TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 5. CARBON DIOXIDE (CO2)

The Railroad Commission of Texas (the "Commission") proposes amendments to §5.101 and §5.102, relating to Purpose, and Definitions, in Subchapter A; amendments to §§5.201 - 5.207, relating to Applicability and Compliance; Permit Required; Application Requirements; Notice and Hearing; Fees, Financial Responsibility, and Financial Assurance; Permit Standards; and Reporting and Record-Keeping.

The Commission proposes the amendments to implement changes made during the 87th Texas Legislative Session (Regular Session, 2021) and to reflect additional federal requirements to allow the Commission to submit an application for enforcement primacy for the federal Class VI Underground Injection Control (UIC) program.

The U.S. Environmental Protection Agency (EPA) protects underground sources of drinking water (USDWs) 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. Historically, most States have sought and been granted primacy over one or more classes of wells. For example, most states have primacy over Class II wells, in which fluids are injected for natural gas and oil production, hydrocarbons storage, and enhanced recovery of oil and gas.

In 2010, EPA promulgated rules creating a sixth well class (Class VI) specifically to regulate the injection of 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. If EPA approves a State's application, the State assumes primary enforcement authority (i.e., primacy) over a class or classes of wells. Until a State receives primacy, EPA directly implements the UIC program through its regional offices.

The State of Texas established a framework for projects involving the capture, injection, sequestration or geologic storage of anthropogenic carbon dioxide in Senate Bill 1387, 81st Texas Legislature, R.S., 2009. The statutes required the state to pursue primacy for the Class VI UIC program. In recent years, interest in carbon capture and storage has increased. In June 2021, Texas took an important step towards primacy by enacting House Bill 1284 (HB 1284, 87th Legislature, R.S., 2021), which gives the Railroad Commission of Texas sole jurisdiction over carbon sequestration wells (jurisdiction had previously been shared with the Texas Commission on Environmental Quality (TCEQ)). When Texas seeks primacy over Class VI wells, its primacy application should be greatly simplified by giving a single state agency jurisdiction over Class VI permitting.

HB 1284 also amended Texas Water Code, §27.041(a) and (c), to provide the Commission with jurisdiction over a well used for geologic storage of carbon dioxide regardless of whether the well was initially completed for that purpose or was initially completed for another purpose and is converted to the geologic storage of anthropogenic carbon dioxide.

HB 1284 also amended Texas Water Code, §27.043, to prohibit the Commission from issuing a permit for the conversion of a previously plugged and abandoned Class I injection well, including any associated waste plume, to a Class VI injection well.

HB 1284 amended Texas Water Code, Chapter 27, Subchapter C-1, by adding §27.0461, relating to letter of determination from Commission, which requires that a person making an application to the Commission for a Class VI permit must submit with the application a letter of determination from TCEQ concluding that drilling and operating an anthropogenic carbon dioxide injection well for geologic storage or constructing or operating a geologic storage facility will not impact or interfere with any previous or existing Class I injection well, including any associated waste plume, or any other injection well authorized or permitted by TCEQ.

HB 1284 amended Texas Water Code, §27.048(b), to require that the Commission seek primacy to administer and enforce the program for the geologic storage and associated injection of anthropogenic carbon dioxide in this state, including onshore and offshore geologic storage and associated injection.

The Commission's Class II program was approved under §1425 of the SDWA, which requires that the state's program be effective in preventing endangerment of USDWs. However, EPA must review the Commission's Class VI program for geologic sequestration of carbon dioxide under §1422 of the SDWA, which requires that a state's program meet the minimum federal requirements. The proposed amendments would ensure that the Commission's regulations meet the minimum federal requirements for Class VI UIC wells.

The Commission proposes amendments in §5.101 to remove language that references the Commission having jurisdiction over only a portion of the program.

The Commission proposes to amend §5.102 to add terms defined in HB 1284 and to add other terms included in the federal Class VI UIC regulations. The Commission proposes to add a definition for "offshore" to reflect the definition included in HB 1284. The Commission proposes to add definitions for "casing," "cementing," "Class VI well," "draft permit," "exempted aquifer," "flow rate," "formation," "injection well," "lithology," "packer," "permit," "plugging," "stratum," "surface casing," and "well injection" for consistency with the federal Class VI UIC regulations.

In §5.201, the Commission proposes to amend subsection (a) to reflect the change in jurisdiction under HB 1284 and to clarify that the Commission has jurisdiction over all geologic storage of anthropogenic carbon dioxide and the injection of anthropogenic carbon dioxide in the state, both onshore and offshore.

The Commission proposes amendments in §5.201(b) to add a title to the subsection and to include the factors that the Commission will consider when determining whether there is an increased risk to underground sources of drinking water such that a Class VI permit is required.

The Commission proposes new §5.201(c) to clarify that Subchapter B of Chapter 5 does not apply to the disposal of acid gas waste generated from oil and gas activities from a single lease, unit, field, or gas processing facility. Injection of acid gas that contains carbon dioxide and was generated as part of oil and gas processing may continue to be appropriately permitted as Class II injection. The potential need to transition from Class II to Class VI will be based on the increased risk to underground sources of drinking water related to significant storage of carbon dioxide in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. The Commission will consider similar factors enumerated in §5.201(b) when determining whether there is such an increased risk.

The Commission proposes to amend §5.201(d), currently subsection (c), to add language from HB 1284 to clarify that this subchapter applies regardless of whether the well was initially completed for the purpose of injection and geologic storage of anthropogenic carbon dioxide or was initially completed for another purpose and is converted to the purpose of injection and geologic storage of anthropogenic carbon dioxide except that the Commission may not issue a permit under this subchapter for the conversion of a previously plugged and abandoned Class I injection well, including any associated waste plume, to a Class VI injection well.

The Commission proposes new §5.201(e) to allow for the expansion of the areal extent of an aquifer exemption for a Class II enhanced recovery well for the exclusive purpose of Class VI injection for geologic storage in accordance with 40 Code of Federal Regulations (CFR) §146.4, relating to criteria for exempted aquifers. The Commission also proposes to adopt 40 CFR §144.7, relating to identification of underground sources of drinking water and exempted aquifers, and §146.4 by reference. Title 40 CFR §144.7 requires protection of aquifers and parts of aquifers that meet the definition of "underground source of drinking water" in 40 CFR §144.3. The section also provides for the designation of certain aquifers as exempt aquifers. Title 40 CFR §146.4 outlines the criteria an aquifer must meet for it to be designated exempt. The aquifer must not currently serve as a source of drinking water and must show it will not in the future serve as a source of drinking water because of one or more reasons listed in §146.4(b). The Commission proposes an effective date of July 1, 2022, as an estimated date for which the federal regulations will be adopted by reference. The Commission will adopt this section with a change to indicate the actual effective date.

The Commission proposes new §5.201(f) to provide for a waiver from the Class VI injection depth requirements for geologic storage to allow injection into non-USDW formations while ensuring that USDWs above and below the injection zone are protected from endangerment. The Commission also proposes to adopt 40 CFR §146.95, relating to Class VI injection depth waiver requirements, by reference. Title 40 CFR §146.95 requires that an operator seeking a waiver submit a supplemental report with its permit application. The section also specifies the required elements of the supplemental report. As with subsection (e), the effective date is proposed as July 1, 2022, but the Commission will include the correct effective date at the time of adoption.

The Commission proposes new §5.201(g) to state that the regulations do not apply to the injection of any CO2 stream that meets the definition of a hazardous waste.

Finally, in §5.201, the Commission proposes to redesignate existing subsections (d) and (e) as new subsection (h) and (i), with no other changes.

In §5.202(a), the Commission proposes wording to require a storage operator to obtain a permit before engaging in certain activities and proposes new paragraph (2) regarding when injection may begin.

The Commission proposes to amend §5.202(d) to include language in the federal regulations at 40 CFR §124.5, relating to modification, revocation and reissuance, or termination of permits, and §144.39(a), relating to modification or revocation and reissuance of permits. Proposed new subsection (d)(1) states that permits issued pursuant to this subsection are subject to review by the Commission and allows any interested person to request that the Commission review a permit for one or more of several reasons. The request must be in writing and must contain facts to support the request. The Commission may review the permit if it determines that the request may have merit or at the Commission's initiative.

The Commission proposes new subsection (d)(2), redesignated from current subsection (d)(1), to incorporate requirements of 40 CFR §144.39(a), relating to causes for modification or for revocation and reissuance. These causes include material and substantial alterations or additions to the permitted facility or activity, new information, new regulations, and modification of compliance schedules. The Commission proposes new language to state that if the Director of the Oil and Gas Division or the director's delegate (hereinafter "director") tentatively decides to modify or revoke and reissue a permit, the director shall prepare a draft permit incorporating the proposed changes, and to clarify that the director may request additional information and, in the case of a modified permit, may require the submission of an updated application. In the case of revoked and reissued permits, the director shall require the submission of a new application.

The Commission also proposes to add language in subsection (d)(2)(A)(vii) to state that in a permit modification, only those conditions to be modified shall be reopened when a new draft permit is prepared and all other aspects of the existing permit shall remain in effect for the duration of the unmodified permit. When a permit is revoked and reissued under this section, the entire permit is reopened and subject to revision just as if the permit had expired and was being reissued. During any revocation and reissuance proceeding, the permittee shall comply with all conditions of the existing permit until a new final permit is reissued.

