PART 2. PUBLIC UTILITY COMMISSION OF TEXAS
CHAPTER 22. PROCEDURAL RULES
SUBCHAPTER F. PARTIES
The Public Utility Commission of Texas (commission) adopts 16 Texas Administrative Code (TAC) §22.104, relating to Motions to Intervene. The commission adopts the rule with no changes to the proposed text as published in the March 22, 2024, issue of the Texas Register (49 TexReg 1803). The amended rule facilitates the implementation of PURA §37.057, as amended by Senate Bill (SB) 1076, enacted by the 88th Texas Legislature (R.S.), which reduced the time for the commission to approve new transmission facility certificate of convenience and necessity (CCN) to 180 days. Specifically, amended §22.104 changes the intervention deadline from 45 days to 30 days after the date an application is filed in a proceeding involving an application for a CCN for a new transmission facility that is subject to PURA §37.057. The amended rule also makes minor clerical and grammatical changes. The rule is adopted in Project No. 56253. The rule will not be republished.
The commission received comments on the proposed rule from the Lower Colorado River Authority (LCRA), Oncor Electric Delivery Company LLC (Oncor), and the Office of Public Utility Counsel (OPUC).
§22.104(b)
Proposed §22.104(b) reduced the intervention deadline from 45 to 30 days from the date an application is filed for a CCN application for a new transmission facility subject to PURA §37.057.
OPUC opposed changing the intervention deadline from 45 days to 30 days for CCN applications for a new transmission facility subject to PURA §37.057. Oncor and LCRA supported changing the intervention deadline as proposed.
OPUC opposed the proposed rule and recommended the commission retain the existing 45-day deadline for intervention in new transmission facility CCN proceedings. For consistency, OPUC also recommended making a corresponding revision to §22.52(a), relating to Notice in Licensing Proceedings, that would revert to a preexisting version of the rule that required notice of a 45-day intervention deadline in these proceedings. OPUC commented that while SB 1076 reduced the timeline for CCN applications from 360 days to 180 days, a corresponding reduction to the intervention deadline is unnecessary and unsupported by statute. Specifically, the timeline reduction would undermine the ability of affected persons and other stakeholders to intervene in new transmission CCN cases. OPUC emphasized that no evidence was presented, in this rulemaking or in other rulemakings implementing SB 1076, to indicate that any internal review processes are adversely affected by the existing 45-day intervention period or would otherwise become more efficient from the proposed reduction. OPUC commented that the intervention deadline reduction would reduce a landowner's capability to defend its property rights in proposed CCN cases. OPUC highlighted that requests for intervention in commission proceedings frequently require professional assistance if the interested party is unfamiliar with the process. OPUC remarked that there are numerous ordinary and foreseeable circumstances that may delay a potentially interested party from checking the mail or responding to a mailed CCN notice that renders the shortened timeframe even more impractical for intervention.
Oncor and LCRA, by contrast, supported the proposed rule and commented that it provides essential clarity regarding the intervention period. These commenters also emphasized that a revised intervention period is necessary to facilitate transmission line CCN applications within the 180-day period required by SB 1076.
Commission Response
The commission declines to modify the rule to retain the existing 45-day deadline for intervention in new transmission facility CCN proceedings as recommended by OPUC. The commission agrees with Oncor and LCRA that the revised intervention period is required to enable the commission to review new facility transmission line CCN applications within the condensed 180-day statutory timeline for such proceedings. This modification is also, as noted by OPUC, consistent with the commission's modifications to §22.52(a).
The commission does not agree with OPUC that a 45-day intervention deadline is necessary to protect a landowner's capability to defend its property rights in proposed CCN cases. The commission is updating the landowner brochure for CCN proceedings under project no. 55648 to ensure landowners are provided with accurate information about these proceedings. Moreover, the commission has recently established its Office of Public Engagement to assist members of the public when engaging with the commission, including individuals affected by CCN proceedings. Finally, when appropriate, the presiding officer has the ability to grant late intervention in CCN proceedings.
The amended rule is adopted under the following provisions of PURA: §14.002 and §14.052, which provide the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; and §37.057 which requires the commission to approve or deny an application for a certificate for a new transmission facilities not later than the 180th day after the date the application is filed.
Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.052; 37.057.
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 April 25, 2024.
TRD-202401755
Adriana Gonzales
Rules Coordinator
Public Utility Commission of Texas
Effective date: May 15, 2024
Proposal publication date: March 22, 2024
For further information, please call: (512) 936-7322
The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §22.246, relating to Administrative Penalties with changes to the proposed text as published in the February 2, 2024, issue of the Texas Register (49 TexReg 459) and will be republished. The rule is adopted under Project Number 55955. The changes to the proposed text are limited to the correction of typographical and minor grammatical errors in the proposed text. The amended rule partially implements Public Utility Regulatory Act (PURA) §15.023 as revised by House Bill (HB) 1500 during the Texas 88th Regular Legislative Session. Specifically, the amended rule adds whether a person complied with a voluntary mitigation plan as a factor for the commission to consider when determining the amount of an administrative penalty. The amended rule also removes redundant provisions and replaces them with a reference to §25.8 of this title (relating to Classification System for Violations of Statutes, Rules, and Orders Applicable to Electric Service Providers).
The commission received comments on the proposed rule from: the Steering Committee of Cities served by Oncor and the Texas Coalition for Affordable Power (OCSC and TCAP) and Texas Competitive Power Advocates (TCPA).
Each of the filed comments was in support of the proposed rule. Specifically, OCSC and TCAP supported applying the $1,000,000 penalty authority to VMP violations and adding VMP compliance as a factor for the commission to consider for purposes of administrative penalties, citing a benefit of allowing the commission to issue effective penalties to disincentivize market abuse behavior. TCPA argued that the proposed amendments establish an appropriate framework to implement the statutory changes made to PURA §15.023(b-1) and PURA §15.023(f). TCPA also emphasized the importance of the generation entity, the commission, and the independent market monitor mutually understanding the function of a voluntary mitigation plan and that the proposed rule provides such clarity.
The filed comments did not include any suggested modifications to the proposed rule.
The amended rule is adopted under the following provisions of the Public Utility Regulatory Act (PURA): §14.001, which provides the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by PURA that is necessary and convenient to the exercise of that power and jurisdiction; §14.002 and §14.052 which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure. The amended rule is also adopted under §15.023(b-1) which establishes that the penalty for a violation of a provision of a voluntary mitigation plan entered into under PURA §15.023(f) may be in an amount not to exceed $1,000,000 for a violation and that each day a violation continues is a separate violation for purposes of imposing a penalty; PURA §15.023(f) which authorizes the commission and a person to develop and enter into a voluntary mitigation plan relating to a violation of Section 39.157 or rules adopted by the commission under that section only if the plan is in the public interest; and PURA §15.024, which authorizes the commission to impose an administrative penalty when the commission finds that a violation has occurred.
Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.002, §15.023(b-1); §15.023(f); §15.024.
§22.246.Administrative Penalties.
(a) Scope. This section addresses enforcement actions related to administrative penalties or disgorgement of excess revenues only and does not apply to any other enforcement actions that may be undertaken by the commission or the commission staff.
(b) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise:
(1) Affected wholesale electric market participant--An entity, including a retail electric provider (REP), municipally owned utility (MOU), or electric cooperative, that sells energy to retail customers and served load during the period of the violation.
(2) Excess revenue--As defined in §25.503 of this title (relating to Oversight of Wholesale Market Participants).
(3) Executive director--The executive director of the commission or the executive director's designee.
(4) Person--Includes a natural person, partnership of two or more persons having a joint or common interest, mutual or cooperative association, and corporation.
(5) Violation--Any activity or conduct prohibited by the Public Utility Regulatory Act (PURA), the Texas Water Code (TWC), commission rule, or commission order.
(6) Continuing violation--Except for a violation of PURA chapter 17, 55, or 64, and commission rules or commission orders adopted or issued under those chapters, any instance in which the person alleged to have committed a violation attests that a violation has been remedied and was accidental or inadvertent and subsequent investigation reveals that the violation has not been remedied or was not accidental or inadvertent.
(c) Amount of administrative penalty for violations of PURA or a rule or order adopted under PURA.
(1) Each day a violation continues or occurs is a separate violation for which an administrative penalty can be levied, regardless of the status of any administrative procedures that are initiated under this subsection.
(2) The administrative penalty for each separate violation of PURA or of a rule or order adopted under PURA may not exceed the limits established by §25.8 of this title (relating to Classification System for Violations of Statutes, Rules, and Orders Applicable to Electric Service Providers).
(3) The amount of the administrative penalty must be based on:
(A) the seriousness of the violation, including the nature, circumstances, extent, and gravity of any prohibited acts, and the hazard or potential hazard created to the health, safety, or economic welfare of the public;
(B) the economic harm to property or the environment caused by the violation;
(C) the history of previous violations;
(D) the amount necessary to deter future violations;
(E) efforts to correct the violation;
(F) adherence to an applicable voluntary mitigation plan approved by the commission under §25.504 of this title (relating to Wholesale Market Power in the Electric Reliability Council of Texas Power Region); and
(G) any other matter that justice may require, including, but not limited to, the respondent's timely compliance with requests for information, completeness of responses, and the manner in which the respondent has cooperated with the commission during the investigation of the alleged violation.
(d) Amount of administrative penalty for violations of the TWC or a rule or order adopted under chapter 13 of the TWC.
(1) Each day a violation continues may be considered a separate violation for which an administrative penalty can be levied, regardless of the status of any administrative procedures that are initiated under this subsection.
(2) The administrative penalty for each separate violation may be in an amount not to exceed $5,000 per day.
(3) The amount of the penalty must be based on:
(A) the nature, circumstances, extent, duration, and gravity of the prohibited acts or omissions;
(B) the degree of culpability, including whether the violation was attributable to mechanical or electrical failures and whether the violation could have been reasonably anticipated and avoided;
(C) the demonstrated good faith, including actions taken by the person, affiliated interest, or entity to correct the cause of the violation;
(D) any economic benefit gained through the violations;
(E) the amount necessary to deter future violations; and
(F) any other matters that justice requires.
(e) Initiation of investigation. Upon receiving an allegation of a violation or of a continuing violation, the executive director will determine whether an investigation should be initiated.
(f) Report of violation or continuing violation. If, based on the investigation undertaken in accordance with subsection (e) of this section, the executive director determines that a violation or a continuing violation has occurred, the executive director may issue a report to the commission.
(1) Contents of the report. The report must state the facts on which the determination is based and a recommendation on the imposition of an administrative penalty, including a recommendation on the amount of the administrative penalty and, if applicable under §25.503 of this title, a recommendation that excess revenue be disgorged.
(2) Notice of report.
(A) Within 14 days after the report is issued, the executive director will give written notice of the report to the person who is alleged to have committed the violation or continuing violation which is the subject of the report. The notice may be given by regular or certified mail.
(B) For violations of the TWC or a rule or order adopted under chapter 13 of the TWC, within ten days after the report is issued, the executive director will, by certified mail, return receipt requested, give written notice of the report to the person who is alleged to have committed the violation or continuing violation which is the subject of the report.
(C) The notice must include:
(i) a brief summary of the alleged violation or continuing violation;
(ii) a statement of the amount of the recommended administrative penalty;
(iii) a statement recommending disgorgement of excess revenue, if applicable, under §25.503 of this title;
(iv) a statement that the person who is alleged to have committed the violation or continuing violation has a right to a hearing on the occurrence of the violation or continuing violation, the amount of the administrative penalty, or both the occurrence of the violation or continuing violation and the amount of the administrative penalty;
(v) a copy of the report issued to the commission under this subsection; and
(vi) a copy of this section, §22.246 of this title (relating to Administrative Penalties).
(D) If the commission sends written notice to a person by mail addressed to the person's mailing address as maintained in the commission's records, the person is deemed to have received notice:
(i) on the fifth day after the date that the commission sent the written notice, for notice sent by regular mail; or
(ii) on the date the written notice is received or delivery is refused, for notice sent by certified mail.
(g) Options for response to notice of violation or continuing violation.
(1) Opportunity to remedy.
(A) This paragraph does not apply to a violation of PURA chapters 17, 55, or 64; PURA §35.0021 or §38.075; or chapter 13 of the TWC; or of a commission rule or commission order adopted or issued under those chapters or sections.
(B) Within 40 days of the date of receipt of a notice of violation set out in subsection (f)(2) of this section, the person against whom the administrative penalty or disgorgement may be assessed may file with the commission proof that the alleged violation has been remedied and that the alleged violation was accidental or inadvertent. A person who claims to have remedied an alleged violation has the burden of proving to the commission both that an alleged violation was remedied before the 31st day after the date the person received the report of violation and that the alleged violation was accidental or inadvertent. Proof that an alleged violation has been remedied and that the alleged violation was accidental or inadvertent must be evidenced in writing, under oath, and supported by necessary documentation.
(C) If the executive director determines that the alleged violation has been remedied, was remedied within 30 days, and that the alleged violation was accidental or inadvertent, no administrative penalty will be assessed against the person who is alleged to have committed the violation.
(D) If the executive director determines that the alleged violation was not remedied or was not accidental or inadvertent, the executive director will make a determination as to what further proceedings are necessary.
(E) If the executive director determines that the alleged violation is a continuing violation, the executive director will institute further proceedings, including referral of the matter for hearing under subsection (i) of this section.
(2) Payment of administrative penalty, disgorged excess revenue, or both. Within 20 days after the date the person receives the notice set out in subsection (f)(2) of this section, the person may accept the determination and recommended administrative penalty and, if applicable, the recommended excess revenue to be disgorged through a written statement sent to the executive director. If this option is selected, the person must take all corrective action required by the commission. The commission by written order will approve the determination and impose the recommended administrative penalty and, if applicable, recommended disgorged excess revenue or order a hearing on the determination and the recommended penalty.
(3) Request for hearing. Not later than the 20th day after the date the person receives the notice set out in subsection (f)(2) of this section, the person may submit to the executive director a written request for a hearing on any or all of the following:
(A) the occurrence of the violation or continuing violation;
(B) the amount of the administrative penalty; and
(C) the amount of disgorged excess revenue, if applicable.
(4) Failure to respond. If the person fails to timely respond to the notice set out in subsection (f)(2) of this section, the commission by order will approve the determination and impose the recommended penalty or order a hearing on the determination and the recommended penalty.
(5) Opportunity to remedy a weather preparedness violation.
(A) This paragraph applies to a violation of PURA §35.0021, §38.075, or a commission rule or order adopted or issued under those sections.
(B) PURA §15.024(c), as written, does not apply to a violation of PURA §35.0021, §38.075, or a commission rule or order adopted or issued under those sections. This paragraph implements PURA §15.024(c), as modified by PURA §15.023(a), §35.0021(g), and §38.075(d), for violations of PURA §35.0021, §38.075, or a commission rule or order adopted or issued under those sections.
(C) The commission may impose an administrative penalty against an entity regulated under PURA §35.0021 or §38.075 that violates those sections, or a commission rule or order adopted under those sections, except:
(i) the commission will assess a penalty for a violation of PURA §35.0021, §38.075, or a commission rule adopted under those sections if the entity against which the penalty may be assessed does not remedy the violation within a reasonable amount of time; and,
(ii) the commission will not assess a penalty for a violation of PURA §35.0021, §38.075, or a commission rule or order adopted or issued under those sections if the violation was accidental or inadvertent, and the entity against which the penalty may be assessed remedies the violation within a reasonable period of time.
(D) For purposes of this paragraph, the following provisions apply unless a provision conflicts with a commission rule or order adopted under PURA §35.0021 or §38.075, in which case, the commission rule or order applies.
(i) Not all violations to which this paragraph applies can be remedied. Subparagraph (C)(i) and (ii) of this paragraph do not apply to a violation that cannot be remedied.
(ii) For purposes of subparagraph (C)(i) and (ii) of this paragraph, an entity that claims to have remedied an alleged violation and, if applicable, that the alleged violation was accidental or inadvertent has the burden of proving its claim to the commission. Proof that an alleged violation has been remedied and, if applicable, that the alleged violation was accidental or inadvertent must be evidenced in writing, under oath, and supported by necessary documentation.
(iii) An entity that remedies a violation that is discovered during an inspection by the independent organization certified under PURA §39.151 for the ERCOT power region prior to the deadline provided to that entity by the independent organization in accordance with PURA §35.0021 or §38.075 is deemed to have remedied that violation in a reasonable period of time.
(iv) If the independent organization certified under PURA §39.151 has not provided an entity with a deadline, the executive director will determine whether the deadline can be remedied and, if so, the deadline for remedying a violation within a reasonable period of time. The executive director will provide the entity with written notice of the violation and the deadline for remedying the violation within a reasonable period of time. This notice does not constitute notice under subsection (f)(2) of this section unless it fulfills the other requirements of that subsection. However, the provisions of subsection (f)(2)(D) of this section apply to notice under this clause.
(v) The executive director will determine if and when a report should be issued to the commission under subsection (f) of this section and will make a determination as to what further proceedings are necessary.
(vi) If the executive director determines that the alleged violation was not remedied within a reasonable period of time or is a continuing violation, the executive director will issue a report to the commission under subsection (f) of this section and will institute further proceedings, including referral of the matter for hearing under subsection (i) of this section.
(vii) If the commission determines that the deadline for remedying a violation provided by the independent organization certified under PURA §39.151 or determined by the executive director is unreasonable, the commission will determine what the deadline should have been. The commission will use this updated deadline to determine the applicability of subparagraph (C)(i) and (ii) of this paragraph and, if appropriate, as a factor in determining the magnitude of administrative penalty to impose against the entity for the violation.
(h) Settlement conference. A settlement conference may be requested by any party to discuss the occurrence of the violation or continuing violation, the amount of the administrative penalty, disgorged excess revenue if applicable, and the possibility of reaching a settlement prior to hearing. A settlement conference is not subject to the Texas Rules of Evidence or the Texas Rules of Civil Procedure; however, the discussions are subject to Texas Rules of Civil Evidence 408, concerning compromise and offers to compromise.
(1) If a settlement is reached:
(A) the parties must file a report with the executive director setting forth the factual basis for the settlement;
(B) the executive director will issue the report of settlement to the commission; and
(C) the commission by written order will approve the settlement.
(2) If a settlement is reached after the matter has been referred to the State Office of Administrative Hearings, the matter will be returned to the commission. If the settlement is approved, the commission will issue an order memorializing commission approval and setting forth commission orders associated with the settlement agreement.
(i) Hearing. If a person requests a hearing under subsection (g)(3) of this section, or the commission orders a hearing under subsection (g)(4) of this section, the commission will refer the case to SOAH under §22.207 of this title (relating to Referral to State Office of Administrative Hearings) and give notice of the referral to the person. For violations of the TWC or a rule or order adopted under chapter 13 of the TWC, if the person charged with the violation fails to timely respond to the notice, the commission by order will assess the recommended penalty or order a hearing to be held on the findings and recommendations in the report. If the commission orders a hearing, the case will then proceed as set forth in paragraphs (1) - (5) of this subsection.
(1) The commission will provide the SOAH administrative law judge a list of issues or areas that must be addressed.
(2) The hearing must be conducted in accordance with the provisions of this chapter and notice of the hearing must be provided in accordance with the Administrative Procedure Act.
(3) The SOAH administrative law judge will promptly issue to the commission a proposal for decision, including findings of fact and conclusions of law, about:
(A) the occurrence of the alleged violation or continuing violation;
(B) whether the alleged violation was cured and was accidental or inadvertent for a violation of any chapter other than PURA chapters 17, 55, or 64; of a commission rule or commission order adopted or issued under those chapters; or of chapter 13 of the TWC; and
(C) the amount of the proposed administrative penalty and, if applicable, disgorged excess revenue.
(4) Based on the SOAH administrative law judge's proposal for decision, the commission may:
(A) determine that a violation or continuing violation has occurred and impose an administrative penalty and, if applicable, disgorged excess revenue;
(B) if applicable, determine that a violation occurred but that, as permitted by subsection (g)(1) of this section, the person remedied the violation within 30 days and proved that the violation was accidental or inadvertent, and that no administrative penalty will be imposed; or
(C) determine that no violation or continuing violation has occurred.
(5) Notice of the commission's order issued under paragraph (4) of this subsection must be provided under the Government Code, chapter 2001 and §22.263 of this title (relating to Final Orders) and must include a statement that the person has a right to judicial review of the order.
(j) Parties to a proceeding. The parties to a proceeding under chapter 15 of PURA relating to administrative penalties or disgorgement of excess revenue will be limited to the person who is alleged to have committed the violation or continuing violation and the commission, including the independent market monitor. This does not apply to a subsequent proceeding under subsection (k) of this section.
(k) Distribution of Disgorged Excess Revenues. Disgorged excess revenues must be remitted to an independent organization, as defined in PURA §39.151. The independent organization must distribute the excess revenue to affected wholesale electric market participants in proportion to their load during the intervals when the violation occurred to be used to reduce costs or fees incurred by retail electric customers. The load of any market participants that are no longer active at the time of the distribution will be removed prior to calculating the load proportions of the affected wholesale electric market participants that are still active. However, if the commission determines other wholesale electric market participants are affected or a different distribution method is appropriate, the commission may direct commission staff to open a subsequent proceeding to address those issues.
(1) No later than 90 days after the disgorged excess revenues are remitted to the independent organization, the monies must be distributed to affected wholesale electric market participants active at the time of distribution, or the independent organization must, by that date, notify the commission of the date by which the funds will be distributed. The independent organization must include with the distributed monies a communication that explains the docket number in which the commission ordered the disgorged excess revenues, an instruction that the monies must be used to reduce costs or fees incurred by retail electric customers, and any other information the commission orders.
(2) The commission may require any affected wholesale electric market participants receiving disgorged funds to demonstrate how the funds were used to reduce the costs or fees incurred by retail electric customers.
(3) Any affected wholesale electric market participant receiving disgorged funds that is affiliated with the person from whom the excess revenue is disgorged must distribute all of the disgorged excess revenues directly to its retail customers and must provide certification under oath to the commission.
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 April 25, 2024.
