be considered in determining whether to impose a sanction for the utility's failure to meet the goal include:

(1) the level of demand by retail electric providers and energy efficiency service providers for program incentive payments made by the utility through its programs;

(2) changes in building energy codes; and

(3) changes in government-imposed appliance or equipment efficiency standards.

§25.182. Energy Efficiency Cost Recovery Factor.

(a) Purpose. The purpose of this section is to implement Public Utility Regulatory Act (PURA) §39.905 and establish:

(1) an energy efficiency cost recovery factor (EECRF) that enables an electric utility to timely recover the reasonable costs of providing a portfolio of cost-effective energy efficiency programs that complies with this section and §25.181 of this title (relating to Energy Efficiency Goal).

(2) a utility incentive to reward an electric utility that exceeds its demand and energy reduction goals under the requirements of §25.181 of this title at a cost that does not exceed the cost caps established in subsection (d)(7) of this section.

(b) Application. This section applies to electric utilities.

(c) Definitions. The definitions provided in §25.181(c) of this title also apply in this section. The following terms, when used in this section, have the following meaning unless the context indicates otherwise:

(1) Billing determinants--The measures of energy consumption or load used to calculate a customer's bill or to determine the aggregate revenue from rates from all customers.

(2) Rate class--For the purpose of calculating EECRF rates, a utility's rate classes are those retail rate classes approved in the utility's most recent base-rate proceeding, excluding non-eligible customers.

(d) Cost recovery. A utility must establish an EECRF that complies with this subsection to timely recover the reasonable costs of providing a portfolio of cost-effective energy efficiency programs under §25.181 of this title. Each utility must file its application according to the commission's file format standards in §22.72 of this title (relating to Formal Requisites of Pleadings and Documents to be Filed with the Commission).

(1) The EECRF must be calculated based on the following:

(A) The utility's forecasted annual energy efficiency program expenditures, the preceding year's over- or under-recovery including interest and municipal and utility EECRF proceeding expenses, any utility incentive earned under subsection (e) of this section, and evaluation, measurement, and verification (EM&V) contractor costs allocated to the utility by the commission for the preceding year under §25.181 of this title.

(B) For a utility that collects any amount of energy efficiency costs in its base rates, the amounts described in subparagraph (A) of this paragraph in excess of the actual energy efficiency revenues collected from base rates as described in paragraph (2) of this subsection.

(2) The commission may approve an EECRF for each eligible rate class. The costs must be directly assigned to each rate class that received services under the programs to the maximum extent reasonably possible. In its EECRF proceeding, a utility may request a good cause exception to combine one or more rate classes, each containing fewer than 20 customers, with a similar rate class that received services under the same energy efficiency programs in the preceding year. For each rate class, the under- or over-recovery of the energy efficiency costs must be the difference between actual EECRF revenues and actual costs for that class that comply with paragraph (12) of this subsection, including interest applied on such over- or under-recovery calculated by rate class and compounded on an annual basis for a two-year period using the annual interest rates authorized by the commission for over- and under-billing for the year in which the over- or under-recovery occurred and the immediately subsequent year. Where a utility collects energy efficiency costs in its base rates, actual energy efficiency revenues collected from base rates consist of the amount of energy efficiency costs expressly included in base rates, adjusted to account for changes in billing determinants from the test year billing determinants used to set rates in the last base rate proceeding.

(3) A proceeding conducted under this subsection is a ratemaking proceeding for purposes of PURA §33.023 and §36.061. EECRF proceeding expenses must be included in the EECRF calculated under paragraph (1) of this subsection as follows:

(A) For a utility's EECRF proceeding expenses, the utility may include only its expenses for the immediately previous EECRF proceeding conducted under this subsection.

(B) For municipalities' EECRF proceeding expenses, the utility may include only expenses paid or owed for the immediately previous EECRF proceeding conducted under this subsection for services reimbursable under PURA §33.023(b).

(4) Base rates must not be set to recover energy efficiency costs.

(5) If a utility recovers energy efficiency costs through base rates, the EECRF may be changed in a general rate proceeding. If a utility is not recovering energy efficiency costs through base rates, the EECRF may be adjusted only in an EECRF proceeding under this subsection.

(6) For residential customers and for non-residential rate classes whose base rates do not provide for demand charges, the EECRF rates must be designed to provide only for energy charges. For non-residential rate classes whose base rates provide for demand charges, the EECRF rates must provide for energy charges or demand charges, but not both. Any EECRF demand charge must not be billed using a demand ratchet mechanism.

(7) The total EECRF costs outlined in paragraph (1) of this subsection, excluding EM&V costs, excluding municipal EECRF proceeding expenses, and excluding any interest amounts applied to over- or under-recoveries, must not exceed the amounts prescribed in this paragraph unless a good cause exception filed under §25.181(e)(2) of this title is granted.

(A) For residential customers for program year 2018, $0.001263 per kWh increased or decreased by a rate equal to the 2016 calendar year's percentage change in the South urban consumer price index (CPI), as determined by the Federal Bureau of Labor Statistics; and

(B) For commercial customers for program year 2018, rates designed to recover revenues equal to $0.000790 per kWh increased or decreased by a rate equal to the 2016 calendar year's percentage change in the South urban CPI, as determined by the Federal Bureau of Labor Statistics times the aggregate of all eligible commercial customers' kWh consumption.

(C) For the 2019 program year and thereafter, the residential and commercial cost caps must be calculated to be the prior period's cost caps increased or decreased by a rate equal to the most recently available calendar year's percentage change in the South urban CPI, as determined by the Federal Bureau of Labor Statistics.