The Commission proposes to add new subsection (d)(2)(A)(viii) to clarify that, upon the consent of the permittee, the director may modify a permit to make the corrections or allowances for changes in the permit, without following the procedures of §5.202(e) and §5.204, to correct typographical errors; require more frequent monitoring or reporting by the permittee; change an interim compliance date in a schedule of compliance, provided the new date is not more than 120 days after the date specified in the existing permit and does not interfere with attainment of the final compliance date requirement; allow for a change in ownership or operational control of a facility where the director determines that no other change in the permit is necessary, provided that a written agreement containing a specific date for transfer of permit responsibility, coverage, and liability between the current and new permittees has been submitted to the director; change quantities or types of fluids injected which are within the capacity of the facility as permitted and, in the judgment of the director, would not interfere with the operation of the facility or its ability to meet the permit conditions; change construction requirements approved by the director pursuant to §5.206, provided that any such alteration shall comply with the requirements of this subchapter; amend a plugging and abandonment plan which has been updated under §5.203(k); or amend an injection well testing and monitoring plan, plugging plan, post-injection site care and site closure plan, or emergency and remedial response plan where the modifications merely clarify or correct the plan, as determined by the director.

The Commission proposes new §5.202(d)(2)(B) to make it consistent with the requirements in 40 CFR §144.40, relating to termination of permits, and includes the causes that could lead to termination of a permit during its term or to deny renewal of a permit consistent with 40 CFR §144.40. The proposed new subparagraph also requires the director to issue an intent to terminate a permit, draft permit and fact sheet and provide for public comment in terminating any permit.

The Commission proposes to delete existing subsection (d)(1)(A) - (E) because the reasons for modifying or revoking and reissuing a permit are enumerated in proposed new subsection (d)(2).

The Commission proposes to add new §5.202(d)(3) to state that the suitability of a facility location will not be considered at the time of permit modification or revocation and reissuance unless new information or standards indicate that a threat to human health or the environment exists which was unknown at the time of permit issuance.

The Commission proposes to renumber current §5.202(d)(2) as new subsection (d)(4).

The Commission proposes to amend the title of §5.202 based on new subsection (e), which is proposed to comply with 40 CFR §124.6, relating to draft permits, and 40 CFR §124.8, relating to fact sheet.

In §5.203, the Commission proposes to amend §5.203(a) to add requirements under 40 CFR §146.91(e), relating to reporting requirements, that operators of Class VI wells must submit geologic sequestration project information directly to EPA in an electronic format approved by EPA, regardless of whether a state has primacy for the Class VI program. Such data includes the permit application and associated data, as well as all required reports, submittals, and notifications. As of the time of this proposal, EPA is requiring the use of its Geologic Sequestration Data Tool (GSDT), which is a centralized, web-based system that receives, stores, and manages Class VI data, and satisfies the Class VI electronic reporting requirement. Whether or not the State has primacy for the Class VI UIC program, an applicant is required to submit to EPA all application and reporting information through the GSDT. The Commission plans to access Class VI information through the GSDT; the Commission will not develop or require the use of a separate online system.

The Commission proposes new wording in subsection (a)(1)(B) consistent with federal regulations at 40 CFR §144.32(a), relating to requirements for signatories to permit applications, and proposes new wording in subsection (a)(1)(C) consistent with federal regulations at 40 CFR §144.32(d), relating to certification of an application or report.

The Commission proposes new §5.203(a)(2)(B) to clarify that when a geologic storage facility is owned by one person but is operated by another person, it is the operator's duty to file an application for a permit. The federal regulation at 40 CFR §144.31 relating to application for permit; authorization by permit, references "owner or operator;" however, the Commission holds the operator of the well, as identified by the Commission's Form P-4 (Certificate of Compliance and Transportation Authority), responsible.

The Commission proposes new §5.203(a)(2)(C) to add language consistent with 40 CFR §144.31(e)(6), relating to application for permit; authorization by permit, to require that an application include a listing of all relevant permits or construction approvals for the facility received or applied for under federal or state environmental programs.

The Commission proposes new §5.203(a)(2)(D) to reflect changes made by HB 1284 to Texas Water Code, §27.0461, to require that an applicant under this subchapter submit a letter of determination from TCEQ concluding that drilling and operating a Class VI injection well or constructing or operating a geologic storage facility will not impact or interfere with any previous or existing Class I injection well, including any associated waste plume, or any other injection well authorized or permitted by TCEQ.

The Commission proposes new §5.203(a)(5) regarding the requirement that, if required under Occupations Code, Chapter 1001, relating to Texas Engineering Practice Act, or Chapter 1002, relating to Texas Geoscience Practice Act, respectively, a licensed professional engineer or geoscientist must conduct the geologic and hydrologic evaluations required under this subchapter and must affix the appropriate seal on the resulting reports of such evaluations.

The Commission proposes to amend §5.203(d)(1)(A)(i)(III) to clarify that the initial delineation of the area of review must be estimated from initiation of injection until the plume movement ceases, for a minimum of 10 years after the end of the injection period proposed by the applicant.

The Commission proposes to amend §5.203(e)(1)(B)(i) to clarify that the operator must ensure that injection wells are cased and the casing is cemented in compliance with §3.13 of this title (relating to Casing, Cementing, Drilling, and Completion Requirements), in addition to the requirements of this section.

The Commission proposes to amend §5.203(h)(1)(B) to clarify that internal mechanical integrity must be demonstrated by pressure testing of the tubing casing annulus.

The Commission proposes to amend §5.203(h)(1)(D) to reflect the federal standard in 40 CFR §146.89, relating to mechanical integrity, and §146.90(e), relating to testing and monitoring requirements, that, at least once per year until the injection well is plugged, amended from the current text which says five years, the operator must confirm external mechanical integrity using an approved method.

The Commission proposes to amend §5.203(h)(1)(E) to clarify the requirement to test injection wells after any workover that disturbs the seal between the tubing, packer, and casing to verify the internal mechanical integrity of the tubing and long string casing.

The Commission proposes to amend §5.203(h)(2) to delete language regarding test frequency of five years to make the language consistent with the federal requirements in 40 CFR §146.89 and §146.90 for internal and external mechanical integrity testing.

The Commission proposes to amend §5.203(h)(2)(E) to clarify that some alternative test methods may need to be approved by the Administrator of EPA consistent with 40 CFR §146.89(e).

The Commission proposes to add new §5.203(j)(2)(F) to require that a plan for monitoring, sampling, and testing after initiation of operation must include a pressure fall-off test at least once every five years unless more frequent testing is required by the director based on site-specific information consistent with federal requirements at 40 CFR §146.90(f), relating to injection well plugging.

The Commission proposes to amend §5.203(k)(1) to add the specific information required under 40 CFR §146.92(b), relating to injection well plugging, to be included in a well plugging plan.

The Commission proposes to amend §5.203(m) to add language to conform with the federal regulations. Following cessation of injection, the federal rules at 40 CFR §146.93, relating to post injection site care and site closure, require that the operator continue to conduct monitoring for at least 50 years. However, the director may approve, in consultation with EPA, an alternative timeframe other than the 50-year default, if the operator can demonstrate during the permitting process that an alternative timeframe is appropriate and ensures non-endangerment of USDWs. The federal rules require that the demonstration be based on significant, site-specific data and information and contain substantial evidence that the geologic storage project will no longer pose a risk of endangerment to USDWs at the end of the alternative post injection site care timeframe. Current Commission rules do not include a 50-year default post injection site care period. To meet the minimum federal requirements, the Commission proposes to amend §5.203(m) to include the data and information required to make a demonstration that an alternative timeframe is appropriate and ensures non-endangerment of USDWs. The proposed amendment would require additional effort for each Class VI permit application, but would provide a more appropriate, site-specific post injection site care timeframe. The Commission anticipates that the benefit of this change would be reflected in the costs associated with post injection site care monitoring. The Commission requests comments on whether the Commission should finalize the rules as proposed or adopt the federal 50-year default timeframe with the option for an alternative timeframe. In addition, the Commission requests comment on whether the Commission should consider a minimum post injection site care monitoring period.

In §5.204, the Commission proposes to amend the title from Notice and Hearing to Notice of Permit Actions and Public Comment Period; other proposed amendments comply with the federal requirements at 40 CFR 124.10, public notice of permit actions and public comment period. The federal regulations require that the Commission provide notice of a draft permit. Therefore, the Commission proposes to delete language regarding operator notice of an application under this subsection. The Commission also proposes to include language stating that notice must include information satisfying the requirements of 40 CFR §124.10(d)(1).

The Commission also proposes new §5.204(a)(5) to require that the applicant identify whether any portions of the area of review encompass an environmental justice (EJ) or Limited English Proficiency (LEP) area using U.S. Census Bureau 2018 American Community Survey data. If the area of review incudes an EJ or LEP area, the proposed new wording includes the actions that the applicant shall conduct.

The Commission proposes to amend current §5.204(c) to redesignate it as subsection (b), to rename the subsection, and to make the requirements consistent with federal regulations at 40 CFR §124.12, relating to public hearings. Proposed new subsection (b)(1) clarifies that during the public comment period, an interested person may submit written comments on the draft permit and may request a hearing if one has not already been scheduled, that reasonable limits may be set upon the time allowed for oral statements, and the submission of statements in writing may be required; and that 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. The Commission proposes new wording in subsection (b)(2) to state that the director must hold a public hearing whenever the director finds, on the basis of requests, a significant degree of public interest in a draft permit; and may also hold a public hearing at the director's discretion, whenever, for instance, such a hearing might clarify one or more issues involved in the permit decision.

