TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 3. OIL AND GAS DIVISION

The Railroad Commission of Texas proposes amendments to §3.15, and §3.58, relating to Surface Equipment Removal Requirements and Inactive Wells; and Certificate of Compliance and Transportation Authority. The Commission proposes the amendments to implement Senate Bill 1150, 89th Texas Legislature (Regular Session, 2025). The bill amends Texas Natural Resources Code §89.023 to require operators to plug wells that have been inactive for more than 15 years, and completed more than 25 years prior to the operator submits an application for a plugging extension ("15/25 wells"), unless the Commission finds that granting a plugging extension is warranted based on: (1) the operator's prior history of restoring inactive wells to active operation; (2) the operator's financial hardship in complying with its duty to plug 15/25 wells; (3) the operator includes the inactive well in a compliance plan that addresses the inactive well before September 1, 2042; or (4) the operator files an individual performance bond not less than the full cost calculation for plugging an inactive well that runs with and covers the lifetime of the well. The bill also requires the Commission to adopt rules requiring operators involved in the transfer of an inactive well to jointly submit a transfer application, confirming that the well is in compliance, the transfer was a business practice performed in good faith, and that the new operator will ensure continued compliance. Additionally, SB 1150 prevents plugging extensions based on an operator's prior history of restoring inactive wells to active operation, or an operator's financial hardship, from transferring with the inactive well.

The bill also adds new Texas Natural Resources Code §§89.049, 89.050, and 89.051, requiring the Commission to produce and deliver to the Governor, Lieutenant Governor, and Legislature, an annual report that includes: (1) the number of inactive wells in the state; (2) the age and length of inactivity of each inactive well; (3) the number of inactive wells for which an plugging extension has been granted; (4) the financial assurance methods available for inactive wells, and the number of wells using each available financial assurance method; (5) the number of wells that were plugged in the preceding year, both by operators and by the Commission with state funds; (6) the number of inactive wells restored to active operation in the preceding year; (7) a summary of the number of operators of inactive wells, including the total number of operators and wells that are in compliance, are delinquent, have been delinquent for over a year, or have been granted a plugging extension; (8) the number of organization reports that the Commission has not renewed or approved, including the operator's total well count and total amount of financial assurance; and, (9) the annual cost calculation for plugging an inactive well. §89.050 requires an operator whose inactive well was completed at least 15 years ago to submit an annual report to the Commission containing the results of a fluid level or hydraulic pressure test for the inactive well. Lastly, §89.051 grants the Commission the power to adopt any necessary rules to regulate and monitor inactive wells, while considering the risk to public safety or the environment, the wellbore and wellhead integrity, and regional risk considerations.

The Commission proposes amendments in §3.15(a)(1) and §3.15(a)(6) to add definitions for "15/25 well" and "full cost calculation for plugging an inactive well." Current subsections (a)(1)-(4) are redesignated as subsections (a)(2)-(5), and current subsections (a)(5)-(8) are redesignated as (a)(7)-(a)(10), as a result of these proposed amendments.

The Commission proposes amendments throughout §3.15, beginning in §3.15(c)(4), to require operators to perform fluid level tests or hydraulic pressure tests on inactive wells that were completed at least 15 years ago. This amendment is also proposed in §3.15(e)(5), 3.15(n), 3.15(n)(3), 3.15(n)(7), 3.15(o), 3.15(o)(4), and 3.15(o)(7).

The Commission also proposes amendments in §3.15(e)(1) to add references to documentation that is submitted under subsection (f) or new subsection (h).

The Commission proposes amendments in §§3.15(f) and 3.15(g) to acknowledge that the current plugging extensions are only available for inactive land wells that are not 15/25 wells.

Proposed new §3.15(h) specifies the application process for a plugging extension for a 15/25 well. Under new subsection (h)(1)-(3), all applications for plugging extensions for 15/25 wells: (1) only apply to inactive land wells, not bay or offshore wells; (2) only valid for one year, renewable concurrently with the operator's organization report; and (3) require documentation identifying nonoperators, as that term is defined by Texas Natural Resources Code §89.002(3). Proposed new subsection (h)(3), regarding the identification of nonoperators, specifies that the operator must use good faith and reasonable efforts in identifying nonoperators, which entails examining Commission filings, current county tax rolls, and other reliable and readily available sources of information.

Proposed new §3.15(h)(4) addresses how the operator may apply for each of the four available plugging extensions for 15/25 wells. SB 1150 authorized four different types of plugging extensions that the operator may apply for, and the Commission may approve. The details of each plugging extension application are proposed in subsection (h)(4)(A)-(D). These plugging extension application options include: (A) a written request that the Commission, by order, determine that the operator's history of restoring inactive wells to active operation warrants the approval of its 15/25 well plugging extension application; (B) a written request that the Commission, by order, determine that the operator's financial hardship warrants the approval of its 15/25 well plugging extension; (C) a compliance plan that identifies the inactive well and sets forth the operator's commitment to plugging or restoring the 15/25 well to active operation by the statutory deadline of September 1, 2042; and (D) an individual performance bond that is greater than or equal to the full cost calculation of plugging the 15/25 well, and runs with and covers the lifetime of the inactive well.

Application based on the operator's prior history of restoring inactive wells to active operation.

The proposed new amendments regarding what is required in an application for a 15/25 well plugging extension based on the operator's prior history of restoring inactive wells are in new §3.15(h)(4)(A)(i)-(v). Under the new proposed clauses for the "prior history" plugging extension, the operator would be required to include documentation that identifies: (i) all of the operator's wells; (ii) the active or inactive status of each well; (iii) the length of inactivity of each inactive well; (iv) the date an inactive well was restored to active operation, if it has been restored; and (v) all Commission assigned permit numbers, oil and gas lease numbers, API well numbers, and production report filing dates for each active well that was previously inactive.

Application based on the operator's financial hardship.

Proposed new subsection (h)(4)(B)(i)-(iv) details the requirements for an application for a 15/25 well plugging extension based on the operator's financial hardship. These proposed rules require an operator's application to include: (i) sworn financial statements, certified by a certified public accountant, containing financial information for at least the three fiscal years prior to the operator's organization report renewal date; (ii) an attestation signed by the operator or its representative, confirming that its financial hardship warrants a plugging extension; (iii) objective evidence demonstrating a reasonable basis and justification for the approval of its plugging extension application; and (iv) any other relevant information the Commission may consider in reviewing its plugging extension application. The proposed rule language for "any other relevant information" references Texas Natural Resources Code §89.023(e), which defines what the Commission may consider in deciding whether to grant an operator's plugging extension application based on financial hardship.

The Commission proposes new subsection (h)(4)(B)(iii)(I)-(III) to provide examples of what information may demonstrate a reasonable basis and provide justification for granting a plugging extension application based on the operator's financial hardship. The examples include additional costs: (I) specific to the wellbore's construction; (II) relating to road construction, brush clearing, or other actions necessary to access the inactive well site; and (III) relating to the inactive well's location, including subsurface factors.

The Commission also proposes new subsection (h)(4)(B)(iv)(I)-(V), providing the operator with an opportunity to supply information relevant to what the Commission may consider in deciding whether to grant an operator's plugging extension application based on financial hardship. Referencing Texas Natural Resources Code §89.023(e), this information includes: (I) the operator's prior investment in plugging or maintenance of wells; (II) the operator's history of compliance or noncompliance; (III) the current economic conditions; (IV) the percentage of the operator's total well count that are inactive wells; and (V) any additional information the operator believes is relevant and would like the Commission to consider with its application.

Application based on the operator's creation of a compliance plan.

The Commission proposes new subsection (h)(4)(C), allowing operators to apply for a plugging extension for a 15/25 well if it is included in a compliance plan in which the operator commits to plugging or restoring the well to active operation by September 1, 2042, as required by statute. The proposed rules in subsection (h)(4)(C)(i)(I)-(VI) describe what the compliance plan must include: (I) the age and length of inactivity for each well included in the compliance plan; (II) the operator's total well count, denoting how many are active and inactive; (III) a schedule that specifies how many wells will be plugged or restored to active operation annually, in an amount that is not less than the operator would need to plug or restore to active operation each year to achieve compliance by the statutory deadline, September 1, 2042; (IV) the wells the operator has plugged or restored to active operation in the last P-5 organization report renewal period; (V) the full cost calculation of plugging or restoring to active operation for all the wells included in the compliance plan; and (VI) an attestation confirming the operator's ability to adhere to its compliance plan.

The Commission also proposes new subsection (h)(4)(C)(ii)(I)-(III) to grant operators the opportunity to include other information in its compliance plan that the Commission will consider in deciding whether to approve the compliance plan and plugging extensions for the included 15/25 wells. This information may relate to: (I) the current economic conditions; (II) the operator's record of compliance or noncompliance; (III) any additional financial assurance the operator has submitted under Texas Natural Resources Code §§89.023(a)(3) or 89.027.

The Commission also proposes new subsection (h)(4)(C)(iii) to require operators with an approved compliance plan and plugging extension to annually provide the Commission with the status of every inactive well in the approved compliance plan with its annual operator report, and the plugging extension status of all other 15/25 wells that are not included in the compliance plan.

Application based on an individual performance bond

The Commission proposes new subsection (h)(4)(D) allowing operators to obtain a plugging extension for a 15/25 well if the operator files with the Commission an individual performance bond that is equal to at least the full cost calculation for plugging the inactive well.

The Commission proposes new §3.15(i) to describe the actions the Commission may take on each type of plugging extension application for a 15/25 well. In the proposed new subsection (i)(1), the Commission will notify the operator if the application for a plugging extension for a 15/25 well is complete or incomplete. If the application is incomplete, the operator will have 90 days to correct its application. Once the application is complete, the Commission will review the application and required documentation, and approve the plugging extension, if warranted. Proposed subsection (i)(1)(A)-(D) describes the criteria that may signify whether approval is warranted or not.

Commission action on an application based on the operator's prior history in restoring inactive wells to active operation.

The Commission proposes new subsection (i)(1)(A)(i)-(ii) to set forth the criteria for when approval would be warranted for an application that is based on the operator's prior history in restoring inactive wells to active operation. Under subsection (i)(1)(A)(i), the Commission proposes that operators with less than 10 inactive wells warrant approval of their plugging extensions if they have restored at least one well to active operation in the preceding year. For operators with more than 10 inactive wells, the Commission proposes new subsection (i)(1)(A)(ii). Approval would be warranted if the operator has restored at least ten percent of its total inactive well population to active operation, in the preceding year.

Commission action on an application based on the operator's financial hardship.

Proposed new subsection (i)(1)(B), sets forth criteria for approval of a plugging extension based on the operator's financial hardship. The criteria are listed in proposed new subsection (i)(1)(B)(i)-(v). Approval would be warranted if: (i) the difference between the operator's total annual revenue, and the full cost calculation for plugging all of its 15/25 wells, is negative; (ii) the difference between the operator's total assets, and the operator's full cost calculation for plugging all its 15/25 wells is negative; (iii) the difference in the operator's earnings before interest, taxes, depreciation and amortization, and one-fifteenth of the full cost calculation for plugging all of its 15/25 wells, is negative; (iv) paying one-fifteenth of the full cost calculation for plugging all of its 15/25 wells would result in the operator seeking bankruptcy relief; or (v) paying one-fifteenth of the full cost calculation for plugging all of its 15/25 wells would cause the operator to default on one or more of its material debt obligations.

Commission action on an application based on the operator's creation of a compliance plan.

Proposed new subsection (i)(1)(C) sets forth criteria for approval of a compliance plan, and thus the plugging extension for an included 15/25 well. The criteria are listed in proposed new subsection (i)(1)(C)(i)-(v). Approval would be warranted if the compliance plan: (i) specifies a number of wells to be plugged or restored to active operation that will enable the operator to achieve compliance for all of its 15/25 wells by the statutory deadline, September 1, 2042; (ii) the number of wells to be plugged or restored to active operation each year is not less than the amount the operator would need to achieve compliance by the statutory deadline; (iii) the minimum amount of 15/25 wells an operator will plug or restore to active operation each year is not less than the total amount of 15/25 wells, divided by the remaining number of years until the statutory deadline; (iv) each year, the operator reasonably prioritizes the 15/25 wells to be plugged or restored to active operation based on the age and length of inactivity of the inactive well, and any potential hazards to public health and safety or the environment of the inactive well; and (v) if renewing a compliance plan, whether the operator has plugged above the minimum number of wells required by clause (iii).

Commission action on an application based on a performance bond.

Proposed new subsection (i)(1)(D) sets forth criteria that if met would warrant approval of a plugging extension based on an operator's performance bond. The criteria are listed in proposed new subsection (i)(1)(D)(i)-(iii). If the operator provides a performance bond with its application for plugging extensions for a 15/25 well, approval is warranted if it meets the following criteria: (i) it is an amount equal to the full cost calculation for plugging the 15/25 well; (ii) it runs with and covers the lifetime of the well, regardless of a change of operator; and (iii) it is issued by a third-party bank authorized to do business in Texas.