(8) Not later than May 1 of each year, a utility in an area in which customer choice is not offered must apply to adjust its EECRF effective January 1 of the following year. Not later than June 1 of each year, a utility in an area in which customer choice is offered must apply to adjust its EECRF effective March 1 of the following year. If a utility is in an area in which customer choice is offered in some but not all parts of its service area and files one energy efficiency plan and report covering all of its service area, the utility must apply to adjust the EECRF not later than May 1 of each year, with the EECRF effective January 1 in the parts of its service area in which customer choice is not offered and March 1 in the parts of its service area in which customer choice is offered.

(9) Upon a utility's filing of an application to establish a new EECRF or adjust an EECRF, the presiding officer must set a procedural schedule that will enable the commission to issue a final order in the proceeding required by subparagraphs (A), (B), and (C) of this paragraph as follows:

(A) For a utility in an area in which customer choice is not offered, the presiding officer must set a procedural schedule that will enable the commission to issue a final order in the proceeding prior to the January 1 effective date of the new or adjusted EECRF, except where good cause supports a different procedural schedule.

(B) For a utility in an area in which customer choice is offered, the effective date of a new or adjusted EECRF must be March 1. The presiding officer must set a procedural schedule that will enable the utility to file an EECRF compliance tariff consistent with the final order within ten days of the date of the final order. The procedural schedule must also provide that the compliance filing date will be at least 45 days before the effective date of March 1. The effective date of any new or adjusted EECRF must occur at least 45 days after the utility files a compliance tariff consistent with a final order approving the new or adjusted EECRF. The utility must serve notice of the approved rates and the effective date of the approved rates by the working day after the utility files a compliance tariff consistent with the final order approving the new or adjusted EECRF to retail electric providers that are authorized by the registration agent to provide service in the utility's service area. Notice under this subparagraph may be served by email. The procedural schedule may be extended for good cause, but the effective date of any new or adjusted EECRF must occur at least 45 days after the utility files a compliance tariff consistent with a final order approving the new or adjusted EECRF. The utility may not serve notice of the approved rates and the effective date of the approved rates to retail electric providers that are authorized by the registration agent to provide service in the utility's service area more than one working day after the utility files the compliance tariff.

(C) For a utility in an area in which customer choice is offered in some but not all parts of its service area and that files one energy efficiency plan and report covering all of its service area, the presiding officer must set a procedural schedule that will enable the commission to issue a final order in the proceeding prior to the January 1 effective date of the new or adjusted EECRF for the areas in which customer choice is not offered, except where good cause supports a different schedule. For areas in which customer choice is offered, the effective date of the new or adjusted EECRF must be March 1. The presiding officer must set a procedural schedule that will enable the utility to file an EECRF compliance tariff consistent with the final order within ten days of the date of the final order. The procedural schedule must also provide that the compliance filing date will be at least 45 days before the effective date of March 1. The effective date of any new or adjusted EECRF must occur at least 45 days after the utility files a compliance tariff consistent with a final order approving the new or adjusted EECRF. The utility must serve notice of the approved rates and the effective date of the approved rates by the working day after the utility files a compliance tariff consistent with the final order approving the new or adjusted EECRF to retail electric providers that are authorized by the registration agent to provide service in the utility's service area. Notice under this subparagraph of this paragraph may be served by email. The procedural schedule may be extended for good cause, but the effective date of any new or adjusted EECRF must occur at least 45 days after the utility files a compliance tariff consistent with a final order approving the new or adjusted EECRF. The utility may not serve notice of the approved rates and the effective date of the approved rates to retail electric providers that are authorized by the registration agent to provide service in the utility's service area more than one working day after the utility files the compliance tariff.

(D) If no hearing is requested within 30 days of the filing of the application, the presiding officer must set a procedural schedule that will enable the commission to issue a final order in the proceeding within 90 days after a sufficient application was filed; or

(E) If a hearing is requested within 30 days of the filing of the application, the presiding officer must set a procedural schedule that will enable the commission to issue a final order in the proceeding within 180 days after a sufficient application was filed. If a hearing is requested, the hearing will be held no earlier than the first working day after the 45th day after a sufficient application is filed.

(10) A utility's application to establish or adjust an EECRF must include the utility's most recent energy efficiency plan and report, consistent with §25.181(l) and §25.183(d) of this title, as well as testimony and schedules, in Excel format with formulas intact, showing the following, by rate class, for the prior program year and the program year for which the proposed EECRF will be collected as appropriate:

(A) the utility's forecasted energy efficiency costs;

(B) the actual base rate recovery of energy efficiency costs, adjusted for changes in load and usage subsequent to the last base rate proceeding, with supporting calculations;

(C) a calculation showing whether the utility qualifies for a utility incentive and the amount that it calculates to have earned for the prior year;

(D) any adjustment for past over- or under-recovery of energy efficiency revenues, including interest;

(E) information concerning the calculation of billing determinants for the preceding year and for the year in which the EECRF is expected to be in effect;

(F) the direct assignment and allocation of energy efficiency costs to the utility's eligible rate classes, including any portion of energy efficiency costs included in base rates, provided that the utility's actual EECRF expenditures by rate class may deviate from the projected expenditures by rate class, to the extent doing so does not exceed the cost caps in paragraph (7) of this subsection;

(G) information concerning calculations related to the requirements of paragraph (7) of this subsection;

(H) the program incentive payments by the utility, by program, including a list of each energy efficiency administrator or service provider receiving more than 5% of the utility's overall program incentive payments and the percentage of the utility's program incentive payments received by those providers. Such information may be treated as confidential;

(I) the utility's administrative costs, including any affiliate costs and EECRF proceeding expenses and an explanation of both;

(J) the actual EECRF revenues by rate class for any period for which the utility calculates an under- or over-recovery of EECRF costs;

(K) the utility's bidding and engagement process for contracting with energy efficiency service providers, including a list of all energy efficiency service providers that participated in the utility programs and contractors paid with funds collected through the EECRF. Such information may be treated as confidential;

(L) the estimated useful life used for each measure in each program, or a link to the information if publicly available; and

(M) any other information that supports the determination of the EECRF.