In §5.205, the Commission proposes removing the $5 million cap in subsection (a)(4) and other nonsubstantive changes.

In §5.206, the Commission proposes amendments to make the section consistent with the federal requirements. The Commission proposes new subsection (a) consistent with 40 CFR §146.92(b) to require that all conditions applicable to all permits be incorporated into the permits either expressly or by reference. If incorporated by reference, a specific citation to these regulations must be given in the permit. The requirements are directly enforceable regardless of whether the requirement is a condition of the permit.

The Commission proposes to amend current §5.206(a), redesignated as subsection (b), to reorganize the subsection and to add new paragraph (8) requiring that an applicant provide a letter of determination from TCEQ concluding that drilling and operating an anthropogenic carbon dioxide injection well for geologic storage or constructing or operating a geologic storage facility will not impact or interfere with any previous or existing Class I injection well, including any associated waste plume, or any other injection well authorized or permitted by TCEQ, consistent with HB 1284.

The Commission proposes to amend current subsection §5.206(b), redesignated as subsection (c), to require written notice to the director 30 days, rather than 48 hours, prior to conducting any well workover that involves running tubing and setting packers, beginning any workover or remedial operation, or conducting any required pressure tests or surveys, and to clarify that no such work may commence until approved by the director.

The Commission proposes to amend current §5.206(c)(2)(C), redesignated as subsection (d)(2)(C), to clarify that the Commission will include in any permit it might issue a limit of 90 percent of the fracture pressure to ensure that the injection pressure does not initiate new fractures or propagate existing fractures in the injection zone(s). In no case may injection pressure initiate fractures in the confining zone(s) or cause the movement of injection or formation fluids that endangers a USDW.

The Commission proposes to amend §5.206(d)(2)(D) to include a requirement that the operator maintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines that such requirement might harm the integrity of the well or endanger USDWs.

The Commission proposes to amend current subsection §5.206(d), redesignated as subsection (e), to reorganize the subsection and to add a new paragraph (2) requiring that all permits specify requirements concerning the proper use, maintenance, and installation, when appropriate, of monitoring equipment or methods; required monitoring including type, intervals, and frequency sufficient to yield data that are representative of the monitored activity including when required, continuous monitoring; and applicable reporting requirements. Reporting shall be no less frequent than specified in this subchapter.

The Commission proposes to amend current §5.206(e)(4), redesignated as subsection (f), to add the term "significant" consistent with the language in federal regulations at 40 CFR §146.89(g).

The Commission proposes to amend current subsection §5.206(h), redesignated as subsection (i), consistent with the federal requirements at 40 CFR §146.91(d) to require that operators notify the Director in writing 30 days in advance of any planned workover, any planned stimulation activities, other than stimulation for formation testing conducted; and any other planned test of the injection well conducted by the permittee.

The Commission proposes to amend current subsection §5.206(j), redesignated as subsection (k), to add wording in paragraph (1)(B) to require that any amendments to the post-injection site care and site closure plan must be approved by the director, be incorporated into the permit, and are subject to the permit modification requirements at §5.202 of this subchapter, as appropriate. The Commission adds this language consistent with federal regulations at 40 CFR §146.93(a)(3), relating to post-injection site care and site closure. The Commission also proposes to amend paragraph (4) to clarify that notice by the operator to the director before closure must be in writing consistent with federal regulations at 40 CFR §146.93(d).

The Commission proposes to amend current subsection §5.206(l), redesignated as subsection (m), to clarify that the operator must retain records collected during the post-injection storage facility care period for 10 years rather than five years following storage facility closure consistent with federal requirements at 40 CFR §146.93(h).

The Commission proposes to amend current subsection §5.206(n), redesignated as subsection (o), to reorganize the subsection and to replace the term "suspended" with "terminated." The Commission also proposes new paragraph (2) consistent with federal regulations at 40 CFR Part 144, Subpart E, relating to permit conditions. Federal regulations require that permits for Class VI injection wells include conditions relating to the duty to comply, the need to halt or reduce activity not a defense in an enforcement action, the need take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance, the need to properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the permittee to achieve compliance with the conditions of this permit; the need for proper operation and maintenance, including effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures; the issuance of a permit does not convey any property rights of any sort, or any exclusive privilege; the issuance of a permit does not authorize any injury to persons or property or invasion of other private rights, or any infringement of State or local law or regulations; the duty to provide information; the need to allow the Commission to enter and inspect any Class VI facility or where records are kept, have access to and copy, during reasonable working hours, any records required to be kept under the conditions of the permit; sample or monitor any substance or parameter for the purpose of assuring compliance with the permit or as otherwise authorized by the Texas Water Code, §27.071, or the Texas Natural Resources Code, §91.1012; and the inclusion of a schedule of compliance, when appropriate.

The Commission also proposes to amend subsection §5.206(o) to add new paragraph (2)(G) to state that the permittee of a geologic storage well will be required to coordinate with any operator planning to drill through the area of review (AOR) to explore for oil and gas or geothermal resources. The Commission plans to designate the AOR of geologic storage projects on the GIS maps used by the Drilling Permits Section to alert the section of a drilling permit application for a well within the AOR. A condition will be included in the drilling permit requiring the drilling permittee to notify and coordinate with the permittee of the geologic storage project of its plans to drill.

The proposed amendments to §5.206(o)(2)(G) are made pursuant to the Commission's authority in Texas Natural Resources Code Chapters 85 and 91, as well as Water Code Chapter 27.

Texas Natural Resource Code, §85.042(b) requires the Commission to make and enforce rules either general in their nature or applicable to particular fields where necessary for the prevention of actual waste of oil or operations in the field dangerous to life or property. Section 85.046 defines "waste" to mean, "among other things, specifically includes: ... underground waste or loss, however caused and whether or not the cause of the underground waste or loss is defined in this section." Section 85.202 requires the Commission to include rules and orders to prevent waste of oil and gas in drilling and producing operations, to require wells to be drilled and operated in a manner that will prevent injury to adjoining property; and to prevent oil and gas and water from escaping from the strata in which they are found into other strata. Section 91.015 states that "Operators and drillers that drill for oil or gas shall use every possible precaution in accordance with the most approved methods to stop and prevent waste of oil, gas, or both oil and gas in drilling operations and shall not wastefully use oil or gas or allow oil or gas to leak or escape from natural reservoirs." Section 91.101 requires the Commission to adopt and enforce rules and orders and may issue permits relating to the drilling of exploratory wells and oil and gas wells to prevent pollution of surface water or subsurface water,

Texas Water Code, §27.051 authorizes the Commission to issue a permit for the geologic storage of carbon dioxide if it finds, among other things, that the injection and geologic storage of anthropogenic carbon dioxide will not endanger or injure any oil, gas, or other mineral formation, that, with proper safeguards, both ground and surface fresh water can be adequately protected from carbon dioxide migration or displaced formation fluids, and that the injection of anthropogenic carbon dioxide will not endanger or injure human health and safety.

In §5.207, the Commission proposes to amend subsection (a)(2)(C)(iii) and (iv) to add mass and monthly annulus fluid volume to the items that the operator must include on the semi-annual report consistent with federal regulations at 40 CFR §146.91.

The Commission proposes to amend §5.207(a)(2)(D) to move the language in subsection (a)(2)(D)(vi)(III) to new subsection (a)(3) and proposes to clarify that the director will require such revisions after significant changes to the facility.

The Commission proposes to amend §5.207(b) to clarify that the results of internal mechanical integrity tests are to be reported on Form H-5, and to require that operators submit all required reports, submittals, and notifications under this subchapter to the director and to EPA in an electronic format approved by the EPA administrator.

The Commission proposes new subsection (c) to reflect federal regulations for signatories to reports at 40 CFR §144.32(b).

The Commission proposes new subsection (d) to require that all reports and other information be certified consistent with federal regulations at 40 CFR §144.32(d).

The Commission proposes to amend current subsection (c), redesignated as subsection (e), to clarify that the operator must retain records, including modeling inputs and data to support area of review calculations and integrity test results, for at least 10 years, rather than five years, consistent with federal regulations at 40 CFR §146.84(g), relating to area of review and corrective action.

Leslie Savage, Chief Geologist, Oil and Gas Division, has determined that for each year of the first five years that the proposed amendments will be in effect, there will be no foreseeable implications relating to cost or revenues of state governments or local governments as a result of enforcing or administering the amendments. Commission staff responsible for permitting of disposal wells will review information required to be submitted with each disposal well application; however, these additional duties will be performed by existing personnel and within current budget constraints, resulting in no additional costs to the agency.

Ms. Savage 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. 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 is not approved to enforce the Class VI program, the EPA will enforce the same requirements. The proposed amendments to Commission rules do not create any additional economic costs for persons required to comply.

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 Commission's evaluation of information regarding geologic storage of anthropogenic carbon dioxide, and consideration of other factors related to 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. Operators of oil and gas wells fall within the category for crude petroleum and natural gas extraction. This category is listed on the Texas Comptroller of Public Accounts website page entitled "HB 3430 Reporting Requirements-Determining Potential Effects on Small Businesses" as business type 2111 (Oil & Gas Extraction), for which there are listed 2,784 companies in Texas. This source further indicates that 2,582 companies (92.7%) are small businesses or micro-businesses as defined in Texas Government Code, §2006.001.