Proposed new subsection (i)(2) provides that the Commission may deny an application for a plugging extension for a 15/25 well if approval is not warranted, but shall deny under any of the factors listed in subsection (i)(2)(A)-(G). In subparagraph (A), the Commission proposes to deny an application if a nonoperator of the well is an entity or individual who was a previous P-5 operator of the 15/25 well, and is currently barred from being on an organization report under Texas Natural Resources Code §91.114(2). In subparagraph (B), the Commission proposes to deny an application for a plugging extension of a 15/25 well if the operator has been penalized for falsely filing documents with the Commission, under Texas Natural Resources Code §91.143. In subparagraph (C), the Commission proposes to deny a plugging extension application for a 15/25 well if the well poses potential hazards to the health and safety of the public or the environment. In subparagraph (D), the Commission proposes to deny an application for a plugging extension for a 15/25 well based on the operator's financial hardship, if the operator's financial hardship is due to the operator's fault or negligence. In subparagraph (E), the Commission proposes to deny an application for a plugging extension for a 15/25 well if the operator has been previously penalized for a violation that was a safety or pollution-related violation that caused a significant impact to public safety or the environment, was accompanied by conditions that indicated a significant impact to public safety or the environment was imminent, or was the result of deliberate disregard of Commission rules and regulations related to public safety or environmental protection. In subparagraph (F), the Commission proposes to deny an application for a plugging extension for a 15/25 well if the operator is renewing its compliance plan, and the operator, in bad faith, deviated from the previous year's approved compliance plan. In subparagraph (G), the Commission proposes to deny an application for a plugging extension for a 15/25 well if the performance bond is not issued by a bank authorized to do business in Texas.

Proposed new subsection (i)(3) states the Commission will notify an operator when an application for a plugging extension for a 15/25 well is denied and will provide an opportunity for hearing to challenge the denial. The operator will have 30 days to request a hearing from the date of the denial letter and the burden of proof will be on the party requesting the hearing.

Current subsections (h)-(k) are redesignated as subsections (j)-(m) with no other proposed changes.

The Commission proposes to redesignate current subsection (l) as subsection (n). Proposed amendments to §3.15(n)(3) and (n)(6) specify that, although a hydraulic pressure test, if approved by the Commission, is still valid for up to five years, the operator must provide the test results annually to the Commission in accordance with Texas Natural Resources Code §89.050.

Current subsections (m)-(p) are redesignated as subsections (o)-(r) with no other proposed changes, except those previously discussed.

Proposed new §3.58(a)(5) codifies SB 1150's amendments to the transfer rules for inactive wells. Proposed subsection (a)(5) requires a transfer of an inactive well to be filed on a Commission form signed by both operators involved in the transfer. New subsection (a)(5)(A)-(C) requires that the operators confirm that the well is currently in compliance, the transfer was done in good faith, and the receiving operator will ensure continued compliance.

Proposed new subsection (a)(6) confirms that a plugging extension based on the operator's prior history in restoring inactive wells to active operation, or the operator's financial hardship, is not transferable.

David Lindley, Director, Oil and Gas Division, has determined there will be costs to the Commission as a result of the enrollment of SB 1150, which required these amendments. At the time of proposal, no funds have been appropriated from the General Revenue Fund to the Commission to implement SB 1150. Based on the fiscal analysis provided to the Legislature during the 89th Legislative Session, to implement SB 1150 and these amendments, Mr. Lindley expects the additional costs to the Commission to total $6,036,855 in year 1 after the effective date, $4,883,756 in year 2, $14,884,216 in year 3, $10,980,356 in year 4, and $10,541,996 in year 5. These cost estimates are based on the Commission's need to implement new technology systems, hire information technology personnel and contractors, hire and retain 86 full-time employees, purchase additional motor vehicles, equipment, and other administrative and operating expenses. Mr. Lindley has determined that for the first five years the amendments will be in effect, there will be no fiscal implications for local governments as a result of enforcing the amendments.

Mr. Lindley has also determined that the public benefit anticipated as a result of enforcing or administering the amendments will be a reduction in the amount of wells that remain inactive indefinitely, and ultimately placed on the orphaned well list, becoming the responsibility of the Commission to plug, and financial burden of Texas.

Mr. Lindley has determined that for each year of the first five years that the amendments will be in effect, there will be no additional economic costs for persons required to comply as a result of Commission adoption of the proposed amendments. Should an operator choose to apply for a plugging extension for 15/25 wells that SB 1150 has created, and these amendments have implemented, the operator may have additional costs to create a compliance plan, financial statements, or filing a performance bond for the full cost calculation of plugging the 15/25 well; however, these plugging extensions are options available to the operator. They are not obligatory costs. An operator's duty to plug inactive wells has not changed because of these amendments, and thus, the amendments do not cause additional economic costs to regulated persons.

In accordance with Texas Government Code §2006.002, the Commission has determined there will be no adverse economic effect on rural communities, small businesses or micro-businesses resulting from the proposed amendments; therefore, the Commission has not prepared the economic impact statement or the regulatory flexibility analysis required under §2006.002. To the contrary, these rules may have a positive economic effect on rural communities, small businesses, or micro-businesses, as SB 1150 and these amendments intent is to decrease the number of inactive wells, and ultimately, the number of orphaned wells, which should increase economic opportunity via growth in the well plugging industry, and potentially increased property values as a result of a decrease in inactive wells and orphaned wells.

The Commission has determined that the proposed rulemaking will not affect a local economy; therefore, pursuant to Texas Government Code §2001.022, the Commission is not required to prepare a local employment impact statement for the proposed rule.

The Commission has determined that the proposed amendments do not meet the statutory definition of a major environmental rule as set forth in Texas Government Code §2001.0225; therefore, a regulatory analysis conducted pursuant to that section is not required.

During the first five years that the rules would be in effect, the proposed amendments would not: create or eliminate a government program; create or eliminate any employee positions; require an increase or decrease in future legislative appropriations; increase fees paid to the agency; create a new regulation; increase or decrease the number of individuals subject to the rule's applicability; expand, limit, or repeal an existing regulation; or affect the state's economy.

Comments on the proposal may be submitted to Rules Coordinator, Office of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711-2967; online at www.rrc.texas.gov/general-counsel/rules/comment-form-for-proposed-rulemakings; or by electronic mail to rulescoordinator@rrc.texas.gov. The Commission will accept comments until 5:00 p.m., on Friday, November 13, 2026. The Commission finds that this comment period is reasonable because the proposal and an online comment form will be available on the Commission's web site more than two weeks prior to Texas Register publication of the proposal, giving interested persons additional time to review, analyze, draft, and submit comments. The Commission encourages all interested persons to submit comments no later than the deadline. The Commission cannot guarantee that comments submitted after the deadline will be considered. For further information, call Mr. Lindley at (512) 463-6217. The status of Commission rulemakings in progress is available at www.rrc.texas.gov/general-counsel/rules/proposed-rules. Once received, all comments are posted on the Commission's website at https://rrc.texas.gov/general-counsel/rules/proposed-rules/. If you submit a comment and do not see the comment posted at this link within three business days of submittal, please call the Office of General Counsel at (512) 463-7149. The Commission has safeguards to prevent emailed comments from getting lost; however, your operating system's or email server's settings may delay or prevent receipt.

The Commission proposes the amendments under Texas Natural Resources Code §81.051 and §81.052, which provide the Commission with jurisdiction over all persons owning or engaged in drilling or operating oil or gas wells in Texas and the authority to adopt all necessary rules for governing and regulating persons and their operations under Commission jurisdiction; Texas Natural Resources Code §§85.042, 85.202, 86.041 and 86.042, which require the Commission to adopt rules to control waste of oil and gas; Texas Natural Resources Code §89.023, which authorizes the Commission to adopt rules relating to plugging extensions; Texas Natural Resources Code §89.051, which requires the Commission to adopt rules necessary to regulate and monitor inactive wells.

Statutory authority: Texas Natural Resources Code §§81.051, 81.052, 85.042, 85.202, 86.041, 86.042, 89.023, 89.050, 89.051.

Cross-reference to statute: Texas Natural Resources Code, Chapter 81, 85, 86, and 89.

§3.15. Surface Equipment Removal Requirements and Inactive Wells.

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

(2) [(1)] Active operation--Regular and continuing activities related to the production of oil and gas for which the operator has all necessary permits. In the case of a well that has been inactive for 12 consecutive months or longer and that is not permitted as a disposal or injection well, the well remains inactive for purposes of this section, regardless of any minimal activity, until the well has reported production of at least five barrels of oil for oil wells or 50 Mcf of gas for gas wells each month for at least three consecutive months, or until the well has reported production of at least one barrel of oil for oil wells or at least one Mcf of gas for gas wells each month for 12 consecutive months.

(3) [(2)] Cost calculation for plugging an inactive well--The cost, calculated by the Commission or its delegate, for each foot of well depth plugged based on average actual plugging costs for wells plugged by the Commission for the preceding state fiscal year for the Commission Oil and Gas Division district in which the inactive well is located.

(4) [(3)] Delinquent inactive well--An inactive well for which, after notice and opportunity for a hearing, the Commission or its delegate has not extended the plugging deadline.

(5) [(4)] Enhanced oil recovery (EOR) project--A project that does not include a water disposal project and is:

(A) a Commission-approved EOR project that uses any process for the displacement of oil or other hydrocarbons from a reservoir other than primary recovery and includes the use of an immiscible, miscible, chemical, thermal, or biological process;

(B) a certified project described by Texas Tax Code, §202.054; or

(C) any other project approved by the Commission or its delegate for EOR.

(7) [(5)] Good faith claim--A factually supported claim based on a recognized legal theory to a continuing possessory right in a mineral estate, such as evidence of a currently valid oil and gas lease or a recorded deed conveying a fee interest in the mineral estate.

(8) [(6)] Inactive well--An unplugged well that has been spudded or has been equipped with cemented casing and that has had no reported production, disposal, injection, or other permitted activity for a period of greater than 12 months.

(9) [(7)] Operator designation form--A certificate of compliance and transportation authority or an application to drill, recomplete, and reenter that has been approved by the Commission or its delegate.

(10) [(8)] Physical termination of electric service to the well's production site--Disconnection of the electric service to an inactive well site at a point on the electric service lines most distant from the production site toward the main supply line in a manner that will not interfere with electrical supply to adjacent operations, including cathodic protection units.

(b) (No change.)

(c) Extension of deadline for plugging an inactive bay or offshore well. The Commission or its delegate may administratively grant an extension of the deadline for plugging an inactive bay or offshore well as defined by Commission rules if:

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

(4) for a well more than 15 [25] years old, the operator successfully conducts and the Commission or its delegate approves a fluid level or hydraulic pressure test establishing that the well does not pose a potential threat of harm to natural resources, including surface and subsurface water, oil, and gas.

(d) (No change.)

(e) Extension of deadline for plugging an inactive land well. The Commission or its delegate may administratively grant an extension of the deadline for plugging an inactive land well if:

(1) the Commission or its delegate approves the operator's Application for an Extension of Deadline for Plugging an Inactive Well (Commission Form W-3X), including any documentation submitted under subsections (f) or (h) of this section;

(2) - (4) (No change.)

(5) for a well more than 15 [25] years old, the operator successfully conducts and the Commission or its delegate approves a fluid level or hydraulic pressure test establishing that the well does not pose a potential threat of harm to natural resources, including surface and subsurface water, oil, and gas.

(f) Application for an extension of deadline for plugging an inactive land well that is not a 15/25 well.

(1) - (2) (No change.)

(g) Commission action on application for plugging extension for an inactive land well that is not a 15/25 well.

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

(j) [(h)] Revocation of extension. The Commission or its delegate may revoke an extension of the deadline for plugging an inactive well if the Commission or its delegate determines, after notice and an opportunity for a hearing, that the applicant is ineligible for the extension under the Commission's rules or orders.

(k) [(i)] Removal of surface equipment for land wells inactive more than 10 years. Requirements to remove surface equipment for land wells inactive more than 10 years do not excuse an operator from compliance with all other applicable Commission rules and orders including the requirements in Chapter 4 of this title (relating to Environmental Protection).

(1) An operator of an inactive land well must leave a clearly visible sign as required by §3.3 of this title (relating to Identification of Properties, Wells, and Tanks) at the wellhead of the well and must maintain wellhead control as required by §3.13 of this title (relating to Casing, Cementing, Drilling, and Completion Requirements).

(2) An operator may not store surface equipment removed from an inactive land well on an active lease.

(3) An operator may be eligible for a temporary extension of the deadline for plugging an inactive land well or a temporary exemption from the surface equipment removal requirements if the operator is unable to comply with the requirements of subsection (f)(2)(A) of this section because of safety concerns or required maintenance of the well site and the operator includes with the application a written affirmation of the facts regarding the safety concerns or maintenance.

(4) An operator may be eligible for an extension of the deadline for plugging a well without complying with the surface equipment removal requirements for inactive land wells if the well is located on a unit or lease or in a field associated with an EOR project and the operator includes a statement in the written affirmation that the well is part of such a project. The exemption provided by this subsection applies only to the equipment associated with current and future operations of the project.

(l) [(j)] Abeyance of plugging report.

(1) An operator that files an abeyance of plugging report must:

(A) pay an annual fee of $100 for each inactive land well covered by the report;

(B) use Commission Form W-3X on which the operator must specify the field and the covered wells within that field; and

(C) for each well, include a certification signed and sealed by a person licensed by the Texas Board of Professional Engineers or the Texas Board of Professional Geoscientists stating that the well has:

(i) a reasonable expectation of economic value in excess of the cost of plugging the well for the duration of the period covered by the report, based on the cost calculation for plugging an inactive well;

(ii) a reasonable expectation of being restored to a beneficial use that will prevent waste of oil or gas resources that otherwise would not be produced if the well were plugged; and

(iii) documentation demonstrating the basis for the affirmation of the well's future utility.

(2) Except as provided in paragraph (3) of this subsection, the Commission or its delegate may not transfer an abeyance of plugging report to a new operator of an existing inactive land well. The new operator of an existing inactive land well must file a new abeyance of plugging report or otherwise comply with the requirements of this subchapter not later than six months after the date the Commission or its delegate approves the new operator's request to be recognized as the operator of the well.