(11) The following factors must be included in the application, as applicable, to support the recovery of energy efficiency costs under this subsection.

(A) the costs are less than or equal to the benefits of the programs, as calculated in §25.181(d) of this title;

(B) the program portfolio was implemented in accordance with recommendations made by the commission's EM&V contractor and approved by the commission and the EM&V contractor has found no material deficiencies in the utility's administration of its portfolio of energy efficiency programs under §25.181 of this title. This subparagraph does not preclude parties from examining and challenging the reasonableness of a utility's energy efficiency program expenses nor does it limit the commission's ability to address the reasonableness of a utility's energy efficiency program expenses;

(C) if a utility is in an area in which customer choice is offered and is subject to the requirements of PURA §39.905(f), the utility met its targeted low-income energy efficiency requirements under §25.181 of this title;

(D) existing market conditions in the utility's service territory affected its ability to implement one or more of its energy efficiency programs or affected its costs;

(E) the utility's costs incurred and achievements accomplished in the previous year or estimated for the year the requested EECRF will be in effect are consistent with the utility's energy efficiency program costs and achievements in previous years notwithstanding any recommendations or comments by the EM&V contractor;

(F) changed circumstances in the utility's service area since the commission approved the utility's budget for the implementation year that affect the ability of the utility to implement any of its energy efficiency programs or its energy efficiency costs;

(G) the number of energy efficiency service providers operating in the utility's service territory affects the ability of the utility to implement any of its energy efficiency programs or its energy efficiency costs;

(H) customer participation in the utility's prior years' energy efficiency programs affects customer participation in the utility's energy efficiency programs in previous years or its proposed programs underlying its EECRF request and the extent to which program costs were expended to generate more participation or transform the market for the utility's programs;

(I) the utility's energy efficiency costs for the previous year or estimated for the year the requested EECRF will be in effect are comparable to costs in other markets with similar conditions; and

(J) the utility has set its program incentive payments with the objective of achieving its energy and demand goals under §25.181 of this title at the lowest reasonable cost per program.

(12) The scope of an EECRF proceeding includes the extent to which the costs recovered through the EECRF complied with PURA §39.905, this section, and §25.181 of this title; the extent to which the costs recovered were reasonable and necessary to reduce demand and energy growth; and a determination of whether the costs to be recovered through an EECRF are reasonable estimates of the costs necessary to provide energy efficiency programs and to meet or exceed the utility's energy efficiency goals. The proceeding will not include a review of program design to the extent that the programs complied with the energy efficiency implementation project (EEIP) process defined in §25.181(q) of this title. The commission will not allow recovery of expenses that are designated as non-recoverable under §25.231(b)(2) of this title (relating to Cost of Service).

(13) Notice of a utility's filing of an EECRF application is reasonable if the utility provides in writing a general description of the application and the docket number assigned to the application within seven days of the application filing date to:

(A) All parties in the utility's most recent completed EECRF docket;

(B) All retail electric providers that are authorized by the registration agent to provide service in the utility's service area at the time the EECRF application is filed;

(D) The state agency that administers the federal weatherization program.

(14) The utility must file an affidavit attesting to the completion of notice within 14 days after the application is filed.

(15) The commission may approve a utility's request to establish an EECRF revenue requirement or EECRF rates that are lower than the amounts otherwise determined under this section.

(e) Utility incentive. To receive a utility incentive, a utility must exceed its demand and energy reduction goals established in §25.181 of this title at a cost that does not exceed the cost caps established in subsection (d)(7) of this section. The utility incentive must be based on the utility's energy efficiency achievements for the previous program year. The utility incentive calculation must not include demand or energy savings that result from programs other than programs implemented under §25.181 of this title.

(1) The utility incentive allows a utility to receive a share of the net benefits realized in exceeding its demand reduction goal established according to §25.181 of this title.

(2) Net benefits are calculated as the sum of total avoided cost associated with the eligible programs administered by the utility minus the sum of all program costs. Program costs include the cost of program incentive payments, incurred EM&V contractor costs, any utility incentive awarded to the utility, and actual or allocated research and development and administrative costs, but do not include any interest amounts applied to over- or under-recoveries. Total avoided costs and program costs must be calculated in accordance with this section and §25.181 of this title.

(3) If a utility exceeds 100% of its demand and energy reduction goals, it will receive a utility incentive. The utility incentive is calculated as 1% of the applicable program year's net benefits for every 2% that the demand reduction goal has been exceeded, with a maximum of 5% of the utility's total net benefits.

(4) The commission may reduce the utility incentive otherwise permitted under this subsection for a utility with a lower goal, higher administrative spending cap, or higher EECRF cost cap established by the commission under §25.181(e)(2) of this title. The utility incentive will be considered in the EECRF proceeding in which the utility incentive is requested.

(5) In calculating net benefits to determine a utility incentive, a discount rate equal to the utility's weighted average cost of capital of the utility and an escalation rate of 2% must be used. The utility must provide documentation for the net benefits calculation, including, but not limited to, the weighted average cost of capital, useful life of equipment or measure, and quantity of each measure implemented.

(6) The utility incentive must be allocated in proportion to the program costs associated with meeting the demand and energy goals under §25.181 of this title and allocated to eligible customers on a rate class basis.

(7) A utility incentive earned under this section must not be included in the utility's revenues or net income for the purpose of establishing a utility's rates or commission assessment of its earnings.

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 December 12, 2025.