Based on the information available to the Commission regarding oil and gas operators, 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 is 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 §505.11(b)(4), nor would they affect any action or authorization identified in Coastal Coordination Act Implementation Rules, 31 TAC §505.11(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 adopted pursuant to House Bill 1284 (87th Legislature, Regular Session) could create a new government program because the proposed amendments will allow the Commission to apply for state primacy such that the state may administer a Class VI UIC program. However, the EPA must first approve the Commission's application for primacy. The proposed amendments would not create a new 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. If the Commission's primacy application is approved, the state will administer the Class VI UIC program rather than the EPA. Therefore, the proposed amendments could create an increase in fees paid to the Commission. The Commission does not propose amending the fees contained in §5.205 but may receive those fees if it is approved to administer the Class VI UIC program. 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 and on the Commission's application to EPA for primacy of the Class VI UIC program. The first part of the hearing will consist of a brief overview by Commission staff regarding the proposed rule amendments and the Commission's application for enforcement primacy of the Class VI UIC program. The second part of the hearing will consist of public comment on both the proposed amendments and the primacy application.

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 to discuss the proposal 30 minutes prior to the hearing. 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 Monday, June 20, 2022. 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.

The Commission proposes the amendments pursuant to House Bill 1284 (HB 1284, 87th Legislature, R.S., 2021), which gives the Railroad Commission of Texas sole jurisdiction over carbon sequestration wells; 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, as enacted by SB 1387 (81st Texas Legislature, R.S., 2009), relating to authorization for multiple or alternative uses of wells; Texas Water Code, Chapter 27, Subchapter C-1, as enacted by SB 1387 (81st Texas Legislature, R.S., 2009), 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; and Texas Water Code, Chapter 120, as enacted by SB 1387 (81st Texas Legislature, R.S., 2009), 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.

SUBCHAPTER A. GENERAL PROVISIONS

16 TAC §5.101, §5.102

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

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

§5.101.Purpose.

The purpose of this chapter is to implement the [portion of the] state program for geologic storage of anthropogenic CO2 [over which the Railroad Commission has jurisdiction] consistent with state and federal law related to protection of underground sources of drinking water.

§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, as a result of actions proposed by an application for a geologic storage facility permit or an amendment or modification of an existing geologic storage facility permit, has suffered or may suffer actual injury or economic damage other than as a member of the general public.

(2) Anthropogenic carbon dioxide (CO2)--

(A) CO2 that would otherwise have been released into the atmosphere that has been:

(i) separated from any other fluid stream; or

(ii) captured from an emissions source, including:

(I) an advanced clean energy project as defined by Health and Safety Code, §382.003, or another type of electric generation facility; or

(II) an industrial source of emissions; and

(iii) any incidental associated substance derived from the source material for, or from the process of capturing, CO2 described by clause (i) of this subparagraph; and

(iv) any substance added to CO2 described by clause (i) of this subparagraph to enable or improve the process of injecting the CO2; and

(B) does not include naturally occurring CO2 that is produced, acquired, recaptured, recycled, and reinjected as part of enhanced recovery operations.

(3) Anthropogenic CO2 injection well--An injection well used to inject or transmit anthropogenic CO2 into a reservoir.

(4) Aquifer--A geologic formation, group of formations, or part of a formation that is capable of yielding a significant amount of water to a well or spring.

(5) Area of review (AOR)--The subsurface three-dimensional extent of the CO2 stream plume and the associated pressure front, as well as the overlying formations, any underground sources of drinking water overlying an injection zone along with any intervening formations, and the surface area above that delineated region.

(6) Carbon dioxide (CO2) plume--The underground extent, in three dimensions, of an injected CO2stream.

(7) Carbon dioxide (CO2) stream--CO2 that has been captured from an emission source, incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. The term does not include any CO2 stream that meets the definition of a hazardous waste under 40 CFR [Code of Federal Regulations] Part 261.

(8) Casing--A pipe or tubing of appropriate material, of varying diameter and weight, lowered into a borehole during or after drilling in order to support the sides of the hole and thus prevent the walls from caving, to prevent loss of drilling mud into porous ground, or to prevent water, gas, or other fluid from entering or leaving the hole.

(9) Cementing--The operation whereby a cement slurry is pumped into a drilled hole and/or forced behind the casing.

(10) Class VI well--Any well used to inject anthropogenic CO2 specifically for the purpose of the long-term containment of a gaseous, liquid, or supercritical CO2 in subsurface geologic formations.

(11) Code of Federal Regulations (CFR)--The codification of the general and permanent rules published in the Federal Register by the executive departments and agencies of the federal government.

(12) [(8)] Commission--A quorum of the members of the Railroad Commission of Texas convening as a body in open meeting.

(13) [(9)] Confining zone--A geologic formation, group of formations, or part of a formation that is capable of limiting fluid movement from an injection zone.

(14) [(10)] 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.

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

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

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

(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.

(19) [(14)] 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.

(20) 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.

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

(22) 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.

(23) 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.

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

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

(26) [(18)] Geologic storage--The long-term containment of anthropogenic CO2 in a reservoir.

(27) [(19)] Geologic storage facility or storage facility--The underground reservoir, 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, 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[, and pressure fronts]. 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.

(28) [(20)] 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.

(29) Injection well--A well into which fluids are injected.

(30) Lithology--The description of rocks on the basis of their physical and chemical characteristics.

(31) [(21)] 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.

(32) [(22)] 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.

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

(34) [(23)] Operator--A person, acting for itself [himself] 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.

(35) Packer--A device lowered into a well to produce a fluid-tight seal.

(36) Permit--An authorization, license, or equivalent control document issued by the Commission to implement the requirements of chapter.

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

(38) 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.

(39) [(25)] 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.

(40) [(26)] 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.

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

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

(43) Surface casing--The first string of well casing to be installed in the well.

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

(45) [(29)] Underground source of drinking water (USDW)--An aquifer or its portion which is not an exempt aquifer as defined in 40 CFR [Code of Federal Regulations] §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.

(46) Well injection--The subsurface emplacement of fluids through a well.

(47) [(30)] 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.

(48) [(31)] 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 May 3, 2022.

TRD-202201723

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: June 19, 2022

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


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

16 TAC §§5.201 - 5.207

The Commission proposes the amendments pursuant to House Bill 1284 (HB 1284, 87th Legislature, R.S., 2021), which gives the Railroad Commission of Texas sole jurisdiction over carbon sequestration wells; 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, as enacted by SB 1387 (81st Texas Legislature, R.S., 2009), relating to authorization for multiple or alternative uses of wells; Texas Water Code, Chapter 27, Subchapter C-1, as enacted by SB 1387 (81st Texas Legislature, R.S., 2009), 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; and Texas Water Code, Chapter 120, as enacted by SB 1387 (81st Texas Legislature, R.S., 2009), 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; and Texas Water Code, Chapters 27 and 120.

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

§5.201.Applicability and Compliance.

(a) Scope of jurisdiction. This subchapter applies to the geologic storage and associated injection of anthropogenic CO2 in this state, both onshore and offshore[, and the injection of anthropogenic CO2 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. A reservoir that may be productive means an identifiable geologic unit that has had production in the past, which is similar to productive or previously productive reservoirs along the same or a similar trend, or potentially contains oil, gas, or geothermal resources based on analysis of geophysical and/or seismic data].

(b) Injection of CO2 for enhanced recovery.

(1) This subchapter does not apply to the injection of fluid through the use of an injection well regulated under §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) for the primary purpose of enhanced recovery operations from which there is reasonable expectation of more than insignificant future production volumes of oil, gas, or geothermal energy and operating pressures are no higher than reasonably necessary to produce such volumes or rates. However, the operator of an enhanced recovery project may propose to also permit the enhanced recovery project as a CO2 geologic storage facility simultaneously.

(2) If the director determines that an injection well regulated under §3.46 of this title should be regulated under this subchapter because the injection well is no longer being used for the primary purpose of enhanced recovery operations or there is an increased risk to USDWs, the director must notify the operator of such determination and allow the operator at least 30 days to respond to the determination and to file an application under this subchapter or cease operation of the well. In determining if there is an increased risk to USDWs, the director shall consider the following factors:

(A) increase in reservoir pressure within the injection zone;

(B) increase in CO2 injection rates;

(C) decrease in reservoir production rates;

(D) distance between the injection zone and USDWs;

(E) suitability of the enhanced oil or gas recovery AOR delineation;

(F) quality of abandoned well plugs within the AOR;

(G) the storage operator's plan for recovery of CO2 at the cessation of injection;

(H) the source and properties of injected CO2; and

(I) any additional site-specific factors as determined by the Commission.

(3) This [Additionally, this] subchapter does not preclude an enhanced oil recovery project operator from opting into a regulatory program that provides carbon credit for anthropogenic CO2 sequestered through the enhanced recovery project.

(c) Injection of acid gas. This subchapter does not apply to the disposal of acid gas generated from oil and gas activities from a single lease, unit, field, or gas processing facility. Injection of acid gas that contains CO2 and that was generated as part of oil and gas processing may continue to be permitted as a Class II injection well. The potential need to transition a well from Class II to Class VI shall be based on the increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. In determining if there is an increased risk to USDWs, the director shall consider the factors listed in subsection (b)(2)(A), (B), and (D) through (I) of this section.

(d) [(c)] This subchapter applies to a well that is authorized as or converted to an anthropogenic CO2 injection well for geologic storage (a Class VI injection well). This subchapter applies regardless of whether the well was initially completed for the purpose of injection and geologic storage of anthropogenic CO2 or was initially completed for another purpose and is converted to the purpose of injection and geologic storage of anthropogenic CO2, except that the Commission may not issue a permit under this subchapter for the conversion of a previously plugged and abandoned Class I injection well, including any associated waste plume, to a Class VI injection well.