TRD-202401758
Adriana Gonzales
Rules Coordinator
Public Utility Commission of Texas
Effective date: May 15, 2024
Proposal publication date: February 2, 2024
For further information, please call: (512) 936-7322
SUBCHAPTER A. GENERAL PROVISIONS
The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §25.8, relating to Classification System for Violations of Statutes, Rules, and Orders Applicable to Electric Service Providers with no changes to the proposed text as published in the February 2, 2024, issue of the Texas Register (49 TexReg 461). The rule is adopted under Project Number 55955. The amended rule partially implements Public Utility Regulatory Act (PURA) §15.023 as revised by House Bill (HB) 1500 during the Texas 88th Regular Legislative Session. Specifically, the amended rule increases the authorized penalty for violations of market power abuse regulations in conjunction with not adhering to an applicable voluntary mitigation plan to be up to $1,000,000 per violation per day. The amended rule also aligns violation definitions across classifications, consolidates violation descriptions, and adds a new description for "special violations." The rule will not be republished.
The commission received comments on the proposed rule from the Steering Committee of Cities served by Oncor and the Texas Coalition for Affordable Power (OCSC and TCAP).
Each of the filed comments was in support of the proposed rule. Specifically, OCSC and TCAP supported applying the $1,000,000 penalty authority to VMP violations, noting the intent of the Legislature to disincentivize market abuse behavior by enacting HB 1500 §7.
The filed comments did not include any suggested modifications to the proposed rule.
The amended rule is adopted under the following provisions of the Public Utility Regulatory Act (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 authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction. The amended rule is also adopted under §15.023(b-1) which establishes that the penalty for a violation of a provision of a voluntary mitigation plan entered into under PURA §15.023(f) may be in an amount not to exceed $1,000,000 for a violation and that each day a violation continues is a separate violation for purposes of imposing a penalty; PURA §15.023(f) which authorizes the commission and a person to develop and enter into a voluntary mitigation plan relating to a violation of Section 39.157 or rules adopted by the commission under that section only if the plan is in the public interest; and PURA §15.024, which authorizes the commission to impose an administrative penalty when the commission finds that a violation has occurred.
Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.002, §15.023(b-1); §15.023(f); §15.024.
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 April 25, 2024.
TRD-202401757
Adriana Gonzales
Rules Coordinator
Public Utility Commission of Texas
Effective date: May 15, 2024
Proposal publication date: February 2, 2024
For further information, please call: (512) 936-7322
The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §25.504, relating to Wholesale Market Power in the Electric Reliability Council of Texas Power Region with changes to the proposed text as published in the February 2, 2024, issue of the Texas Register (49 TexReg 462). The rule will be republished. The rule is adopted under Project Number 55948. The amended rule will partially implement Public Utility Regulatory Act (PURA) §15.023 as revised by House Bill (HB) 1500 by the 88th Texas Legislature (R.S.). Specifically, the amended rule revises the standards, processes, and timelines under which voluntary mitigation plans are approved, reviewed, and terminated by the commission. The amended rule also clarifies that adherence to a commission-approved voluntary mitigation plan must be considered in a proceeding to determine whether a generation entity engaged in market power abuse and, if so, the appropriate administrative penalty to be assessed for the violation.
The commission received comments on the proposed rule from the Steering Committee of Cities served by Oncor and the Texas Coalition for Affordable Power (OCSC and TCAP); Texas Electric Cooperatives, Inc. (TEC); Texas Competitive Power Advocates (TCPA); and Texas Public Power AssociationDefinition of "wholesale market design change" PURA §15.023(f) requires the commission to review each voluntary mitigation plan to ensure it remains in the public interest 90 days after the implementation of a wholesale market design change. The commission requested comment on whether the proposed rule should define "wholesale market design change" and if so, how the term should be defined.
All commenters recommended the commission define "wholesale market design change" in the adopted rule. OCSC and TCAP recommended the term "wholesale market design change" be defined to provide clarity to VMP applicants and market participants regarding when the commission will review a VMP and cited the 90-day commission review period required by HB 1500, §7. OCSC and TCAP further recommended a sufficiently broad definition be adopted that requires more frequent VMP review by the commission which would include "ancillary service procurement modifications, market product additions and modifications, and system-wide offer cap adjustments."
TEC recommended the commission define "wholesale market design change" only for the limited purpose of §25.504 to avoid confusion with similar terms used by market participants in certain contracts such as operations and maintenance agreements. TEC also recommended that, per PURA §15.023(f), such a definition encompass "(a)ny market design change that could enable an entity to exercise market power abuse" and result in Commission review of VMPs pursuant to statute." Specifically, TEC recommended that the definition of wholesale market design change "include any change that alters administrative pricing or that introduces new or substantially modified ancillary services."
TPPA indicated that it reviewed recent and upcoming wholesale market design changes, including the 2022 market design blueprint, and recommended wholesale market design change be defined as the "addition of a new or material modification of an existing market product or process, a material increase in the amount of ancillary service capacity procured by ERCOT, a change in any system-wide offer cap, or a change in how price adders or ancillary service prices are calculated."
TCPA recommended the commission define "wholesale market design change" and that such a change must be "something" material that has the substantial likelihood to modify wholesale market commercial operations in a substantial way" which could include the offering, award, or compensation of energy, ancillary, or reliability services. TCPA stated that otherwise any NPRR could be construed to be a "wholesale market design change" without further elaboration or context. TCPA also emphasized the importance of issuing a market notice as soon as possible, including ahead of the wholesale market design change. TCPA stated that this is necessary to clearly indicate the date by which the change is considered (to be) in effect and include the date by which the mitigation plans must be reviewed by the commission. TCPA provided draft language to amend proposed §25.504(f)(1) to incorporate a definition of "wholesale market design change consistent with its recommendation.
Commission Response
The commission declines to modify the proposed rule to include "wholesale market design change" as a defined term. Instead, the commission modifies the rule to clarify that in determining whether a change in a commission or ERCOT regulation constitutes a wholesale market design change for purposes of this section, commission staff and the independent market monitor will consider whether the change could materially increase the ability of a generation entity with an existing voluntary mitigation plan to exercise market power. The commission also modifies the rule to clarify that the commission, on its own motion, may determine that a change in a commission or ERCOT regulation constitutes a wholesale market design change.
As noted by TCPA, any revision of ERCOT's protocols could be considered a wholesale market design change, and as noted by OCSC and TCAP, the term may appropriately apply to a broad range of policy changes, such as ancillary service procurement modifications, market product additions, and system-wide offer cap adjustments. This broad range of possible wholesale market design changes could lead to frequent reviews of voluntary mitigation plans, creating uncertainty for market participants and administrative burdens for the commission, commission staff, and the independent market monitor. The commission also agrees with TEC that the rule should focus on market changes that could enable a generation entity to exercise market power abuse, and that any construal of wholesale market design change should be limited in its application to this section.
The adopted rule addresses these stakeholder concerns by including a wide range of possible change types - any change in a commission or ERCOT regulation - but only requiring a VMP review when a change has the potential to materially increase market power abuse. The rule also, appropriately, entrusts the primary responsibility of determining when a change as the potential to materially increase market power abuse with commission staff and the independent market monitor. Under PURA §39.1515(a), the independent market monitor is specifically charged with "detect(ing) and prevent(ing) market manipulation strategies" and provid(ing) independent analysis of any material changes proposed to the wholesale market." Further, allowing commission staff to initiate VMP reviews without formal commission action is consistent with the limited 90-day statutory deadline for completing these reviews.
The commission declines to require the issuance of a market notice when it initiates a review of voluntary mitigation plans in response to a wholesale market design change, as requested by TCPA. Instead, the commission modifies the rule to require commission staff to provide notice to each generation entity with an existing plan when that entity's plan is under review. This notice must be provided no later than the date commission staff files its recommendation on whether the voluntary mitigation plan remains in the public interest. In most cases, commission staff will be in contact with an affected generation entity sooner than this required date, but as noted by TCPA, a voluntary mitigation plan can be terminated by the commission or the generation entity with only a few days' notice. Requiring a significant period of advanced notice for a mere review of a plan would be inconsistent with allowing these short-notice terminations.
However, the commission also modifies the rule to clarify that commission staff may, if it has already made its determination, indicate whether a proposed change in a commission or ERCOT regulation is a wholesale market design change for purposes of this section with its filings addressing that proposed change. For example, commission staff may signal an upcoming wholesale market design change in its memo addressing a proposed revision to the ERCOT protocols or in its memo recommending approval of an adoption order in a commission rulemaking.
Proposed §25.504(c) - Exemption based on installed generation capacity Under existing §25.504(c), a single generation entity that controls less than five percent of the installed generation capacity in ERCOT, is deemed not to have ERCOT-wide market power. This provision is commonly referred to as the "small fish exemption." OCSC and TCAP recommended the commission remove the small fish exemption under proposed §25.504(c) because the exemption is "obsolete and no longer necessary due to recent market mechanisms including the nodal market and Operating Reserve Demand Curve." OCSC and TCAP remarked that the provision is based on the incorrect assumption that generators that control less than 5% of installed ERCOT generation capacity do not possess market power and therefore needlessly exposes consumers to abusive market behavior.
Commission Response
The commission declines to remove §25.504(c) from the rule, as recommended by OCSC and TCAP. Modifications to this provision were not noticed in the proposal for publication and are, therefore, beyond the scope of this rulemaking proceeding.
Proposed §25.504(e) - Voluntary mitigation plan Proposed §25.504(e) provides that any generation entity may submit to the commission a mitigation plan relating to compliance with §25.503(g)(7), relating to Oversight of Wholesale Market Participants, or PURA §39.157.
Proposed §25.504(e) also requires that a commission-approved voluntary mitigation plan be considered in a proceeding to determine whether the generation entity violated PURA 439.157 or §25.503(g)(7) and, if so, the amount of the administrative penalty to be assessed for the violation. OCSC and TCAP agreed that a VMP, by itself, should not constitute an absolute defense against market abuse allegations. OSAC and TCAP supported the proposed rule providing the commission with discretion to assess VMP compliance and the associated administrative penalty from a variety of factors including the severity of the violation, history of previous violations, and any efforts to correct the violation. Commission Response. The commission declines to modify the proposed rule in response to these comments, because no modifications were requested.
Proposed §25.504(e)(2) and (3) - Amendment or termination of voluntary mitigation plan. Proposed §25.504(e)(2) states that a generation entity or commission staff may apply to amend or terminate a voluntary mitigation plan that applies to the generation entity.
Proposed §25.504(e)(3) limits the parties to a proceeding related to the approval or amendment of a voluntary mitigation plan to the generation entity applying for the mitigation plan, commission staff, and the independent market monitor. TCPA opposed the proposed requirement for a generation entity to "apply to amend or terminate" its VMP because it is inconsistent with historical practice and is not supported by statute. TCPA explained that if a generator is required to apply and wait for action by the commission to terminate its VMP, then such a plan is no longer "voluntary." TCPA recommended that the rule be revised to ensure a generator may terminate such a plan upon notice to the Commission of its intent to terminate and the date on which the termination becomes effective" which is the same termination right the commission possesses under the proposed rule. TCPA also recommended that the requirement to provide notice of an intent to terminate should also include an administrative step ensuring public notice of the generator's decision. TCPA provided draft language consistent with its recommendation.
Commission Response
The commission agrees with TCPA that a generation entity should be able to terminate its VMP unilaterally after providing notice of the termination to the commission and modifies the rule accordingly. Specifically, the commission modifies the rule to require the generation entity to provide notice to the executive director or executive director's designee and file a notice of termination with the commission three working days prior to the effective termination date. This three-day notice period is in line with historical practice and consistent with the provisions of existing plans. Additionally, the commission further modifies the rule to allow the generation entity or executive director to withdraw a notice of termination at any point before the effective date of the termination.
The amended rule is adopted under the following provisions of the Public Utility Regulatory Act (PURA): §14.001, which provides the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by PURA that is necessary and convenient to the exercise of that power and jurisdiction; §14.002, which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction. The amended rule is also adopted under §39.154 which, after the introduction of customer choice, prohibits a power generation company from owning or controlling more than 20 percent of the installed generation capacity located in, or is capable of delivering electricity to, a power region; and §39.157 which requires the commission to monitor market power associated with the generation, transmission, distribution, and sale of electricity in the State of Texas and authorizes the commission to require reasonable mitigation of the market power.
Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.002, 39.154, and 39.157
§25.504.Wholesale Market Power in the Electric Reliability Council of Texas Power Region.
(a) Application. This section applies to all generation entities in the Electric Reliability Council of Texas (ERCOT). This section defines the term "market power," as that term is used in §25.503 of this title (relating to Oversight of Wholesale Market Participants).
(b) Definitions. The following terms, when used in this section, shall have the following meanings, unless the context or specific language of a section indicates otherwise:
(1) Generation entity--An entity that controls a generation resource. An entity affiliated with a generation entity shall be considered part of that generation entity.
(2) Market power--The ability to control prices or exclude competition in a relevant market.
(3) Market power abuse--Practices by persons possessing market power that are unreasonably discriminatory or tend to unreasonably restrict, impair, or reduce the level of competition, including practices that tie unregulated products or services to regulated products or services or unreasonably discriminate in the provision of regulated services. Market power abuses include predatory pricing, withholding of production, precluding entry, and collusion.
(c) Exemption based on installed generation capacity. A single generation entity that controls less than 5% of the installed generation capacity in ERCOT, as the term "installed generation capacity" is defined in §25.5 of this title (relating to Definitions), excluding uncontrollable renewable resources, is deemed not to have ERCOT-wide market power. Controlling 5% or more of the installed generation capacity in ERCOT does not, of itself, mean that a generating entity has market power.
(d) Withholding of production. Prices offered by a generation entity with market power may be a factor in determining whether the entity has withheld production. A generation entity with market power that prices its services substantially above its marginal cost may be found to be withholding production; offering prices that are not substantially above marginal cost does not constitute withholding of production.
(e) Voluntary mitigation plan. Any generation entity may submit to the commission a voluntary mitigation plan relating to compliance with §25.503(g)(7) of this title or with the Public Utility Regulatory Act (PURA) §39.157(a). Adherence to a commission-approved voluntary mitigation plan must be considered in a proceeding to determine whether the generation entity violated PURA §39.157 or §25.503(g)(7) of this title and, if so, the amount of the administrative penalty to be assessed for the violation.
(1) The commission will approve the voluntary mitigation plan only if it finds that the plan is in the public interest.
(2) A generation entity or commission staff may apply to amend a voluntary mitigation plan that applies to the generation entity.
(3) The parties to a proceeding related to the approval or amendment of a voluntary mitigation plan are limited to the generation entity applying for the mitigation plan, commission staff, and the independent market monitor.
(4) Termination of voluntary mitigation plan.
(A) The commission, on its own motion, may terminate, in whole or in part, a voluntary mitigation plan approved under this subsection. The executive director or the executive director's designee may also terminate a voluntary mitigation plan, in whole or in part, under the following conditions:
(i) The executive director or the executive director's designee must determine that continuation of the plan is no longer in the public interest.
(ii) The executive director or the executive director's designee must provide notice of the termination to the applicable generation entity and file a notice of termination in the same control number in which the plan was approved at least three working days prior to the effective date of the termination. The executive director or the executive director's designee may withdraw the notice of termination at any point prior to the effective date of the termination.
(iii) The commission must affirm or set aside the executive director or the executive director's designee's termination of a voluntary mitigation plan as soon as practicable after the effective date of the termination.
(B) A generation entity with a commission-approved voluntary mitigation plan may terminate the plan. The generation entity must provide the executive director or executive director's designee notice of the termination and file a notice of termination in the same control number in which the plan was approved at least three working days prior to the effective date of the termination. The generation entity may withdraw its notice of termination at any point prior to the effective date of the termination.
(f) Review of voluntary mitigation plans.
(1) The commission will review each effective voluntary mitigation plan adopted under subsection (e) of this section to determine whether the plan remains in the public interest at least once every two years and not later than 90 days after the implementation date of a wholesale market design change. Commission staff, in consultation with the independent market monitor, will determine when a wholesale market design change requiring the review of voluntary mitigation plans has occurred.
(A) In determining whether a change in a commission or ERCOT regulation constitutes a wholesale market design change for purposes of this subsection, commission staff and the independent market monitor must consider whether the change could materially increase the ability of a generation entity with an existing voluntary mitigation plan to exercise market power.
(B) If, at the time a proposed change in a commission or ERCOT regulation is being considered for approval by the commission, commission staff has determined that the proposed change would, if implemented, constitute a wholesale market design change, commission staff may include its determination in a filing addressing the proposed change (e.g. as part of a staff memo recommending commission approval of a change in the ERCOT protocols).
(C) Commission staff must provide notice, using a reasonable method of notice, to a generation entity with an existing voluntary mitigation plan when its voluntary mitigation plan is under review. This notice must be provided no later than the date commission staff files its recommendation under paragraph (2) of this subsection.
(D) Nothing in this paragraph prevents the commission, on its own motion, from determining that a change in a commission or ERCOT regulation constitutes a wholesale market design change for purposes of this subsection and directing commission staff, in consultation with the independent market monitor, to provide a recommendation on whether each existing voluntary mitigation plan remains in the public interest.
(2) At least 40 days prior to a deadline established by paragraph (1) of this subsection, commission staff must file a recommendation and draft order addressing whether each voluntary mitigation plan remains in the public interest. Commission staff's recommendation must include the date of the deadline established by paragraph (1) of this subsection and, if applicable, the details and implementation date of the applicable wholesale market design change. As part of its recommendation, for each voluntary mitigation plan adopted prior to September 1, 2023, commission staff must also address whether the plan complies with PURA §15.023(f) and this section.
(3) If the commission determines that all or a part of the plan is no longer in the public interest, the commission will terminate any part of the plan that it determines is no longer in the public interest. The generation entity may propose an amended plan for the commission's consideration.
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 April 25, 2024.
TRD-202401756
Adriana Gonzales
Rules Coordinator
Public Utility Commission of Texas
Effective date: May 15, 2024
Proposal publication date: February 2, 2024
For further information, please call: (512) 936-7322
The Public Utility Commission of Texas (commission) adopts new 16 Texas Administrative Code (TAC) §25.511, relating to the Texas Energy Fund (TEF) Completion Bonus Grant Program. The commission adopts this rule with changes to the proposed text as published in the December 15, 2023, issue of the Texas Register (48 TexReg 7272). The rule will be republished. New §25.511 implements Public Utility Regulatory Act (PURA) §34.0105 and §34.0106, enacted as part of Senate Bill (SB) 2627 during the 88th Texas Legislature (R.S.). The new rule will establish procedures for applying for a completion bonus grant award and terms for each annual grant payment. The new rule also specifies performance standards that an electric generating facility must achieve to obtain a completion bonus grant payment. The rule is adopted in Project No. 55812.
The commission received comments on the proposed rule from Calpine Corporation (Calpine), Drax Group, Electric Reliability Council of Texas Inc. (ERCOT), Golden Spread Electric Cooperative Inc. (Golden Spread), Grid Resilience in Texas (GRIT), Hunt Energy Network LLC (HEN), Lower Colorado River Authority (LCRA), LS Power Development LLC (LSP), NRG Energy Inc. (NRG), Sierra Club, Targa Resources LLC (Targa), Texas Competitive Power Advocates (TCPA), Texas Electric Cooperatives Inc. (TEC), Texas Public Power Association (TPPA), Texas Industrial Energy Consumers (TIEC), USA Compression Partners LLC (USA Compression), Vistra Corp. (Vistra), and WattBridge Texas LLC (WattBridge).
Note on Definition of Entities
The following terms are used in this order. "Applicant" refers to the entity applying to the Completion Bonus Grant Program under §25.511. "Eligible applicant" refers to an entity whose application to the completion bonus grant program has been approved and that is eligible to receive a completion bonus grant, subject to performance in each of the ten successive years following its interconnection date. "Corporate sponsor" refers to the corporate parent entity of an applicant. Use of this term accommodates a scenario in which a project-specific corporate entity is established to own a newly built facility after the grant application process. If a project entity is formed just prior to the grant application process and therefore lacks history, the credit and experience of the corporate sponsor may be considered. "TEF administrator" refers to the individuals responsible for administering the TEF programs. The term may apply to commission staff or to a contractor hired to assist with certain program functions. The specific duties and responsibilities of any contractor hired to assist with the administration of the TEF programs are defined by the terms of the commission's contract with that entity, which will be publicly available on the commission's website. Decisions of the TEF administrator are subject to the oversight of the commission.
Duties of TEF Administrator and Commission Staff
The commission will evaluate applications for TEF funding with the assistance of commission staff and the contractor hired to perform duties assigned to the commission's TEF administrator. The contractor will be responsible for assessing each application for completeness and providing commission staff with recommendations for funding according to the requirements of PURA §§34.0105 and 34.0106 and the evaluation criteria listed in §25.511. Commission staff will review the contractor's recommendations and provide recommendations for approval to the commission. The commission will approve an application in consideration of these recommendations, the statutory requirements, and the criteria listed in §25.511.
Performance Reliability Factor (PRF)
The North American Electric Reliability Corporation (NERC) Generating Availability Data System (GADS)-based data necessary to calculate the proposed equivalent availability factor (EAF) presents challenges in computing performance. Specifically, the statute requires that each eligible facility's performance be measured annually against the median and optimal performance of a reference group of similar facilities. Using NERC GADS data would result in delays in payment because this data is proprietary, and the data available from NERC GADS may not be in the appropriate format to allow the commission or ERCOT to measure facilities' performance uniformly or at the level of detail required by the statute. The adopted rule instead uses a new metric, the performance reliability factor (PRF), that is based on ERCOT data.
Public Comments
The commission invited interested parties to address three questions related to eligibility requirements of the proposed rule.
1. Should the rule require registration as a power generation company (PGC) with the commission as a condition for eligibility to receive a completion bonus grant award? Why or why not?
Sierra Club suggested requiring registration as a PGC as a condition for eligibility to receive a completion bonus grant award.
WattBridge, HEN, Drax Group, NRG, LSP, and TCPA suggested requiring registration as a PGC prior to completion bonus grant disbursement but were against requiring registration at the time of application for a completion bonus grant award.
HEN, NRG, LSP, Calpine and TCPA suggested registration should be completed by the commercial operations date (COD) per §25.109, relating to Registration by Power Generation Companies and Self-Generators, and timeframes of the ERCOT protocols, and continuously maintained for eligibility.
TEC, GRIT, Targa, and LCRA opposed the requirement to register as a PGC, because this would exclude municipally owned electric utilities (MOUs) and cooperatives. LCRA commented that it would also exclude river authorities. TPPA supported the requirement to register so long as MOUs and cooperatives are excluded from the requirement. Targa did not oppose a PGC registration requirement if the commission desires applicants for the completion bonus grant program to be subject to the regulatory requirements for PGCs. GRIT stated that SB 2627 does not include such a requirement and applying it now would potentially discriminate against certain generating facilities without regard for the facilities' potential contributions to the reliable provision of service to the ERCOT region.