TRD-202504615

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 1, 2026

Proposal publication date: September 5, 2025

For further information, please call: (512) 936-7244

SUBCHAPTER C. INFRASTRUCTURE AND RELIABILITY

16 TAC §25.53

The Public Utility Commission of Texas (commission) adopted amendments to 16 Texas Administrative Code (TAC) §25.53, relating to Electric Service Emergency Operations Plans with changes to the proposed text as published in the September 5, 2025 issue of the Texas Register (50 TexReg 5849). The amended rule requires each entity that submits an Emergency Operations Plan (EOPs) to comply with an executive summary template, include a comprehensive list of generation assets in its executive summaries, file flood annexes for transmission and distribution facilities and generation resources, file annexes in their entirety, and comprehensively re-file its EOP every three years. The amended rule additionally clarifies how an EOP should be made available to commission staff and makes other minor changes. The rule will be republished.

The commission received comments about this project from AEP Texas Inc., Electric Transmission Texas, LLC, and Southwestern Electric Power Company (AEP Companies), CenterPoint Energy Houston Electric (CenterPoint), City of Houston (Houston), El Paso Electric (EPE), Entergy Texas, Inc. (Entergy), Lower Colorado River Authority and LCRA Transmission Services Corporation (LCRA), Oncor Electric Delivery Company LLC (Oncor), Southwestern Public Service Company (SPS), Texas Competitive Power Advocates (TCPA), Texas Energy Association for Marketers (TEAM), Texas Electric Cooperatives, Inc. (TEC), and Texas Public Power Association (TPPA). The commission adopts the rule with changes to the proposal.

The commission invited interested persons to address one question related to the proposed rule.

Question One

To further assist the commission in implementing the provisions of House Bill. 145 (89th Legislature, Regular Session), the commission requested comments on the following issue:

1. What, if any, changes should the commission make to align this rule with proposed §25.60, Transmission and Distribution Wildfire Mitigation Plans, currently under consideration in Project No. 56789.

SPS recommended allowing wildfire mitigation plans (WMPs) to be included as an annex to an EOP after the WMP has been approved under §25.60. Oncor similarly commented that if a wildfire mitigation plan is approved by the commission under §25.60, then the entity should be able to comply with §25.53(e)(1)(D) by filing the wildfire mitigation plan as an annex.

LCRA recommended removing the requirement to file a wildfire annex from the EOP rule and instead recommended allowing an entity to cross reference its WMP in its EOP filing. TEC also recommended the commission allow cross reference in filing WMPs and EOPs.

TPPA suggested that providing duplicative information in WMP, EOP, and other filings may cause confusion for utility personnel and instead recommended that the commission review information from one filing that refers to discreet information on both WMP and EOP. It also recommended making the language between the two rules similar so that the executive director or the designee may request after-action reports.

AEP recommended making changes to maintain consistency between §25.53 and §25.60, including reducing duplication through cross-referencing, coordinating filing timelines, standardizing key definitions, harmonizing emergency protocols, and safeguarding confidential information.

CenterPoint recommended no changes to the rule as proposed and emphasized that mitigation plans and emergency operation plans should be kept separate, as they serve two different purposes.

Houston recommended that the commission specifically address the prudency of achieving cost savings without materially reducing the necessary effectiveness of these operational plans.

Commission Response

The commission agrees with SPS and Oncor that a wildfire mitigation plan approved by the commission under §25.60 complies with §25.53(e)(1)(D). The commission disagrees with LCRA and TEC that cross references to the WMP would be a sufficient alternative, as staff would then have to access alternative dockets as it conducts its biennial review of EOPs required under Tex. Util. Code §186.007. Though the commission agrees that standardizing terms is best practice across agency rules, there are times when different rules must have different terms to clarify which parties are intended to be captured in a particular rule. In this case, the EOP rules apply to more types of entities than do the requirements under §25.60, such as generators, for example. The commission declines to include the factors laid out by Houston as these are outside the scope of the rulemaking project.

Proposed §25.53(c)(1)(A)

Proposed §25.53(c)(1)(A) requires entities to file an executive summary containing specific information and a complete copy of the EOP.

TEC recommended allowing for flexibility in the application of the PUC executive summary template because a standardized template may not account for corporate or governing differences that may exist between filing entities.

LCRA recommended deleting or modifying the language to allow for the optional use of the executive summary template.

Commission Response

The commission disagrees with TEC that a standardized template will not account for difference between filing entities. The commission establishes the template to rectify recurring inconsistencies and other common issues commission staff faced in the review of EOP filings. Accordingly, the commission declines to modify the template and referenced rule language. The commission disagrees with LCRA's recommendation to delete the executive summary template or modify the language to make it optional. The template is necessary for consistency of document review across multiple entities.

Proposed §25.53(c)(1)(A)(i)(III) & (c)(3)(A)(i)(III)

Proposed §25.53(c)(1)(A)(i)(III) requires an entity to include in the filed executive summary a comprehensive list of affiliated assets and facilities for power generation companies (PGCs) that are included in the EOP, and proposed §25.53(c)(3)(A)(i)(III) requires the same in the instance of a material change.

TCPA opposed the rule requirement to provide a comprehensive list of affiliated assets and facilities for PGCs. TCPA recommended limiting the list to generating units or facilities.

Commission Response

The commission agrees with TCPA and modifies §25.53 (c)(1)(A)(i)(III) and (c)(3)(A)(i)(III) so that only generating units must be listed.

Proposed §25.53(c)(1)(A)(VI)

Proposed §25.53(c)(1)(A)(VI) requires and entity to include a record of distribution and in accordance with §25.53(c)(4)(A), the entity must file this record in a formatted table.