(e) Expansion of aquifer exemption. The areal extent of an aquifer exemption for a Class II enhanced recovery well may be expanded for the exclusive purpose of Class VI injection for geologic storage if the aquifer does not currently serve as a source of drinking water; and the total dissolved solids content is more than 3,000 milligrams per liter (mg/l) and less than 10,000 mg/l; and it is not reasonably expected to supply a public water system in accordance with 40 CFR §146.4. An operator seeking such an expansion shall submit, concurrent with the permit application, a supplemental report that complies with 40 CFR §144.7(d). The Commission adopts 40 CFR §144.7 and §146.4 by reference, effective July 1, 2022.

(f) Injection depth waiver. An operator may seek a waiver from the Class VI injection depth requirements for geologic storage to allow injection into non-USDW formations while ensuring that USDWs above and below the injection zone are protected from endangerment. An operator seeking a waiver of the requirement to inject below the lowermost USDW shall submit, concurrent with the permit application, a supplemental report that complies with 40 CFR §146.95. The Commission adopts 40 CFR §146.95 by reference, effective July 1, 2022.

(g) This subchapter does not apply to the injection of any CO2 stream that meets the definition of a hazardous waste.

(h) [(d)] If a provision of this subchapter conflicts with any provision or term of a Commission order or permit, the provision of such order or permit controls.

(i) [(e)] The operator of a geologic storage facility must comply with the requirements of this subchapter as well as with all other applicable Commission rules and orders, including the requirements of Chapter 8 of this title (relating to Pipeline Safety Regulations) for pipelines and associated facilities.

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

(a) Permit required.

(1) A person shall [may] not begin drilling or operating an anthropogenic CO2 injection well for geologic storage or constructing or operating a geologic storage facility regulated under this subchapter without first obtaining the necessary permits [permit(s)] from the Commission. Following receipt of a geologic storage facility permit issued under this subchapter, the storage operator shall obtain a permit to drill, deepen, or convert a well for storage purposes in accordance with §3.5 of this title (relating to Application to Drill, Deepen, Reenter, or Plug Back).

(2) A person may not begin injection until:

(A) construction of the well is complete;

(B) the operator has submitted to the director notice of completion of construction;

(C) the Commission has inspected or otherwise reviewed the injection well and finds it is in compliance with the conditions of the permit; and

(D) the director has issued a permit to operate the injection well.

(b) Permit amendment.

(1) An operator must file an application to amend an existing geologic storage facility permit with the director:

(A) prior to expanding the areal extent of the storage reservoir;

(B) prior to increasing the permitted injection pressure;

(C) prior to adding injection wells; or

(D) at any time that conditions at the geologic storage facility materially deviate from the conditions specified in the permit or permit application.

(2) Compliance with plan amendments required by this subchapter does not necessarily constitute a material deviation in conditions requiring an amendment of the permit.

(c) Permit transfer. An operator may transfer its geologic storage facility permit to another operator if the requirements of this subsection are met. A new operator shall [may] not assume operation of the geologic storage facility without a valid permit.

(1) Notice. An applicant must submit written notice of an intended permit transfer to the director at least 45 days prior to the date the transfer of operations is proposed to take place, unless such action could trigger U. S. Securities and Exchange Commission fiduciary and insider trading restrictions and/or rules.

(A) The applicant's notice to the director must contain:

(i) the name and address of the person to whom the geologic storage facility will be sold, assigned, transferred, leased, conveyed, exchanged, or otherwise disposed;

(ii) the name and location of the geologic storage facility and a legal description of the land upon which the storage facility is situated;

(iii) the date that the sale, assignment, transfer, lease conveyance, exchange, or other disposition is proposed to become final; and

(iv) the date that the transferring operator will relinquish possession as a result of the sale, assignment, transfer, lease conveyance, exchange, or other disposition.

(B) The person acquiring a geologic storage facility, whether by purchase, transfer, assignment, lease, conveyance, exchange, or other disposition, must notify the director in writing of the acquisition as soon as it is reasonably possible but not later than five business days after the date that the acquisition of the geologic storage facility becomes final. The director shall [may] not approve the transfer of a geologic storage facility permit until the new operator provides all of the following:

(i) the name and address of the operator from which the geologic storage facility was acquired;

(ii) the name and location of the geologic storage facility and a description of the land upon which the geologic storage facility is situated;

(iii) the date that the acquisition became or will become final;

(iv) the date that possession was or will be acquired; and

(v) the financial assurance required by this subchapter.

(2) Evidence of financial responsibility. The operator acquiring the permit must provide the director with evidence of financial responsibility satisfactory to the director in accordance with §5.205 of this title (relating to Fees, Financial Responsibility, and Financial Assurance).

(3) Transfer of responsibility. An operator remains responsible for the geologic storage facility until the director approves in writing the sale, assignment, transfer, lease, conveyance, exchange, or other disposition and the person acquiring the storage facility complies with all applicable requirements.

(d) Modification, revocation and reissuance, or termination [cancellation, or suspension] of a geologic storage facility permit.

(1) Permit review. Permits are subject to review by the Commission. Any interested person may request that the Commission review a permit issued under this subchapter for one of the reasons set forth in paragraph (2) of this subsection. All requests must be in writing and must contain facts or reasons supporting the request. If the Commission determines that the request may have merit or at the Commission's initiative for one or more of the reasons set forth in paragraph (2) of this subsection, the Commission may review the permit. An interested person includes:

(A) the storage operator;

(B) local governments having jurisdiction over land within the area of review; or

(C) any person who has suffered or will suffer actual injury or economic damage.

(2) [(1)]Action by the Commission [General]. The director may modify, revoke and reissue [suspend], or terminate [cancel ] a geologic storage facility permit after notice and opportunity for hearing under any of the following circumstances. [:]

(A) Causes for modification or for revocation and reissuance. The following may be causes for revocation and reissuance as well as modification:

(i) Alterations. There are material and substantial alterations or additions to the permitted facility or activity which occurred after permit issuance that justify the inclusion of permit conditions that are different from or absent in the existing permit.

(ii) New information. The director has received information that was not available at the time of permit issuance and would have justified the inclusion of different permit conditions at the time of issuance. This may include any increase greater than the permitted CO2 storage volume, and/or changes in the chemical composition of the CO2 stream,

(iii) New regulations. The standards or regulations on which the permit was based have been changed by promulgation of new or amended standards or regulations or by judicial decision after the permit was issued.

(iv) Compliance schedules. The director determines good cause exists for modification of a compliance schedule, such as an act of God, strike, flood, or materials shortage, or other events over which the permittee has little or no control and for which there is no reasonably available remedy.

(v) Basis for permit modification. The director shall modify the permit whenever the director determines that permit changes are necessary based on:

(I) a re-evaluation under §5.203(d) of this title (relating to Application Requirements);

(II) any amendments to the testing and monitoring plan under §5.203(j) of this subchapter;

(III) any amendments to the injection well plugging plan under §5.203(k) of this title;

(IV) any amendments to the post-injection site care and site closure plan under §5.203(m) of this title;

(V) any amendments to the emergency and remedial response plan under §5.203(l) of this title;

(VI) a review of monitoring and/or testing results conducted in accordance with permit requirements;

(VII) cause exists for termination under subparagraph (B) of this paragraph, and the director determines that modification or revocation and reissuance is appropriate;

(VIII) the director has received notification of a proposed transfer of the permit; or

(IX) a determination that the fluid being injected is a hazardous waste as defined in 40 CFR §261.3 either because the definition has been revised, or because a previous determination has been changed.

(vi) If the director tentatively decides to modify or revoke and reissue a permit, the director shall prepare a draft permit incorporating the proposed changes. The director may request additional information and, in the case of a modified permit, may require the submission of an updated application. In the case of revoked and reissued permits, the director shall require the submission of a new application.

(vii) In a permit modification, only those conditions to be modified shall be reopened when a new draft permit is prepared. All other aspects of the existing permit shall remain in effect for the duration of the existing permit. When a permit is revoked and reissued under this section, the entire permit is reopened just as if the permit had expired and was being reissued. During any revocation and reissuance proceeding, the permittee shall comply with all conditions of the existing permit until a new final permit is reissued.

(viii) Upon the consent of the permittee, the director may modify a permit to make the corrections or allowances for changes in the permit, without following the procedures of subsection (e) of this section, and §5.204 of this title (relating to Notice of Permit Actions and Public Comment Period), to:

(I) correct typographical errors;

(II) require more frequent monitoring or reporting by the permittee;

(III) change an interim compliance date in a schedule of compliance, provided the new date is not more than 120 days after the date specified in the existing permit and does not interfere with attainment of the final compliance date requirement;

(IV) allow for a change in ownership or operational control of a facility where the director determines that no other change in the permit is necessary, provided that a written agreement containing a specific date for transfer of permit responsibility, coverage, and liability between the current and new permittees has been submitted to the director;

(V) change quantities or types of fluids injected which are within the capacity of the facility as permitted and, in the judgment of the director, would not interfere with the operation of the facility or its ability to meet the permit conditions;

(VI) change construction requirements approved by the director pursuant to §5.206 of this title (relating to Permit Standards), provided that any such alteration shall comply with the requirements of this subchapter;

(VII) amend a plugging and abandonment plan which has been updated under §5.203(k) of this title; or

(VIII) amend an injection well testing and monitoring plan, plugging plan, post-injection site care and site closure plan, or emergency and remedial response plan where the modifications merely clarify or correct the plan, as determined by the director.