(3) The Commission or its delegate may transfer an abeyance of plugging report in the event of a change of name of an operator.

(m) [(k)] Enhanced oil recovery (EOR) project.

(1) An inactive well is considered to be part of an EOR project if the well is located on a unit or lease or in a field associated with a Commission-approved EOR project.

(2) Except as provided in paragraph (3) of this subsection, the Commission and its delegate may not transfer a statement that an inactive well is part of an EOR project to a new operator of an existing inactive well. A new operator of an existing inactive well must file a new statement stating that the well is part of such an EOR project or otherwise comply with the provisions of this section not later than six months after the date the Commission or its delegate approves the new operator's request to be recognized as the operator of the well.

(3) The Commission or its delegate may transfer a statement that a well is part of an EOR project in the event of a change of name of an operator.

(n) [(l)] Fluid level or hydraulic pressure test for inactive wells more than 15 [25] years old.

(1) At least three days prior to the test, the operator must give the district office notice of the date and approximate time the operator intends to conduct a fluid level or hydraulic pressure test. The district office may require that a test be witnessed by a Commission employee. The district office may allow an operator to conduct a test even if notice of the test is provided to the district office fewer than three days prior to the test.

(2) No operator may conduct a test other than a fluid level or hydraulic pressure test without prior approval from the district director or the director's delegate.

(3) For each inactive well that is more than 15 [25] years old [and that has been inactive more than 10 years], the operator must perform either a fluid level test once every 12 months or a hydraulic pressure test once every five years and annually obtain the approval of the Commission or its delegate of the results of said tests.

(4) Notwithstanding the provisions of paragraph (1) of this subsection, an operator may conduct a hydraulic pressure test without prior approval from the district director or the director's delegate, provided that the operator gives the district office written notice of the date and approximate time for the test at least three days prior to the time the test will be conducted; the production casing is tested to a depth of at least 250 feet below the base of usable quality water strata or 100 feet below the top of cement behind the production casing, whichever is deeper; and the minimum test pressure is greater than or equal to 250 psig for a period of at least 30 minutes.

(5) Using Commission Form H-15, each operator must file in the Commission's Austin office the results of a successful fluid level test within 30 days of the date the test was performed. The results, if approved, are valid for a period of one year from the date of the test. Upon request by the Commission or its delegate, the operator must file the actual test data.

(6) Using Commission Form H-5 or Form H-15, each operator must file in the district office the results of a successful hydraulic pressure test, including the original pressure recording chart or its electronic equivalent, within 30 days of the date the test was performed. The results, if approved, are valid for a period of five years from the date of the test, unless the Commission or its delegate requires the operator to perform testing more frequently to ensure that the well does not pose a threat of harm to natural resources. Even if approved and valid for up to five years, the results shall be submitted annually to the Commission, in accordance with Texas Natural Resources Code section 89.050.

(7) An operator of an inactive well that is more than 15 [25] years old may not return that inactive well to active operation unless the operator performs either a successful fluid level test of the well within 12 months prior to the return to activity or a successful hydraulic pressure test of the well within five years prior to the return to activity.

(o) [(m)] Fluid level or hydraulic pressure test for inactive land well less than 15 [25] years old.

(1) At least three days prior to the test, each operator must give the district office notice of the date and approximate time the operator intends to conduct a fluid level or hydraulic pressure test. The district office may require that a test be witnessed by a Commission employee. The district office may allow an operator to conduct a test even if notice of the test is provided to the district office fewer than three days prior to the test.

(2) No operator may conduct a test other than a fluid level or hydraulic pressure test without prior approval from the district director or the director's delegate.

(3) Notwithstanding the provisions of paragraph (1) of this subsection, an operator may conduct a hydraulic pressure test without prior approval from the district director or the director's delegate, provided that the operator gives the district office written notice of the date and approximate time for the test at least three days prior to the time the test will be conducted; the production casing is tested to a depth of at least 250 feet below the base of usable quality water strata or 100 feet below the top of cement behind the production casing, whichever is deeper; and the minimum test pressure is greater than or equal to 250 psig for a period of at least 30 minutes.

(4) An operator that files documentation of a fluid level test or a hydraulic pressure test for an inactive land well less than 15 [25] years old in order to obtain a plugging extension must pay an annual fee of $50 for each well covered by the documentation.

(5) Using Commission Form H-15, each operator must file in the Commission's Austin office the results of a successful fluid level test within 30 days of the date the test was performed. The results, if approved, are valid for a period of one year from the date of the test. Upon request by the Commission or its delegate, the operator must file the actual test data.

(6) Using Commission Form H-5 or Form H-15, each operator must file in the district office the results of a successful hydraulic pressure test, including the original pressure recording chart or its electronic equivalent, within 30 days of the date the test was performed. The results, if approved, are valid for a period of five years from the date of the test, unless the Commission or its delegate requires the operator to perform testing more frequently to ensure that the well does not pose a threat of harm to natural resources.

(7) The Commission or its delegate may transfer documentation of the results of a fluid level or hydraulic pressure test to a new operator of an existing inactive land well that is less than 15 [25] years old.

(p) [(n)] Supplemental financial assurance.

(1) A supplemental bond, letter of credit, or cash deposit filed as part of an application for an extension for an inactive land well is in addition to any other financial assurance otherwise required of the operator or for the well.

(2) The Commission or its delegate may not transfer a supplemental bond, letter of credit, or cash deposit to a new operator of an existing inactive land well. A new operator of an existing inactive land well must file a new supplemental bond, letter of credit, or cash deposit or otherwise comply with the provisions of this section not later than six months after the date the Commission or its delegate approves an operator designation form.

(q) [(o)] Escrow funds.

(1) An operator must deposit escrow funds with the Commission each time the operator files an application for an extension of the deadline for plugging an inactive well.

(2) The Commission or its delegate may release escrow funds deposited with the Commission only as prescribed by §3.78 of this title.

(r) [(p)] Plugging more than 10% of inactive well inventory. If an operator plugs more than 10% of the number of inactive land wells during a 12-month organization report cycle, the Commission will count the number of plugged wells above 10% toward fulfillment of the 10% blanket option under subsection (f)(2)(B)(i) of this section during the next organization report cycle.

§3.58. Certificate of Compliance and Transportation Authority; Operator Reports.

(a) Certificate of Compliance and transportation authority.

(1) - (4) (No change.)

(b) - (d) (No change.)

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

Filed with the Office of the Secretary of State on October 6, 2026.

TRD-202604256

Jonathan Broker

Attorney

Railroad Commission of Texas

Earliest possible date of adoption: November 22, 2026

For further information, please call: (512) 463-7262

CHAPTER 5. CARBON DIOXIDE (CO2)

The Railroad Commission of Texas (the "Commission") proposes amendments to §5.102 (relating to Definitions) in Subchapter A; and in Subchapter B proposes amendments to §5.202 (relating to Permit Required, and Draft Permit and Fact Sheet); §5.203 (relating to Application Requirements), §5.204 (relating to Notice of Permit Actions and Public Comment Period), §5.205 (relating to Fees, Financial Responsibility, and Financial Assurance), and §5.206 (relating to Permit Standards).

The Commission proposes to add two definitions, amend two definitions, add flexibility with respect to casing/tubing through the injection interval and the placement of a packer with respect to cemented casing, clarify the difference between a public meeting and a contested case hearing, and expand the options for financial responsibility mechanisms.

The Environmental Protection Agency (EPA) protects underground sources of drinking water (USDW) by regulating the injection of fluids underground for storage or disposal. The Safe Drinking Water Act (SDWA) and the Underground Injection Control (UIC) program provide the primary regulatory framework. From the early 1980s until 2010, EPA regulated five classes of wells according to the type of fluid injected, the depth of injection, and the potential to endanger USDWs. In 2010, EPA promulgated rules creating a sixth well class (Class VI) specifically to regulate the injection of carbon dioxide ("CO₂") into deep subsurface rock formations. EPA established minimum technical criteria for permitting, site characterization, area of review and corrective action, financial responsibility, well construction, operation, mechanical integrity testing, monitoring, well-plugging, post-injection site care, and site closure requirements.

Under the SDWA, EPA may delegate its authority to implement and enforce the UIC program to states upon application. Until a state receives primacy, EPA directly implements the UIC program through its regional offices.

The Commission adopted initial regulations to implement the Class VI UIC program effective December 20, 2010, and amended those regulations to be effective on September 19, 2022, and again on September 13, 2023, to reflect changes in the Texas statutes and to ensure that the state's program meets the minimum federal requirements for Class VI UIC wells. The State submitted to EPA its official application for primacy of the Class VI UIC program on December 19, 2022. EPA determined that the Commission's program met the minimum federal requirements and approved the Commission's application for primacy over Class VI UIC wells effective December 15, 2025.

Proposed Amendments to §5.201 Definitions

The Commission proposes to amend the definition of "Affected person" in §5.102(1) to clarify that an affected person is a person who has a personal justiciable interest related to a legal right, duty, or privilege and that has suffered or may suffer actual injury or economic damage as a result of the activity sought to be permitted. Affected persons may protest a permit and request a contested case hearing.

The Commission proposes to amend §5.201(14) to add a definition for "contaminant" as "any physical, chemical, biological, or radiological substance or matter in water."

The Commission proposes to add a definition for "Public meeting" as a meeting held by the Commission to receive comments on a draft permit for a Class VI injection well.

The Commission proposes to renumber the remaining definitions.

The Commission proposes to amend the definition of "Geologic Storage Facility" to replace the undefined term "area of elevated pressure" with the term "pressure front," as that term is defined in 16 TAC §5.102(47). The current definition uses the term "area of elevated pressure," which could be interpreted to encompass any non-zero pressure increase. The proposed clarification resolves this ambiguity by incorporating the existing defined term.

Proposed Amendments to §5.202, Permit Required, and Draft Permit and Fact Sheet

The Commission proposes to amend §5.202(e)(2)(C)(iv)(III) to replace the term "hearing" with "public meeting" to clarify that the fact sheet must include the date, time, and location of the public meeting if a public meeting has been scheduled.

Proposed Amendments to §5.203 Application Requirements

The Commission proposes to amend §5.203(e)(1)(B)(v) to state that an operator may request approval of an exception to a cemented well string or liner through the injection zone by filing with the director of the Oil and Gas Division a written request for such approval providing all pertinent information to support the exception. The current language requires that if the long string casing does not extend through the injection zone, another well string or liner must be cemented through the injection zone (for example, a chrome liner).

The Commission proposes to amend §5.203(e)(1)(C)(i) to provide for approval of an exception to the requirement that the packer must be set at a depth opposite of a cemented interval by filing with the director a written request for such approval providing all pertinent information to support the exception.

The Commission proposes to amend §5.203(j) (relating to Plan for monitoring, sampling, and testing after initiation of operation) to delete language in subsection (j)(2)(C) to delete the phrase "after initiation of injection" as superfluous because subsection (j) relates to activities after initiation of operation.

The Commission proposes to amend §5.203(j)(2)(D)(i) by deleting the requirement for periodic sampling of the fluid temperature, pH, conductivity, reservoir pressure and static fluid level of the injection zone. The Federal regulations at 40 CFR §146.87 require this information prior to injection well operation- not during injection- and this requirement is already in existing §5.203(f)(3)(A).

The Commission proposes to amend §5.203(j)(2)(E) to clarify that both direct and indirect methods of tracking the extent of the CO₂ plume and the position of the pressure front are required by the current Federal regulations at 40 CFR §146.90(g), and to clarify that indirect methods other than those enumerated in the section may be required based on site-specific geology.

The Commission proposes to clarify §5.203(m)(7)(H) by replacing the phrase "area of elevated pressure" with the term "pressure front" as defined in §5.201(48) consistent with the changes discussed above.

Proposed Amendments to §5.204 Notice of Permit Actions and Public Comment Period

The Commission proposes to amend §5.204, relating to Notice of Permit Actions and Public Comment Period, to clarify the difference between a contested case hearing to consider protests from affected persons and a public meeting to accept comments from interested persons. The Commission has replaced the term "public hearing" with the terms "public meeting" and "contested case hearing", where appropriate.

The Commission proposes to amend §5.204(a), relating to Notice requirements, to distinguish between a "public meeting" and a "contested case hearing". The Commission proposes to amend §5.204(a)(1) to clarify that the Commission will give notice when the Commission has scheduled a public meeting to accept comment from interested persons under §5.204(b)(1)(A) and a contested case hearing to consider protests from affected persons under §5.204(b)(2).

The Commission proposes to amend §5.204(a)(3), relating to Methods of notification, to clarify that the Commission will give individual notice of a draft permit, public meeting, or contested case hearing.

The Commission proposes to amend §5.204(a)(4)(E)(i) to clarify that interested persons may request a public meeting. The Commission proposes to amend §5.204(a)(4)(E)(ii) to add a requirement that affected persons include a basis for their claimed status as an affected person and to distinguish between a public meeting and a contested case hearing. The Commission proposes to amend §5.204(a)(4)(E)(iii) to clarify the beginning and end of the period during which the Commission will receive comments, requests for a public meeting, and protests.

The Commission proposes to amend §5.204(a)(6) to delete existing language and add language to require that notices of public meetings include information satisfying the requirements of 40 CFR §124.10(d)(2), which requires that notice of public hearings include reference to the date of previous public notices relating to the permit; date, time, and place of the meeting; and a brief description of the nature and purpose of the hearing, including the applicable rules and procedures.

The Commission proposes to amend §5.204(a)(6) to replace "Notice to certain communities" with "Public outreach and community engagement." The Commission proposes to create new subparagraphs (A), (B), and (C). Subparagraph (A) requires the applicant to conduct engagement with key stakeholders such as state and local emergency response officials while developing required Class VI project plans such as the Emergency and Remedial Response Plan, to better understand community concerns and needs.