TIEC suggested that registration need not be addressed in the rules because any completion bonus grant recipient would be required to register prior to generating energy as required by PURA and commission rules.
Commission Response
The commission agrees with commenters that recommended requiring an applicant to register as a PGC prior to receiving a completion bonus grant payment. PURA §39.351 requires an entity to register as a PGC prior to generating electricity in the ERCOT region. Therefore, it is appropriate to require PGC registration for awarded entities. A requirement of registration as a condition of application would be premature, given that a proposed project may not ultimately be approved for a grant.
The commission also agrees with comments concluding that requiring an applicant to register as a PGC would exclude MOUs, electric cooperatives, and river authorities. The commission does not intend such a result.
Therefore, the commission modifies the rule to include the registration requirement with an exception for those three types of entities.
2. Should the rule require registration as a Generation Resource (GR) with ERCOT as a condition for eligibility to receive a completion bonus grant award? Why or why not?
Sierra Club, Vistra, LCRA, and TPPA agreed with requiring GR registration as a condition for eligibility to receive a completion bonus grant award. WattBridge, TEC, HEN, Drax Group, NRG, LSP, TCPA, GRIT, and Targa disagreed with requiring registration as a GR with ERCOT at the time of application. Calpine, WattBridge, HEN, NRG, LSP, and TCPA suggested that registration timeline requirements should be consistent with existing ERCOT protocols. Drax Group commented that the completion bonus grant recipient would ultimately register with ERCOT as a GR but suggested that such registration should not be a condition to receive a completion bonus grant. Targa did not oppose a GR registration requirement if the commission intends to make grantees subject to ERCOT's resource requirements. However, Targa commented that the commission should recognize that a GR that serves critical natural gas infrastructure may need to remain available to serve co-located critical load during an energy emergency, consistent with existing requirements, House Bill (HB) 3648, and SB 3.
GRIT opposed the requirement for GR registration with ERCOT as a condition for eligibility and commented that it is improperly narrow given the much broader eligibility criteria in the statute. GRIT suggested that resources that are registered as Settlement Only Distribution Generators (SODGs), Private Use Networks (PUNs) with dispatchable generation, or GRs with ERCOT all should be eligible to receive a completion bonus grant under the TEF program.
TIEC suggested that a registration requirement is unnecessary because all generators are required to register before commercial operation begins. TIEC also commented that self-generators should not be eligible because they cannot apply as a GR.
Commission Response
The commission agrees with Sierra Club, Vistra, and TPPA, who recommended requiring GR registration with ERCOT as a condition for eligibility to receive a completion bonus grant award. The commission also agrees with the commenters who recommended that the registration timeline should be consistent with existing ERCOT protocols. The commission disagrees that all SODGs and PUNs with dispatchable generation should be eligible to receive a completion bonus grant.
For a generation facility to provide energy and ancillary services to the ERCOT system, be available for reliability unit commitment, and make energy offers, the resources in a facility must be registered with ERCOT as GRs. Because PURA §34.0104(a) and §34.0106(b)(1) describe grant-eligible projects as both dispatchable and primarily in service of the ERCOT system, the most appropriate ERCOT asset registration type is GR. Therefore, to receive a completion bonus grant, a facility must register its resources as GRs in the normal course of the ERCOT commissioning process. The commission amends subsection (d) of the rule to include this requirement.
3. How should the commission evaluate PURA §34.0106(b)'s prohibition against providing a completion bonus grant award to an electric generating facility that will be used primarily to serve an industrial load or PUN?
TIEC recommended that eligibility of a "facility" under PURA §34.0106 should be determined by comparing the industrial site's net dependable capacity of generation to the maximum non-coincident peak (NCP) demand of the co-located load. TIEC suggested that any new, excess capacity of 100 MW or more should be eligible participation in the TEF programs on a pro-rata basis.
Drax Group and LCRA commented that serving additional load behind the meter should not preclude eligibility for the completion bonus grant provided that the 100 MW capacity requirement for ERCOT is met.
GRIT recommended allowing proposals for excess dispatchable generation capacity within PUNs and resources behind an industrial customer's meter to participate in the completion bonus grant program, provided that the dispatchable generation is primarily available for delivery to the ERCOT grid. GRIT also supported TIEC's comments filed under Project No. 54999, in advance of the September 21, 2023, workshop, which stated that there are large industrial companies that are considering building on-site dispatchable generating facilities and may oversize those facilities if the excess capacity were eligible for the completion bonus grant.
Sierra Club commented that the commission should focus primarily on resources intended to serve the ERCOT wholesale market and not to allow taxpayer funds to be used for PUNs or industrial load facilities that, for the most part, are intended to self-provide energy to industrial loads.
TEC commented that it does not oppose the funding of facilities that have a split usage between the bulk power system and private use. TEC recommended that the commission require that any entity submitting a completion bonus grant application for a facility that will serve a PUN or industrial load provide supporting documentation as to how the facility will support the ERCOT grid.
TCPA submitted comments on behalf of TCPA, NRG, and LSP. TCPA recommended that the commission interpret the language to mean that TEF program funds should not be used to subsidize private, behind the meter generation.
TPPA did not oppose split usage facilities being eligible for the completion bonus grant but recommended that the commission develop factors for evaluation. TPPA provided a non-exhaustive list of seven factors to evaluate.
Calpine recommended the commission give preference to applicants whose new capacity will not be part of an industrial load or a PUN. Calpine remarked that the commission should typically not consider applicants who are or will be part of an industrial load or PUN because these generators do not primarily participate in the wholesale market.
Calpine commented that for a generator serving industrial load or within a PUN to qualify, it must always have 100 MW of capacity available for ERCOT wholesale markets, according to PURA §34.0104(a). However, Calpine argued that this requirement is not typically met by most PUN arrangements in ERCOT because excess capacity is mainly used for contingency reserves to prevent interruption to industrial steam and power loads during turbine outages.
Calpine commented that allowing industrial load or PUN generation in the eligible pool of applicants potentially increases administrative costs and tasks to ensure the generation project is truly separated from the host load such that the load does not benefit from public funding and to ensure that the generation is primarily available for the ERCOT market. Calpine suggested an exception for facilities that export full capacity to ERCOT but is also party to an "offtake" agreement with an industrial load or is located behind a common meter with an industrial load.
Targa requested clarification on whether a facility may be eligible if the facility has 100 MW of nameplate capacity that either serves critical gas suppliers or critical customers or provides excess energy generation to the grid.
Commission Response
The adopted rule's definition of "primarily" improves precision and alignment with the goals outlined in PURA §34.0105 and the approach to "primarily" in §25.510.
The adopted rule requires a facility that serves an industrial load or PUN to provide less than 50 percent of the facility's total nameplate capacity to the industrial load or PUN, and the remaining facility capacity serving the ERCOT market must be greater than 100 MW. This requirement aligns the rule's eligibility criteria with the commission's goal to promote the development of dispatchable generation and increased generating capacity for the ERCOT grid. PURA §34.0105(b) states that the amount of a completion bonus grant must be based on the MW of capacity provided to the ERCOT power region by the facility, and this requirement is reflected in subsection (c) of the adopted rule.
To determine whether an electric generating facility will be used primarily to serve an industrial load or PUN, the adopted rule relies upon a calculation of excess dispatchable capacity. The portion of the nameplate capacity that will be expected to serve the industrial load or PUN must be less than 50 percent of the facility's total nameplate capacity. This determination will be based on a comparison between the total nameplate capacity of the new facility and the maximum non-coincident peak (NCP) demand of the associated industrial load or PUN. For example, a 300 MW co-located facility that serves a 140 MW NCP demand has dedicated 160 MW to the ERCOT region and will be deemed to primarily serve the ERCOT region. However, a 300 MW co-located facility that serves a 160 MW NCP demand and dedicates 140 MW to the ERCOT region will be considered to primarily serve the associated industrial load or PUN. In addition, the combined total nameplate capacity of a new facility will be evaluated, not just the capacity dedicated to ERCOT, and it must provide greater than 100 MW to the ERCOT region. Accordingly, the entire facility must not primarily serve an industrial load or PUN. The commission declines to adopt additional factors as recommended by TPPA because the two factors provide a clear and replicable calculation that determines eligibility.
In response to Targa's request for clarification, whether capacity is used to serve critical gas suppliers or critical customers is not a factor in determining if a facility primarily serves an industrial load or PUN.
3.a. Should the commission prescribe a percentage of total energy output that an electric generating facility must achieve to be eligible for a completion bonus grant award? If so, what percentage should the commission prescribe?
Vistra recommended that a simple majority (greater than 50 percent) threshold would be insufficient and suggested increasing the threshold. Vistra also recommended completion bonus grant award amounts awarded to facilities serving an industrial load or PUN be discounted on a pro rata basis.
Sierra Club recommended that to the extent funding is available, at least 50.1 percent of the energy from a PUN or industrial load should be intended for the ERCOT wholesale electricity market and that the commission should only consider the part of the generation serving the larger market when awarding completion bonus grants.
TCPA recommended that if the commission is to permit PUNs to qualify for the TEF programs it should prescribe a percentage of no less than 51 percent of total facility net output in the ERCOT wholesale market to be eligible for the completion bonus grant. NRG and LSP joined the comments of TCPA.
GRIT, LCRA, and TIEC recommended that the threshold should be a minimum of 100 MW of new capacity dedicated to serving and participating in the ERCOT wholesale market. Additionally, LCRA suggested this in conjunction with (1) requiring appropriate facility configurations, and (2) metering schemes at the outset and an affidavit from the applicant committing that no less than 100 MW of capacity will be dedicated to serving the grid. LCRA commented that the 100 MW of capacity requirement minimum avoids needless complexity and the policing of meter data during a historical look-back period to determine whether the energy output of the facility met the statutory requirements. GRIT recommended that, if percentage of output is used, an eligibility threshold of greater than 90 percent of the total potential annual energy output from the electric generating facility must be supplied to the ERCOT grid via dispatchable load reduction or export.
TPPA provided seven factors for evaluating the eligibility of split usage facilities. One of the factors provided was the percentage of total nameplate capacity that would be expected to serve the load of the PUN at any time, as well as under seasonal net capacities for peak load seasons. Similarly, TEC recommended that the commission develop factors for evaluation, including but not limited to the percent of time power flows to ERCOT, ERCOT's functional control of the facility, regular use of the unit, and percentage of output used by ERCOT versus the industrial load or PUN. TEC did not recommend a specific qualifying threshold.
Commission Response
The eligibility threshold for a project will be measured by nameplate capacity, rather than energy output. Whether a given facility is dispatched can be outside a generation entity's control and could affect the amount of its energy output that is exported to the grid. Therefore, it is appropriate to rely on nameplate capacity rather than energy output measured over a period of time as a criterion for project eligibility. The commission declines to adopt additional factors as recommended by TPPA and TEC because the single factor provides a clear and replicable calculation that determines eligibility.
3.b. Should the commission employ another method to ensure that an electric generating facility primarily serves the ERCOT grid? If so, what method is appropriate and why?
TEC recommended that the commission develop factors for evaluation, including but not limited to ERCOT's functional control of the facility and regular use of the unit.
TCPA recommended that the commission use North American Electric Reliability Corporation (NERC) Generating Availability Data System (GADS) definitions for "availability," based on Equivalent Unplanned Outage Factor (EUOF), and that performance should be calculated on a rolling average of at least 12 months as opposed to hourly. TCPA commented that the commission should specify a methodology that does not allow a facility to allocate less equivalent outage hours to the portion of the facility serving ERCOT load.
TPPA recommended that prior to each grant payment over the 10-year period, the commission should review 1) an annual affidavit from the industrial load or PUN as to its activities in the ERCOT wholesale market, and 2) an independent analysis of facility market offering behaviors. TPPA also recommended that the rule include clawback provisions for facilities whose market behaviors did not align with the description in the initial application.
Commission Response
The commission clarifies the references to "primarily" in subsections (c) and (d) to better align with PURA §34.0105.
An electric generating facility that will serve an industrial load or a PUN is eligible to apply for a completion bonus grant if it fulfills the eligibility conditions described under subsection(c). Specifically, the combined total nameplate capacity of a new facility will be evaluated for purposes of determining if it primarily serves an industrial load or a PUN, as part of the eligibility determination. Whether the entire facility primarily serves an industrial load or PUN will be based on a comparison between the nameplate capacity of the new facility and the maximum NCP demand of the associated industrial load or PUN. However, for purposes of determining the completion bonus grant amount, for an electric generating facility that will not provide its entire nameplate capacity exclusively to the ERCOT region, only the capacity that exclusively serves the ERCOT region will be considered and will be awarded accordingly. The commission modifies subsections (c) and (e) of the rule accordingly.
The commission disagrees with TEC's recommendation for the rule to require calculation of factors using ERCOT performance data. Whether a facility that will serve an industrial load or PUN is primarily serving that load is based on the comparison described above. The commission declines to implement TCPA's recommendations to use NERC GADS' definition of availability and to evaluate performance over a rolling 12-month performance year. The completion bonus grant payment will be based on a facility's PRF and ARF during the assessed hours, as defined in subsection (b) of the rule. "Assessed hours" is defined as the 100 hours with the least quantity of operating reserves, as defined by the highest values of peak net load, where peak net load is calculated as gross load minus wind, solar, and storage injection.
The commission disagrees that it is necessary to further detail the procedures determining grant payments, as recommended by TPPA. The adopted rule has sufficient guidance in subsection (f) of the rule, which will govern specific procedures.
General Comments
Prohibition of Completion Bonus Grant for Backup Power Facilities
TPPA recommended an express exclusion of a completion bonus grant for a backup power package facility. Specifically, such facilities would be used to isolate a facility from the grid for at least 48 continuous hours and must be 2.5 megawatts (MW) or less of load and therefore would be inconsistent with the eligibility criteria for receipt of a completion bonus grant.
Commission Response
The commission declines to modify the rule as recommended by TPPA to explicitly prohibit backup power packages from receiving completion bonus grants. Backup power packages are ineligible for completion bonus grants. Completion bonus grants only apply to facilities providing at least 100 MW of capacity for the ERCOT grid, while Texas Backup Power Packages will only provide a maximum of 2.5 MW of generation capacity.
Proposed Ineligibility for Performance Bonus During Environmental Noncompliance
Sierra Club recommended that facilities that are in substantial noncompliance with environmental permits should not be eligible for a performance bonus for any year in which they are in substantial noncompliance.
Commission Response
The commission declines to modify the rule to include compliance with environmental permits as an annual eligibility criterion for receipt of a grant as recommended by Sierra Club. The commission does not have access to data verifying compliance with environmental permits, and such compliance is unrelated to a facility's availability during the assessed hours, which is what PURA §34.0105 and the proposed rule require.
Fund Allocation Across TEF Programs
LSP recommended that the rule explicitly require the fund administrator to "earmark and set aside funds sufficient to cover known grant payment obligations through the entire distribution period" to incentivize developers to make incremental investments for reliability purposes.
Commission Response
The commission declines to amend the rule to require that funds be earmarked to cover grant payment obligations through the entire disbursement period because it is unnecessary. The commission and the Texas Treasury Safekeeping Trust Company will monitor future award payments and other TEF obligations as they occur under PURA §34.0107(b) and (g).
Request for Guidance on Allocation of State Funds for TEF Programs
TPPA requested guidance from the commission as to how the $7.2 billion of state funds allocated for the TEF will be divided between the generation loan and completion bonus grant programs. TPPA also requested that the commission provide guidance as to how the larger $10 billion of appropriations, of which $1.8 billion is for the Backup Power Package program and another $1 billion is for grants to non-ERCOT entities, will be assigned among all programs given that only $5 billion was allocated by the 88th Legislature. Specifically, TPPA requested information on whether the limited biennium allocation would impact award amounts between the different programs.
Commission Response
The commission declines to specify how the TEF funds will be specifically allocated across programs, as requested by TPPA. PURA Chapter 34 provides independent eligibility and evaluation criteria for each TEF program. While PURA §34.0106(e)(2) allocates an aggregated maximum of $7.2 billion from the TEF to both the In-ERCOT Generation Loan Program and completion bonus grant programs, applicants, or projects for each of the two programs need not be related and cannot be known in advance. Each TEF program is independent with respect to eligibility and evaluation criteria. Therefore, it is unnecessary to modify the rule to refer to other TEF programs.
Specific allocations for the completion bonus grant and the In-ERCOT Generation Loan Program cannot be determined in advance. The distinct characteristics and financial implications of each program, including differences in potential loan sizes, disbursement periods, and repayment expectations, complicate preset funding distributions. Furthermore, the varying timelines-loans spanning 20 years with a 2025 deadline to start disbursements and grants spanning ten years available until 2029-render impracticable the concept of establishing fixed allocations before receiving any applications.
Public Reporting
Sierra Club recommended that a provision be added to the rule that would require the commission to create an Interchange project where public information on any project application for a completion bonus grant award will be made available. Sierra Club also recommended another provision be added that would require the commission to create a quarterly report on any applications received or any grants approved or denied, to keep policymakers and the public informed as to whether the program will successfully incentivize the new construction of dispatchable generation.
TPPA requested clarification on whether filings required under §25.511(d)(4) and §25.511(d)(2) will be considered confidential and not subject to disclosure under Chapter 552 of the Texas Government Code.
Commission Response
The commission declines to add a provision to the rule to require public filings in addition to those already part of proposed §25.511, as recommended by Sierra Club. Under proposed §25.511(d)(3), information as part of applications for completion bonus grants is confidential and not subject to disclosure under Chapter 552 of the Texas Government code. However, proposed subsection (d)(4) requires the submission of a separate statement that will not be treated as confidential. Commission filings giving applicants a notice of eligibility will also not be confidential.
The commission may require public reporting on the TEF at open meetings, but any such specific requirement is beyond the scope of this rulemaking.
Proposed §25.511(b)(1)-Definition of "Commercial Operations Date"
Proposed §25.511(b)(1) defines "commercial operations date" as the date on which the electric generating facility completes ERCOT's commissioning process and is approved for participation in the ERCOT market, as identified by ERCOT in the applicable monthly generator interconnection status (GIS) report.
WattBridge recommended inserting "under Part 3 approval" to the definition of "commercial operations date" to accurately capture the date the grant payment request and performance standard is dependent upon. WattBridge commented that "system checks and testing occur between Part 2 and 3 approvals and therefore referencing Part 3 approval in the definition is the appropriate commercial operations date for the performance standard."
Conversely, HEN commented that the defined term "commercial operations date" is ambiguous and should be revised to reference Part 2 of the ERCOT New Generator Commissioning Checklist. HEN commented that the phrase "approved for participation in the ERCOT market" in the proposed definition of "commercial operations date" coupled with the reference to the monthly interconnection status report is ambiguous. Specifically, the proposed definition suggests that a generator must wait until the monthly report is issued before it can demonstrate is has met the commercial operations milestone. HEN commented that referencing Part 2 of the ERCOT checklist would be a clear, preferable alternative to the current language because, upon receiving approval for Part 2, a generation resource is synchronized to the grid and can begin to schedule energy. HEN further commented that it is standard practice in loan agreements to link the definition of "commercial operation date" with receiving Part 2 Checklist approval.
Vistra recommended "commercial operations date" be revised to not solely rely on the ERCOT GIS report because that report shows both projected and actual commercial operations dates and could therefore introduce ambiguity.
TPPA and Calpine recommended the proposed definition of "commercial operations date" under §25.511(b)(1) be revised to be made consistent with the same definition in §25.510, the proposed loan program rule. TPPA added that the definition should also be consistent with the ERCOT Protocols.
Commission Response
The commission modifies the rule to remove the term "COD" from the rule and replace it with "interconnection date," which is defined as "the resource commissioning date, as defined in the ERCOT protocols, for the last generation resource in an electric generating facility for which an applicant seeks a completion bonus grant award. The new electric generating facility or new generation resources at an existing electric generating facility must meet the eligibility criteria described in subsection (c) of this section." The resource commissioning date represents the conclusion of the commissioning process and indicates a GR's fully interconnected status with the ERCOT power region. In addition, the meaning of "interconnection date" in §25.510 is the resource commissioning date, and this meaning will remain consistent across rules related to the suite of Texas Energy Fund programs. Alignment of the COD and interconnection date simplifies and streamlines the rule by removing duplicative terminology.
In addition, the added definition of "interconnection date" allows for construction of new generation resources at an existing electric generating facility. The commission interprets PURA §34.0105 to allow for the construction of new generation resources, even if they will be added to an existing electric generating facility, because the overall intent of the Texas Energy Fund is to increase the availability of reliable, dispatchable electricity in the ERCOT power region. The commission makes other conforming modifications throughout the rule to allow for new generation resources at existing electric generating facilities to be eligible for completion bonus grants.
Proposed §25.511(b)(2)-Definition of "Performance Year"
Proposed §25.511(b)(2) defines "performance year" as the one-year period that ends on an electric generating facility' s most recent anniversary of its commercial operations date.
LCRA and Calpine both commented that the "performance year" should not be tied to a facility's commercial operation date. Calpine further argued that tying the performance year to the facility's COD would create different performance periods for each grant recipient, which could be burdensome to account for and track. LCRA recommended the definition of "performance year" be revised to a uniform lookback period comprised of a rolling twelve months beginning from the date the commission begins awarding completion bonus grants until the expiration of the program. LCRA commented that, as proposed, the definition of "performance year" could result in a facility that began commercial operations prior to a weather emergency being evaluated under a completely different 100-hour compliance period than a facility that became commercially operational only a few days later. LCRA also commented that SB 2627 only requires that grant disbursements be provided on the first anniversary of the commercial operations date of a facility, but that requirement does not extend to the performance standards. LCRA further commented that the commission has authority under PURA §34.0105(i) to determine the performance year. As an alternative, LCRA proposed "performance year" be defined on a calendar year basis. Specifically, a generator could be required to operate for a full performance year to be eligible for a grant award or have its performance evaluated during only the portion of the 100 hours when the facility is commercially operational.
Commission Response
The commission agrees with LCRA and Calpine that defining the performance year in reference to the COD could result in different measurement hours and increase the computational and data requirements. Having a common performance year, rather than one based on COD, will result in simpler and faster calculations. For this reason, the commission modifies subsection (b) of the rule to delete the definition of "performance year." Rather than including a definition for "performance year," the commission modifies subsection (d) of the rule to state that an eligible facility's performance will be measured against the test period for ten successive test periods, beginning in the first test period following each facility's or new GRs' interconnection date. The commission also modifies the rule to add a definition for "test period": the one-year (12-month) period from June 1 to May 31, to align with the June 1 date used in PURA §§34.0105(c)(2), 34.0105(f)(1), and 34.0105(f)(2). This test period will contain the 100 hours with the least quantity of operating reserves. For ease of administration, the commission also adds a definition for "assessed hours" to mean the 100 hours with the least quantity of operating reserves.