LCRA recommended deleting §25.53(c)(4)(A) in its entirety as it does not allow parties the ability to customize the chart. Specifically, LCRA expressed the table template was overly prescriptive does not align with LCRA's practices in terms of tracking recipients of the EOP. In the alternative, Table 4 in the Executive Summary Template should be deleted or discretionary.

Commission Response

The commission declines in deleting §25.53(c)(1)(A)(VI), the template is necessary for the purposes of providing our contractor with consistent documents for ease of review.

Proposed §25.53(c)(1)(D)

Proposed §25.53(c)(1)(D) requires an entity to make its unredacted EOP available in its entirety to commission staff on request through an encrypted electronic method designated by commission staff.

EPE, SPS and TEAM recommended that §25.53(c)(1)(D) remain unchanged, which requires that EOPs be made available to staff at a physical location. Should the commission approve the amendment to §25.53(c)(1)(D), EPE requested that the rule detail the chosen encrypted electronic method.

Entergy recommended removing the requirement to upload the entire unredacted EOP through an encrypted electronic method.

Oncor recommended clarifying that existing encryption practices, such as Oncor's provision of materials to ERCOT through secure electronic means using password-protection, are sufficient for compliance.

AEP recommended adding a confidentiality requirement for commission staff.

Commission Response

The commission disagrees with commenters who recommended deletion of the requirement to make an EOP available to commission staff through an encrypted electronic process. The commission must review roughly 700 EOPs to ensure compliance with statutes and regulations and to provide a report to the Legislature related to the preparedness of the industry. Additionally, each emergency operations plan amounts to thousands of pages per document. Currently, the outside of ERCOT region entities present the EOP documents physically, but commission staff and its contractor have only one day to review the thousands of pages. Coordinating between multiple filing entities, commission staff, and the commission's contractors accrues unnecessary costs and wastes time when the same information can be delivered by secure file sharing.

The commission declines to remove the encryption language from §25.53(c)(1)(D), but will clarify that an entity may coordinate with staff to set up a secure file sharing method for document transfer. Further, the commission agrees with Oncor that the practice of sending materials to ERCOT through secure electronic means using password-protection is sufficient for compliance. However, the commission declines to modify the proposed rule language as it is unnecessary.

The commission declines to include a confidentially requirement exclusively for commission staff because it is unnecessary. Commission staff is required to follow the same confidentially rules as any other party under §22.71 of this Title.

Proposed §25.53(c)(3)

Proposed §25.53(c)(3) requires an entity to continuously maintain its EOP between the required three-year filing period.

AEP recommended eliminating the proposed three-year refiling requirement; instead, require full EOP refiling only when material changes occur or when the commission determines the existing plan is inadequate under Tex. Util. Code §186.007(b).

TEAM recommended that for a retail electric provider (REP) the requirement to file a complete EOP every three years should be extended to no more than once every five years. LCRA similarly requested changing the rule to require a renewing the EOP every five years.

TPPA opposed the three-year refiling requirement because it is redundant and administratively burdensome. TEC requested removing the requirements to file annual updates and three-year full re-filings.

Commission Response

The commission declines to extend the refiling deadline to every five years to remain consistent with the reporting cadence of the WMP rule. Actively maintaining, reviewing, and revising an EOP is a necessary industry best practice. It mitigates against the usage of and reliance on old documents and plans for several years. Therefore, the commission declines to remove the language requiring the continuous maintenance of EOP documents.

Proposed §25.53(c)(3)(E)

Proposed §25.53(c)(3)(E) requires an entity make a revised unredacted EOP available in its entirety to commission staff on request through an encrypted electronic method designated by commission staff.

SPS recommended removing the requirement to upload an entire unredacted EOP through an encrypted electronic method and recommended making it available at a location instead.

AEP requested adding a confidentiality requirement for commission staff.

Commission Response

The commission declines to remove the encryption language from 25.53(c)(3)(E), but will clarify that an entity may coordinate with staff to set up a secure file sharing method for document transfer. Further, the commission agrees with Oncor that the practice of sending materials to ERCOT through secure electronic means using password-protection is sufficient for compliance. However, the commission declines to modify the proposed rule language as it is unnecessary.

Proposed §25.53(c)(4)(C)

Proposed §25.53(c)(4)(C) requires an entity to file an affidavit from the entity's highest-ranking representative, official, or officer with binding authority over the entity attesting to various provisions relating to the entity's training, review processes, and management of the EOP.

TPPA recommended that the commission specify that the affidavit be signed by an officer with operational responsibility over the entity.

TEAM recommended amending 16 TAC §25.53(c)(4)(C) to state: "relevant operating personnel have received a copy of the EOP, are familiar with the EOP, and have received training on the applicable contents and execution of the EOP."

Commission Response

The commission declines to implement TPPA's and TEAM's requests as the recommended changes fall outside the scope of the modifications noticed in the proposal for publication.

Proposed §25.53(d)(6)

Proposed §25.53(d)(6) requires an entity to present each relevant annex in its full and comprehensive version.

TCPA opposed language in §25.53(d)(6) requiring presenting each annex in its full and comprehensive version because it could add thousands of pages to an entity's EOP, some information of which may be sensitive security or business information. TCPA opined that commission staff can already review any of the annexes on request, making the proposed requirement redundant.

LCRA recommended the commission allow for cross-references to previously filed plans in lieu of comprehensive re-filings of the same material.

AEP requested replacing the "full and comprehensive annex" requirement with language that ensures sufficient operational detail while allowing sensitive information to be submitted confidentially to the Commission.

SPS recommended that authorization to redact confidential information in this section be provided to preserve the security of the system.