New subparagraph (B) would encourage applicants to initiate public outreach as well as community engagement during the planning stage of a project to appropriately incorporate input from the surrounding community prior to the eventual development and submittal of a Class VI permit application. The Commission proposes to delete reference to the term "Environmental Justice" community to emphasize that the Commission encourages the applicant to initiate public outreach and community engagement for all communities in the area of a project. The Commission does not propose to change the language regarding Limited English-Speaking Household communities.

New subparagraph (C) would require the applicant to provide the Commission with a list and summary of meetings held under subparagraphs (A) and (B).

The Commission proposes to add new paragraph §5.204(a)(7) to replace "Notice to certain communities" with "Public outreach and community engagement" to clarify that such activities should include all communities. The Commission proposes to amend §5.204(a)(7)(B) to change the language to active voice, make other grammatical changes, and to delete reference to environmental justice to reflect the fact that public outreach and engagement should involve all communities in the area of a specific proposed project. The Commission proposes to move the current language in §5.204(a)(7) relating to comment period for a draft permit more appropriately to §5.204(b) relating to public comment.

The Commission proposes to amend §5.204(b) to distinguish between public meetings and contested case hearings.

The Commission proposes to amend §5.204(b)(1)(A) to clarify that public notice of a draft permit, including a notice of intent to deny a permit application, must allow at least 30 days for public comment. The Commission also proposes to replace "public hearing" with "public meeting" to clarify that the purpose of the public meeting is to receive public comment and the public comment period must be extended to the close of any public meeting, rather than contested case hearing, which is addressed in §5.204(b)(3). The Commission also proposes to add language that states that, if the director extends the comment period, the Commission must notice such extension on the Commission's public website.

The Commission proposes to amend §5.204(b)(1)(B) to delete the language regarding reasonable limits for oral statement and the possible requirement that statements be in writing and move the language to the section discussing public meetings. The Commission also proposes to clarify that during the public comment period, any interested person may submit written comments on the draft permit and may request a public meeting rather than a contested case hearing if one has not already been scheduled as this section addresses receipt of public comment.

The Commission proposes to move the language in current §5.204(b)(1)(C) regarding automatic extension of the public comment period to the close of any public meeting to §5.204(b)(1)(A), which addresses public comment. The Commission proposes to delete the current language stating that the hearing examiner may also extend the comment period by so stating at the hearing to distinguish the public comment period and public meeting from a contested case hearing.

The Commission proposes to amend §5.204(b)(2) to add a new paragraph relating to public meetings to clarify that the Commission must hold a public meeting if the director finds, on the basis of requests, a significant degree of public interest in a draft permit. The public meeting shall be structured for the receipt of oral or written comments. The Commission also proposes to clarify that the Commission may set reasonable limits upon the time allowed for oral statements at a public meeting, and the submission of statements in writing may be required. The Commission also proposes to clarify that the director must issue a response to comments specifying which provisions, if any, of the draft permit have been changed in the final permit decision, and the reasons for the change, and briefly describing and responding to all significant comments on the draft permit raised during the public comment period. The Commission must post the response to comments on the Commission's public website.

The Commission proposes to amend §5.204(b)(3) to clarify that the paragraph relates to contested case hearings. The Commission proposes to reorganize the language in subparagraph (B) to clarify that the subparagraph relates to contested case hearings and to clarify that it is the Commission, rather than the director, that conducts contested case hearings. Current subparagraph (D) is renumbered to (C).

The Commission proposes to amend subparagraph §5.204(b)(3)(D) (current subparagraph (E)) to delete the phrase "Upon written request of the applicant" and to reorganize the language to make the subparagraph clearer.

The Commission proposes to renumber current paragraph §5.204(b)(3) to (4) and current paragraph §5.204(b)(4) to (5) and to clarify that the paragraphs relate to contested case hearings.

The Commission proposes to renumber current paragraph §5.204(b)(5) to (6) and to clarify that response to issues considered during a contested case hearing will be addressed in the Hearing Examiners' recommendation for final action and to state that the Commission will post the Hearing Examiners' recommendation for final action and the final order on the Commission's public website.

Proposed Amendments to §5.205 Fees, Financial Responsibility, and Financial Assurance

The Commission proposes to amend §5.205 Fees, Financial Responsibility, and Financial Assurance to expand the options for financial assurance mechanisms. Currently, the rule allows bonds and letters of credit. The current rules in Chapter 5 do not include the additional options partly because the various potential additional forms of financial assurance had not been fully evaluated in terms of either their compliance with EPA's rules or the nature and extent of the financial risk to the state. The Commission stated that it would consider future amendments to allow additional mechanisms for financial assurance in the future. The Commission has reviewed the various options for financial assurance mechanisms and proposes to broaden the options allowed by the current rule.

Section 5.205 requires financial assurance for corrective action, post-injection site care and monitoring, site closure (including injection well plugging), and emergency and remedial response. The financial responsibility requirements are designed to ensure that owners and operators have the resources to carry out required geologic storage activities related to operating, closing and remediating geologic storage sites, if needed, so that they do not endanger USDWs. Financial assurance is intended to prevent the general public from bearing the costs of any emergency response, closure, and/or monitoring of a geologic storage facility.

Staff have received numerous questions from industry regarding calculating the necessary financial assurance to cover the Emergency and Remedial Response Plan. Staff plans to develop guidance that will incorporate all the considerations necessary to ensure that there will be adequate financial assurance to cover emergency and remedial response actions and welcomes input into such guidance.

The federal regulations allow for trust funds, surety bonds, letters of credit, insurance, self-insurance (i. e., Financial Test and Corporate Guarantee), escrow accounts, and any other instrument(s) satisfactory to the Director. The Commission has evaluated the various options for financial assurance for geologic storage activities and proposes that, in addition to surety bonds and letters of credit, an owner or operator of a geologic storage facility may use trust funds, insurance, escrow accounts, and any other instrument(s) satisfactory to the director to meet the financial responsibility requirements of the rule.

The Commission proposes to amend §5.204(i) to allow an owner or operator to demonstrate financial responsibility by using one or multiple qualifying financial instruments for specific phases of a geologic storage project. In the event that the owner or operator combines more than one instrument for a specific geologic storage phase (e.g., well plugging), such combination must be limited to instruments that are not based on financial strength or performance (i.e., performance bond), for example trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, escrow account, and insurance. and any other instrument(s) satisfactory to the director. In this case, it is the combination of mechanisms, rather than the single mechanism, which must provide financial responsibility for an amount at least equal to the current cost estimate. This language is consistent with federal requirements.

Certain financial assurance instruments are not appropriate for all geologic storage activities. The appropriateness of the instrument is tied to the financial risk to the state. Trust funds, letters of credit, and surety bonds may be appropriate for corrective action. Trust funds may be appropriate for post-injection site care and site closure. Insurance may be appropriate for unforeseen circumstances, such as emergency response and remedial action.

The Commission is not specifically proposing to allow self insurance or financial assurance mechanisms based on financial strength of the owner or operator of a geologic storage facility. Under self-insurance, an owner or operator assumes full financial responsibility for potential losses rather than transferring risk to an insurance company. Although self insurance is beneficial for owners and operators because it is likely to have the lowest overhead cost, it exposes the owner or operator to possible catastrophic financial exposure and unpredictable out-of-pocket expenses. Unlike traditional insurance that pools risks across thousands of policyholders, self insurance leaves the owner or operator solely responsible for covering massive, unexpected events. A single large claim can devastate cash flow or even cause bankruptcy.

Self insurance also represents the highest financial risk to the public. There is a greater risk of instrument failure for self-insurance. This is particularly true in the post injection site care period, because the facility represents an ongoing liability as the injection well is no longer in operation and profitable. In addition, in the past several large corporations that were considered unimpeachable and too big to fail have ultimately collapsed, leaving the state to bear the costs. Furthermore, self insurance is the most labor intensive form of financial assurance for the permitting agency.

In Water Code Section 27.073, relating to injection wells, the statute provides that a person to whom an injection well permit is issued may be required by the Railroad Commission to maintain a performance bond or other form of financial security to ensure that an abandoned injection well is properly plugged; or funds are available for plugging, postinjection site care, and closure of an anthropogenic carbon dioxide injection well. By using the phrase "other form of financial security" alongside a specific security instrument, a performance bond, the Legislature appears to have intended for the rules of the Commission to require entities to supply fungible financial assurance, rather than just evidence of financial assurance.

The Commission welcomes comments from interested persons regarding the various forms of financial assurance and specifically whether certain forms of financial assurance are appropriate to mitigate particular risks to the state.

The Commission proposes to amend §5.204(c) to add the language surrounding these additional financial assurance mechanisms to make sure they comport with federal regulations. The Commission proposes to add a sentence to clarify that financial responsibility instruments must be approved by the director. The Commission also proposes to amend §5.204 to replace the phrase "bond or letter of credit" with "financial assurance instrument" to reflect the expansion of financial assurance options.

The Commission proposes to amend §5.204(c)(2)(C)(i) to replace the term "perform" with the phrase "cover the cost of" to clarify that the amount of financial assurance must be equal to or greater than the maximum amount necessary to cover the cost of corrective action, emergency response, and remedial action, post-injection monitoring and site care, and closure of the geologic storage facility, including plugging of wells, at any time during the permit term in accordance with all applicable state laws, Commission rules and orders, and the permit. The Commission also proposes to add a sentence to clarify that the financial assurance instruments must be sufficient to address endangerment of underground sources of drinking water consistent with the federal requirements for Class VI injection wells. The Commission also proposes to add a new clause (iii) to state that the requirement to maintain adequate financial responsibility and resources is directly enforceable regardless of whether the requirement is a condition of the permit consistent with the federal requirements. The Commission proposes to renumber the remaining clauses.

The Commission proposes to amend §5.204(c)(2) to add a new subparagraph (D) relating to the acceptable financial responsibility instruments. Such instruments include trust funds, surety bonds, letters of credit, insurance, escrow accounts, and any other instrument(s) satisfactory to the director. The owner or operator may demonstrate financial responsibility by using one or multiple qualifying financial instruments for specific phases of the geologic storage project. In the event that the owner or operator combines more than one instrument for a specific geologic storage phase, such combination must be limited to instruments that are not based on financial strength or performance, for example trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, escrow account, and insurance. In this case, it is the combination of mechanisms that must provide financial responsibility for an amount at least equal to the current cost estimate.

The Commission also proposes to add language that requires that the owner or operator provide proof that any third-party provider either has passed financial strength requirements based on credit ratings; or has met a minimum rating, minimum capitalization, and ability to pass the bond rating when applicable. In addition, an owner or operator using certain types of third-party instruments must establish a standby trust to enable the Commission to be party to the financial responsibility agreement without EPA being the beneficiary of any funds. The standby trust fund must be used along with other financial responsibility instruments (e.g., surety bonds, letters of credit, or escrow accounts) to provide a location to place funds if needed.

The Commission proposes to add language that states that an owner or operator may deposit money into an escrow account to cover financial responsibility requirements and that this account must segregate funds sufficient to cover estimated costs for Class VI financial responsibility from other accounts and uses. The director must approve the use and length of pay-in-periods for trust funds or escrow accounts.

The Commission proposes to add language that allows an owner or operator to obtain an insurance policy to cover the estimated costs of geologic storage activities requiring financial responsibility, but that the insurance policy must be obtained from a third-party provider.

The Commission proposes to amend §5.204(c) to add new paragraph (6) to clarify that the director may deny the use of a financial instrument if the director determines that it is not sufficient to meet the requirements of this section.

The Commission proposes to amend §5.204(c) to add new paragraph (7) to state that the owner or operator must provide any updated information related to its financial responsibility instrument(s) on an annual basis and, if there are any changes, the director must evaluate, within a reasonable time, the financial responsibility demonstration to confirm that the instruments used remain adequate for use.

The Commission proposes to amend new subsection (d), relating to notice of adverse financial conditions, to state that, in the event that the owner or operator or the third party provider of a financial responsibility instrument is going through a bankruptcy, the owner or operator must notify the director by certified mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 days after commencement of the proceeding.

The Commission proposes to renumber current paragraph (3) and replace the term "bond" with "financial assurance".

The Commission proposes to add new paragraph (5) to state that an owner or operator who fulfills the requirements of this section by obtaining a trust fund, surety bond, letter of credit, escrow account, or insurance policy will be deemed to be without the required financial assurance in the event of bankruptcy of the trustee or issuing institution, or a suspension or revocation of the authority of the trustee institution to act as trustee of the institution issuing the trust fund, surety bond, letter of credit, escrow account, or insurance policy. The owner or operator must establish other financial assurance within 60 days after such an event. This language is required to ensure that the rule language is consistent with the federal requirements.

The Commission proposes to amend §5.206(k)(3)(A) to replace the phrase "area of elevated pressure" with "pressure front" as discussed above.

Leslie Savage, Chief Geologist, Oil and Gas Division, has determined that for each year of the first five years that the amendments will be in effect, there will be no additional economic costs for persons required to comply with the proposed amendments. Similarly, there will be no additional economic costs, reduction in costs, or losses or increases in revenue to the state or local governments as a result of enforcing or administering the rule. The federal regulations governing Class VI wells may create costs for persons required to comply. However, persons required to comply with the federal requirements must do so regardless of whether the requirements are adopted in Commission rules because if the Commission were not approved to enforce the Class VI program, EPA would enforce the same requirements. The proposed amendments to Commission rules do not create any additional economic costs for persons required to comply. The proposed amendments provide clarity and flexibility to the requirements of the rules.