(B) Termination of permits.

(i) The following may be causes to terminate a permit during its term, or deny a permit renewal application:

(I) the permittee's failure to comply with any condition of the permit or applicable Commission orders or regulations;

(II) the permittee's failure in the application or during the permit issuance process to disclose fully all relevant facts, or the permittee's misrepresentation of any relevant facts at any time;

(III) fluids are escaping or are likely to escape from the injection zone;

(IV) USDWs are likely to be endangered as a result of the continued operation of the geologic storage facility; or

(V) a determination that the permitted activity endangers human health or the environment and can only be regulated to acceptable levels by permit modification or termination.

(ii) The director shall follow the applicable procedures in subsection (e) of this section, and §5.204 of this title, in terminating any permit under this section.

(iii) If the director tentatively decides to terminate a permit under this subchapter, where the permittee objects, the director shall issue a notice of intent to terminate. A notice of intent to terminate is a type of draft permit.

[(A) There is a material change in conditions in the operation of the geologic storage facility, or there are material deviations from the information originally furnished to the director. A change in conditions at a facility that does not affect the ability of the facility to operate without causing an unauthorized release of CO2 and/or formation fluids is not considered to be material;]

[(B) Underground sources of drinking water are likely to be endangered as a result of the continued operation of the geologic storage facility;]

[(C) There are substantial violations of the terms and provisions of the permit or of applicable Commission orders or regulations;]

[(D) The operator misrepresented material facts during the permit application or issuance process; or]

[(E) Fluids are escaping or are likely to escape from the injection zone.]

(3) Facility siting. Suitability of the facility location shall not be considered at the time of permit modification or revocation and reissuance unless new information or standards indicate that a threat to human health or the environment exists which was unknown at the time of permit issuance.

(4) [(2)] Emergency shutdown. Notwithstanding the provisions of paragraph (2) [(1)] of this subsection, in the event of an emergency that threatens endangerment to USDWs [underground sources of drinking water] or to life or property, or an imminent threat of uncontrolled release of CO2 , the director may immediately order suspension of the operation of the geologic storage facility until a final order is issued pursuant to a hearing, if any.

(e) Draft permit and fact sheet.

(1) Draft permit; notice of intent to deny.

(A) Once a geologic storage facility permit application is complete, the director shall decide whether to prepare a draft permit or to deny the application.

(B) If the director tentatively decides to deny the permit application, the director shall issue a notice of intent to deny. A notice of intent to deny the permit application is a type of draft permit which follows the same procedures as any draft permit prepared under this section. If the director's final decision is that the tentative decision to deny the permit application was incorrect, the director shall withdraw the notice of intent to deny and proceed to prepare a draft permit.

(C) If the director decides to prepare a draft permit, the draft permit shall contain the permit conditions required under §5.206 of this title (relating to Permit Standards).

(2) Fact sheet.

(A) The director shall prepare a fact sheet for every draft permit. The fact sheet shall briefly set forth the principal facts and the significant factual, legal, methodological and policy questions considered in preparing the draft permit.

(B) The director shall send this fact sheet to the applicant and, on request, to any other person.

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

(i) a brief description of the type of facility or activity which is the subject of the draft permit;

(ii) the quantity of CO2 proposed to be injected and stored;

(iii) the reasons why any requested variances or alternatives to required standards do or do not appear justified;

(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 date, time, and location of the storage facility permit hearing, if a hearing has been scheduled; and

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

(v) the name and telephone number of a person to contact for additional information.

§5.203.Application Requirements.

(a) General.

(1) Form and filing; signatories; certification.

(A) Form and filing. Each applicant for a permit to construct and operate a geologic storage facility must file an application with the division in Austin on a form prescribed by the Commission. The applicant must file [one copy of] the application and all attachments with the division and with EPA Region 6 in an electronic format approved by EPA. On the same date, the applicant must file one copy with each [the] appropriate district office [office(s)] and one copy with the Executive Director of the Texas Commission on Environmental Quality.

(B) Signatories to permit applications. An applicant must ensure that the application is executed by a party having knowledge of the facts entered on the form and included in the required attachments. All permit applications shall be signed as specified in this subparagraph:

(i) For a corporation, the permit application shall be signed by a responsible corporate officer. For the purpose of this section, a responsible corporate officer means a president, secretary, treasurer, or vice president of the corporation in charge of a principal business function, or any other person who performs similar policy- or decision making functions for the corporation, or the manager of one or more manufacturing, production, or operating facilities employing more than 250 persons or having gross annual sales or expenditures exceeding $25 million (in second-quarter 1980 dollars), if authority to sign documents has been assigned or delegated to the manager in accordance with corporate procedures.

(ii) For a partnership or sole proprietorship, the permit application shall be signed by a general partner or the proprietor, respectively.

(iii) For a municipality, State, Federal, or other public agency, the permit application shall be signed by either a principal executive officer or ranking elected official. [If otherwise required under Occupations Code, Chapter 1001, relating to Texas Engineering Practices Act, or Chapter 1002, relating to Texas Geoscientists Practices Act, respectively, a licensed professional engineer or geoscientist must conduct the geologic and hydrologic evaluations required under this section and must affix the appropriate seal on the resulting reports of such evaluations.]

(C) Certification. Any person signing a permit application or permit amendment application shall make the following certification: "I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations."

(2) General information.

(A) On the application, the applicant must include the name, mailing address, and location of the facility for which the application is being submitted and the operator's name, address, telephone number, Commission Organization Report number, and ownership of the facility.

(B) When a geologic storage facility is owned by one person but is operated by another person, it is the operator's duty to file an application for a permit.

(C) The application must include a listing of all relevant permits or construction approvals for the facility received or applied for under federal or state environmental programs;

(D) A person making an application to the director for a permit under this subchapter must submit a copy of the application to the Texas Commission on Environmental Quality (TCEQ) and must submit to the director a letter of determination from TCEQ concluding that drilling and operating an anthropogenic CO2 injection well for geologic storage or constructing or operating a geologic storage facility will not impact or interfere with any previous or existing Class I injection well, including any associated waste plume, or any other injection well authorized or permitted by TCEQ. The letter must be submitted to the director before any permit under this subchapter may be issued.

(3) Application completeness. The Commission shall [may] not issue a permit before receiving a complete application. A permit application is complete when the director determines that the application contains information addressing each application requirement of the regulatory program and all information necessary to initiate the final review by the director.

(4) Reports. An applicant must ensure that all descriptive reports are prepared by a qualified and knowledgeable person and include an interpretation of the results of all logs, surveys, sampling, and tests required in this subchapter. The applicant must include in the application a quality assurance and surveillance plan for all testing and monitoring, which includes, at a minimum, validation of the analytical laboratory data, calibration of field instruments, and an explanation of the sampling and data acquisition techniques.

(5) If otherwise required under Occupations Code, Chapter 1001, relating to Texas Engineering Practice Act, or Chapter 1002, relating to Texas Geoscientists Practice Act, respectively, a licensed professional engineer or geoscientist must conduct the geologic and hydrologic evaluations required under this subchapter and must affix the appropriate seal on the resulting reports of such evaluations.

(b) Surface map and information. Only information of public record is required to be included on this map.

(1) The applicant must file with the director a surface map delineating the proposed location [location(s)] of any injection wells [well(s)] and the boundary of the geologic storage facility for which a permit is sought and the applicable AOR [area of review].

(2) The applicant must show within the AOR [area of review] on the map the number or name and the location of:

(A) all known artificial penetrations through the confining zone, including injection wells, producing wells, inactive wells, plugged wells, or dry holes;

(B) the locations of cathodic protection holes, subsurface cleanup sites, bodies of surface water, springs, surface and subsurface mines, quarries, and water wells; and

(C) other pertinent surface features, including pipelines, roads, and structures intended for human occupancy.

(3) The applicant must identify on the map any known or suspected faults expressed at the surface.

(c) Geologic, geochemical, and hydrologic information.

(1) The applicant must submit a descriptive report prepared by a knowledgeable person that includes an interpretation of the results of appropriate logs, surveys, sampling, and testing sufficient to determine the depth, thickness, porosity, permeability, and lithology of, and the geochemistry of any formation fluids in, all relevant geologic formations.

(2) The applicant must submit information on the geologic structure and reservoir properties of the proposed storage reservoir and overlying formations, including the following information:

(A) geologic and topographic maps and cross sections illustrating regional geology, hydrogeology, and the geologic structure of the area from the ground surface to the base of the injection zone within the AOR [area of review] that indicate the general vertical and lateral limits of all USDWs [underground sources of drinking water] within the AOR [area of review], their positions relative to the storage reservoir and the direction of water movement, where known;

(B) the depth, areal extent, thickness, mineralogy, porosity, permeability, and capillary pressure of, and the geochemistry of any formation fluids in, the storage reservoir and confining zone and any other relevant geologic formations, including geology/facies changes based on field data, which may include geologic cores, outcrop data, seismic surveys, well logs, and lithologic descriptions, and the analyses of logging, sampling, and testing results used to make such determinations;

(C) the location, orientation, and properties of known or suspected transmissive faults or fractures that may transect the confining zone within the AOR [area of review] and a determination that such faults or fractures would not compromise containment;

(D) the seismic history, including the presence and depth of seismic sources, and a determination that the seismicity would not compromise containment;

(E) geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone;

(F) a description of the formation testing program used and the analytical results used to determine the chemical and physical characteristics of the injection zone and the confining zone; and

(G) baseline geochemical data for subsurface formations that will be used for monitoring purposes, including all formations containing USDWs [underground sources of drinking water] within the AOR [area of review].