Commission Response

The commission disagrees with TCPA's recommendation to remove the language requiring annexes to be included in their entirety and with LCRA's suggestion that cross references to the WMP would be a sufficient alternative, as staff would then have to access myriad alternative dockets, which would be administratively inefficient in its review of roughly 700 EOPs. The commission disagrees with AEP that an annex with "sufficient operational detail" would suffice in providing the commission with the comprehensive understanding about industry preparedness across the grid. Because filing entities are allowed to file information they deem confidential as a confidential filing, the commission declines to modify the proposed rule as suggested by SPS.

Proposed §25.53(e)(1)(D)

Proposed §25.53(e)(1)(D) requires an entity to file its wildfire annex as part of its EOP.

Houston recommended clarifying that an entity may reference its WMP in its EOP in lieu of including the full content of the WMP, provided the WMP is readily available, and the document location is referenced in a manner that allows for direct access by authorized agents to the document.

Commission Response

The commission disagrees with Houston that a cross reference to the WMP filed under §25.60 of this chapter would be a sufficient alternative to the requirement proposed in this rule, as this would be administratively inefficient for staff for the reasons stated above in its response to the question for comment issued in the proposal for publication.

Proposed §25.53(e)(3)(H)

Proposed §25.53(e)(3)(H) requires a PGC or an electric cooperative, an electric utility, or a municipally owned utility that operates a generation resource in Texas to include a flood annex for its generation resources.

TCPA recommended that such an annex only be required for generation resources that are in identified flood plains or high-risk flood areas.

Commission Response

The commission declines to modify §25.53(e)(3)(H) as proposed by TCPA because it is unnecessary. Subsection (d) of this section enables an entity to provide an explanation as to why a provision of the rule should not apply. Therefore, if an entity believes a flood annex should not apply to one of its generation resources, the entity must provide an explanation for the commission to review.

Statutory Authority

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 The rule is also adopted under Tex. Util. Code §186.007, which requires the commission to analyze the EOPs developed by electric utilities, power generation companies, municipally owned utilities, and electric cooperatives that operate generation facilities in this state, and retail electric providers; prepare a weather emergency preparedness report; and require entities to submit updated EOPs if the EOP on file does not contain adequate information to determine whether the entity can provide adequate electric services.

Cross Reference to Statute: Public Utility Regulatory Act §14.001 and §14.002; Tex. Util. Code §186.007.

§25.53. Electric Service Emergency Operations Plans.

(a) Application. This section applies to an electric utility, transmission and distribution utility, power generation company (PGC), municipally owned utility, electric cooperative, and retail electric provider (REP), and to the Electric Reliability Council of Texas (ERCOT).

(b) Definitions.

(1) Annex--a section of an emergency operations plan that addresses how an entity plans to respond in an emergency involving a specified type of hazard or threat.

(2) Drill--an operations-based exercise that is a coordinated, supervised activity employed to test an entity's EOP or a portion of an entity's EOP. A drill may be used to develop or test new policies or procedures or to practice and maintain current skills.

(3) Emergency--a situation in which the known, potential consequences of a hazard or threat are sufficiently imminent and severe that an entity should take prompt action to prepare for and reduce the impact of harm that may result from the hazard or threat. The term includes an emergency declared by local, state, or federal government, or ERCOT or another reliability coordinator designated by the North American Electric Reliability Corporation and that is applicable to the entity.

(4) Entity--an electric utility, transmission and distribution utility, PGC, municipally owned utility, electric cooperative, REP, or ERCOT.

(5) Hazard--a natural, technological, or human-caused condition that is potentially dangerous or harmful to life, information, operations, the environment, or property, including a condition that is potentially harmful to the continuity of electric service.

(6) Threat--the intention and capability of an individual or organization to harm life, information, operations, the environment, or property, including harm to the continuity of electric service.

(1) Except as provided by paragraph (3) of this subsection, an entity must file an emergency operations plan (EOP) and executive summary under this section by March 15 of every calendar year. Each individual entity is responsible for compliance with the requirements of this section. An entity filing a joint EOP or other joint document under this section on behalf of one or more entities over which it has control is jointly responsible for each entity's compliance with the requirements of this section.

(A) An entity must file with the commission:

(i) an executive summary that:

(I) describes the contents and policies contained in the EOP;

(II) includes a reference to specific sections and page numbers of the entity's EOP that correspond with the requirements of this rule;

(III) includes a comprehensive list of affiliated generation assets and facilities for PGCs that are included in the EOP including changes in facilities from the previous year such as sale of assets, relinquishments, and name changes;

(IV) includes the record of distribution required under paragraph (4)(A) of this subsection;

(V) contains the affidavit required under paragraph (4)(C) of this subsection; and

(VI) follows the executive summary template posted on PUCT website.

(ii) a complete copy of the EOP with all confidential portions removed.

(B) For an entity with operations within the ERCOT region, the entity must submit its unredacted EOP in its entirety to ERCOT.

(D) An entity must make its unredacted EOP available in its entirety to commission staff on request through an encrypted electronic method designated by commission staff, such as a secure file sharing method selected by an entity in consultation with commission staff.

(E) An entity may file a joint EOP on behalf of itself and one or more other entities over which it has control provided that:

(i) the executive summary required under subparagraph (A)(i) of this paragraph identifies which sections of the joint EOP apply to each entity; and

(ii) the joint EOP satisfies the requirements of this section for each entity as if each entity had filed a separate EOP.

(F) An entity filing a joint EOP under subparagraph (E) of this paragraph may also jointly file one or more of the documents required under paragraph (4) of this subsection provided that each joint document satisfies the requirements for each entity to which the document applies.

(G) An entity that is required to file similar annexes for different facility types under subsection (e) of this section, such as a pandemic annex for both generation facilities and transmission and distribution facilities, may file a single combined annex addressing the requirement for multiple facility types. The combined annex must conspicuously identify the facilities to which it applies.