Ms. Savage has determined that for each year of the first five years that the amendments will be in effect, the public benefit will be the clarification of the Commission regulations regarding geologic storage of anthropogenic carbon dioxide, and flexibility for financial assurance of such facilities in support of the prevention of pollution of surface and subsurface waters of the state and promotion of safety in accordance with Texas Natural Resources Code, §85.042 and §91.101. Achieving meaningful reductions in CO₂ emissions while preserving the benefits of our energy-intensive economy cannot be accomplished without significant deployment of carbon sequestration.

Texas Government Code, §2006.002, relating to Adoption of Rules with Adverse Economic Effect, requires that, before adopting a rule that may have an adverse economic effect on small businesses or micro-businesses, a state agency prepare an economic impact statement and a regulatory flexibility analysis. The economic impact statement must estimate the number of small businesses subject to the proposed rule and project the economic impact of the rule on small businesses. A regulatory flexibility analysis must include the agency's consideration of alternative methods of achieving the purpose of the proposed rule. If consistent with the health, safety, and environmental and economic welfare of the state, the analysis must consider the use of regulatory methods that will accomplish the objectives of applicable rules while minimizing adverse impacts on small businesses. Government Code §2006.001(2) defines "small business" as a legal entity, including a corporation, partnership, or sole proprietorship, that is formed for the purpose of making a profit; is independently owned and operated; and has fewer than 100 employees or less than $6 million in annual gross receipts. A "micro-business" is defined as a legal entity, including a corporation, partnership, or sole proprietorship, that is formed for the purpose of making a profit; is independently owned and operated; and has no more than 20 employees.

Entities that perform activities under the jurisdiction of the Commission are not required to report to the Commission their number of employees or their annual gross receipts, which are elements of the definitions of "micro-business" and "small business" in Texas Government Code, §2006.001; therefore, the Commission has no factual bases for determining whether any persons who drill and complete wells under the jurisdiction of the Railroad Commission will be classified as small businesses or micro-businesses, as those terms are defined. The North American Industrial Classification System (NAICS) sets forth categories of business types. The Texas Comptroller of Public Accounts website page entitled "HB 3430 Reporting Requirements-Determining Potential Effects on Small Businesses" provides information regarding various categories of businesses. There appears to be no category for "carbon sequestration". Based on the information available to the Commission regarding oil and gas operators and the complexity of the Class VI UIC requirements, Ms. Savage has concluded that, of the businesses that could be affected by the proposed amendments, it is unlikely that many would be classified as small businesses or micro-businesses, as those terms are defined in Texas Government Code, §2006.001. Furthermore, the bulk of the proposed amendments are necessary to ensure that the Commission's regulations meet the requirements of the U.S. Environmental Protection Agency (EPA) to enable EPA to approve state primacy for the Class VI UIC program. If the state does not have primacy for the Class VI program, EPA would be the permitting agency. Therefore, the costs imposed by the proposed amendments would be comparable to the costs imposed by the federal regulations.

The Commission has also determined that the proposed amendments will not affect a local economy. Therefore, the Commission has not prepared a local employment impact statement pursuant to Texas Government Code §2001.022.

The Commission has determined that the amendments do not meet the statutory definition of a major environmental rule as set forth in Texas Government Code, §2001.0225(a); therefore, a regulatory analysis conducted pursuant to that section is not required.

The Commission reviewed the proposed amendments and found that they are neither identified in Coastal Coordination Act Implementation Rules, 31 TAC §29.11(b)(4), nor would they affect any action or authorization identified in Coastal Coordination Act Implementation Rules, 31 TAC §29.11(a)(3). Therefore, the proposed amendments are not subject to the Texas Coastal Management Program.

During the first five years that the rules would be in full effect, the proposed amendments would not create or eliminate a new government program because the amendments are proposed to the Commission's existing Class VI program. The proposed amendments would not create new employee positions or eliminate any existing employee positions; increase or decrease future legislative appropriations to the agency; or increase or decrease fees paid to the agency. The proposed amendments would not create a new regulation and will not expand, limit, or repeal an existing regulation because the Commission is adopting requirements that are included in existing federal regulations. Similarly, because federal regulations are in place to govern Class VI UIC activities, the proposed amendments also do not increase responsibility for persons under the Commission's jurisdiction and would not increase or decrease the number of individuals subject to the rules. Finally, the proposed amendments would not affect the state's economy and would not require a change in employee positions.

As part of the public comment period, the Commission will hold a virtual public hearing to receive comments on the proposed amendments to Chapter 5.

The hearing will be structured for the receipt of oral or written comments by interested persons. Individuals may present oral statements when called upon in order of registration. Open discussion will not be permitted during the virtual hearing; however, Commission staff will be available after the meeting to discuss the proposal. Depending on the number of persons wishing to speak, the Commission may impose a time limit so that everyone who wishes to make a public comment will have the opportunity to do so.

The hearing will be conducted remotely using an internet meeting service. Individuals who plan to participate in the hearing and provide oral comments and/or want their participation on record must register in accordance with instructions provided on the Commission's website. Information regarding the public hearing will be posted on the Commission's website at least 10 business days in advance of the hearing, which will occur within the comment period. Instructions for participating in the hearing will be sent to those who register for the hearing. Individuals who do not wish to provide oral comments but would like to view the hearing may do so. A link to the webcast will be added on the Commission's website.

Any individual with a disability who plans to participate in the hearing and who requires auxiliary aids or services should notify the Commission as far in advance as possible so that appropriate arrangements can be made. Requests may be made to the Human Resources Department of the Railroad Commission of Texas by mail at P.O. Box 12967, Austin, Texas 78711-2967; by telephone at (512) 463-6981 or TDD No. (512) 463-7284; by e-mail at ADA@rrc.texas.gov; or in person at 1701 North Congress Avenue, Suite 12-110, Austin, Texas.

Comments on the proposed amendments may be submitted to Rules Coordinator, Office of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711-2967; online at www.rrc.texas.gov/general-counsel/rules/comment-form-for-proposed-rulemakings; or by electronic mail to rulescoordinator@rrc.texas.gov. The Commission will accept comments until 5:00 p.m. on November 23, 2026. The Commission finds that this comment period is reasonable because the proposal and an online comment form will be available on the Commission's website more than two weeks prior to Texas Register publication of the proposal, giving interested persons additional time to review, analyze, draft, and submit comments. The Commission cannot guarantee that comments submitted after the deadline will be considered. For further information, call Ms. Savage at (512) 463-7308. The status of Commission rulemakings in progress is available at www.rrc.texas.gov/general-counsel/rules/proposed-rules. Once received, all comments are posted on the Commission's website at https://rrc.texas.gov/general-counsel/rules/proposed-rules/. If you submit a comment and do not see the comment posted at this link within three business days of submittal, please call the Office of General Counsel at (512) 463-7149. The Commission has safeguards to prevent emailed comments from getting lost; however, your operating system's or email server's settings may delay or prevent receipt.

SUBCHAPTER A. GENERAL PROVISIONS

The Commission proposes the amendments pursuant to Texas Natural Resources Code, §§81.051 and 81.052, which give the Commission jurisdiction over all persons owning or engaged in drilling or operating oil or gas wells in Texas and the authority to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission; Texas Natural Resources Code, Chapter 91, Subchapter R, relating to authorization for multiple or alternative uses of wells; Texas Water Code, Chapter 27, Subchapter C-1, which gives the Commission jurisdiction over the geologic storage of carbon dioxide in, and the injection of carbon dioxide into, a reservoir that is initially or may be productive of oil, gas, or geothermal resources or a saline formation directly above or below that reservoir; Texas Health and Safety Code §382.502, which allows the Commission to adopt by rule standards for the location, construction, maintenance, monitoring, and operation of a carbon dioxide repository and requires the Commission to ensure standards comply with federal requirements issued by the EPA; and Texas Water Code, Chapter 120, which establishes the Anthropogenic Carbon Dioxide Storage Trust Fund, a special interest-bearing fund in the state treasury, to consist of fees collected by the Commission and penalties imposed under Texas Water Code, Chapter 27, Subchapter C-1, and to be used by the Commission for only certain specified activities associated with geologic storage facilities and associated anthropogenic carbon dioxide injection wells.

Statutory authority: Texas Natural Resources Code, §§81.051, 81.052; Texas Natural Resources Code, Chapter 91, Subchapter R; Texas Health and Safety Code §382.502; and Texas Water Code, Chapters 27 and 120.

Cross reference to statute: Texas Natural Resources Code, Chapters 81 and 91, Texas Health and Safety Code, Chapter 382, and Texas Water Code, Chapters 27 and 120.

§5.102. Definitions.

The following terms, when used in Subchapter B of this chapter, shall have the following meanings, unless the context clearly indicates otherwise.

(1) Affected person--A person who has a personal justiciable interest related to a legal right, duty, or privilege, and who [, as a result of activity sought to be permitted] has suffered or may suffer actual injury or economic damage as a result of the activity sought to be permitted. An interest common to members [other than as a member] of the general public does not qualify as a personal justiciable interest.

(2) - (13) (No change.)

(15) [(14)] Corrective action--Methods to assure that wells within the area of review do not serve as conduits for the movement of fluids into or between underground sources of drinking water, including the use of corrosion resistant materials, where appropriate.

(16) [(15)] Delegate--The person authorized by the director to take action on behalf of the Railroad Commission of Texas under this chapter.

(17) [(16)] Director--The director of the Oil and Gas Division of the Railroad Commission of Texas or the director's delegate.

(18) [(17)] Division--The Oil and Gas Division of the Railroad Commission of Texas.

(19) [(18)] Draft permit--A document prepared indicating the director's tentative decision to issue or deny, modify, revoke and reissue, terminate, or reissue a permit. A notice of intent to terminate a permit, and a notice of intent to deny a permit are types of "draft permits." A denial of a request for modification, revocation and reissuance, or termination is not a draft permit.

(20) [(19)] Enhanced recovery operation--Using any process to displace hydrocarbons from a reservoir other than by primary recovery, including using any physical, chemical, thermal, or biological process and any co-production project. This term does not include pressure maintenance or disposal projects.

(21) [(20)] EPA--The United States Environmental Protection Agency.

(22) [(21)] Exempted aquifer--An aquifer or its portion that meets the criteria in the definition of underground source of drinking water but which has been exempted according to the procedures in 40 CFR §144.7.

(23) [(22)] Facility closure--The point at which the operator of a geologic storage facility is released from post-injection storage facility care responsibilities.

(24) [(23)] Flow rate--The volume per time unit given to the flow of gases or other fluid substance which emerges from an orifice, pump, turbine or passes along a conduit or channel.

(25) [(24)] Fluid--Any material or substance which flows or moves whether in a semisolid, liquid, sludge, gas, or any other form or state.

(26) [(25)] Formation--A body of consolidated or unconsolidated rock characterized by a degree of lithologic homogeneity which is prevailingly, but not necessarily, tabular and is mappable on the earth's surface or traceable in the subsurface.

(27) [(26)] Formation fluid--Fluid present in a formation under natural conditions.

(28) [(27)] Fracture pressure--The pressure that, if applied to a subsurface formation, would cause that formation to physically fracture.

(29) [(28)] Geologic storage--The long-term containment of gaseous, liquid, or supercritical anthropogenic CO₂ in subsurface geologic formations.

(30) [(29)] Geologic storage facility or storage facility--The underground geologic formation, underground equipment, injection wells, and surface buildings and equipment used or to be used for the geologic storage of anthropogenic CO₂ and all surface and subsurface rights and appurtenances necessary to the operation of a facility for the geologic storage of anthropogenic CO₂. The term includes the subsurface three-dimensional extent of the CO₂ plume, pressure front, [associated area of elevated pressure, and displaced fluids, as well as] the surface area above that delineated region, and any reasonable and necessary areal buffer and subsurface monitoring zones. The term does not include a pipeline used to transport CO₂ from the facility at which the CO₂ is captured to the geologic storage facility. The storage of CO₂ incidental to or as part of enhanced recovery operations does not in itself automatically render a facility a geologic storage facility.

(31) [(30)] Good faith claim--A factually supported claim based on a recognized legal theory to a continuing possessory right in pore space such that the pore space can be used for geologic storage of carbon dioxide.

(32) [(31)] Injection zone--A geologic formation, group of formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and permeability to receive CO₂ through a well or wells associated with a geologic storage facility.

(33) [(32)] Injection well--A well into which fluids are injected.

(34) [(33)] Interested person--Any person who expresses an interest in an application, permit, or Class VI UIC well.

(35) [(34)] Limited English-speaking household--A household in which all members 14 years and older have at least some difficulty with English.

(36) [(35)] Lithology--The description of rocks on the basis of their physical and chemical characteristics.

(37) [(36)] Mechanical integrity--

(A) An anthropogenic CO₂ injection well has mechanical integrity if:

(i) there is no significant leak in the casing, tubing, or packer; and

(ii) there is no significant fluid movement into a stratum containing an underground source of drinking water through channels adjacent to the injection well bore as a result of operation of the injection well.

(B) The Commission will consider any deviations during testing that cannot be explained by the margin of error for the test used to determine mechanical integrity, or other factors, such as temperature fluctuations, to be an indication of the possibility of a significant leak and/or the possibility of significant fluid movement into a stratum containing an underground source of drinking water through channels adjacent to the injection wellbore.

(38) [(37)] Monitoring well--A well either completed or re-completed to observe subsurface phenomena, including the presence of anthropogenic CO₂, pressure fluctuations, fluid levels and flow, temperature, and/or in situ water chemistry.

(39) [(38)] Offshore--The area in the Gulf of Mexico seaward of the coast that is within three marine leagues of the coast.