Proposed §25.511(b)-Definitions
Proposed §25.511(b) defines certain terms used in the rule.
TIEC recommended the terms "EAF," "median EAF," and "test period" be defined. Vistra recommended the term "equivalent unplanned outage factor" be defined.
Commission Response
The EAF metric used in the proposed rule relies on confidential NERC GADS data that is not readily available to ERCOT or the commission, and has been replaced in the adopted rule by a new metric, the PRF. Therefore, the recommendation to define EAF-related terms is moot. The commission adds a definition for the term "test period" to subsection (b) as described above.
HEN recommended defining the terms "interconnected" as the date on which a new generator has received approval from ERCOT of Part 1 of the new generator commissioning checklist and offered a definition of "new generator commissioning checklist" to accompany the definition of "interconnected."
Commission Response
The commission declines to define "interconnected" as the date on which a new generator has received approval from ERCOT of Part 1 of the new generator commissioning checklist as recommended by HEN. The meaning of "interconnection" in §25.510 is the resource commissioning date, and this meaning will remain consistent across rules related to the suite of Texas Energy Fund programs. Further, the resource commissioning date represents the conclusion of the commissioning process and indicates a generation resource's fully interconnected status with the ERCOT power region. Accordingly, the commission adds a definition of "interconnection date" as described above.
The commission also declines to define "new generator commissioning checklist" because this term is not used in the rule.
TIEC recommended a new definition for the term "electric generating facility" to specify an entire generation unit or specific portions of a generation unit's capacity such that co-located generation facilities may be eligible for a completion bonus grant.
Commission Response
The commission declines to define "electric generating facility" in the rule because the term is defined in §25.5.
The commission modifies subsection (c) of the rule to clarify that, to be eligible, an electric generating facility must consist of one or more GRs physically capable of interconnecting to the ERCOT power region through a single point of interconnection.
Proposed §25.511(b) and §25.511(e)(1)-Definition of "Capacity" and Completion Bonus Grant Award Amount
Proposed §25.511(b) defines terms used in the rule language. Proposed §25.511(e)(1) specifies the maximum completion bonus grant amount that the commission is allowed to award eligible applicants based on the capacity and interconnection date of the facility.
HEN recommended that capacity measurement be defined in the rule based on nameplate capacity because that is the measurement used in the ERCOT interconnection process. HEN commented that defining the term is essential for determining the bonus payment under proposed §25.511(e)(1)(A) and (B) and the term can be defined in different ways, such as nameplate capacity or summer net dependable capacity.
Alternatively, Calpine recommended that "capacity" under proposed §25.511(e)(1) be measured as a generating facility's High Sustained Limit (HSL). Specifically, "as the generating facility's average [HSL] or expected average HSL, following construction completion" and not as a facility's installed capacity. Calpine commented that the HSL is a capacity value that describes the maximum sustained energy production capability of the facility, but the installed capacity rating only measures a generating unit's maximum power. Calpine recommended the HSL as a more suitable measure for the completion bonus grant award amount because it is "the maximum sustained energy production capability of the facility," and therefore is most accurately reflective of actual generation capability.
Commission Response
The commission disagrees with Calpine's recommendation to measure capacity as a generating facility's HSL because HSL is subject to change and less readily identified early in the development process. Instead, the commission modifies the rule to use the term "nameplate capacity" throughout, where it is called for; therefore, a definition for the term "capacity," as suggested by HEN and Calpine, is unnecessary.
Proposed §25.511(b), §25.511(e)(1), and §25.511(e)(1)(A) Interconnection Date and Completion Bonus Grant Award Amount
Proposed §25.511(b) defines terms used in the rule language. Proposed §25.511(e)(1) specifies the maximum completion bonus grant amount that the commission is allowed to award eligible applicants based on the capacity and interconnection date of the facility. Proposed §25.511(e)(1)(A) states an award amount may not exceed $120,000 per MW of capacity for an electric generating facility that is interconnected to the ERCOT region before June 1, 2026.
WattBridge and Calpine both recommended that "interconnection date" reference Part 1 of the ERCOT new generator commissioning checklist approval because that stage in the ERCOT commissioning process is "the first instance of a generation project connecting to the ERCOT grid and back feeding power."
HEN recommended that the term "interconnected" be defined as it is critical to determining if completion bonus grant eligibility requirements have been met. HEN recommended adding a definition for "interconnected" in section (b) of the rules and defining it as the date on or after which the generator receives ERCOT's approval of a Part 1, Request for Energization per the ERCOT new generator commissioning checklist.
Commission Response
The commission declines to modify the rule to reference Part 1 of the ERCOT new generator commissioning checklist to define interconnection, as recommended by WattBridge, Calpine, and HEN. As described above, the commission defines "interconnection date" to align with the resource commissioning date as defined in the ERCOT protocols. The resource commissioning date represents the conclusion of the commissioning process and indicates a generation resource's fully interconnected status with the ERCOT power region. This definition also aligns with the commission's use of the term "interconnection date" in §25.510.
"Primarily" Serving ERCOT
Proposed §25.511(c)(6), §25.511(d)(1)(E), and §25.511(f)(2)(E)-Eligibility and Grant Payment Request
Proposed §25.511(c)(6) requires an applicant's electric generating facility to operate in such a manner that the electric generating facility serves a greater output of electricity to the ERCOT bulk power system than it serves to an industrial load or PUN. Proposed §25.511(d)(1)(E) states that the application must include a description of the operational attributes of the electric generating facility, including the manner in which it will serve an associated PUN or industrial load, if any, along with a description of how the electric generating facility primarily serves and benefits the ERCOT bulk power system given its relationship to a PUN or industrial load and whether full generation output would be available to the ERCOT bulk power system during any Energy Emergency Alert. Proposed §25.511(f)(2)(E) describes that the request for completion bonus grant payment for an electric generating facility that also serves a PUN or industrial load must include an accounting showing that the majority of the output of the electric generating facility served the ERCOT bulk power system during the performance year.
Drax Group proposed amending the standard for an electric generating facility to "primarily serves" the ERCOT bulk power system." Drax Group argued that the facility should only be required serve at least 100 MW of electricity to the ERCOT bulk power system.
Vistra, TPPA, and GRIT recommended using a higher threshold requirement than a simple majority for the amount of capacity serving the ERCOT power region. Vistra commented that a simple majority eligibility threshold for a facility's output serving the ERCOT grid is insufficient. Specifically, Vistra stated that a 50.1 percent minimum requirement to serve the ERCOT grid does not fulfill the intent of SB 2627 in promoting reliability by investing into new dispatchable generation and recommended a higher threshold be instituted.
TPPA recommended that the "serves a greater output to ERCOT" be significantly enhanced to ensure taxpayer money is being used for the entire ERCOT region's benefit, as opposed to benefiting individual consumers.
GRIT recommended requiring an industrial load or PUN "primarily serve" the ERCOT grid by supplying 90 percent of its total potential annual energy output in order to be eligible. GRIT elaborated, stating that "dispatchable load reduction component of the 90 percent eligibility criteria should be inclusive of run hours in response to ERCOT Emergency Response Service calls, economic runs in response to energy market prices, and run hours in anticipation of ERCOT 4CP periods." GRIT explained that this methodology would ensure that baseload power or islanded backup power would constitute "primary service" to the industrial load or PUN. GRIT also recommended that dispatchable generation within a PUN should be eligible for a completion bonus grant provided "it offers over 100 MW of dispatchable generating capacity to the grid in excess of the capacity reserved to serve the co-located load" to ensure that excess reserve capacity is not used to serve the co-located load.
Conversely, TIEC recommended that §25.511(c)(6) be deleted from the rule because the 50 percent "greater output" energy production threshold for eligibility would disqualify most, if not all, industrial generation facilities from qualifying for TEF loans and completion bonus grants. TIEC asserted that basing the eligibility threshold on energy production rather than capacity contradicts the intent of the TEF, which aims to support excess capacity primarily used during periods of high demand. TIEC explained that generators serving industrial loads typically produce a much higher ratio of energy relative to their total capacity compared to sales of energy to the grid.
Commission Response
The commission modifies subsection (c) of the rule such that an electrical generation facility that is also serving an industrial load or PUN must provide more than 100 MW of nameplate capacity and greater than 50 percent of its nameplate capacity to the ERCOT region to qualify for a completion bonus grant. This modification is consistent with PURA §34.0105(c)(1), which requires eligible facilities to have a generation capacity of at least 100 MW. It is also consistent with PURA §34.0105(c)(1), which states that the commission may not provide a completion bonus grant for a facility that will be used primarily to serve an industrial load or PUN. The commission interpreted "a facility that will be used primarily to serve an industrial load or private use network" as a facility that uses 50 percent or more of its total capacity for an industrial load or PUN in its adoption order for §25.510.
The commission agrees with TIEC that the eligibility threshold for participation of facilities serving PUNs or industrial load should be based on capacity rather than actual load served. However, the commission disagrees with comments recommending a higher or lower threshold for "primarily serves" because the meaning will remain consistent across rules related to the suite of TEF programs. Similarly, the commission also declines to adopt TIEC's recommendation that any incremental capacity above the NCP demand should be considered eligible for completion bonus grants because this recommendation is inconsistent with the commission's interpretation of the phrase "primarily serves."
Targa proposed modifications to §25.511(c)(6), §25.511(d)(1)(E), and §25.511(f)(2)(E) of the proposed regulations, aimed at expanding eligibility criteria for electric generating facilities to include those providing electricity to critical natural gas facilities during energy emergencies, as per Tex. Util. Code §38.074 and associated regulations. Targa argued that such changes would serve the public interest by enhancing reliability for critical natural gas facilities which are crucial for grid reliability, especially in areas with generation and transmission constraints.
Additionally, Targa contended that PURA §34.0106(b) lacks clarity in defining when an electric generating facility "primarily" serves an industrial load or PUN. The company commented that the commission could designate such facilities as eligible for a completion bonus grant, citing PURA §34.0104(c)(3) and general principles of statutory interpretation.
Commission Response
The commission declines to adopt Targa's recommendation to expand eligibility criteria for electric generating facilities that provide electricity to critical natural gas facilities. PURA §34.0106 does not indicate any differentiation or special allowance for facilities that provide service to critical natural gas facilities. Likewise, there is no statutory provision authorizing a completion bonus grant for facilities that primarily serve industrial loads if those loads are critical natural gas facilities.
Proposed §25.511(b) and §25.511(c)-Eligibility and Definitions
Proposed §25.511(c) outlines the requirements to which an applicant's electric generating facility must adhere. Proposed §25.511(b) defines specific terms used in the rule.
TIEC recommended that pro-rata shares of generation units should be eligible for a completion bonus grant because facilities with co-located industrial load may be intentionally oversized to sell excess generation at wholesale in the ERCOT market. TIEC advised that the proposed rule should promote such co-located generation configurations to utilize economics of scale and encourage the development of dispatchable generation. As mentioned above, TIEC recommended additional rule language to the define "electric generating facility" consistent with its recommendations.
Further, TIEC recommended revisions to the determination of generating capacity eligibility for completion bonuses, aligning with the prohibition outlined in PURA §34.0106. TIEC proposed that eligibility should be determined "by comparing the net dependable capacity of generation at an industrial site to the maximum NCP demand of the co-located load" and that any new generation facilities with an excess capacity of 100 MW or more should also be eligible on a pro-rata basis. TIEC also commented that the proposed rule's method of determining whether a generator "primarily serves" an industrial load or PUN "be based on the percentage of energy output exported to the grid versus the energy that is consumed on-site" is flawed, and that revising eligibility in this manner would enable industrial customers to leverage economies of scale by oversizing generation capacity relative to on-site load and providing excess capacity to the grid, thereby enhancing reliability during periods of peak energy consumption. TIEC concluded that the critical factor for eligibility should be the amount of capacity from a generator, rather than energy exported to the grid. Additionally, TIEC asserted that the allocation of a greater share of capacity to load should not affect eligibility as long as a minimum of 100 MW is dedicated to serving the ERCOT grid because such capacity would qualify for TEF loans or grants as a standalone generator.
Commission Response
The commission declines to define electric generating facility to include pro rata shares of generation resources co-located with industrial loads, as recommended by TIEC. The program does allow co-located generation facilities to receive a completion bonus grant, but the rule requires the facility to provide more than 100 MW and more than 50 percent of the nameplate capacity to the ERCOT region. "Electric generating facility" is defined in 16 TAC §25.5, and subsection (c) of the proposed rule is modified to state that, to be eligible, the electric generating facility must consist of one or more generation resources physically capable of interconnecting to the ERCOT region through a single point of interconnection to be eligible for a completion bonus grant.
The commission declines to determine eligibility for completion bonus grants based on comparing net dependable capacity to the maximum NCP of co-located loads, as recommended by TIEC. The approach proposed by TIEC applies only to excess capacity and would not conform to the criteria described earlier for eligibility of facilities that serve an industrial load or PUN.
Proposed §25.511(d)(2)(B), §25.511(f)(2)(C-D), and §25.511(h)(1)(D)- Determination of Eligibility for Grant, Grant Payment Request, Discount of Payment
Proposed §25.511(d)(2)(B) states a notice of eligibility will authorize an applicant to request and obtain data from ERCOT showing the electric generating facility's EAF performance during the 100 hours with the least quantity of operating reserves during a performance year. A notice of eligibility will automatically expire 45 days after the tenth anniversary of the electric generating facility's commercial operations date. Proposed §25.511(f)(2) describes the information required when submitting a request for grant payment. Proposed §25.511(h)(1)(D) adds a new section discounting facilities serving an industrial load or PUN on a pro-rata basis.
Vistra provided comments suggesting that completion bonus grants issued to facilities serving industrial loads or PUNs should be discounted on a pro-rata basis, similar to facilities falling below optimal performance standards. Vistra argued that facilities serving industrial loads or PUNs are akin to generators with sub-optimal performance as only a portion of their output capacity serves the grid. Vistra recommended the addition of a new section, §25.511(d)(1)(D), to implement this suggestion.
Vistra and NRG proposed redlines for sections §25.511(f)(2)(C) and §25.511(f)(2)(D) to eliminate references to EAF. NRG recommended replacing EAF with "availability factor" in various places throughout the rule and suggested that EAF would not be a factor in determining the completion bonus grant payment amount and performance record for an electric generating facility. Vistra also proposed redline for §25.511(d)(2)(B) and §25.511(f)(2)(E), suggesting adjustments to the notice of eligibility ERCOT data request provision, striking "equipment availability factor (EAF)" and adding "EUOF" and noting that information relevant to a determination under their new (h)(1)(D), detailed below, was relevant to this data request.
Vista recommended redline for a new section, §25.511(h)(1)(D), stating the following: "(D) The commission will further reduce a [completion bonus] grant payment to a facility that serves a PUN or industrial load by multiplying the grant payment by the ratio between the MW-hours the facility served the ERCOT grid during the completion bonus grant award payment year and the total number of MW-hours the facility produced in that year."
Commission Response
The commission declines Vistra's proposed modification to discount completion bonus grant payments on a pro-rata basis for facilities serving industrial loads or PUNs. The criteria described previously for eligibility of facilities that serve industrial loads or PUNs satisfy PURA §34.0105(b) and §34.0106(b)(1). Vistra's proposed treatment for facilities that serve an industrial load or PUN does not conform to the statutory requirements and does not align with PURA §34.0105(i), which relates to discounting grant disbursements based on performance during the assessed hours rather than service to industrial loads or PUNs.
The commission addresses NRG's and Vistra's recommendation by replacing the EAF with the PRF, a performance standard metric based on ERCOT real-time telemetered and current operating plan (COP) data. The PRF is defined at in subsection (b) of the adopted rule.
Dispatchable Electric Generation vs Electric Generating Facility
Proposed §25.511(c)(1)(A-B), §25.511(c)(2), and §25.511(d)(1)(D)-Eligibility, Determination of Eligibility for Grant
Proposed §25.511(c)(1) describes the requirements for an applicant's electric generating facility to be eligible for an award. Proposed §25.511(c)(2) states an electric generating facility must be a dispatchable electric generating facility with an output that can be controlled primarily by forces under human control that is not an electric energy storage facility. Proposed §25.511(d)(1)(D) states an application must contain a record of the applicant's history of electric generation operations in this state, including information demonstrating the applicant's prior experience with operating and maintaining dispatchable electric generating facilities.
TPPA recommended maintaining consistency in the use of the term "dispatchable electric generating facility" throughout several sections of the proposed regulations, specifically in §25.511(c)(1)(A-B), §25.511(c)(2), and §25.511(d)(1)(D). TPPA commented that there appears to be no significant distinction between the terms "dispatchable electric generating facility" and "electric generating facility" used elsewhere in the rule. Additionally, TPPA highlighted that the term "electric generating facility" is already defined by §25.5(36) and could potentially encompass electric energy storage facilities.
Commission Response
The commission declines to provide further definition of "dispatchable electric generating facility" in response to TPPA's comment. The eligibility requirements in PURA and the rule specifically require facilities to be dispatchable to participate in the program, and subsection (d) specifies that an applicant's prior experience with operating and maintaining dispatchable electric generating facilities must be included in the application. Further, subsection (c) explicitly excludes electric energy storage facilities from participating in the program. Thus, revisions to the rule are not necessary.
Eligibility Criteria
Proposed §25.511(c)-Eligibility
Proposed §25.511(c) describes the requirements an applicant's electric generating facility must abide by to be eligible for a completion bonus grant award.
HEN and Golden Spread both filed comments focused on the independent treatment of applications to both the Loans for the ERCOT Power Region program and the Completion Bonus Grant program. HEN recommended that the rule explicitly state that receipt of a loan from the TEF Loans for ERCOT Power Region program is not a requirement for eligibility to receive a completion bonus grant. HEN stated that given the proposed language is silent on this issue, there may be confusion as to the eligibility requirements for completion bonus grants. HEN explained that PURA §34.0105 does not require completion bonus grants to be limited to entities that also received loan awards under PURA §34.0104. Similarly, Golden Spread commented that, to encourage participation in TEF programs, an entity’s eligibility or application in one TEF program should not adversely affect an entity's eligibility in another TEF program.
Alternatively, GRIT recommended that an applicant that meets the in-service deadlines for the TEF loans for ERCOT Power Region program under proposed §25.510 also be eligible for completion bonus grant under proposed §25.511.
Commission Response
The commission declines to modify the proposed rule to refer to an applicant's eligibility for other TEF programs as recommended by HEN, GRIT, and Golden Spread. PURA Chapter 34 provides independent eligibility and evaluation criteria for each TEF program. Although PURA §34.0106(e)(2) allocates an aggregated maximum of $7.2 billion from the TEF to both the Loans for ERCOT Power Region and Completion Bonus Grant programs, to support a combined maximum of 10,000 additional MW, the statute is silent on whether participation in one TEF program affects eligibility for another TEF program. For these reasons, the commission interprets PURA Chapter 34 not to impose any restrictions for interested entities who wish to participate in either, or both, the loan or completion bonus grant program. Therefore, it is unnecessary to modify proposed §25.511 to refer to an applicant's eligibility for other TEF programs.
TPPA recommended that compliance with the Lone Star Infrastructure Protection Act (LSIPA), codified under Texas Business and Commerce Code §117.002, should be a requirement for eligibility of a completion bonus grant because of the prohibition on interconnecting of facilities out of compliance with LSIPA.
Commission Response
The commission adds a provision to subsection (c) to explicitly require compliance with the LSIPA, as recommended by TPPA. The modification will also align with similar requirements in §25.510.
TPPA recommended the commission authorize MOUs to be eligible for funding because such entities may be interested in applying and their inclusion would provide "dispatchable electric generation capacity operated by credible, experienced utilities.' TPPA highlighted concerns regarding potential exclusion due to registration requirements as a power generation company.
Commission Response
The commission declines TPPA's recommendation to explicitly authorize MOUs to participate in the completion bonus grants program. PURA §34.0105 does not exclude MOUs and cooperatives from participation, rendering explicit inclusion unnecessary. However, the commission modifies subsection (d) of the rule to add an exception to registration with the commission as a power generation company for MOUs, electric cooperatives, and river authorities.
Proposed §25.511(c)(1)-Eligibility
Proposed §25.511(c)(1) describes the requirements for an electric generating facility to be eligible for an award.
TPPA recommended proposed §25.511(c)(1) be revised to explicitly require the 100 MW of dispatchable generation to originate from new facilities. TPPA explained that, under the proposed language, a facility could be eligible if enough generation was added at an existing site, such as adding one MW of new generation to an existing site of 99 MW. TPPA stated that such an outcome is inconsistent with plain language and intent of the statute. As an alternative, TPPA recommended that the 100 MW eligibility standard from the loan program rule under proposed §25.510 could be duplicated in proposed §25.511. TPPA also recommended that the commission clarify that the term "capacity,' as used in proposed §25.511(c)(1) is the facility's nameplate rating, as defined in §25.5(72), and does not have another meaning, such as a facility's summer or winter net dependable capability.
Conversely, Calpine recommended that new generating facilities that would increase the total capacity of existing dispatchable generation resources by at least 100 MW should be eligible for a completion bonus grant. Calpine recommended the commission specifically denote that such facilities are eligible because of the intent of SB 2627 to incentivize the construction of additional dispatchable capacity.
Commission Response
The commission agrees with TPPA and Calpine that a completion bonus grant should be available for the construction of new generation at existing electric generation facility sites so long as the new construction results in at least 100 MW of capacity. The commission modifies subsection (c) to allow both construction of a new electric generating facility and construction of new GRs at an existing electric generating facility to be eligible for a completion bonus grant. The commission makes additional conforming modifications to the rule to reflect this change in eligibility.
Golden Spread advised that existing facilities that serve a non-ERCOT interconnection should be eligible for completion bonus grants if the existing facility newly interconnects to ERCOT. Golden Spread requested modification to the language to recognize that switchable resources may not always provide power to the ERCOT grid during the term of a completion bonus grant.
Commission Response
The commission declines to modify the rule as requested by Golden Spread. Switchable facilities that are newly built and meet the requirements in proposed §25.511 are eligible to apply for completion bonus grants; no modifications to the rule are necessary to accommodate their eligibility. However, a new interconnection at an existing facility that does not require new construction would not meet eligibility requirements.