(2) A person seeking registration as a PGC or certification as a REP must meet the filing requirements under paragraph (1)(A) of this subsection at the time it applies for registration or certification with the commission and must submit the EOP to ERCOT if it will operate in the ERCOT region, no later than ten days after the commission approves the person's registration or certification.

(3) An entity must continuously maintain its EOP in between the annual updates required under this paragraph. No later than March 15 of each calendar year, an entity that has previously filed an EOP must submit an update in accordance with the provisions of this paragraph, except that an entity must file its EOP in full in accordance with paragraph (1) of this subsection at least once every three calendar years.

(A) An entity that in the previous calendar year made a change to its EOP that materially affects how the entity would respond to an emergency must:

(i) file with the commission an executive summary that:

(I) describes the changes to the contents or policies contained in the EOP;

(II) includes an updated reference to specific sections and page numbers of the entity's EOP that correspond with the requirements of this rule;

(IV) includes the record of distribution required under paragraph (4)(A) of this subsection;

(V) contains the affidavit required under paragraph (4)(C) of this section; and

(VI) follows the executive summary template posted on PUCT website.

(ii) file with the commission a complete, revised copy of the EOP with all confidential portions removed; and

(iii) submit to ERCOT its revised unredacted EOP in its entirety if the entity operates within the ERCOT region.

(B) An entity that in the previous calendar year did not make a change to its EOP that materially affects how the entity would respond to an emergency must file with the commission:

(i) a pleading that documents any changes to the list of emergency contacts as provided under paragraph (4)(B) of this subsection;

(ii) an attestation from the entity's highest-ranking representative, official, or officer with binding authority over the entity stating the entity did not make a change to its EOP that materially affects how the entity would respond to an emergency; and

(iii) the affidavit described under paragraph (4)(C) of this subsection.

(C) An entity must update its EOP or other documents required under this section if commission staff determines that the entity's EOP or other documents do not contain sufficient information to determine whether the entity can provide adequate electric service through an emergency. If directed by commission staff, the entity must file its revised EOP or other documentation, or a portion thereof, with the commission and, for entities with operations in the ERCOT region, with ERCOT.

(D) ERCOT must designate any revised unredacted EOP submitted by an entity as Protected Information under the ERCOT Protocols.

(E) An entity must make a revised unredacted EOP available in its entirety to commission staff on request through an encrypted electronic method designated by commission staff, such as a secure file sharing method selected by an entity in consultation with commission staff.

(F) The requirements for joint and combined filings under paragraph (1) of this subsection apply to revised joint and revised combined filings under this paragraph.

(4) In accordance with the deadlines prescribed by paragraphs (1) and (3) of this subsection, an entity must also file with the commission the following documents:

(A) A record of distribution that contains the following information in table format:

(i) titles and names of persons in the entity's organization receiving access to and training on the EOP; and

(ii) dates of access to or training on the EOP, as appropriate.

(B) A list of primary and, if possible, backup emergency contacts for the entity, including identification of specific individuals who can immediately address urgent requests and questions from the commission during an emergency.

(C) An affidavit from the entity's highest-ranking representative, official, or officer with binding authority over the entity affirming the following:

(i) relevant operating personnel are familiar with and have received training on the applicable contents and execution of the EOP, and such personnel are instructed to follow the applicable portions of the EOP except to the extent deviations are appropriate as a result of specific circumstances during the course of an emergency;

(ii) the EOP has been reviewed and approved by the appropriate executives;

(iii) drills have been conducted to the extent required by subsection (f) of this section;

(iv) the EOP or an appropriate summary has been distributed to local jurisdictions as needed;

(v) the entity maintains a business continuity plan that addresses returning to normal operations after disruptions caused by an incident; and

(vi) the entity's emergency management personnel who are designated to interact with local, state, and federal emergency management officials during emergency events have received the latest IS-100, IS-200, IS-700, and IS-800 National Incident Management System training.

(5) Notwithstanding the other requirements of this subsection, ERCOT must maintain its own current EOP in its entirety, consistent with the requirements of this section and available for review by commission staff.

(d) Information to be included in the emergency operations plan. An entity's EOP must address both common operational functions that are relevant across emergency types and annexes that outline the entity's response to specific types of emergencies, including those listed in subsection (e) of this section. An EOP may consist of one or multiple documents. Each entity's EOP must include the information identified below, as applicable. If a provision in this section does not apply to an entity, the entity must include in its EOP an explanation of why the provision does not apply.

(1) An approval and implementation section that:

(A) introduces the EOP and outlines its applicability;

(B) lists the individuals responsible for maintaining and implementing the EOP, and those who can change the EOP;

(C) provides a revision control summary that lists the dates of each change made to the EOP since the initial EOP filing pursuant to paragraph (1) of this subsection;

(D) provides a dated statement that the current EOP supersedes previous EOPs; and

(E) states the date the EOP was most recently approved by the entity.

(2) A communication plan.

(A) An entity with transmission or distribution service operations must describe the procedures during an emergency for handling complaints and for communicating with the public; the media; customers; the commission; the Office of Public Utility Counsel (OPUC); local and state governmental entities, officials, and emergency operations centers, as appropriate in the circumstances for the entity; the reliability coordinator for its power region; and critical load customers directly served by the entity.

(B) An entity with generation operations must describe the procedures during an emergency for communicating with the media; the commission; OPUC; fuel suppliers; local and state governmental entities, officials, and emergency operations centers, as appropriate in the circumstances for the entity; and the applicable reliability coordinator.

(C) A REP must describe the procedures for communicating during an emergency with the public, media, customers, the commission, and OPUC, and the procedures for handling complaints during an emergency.