(40) [(39)] Operator--A person, acting for itself or as an agent for others, designated to the Railroad Commission of Texas as the person with responsibility for complying with the rules and regulations regarding the permitting, physical operation, closure, and post-closure care of a geologic storage facility, or such person's authorized representative.

(41) [(40)] Owner--The owner of any facility or activity subject to regulation under the UIC program.

(42) [(41)] Owner or operator--The owner or operator of any injection well, or any other facility or activity that is subject to regulation under the UIC program. When a geologic storage facility is owned by one person but is operated by another person, it is the operator's duty to comply with the requirements of this subchapter and any permit issued under this subchapter, except that either the owner or the operator may demonstrate financial responsibility.

(43) [(42)] Packer--A device lowered into a well to produce a fluid-tight seal.

(44) [(43)] Permit--An authorization, license, or equivalent control document issued by the Commission to implement the requirements of this chapter.

(45) [(44)] Person--A natural person, corporation, organization, government, governmental subdivision or agency, business trust, estate, trust, partnership, association, or any other legal entity.

(46) [(45)] Plugging--The act or process of stopping the flow of water, oil or gas into or out of a formation through a borehole or well penetrating that formation.

(47) [(46)] Post-injection facility care--Monitoring and other actions (including corrective action) needed following cessation of injection to assure that underground sources of drinking water are not endangered and that the anthropogenic CO₂ remains confined to the permitted injection interval.

(48) [(47)] Pressure front--The zone of elevated pressure that is created by the injection of the CO₂ stream into the subsurface where there is a pressure differential sufficient to cause movement of the CO₂ stream or formation fluids from the injection zone into an underground source of drinking water.

(50) [(48)] Reservoir--A natural or artificially created subsurface stratum, formation, aquifer, cavity, void, or coal seam.

(51) [(49)] Stratigraphic test well--An exploratory well drilled for the purpose of gathering information in connection with a proposed carbon dioxide geologic storage project, including formation testing to obtain information on the chemical and physical characteristics of the injection zones and confining zones. Such testing may include injectivity testing.

(52) [(50)] Stratum (or strata)--A single sedimentary bed or layer, regardless of thickness, that consists of generally the same kind of rock material.

(53) [(51)] Surface casing--The first string of well casing to be installed in the well.

(54) [(52)] Transmissive fault or fracture--A fault or fracture that has sufficient permeability and vertical extent to allow fluids to move beyond the confining zone.

(55) [(53) UIC--Underground injection control.

(56) [(54)] Underground source of drinking water (USDW)--An aquifer or its portion which is not an exempt aquifer as defined in 40 CFR §146.4 and which:

(A) supplies any public water system; or

(B) contains a sufficient quantity of ground water to supply a public water system; and

(i) currently supplies drinking water for human consumption; or

(ii) contains fewer than 10,000 mg/l total dissolved solids.

(57) [(55)] Well injection--The subsurface emplacement of fluids through a well.

(58) [(56)] Well stimulation--Any of several processes used to clean the well bore, enlarge channels, and increase pore space in the interval to be injected thus making it possible for fluid to move more readily into the formation including, but not limited to, surging, jetting, blasting, acidizing, and hydraulic fracturing.

(59) [(57)] Workover--An operation in which a down-hole component of a well is repaired or the engineering design of the well is changed. Workovers include operations such as sidetracking, the addition of perforations within the permitted injection interval, and the addition of liners or patches. For the purposes of this chapter, workovers do not include well stimulation operations.

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

Filed with the Office of the Secretary of State on October 6, 2026.

TRD-202604254

Betsy Peticolas

Attorney

Railroad Commission of Texas

Earliest possible date of adoption: November 22, 2026

For further information, please call: (512) 463-7262

SUBCHAPTER B. GEOLOGIC STORAGE AND ASSOCIATED INJECTION OF ANTHROPOGENIC CARBON DIOXIDE (CO2)

The Commission proposes the amendments pursuant to Texas Natural Resources Code, §§81.051 and 81.052, which give the Commission jurisdiction over all persons owning or engaged in drilling or operating oil or gas wells in Texas and the authority to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission; Texas Natural Resources Code, Chapter 91, Subchapter R, relating to authorization for multiple or alternative uses of wells; Texas Water Code, Chapter 27, Subchapter C-1, which gives the Commission jurisdiction over the geologic storage of carbon dioxide in, and the injection of carbon dioxide into, a reservoir that is initially or may be productive of oil, gas, or geothermal resources or a saline formation directly above or below that reservoir; Texas Health and Safety Code §382.502, which allows the Commission to adopt by rule standards for the location, construction, maintenance, monitoring, and operation of a carbon dioxide repository and requires the Commission to ensure standards comply with federal requirements issued by the EPA; and Texas Water Code, Chapter 120, which establishes the Anthropogenic Carbon Dioxide Storage Trust Fund, a special interest-bearing fund in the state treasury, to consist of fees collected by the Commission and penalties imposed under Texas Water Code, Chapter 27, Subchapter C-1, and to be used by the Commission for only certain specified activities associated with geologic storage facilities and associated anthropogenic carbon dioxide injection wells.

Statutory authority: Texas Natural Resources Code, §§81.051, 81.052; Texas Natural Resources Code, Chapter 91, Subchapter R; Texas Health and Safety Code §382.502; and Texas Water Code, Chapters 27 and 120.

Cross reference to statute: Texas Natural Resources Code, Chapters 81 and 91, Texas Health and Safety Code, Chapter 382, and Texas Water Code, Chapters 27 and 120.

§5.202. Permit Required, and Draft Permit and Fact Sheet.

(a) - (d) (No change.)

(e) Draft permit and fact sheet.

(1) (No change.)

(2) Fact sheet.

(A) - (B) (No change.)

(C) The fact sheet shall include, when applicable:

(i) - (iii) (No change.)

(iv) a description of the procedures for reaching a final decision on the draft permit including:

(I) the beginning and ending dates of the comment period;

(II) the address where comments will be received;

(III) the [The] date, time, and location of the storage facility permit public meeting [hearing], if a public meeting [hearing] has been scheduled; and

(IV) any other procedures by which the public may participate in the final decision; and

(v) (No change.)

§5.203. Application Requirements.

(a) - (d) (No change.)

(e) Injection well construction.

(1) Criteria for construction of anthropogenic CO₂ injection wells. This paragraph establishes the criteria for the information about the construction and casing and cementing of, and special equipment for, anthropogenic CO₂ injection wells that an applicant must include in an application.

(A) (No change.)

(B) Casing and cementing of anthropogenic CO₂ injection wells.

(i) - (iv) (No change.)

(v) At least one long string casing, using a sufficient number of centralizers, must extend from the surface to the injection zone and must be cemented by circulating cement to the surface in one or more stages. The long string casing must isolate the injection zone and other intervals as necessary for the protection of USDWs and to ensure confinement of the injected and formation fluids to the permitted injection zone using cement and/or other isolation techniques. If the long string casing does not extend through the injection zone, another well string or liner must be cemented through the injection zone (for example, a chrome liner). An operator may request an exception to the packer setting depth by submitting a written request to the director and providing all pertinent information to support the requested exception.

(vi) - (vii) (No change.)

(C) Special equipment.

(i) Tubing and packer. All injection wells must inject fluids through tubing set on a packer. Packers must be set at a depth opposite of a cemented interval and no higher than 100 feet above the top of the permitted injection interval or at a location approved by the director. An operator may request an exception to the packer setting depth by submitting a written request to the director and providing all pertinent information to support the requested exception.

(ii) (No change.)

(2) - (4) (No change.)

(f) - (i) (No change.)

(j) Plan for monitoring, sampling, and testing after initiation of operation.

(1) (No change.)

(2) The plan must include the following:

(A) - (B) (No change.)

(C) [after initiation of injection,] the performance on a quarterly basis of corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting, and other signs of corrosion to ensure that the well components meet the minimum standards for material strength and performance set forth in subsection (e)(1)(A) of this section. The operator must report the results of such monitoring semi-annually. Corrosion monitoring may be accomplished by:

(i) - (iii) (No change.)

(D) monitoring of geochemical and geophysical changes, including:

(i) periodic [sampling of the fluid temperature, pH, conductivity, reservoir pressure and static fluid level of the injection zone and] monitoring for pressure changes, and for changes in geochemistry, in a permeable and porous formation near to and above the top confining zone;

(ii) - (iv) (No change.)

(E) tracking the extent of the CO₂ plume and the position of the pressure front by using direct methods in the injection zone and indirect methods, [geophysical techniques,] which may include seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO₂ detection tools unless the director determines, based on site-specific geology, that such methods are not appropriate;

(F) - (H) (No change.)

(k) - (l) (No change.)

(m) Post-injection storage facility care and closure plan. The applicant must submit a post-injection storage facility care and closure plan. The plan must include:

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

(7) consideration and documentation of:

(A) - (G) (No change.)

(H) the presence of potential conduits for fluid movement including planned injection wells and project monitoring wells associated with the proposed geologic storage project or any other projects in proximity to the predicted/modeled, final extent of the CO₂ plume and pressure front [area of elevated pressure];

(I) - (K) (No change.)

(8) (No change.)

(n) - (p) (No change.)

§5.204. Notice of Permit Actions and Public Comment Period.

(a) Notice requirements.

(1) The Commission shall give notice of the following actions:

(A) a draft permit has been prepared under §5.202(e) of this title (relating to Permit Required, and Draft Permit and Fact Sheet) or the director proposes to deny an application; [and]

(C) [(B)] a contested case hearing has been scheduled under subsection (b)(3) [(b)(2)] of this section.

(2) (No change.)

(3) Methods of notification. The Commission shall give notice by the following methods:

(A) Individual notice. Notice of a draft permit, a public meeting, or a contested case [public] hearing shall be given by mailing a copy of the notice to the following persons:

(i) - (xi) (No change.)

(xii) persons on the mailing list developed by the Commission, including those who request in writing to be on the list and by soliciting participants in public meetings [hearings] in that area for their interest in being included on area mailing lists; and

(xiii) (No change.)

(B) (No change.)

(4) Content of notice. Individual notice must consist of:

(A) - (D) (No change.)

(E) a statement that:

(i) affected persons may protest[,] and request a contested case hearing, and interested persons may request a public meeting [hearing] on[,] the application;

(ii) protests and requests for a public meeting [hearing] must be submitted [filed] in writing and may [must] be mailed or delivered to Technical Permitting, Oil and Gas Division, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711 or submitted electronically to SIP@rrc.texas.gov; [and]

(iv) [(iii)] public comments, requests for a public meeting, and requests for a contested case hearing may be submitted at any time during the public comment period. Unless extended by the director for good cause, the public comment period ends 30 days after the notice of the draft permit, 30 days from the date of the last publication of notice, or at the close of any public meeting [protests and requests for a hearing must be received by the director within 30 days of the date of receipt of the application by the division, receipt of individual notice, or last publication of notice], whichever is later.[; and]

(F) information satisfying the requirements of 40 CFR §124.10(d)(1).

(5) (No change.)

(7) [(6)] Public outreach and community engagement. [Notice to certain communities.]

(B) The Commission encourages applicants to initiate public outreach and community engagement during the planning stage of a project to appropriately incorporate input from the surrounding community prior to the eventual development and submittal of a Class VI permit application. If [The applicant shall identify whether] any portions of the AOR encompass a [an Environmental Justice (EJ) or] Limited English-Speaking Household community using the most recent U.S. Census Bureau American Community Survey data, the applicant is encouraged to: [. If the AOR incudes an EJ or Limited English-Speaking Household community, the applicant shall conduct enhanced public outreach activities to these communities. Efforts to include EJ and Limited English-Speaking Household communities in public involvement activities in such cases shall include:]

(i) [(A)] publish any [published] meeting notice in English and the identified language (e.g., Spanish);

(ii) [(B)] post comment forms [posted] on the applicant's webpage and make them available at any public meeting in English and the alternate language;

(iii) [(C)] provide interpretation services [accommodated] upon request;

(iv) [(D)] provide a [English] translation of any public comments [made during any comment period] in the alternate language; and

(v) [(E)] to the extent possible, locate public meeting venues near public transportation.

(b) Public comment, public meeting, and contested case hearing requirements.

(1) Public comment.

(A) Public notice of a draft permit, including a notice of intent to deny a permit application, shall allow at least 30 days for public comment. The public comment period shall automatically be extended to the close of any public meeting under this section. The director may also extend the comment period for good cause. If the director extends the comment period, the Commission shall post notice of the extension on the Commission's public website. [During the public comment period, any interested person may submit written comments on the draft permit and may request a hearing if one has not already been scheduled.]

(B) During the public comment period, any interested person may submit written comments on the draft permit and may request a public meeting if one has not already been scheduled. [Reasonable limits may be set upon the time allowed for oral statements, and the submission of statements in writing may be required.]

(C) During the public comment period, any affected person may submit written comments on the draft permit and may request a contested case hearing. [The public comment period shall automatically be extended to the close of any public hearing under this section. The hearing examiner may also extend the comment period by so stating at the hearing.]

(3) [(2)] Contested case [Public] hearing.

(B) [(A)] If the director [Commission] receives a timely protest [regarding an application for a new permit or for an amendment of an existing permit for a geologic storage facility] from an affected person [a person notified pursuant to subsection (a) of this section or from any other affected person within 30 days of the date of receipt of the application by the division, receipt of individual notice, or last publication of notice, whichever is later], then the director will notify the applicant that the director cannot administratively approve the application. Upon the written request of the applicant, the director will schedule a contested case hearing on the application.