USA Compression requested clarification on the eligibility of distributed generation for a completion bonus grant. USA Compression recommended that the electronic application allow for an applicant to list certain information such as the discrete names, operational attributes, construction schedules, and commercial operations dates of each of the applicant's generating facilities.
Commission Response
The commission agrees with USA Compression that applicants should be allowed to submit information for each generating facility in the application. The commission will provide applicants a web-based portal for electronic submission of application information, and the system will be capable of receiving and tracking a wide range of input data, data types, and formats. As USA Compression's comments relate to distributed generation, the commission does not agree that distributed generation is eligible if aggregation of capacity across separate facilities is needed to meet the 100 MW capacity requirement. No modifications to the rule are necessary.
Proposed §25.511(c)(1), §25.511(c)(1)(A-B), and §25.511(c)(5)-Eligibility
See proposed §25.511(c)(1) in the section above. Proposed §25.511(c)(5) states an applicant's electric generating facility must meet the planning model requirements necessary to be included in an ERCOT capacity, demand, and reserves report for the ERCOT region after June 1, 2023.
Vistra recommended the term "new" be omitted from proposed §25.511(c)(1)(A) and (B) as it introduces uncertainty as to what projects are eligible for a completion bonus grant and is inconsistent with statute. Vistra commented that PURA §34.0105(a) already limits the grants only to "facilities that were not included in ERCOT's Capacity, Demand, and Reserves Report (CDR) before June 1, 2023" and provides no other time-based metric for eligibility.
Commission Response
The commission declines to modify the rule to remove the use of "new" as recommended by Vistra. The commission agrees with Vistra that the restriction related to the ERCOT CDR report requires new construction but disagrees that the use of "new" in the rule introduces uncertainty. The commission also modifies the rule to clarify that new construction of GRs at an existing electric generating facility is also eligible for a completion bonus grant.
Proposed §25.511(c)(2)-Eligibility Criteria for Dispatchable Electric Generating Facilities
Proposed §25.511(c)(2) states an electric generating facility must be a dispatchable electric generating facility with an output that can be controlled primarily by forces under human control that is not an electric energy storage facility.
Sierra Club commented that, while the statutory prohibition on electric energy storage facilities being eligible for completion bonus grants is clear, the mere presence of electric energy storage at a facility does not disqualify the facility from the program. Sierra Club explained that any electricity produced by the electric energy storage could be determined to be ineligible by default and excluded from a completion bonus grant application without affecting facilities that would otherwise be eligible.
Sierra Club suggested that the prohibition on electric energy storage should not extend to thermal energy storage such as geothermal or hydrogen plants because they are "energy storage facilities" not "electric energy storage facilities."
TPPA requested clarification as to the term "electric energy storage facility" as used in proposed §25.511(c)(2) because facilities are ineligible for the program and the term is undefined. TPPA also remarked that it is ambiguous whether an "electric energy storage facility" is the same as an "energy storage resource" which is used in other commission rules such as §25.55(b)(1), relating to Weather Emergency Preparedness.
Commission Response
The commission declines Sierra Club's proposed modification to the rule relating to thermal energy storage facilities not being an "electric energy storage facility." Energy storage, regardless of the underlying technology, is not dispatchable generation. Consequently, with respect to the TEF program eligibility requirements, the commission does not consider the output from storage as capacity for the facility. However, the existence of energy storage associated with an electric generating facility does not, by itself, affect the eligibility for a completion bonus grant.
With respect to energy storage more broadly, the commission notes that the TEF completion bonus grants are directed to "dispatchable electric generating facilities"--not energy storage. Accordingly, to the extent that a dispatchable electric generating facility is configured to store some of its energy output, such storage is outside the scope of this rule. Energy storage that is part of an electric generating facility would not itself disqualify the facility, but the storage would also not enhance or contribute to the capacity of the underlying electric generating facility with respect to a completion bonus grant.
Regarding TPPA's request for clarification, the commission declines to define the term "electric energy storage facility" in this section and clarifies that "electric energy storage facility" and "energy storage resource" are not used synonymously in this section.
Proposed §25.511(c)(3)-Eligibility
Proposed §25.511(c)(3) states an applicant's electric generating facility must interconnect and provide electricity to the ERCOT region.
TPPA recommended proposed §25.511(c)(3) be revised to explicitly limit completion bonus grant eligibility to facilities that only provide power to the ERCOT region, as opposed to switchable facilities that can provide electricity to another ISO or RTO besides the ERCOT power region.
TEC recommended that switchable units should be eligible to receive a completion bonus grant award under the proposed rule if the unit can meet the applicable performance standards, subject to any additional requirements imposed by agreement between the ERCOT power region and another ISO.
Golden Spread commented that the restriction on eligibility under PURA §34.0106(b)(1) does not prevent switchable facilities that can provide electricity to another ISO or RTO besides the ERCOT power region from being eligible for a completion bonus grant. Golden Spread noted that the statutory prohibition only applies to a facility that is used "primarily" to serve an industrial load or PUN.
Commission Response
The commission agrees with Golden Spread that PURA §34.0106(b)(1) does not categorically exclude switchable facilities from eligibility for the TEF completion bonus grant program. However, it is unnecessary to modify the rule; switchable facilities are eligible if they provide generation capacity to the ERCOT region and otherwise meet all other eligibility requirements. Further, switchable facilities are not synonymous with facilities that serve an industrial load or PUN and, therefore, are not subject to the statutory restrictions on those types of facilities.
Proposed §25.511(c)(3) and §25.511(c)(4)-Eligibility
Proposed §25.511(c)(3) states an applicant's electric generating facility must interconnect and provide electricity to the ERCOT region. Proposed §25.511(c)(4) requires an applicant's electric generating facility to participate in the ERCOT wholesale market.
TPPA requested clarification as to whether there is a meaningful distinction between requiring a facility to "interconnect and provide electricity to the ERCOT market" in proposed §25.511(c)(3) and requiring a facility to "participate in the ERCOT wholesale market" in proposed §25.511(c)(4). TPPA recommended merging the provisions to require a dispatchable electric generating facility to "interconnect, produce, and sell electricity in the wholesale power market in ERCOT."
Commission Response
The commission declines to modify the rule to combine the two provisions related to dispatchable facilities, as TPPA recommended. PURA §34.0106(d) states that each facility that receives a completion bonus grant must participate in the ERCOT wholesale electricity market, and PURA §34.0105(f) requires facilities to be interconnected in the ERCOT power region by certain dates to be eligible to receive a completion bonus grant. The intent of the program is to not only interconnect with the ERCOT power region, but to provide capacity to and participate in the ERCOT market. Thus, facilities need to both "interconnect and provide electricity to the ERCOT region" and "participate in the ERCOT wholesale market." However, the commission modifies the rule for other reasons to eliminate the provision "interconnect and provide electricity to the ERCOT region." This provision is now accounted for in (c)(1), which requires that any new GR "interconnect to and provide power for the ERCOT region."
USA Compression filed comments discussing the benefits of distributed generation and whether it should be eligible for a completion bonus grant. Specifically, USA Compression interpreted the proposed §25.511(c)(1) as allowing the aggregation of distributed energy resources.
Commission Response
The commission declines to amend the rule to allow entities that aggregate electric generating facilities across multiple locations to apply for TEF completion bonus grant funding, as recommended by USA Compression. To be eligible for a TEF completion bonus grant, a project must consist of new GRs, whether at a new electric generating facility or an existing facility, and install at least 100 MW in nameplate capacity that is physically capable of operating behind a single point of interconnection.
Proposed §25.511(c)(1)(A)-Eligibility
Proposed §25.511(c)(1)(A) states an applicant's electric generating facility must have a capacity of at least 100 MW attributable to the construction of new dispatchable electric generating facilities providing power for the ERCOT region.
GRIT recommended that portfolios of distribution-interconnected generators between 2.5 and 100 MW be eligible for a completion bonus grant if such generators are aggregated. GRIT commented that there is no reason to allow aggregation of transmission-interconnected facilities but not distributed generation facilities. GRIT stated that authorizing such aggregation would enhance resiliency, reliability, affordability, and congestion in urban areas.
Commission Response
The commission declines to permit distributed generation eligibility on an aggregated basis per GRIT's recommendation. PURA §34.015(c) states that construction of a new facility is eligible only if the facility has a generation capacity of at least 100 MW. An eligible facility must consist of one or more GRs physically capable of interconnecting to the ERCOT power region through a single point of interconnection, as required by (c)(5) of the adopted rule. Consequently, GRs operating within an individual facility must be physically capable of delivering energy from a single point of interconnection and must meet the 100 MW minimum capacity requirement to qualify for a completion bonus grant.
Proposed §25.511(c)(7) and §25.511(d)(1)(F)-Eligibility, Determination of Eligibility for Grant
Proposed §25.511(c)(7) states an applicant's electric generating facility must meet the interconnection deadlines. Proposed §25.511(d)(1)(F) states that an eligibility application must include a description of the electric generating facility's ability to address regional and reliability needs. Vistra recommended requiring applicants to register as a "generation entity" because this will ensure the commission's weatherization rules at §25.55 apply.
Commission Response
The commission agrees with Vistra that the registration of the facility's GR with ERCOT would necessitate adherence to the weather preparation requirements of §25.55. However, for added clarity, the commission modifies subsection (c) of the rule to explicitly state the obligation of the electric generating facility qualifying for the TEF completion bonus grant to comply with §25.55.
Proposed §25.511(d)(1)(A) and §25.511(d)(1)(H)(iv)-Determination of Eligibility for Completion Bonus Grant Award
Proposed §25.511(d)(1)(A) requires applicants to provide the applicant's corporate name and the name of the generating facility for which it seeks a completion bonus grant award. Proposed §25.511(d)(1)(H)(iv) requires applicants to provide the name of the electric generating facility on ERCOT's market participant list for electric generating facilities already interconnected to the ERCOT region.
TPPA recommended inserting the word "proposed" before "name of the electric generating facility" in (d)(1)(A) and (d)(1)(H)(iv) to provide flexibility in accounting for facility name changes during the pendency of a completion bonus grant application.
Commission Response
The commission agrees with TPPA and modifies subsection (d) to acknowledge that the name of an electric generating facility may change. However, the commission declines to modify subsection (d)(1)(H)(iv) because the section pertains to facilities already interconnected to the ERCOT region, after which the facility's name is known.
Proposed §25.511(d)(1)(G)(iii) and §25.511(d)(1)(H)(i)-Construction Costs
Proposed §25.511(d)(1)(G)(iii) states that applications must include the estimated construction costs of the electric generating facility for facilities not yet interconnected to the ERCOT power region. Proposed §25.511(d)(1)(H)(i) states that applications must include the actual new construction costs of the electric generating facility for facilities already interconnected to the ERCOT power region.
Calpine recommended removing (d)(1)(G)(iii), which requires an eligibility application to include the estimated construction costs of an electric generating facility not yet interconnected to the ERCOT region. Calpine also recommended removing (d)(1)(H)(i), which requires an eligibility application to include the actual construction costs of an electric generating facility already interconnected to the ERCOT region. Calpine noted that SB 2627 neither states nor implies that a generator's eligibility to receive a completion bonus grant is related to the total amount of costs estimated or incurred. Calpine commented that, unlike for the Loans for ERCOT Power Region program, a grant recipient is not required by statute to "independently fund any portion of the generator's construction costs to be eligible for a completion bonus grant." Calpine also noted that by the time an applicant requests funding under the grant program, the generator will have achieved commercial operations and that construction costs will therefore already have been incurred and paid.
Commission Response
The commission declines to modify the rule to eliminate costs from the eligibility application as recommended by Calpine. PURA §34.0105(d)(2) directs the commission to evaluate an application based on "the generation capacity and estimated construction costs of the facility."
Proposed §25.511(e)(1)(A)-Completion Bonus Grant Award Amount
Proposed §25.511(e)(1)(A) states an award amount may not exceed $120,000 per MW of capacity for an electric generating facility that is interconnected to the ERCOT region before June 1, 2026.
Sierra Club recommended that taxpayer money should not be used to provide completion bonus grants to facilities already in operation when the TEF constitutional amendment was approved. Sierra Club recommended adding language to §25.511(e)(1)(A) that would set the day after voter approval [November 7, 2023] as the earliest date of eligibility.
Commission Response
The commission declines Sierra Club's request to modify the rule to include a date of eligibility. PURA §34.0105(c)(2) expressly prohibits facilities that met the planning model requirements necessary to be included in the CDR before June 1, 2023. Projects that did not meet these CDR requirements before June 1, 2023, are eligible to apply for a completion bonus grant.
Eligibility Application
Proposed §25.511(d)(1)(G) and §25.511(d)(1)(H)-Application Requirements
Proposed §25.511(d)(1)(G) states the application requirements that are specific to electric generating facilities that are not yet interconnected to the ERCOT region. Proposed §25.511(d)(1)(H) states the application requirements that are specific to electric generating facilities that are already interconnected to the ERCOT region.
HEN and TPPA recommended removing (d)(1)(G) from the rule because it applies to generators that have not yet interconnected to the ERCOT region. HEN explained that, per the statutory language of PURA §34.0105(f), a key precondition to eligibility for completion bonus grants is meeting target interconnection dates. Therefore, only generators that have achieved interconnection should be eligible for a completion bonus grant. TPPA stated that because the provision applies to facilities that have yet to interconnect with the ERCOT region, there is no guarantee that such generators would become operational. Therefore, awarding funds to such projects would divert commission resources from completed projects and reduce funds available for projects that would be beneficial to consumers.
Commission Response
The commission disagrees with HEN and TPPA's recommendation to remove (d)(1)(G). PURA §34.0105(f) limits the amount of an award based on when an electric generation facility interconnects but does not limit the time at which an applicant may apply. PURA §34.0105(h) directs payments of a completion bonus grant award to begin on the first anniversary of COD, but the notice of eligibility for a completion bonus grant will precede initial payment, and this notice is not prohibited from occurring before the COD.
Determining that an entity with a project that is not yet interconnected to the ERCOT region is eligible to receive completion bonus grants does not necessarily divert or reduce resources because the mere notice of eligibility for a completion bonus grant does not equate with making payments. An electric generating facility is potentially eligible for a completion bonus grant if it interconnects in the ERCOT power region before June 1, 2029, and there is no statutory requirement for such an electric generating facility to wait until it is interconnected in the ERCOT power region to apply for a completion bonus grant. An applicant can file an application at any time beginning January 1, 2025, up to 180 days after the facility's interconnection date. Facilities must interconnect prior to June 1, 2029, to be eligible for the program, unless the commission determines that extenuating circumstances merit an extension of this deadline. Applications will be accepted according to the requirements in subsection (d) of the adopted rule or until program funding, the statutory budget, or MW limit outlined in PURA §§34.0104(d) and 34.0106(e)(2) has been reached.
Proposed §25.511(d)(1)-Eligibility Application
Proposed §25.511(d)(1) states that an applicant must submit an application for a completion bonus grant no later than 180 days after the commercial operations date of the electric generating facility for which the completion bonus grant is requested.
NRG recommended revising §25.511(d)(1) to allow applicants not yet interconnected to the ERCOT power region to submit a contingent notice of eligibility for a completion bonus grant beginning on June 1, 2024. NRG stated that this allows applicants also seeking a TEF loan to factor potential grant payments into their financial projections. NRG recommended the notice of eligibility and amount of the grant be conditioned upon the applicant filing supplemental documentation upon interconnection to demonstrate the date of interconnection and capacity interconnected.
Commission Response
The commission declines to modify the rule to allow for submission of a contingent notice of eligibility, as recommended by NRG. An electric generating facility is not required to be interconnected in the ERCOT power region before submitting an application for a completion bonus grant. Any completion bonus grant award or payment would be conditioned on satisfying all requirements, including historical performance. No completion bonus grant payments would be made until after the electric generating facility has interconnected to the ERCOT region and completed its first full test period.
Proposed §25.511(d)(1)(G)(i)-Proposed Project Schedule, Registration Documents, and Anticipated COD
Proposed §25.511(d)(1)(G)(i) states that applications for generating facilities that are not yet interconnected to the ERCOT region must include a proposed project schedule with anticipated dates for completion of construction, submission of registration documents with ERCOT and the commission, and anticipated commercial operations date.
Sierra Club recommended that facilities not yet connected to the ERCOT region be required to include regulatory approvals of any environmental permits in the project schedule required under §25.511(d)(1)(G)(i).
Commission Response
The commission declines Sierra Club's recommendation to modify the rule to include a schedule of regulatory approvals and permits. All regulatory approvals and permits would be in place before an electric generating facility interconnects to the ERCOT region, and no completion bonus grant payments would be made until after the electric generating facility has interconnected and completed its first full test period.
Proposed §25.511(d)(1)-Eligibility Application
Proposed §25.511(d)(1) outlines the requirements for eligibility applications.
Vistra recommended that the rule authorize a corporate parent to submit a completion bonus grant award application on behalf of its subsidiary for efficiency. Vistra explained that at the time of application, the company that will undertake the project may not exist or have sufficient resources, or that a project may not even be economically viable without a completion bonus grant award.
Commission Response
The commission agrees with Vistra and modifies subsection (d) of the rule to authorize a corporate parent to submit an application on behalf of its subsidiary. A corporate parent entity may apply on behalf of a project entity so long as the project entity is the eventual party to the completion bonus grant agreement and provides appropriate evidence confirming it is owned by the parent.
Proposed §25.511(d)(1)(B)-Applicant's Quality of Services and Management
Proposed §25.511(d)(1)(B) states that applications must include information describing the applicant's quality of services and management.
Calpine recommended that the rule provide more specific, objective standards to demonstrate an applicant possesses sufficient quality of service and management for efficiency and to ensure only qualified applicants are considered for a completion bonus grant. Specifically, Calpine advised the commission to consider possible factors based on prior experience operating electric generating facilities, such as an applicant's employees having a minimum number of years of experience in the dispatchable electric generation industry and in firm fuel contract procurement, and applicants disclosing their disciplinary record with ERCOT and the commission. Calpine further recommended that an applicant that does not possess at least ten years of experience should be ineligible to receive a completion bonus grant.
Commission Response
The commission declines to modify the rule regarding specific criteria for quality of services and management, as recommended by Calpine. While the commission agrees that the examples cited by Calpine may be reasonable indicators, the commission disagrees that the rule should list explicit and specific thresholds, such as minimum years of experience. PURA Chapter 34 provides adequate guidance to the commission on the required program eligibility evaluation criteria.
Proposed §25.511(d)(1)(D)-Applicant's History of Electric Generation Operations
Proposed §25.511(d)(1)(D) states an eligibility application must contain a record of the applicant's history of electric generation operations in this state.
TPPA recommended proposed §25.511(d)(1)(D) be revised to also include an applicant's history of electricity generation operations in the United States, rather than be limited to just history of electrical generation operations in the State of Texas. TPPA commented that this change would align the provision with the language of PURA §34.0105(d)(1)(C).
Commission Response
The commission agrees with TPPA's recommendation and modifies subsection (d) to also require an applicant's history of electricity generation operations in this country.
Proposed §25.511(d)(1)(E)-Determination of Eligibility for Grant
Proposed §25.511(d)(1)(E) states that the application must include a description of the operational attributes of the electric generating facility.
USA Compression recommended that proposed §25.511(d)(1)(E) be revised to include "information from applicants regarding the flexibility, ramp rate, and maximum duration of the applicants' electric generating facilities" so that the commission can prioritize "flexible, fast-ramping, multi-hour-duration dispatchable generation projects for completion bonus grants."
Commission Response
The commission declines to modify the rule to require specific additional application information, as recommended by USA Compression. The application form will allow entities to list "operational attributes" of the project, and applicants can choose to submit details, such as those suggested by USA Compression, for consideration. The commission will evaluate applications on a holistic basis.
Vistra requested clarification on the purpose in the application process for requesting whether a facility will be available during any EEA under proposed §25.511(d)(1)(E). Vistra also requested the rule specify whether a facility that is unable to be available during an EEA event will either be disqualified from receiving a completion bonus grant or will receive a prorated grant.
Commission Response
The commission declines to modify the rule to specifically disqualify or prorate a completion bonus grant if a facility declares it will be unavailable during an EEA in its application materials, as suggested by Vistra. The required statement regarding whether a facility will be available during an EEA in subsection (d) relates only to facilities that will serve an industrial load or PUN. The commission modifies subsection (d) to clarify that this provision relates only to those facilities, rather than to all applicants.
Commission Evaluation of Application
Proposed §25.511(c)(5), §25.511(d)(1)(I), and §25.511(d)(2)(A)-Planning Model Requirements and Project Eligibility
Proposed §25.511(c)(5) states that applicants must meet the planning model requirements necessary to be included in an ERCOT capacity, demand, and reserves report for the ERCOT region after June 1, 2023. Proposed §25.511(d)(1)(I) states that an application must include a statement describing when the electric generating facility met the planning model requirements. Proposed §25.511(d)(2)(A) states that the commission will file a notice of eligibility stating the completion bonus grant award amount based on the capacity of the facility and its interconnection date for applicants deemed eligible to receive a completion bonus grant.
NRG recommended revising §25.511(d)(2)(A) to specify the earliest start date for applications to be filed and to require applicants that have not yet interconnected to later submit updated documentation to determine the actual completion bonus grant amount for which the applicant is eligible. NRG commented that the rule only sets a hard deadline for filing of applications (no later than 180 days after COD) but does not state the earliest start date.
NRG proposed modifying §25.511(c)(5) and (d)(1)(I) to recognize that projects might not have yet met eligibility for inclusion in the CDR or have been interconnected when an initial application is submitted.
Commission Response
The commission agrees with the issues raised by NRG related to application start dates before interconnection and modifies subsection (d) of the rule to clarify application and award for projects that have not yet interconnected at the time of application. Applicants may file an application at any time beginning January 1, 2025, up to 180 days after the facility's interconnection date.
The commission agrees with NRG's recommended modification to subsection (c) to align more clearly with PURA §34.0105(c)(2) regarding the ERCOT CDR report and modifies the rule accordingly.
Proposed §25.511(d)(1)(K) and §25.511(e)(1)(A) -Extenuating Circumstances and Completion Bonus Grant Award Amount
Proposed §25.511(d)(1)(K) states that an applicant can provide a statement asserting that extenuating circumstances support the extension of the interconnection dates described in (e)(1). Proposed §25.511(e)(1)(A) states an award amount may not exceed $120,000 per MW of capacity for an electric generating facility that is interconnected to the ERCOT region before June 1, 2026.