(D) ERCOT must describe the procedures for communicating, in advance of and during an emergency, with the public, the media, the commission, OPUC, governmental entities and officials, the state emergency operations center, and market participants.

(3) A plan to maintain pre-identified supplies for emergency response.

(4) A plan that addresses staffing during emergency response.

(5) A plan that addresses how an entity identifies weather-related hazards, including tornadoes, hurricanes, extreme cold weather, extreme hot weather, drought, and flooding, and the process the entity follows to activate the EOP.

(6) Each relevant annex presented in its full and comprehensive version, as detailed in subsection (e) of this section and other annexes applicable to an entity.

(e) Annexes to be included in the emergency operations plan.

(1) An electric utility, a transmission and distribution utility, a municipally owned utility, and an electric cooperative must include in its EOP for its transmission and distribution facilities the following annexes:

(A) A weather emergency annex that includes:

(i) operational plans for responding to a cold or hot weather emergency, distinct from the weather preparations required under §25.55 of this title (relating to Weather Emergency Preparedness); and

(ii) a checklist for transmission or distribution facility personnel to use during cold or hot weather emergency response that includes lessons learned from past weather emergencies to ensure necessary supplies and personnel are available through the weather emergency;

(B) A load shed annex that must include:

(i) procedures for controlled shedding of load;

(ii) priorities for restoring shed load to service; and

(iii) a procedure for maintaining an accurate registry of critical load customers, as defined under 16 TAC §25.5(22) of this title (relating to Definitions), §25.52(c)(1) and (2) of this title (relating to Reliability and Continuity of Service) and §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), and TWC §13.1396 (relating to Coordination of Emergency Operations), directly served, if maintained by the entity. The registry must be updated as necessary but, at a minimum, annually. The procedure must include the processes for providing assistance to critical load customers in the event of an unplanned outage, for communicating with critical load customers during an emergency, coordinating with government and service agencies as necessary during an emergency, and for training staff with respect to serving critical load customers;

(D) A wildfire annex;

(E) A hurricane annex that includes evacuation and re-entry procedures if facilities are located within a hurricane evacuation zone, as defined by the Texas Division of Emergency Management (TDEM);

(F) A cyber security annex;

(G) A physical security incident annex;

(H) A flood annex; and

(I) Any additional annexes as needed or appropriate to the entity's particular circumstances.

(2) A transmission and distribution utility that leases or operates facilities under PURA §39.918(b)(1) or procures, owns, and operates facilities under PURA §39.918(b)(2) must include an annex that details its plan for the use of those facilities.

(3) A PGC or an electric cooperative, an electric utility, or a municipally owned utility that operates a generation resource in Texas must include the following annexes for its generation resources:

(A) A weather emergency annex that includes:

(i) operational plans for responding to a cold or hot weather emergency, distinct from the weather preparations required under §25.55 of this title;

(ii) verification of the adequacy and operability of fuel switching equipment, if installed; and

(iii) a checklist for generation resource personnel to use during a cold or hot weather emergency response that includes lessons learned from past weather emergencies to ensure necessary supplies and personnel are available through the weather emergency;

(B) A water shortage annex that addresses supply shortages of water used in the generation of electricity;

(C) A restoration of service annex that identifies plans intended to restore to service a generation resource that failed to start or that tripped offline due to a hazard or threat;

(D) A pandemic and epidemic annex;

(E) A hurricane annex that includes evacuation and re-entry procedures if facilities are located within a hurricane evacuation zone, as defined by TDEM;

(F) A cyber security annex;

(G) A physical security incident annex;

(H) A flood annex; and

(I) Any additional annexes as needed or appropriate to the entity's particular circumstances.

(4) A REP must include in its EOP the following annexes:

(A) A pandemic and epidemic annex;

(B) A hurricane annex that includes evacuation and re-entry procedures if facilities are located within a hurricane evacuation zone, as defined by TDEM;

(D) A physical security incident annex; and

(E) Any additional annexes as needed or appropriate to the entity's particular circumstances.

(5) ERCOT must include the following annexes:

(A) A pandemic and epidemic annex;

(B) A weather emergency annex that addresses ERCOT's plans to ensure continuous market and grid management operations during weather emergencies, such as tornadoes, wildfires, extreme cold weather, extreme hot weather, and flooding;

(C) A hurricane annex that includes evacuation and re-entry procedures if facilities are located within a hurricane evacuation zone, as defined by TDEM;

(D) A cyber security annex;

(E) A physical security incident annex; and

(F) Any additional annexes as needed or appropriate to ERCOT's particular circumstances.

(f) Drills. An entity must conduct or participate in at least one drill each calendar year to test its EOP. Following an annual drill the entity must assess the effectiveness of its emergency response and revise its EOP as needed. If the entity operates in a hurricane evacuation zone as defined by TDEM, at least one of the annual drills must include a test of its hurricane annex. An entity conducting an annual drill must, at least 30 days prior to the date of at least one drill each calendar year, notify commission staff, using the method and form prescribed by commission staff on the commission's website, and the appropriate TDEM District Coordinators, by email or other written form, of the date, time, and location of the drill. An entity that has activated its EOP in response to an emergency is not required, under this subsection, to conduct or participate in a drill in the calendar year in which the EOP was activated.

(g) Reporting requirements. Upon request by commission staff during an activation of the State Operations Center by TDEM, an affected entity must provide updates on the status of operations, outages, and restoration efforts. Updates must continue until all incident-related outages of customers able to take service are restored or unless otherwise notified by commission staff. After an emergency, commission staff may require an affected entity to provide an after action or lessons learned report and file it with the commission by a date specified by commission staff.

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 December 12, 2025.

TRD-202504607

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 1, 2026

Proposal publication date: September 5, 2025

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