(C) The Commission [director] may also hold a contested case [public] hearing at the director's discretion, whenever, for instance, such a hearing might clarify one or more issues involved in the permit decision or the director determines there is a significant degree of public interest in a draft permit.

(D) Notice [Public notice] of a contested case [public] hearing shall be given in accordance with Texas Government Code §2001.052 [at least 30 days before the hearing]. Notice [Public notice] of a contested case hearing may be given at the same time as public notice of the draft permit and the two notices may be combined.

(E) The [Upon the written request of the applicant, the] Commission must give notice of a contested case hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. Notice of a contested case hearing shall include information satisfying the requirements of 40 CFR §124.10(d)(2) and Texas Government Code, §2001.052. After the contested case hearing, the examiner will recommend a final action to [by] the Commission. [Notices shall include information satisfying the requirements of 40 CFR §124.10(d)(2) and the Texas Government Code, §2001.052.]

(4) [(3)] If the Commission receives no timely protest regarding an application for a new permit or for the amendment of an existing permit for a geologic storage facility from an [a person notified pursuant to subsection (a) of this section or from any other] affected person, the director may administratively approve the application.

(5) [(4)] If the director administratively denies an application for a new permit or for the amendment of an existing permit for a geologic storage facility, upon the written request of the applicant, the director will schedule a contested case hearing. After the contested case hearing, the examiner will recommend a final action to [by] the Commission.

(6) [(5)] [Upon making a final permit decision, the director shall issue a response to comments. The response shall specify which provisions, if any, of the draft permit have been changed in the final permit decision, and the reasons for the change, and shall briefly describe and respond to all significant comments on the draft permit raised during the public comment period or during any hearing.] The Commission shall post the hearing examiner's recommendation for final action and the final order [response to comments] on the Commission's public [internet] website.

§5.205. Fees, Financial Responsibility, and Financial Assurance.

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

(c) Financial assurance. The qualifying financial responsibility instruments must be approved by the director. The director shall consider and approve the [applicant's] demonstration of financial responsibility for all the phases of the geologic sequestration project, including the post-injection storage facility care and closure phase and the plugging phase, prior to issuance of a geologic storage injection well permit.

(1) (No change.)

(2) Geologic storage facility.

(A) The applicant must include in an application for a geologic storage facility permit:

(i) (No change.)

(ii) a copy of the form of the financial assurance instruments [bond or letter of credit] that will be filed with the Commission; and

(iii) information concerning the issuer of the financial assurance instrument, [bond or letter of credit] including the issuer's name and address and evidence of authority to issue financial assurance instruments [bonds or letters of credit] in Texas.

(B) A geologic storage facility shall not receive CO₂ until financial assurance [a bond or letter of credit] in an amount approved by the director under this subsection and meeting the requirements of this subsection as to form and issuer has been filed with and approved by the director.

(C) The determination of the amount of financial assurance for a geologic storage facility is subject to the following requirements:

(i) The director must approve the dollar amount of the financial assurance. The amount of financial assurance required to be filed under this subsection must be equal to or greater than the maximum amount necessary to cover the cost of [perform] corrective action, emergency response, and remedial action, post-injection monitoring and site care, and closure of the geologic storage facility, including plugging of wells, at any time during the permit term in accordance with all applicable state laws, Commission rules and orders, and the permit. The financial assurance instruments must be sufficient to address endangerment of USDWs. The cost estimate must be performed for each phase separately and must be based on the costs to the Commission of hiring a third party to perform the required activities. A third party is a party who is not within the corporate structure of the owner or operator;

(ii) (No change.)

(iv) [(iii)] The Commission may use the proceeds of financial assurance filed under this subsection to pay the costs of plugging any well or wells at the facility if the financial assurance for plugging costs filed with the Commission is insufficient to pay for the plugging of such well or wells.

(E) [(D)] Financial responsibility instruments [Bonds and letters of credit] filed in satisfaction of the financial assurance requirements for a geologic storage facility must comply with the following standards as to issuer and form.

(i) The issuer of any geologic storage facility bond filed in satisfaction of the requirements of this subsection must be a corporate surety authorized to do business in Texas. The form of bond filed under this subsection must provide that the bond be renewed and continued in effect until the conditions of the bond have been met or its release is authorized by the director.

(ii) Any letter of credit filed in satisfaction of the requirements of this subsection must be issued by and drawn on a bank authorized under state or federal law to operate in Texas. The letter of credit must be an irrevocable, standby letter of credit subject to the requirements of Texas Business and Commerce Code, §§5.101 - 5.118. The letter of credit must provide that it will be renewed and continued in effect until the conditions of the letter of credit have been met or its release is authorized by the director.

(F) [(iii)] The qualifying financial responsibility instruments must comprise protective conditions of coverage. Protective conditions of coverage must include at a minimum cancellation, renewal, and continuation provisions; specifications on when the provider becomes liable following a notice of cancellation if there is a failure to renew with a new qualifying financial instrument; and requirements for the provider to meet a minimum rating, minimum capitalization, and ability to pass the bond rating when applicable.

(i) [(I)] Cancellation. An owner or operator must provide that its financial instrument may not cancel, terminate, or fail to renew except for failure to pay such financial instrument. If there is a failure to pay the financial instrument, the financial institution may elect to cancel, terminate, or fail to renew the instrument by sending notice by certified mail to the owner or operator and the director. The cancellation must not be final until at least 120 days after the Commission receives the cancellation notice. The owner or operator must provide an alternate financial responsibility demonstration within 60 days of notice of cancellation, and if an alternate financial responsibility demonstration is not acceptable or possible, any funds from the instrument being cancelled must be released within 60 days of notification by the director.

(ii) [(II)] Renewal. If a financial instrument expires, the owner or operator must renew the financial instrument for the entire term of the geologic storage project. The instrument may be automatically renewed as long as the owner or operator has the option of renewal at the face amount of the expiring instrument. The automatic renewal of the instrument must, at a minimum, provide the holder with the option of renewal at the face amount of the expiring financial instrument.

(iii) [(III)] Financial instrument to remain in effect. Cancellation, termination, or failure to renew shall not occur and the financial instrument shall remain in full force and effect if on or before the date of expiration:

(I) [(-a-)] the director deems the facility abandoned;

(II) [(-b-)] the permit is terminated or revoked or a new permit is denied;

(III) [(-c-)] closure is ordered by the director or a United States district court or other court of competent jurisdiction;

(IV) [(-d-)] the owner or operator is named as debtor in a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code; or

(V) [(-e-)] the amount due is paid.

(G) [(E)] During the active life of the geologic storage project, the owner or operator must adjust the cost estimate for inflation within 60 days prior to the anniversary date of the establishment of the financial instruments used to comply with paragraph (2)(C)(i) of this subsection and provide this adjustment to the director. The owner or operator must also provide to the director written updates of adjustments to the cost estimate within 60 days of any amendments to the area of review and corrective action plan, the injection well plugging plan, the post-injection storage facility care and closure plan, and the emergency and remedial response plan.

(H) [(F)] The owner or operator of a geologic storage facility must provide to the director, and the director must approve, annual written updates of the cost estimate to increase or decrease the cost estimate to account for any changes to the AOR and corrective action plan, the emergency response and remedial action plan, the injection well plugging plan, and the post-injection storage facility care and closure plan. The director [Director] must approve any decrease or increase to the initial cost estimate. During the active life of the geologic storage project, the owner or operator must revise the cost estimate no later than 60 days after the director has approved the request to modify the AOR and corrective action plan, the injection well plugging plan, the post-injection storage facility care and closure plan, and the emergency and response plan, if a change in any of these plans increases the cost. If a change to a plan decreases the cost, any withdrawal of funds must be approved by the director. Any decrease to the value of a financial assurance instrument must first be approved by the director. The revised cost estimate must be adjusted for inflation as specified at paragraph (2)(G) [(2)(E)] of this subsection. The owner or operator must provide to the director, within 60 days of notification by the director, an adjustment of the cost estimate if the director determines during the annual evaluation of the qualifying financial responsibility instruments that the most recent demonstration is no longer adequate to cover the cost of corrective action, injection well plugging and post-injection storage facility care and closure, and emergency and remedial response.

(I) [(G)] Whenever the current cost estimate increases to an amount greater than the face amount of a financial instrument currently in use, the owner or operator, within 60 days after the increase, must either cause the face amount to be increased to an amount at least equal to the current cost estimate and submit evidence of such increase to the director or obtain other financial responsibility instruments to cover the increase. Whenever the current cost estimate decreases, the face amount of the financial assurance instrument may be reduced to the amount of the current cost estimate only after the owner or operator has received written approval from the director.

(J) [(H)] The requirement to maintain adequate financial responsibility is directly enforceable regardless of whether the requirement is a condition of the permit.

(i) The owner or operator must maintain financial responsibility until:

(I) the director receives and approves the completed post-injection storage facility care and closure plan; and

(II) the director issues the certificate of closure.

(ii) The owner or operator may be released from a financial instrument in the following circumstances:

(I) The owner or operator has completed the phase of the geologic storage project for which the financial instrument was required and has fulfilled all its financial obligations as determined by the director, including obtaining financial responsibility for the next phase of the geologic storage project, if required; or

(II) The owner or operator has submitted a replacement financial instrument and received written approval from the director accepting the new financial instrument and releasing the owner or operator from the previous financial instrument.

(3) The director may consider allowing the phasing in of financial assurance for only corrective action based on project-specific factors.

(4) The director may approve a reduction in the amount of financial assurance required for post-injection monitoring and/or corrective action based on project-specific monitoring results.

(5) The owner or operator must maintain the required financial responsibility regardless of the status of the director's review of the financial responsibility demonstration.

(d) Notice of adverse financial conditions.

(1) - (2) (No change.)

(4) [(3)] Upon the incapacity of a bank or surety company by reason of bankruptcy, insolvency or suspension, or revocation of its charter or license, the Commission must deem the owner or operator to be without financial assurance [bond] coverage. The Commission must issue a notice to any owner or operator who is without financial assurance [bond] coverage and must specify a reasonable period to replace financial assurance [bond] coverage, not to exceed 60 days.

§5.206. Permit Standards.

(a) - (j) (No change.)

(k) Permit conditions for post-injection storage facility care and closure.

(1) - (2) (No change.)

(3) Prior to closure. Prior to authorization for storage facility closure, the operator must demonstrate to the director, based on monitoring, other site-specific data, and modeling that is reasonably consistent with site performance that no additional monitoring is needed to assure that the geologic storage facility will not endanger USDWs. The operator must demonstrate, based on the current understanding of the site, including monitoring data and/or modeling, all of the following:

(A) the estimated magnitude and extent of the facility footprint (the CO₂ plume and the pressure front [area of elevated pressure]);

(B) - (E) (No change.)

(4) - (7) (No change.)

(l) - (o) (No change.)

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

Filed with the Office of the Secretary of State on October 6, 2026.

TRD-202604255

Betsy Peticolas

Attorney

Railroad Commission of Texas

Earliest possible date of adoption: November 22, 2026

For further information, please call: (512) 463-7262

CHAPTER 7. GAS SERVICES

SUBCHAPTER C. RECORDS AND REPORTS; TARIFFS; GAS UTILITY TAX

The Railroad Commission of Texas (Commission) proposes an amendment to 16 Texas Administrative Code §7.351, relating to Gas Utility Pipeline Tax. Section 7.351 establishes the reporting and payment requirements for the gas utility tax imposed under Texas Utilities Code, Chapter 122, including the deadlines and procedures for filing quarterly tax reports and payments.

Currently, subsection (b) of §7.351 provides that the Commission considers a gas utility tax report and payment timely filed if it is received by the Commission's Gas Services department on or before the applicable deadline or is sent by first-class United States mail, properly addressed and stamped, postmarked before the deadline, and received not more than 10 days later. The Commission has implemented a new online payment system under which gas utility tax payments are submitted exclusively through the Commission's electronic payment portal. The Commission therefore proposes to amend §7.351 to conform the rule to the Commission's current payment procedure.

Proposed amended §7.351(b) removes the language addressing the submission of gas utility tax reports and payments by mail. The amended subsection provides only that a gas utility tax report and payment are timely filed if received by the Gas Services department on or before the applicable date.

Mark Evarts, Director, Oversight and Safety Division, has determined that for each year of the first five years the proposed amendment will be in effect, enforcing or administering the amendment will not have foreseeable implications relating to costs or revenues of state or local governments.

Mr. Evarts has also determined that for each year of the first five years the proposed amendment will be in effect, the public benefit anticipated as a result of enforcing or administering the amendment will be increased regulatory clarity by conforming the rule to the Commission's current electronic payment procedures.

Mr. Evarts has determined that for each year of the first five years that the proposed amendment will be in effect, there will be no additional economic costs for persons required to comply as a result of the Commission's adoption of the proposed amendment. Gas utility tax payments may be submitted electronically through an ACH/e-check option without an additional fee. Although payment by credit card may be subject to a convenience fee, use of a credit card is not required to comply with the rule.

In accordance with Texas Government Code, §2006.002, the Commission has determined there will be no adverse economic effect on rural communities, small businesses or micro-businesses resulting from the proposed amendment. As discussed above, there will be no additional economic costs for persons required to comply as a result of adoption of the proposed amendment; therefore, the Commission has not prepared the economic impact statement or the regulatory flexibility analysis under §2006.002.

The Commission has determined that the proposed rulemaking will not affect a local economy; therefore, pursuant to Texas Government Code, §2001.022, the Commission is not required to prepare a local employment impact statement for the proposed amendment.

The Commission has determined that the proposed amendment does not meet the statutory definition of a major environmental rule as set forth in Texas Government Code, §2001.0225; therefore, a regulatory analysis conducted pursuant to that section is not required.