(d) AOR [Area of review] and corrective action. This subsection describes the standards for the information regarding the delineation of the AOR [area of review], the identification of penetrations, and corrective action that an applicant must include in an application.

(1) Initial delineation of the AOR [area of review] and initial corrective action. The applicant must delineate the AOR [area of review], identify all wells that require corrective action, and perform corrective action on those wells. Corrective action may be phased.

(A) Delineation of AOR [area of review].

(i) Using computational modeling that considers the volumes and the physical and chemical properties of the injected CO2 stream, the physical properties of the formation into which the CO2 stream is to be injected, and available data including data available from logging, testing, or operation of wells, the applicant must predict the lateral and vertical extent of migration for the CO2 plume and formation fluids and the pressure differentials required to cause movement of injected fluids or formation fluids into a USDW [an underground source of drinking water] in the subsurface for the following time periods:

(I) five years after initiation of injection;

(II) from initiation of injection to the end of the injection period proposed by the applicant; and

(III) from initiation of injection until the plume movement ceases, for a minimum of [to] 10 years after the end of the injection period proposed by the applicant.

(ii) The applicant must use a computational model that:

(I) is based on geologic and reservoir engineering information collected to characterize the injection zone and the confining zone;

(II) is based on anticipated operating data, including injection pressures, rates, and total volumes over the proposed duration of injection;

(III) takes into account relevant geologic heterogeneities and data quality, and their possible impact on model predictions;

(IV) considers the physical and chemical properties of injected and formation fluids; and

(V) considers potential migration through known faults, fractures, and artificial penetrations and beyond lateral spill points.

(iii) The applicant must provide the name and a description of the model, software, the assumptions used to determine the AOR [area of review], and the equations solved.

(B) Identification and table of penetrations. The applicant must identify, compile, and submit a table listing all penetrations, including active, inactive, plugged, and unplugged wells and underground mines in the AOR [area of review] that may penetrate the confining zone, that are known or reasonably discoverable through specialized knowledge or experience. The applicant must provide a description of each penetration's type, construction, date drilled or excavated, location, depth, and record of plugging and/or completion or closure. Examples of specialized knowledge or experience may include reviews of federal, state, and local government records, interviews with past and present owners, operators, and occupants, reviews of historical information (including aerial photographs, chain of title documents, and land use records), and visual inspections of the facility and adjoining properties.

(C) Corrective action. The applicant must demonstrate whether each of the wells on the table of penetrations has or has not been plugged and whether each of the underground mines (if any) on the table of penetrations has or has not been closed in a manner that prevents the movement of injected fluids or displaced formation fluids that may endanger USDWs [underground sources of drinking water] or allow the injected fluids or formation fluids to escape the permitted injection zone. The applicant must perform corrective action on all wells and underground mines in the AOR [area of review] that are determined to need corrective action. The operator must perform corrective action using materials suitable for use with the CO2 stream. Corrective action may be phased.

(2) Area of review and corrective action plan. As part of an application, the applicant must submit an AOR [area of review] and corrective action plan that includes the following information:

(A) the method for delineating the AOR [area of review], including the model to be used, assumptions that will be made, and the site characterization data on which the model will be based;

(B) for the AOR [area of review], a description of:

(i) the minimum frequency subject to the annual certification pursuant to §5.206(f) of this title (relating to Permit Standards) at which the applicant proposes to re-evaluate the AOR [area of review] during the life of the geologic storage facility;

(ii) how monitoring and operational data will be used to re-evaluate the AOR [area of review]; and

(iii) the monitoring and operational conditions that would warrant a re-evaluation of the AOR [area of review] prior to the next scheduled re-evaluation; and

(C) a corrective action plan that describes:

(i) how the corrective action will be conducted;

(ii) how corrective action will be adjusted if there are changes in the AOR [area of review];

(iii) if a phased corrective action is planned, how the phasing will be determined; and

(iv) how site access will be secured for future corrective action.

(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) General. The operator of a geologic storage facility must ensure that all anthropogenic CO2 injection wells are constructed and completed in a manner that will:

(i) prevent the movement of injected CO2 or displaced formation fluids into any unauthorized zones or into any areas where they could endanger USDWs [underground sources of drinking water];

(ii) allow the use of appropriate testing devices and workover tools; and

(iii) allow continuous monitoring of the annulus space between the injection tubing and long string casing.

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

(i) The operator must ensure that injection wells are cased and the casing cemented in compliance with §3.13 of this title (relating to Casing, Cementing, Drilling, Well Control, and Completion Requirements), in addition to the requirements of this section.

(ii) Casing, cement, cement additives, and/or other materials used in the construction of each injection well must have sufficient structural strength and must be of sufficient quality and quantity to maintain integrity over the design life of the injection well. All well materials must be suitable for use with fluids with which the well materials may be expected to come into contact and must meet or exceed test standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards as approved by the director.

(iii) Surface casing must extend through the base of the lowermost USDW [underground source of drinking water] above the injection zone and must be cemented to the surface.

(iv) Circulation of cement may be accomplished by staging. The director may approve an alternative method of cementing in cases where the cement cannot be circulated to the surface, provided the applicant can demonstrate by using logs that the cement does not allow fluid movement between the casing and the well bore.

(v) At least one long string casing, using a sufficient number of centralizers, must extend through the injection zone. The long string casing must isolate the injection zone and other intervals as necessary for the protection of USDWs [underground sources of drinking water] and to ensure confinement of the injected and formation fluids to the permitted injection zone using cement and/or other isolation techniques.

(vi) The applicant must verify the integrity and location of the cement using technology capable of radial evaluation of cement quality and identification of the location of channels to ensure that USDWs [underground sources of drinking water] will not be endangered.

(vii) The director may exempt existing wells that have been associated with injection of CO2 for the purpose of enhanced recovery from provisions of these casing and cementing requirements if the applicant demonstrates that the well construction meets the general performance criteria in subparagraph (A) of this paragraph.

(C) Special equipment.

(i) Tubing and packer. All injection wells must inject fluids through tubing set on a mechanical packer. Packers must be set no higher than 100 feet above the top of the permitted injection interval or at a location approved by the director.

(ii) Pressure observation valve. The wellhead of each injection well must be equipped with a pressure observation valve on the tubing and each annulus of the well.

(2) Construction information. The applicant must provide the following information for each well to allow the director to determine whether the proposed well construction and completion design will meet the general performance criteria in paragraph (1) of this subsection:

(A) depth to the injection zone;

(B) hole size;

(C) size and grade of all casing and tubing strings (e.g., wall thickness, external diameter, nominal weight, length, joint specification and construction material, tubing tensile, burst, and collapse strengths);

(D) proposed injection rate (intermittent or continuous), maximum proposed surface injection pressure, and maximum proposed volume of the CO2 stream;

(E) type of packer and packer setting depth;

(F) a description of the capability of the materials to withstand corrosion when exposed to a combination of the CO2 stream and formation fluids;

(G) down-hole temperatures and pressures;

(H) lithology of injection and confining zones;

(I) type or grade of cement and additives;

(J) chemical composition and temperature of the CO2 stream; and

(K) schematic drawings of the surface and subsurface construction details.

(3) Well construction plan. The applicant must submit an injection well construction plan that meets the criteria in paragraph (1) of this subsection.

(4) Well stimulation plan. The applicant must submit, as applicable, a description of the proposed well stimulation program and a determination that well stimulation will not compromise containment.

(f) Plan for logging, sampling, and testing of injection wells after permitting but before injection. The applicant must submit a plan for logging, sampling, and testing of each injection well after permitting but prior to injection well operation. The plan need not include identical logging, sampling, and testing procedures for all wells provided there is a reasonable basis for different procedures. Such plan is not necessary for existing wells being converted to anthropogenic CO2 injection wells in accordance with this subchapter, to the extent such activities already have taken place. The plan must describe the logs, surveys, and tests to be conducted to verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, the formations that are to be used for monitoring, storage, and confinement to assure conformance with the injection well construction requirements set forth in subsection (e) of this section, and to establish accurate baseline data against which future measurements may be compared. The plan must meet the following criteria and must include the following information.

(1) Logs and surveys of newly drilled and completed injection wells.

(A) During the drilling of any hole that is constructed by drilling a pilot hole that is enlarged by reaming or another method, the operator must perform deviation checks at sufficiently frequent intervals to determine the location of the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling.

(B) Before surface casing is installed, the operator must run appropriate logs, such as resistivity, spontaneous potential, and caliper logs.

(C) After each casing string is set and cemented, the operator must run logs, such as a cement bond log, variable density log, and a temperature log, to ensure proper cementing.

(D) Before long string casing is installed, the operator must run logs appropriate to the geology, such as resistivity, spontaneous potential, porosity, caliper, gamma ray, and fracture finder logs, to gather data necessary to verify the characterization of the geology and hydrology.

(2) Testing and determination of hydrogeologic characteristics of injection and confining zone.

(A) Prior to operation, the operator must conduct tests to verify hydrogeologic characteristics of the injection zone.

(B) The operator must perform an initial pressure fall-off or other test and submit to the director a written report of the results of the test, including details of the methods used to perform the test and to interpret the results, all necessary graphs, and the testing log, to verify permeability, injectivity, and initial pressure using water or CO2.