WattBridge commented that "extenuating circumstances" should be revised to include delays caused by the commission failing to timely act upon a loan application. WattBridge explained that practical considerations associated with scheduling and implementation of the completion bonus grant program necessitates such language. WattBridge further recommended that §25.511(e)(1)(A) should be revised to account for delays caused by the commission in processing the application. Specifically, WattBridge recommended that if a loan is not awarded within 90 days of submission but is ultimately granted, the June 1, 2026 deadline for the $120/kw completion bonus grant under §25.511(d)(1)(K) should be tolled and extended for each day the commission delays reviewing the application.
Commission Response
The commission declines to modify the rule to account for delays in construction financing, as recommended by WattBridge, because award of a loan is neither a condition precedent nor an eligibility requirement for obtaining a completion bonus grant. The commission will apply a consistent approach to deadlines across all applicants.
Proposed §25.511(d)(2), §25.511(e)(1)(A), and §25.511(f)(4)-Process for Determining Eligibility for Completion Bonus Grant Awards
Proposed §25.511(d)(2) outlines the process by which the commission will determine whether an applicant is eligible for a completion bonus grant and the resulting steps that need to be taken applicants who are determined to be eligible. Proposed §25.511(e)(1)(A) states an award amount may not exceed $120,000 per MW of capacity for an electric generating facility that is interconnected to the ERCOT region before June 1, 2026. Proposed §25.511(f)(4) states that the commission will evaluate a request for grant payment to determine whether an electric generating facility meets the performance standards to receive a grant payment.
TPPA requested that the commission lay out the process by which the commission would review and evaluate an application to determine eligibility. TPPA recommended that section §25.511(d)(2) be expanded to contain additional procedural details, including timelines for the commission review process, entities who would conduct an eligibility review, whether evaluators will be permitted to contact an applicant directly or request additional information or modifications to an application, and the order in which applications will be processed for eligibility.
TPPA requested clarification for §25.511(e)(1) regarding the commission's determination of whether extenuating circumstances justify the extension of certain deadlines and §25.511(f)(4) relating to the commission's evaluation as to whether an eligible application meets the performance standards and should receive a grant payment.
Commission Response
The commission declines to modify the rule to further describe evaluation of applications for completion bonus grants. The rule identifies several categories of information the commission will consider in evaluating applications. The commission will evaluate applicants consistently according to the rule's evaluation criteria.
The commission also declines to modify the rule to describe extenuating circumstances because such circumstances will necessarily be unique to each applicant's situation. Further, the adopted rule describes how an eligible applicant can receive its annual grant payment in subsection (f). The evaluation will be conducted by ERCOT according to the PRF and ARF formulas.
Notice of Eligibility
Proposed §25.511(f)(2)(C)-Grant Payment Request Amount
Proposed §25.511(f)(2)(C) states that an applicant's request for completion bonus grant payment must include the amount of the grant payment requested based on the applicant's notice of eligibility and the electric generating facility's EAF performance rating during the year.
Calpine recommended that proposed §25.511(f)(2)(C) should be revised to state that information submitted in a request for a completion bonus grant payment is confidential and not subject to disclosure under Chapter 552 of the Texas Government Code. Calpine remarked that certain information, such as a facility's EAF, could be sensitive business information.
Commission Response
The commission declines to modify the rule to include a provision for confidentiality of the performance rating as part of the completion bonus grant application, as recommended by Calpine. The calculation of an electric generating facility's annual performance and any associated payment of a completion bonus grant are not an application under this rule. Therefore, this information is not confidential.
Proposed §25.511(d)(2)(A) and §25.511(f)(4)-Applicant Name and Performance Standards
See proposed §25.511(d)(2)(A) in the section above. Proposed §25.511(f)(4) states that the commission will evaluate a request for grant payment to determine whether an electric generating facility meets the performance standards to receive a grant payment.
TEC and Golden Spread recommended that a 60-day timeline on the commission's obligation to issue a notice of eligibility be added to proposed §25.511(d)(2)(A) to provide certainty to applicants for planning of eligible projects. Golden Spread further recommended that the timeline also be applied to §25.511(f)(4).
Commission Response
The commission declines to modify the rule to set a specific timeline for determining eligibility to obtain a completion bonus grant award, as suggested by TEC and Golden Spread. Given the unpredictability of the applicant pool and the eligibility period extending through 2029, the commission opts to maintain its evaluative flexibility for completion bonus grant awards. It should be noted that while each TEF program is distinct, the completion bonus grant program shares a funding cap with the Loans for the ERCOT Power Region program under §25.510, underscoring the commission's intention to retain flexibility in assessing applications across both programs.
However, the commission agrees that prompt administration of grant payments to eligible applicants is an appropriate goal of the completion bonus grant payment program. Accordingly, the commission modifies subsection (f) to incorporate performance calculation, payment notification, and review timelines applicable to the determination of bonus grant payments.
Performance Standards
Proposed §25.511(g), §25.511(d)(2)(B), and §25.511(h)-Performance Standards, Determination of Eligibility for Grant, Grant Payout Discount Formula
Proposed §25.511(g) states that an electric generating facility's performance is based on EAF during the performance year for which an applicant requests a grant payment and EAF is the fraction of a given operating period in which a generating unit is available to produce electricity without any outages or equipment deratings during the 100 hours with the least quantity of operating reserves during a performance year. It also states a grant payment may be discounted based on the formula prescribed subsection (h) of this section. Proposed §25.511(d)(2)(B) states a notice of eligibility will authorize an applicant to request and obtain data from ERCOT showing the electric generating facility's EAF performance during the 100 hours with the least quantity of operating reserves during a performance year. A notice of eligibility will automatically expire 45 days after the tenth anniversary of the electric generating facility's commercial operations date. Proposed §25.511(h) describes specifics of the grant payout discount formula.
HEN and NRG recommended the EAF calculation of 100 hours with the least quantity of operating reserves for generator performance be changed because it is unpredictable and burdensome for the commission or ERCOT to administer. HEN highlighted potential unintended consequences of using this measurement, including how unpredictable high demand or low resource availability periods could cause a generator to fail the performance metric if planned maintenance or large outages coincided. HEN expressed concern about creating a disincentive for generators to perform necessary maintenance to stay available during periods of low operating reserves. To alleviate the administrative burden of identifying and reviewing the 100 hours with the least quantity of operating reserves for each generator, HEN suggested calculating the EAF seasonally and raising the EAF thresholds. As an example, HEN proposed an EAF threshold of 97 percent for full payment and 92 percent for reduced payment during winter and summer, with slightly lower thresholds during spring and fall to account for planned maintenance outages. NRG stated that in the NERC GADS system, EAF is calculated by comparing the actual availability of a resource across all hours in the reporting period against the maximum capability of the resource in that period. Therefore, a resource with 95 percent of its capacity available in a particular operating hour would be considered to have a 95 percent EAF for that hour.
NRG added that any ERCOT-approved planned outage hours should be excluded when calculating performance. NRG remarked that the resource owner should not be penalized for such outages because a resource may not be able to move a planned outage. NRG noted that most planned outages for maintenance occur during spring and fall but unseasonable weather could cause higher than average demand and therefore lower operating reserves.
Further, NRG recommended the availability calculation exclude unplanned outages due to events such as weather emergencies or transmission system failures because such occurrences are outside of the generator's control.
NRG recommended modifying §25.511(g) and §25.511(h)(2) to lower the optimal availability factor for the first performance year to 92 percent to account for expected operational issues during the first 12 to 18 months of commercial operations, making the formula simpler to implement (as it is calculated on a 12-month basis).
TIEC and TPCA recommended that the NERC GADS definition for EAF be added to proposed §25.511(g) provide a commonly understood industry standard and to avoid duplicative metrics. TIEC also recommended the EAF performance metric be rephrased given that the EAF is a ratio of available hours measured against the number of hours in a test period, rather than an absolute number of hours as stated in the proposed rule. TIEC accordingly suggested "EAF of 95" be replaced with "EAF of 0.95" in proposed §25.511(c)(1). For consistency with PURA §34.0105(i), TIEC also recommended that the median performance standard under proposed §25.511(g)(2) evaluate the median performance of all dispatchable resources in the ERCOT power region over a defined test period. Specifically, TIEC recommended the provision be revised to be a measure of all generators in the ERCOT power region over the 50 hours of lowest reserves in the prior year. TIEC remarked that using a lower number of hours for the standard would more effectively capture expected performance of dispatchable units during periods of peak demand and reliability risk. TIEC explained that facilities built under the TEF programs will either be new or recently upgraded, therefore such facilities should reasonably be expected to perform more efficiently than the median performance of older units during the test period.
TCPA added that the EAF should be based on the "average [or equivalent] unit capacity that is actually available during the interval" that would then be averaged across the 100-hour period of lowest operating reserves. TCPA explained that using a different calculation for EAF would be confusing and that the proposed language for the EAF calculation could result in any equipment derate or interruption due to ambient temperature adjustments resulting in a zero EAF interval. TCPA commented that a zero interval could consequently prevent an applicant from receiving a grant for the performance year. TCPA stated that it is foreseeable that any given generating facility could experience small derates in more than half of the 100 hours with the lowest operating reserves which, per the language of proposed §25.511(g), would result in an EAF below the median level required to qualify for a completion bonus grant.
LCRA recommended the EAF calculation under proposed §25.511(g) be revised by either removing "or equipment deratings" or, as an alternative, qualifying the phrase by specifying only "significant equipment deratings" of 30 percent or greater of the nameplate capacity of the unit will factor into the EAF. LCRA commented that requiring a generator to perform at full nameplate capacity with no deratings is too demanding of a performance standard. LCRA explained that such performance is impractical and unreasonable to expect given the typical operations and maintenance procedures associated with dispatchable generating units and the varying weather conditions that may affect output.
LCRA recommended the EAF calculation under proposed §25.511(h) be revised to be consistent with the optimal performance standard under proposed §25.511(g)(1). Specifically, LCRA noted that the proposed linear progression of grant award payments to 100 percent EAF miscalculates the difference between the median EAF and the optimal EAF which would result in a reduced grant award being calculated for grant recipients that achieve an EAF between 50 and 95 points.
Vistra recommended that any discount of a grant award should not "dramatically reduce the payment for performance just below the optimal standard as compared to performance at the optimal standard." Specifically, Vistra commented that the 0.015 multiplier for performance between the median and optimal performance thresholds is unnecessarily punitive towards generators that perform close to, but just below, the optimal performance threshold. Vistra recommended that if the EAF metric is retained, the multiplier should be changed to 0.016667 or 1/60 to mitigate the effect of the multiplier. Vistra noted that the proposed multiplier of 0.015 would suffice if its proposal to replace EAF with EUOF is adopted.
Vistra emphasized that planned outages should be excluded from the performance metric calculations, regardless of whether EAF is retained. Vistra remarked that, per ERCOT's Physically Responsive Capacity data, the fall and spring months can sometimes have low reserves because of unseasonable weather and low renewable output coincides with ERCOT-approved planned outages for dispatchable facilities. Vistra noted that the commission has authority under PURA to establish the median and optimal performance standards, despite the express statutory requirement for the performance standard address the 100 hours of the lowest operating reserves.
Commission Response
The commission declines to modify the rule in the various manners relating to EAF definitions and calculation as recommended by HEN, NRG, TIEC, TCPA, LCRA, and Vistra. Instead, the commission adopts two performance standards based on ERCOT availability and real time (RT) telemetered data: the performance reliability factor (PRF) and the availability reliability factor (ARF). These performance standards are elaborated below. The commission modifies subsections (b) and (g) of the rule to include these standards.
PRF is computed using ERCOT availability and RT telemetered data to holistically evaluate the availability and performance of a GR during the assessed hours:
Figure 1: 16 TAC Chapter 25 - Preamble (.pdf)
"RT Telemetered HSL" is the High Sustained Limit (HSL) telemetered by the GR in real time. "Available flag" is a binary flag that is equal to the minimum of a COP available flag and an RT available flag. "COP available flag" is a binary flag that equals one if each hourly check of the GR's COP for the hour that includes the interval in question indicates the GR will be available in that interval (i.e., any status other than OUT or EMRSWGR), with such hourly checks starting at 14:30 on the day before the relevant interval; otherwise, the flag equals zero. "RT available flag" is a binary flag that equals one if the RT telemetered resource status code indicates the GR is available (i.e., any status other than OUT or EMRSWGR); otherwise, the flag equals zero. For a GR that provides capacity to an industrial load or PUN, obligated capacity is equal to the net capacity that is dedicated to the ERCOT market, as of the interconnection date and as measured by the maximum NCP demand of the associated load. For all other GRs, obligated capacity is equal to the adjusted seasonal net max sustainable rating (defined as the registered ERCOT Seasonal Net Max Sustainable Rating adjusted for planned derates). "Total evaluated period intervals" is equal to the total number of intervals in the assessed hours, excluding any that occurred during an approved planned outage of the generation resource.
ARF is a metric calculated with ERCOT data for each GR in an electric generating facility. The ARF is computed as the proportion of time that each GR was available (i.e., not in a planned outage) during the assessed hours. The ARF is calculated as follows:
Figure 2: 16 TAC Chapter 25 - Preamble (.pdf)
"Total evaluated period intervals" is equal to the total number of intervals in the assessed hours, excluding any that occurred during an approved planned outage of the generation resource. "Total period intervals" is equal to the total number of intervals during the assessed hours.
The adopted rule requires that the PRF be calculated annually for each GR in a facility, for ten consecutive test periods, starting with the first test period following a facility's interconnection date. The PRF of each GR will be compared against PRF performance, during the recent test period, of a randomly sampled reference group of non-grant recipient, dispatchable, interconnected, thermal generation resources with a nameplate capacity of at least 50 MW that have been interconnected to the ERCOT region since 2004.
The test period is a fixed 12-month period from June 1 to May 31. At the conclusion of a test period, ERCOT will calculate the median and optimal PRF values based on the performance of the reference group during the test period. At the same time, ERCOT will compute the PRF and ARF for each grant recipient's GR or GRs and evaluate it against the PRF performance of the reference group during the most recent test period. Eligible applicants will receive a payment for any GR that performs above the median PRF value and whose payment is not withheld due to a low ARF value.
As comments relate to the computation of the 100 hours with the least quantity of operating reserves, or assessed hours, PURA §34.0105(i) requires the use of those assessed hours, which is an objective measure. The commission declines recommendations from commenters that would include or exclude, for example, an individual facility's determination whether to take a planned outage. Planned outage time is excluded from the PRF calculation and included in the ARF calculation. If any GR is in a planned outage during any time within the assessed hours, its PRF will not be affected, its ARF will be negatively affected. Even if, for example, that GR qualifies for its full completion bonus grant payment based on its PRF, the payment amount will be discounted based on the ARF because its planned outage coincided with some of the assessed hours.
Subsection (h) allows for a discounted payment for performance that is above the median but below the optimal PRF value. The ARF and overall discount formula affect a GR's grant payment calculation in this way: the GR will receive its full payment amount if the GR's ARF is between 0.9 and one, a discounted payment if the GR's ARF is less than 0.9, and no payment if the formula in subsection (h) returns a value of less than or equal to zero.
The commission also declines to modify the rule for various EAF levels recommended by commentors because it has adopted the PRF and ARF instead. In response to LCRA's comment that requiring performance at nameplate capacity is too demanding, the commission has set the performance requirement for each facility based on obligated capacity, rather than nameplate capacity. The commission modifies subsection (g) of the rule in accordance with the discussion above.
Proposed §25.511(g)-Performance Standards
See proposed §25.511(g) in the sections above.
NRG recommended the EAF metric be replaced with Equivalent Unplanned Outage Factor excluding Outside Management Control events (XEUOF), which is a different metric taken from GADS. NRG argued that it is more appropriate because it accounts for "planned outages, seasonal derates, and situations outside a resource owner's reasonable control." NRG further proposed converting XEUOF to an availability requirement by deducting XEUOF from 1 and establishing the parameters for "net maximum capacity" to work in the ERCOT power region where the maximum capacity of a resource is generally measured in terms of the unit's applicable seasonal net maximum capability. NRG explained that XEUOF already excludes planned outages and provides a framework for excluding events outside human control. NRG noted that because, "XEUOF reflects the percentage of time a plant is unavailable, as opposed to EAF which reflects the percentage of time the plant is available" the calculation between the two metrics differs slightly.
TCPA, LSP, and WattBridge recommended replacing EAF with (1 - EUOF) to remove planned outages from being used to measure an electric generating facility performance. TCPA suggested that the performance standard should be limited to factors within a generator's reasonable control, specifically, ambient derates and planned outages should be excluded from the performance standard because such events are difficult or impossible for a generator to mitigate. WattBridge further noted that the 100 hours cited in the provision are likely connected to weather periods that may cause either high demand for power or low resource availability for intermittent and dispatchable resources. Therefore, a project's performance under the rule should not be impacted by not accounting for this maintenance standard if one or more planned outages coincide with one or more of the 100 hours with the least quantity of operating reserves. WattBridge stated adjusting the performance standard for maintenance is necessary for logistical realities and to ensure reliability. LSP recommended the optimal performance standard be equal to the 90th percentile using the same test period as the median performance standard and commented that the change would create a high but achievable threshold for optimal performance.
LSP also recommended the median performance standard be the 50th percentile as that may be equivalent to the lowest 25th percentile of fleet performance, therefore resulting in awarding completion bonus grants to facilities with poor performance. LSP said that it is only necessary to calculate the median performance once over a representative period such as between 2022 and 2024 and then utilized for each of the ten years grant distribution period.
Calpine commented that outages or equipment deratings under proposed §25.511(g) should exclude planned outages or outages that are outside of the generator's control such as ERCOT approved planned outages, including ERCOT instruction to reduce output or go offline, limitations imposed by transmission outages, seasonal ambient temperature deratings, or outages directly related to ERCOT denial or a generating facility's request for maintenance. As an alternative to the EAF, Calpine recommended the commission develop a system-wide average metric where performance above the metric would provide full payment to a generator for the performance year, while performance below the threshold would be discounted.
Calpine also recommended the commission consider whether a generator could also be credited for postponing an outage or completing an outage early in response to an ERCOT Advance Action Notice.
Calpine requested clarification as to the meaning of "the fraction of a given operating period" as used in proposed §25.511(g). Calpine remarked that greater transparency and clarity on the EAF calculation process in the rule is beneficial because it aids grant applicants in understanding how to achieve the optimal performance standard and ultimately provide ERCOT electric consumers with more reliable electric capacity in the long run.
Commission Response
The commission modifies subsections (b) and (g) of the rule to define a PRF based on COP and RT telemetered data and measured against the median performance standard of a reference group of GRs. Planned outage time is excluded from the PRF calculation and included in the ARF calculation. If a GR is in a planned outage during any time within the assessed hours, its PRF will not be affected, but its ARF will be negatively affected. Even if, for example, that GR qualifies for its full completion bonus grant payment based on its PRF, the payment amount will be discounted based on the ARF (at an ARF value of less than 0.9) because its planned outage coincided with some of the assessed hours.
Calpine recommended the phrase "available to produce" in proposed §25.511(g) should be revised to mean that "a generating facility has an offer in SCED, has received an ancillary service award, or has an offer in the day-ahead market (DAM)" because such a status demonstrates operational readiness to participate in the ERCOT market.
Commission Response
The commission declines Calpine's recommended rule revisions regarding a facility's availability. The commission modifies subsections (b) and (g) of the rule to define a PRF based on COP and RT telemetered data and measured against the median performance standard of a reference group of GRs. Therefore, it is not necessary to define "available to produce."
WattBridge recommended that the EAF be calculated in a manner consistent with the GADS methodology provided by in Appendix F of NERC's Data Reporting Instruction to ensure that the performance of the entire facility is measures, as opposed to individual units.
Commission Response
The commission declines to modify the rule to calculate EAF in a manner consistent with the GADS methodology, as recommended by WattBridge. The commission will use ERCOT data rather than NERC GADS EAF data, in part because the EAF data are not suited to account for the 100 hours with the least quantity of operating reserves as statutorily specified.
Proposed §25.511(d)(2)(B) and §25.511(g)- Determination of Eligibility for Grant, Performance Standards
See proposed §25.511(d)(2)(B) and §25.511(g) in the sections above.
ERCOT recommended that the rule be revised to provide that any EAF must be calculated using ERCOT's own availability data. ERCOT commented that, using its own data, it can determine the 100 hours with the lowest level of operating reserves and determine an EAF using this information and the calculation under proposed §25.511(g). To further facilitate this change, ERCOT recommended proposed §25.511(d)(2)(B) be revised to allow ERCOT to establish an EAF margin based on the data available to it. Alternatively, ERCOT recommended revising proposed §25.511(g) "to provide for a reduction in the EAF proportional to the magnitude of the derate, rather than considering any derate to mean the unit is entirely unavailable" to ensure that the impact of small derates on a generator's availability would not disproportionately affect a generator's EAF calculation.
ERCOT requested clarification as to whether the EAF data ERCOT must provide to a completion bonus grant applicant will be calculated using data from NERC GADS under proposed §25.511(d)(2)(B). ERCOT further noted that proposed §25.510 in Project 55826 derives EAF from NERC GADS. ERCOT explained that while EAF is a reliable metric for calculating availability, it cannot calculate an EAF using NERC GADS because ERCOT does not have access to that system or the corresponding information within it because it is confidential. ERCOT also commented that an EAF cannot be created for 100 non-continuous hours for purposes of the bonus because NERC GADS calculates EAF on a monthly and yearly basis.
To avoid any potential concerns relating to the integrity of the EAF figure provided to the grant applicant, ERCOT additionally suggested that proposed §25.511(d)(2)(B) be revised to require ERCOT to confidentially file the availability calculation with the commission in a preassigned project number at the same time that ERCOT provides that information to the applicant.
Commission Response
The commission agrees with ERCOT about using ERCOT telemetered and availability data to calculate an EAF metric and modifies the rule to use a separate metric, PRF, to avoid confusion with either NERC EAF or the PAF and POF as applied in §25.510. The EAF metric used in the proposed rule relies on confidential NERC GADS data that is not readily available to ERCOT or the commission.
In addition, in response to ERCOT's comment requesting that the commission modify the proposed rule to add a confidential filing by ERCOT, the commission modifies subsection (f) of the rule to change the process by which ERCOT will communicate with the TEF administrator. The process does not require a confidential filing. It requires that ERCOT send performance data to the TEF administrator, who will then share each eligible applicant's data with that applicant.