During the first five years that the amended rule would be in effect, the proposed amendment would not: create or eliminate a government program; create or eliminate any employee positions; require an increase or decrease in future legislative appropriations; increase fees paid to the agency; create a new regulation; increase or decrease the number of individuals subject to the rule's applicability; or positively or adversely affect the state's economy. The proposed amendment limits the existing regulation only by removing language addressing submission by mail.

Comments on the proposal may be submitted to Rules Coordinator, Office of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711-2967; online at https://rrc.texas.gov/general-counsel/rules/comment-form-for-proposed-rulemakings/; or by electronic mail to rulescoordinator@rrc.texas.gov. The Commission will accept comments until 5:00 p.m. on Monday, November 23, 2026. The Commission finds that this comment period is reasonable because the proposal and an online comment form will be available on the Commission's website more than two weeks prior to Texas Register publication of the proposal, giving interested persons additional time to review, analyze, draft, and submit comments. The Commission encourages all interested persons to submit comments no later than the deadline. The Commission also requests information related to the cost, benefit, or effect of the proposed rule, including any applicable data, research, or analysis, from any person required to comply with the proposed amendment or any other interested person. The Commission cannot guarantee that comments submitted after the deadline will be considered. For further information, call Mr. Evarts at (512) 463-9663. The status of Commission rulemakings in progress is available at www.rrc.texas.gov/general-counsel/rules/proposed-rules.

The Commission proposes the amendment under Title 3 of the Texas Utilities Code, specifically §122.151, which authorizes the Commission to adopt rules necessary under Tex. Util. Code Chapter 122 and to collect and enforce the taxes imposed under that chapter.

Statutory authority: Texas Utilities Code §122.151.

Cross reference to statutes: Texas Utilities Code, Chapter 122.

§7.351. Gas Utility Pipeline Tax.

(a) (No change.)

(b) Tax payment. Each gas utility subject to this tax shall report and pay the tax imposed to the Commission by February 20, May 20, August 20, and November 20 of a year for the preceding calendar quarter. The gas utility tax report shall be of a form and content as established by the Commission and shall be properly completed. The Commission shall consider a gas utility tax report and payment timely filed if it is received by Gas Services on or before the applicable date [or is sent to Gas Services by first-class United States mail in an envelope or wrapper properly addressed and stamped and postmarked before the deadline and received not more than 10 days later. A legible postmark affixed by the United States Postal Service shall be prima facie evidence of the date of mailing].

(c) - (f) (No change.)

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

Filed with the Office of the Secretary of State on October 6, 2026.

TRD-202604253

Fernando Domene

Attorney

Railroad Commission of Texas

Earliest possible date of adoption: November 22, 2026

For further information, please call: (512) 463-7262

PART 4. TEXAS DEPARTMENT OF LICENSING AND REGULATION

CHAPTER 110. ATHLETIC TRAINERS

The Texas Department of Licensing and Regulation (Department) proposes amendments to existing rules at 16 Texas Administrative Code (TAC), Chapter 110, §§110.16, 110.17, 110.24, and 110.70, regarding the Athletic Trainers program. These proposed changes are referred to as the "proposed rules."

EXPLANATION OF AND JUSTIFICATION FOR THE RULES

The rules under 16 TAC, Chapter 110, implement Texas Occupations Code, Chapter 451, Athletic Trainers; Texas Occupations Code, Chapter 51, the enabling statute of the Texas Commission of Licensing and Regulation and the Department; and Texas Education Code, Chapter 38, §38.158, regarding concussion training courses.

The proposed rules implement Senate Bill (SB) 2075, Sections 14 and 15, 89th Legislature, Regular Session (2025), regarding the Advisory Board of Athletic Trainers. The proposed rules remove the requirement that the terms of one or two advisory board members expire on January 31 of each odd-numbered year. The proposed rules also extend the term of the advisory board presiding officer to two years from the current one-year term. The proposed rules are necessary to maintain consistency with Texas Occupations Code §§51.2094(d), 451.053, and 451.055.

In addition, the proposed rules update the rules regarding the delegated authority document that athletic trainers are required to obtain and maintain. The proposed rules remove the term 'physician' from the phrase 'physician-delegated authority document,' as the statute allows athletic training to be done "under the direction of a physician licensed in this state or another qualified, licensed health professional who is authorized to refer for health care services within the scope of the person's license." The proposed rules add language that includes other qualified, licensed health professionals as authorized under the statute. The proposed rules are necessary to provide clarity and consistency with the statutory definition of "athletic training."

Advisory Board Recommendations

The proposed rules were presented to and discussed by the Advisory Board of Athletic Trainers at its meeting on 10/5/2026. The Advisory Board did not make any changes to the proposed rules. The Advisory Board voted and recommended that the proposed rules be published in the Texas Register for public comment.

SECTION-BY-SECTION SUMMARY

The proposed rules amend §110.16, Terms; Vacancies. Under subsection (a), the proposed rules remove the requirement that the terms of one or two advisory board members expire on January 31st of each odd-numbered year. This amendment tracks SB 2075, Section 14, and maintains consistency with relevant Department and program statutes (Texas Occupations Code §51.2094(d) and §451.053).

The proposed rules amend §110.17, Officers. Under subsection (a), the proposed rules extend the term of the advisory board presiding officer from one year to two years. This amendment tracks SB 2075, Section 15, and maintains consistency with relevant Department and program statutes (Texas Occupations Code §51.2094(d) and §451.055).

The proposed rules amend §110.24, License Renewal. The proposed rules update the license renewal requirements related to the delegated authority document. Under subsection (e), the proposed rules remove the term 'physician' from the phrase 'physician-delegated authority document,' so that other qualified, licensed health professionals are not precluded from delegating authority to an athletic trainer. This amendment provides clarity and consistency with the statutory definition of "athletic training."

The proposed rules amend §110.70, Standards of Conduct. The proposed rules update the standards of conduct related to the delegated authority document. Under subsections (a)(1) and (a)(2), the proposed rules remove the term 'physician' from the phrase 'physician-delegated authority document,' so that other qualified, licensed health professionals are not precluded from delegating authority to an athletic trainer. Under subsection (a)(3), the proposed rules add language that includes other qualified, licensed health professionals as authorized by statute. These amendments provide clarity and consistency with the statutory definition of "athletic training."

FISCAL IMPACT ON STATE AND LOCAL GOVERNMENT

Tony Couvillon, Senior Policy Research and Budget Analyst, has determined that for each year of the first five years the proposed rules are in effect, there are no estimated additional costs or reductions in costs to state or local government as a result of enforcing or administering the proposed rules.

Mr. Couvillon has also determined that for each year of the first five years the proposed rules are in effect, there is no estimated increase or loss in revenue to the state or local government as a result of enforcing or administering the proposed rules.

LOCAL EMPLOYMENT IMPACT STATEMENT

There is no impact on local governments, as the changes made by the proposed rules are not anticipated to increase or decrease the number of licensed athletic trainers or temporary athletic trainers, nor are they anticipated to affect potential employers seeking to hire athletic trainers. Because Mr. Couvillon has determined that the proposed rules will not affect a local economy, the agency is not required to prepare a local employment impact statement under Texas Government Code §2001.022.

PUBLIC BENEFITS

Mr. Couvillon also has determined that for each year of the first five-year period the proposed rules are in effect, the public benefit will be the removal of the perceived administrative hurdle of allowing only Medical Doctors (MDs) and Doctors of Osteopathy (DOs) to oversee athletic trainers through the delegated authority document. By refining the language, the proposed rules make it easier to understand that athletic trainers can work with a range of qualified, licensed health professionals.

PROBABLE ECONOMIC COSTS TO PERSONS REQUIRED TO COMPLY WITH PROPOSAL

Mr. Couvillon has determined that for each year of the first five-year period the proposed rules are in effect, there are no anticipated economic costs to persons who are required to comply with the proposed rules. The changes to be made by the rules do not impose additional fees or costs upon licensees, businesses, or any other persons. The additional requirements for the athletic trainer license renewal and those for the temporary license will impose no costs on applicants.

FISCAL IMPACT ON SMALL BUSINESSES, MICRO-BUSINESSES, AND RURAL COMMUNITIES

There will be no adverse economic effect on small businesses, micro-businesses, or rural communities as a result of the proposed rules. License holders will have no additional costs to comply with the proposed rules. The proposed rules have no anticipated adverse economic effect on rural communities because the proposed rules will not decrease the availability of athletic trainers to rural communities or increase the cost of athletic training services in rural communities.

Because the agency has determined that the proposed rule will have no adverse economic effect on small businesses, micro-businesses, or rural communities, preparation of an Economic Impact Statement and a Regulatory Flexibility Analysis, as detailed under Texas Government Code §2006.002, is not required.

ONE-FOR-ONE REQUIREMENT FOR RULES WITH A FISCAL IMPACT

The proposed rules do not have a fiscal note that imposes a cost on regulated persons, including another state agency, a special district, or a local government. Therefore, the agency is not required to take any further action under Texas Government Code §2001.0045.

GOVERNMENT GROWTH IMPACT STATEMENT

Pursuant to Texas Government Code §2001.0221, the agency provides the following Government Growth Impact Statement for the proposed rules. For each year of the first five years the proposed rules will be in effect, the agency has determined the following:

1. The proposed rules do not create or eliminate a government program.

2. Implementation of the proposed rules does not require the creation of new employee positions or the elimination of existing employee positions.

3. Implementation of the proposed rules does not require an increase or decrease in future legislative appropriations to the agency.

4. The proposed rules do not require an increase or decrease in fees paid to the agency.

5. The proposed rules do not create a new regulation.

6. The proposed rules expand, but do not limit or repeal, an existing regulation. The proposed rules expand a regulation by allowing the delegated authority document required when renewing a license to be under not just a physician but also "another authorized qualified, licensed health professional."

7. The proposed rules do not increase or decrease the number of individuals subject to the rules' applicability.

8. The proposed rules do not positively or adversely affect this state's economy.

TAKINGS IMPACT ASSESSMENT

The Department has determined that no private real property interests are affected by the proposed rules and the proposed rules do not restrict, limit, or impose a burden on an owner's rights to his or her private real property that would otherwise exist in the absence of government action. As a result, the proposed rules do not constitute a taking or require a takings impact assessment under Texas Government Code §2007.043.

PUBLIC COMMENTS AND INFORMATION RELATED TO THE COST, BENEFIT, OR EFFECT OF THE PROPOSED RULES

The Department is requesting public comments on the proposed rules and information related to the cost, benefit, or effect of the proposed rules, including any applicable data, research, or analysis. Any information that is submitted in response to this request must include an explanation of how and why the submitted information is specific to the proposed rules. Please do not submit copyrighted, confidential, or proprietary information.

Comments on the proposed rules and responses to the request for information may be submitted electronically on the Department's website at https://ga.tdlr.texas.gov:1443/form/ATH_Rule_Making; by facsimile to (512) 475-3032; or by mail to Shamica Mason, Legal Assistant, Texas Department of Licensing and Regulation, P.O. Box 12157, Austin, Texas 78711. The deadline for comments is 30 days after publication in the Texas Register.

STATUTORY AUTHORITY

The proposed rules are proposed under Texas Occupations Code, Chapter 51, specifically §51.201 and §51.203, which authorize the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement Chapter 51 and any other law establishing a program regulated by the Department.

The proposed rules are also proposed under Texas Occupations Code, Chapter 451, specifically §451.101, which authorizes the Executive Director and the Department to administer and enforce Chapter 451; and §§451.051-451.056, which establish the requirements of the Advisory Board of Athletic Trainers.

The statutory provisions affected by the proposed rules are those set forth in Texas Occupations Code, Chapters 51 and 451, and Texas Education Code, Chapter 38, §38.158. No other statutes, articles, or codes are affected by the proposed rules.

The legislation that enacted the statutory authority under which the proposed rules are proposed to be adopted is SB 2075, 89th Legislature, Regular Session (2025).

§110.16. Terms; Vacancies.

(a) Members of the advisory board serve staggered six-year terms. [The terms of one or two members expiring on January 31st of each odd-numbered year.]

(b) - (c) (No change.)

§110.17. Officers.

(a) The presiding officer of the commission shall designate a member of the advisory board as the presiding officer of the advisory board to serve for a term of two years [one year].

(b) (No change.)

§110.24. License Renewal.

(a) - (d) (No change.)

(e) To renew a license, a licensee must affirm that the licensee will provide all athletic training under the direction of a licensed physician or another qualified, licensed health professional who is authorized to refer for health care services within the scope of the person's license, and that this direction will be in writing and kept current through a [physician-]delegated authority document.

§110.70. Standards of Conduct.

(a) An athletic trainer, when carrying out the practice of athletic training in accordance with §451.001(3) of the Act, shall work under the direction of a licensed physician or another qualified, licensed health professional, who is authorized to refer for health care services within the scope of the person's license.

(1) The athletic trainer must obtain their [physician-]delegated authority document before practicing.

(2) A physical copy of the [physician-]delegated authority document must be kept on file with the athletic trainer's license or current license identification card. Both documents must be made available for inspection upon request.

(3) The [physician-]delegated authority document must include the name, phone number, physical office address, and electronic mail address of the [ sponsoring] physician or other qualified, licensed health professional sponsoring the athletic trainer. The authority document must be renewed each time the physician or other qualified, licensed health professional sponsoring the athletic trainer [physician] changes.

(b) - (y) (No change.)

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

Filed with the Office of the Secretary of State on October 12, 2026.

TRD-202604341

Deanne Rienstra

General Counsel

Texas Department of Licensing and Regulation

Earliest possible date of adoption: November 22, 2026

For further information, please call: (512) 463-7750