Proposed §25.511(f)(2) and §25.511(d)(2)(B)-Grant Payment Request, Determination of Eligibility for Grant
Proposed §25.511(f)(2) describes the information that must be included in the request for grant payment. Proposed §25.511(d)(2)(B) states a notice of eligibility will authorize an applicant to request and obtain data from ERCOT showing the electric generating facility's equivalent availability factor (EAF) performance during the 100 hours with the least quantity of operating reserves during a performance year. A notice of eligibility will automatically expire 45 days after the tenth anniversary of the electric generating facility's commercial operations date.
TPPA recommended that the commission include a defined timeframe under which ERCOT would be expected to furnish EAF data to a requester.
Commission Response
The commission agrees with TPPA that timeliness is an important factor in the administration of the program. Accordingly, the commission modifies subsection (f) of the rule to incorporate calculation deadlines applicable to ERCOT. The processes related to determining assessed hours, median performance, optimal performance, PRF, and ARF will allow for reporting of data to the commission and TEF administrator to be effectively concurrent with reporting to the completion bonus grant recipient.
Proposed §25.511(g), §25.511(g)(1), §25.511(g)(2), and §25.511(h)(2)-Performance Standards and Grant Payment Discount Formula
Proposed §25.511(g) states that an electric generating facility's performance is based on EAF during the performance year of a given operating period in which a generating unit is available to produce electricity without outages or equipment derates during the 100 hours with the least quantity of operating reserves during a performance year and outlines the formula for discounting grant payments based on performance. Proposed §25.511(g)(1) states that optimal performance is an EAF of 95 during the 100 hours with the least quantity of operating reserves for the performance year. Proposed §25.511(g)(2) states that median performance is an EAF of 50 during the 100 hours with the least quantity of operating reserves for the performance year. Proposed §25.511(h)(2) provides an example on how the grant payment discount formula would be applied.
Vistra recommended the EAF metric be replaced with the EUOF metric defined by NERC to account for planned outages and derates or outages and derates outside the generator's control. Vistra noted that planned outages can take days or weeks depending on maintenance and therefore that the inclusion of planned outage hours in the performance calculations may incentivize focusing maintenance efforts on meeting a performance metric rather than safe and reliable operations. Vistra concluded that any performance metric should acknowledge that no generator can operate at all times at maximum capacity. Accordingly, Vistra recommended that an EUOF standard of five percent or EAF standard of 85 percent is appropriate.
Commission Response
The commission declines to replace the EAF metric with the EUOF metric, as recommended by Vistra. However, the commission agrees with Vistra that the rule should not discourage a GR owner from undertaking prudent planned maintenance. The commission therefore modifies the rule to define a PRF, which excludes planned outages. However, the rule also includes the ARF, which will be negatively impacted by planned outages.
Proposed §25.511(g)(2)-Median Performance
Proposed §25.511(g)(2) states that median performance of an electric generating facility is an EAF of 50 during the 100 hours with the least quantity of operating reserves for the performance year.
Sierra Club recommended that the 50 out of 100 hours with least quantity of operating reserves for the performance year performance standard in proposed §25.511(g)(2) should be increased to 70 out of 100. Sierra Club explained that the hours with the lowest quantity of operating reserves is the most important time period. Accordingly, Sierra Club advised that raising the threshold to 70 hours is a reasonable minimum standard to receive a performance bonus from taxpayers.
Commission Response
The commission declines to increase the value of the median performance standard during the 100 hours with the least quantity of operating reserves, or assessed hours, as recommended by Sierra Club. Instead, the commission modifies the rule such that the median performance metric is derived from the 50th percentile of the GR reference group's performance during the assessed hours, and not performance during the 50th hour of the assessed hours. Therefore, the hour count other than the total number of assessed hours is not applicable to the metric. The median performance will be based on actual data during a defined test period and will be evaluated based on the relative position of a GR's test period performance as it relates to the reference group's performance.
Completion Bonus Grant Award Amount
Proposed §25.511(e)(1)(B)-Completion Bonus Grant Award Amount for Interconnection After June 1, 2026, and Before June 1, 2029
Proposed §25.511(e)(1)(B) states an award amount may not exceed $80,000 per MW of capacity for an electric generating facility that is interconnected in the ERCOT region after June 1, 2026, and before June 1, 2029.
Vistra recommended modifying the rule to track the statutory language of SB 2627 more clearly. Specifically, Vistra noted that PURA §34.0105(f)(2) establishes $120,000 and $80,000 as caps on grant awards, not as specific amounts to be awarded. Vistra commented that a "non-discriminatory, pre-determined award amount" would provide the most market certainty, even at amounts lower than the caps provided by PURA. Vistra alternatively recommended revising the provisions to provide the commission's methodology for determining completion bonus grant amounts. Vistra recommended that the rule language precisely track the bonus grant cap for electric generating facilities interconnected "on or after June 1, 2026."
Commission Response
The commission declines to modify the rule to establish a "pre-determined award amount," as recommended by Vistra. PURA §34.0105(f) sets caps on grant awards and does not specify lower award amounts. In addition, PURA §34.0105(i) requires the commission to adopt performance standards that operate to discount a grant award for less-than-optimal performance. To give full effect to these provisions, the commission authorizes a grant award payment at the statutory cap for optimal performance and discounts the award payment in accordance with the formula in subsection (h) for any performance below the optimal level. The commission agrees with Vistra that the grant caps in the rule should exactly track statutory language. Therefore, the commission modifies the rule to reflect that an $80,000 grant cap will apply for an electric generating facility interconnected "on or after" June 1, 2026.
New §25.511(h)(1)(D)-Grant Payment Discount Formula
Calpine recommended adding a new provision in §25.511(h) that would authorize an applicant to earn back some portion of the withheld or discounted payment if performance in a subsequent performance year exceeds 95. Calpine opined that a specified percentage of the withholding could be paid out at each performance increment above 95 up to 100 to incentivize a grant recipient to improve generator performance.
Commission Response
The commission declines to add a new provision allowing an applicant to earn back some portion of the withheld or discounted payment, as suggested by Calpine. The full completion bonus grant serves as an incentive for high performance. Although various factors may impact performance within any given period, improved results in later periods do not compensate for earlier underperformance. Furthermore, PURA §34.0105(i) prohibits the commission from disbursing an annual grant payment if the facility's performance is at or below the median performance standard for the designated test period within that year.
No Contested Case or Appeal
Proposed §25.511(i)-No Contested Case or Appeal
Proposed §25.511(i) states that neither an application for a completion bonus grant award nor a request for grant payment is a contested case and commission decisions in this case are not subject to motions for rehearing or appeal.
Vistra commented that removing completion bonus grant applications from the contested case process would depart from the commission's normal procedures. Vistra advocated for completion bonus grant applications to be processed as limited contested cases under 16 TAC §22.35 in which the only parties to the proceeding would be the applicant and commission staff. Vistra noted that such a change would be prudent for administrative efficiency and would avoid legal challenges to TEF programs.
LCRA and Calpine recommended modifying the rule to permit a completion bonus grant recipient to challenge the EAF data from ERCOT if the recipient concludes ERCOT's data contains errors or contradicts the applicant's data regarding its facility EAF performance. Calpine explained that because certain factors such as planned outages or outages outside of a generator's control should not be counted against a generator's performance, a system of accountability is warranted. Calpine emphasized that this is particularly true in the completion bonus grant program because a developer bears all costs until and unless a grant is awarded.
Calpine also recommended that if the commission were to deny a grant application or otherwise finds it deficient, an applicant should be afforded the opportunity to cure the deficiencies without a contested case proceeding or refile the application without prejudice.
TPPA requested clarification on whether the rule would prohibit all forms of appeal, including judicial review.
Commission Response
The commission declines to process a completion bonus grant application as a contested case, as recommended by Vistra. Under the Texas Administrative Procedure Act (Texas APA), a contested case is a proceeding in which a state agency determines the legal rights, duties, or privileges of a party after an opportunity for an adjudicative hearing. No part of Chapter 34 of PURA provides an applicant the opportunity for an adjudicative hearing to present evidence in favor of its eligibility to receive a completion bonus grant. The commission interprets the absence of an opportunity for hearing to signify that contested case rights under the Texas APA do not apply to whether an applicant is eligible to obtain a completion bonus grant. Accordingly, the commission will make eligibility determinations under subsection (d) of the rule based on information that an applicant provides in its application. Moreover, applicants do not have the opportunity to move for rehearing or seek judicial review under the Texas APA because those rights are exclusively associated with contested cases.
Commission determinations on completion bonus grant applications for program eligibility are final. The limitation of an appeal mechanism reflects that the commission will not develop an internal appeal process for determinations on whether an applicant is eligible to obtain a completion bonus grant. Even so, the commission agrees with Calpine that, in limited circumstances, the commission may need additional information to make a determination on a completion bonus grant application. The absence of Texas APA contested case procedures does not prevent an applicant from supplementing or revising an application upon the request of the commission after initial application.
While completion bonus program eligibility does not provide an opportunity for a hearing, the commission agrees with LCRA and Calpine that ERCOT's determinations of PRF and ARF should be correctable if those terms are calculated based on faulty data inputs. Accordingly, the commission modifies subsection (f) of the rule to reflect that eligible applicants may seek review of ERCOT's determination of PRF, ARF, and the payment calculation using ERCOT's alternative dispute resolution procedures codified under ERCOT Protocols section 20. The commission also modifies subsection (i) of the rule to remove references to requests for grant payments because subsection (f) provides a mechanism to dispute ERCOT determinations that may result in the filing of a complaint at the commission.
The commission is unable to provide further clarification in response to TPPA's question regarding appealability because it does not have the power to define the jurisdiction of Texas courts with respect to the various challenges that applicants may present in relation to this rule.
This new rule is adopted under the following provisions of PURA: §14.002, which provides the commission with the authority to make, adopt, and enforce rules reasonably required in the exercise of its powers and jurisdiction; PURA §34.0105, which provides the framework to establish procedures for applying for a completion bonus grant for the construction of dispatchable electric generating facilities in the ERCOT power region, as well as evaluation criteria, disbursement, and performance standards; and §34.0106, which establishes conditions for the dispensation of completion bonus grants to eligible applicants.
Cross reference to statutes: Public Utility Regulatory Act §§14.002, 34.0105, and 34.0106.
§25.511.Texas Energy Fund Completion Bonus Grant Program.
(a) Purpose. The purpose of this section is to implement Public Utility Regulatory Act (PURA) §34.0105 and §34.0106 and establish:
(1) Procedures for submitting an application to be eligible for a completion bonus grant award;
(2) The process by which an applicant may receive an annual grant payment; and
(3) Performance standards for electric generating facilities for which an applicant seeks a completion bonus grant payment.
(b) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise.
(1) Assessed hours--the 100 hours during the test period with the least quantity of operating reserves, as determined by the highest values of peak net load, where peak net load is calculated as gross load minus wind, solar, and storage injection.
(2) Availability reliability factor (ARF)--a metric calculated with ERCOT data for each generation resource for which the commission awards a completion bonus grant under this section. The ARF is computed as the proportion of time that each generation resource was available (i.e., not in a planned outage) during the assessed hours. The ARF is calculated as follows: "Total evaluated period intervals" is equal to the total number of intervals during the assessed hours, excluding any that occurred during an approved planned outage of the generation resource. "Total period intervals" is equal to the total number of intervals during the assessed hours.
Figure: 16 TAC §25.511(b)(2) (.pdf)
(3) Interconnection date -- the resource commissioning date, as defined in the ERCOT protocols, for the last generation resource in an electric generating facility for which an applicant seeks a completion bonus grant award. The new electric generating facility or new generation resources at an existing electric generating facility must meet the eligibility criteria described in subsection (c) of this section.
(4) Performance reliability factor (PRF) -- a metric calculated with ERCOT availability and real time (RT) telemetered data for each generation resource for which the commission awards a completion bonus grant under this section. The PRF is computed as the average ratio of each generation resource's RT high sustainable limit (HSL) and its obligated capacity over the assessed hours. Intervals that occurred during an approved planned outage of a generation resource are excluded. The PRF is calculated as follows: "RT Telemetered HSL" is the HSL telemetered by the generation resource in real time. "Available Flag" is a binary flag that is equal to the minimum of a current operating plan (COP) available flag and a RT available flag. "COP available flag" is a binary flag that equals one if each hourly check of the generation resource's COP for the hour that includes the interval in question indicates that the generation resource will be available in that interval (i.e., any status other than OUT or EMRSWGR), with such hourly checks starting at 14:30 on the day before the relevant interval; otherwise, the flag equals zero. "RT available flag" is a binary flag that equals one if the RT telemetered resource status code indicates the generation resource is available (i.e., any status other than OUT or EMRSWGR); otherwise, the flag equals zero. For a generation resource that provides capacity to an industrial load or private use network (PUN), obligated capacity is equal to the net capacity that is dedicated to ERCOT, as of the interconnection date. For all other generation resources, obligated capacity is equal to the adjusted seasonal net max sustainable rating (defined as the registered ERCOT Seasonal Net Max Sustainable Rating adjusted for planned derates). "Total evaluated period intervals" is equal to the total number of intervals during the assessed hours, excluding any that occurred during an approved planned outage of the generation resource.
Figure: 16 TAC §25.511(b)(4) (.pdf)
(5) Test period -- the one-year period starting on June 1 of one year and ending on May 31 of the following year.
(c) Eligibility. To be eligible for a completion bonus grant award under this section, an applicant must construct at least 100 MW of new nameplate capacity, either as new generation resources in a new electric generating facility, or new generation resources at an existing electric generating facility, and the generation resources for which a completion bonus grant is sought must also:
(1) interconnect to and provide power for the ERCOT region;
(2) be dispatchable with an output that can be controlled primarily by forces under human control;
(3) not be an electric energy storage facility;
(4) participate in the ERCOT wholesale market;
(5) consist of one or more generation resources physically capable of interconnecting to the ERCOT region through a single point of interconnection;
(6) be eligible to interconnect to the ERCOT region based on the attributes of the owners of the electric generating facility, according to the requirements in the Lone Star Infrastructure Protection Act (codified at Texas Business and Commerce Code §117.002);
(7) not meet the planning model requirements necessary to be included in an ERCOT capacity, demand, and reserves report for the ERCOT region before June 1, 2023 for the construction or addition of any generation resource;
(8) operate in such a manner that the electric generating facility that is serving an industrial load or PUN must meet the following conditions: the portion of nameplate capacity that will serve the maximum non-coincident peak demand of the industrial load or PUN must be less than 50 percent of the facility's total nameplate capacity, and the remaining capacity serving the ERCOT market must be greater than 100 MW; and
(9) meet the interconnection deadlines described in subsection (e)(2) of this section.
(d) Determination of eligibility for completion bonus grant award.
(1) Eligibility application. No earlier than January 1, 2025, and no later than 180 days after the interconnection date of the electric generating facility for which an applicant requests a completion bonus grant award, an applicant must submit an electronic application in the form and manner prescribed by the commission. The application must include:
(A) the applicant's legal name and the proposed name of each generation resource in the electric generating facility for which it seeks a completion bonus grant award. A corporate sponsor or parent may submit the application on behalf of its subsidiary applicant;
(B) information describing the applicant's quality of services and management;
(C) information describing the applicant's efficiency of operations;
(D) a record of the applicant's history of electric generation operations in this state and this country, including information demonstrating the applicant's experience operating and maintaining dispatchable electric generating facilities;
(E) a description of the operational attributes of the electric generating facility; if any generation resource in the electric generating facility will serve an industrial load or PUN, a description of the manner in which it will serve the industrial load or PUN, how the electric generating facility will primarily serve and benefit the ERCOT bulk power system given its relationship to a PUN or industrial load, the total nameplate capacity of the electric generating facility, the anticipated or actual maximum non-coincident peak demand of the associated industrial load or PUN, whether the electric generating facility's generation capacity would be available to the ERCOT bulk power system during any Energy Emergency Alert, and a copy of any information submitted to ERCOT regarding PUN net generation capacity availability;
(F) a description of the electric generating facility's ability to address regional and reliability needs;
(G) for electric generating facilities not yet interconnected to the ERCOT region:
(i) a proposed project schedule with anticipated dates for completion of construction, submission of registration documents with ERCOT and the commission, and anticipated interconnection date;
(ii) the anticipated nameplate capacity of the electric generating facility when commercial operations begin; and
(iii) the estimated construction costs of the electric generating facility.
(H) for electric generating facilities already interconnected to the ERCOT region:
(i) the actual construction costs of the electric generating facility, listed by generation resource;
(ii) the interconnection date of the newly constructed electric generating facility or of the last new generation resource added to an existing electric generating facility;
(iii) the total nameplate capacity of each generation resource in the electric generating facility that meets the eligibility requirement described in subsection (c)(7) of this section; and
(iv) the name of each generation resource in the electric generating facility and the name of the electric generating facility on ERCOT's market participant list.
(I) a statement describing when each generation resource in the electric generating facility met the planning model requirements necessary to be included in an ERCOT capacity, demand, and reserves report with an identification of the first appearance of the electric generating facility, or any generation resource in the electric generating facility, in an ERCOT capacity, demand, and reserves report;
(J) a statement of whether the applicant applied for a loan under §25.510 of this title (relating to Texas Energy Fund In-ERCOT Generation Loan Program) and the commission's determination on the loan application, if known;
(K) if applicable, a statement asserting that extenuating circumstances support the extension of any deadline described in subsection (e)(2) of this section, including the facts surrounding those extenuating circumstances;
(L) documentation that the applicant has registered or will register with the commission as a power generation company, unless the applicant is an MOU, electric cooperative, or river authority;
(M) documentation that the applicant has registered or will register its generation resources according to ERCOT's registration requirements; and
(N) a narrative explanation of the applicant's preparations for compliance with §25.55 of this title (relating to Weather Emergency Preparedness).
(2) The commission will evaluate the information provided in an application to determine whether an applicant is eligible to receive a completion bonus grant award. Determination of eligibility to receive a completion bonus grant award does not entitle an applicant to a grant payment.
(A) The commission will issue a notice of eligibility for an applicant it determines is eligible to receive a completion bonus grant award. The notice of eligibility will state the completion bonus grant award amount based on the actual or projected capacity of each generation resource in the electric generating facility and its actual or projected interconnection date. The award amount is calculated for each generation resource, and these amounts are added together, if applicable, to reach a total award amount for the electric generating facility. For a project that has not reached its interconnection date at the time the application is submitted, the applicant must subsequently submit to the TEF administrator documentation demonstrating that the interconnection date satisfies the applicable deadline in subsection (e)(2) of this section and demonstrate adherence to the criteria described in subsection (c) of this section. If the actual nameplate capacity or interconnection date differs from estimates, the commission may revise the eligible applicant's completion bonus grant award amount to reflect actual information and amend the notice of eligibility accordingly.
(B) For the ten successive test periods following a qualifying electric generating facility's interconnection date, an eligible applicant is authorized to receive an annual completion bonus grant payment for each test period in which its generation resource or resources meet the performance standard established in this section.
(C) An eligible applicant must enter into a grant agreement in the form and manner specified by the commission whereby the eligible applicant commits to adhere to the requirements described in subsection (c) of this section for the duration of any test period for which it may receive a completion bonus grant payment. Failure to enter into a grant agreement or breach of the executed grant agreement will be grounds for the commission to determine that an applicant is ineligible to obtain any future completion bonus grant payment.
(3) Information submitted to the commission in a completion bonus grant application is confidential and not subject to disclosure under Chapter 552 of the Texas Government Code.
(4) An applicant must separately file a statement indicating that an application for a completion bonus grant award has been presented to the commission for review with the date of application submission.
(e) Completion bonus grant award amount.
(1) The amount of a completion bonus grant award is based on program funding availability, and either;
(A) the combined capacity of each new generation resource and interconnection date of the new electric generating facility; or
(B) the combined capacity of each new generation resource and interconnection date of the last new generation resource added to an existing electric generating facility.
(2) Unless the commission determines that extenuating circumstances justify extension of the deadlines under this subsection, the commission may approve a completion bonus grant award for an applicant considered eligible to receive a completion bonus grant award in an amount not to exceed:
(A) $120,000 per MW of applicable capacity that is interconnected to the ERCOT region before June 1, 2026; or
(B) $80,000 per MW of applicable capacity that is interconnected to the ERCOT region on or after June 1, 2026, and before June 1, 2029.
(3) The applicable capacity for use in paragraph (1)(A) and (1)(B) of this subsection is:
(A) the combined nameplate capacity of all new generation resources, if the newly constructed electric generating facility provides all capacity exclusively to the ERCOT power region;
(B) the increase in nameplate capacity attributable to the addition of one or more new generation resources at an existing electric generating facility; or
(C) the net nameplate capacity that exclusively serves the ERCOT region, as determined by the maximum non-coincident peak demand of the industrial load or PUN, if the electric generating facility serves an industrial load or PUN.
(f) Grant payment process.
(1) For each test period, the TEF administrator will disburse a grant payment to an applicant eligible to receive a completion bonus grant award. A grant payment is one-tenth of an applicant's total completion bonus grant award, subject to the performance standards and discount methodology prescribed under subsections (g) and (h) of this section.
(2) No later than 45 days following the end of each test period, ERCOT must determine and provide to the TEF administrator the assessed hours, the median and optimal performance levels of the generation resources in the reference group, the PRF and ARF for each generation resource in an electric generating facility under this section, and the amount of payment each eligible applicant is entitled to for that test period, based on the performance of each of its generation resources. The TEF administrator will provide each eligible applicant the assessed hours, the median and optimal performance levels, the eligible applicant's PRF and ARF, and the eligible applicant's calculated completion bonus grant payment amount.
(3) ERCOT's determination of a generation resource's PRF and ARF and the calculation of the applicant's completion bonus award payment following a test period are subject to review under Section 20 of the ERCOT protocols (alternative dispute resolution procedure) as modified by this subsection. To seek review of ERCOT's determination of PRF, ARF, or payment amount, an eligible applicant must submit a written request for an alternative dispute resolution proceeding to ERCOT no later than 30 days after the date the TEF administrator provides PRF and ARF determinations and payment calculations to the eligible applicant for the test period. The eligible applicant must simultaneously notify the TEF administrator in writing in the manner prescribed by the commission that it has invoked review of ERCOT's determination of PRF or ARF or payment calculations. An eligible applicant may appeal the outcome of the ERCOT review in accordance with §22.251(d) of this title (relating to Review of Electric Reliability Council of Texas (ERCOT) Conduct). The only parties to an appeal of the ERCOT review are the eligible applicant, ERCOT, and commission staff.
(4) Thirty-five days after the TEF administrator provides the PRF, ARF, and completion bonus grant payment amount to each eligible applicant, the TEF administrator will instruct the Texas Treasury Safekeeping Trust Company to disburse the grant payment to the eligible applicant and notify the eligible applicant of the disbursement, unless the eligible applicant requests review of the determination of PRF or ARF under paragraph (3) of this subsection. Upon resolution of a requested review, the TEF administrator will instruct the Texas Treasury Safekeeping Trust Company to disburse the grant payment, if appropriate.
(g) Performance standards. An electric generating facility's performance is based on the PRF and ARF of each generation resource in the facility during the test period. The generation resource's PRF will be compared against the PRF of a reference group of non-grant recipient generation resources in the ERCOT region. ERCOT, in consultation with commission staff, must select a reference group comprising at least 30 resources randomly sampled from all dispatchable, interconnected, thermal generation resources with a nameplate capacity of at least 50 MW that were first interconnected to the ERCOT region on or after January 1, 2004. A grant payment may be discounted based on the formula prescribed in subsection (h) of this section. The performance standards for any test period are as follows:
(1) Optimal performance standard is determined by the 90th percentile of PRF scores achieved by resources in the reference group during the assessed hours.
(2) Median performance standard is determined by the 50th percentile of PRF scores achieved by resources in the reference group during the assessed hours.
(h) Grant payment discount formula. A grant payment equals one-tenth of an applicant's completion bonus grant award as stated in the applicant's notice of eligibility, subject to discount or withholding. Grant payments are calculated per generation resource. Each generation resource's performance is computed separately, and a grant payment for that generation resource calculated accordingly. The total grant payment is summed from the individual generation resources' grant payments, if applicable. The formula for any discount of an annual grant payment is as follows:
Figure: 16 TAC §25.511(h) (.pdf)
(1) Discount or withholding of payment.
(A) The TEF administrator will not apply any discount to a grant payment if the generation resource meets or exceeds the optimal PRF performance standard established under subsection (g)(1) of this section and achieves an ARF of between 0.9 and one.
(B) The TEF administrator will disburse a discounted grant payment if the PRF of the generation resource for which the grant was provided is above the median performance standard established under subsection (g)(2) of this section but less than an optimal performance standard established under subsection (g)(1) of this section, or if the ARF of the generation resource is less than 0.9.
(C) The TEF administrator will withhold a grant payment if the PRF of the generation resource is equal to or below the median performance standard established under subsection (g)(2) of this section, or if the generation resource's calculation according to the formula in this subsection returns a value less than or equal to zero.
(2) Example. An applicant would receive the following grant payments for hypothetical test periods 1, 2, and 3 based on a $12,000,000 completion bonus grant award described in a notice of eligibility for a 100 MW generation resource interconnected on March 1, 2026. The table below represents an example of hypothetical test period PRF distributions.
Figure: 16 TAC §25.511(h)(2) (.pdf)
(i) No Contested Case or Appeal. An application for completion bonus grant eligibility is not a contested case. A commission decision on completion bonus grant program eligibility is not subject to a motion for rehearing or appeal under the commission's procedural rules.
(j) Expiration. This section expires December 1, 2040.
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 April 25, 2024.
TRD-202401762
Adriana Gonzales
Rules Coordinator
Public Utility Commission of Texas
Effective date: May 15, 2024
Proposal publication date: December 15, 2023
For further information, please call: (512) 936-7322
CHAPTER 84. DRIVER EDUCATION AND SAFETY
SUBCHAPTER M. CURRICULUM AND ALTERNATIVE METHODS OF INSTRUCTION
The Texas Commission of Licensing and Regulation (Commission) adopts amendments to existing rules at 16 Texas Administrative Code (TAC), Chapter 84, Subchapter M, §84.500 and §84.502 regarding the Driver Education and Safety program, without changes to the proposed text as published in the January 26, 2024, issue of the Texas Register (49 TexReg 319). These rules will not be republished.
EXPLANATION OF AND JUSTIFICATION FOR THE RULES
The rules under 16 TAC, Chapter 84, implement Texas Education Code, Chapter 1001, Driver and Traffic Safety Education.
The adopted rules are necessary to implement Senate Bill (SB) 2304, Section 3, 88th Legislature, Regular Session (2023), which amends Texas Education Code, Chapter 1001, to require that the curriculum of each driver education and driving safety course include information relating to the Texas Driving with Disability Program (program).
The program is designed, in collaboration with the Department, the Department of Public Safety, the Texas Department of Motor Vehicles, and the Governor's Committee on People with Disabilities, to develop informational materials for prospective students with a health condition or disability that may impede effective communication with a peace officer. Such information will provide an affected person with the option to voluntarily list any such health condition on the person's vehicle registration information or on an application for an original driver's license. This information may serve to reduce issues that can arise at a traffic stop by alerting the peace officer at the start of an encounter that the motorist has a disability or health condition that affects their ability to communicate effectively. The information developed by these organizations, upon completion, will be placed on the Department website for the DES program, and incorporated within its Program Guides as part of a future rulemaking.
SECTION-BY-SECTION SUMMARY
The adopted rules amend §84.500, Courses of Instruction for Driver Education Providers, by: (1) including the Texas Driving with Disabilities Program, adopted by SB 2304, in the educational objectives for driver training course curricula; and (2) reorganizing supplemental educational objectives within the rule section.
The adopted rules amend §84.502, Driving Safety Courses of Instruction, to include the Texas Driving with Disabilities Program, adopted by SB 2304, in the educational objectives for driving safety course curricula.
PUBLIC COMMENTS
The Department drafted and distributed the proposed rules to persons internal and external to the agency. The proposed rules were published in the January 26, 2024, issue of the Texas Register (49 TexReg 319). The public comment period closed on February 26, 2024. The Department received comments from two interested parties on the proposed rules. The public comments are summarized below.
Comment - The Department received a comment from an interested party in support of the proposed rules who stated that the program was a welcome addition to individuals with all types of disabilities who operate motor vehicles. The commenter believes that the program could provide a greater feeling of independence for those persons with disabilities.
Department Response - The Department appreciates the comment in support of the proposed rules and no change was made to the proposed rules as a result of this comment.
Comment - The Department received a second comment from an interested party that noted that the licensing fee for an online driving safety provider was too high. This comment refers to a rule subchapter that was not amended during this rulemaking and, therefore, is outside of the scope of the rulemaking.
Department Response - The Department appreciates the comment, however, as the comment was outside of the scope of the rulemaking, no change was made to the proposed rules as a result of this comment.
ADVISORY BOARD RECOMMENDATIONS AND COMMISSION ACTION
The Driver Education and Training Safety Advisory Board met on February 28, 2024, to discuss the proposed rules and the public comments received. The Advisory Board recommended that the Commission adopt the proposed rules as published in the Texas Register.
STATUTORY AUTHORITY
The adopted rules are adopted under Texas Occupations Code, Chapter 51 and Texas Education Code, Chapter 1001, which authorize the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement these chapters and any other law establishing a program regulated by the Department.
The statutory provisions affected by the adopted rules are those set forth in Texas Occupations Code, Chapter 51 and Texas Education Code, Chapter 1001. No other statutes, articles, or codes are affected by the adopted rules.
The legislation that enacted the statutory authority under which the adopted rules are proposed to be adopted is Senate Bill 2304, 88th Legislature, Regular Session (2023).
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 April 23, 2024.
TRD-202401716
Doug Jennings
General Counsel
Texas Department of Licensing and Regulation
Effective date: May 15, 2024
Proposal publication date: January 26, 2024
For further information, please call: (512) 463-7750
The Texas Commission of Licensing and Regulation (Commission) adopts amendments to existing rules at 16 Texas Administrative Code (TAC), Chapter 111, Subchapter A, §111.1; Subchapter C, §111.23; Subchapter F, §111.50; Subchapter P, §§111.150, 111.151, and 111.155; Subchapter Q, §111.160; and Subchapter T, §111.190 and §111.192; and adopts the repeal of existing rules at Subchapter O, §111.140, regarding the Speech-Language Pathologists and Audiologists program, without changes to the proposed text as published in the December 22, 2023, issue of the Texas Register (48 TexReg 7727). These rules will not be republished.
EXPLANATION OF AND JUSTIFICATION FOR THE RULES
The rules under 16 TAC Chapter 111, implement Texas Occupations Code, Chapter 401, Speech-Language Pathologists and Audiologists; and Chapter 51, the enabling statute of the Texas Commission of Licensing and Regulation (Commission) and the Department. Specific provisions within this rule chapter also implement the statutory requirements under Texas Occupations Code, Chapters 53, 108, 111, 112, 116, and 402, as applicable.
The adopted rules are necessary to implement recommended changes from the Speech-Language Pathologists and Audiologists Advisory Board with input from two of its workgroups; implement select changes from Department staff as a result of the four-year rule review; and make technical corrections from two previous rulemakings.
Advisory Board Workgroup Changes
The adopted rules implement recommended changes from the Speech-Language Pathologists and Audiologists Advisory Board based on input from two of its workgroups. The advisory board agreed with the recommended changes from both workgroups, and those recommended changes are included in these adopted rules.
First, the Licensing Workgroup recommended changes to address how a licensee may provide proof of licensure to a client when providing telehealth services and services outside of an office setting. This workgroup recommended changes to §111.151, which requires a licensee to display a license certificate or carry a license identification card. The requirement to always carry a license while providing services is not convenient and can be burdensome in some clinical settings. The adopted rules provide an additional option and allow a licensee to provide proof of licensure to a requestor through the Department's online license search.
Second, the Standard of Care Workgroup recommended changes to address cognition screenings as part of the communication screenings. This workgroup recommended changes to §111.190 to add provisions on cognition screening as it relates to communication function. Cognition plays an important part in understanding communication, and screening for communication-related cognition issues will allow providers to recommend therapy or rehabilitation. The adopted rules provide that cognitive processes affecting communication function may be screened for under communication screening.
Four-Year Rule Review Changes
The adopted rules implement select changes from Department staff as a result of the four-year rule review conducted under Government Code §2001.039. The Department conducted the required four-year review of the rules under 16 TAC Chapter 111, and the Commission readopted the rule chapter in its entirety and in its current form. (Proposed Rule Reviews, 45 TexReg 7281, October 9, 2020. Adopted Rule Reviews, 46 TexReg 2050, March 26, 2021). In response to the Notice of Intent to Review that was published, the Department received public comments regarding 16 TAC Chapter 111, but none of those public comments affect these adopted rules.
The adopted rules include select changes from Department staff based on the Department's review of the rules during the rule review process. These changes include clarification and clean-up changes to existing rules and updates to statute and rule citations.
Technical Corrections
The adopted rules make technical corrections from two previous rulemakings: the emergency telehealth rules (Emergency Rules, 46 TexReg 5313, August 27, 2021) and the comprehensive telehealth rules (Proposed Rules, 46 TexReg 5698, September 10, 2021. Adopted Rules, 46 TexReg 9021, December 24, 2021). In the previous rulemakings, the "in-person" supervision requirement was removed throughout the rules package in multiple rules (both rulemakings); the definitions of "direct supervision" and "indirect supervision" were amended (both rulemakings); and a new definition of "tele-supervision" was added that replaced former language regarding supervision through telehealth or telepractice/telehealth (comprehensive rulemaking). The preambles for those rules explained that the rules allow for direct and indirect supervision to be performed through tele-supervision and that in-person supervision is not required.
The previous rulemakings amended §111.50(e) regarding supervision of speech-language pathology assistants, and the preambles stated: "Subsection (e) is amended to allow supervision to be performed through tele-supervision and not require in-person supervision." The "in-person" reference was removed from the introduction paragraph of §111.50(e), but inadvertently was not removed from paragraphs (e)(4) and (e)(6). The adopted rules make technical corrections to remove the remaining "in-person" references under §111.50(e).
SECTION-BY-SECTION SUMMARY
Subchapter A. General Provisions.
The adopted rules amend §111.1. Authority and Applicability. The adopted rules change the name of the section from "Authority" to "Authority and Applicability." The adopted rules amend subsection (a) to identify the other statutes that are implemented by the rules in Chapter 111. The adopted rules also add new subsection (b) to explain that the Chapters 60 and 100 rules also apply to the Speech-Language Pathologists and Audiologists program. This new provision replaces the rules under Subchapter O, §111.140, Rules, which are being repealed.
Subchapter C. Examinations.
The adopted rules amend §111.23, License Examination--Jurisprudence Examinations. The adopted rules change the name of the section from "License Examination--Jurisprudence Examination" to "License Examination--Jurisprudence Examinations." The adopted rules amend subsection (a) to recognize that there are two separate jurisprudence exams - one for speech-language pathology and another for audiology; and amend subsection (b) to update the reference to examinations. The adopted rules also create separate provisions for the speech-language pathology jurisprudence examination and the audiology jurisprudence examination. The general provision under subsection (c) has been amended to apply only to the speech-language pathology jurisprudence examination, and a separate provision for the audiology jurisprudence examination has been added as new subsection (d). There are no substantive changes to these provisions.
Subchapter F. Requirements for Assistant in Speech-Language Pathology License.
The adopted rules amend §111.50, Assistant in Speech-Language Pathology License--Licensing Requirements--Education and Clinical Observation and Experience. The adopted rules make technical corrections to §111.50(e) from two previous rulemakings as discussed above. Under subsection (e), the adopted rules remove the "in-person" references under paragraphs (e)(4) and (e)(6).
Subchapter O. Responsibilities of the Commission and the Department.
The adopted rules repeal Subchapter O, Responsibilities of the Commission and the Department, and §111.140, Rules. These explanatory provisions are no longer necessary, since sufficient time has passed since the program was transferred to the Department. New provisions regarding the applicability of the rules under Chapters 60 and 100 have been included in the changes to §111.1, Authority and Applicability. The rules under Chapters 60 and 100 have broader applicability than the specific provisions cited in §111.140.
Subchapter P. Responsibilities of the Licensee and Code of Ethics.
The adopted rules amend §111.150, Changes of Name, Address, or Other Information. The adopted rules update subsection (a) to provide that a licensee notify the Department of any changes to the specified information in a form and manner prescribed by the Department.
The adopted rules amend §111.151, Consumer Information, Display of License, and Proof of Licensure. The adopted rules reflect the recommendations from the Speech-Language Pathologists and Audiologists Advisory Board with input from its Licensing Workgroup as discussed above. The adopted rules change the name of the section from "Consumer Information and Display of License" to "Consumer Information, Display of License, and Proof of Licensure." The adopted rules add a new subsection (e), which requires a licensee, upon request, to provide proof of licensure to a client by showing the current license certificate, the current license identification card, or the current results of a license search on the Department's website.
The adopted rules amend §111.155, Standards of Ethical Practice (Code of Ethics). The adopted rules update the statutory citation in subsection (a)(16).
Subchapter Q. Fees.
The adopted rules amend §111.160, Fees. The adopted rules update the cross-referenced fee provisions in subsections (k) - (m) to use updated, standardized fee language.
Subchapter T. Screening Procedures.
The adopted rules amend §111.190, Communication Screening. The adopted rules reflect the recommendations from the Speech-Language Pathologists and Audiologists Advisory Board with input from its Standard of Care Workgroup as discussed above. The adopted rules amend subsection (a) to clarify that individuals licensed under the Act may conduct communication screenings. In addition, the adopted rules amend subsection (b) to provide that communication screenings may include cursory assessments of cognition to determine if further testing is indicated, and to provide that the aspects of cognition to be screened are any cognitive processes affecting communication function. Finally, the adopted rules amend subsection (c) to provide that cognition screenings should be conducted in the client's dominant language and primary mode of communication.
The adopted rules amend §111.192, Newborn Hearing Screening. The adopted rules update the rule citation in subsection (b) to reflect the Health and Human Services Commission's transfer of the rules related to Early Childhood Intervention Services to a new rule chapter in the Texas Administrative Code (TAC).
PUBLIC COMMENTS
The Department drafted and distributed the proposed rules to persons internal and external to the agency. The proposed rules were published in the December 22, 2023, issue of the Texas Register (48 TexReg 7727). The public comment period closed on January 25, 2024. The Department received comments from one interested party on the proposed rules. The public comment is summarized below.
Comment: The Department received a comment from the Texas Academy of Audiology (TAA) in support of the proposed rules. First, TAA agreed with the rule change regarding providing proof of licensure through a licensure search option, which could reduce administrative burdens and delays. Second, TAA agreed with the proposed changes "to add cognition screenings as part of a holistic communication evaluation" and stated that the proposed rule is in alignment with existing language that allows for certain screenings. TAA noted that these screenings "are distinct from medical evaluations for and subsequent diagnosis of cognitive disorders, which remains firmly within the scope of licensed physicians, preferably neurologists." TAA hoped that the Department would monitor how the cognition screening tools are used and the marketing materials that are used. Third, TAA agreed with the clarification and clean-up changes from the four-year rule review. Finally, TAA appreciated the clarification removing the "in-person" supervision references and noted that this change reflects the "clinical realities of telehealth."
Department Response: The Department appreciates the TAA comment in support of the proposed rules. The Department agrees with TAA's statement that the communication screening is not a medical evaluation or diagnosis. Regarding monitoring the use of the screening tools and the marketing materials, while the Department is not in a position to monitor the screenings provided, Rule 111.155, Standards of Ethical Practice (Code of Ethics), specifies the requirements and the prohibitions regarding a licensee's practice, and Rule 111.152, Advertising, prohibits a licensee from presenting false, misleading, deceptive, or non-verifiable information relating to the services of the licensee. The Department will be able to identify issues if complaints are filed with the Department. The Department did not make any changes to the proposed rules in response to this public comment.
ADVISORY BOARD RECOMMENDATIONS AND COMMISSION ACTION
The Speech-Language Pathologists and Audiologists Advisory Board met on February 26, 2024, to discuss the proposed rules and the public comments received. The Advisory Board recommended that the Commission adopt the proposed rules as published in the Texas Register. At its meeting on April 12, 2024, the Commission adopted the proposed rules as recommended by the Advisory Board.
SUBCHAPTER A. GENERAL PROVISIONS
STATUTORY AUTHORITY
The adopted rules are adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement that chapter and any other law establishing a program regulated by the Department. The adopted rules are also adopted under Texas Occupations Code, Chapter 401, Speech-Language Pathologists and Audiologists.
The statutory provisions affected by the adopted rules are those set forth in Texas Occupations Code, Chapters 51 and 401. No other statutes, articles, or codes are affected by the adopted rules.
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 April 26, 2024.
TRD-202401812
Doug Jennings
General Counsel
Texas Department of Licensing and Regulation
Effective date: May 16, 2024
Proposal publication date: December 22, 2023
For further information, please call: (512) 475-4879
STATUTORY AUTHORITY
The adopted rules are adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department’s governing body, to adopt rules as necessary to implement that chapter and any other law establishing a program regulated by the Department. The adopted rules are also adopted under Texas Occupations Code, Chapter 401, Speech-Language Pathologists and Audiologists.
The statutory provisions affected by the adopted rules are those set forth in Texas Occupations Code, Chapters 51 and 401. No other statutes, articles, or codes are affected by the adopted rules.
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 April 26, 2024.
TRD-202401813
Doug Jennings
General Counsel
Texas Department of Licensing and Regulation
Effective date: May 16, 2024
Proposal publication date: December 22, 2023
For further information, please call: (512) 475-4879
STATUTORY AUTHORITY
The adopted rules are adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement that chapter and any other law establishing a program regulated by the Department. The adopted rules are also adopted under Texas Occupations Code, Chapter 401, Speech-Language Pathologists and Audiologists.
The statutory provisions affected by the adopted rules are those set forth in Texas Occupations Code, Chapters 51 and 401. No other statutes, articles, or codes are affected by the adopted rules.
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 April 26, 2024.
TRD-202401814
Doug Jennings
General Counsel
Texas Department of Licensing and Regulation
Effective date: May 16, 2024
Proposal publication date: December 22, 2023
For further information, please call: (512) 475-4879
STATUTORY AUTHORITY
The adopted repeal is adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department’s governing body, to adopt rules as necessary to implement that chapter and any other law establishing a program regulated by the Department. The adopted repeal is also adopted under Texas Occupations Code, Chapter 401, Speech-Language Pathologists and Audiologists.
The statutory provisions affected by the adopted repeal are those set forth in Texas Occupations Code, Chapters 51 and 401. No other statutes, articles, or codes are affected by the adopted repeal.
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 April 26, 2024.
TRD-202401818
Doug Jennings
General Counsel
Texas Department of Licensing and Regulation
Effective date: May 16, 2024
Proposal publication date: December 22, 2023
For further information, please call: (512) 475-4879
16 TAC §§111.150, 111.151, 111.155
STATUTORY AUTHORITY
The adopted rules are adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department’s governing body, to adopt rules as necessary to implement that chapter and any other law establishing a program regulated by the Department. The adopted rules are also adopted under Texas Occupations Code, Chapter 401, Speech-Language Pathologists and Audiologists.
The statutory provisions affected by the adopted rules are those set forth in Texas Occupations Code, Chapters 51 and 401. No other statutes, articles, or codes are affected by the adopted rules.
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 April 26, 2024.
TRD-202401815
Doug Jennings
General Counsel
Texas Department of Licensing and Regulation
Effective date: May 16, 2024
Proposal publication date: December 22, 2023
For further information, please call: (512) 475-4879
STATUTORY AUTHORITY
The adopted rules are adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department’s governing body, to adopt rules as necessary to implement that chapter and any other law establishing a program regulated by the Department. The adopted rules are also adopted under Texas Occupations Code, Chapter 401, Speech-Language Pathologists and Audiologists.
The statutory provisions affected by the adopted rules are those set forth in Texas Occupations Code, Chapters 51 and 401. No other statutes, articles, or codes are affected by the adopted rules.
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 April 26, 2024.
TRD-202401816
Doug Jennings
General Counsel
Texas Department of Licensing and Regulation
Effective date: May 16, 2024
Proposal publication date: December 22, 2023
For further information, please call: (512) 475-4879
STATUTORY AUTHORITY
The adopted rules are adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department’s governing body, to adopt rules as necessary to implement that chapter and any other law establishing a program regulated by the Department. The adopted rules are also adopted under Texas Occupations Code, Chapter 401, Speech-Language Pathologists and Audiologists.
The statutory provisions affected by the adopted rules are those set forth in Texas Occupations Code, Chapters 51 and 401. No other statutes, articles, or codes are affected by the adopted rules.
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 April 26, 2024.
TRD-202401817
Doug Jennings
General Counsel
Texas Department of Licensing and Regulation
Effective date: May 16, 2024
Proposal publication date: December 22, 2023
For further information, please call: (512) 475-4879