(C) The operator must determine or calculate the fracture pressures for the injection and confining zone. The [If the fracture pressures are determined through calculation, the] Commission will include in any permit it might issue a limit of 90% of the [calculated] fracture pressure to ensure that the injection pressure does not exceed the fracture pressure.

(3) Sampling.

(A) The operator must record and submit the formation fluid temperature, pH, and conductivity, the reservoir pressure, and the static fluid level of the injection zone.

(B) The operator must submit analyses of whole cores or sidewall cores representative of the injection zone and confining zone and formation fluid samples from the injection zone. The director may accept data from cores and formation fluid samples from nearby wells or other data if the operator can demonstrate to the director that such data are representative of conditions at the proposed injection well.

(g) Compatibility determination. Based on the results of the formation testing program required by subsection (f) of this section, the applicant must submit a determination of the compatibility of the CO2 stream with:

(1) the materials to be used to construct the well;

(2) fluids in the injection zone; and

(3) minerals in both the injection and the confining zone.

(h) Mechanical integrity testing.

(1) Criteria. This paragraph establishes the criteria for the mechanical integrity testing plan for anthropogenic CO2 injection wells that an applicant must include in an application.

(A) Other than during periods of well workover in which the sealed tubing-casing annulus is of necessity disassembled for maintenance or corrective procedures, the operator must maintain mechanical integrity of the injection well at all times.

(B) Before beginning injection operations and at least once every five years thereafter, the operator must demonstrate internal mechanical integrity for each injection well by pressure testing the tubing-casing annulus.

(C) Following an initial annulus pressure test, the operator must continuously monitor injection pressure, rate, injected volumes, and pressure on the annulus between tubing and long string casing to confirm that the injected fluids are confined to the injection zone.

(D) At least once per year until the injection well is plugged [every five years], the operator must confirm the absence of significant fluid movement into a USDW through channels adjacent to the injection wellbore (external integrity) [that the injected fluids are confined to the injection zone] using a method approved by the director (e.g., diagnostic surveys such as oxygen-activation logging or temperature or noise logs).

(E) The operator must test injection wells after any workover that disturbs the seal between the tubing, packer, and casing in a manner that verifies internal mechanical integrity of the tubing and long string casing.

(F) An operator must either repair and successfully retest or plug a well that fails a mechanical integrity test.

(2) Mechanical integrity testing plan. The applicant must prepare and submit a mechanical integrity testing plan as part of a permit application. [The plan must include a schedule for the performance of a series of tests at a minimum frequency of five years.] The performance tests must be designed to demonstrate the internal and external mechanical integrity of each injection well. These tests may include:

(A) a pressure test with liquid or inert gas;

(B) a tracer survey such as oxygen-activation logging;

(C) a temperature or noise log;

(D) a casing inspection log; and/or

(E) any alternative method approved by the director, and if necessary by the Administrator of EPA under 40 CFR §146.89(e), that provides equivalent or better information approved by the director.

(i) Operating information.

(1) Operating plan. The applicant must submit a plan for operating the injection wells and the geologic storage facility that complies with the criteria set forth in §5.206(d) [§5.206(c)] of this title, and that outlines the steps necessary to conduct injection operations. The applicant must include the following proposed operating data in the plan:

(A) the average and maximum daily injection rates and volumes of the CO2 stream;

(B) the average and maximum surface injection pressure;

(C) the sources [source(s)] of the CO2 stream and the volume of CO2 from each source; and

(D) an analysis of the chemical and physical characteristics of the CO2 stream prior to injection.

(2) Maximum injection pressure. The director will approve a maximum injection pressure limit that:

(A) considers the risks of tensile failure and, where appropriate, geomechanical or other studies that assess the risk of tensile failure and shear failure;

(B) with a reasonable degree of certainty will avoid initiation or propagation of fractures in the confining zone or cause otherwise non-transmissive faults transecting the confining zone to become transmissive; and

(C) in no case may cause the movement of injection fluids or formation fluids in a manner that endangers USDWs [underground sources of drinking water].

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

(1) The applicant must submit a monitoring, sampling, and testing plan for verifying that the geologic storage facility is operating as permitted and that the injected fluids are confined to the injection zone.

(2) The plan must include the following:

(A) the analysis of the CO2 stream prior to injection with sufficient frequency to yield data representative of its chemical and physical characteristics;

(B) the installation and use of continuous recording devices to monitor injection pressure, rate, and volume, and the pressure on the annulus between the tubing and the long string casing, except during workovers;

(C) after initiation of injection, the performance on a semi-annual 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 annually. Corrosion monitoring may be accomplished by:

(i) analyzing coupons of the well construction materials in contact with the CO2stream;

(ii) routing the CO2 stream through a loop constructed with the materials used in the well and inspecting the materials in the loop; or

(iii) using an alternative method, materials, or time period approved by the director;

(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) periodic monitoring of the quality and geochemistry of a USDW [an underground source of drinking water] within the AOR [area of review] and the formation fluid in a permeable and porous formation near to and above the top confining zone to detect any movement of the injected CO2 through the confining zone into that monitored formation;

(iii) the location and number of monitoring wells justified on the basis of the AOR [area of review], injection rate and volume, geology, and the presence of artificial penetrations and other factors specific to the geologic storage facility; and

(iv) the monitoring frequency and spatial distribution of monitoring wells based on baseline geochemical data collected under subsection (c)(2) of this section and any modeling results in the AOR [area of review] evaluation;

(E) tracking the extent of the CO2 plume and the position of the pressure front by using indirect, geophysical techniques, which may include seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools; [and]

(F) A pressure fall-off test at least once every five years unless more frequent testing is required by the director based on site-specific information; and

(G) [(F)] additional monitoring as the director may determine to be necessary to support, upgrade, and improve computational modeling of the AOR [area of review] evaluation and to determine compliance with the requirements that the injection activity not allow the movement of fluid containing any contaminant into USDWs [underground sources of drinking water] and that the injected fluid remain within the permitted interval.

(k) Well plugging plan. The applicant must submit a well plugging plan for all injection wells and monitoring wells that penetrate the base of usable quality water that includes the following:

(1) a proposal for plugging all monitoring wells that penetrate the base of usable quality water and all injection wells upon abandonment in accordance with §3.14 of this title (relating to Plugging), in addition to the requirements of this section. The proposal must include:[;]

(A) the type and number of plugs to be used;

(B) the placement of each plug, including the elevation of the top and bottom of each plug;

(C) the type, grade, and quantity of material to be used in plugging and information to demonstrate that the material is compatible with the CO2 stream; and

(D) the method of placement of the plugs;

(2) proposals for activities to be undertaken prior to plugging an injection well, specifically:

(A) flushing each injection well with a buffer fluid;

(B) performing tests or measures to determine bottomhole reservoir pressure;

(C) performing final tests to assess mechanical integrity; and

(D) ensuring that the material to be used in plugging must be compatible with the CO2 stream and the formation fluids;

(3) a proposal for giving notice of intent to plug monitoring wells that penetrate the base of usable quality water and all injection wells. The applicant's plan must ensure that:

(A) the operator notifies the director at least 60 days before plugging a well. At this time, if any changes have been made to the original well plugging plan, the operator must also provide a revised well plugging plan. At the discretion of the director, an operator may be allowed to proceed with well plugging on a shorter notice period; and

(B) the operator will file a notice of intention to plug and abandon (Form W-3A) a well with the appropriate Commission district office and the division in Austin at least five days prior to the beginning of plugging operations;

(4) a plugging report for monitoring wells that penetrate the base of usable quality water and all injection wells. The applicant's plan must ensure that within 30 days after plugging the operator will file a complete well plugging record (Form W-3) in duplicate with the appropriate district office. The operator and the person who performed the plugging operation (if other than the operator) must certify the report as accurate;

(5) a plan for plugging all monitoring wells that do not penetrate the base of usable quality water in accordance with 16 TAC Chapter 76 (relating to Water Well Drillers and Water Well Pump Installers); and

(6) a plan for certifying that all monitoring wells that do not penetrate the base of usable quality water will be plugged in accordance with 16 TAC Chapter 76.

(l) Emergency and remedial response plan. The applicant must submit an emergency and remedial response plan that:

(1) accounts for the entire AOR [area of review], regardless of whether or not corrective action in the AOR [area of review] is phased;

(2) describes actions to be taken to address escape from the permitted injection interval or movement of the injection fluids or formation fluids that may cause an endangerment to USDWs [underground sources of drinking water] during construction, operation, closure, and post-closure periods;

(3) includes a safety plan that includes emergency response procedures, provisions to provide security against unauthorized activity, and CO2 release detection and prevention measures; and

(4) includes a description of the training and testing that will be provided to each employee at the storage facility on operational safety and emergency response procedures to the extent applicable to the employee's duties and responsibilities. The operator must train all employees before commencing injection and storage operations at the facility. The operator must train each subsequently hired employee before that employee commences work at the storage facility. The operator must hold a safety meeting with each contractor prior to the commencement of any new contract work at a storage facility. Emergency measures specific to the contractor's work must be explained in the contractor safety meeting. Training schedules, training dates, and course outlines must be provided to Commission personnel upon request for the purpose of Commission review to determine compliance with this paragraph.

(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) a demonstration containing substantial evidence that the geologic storage project will no longer pose a risk of endangerment to USDWs at the end of the post-injection storage facility care timeframe. The demonstration must be based on significant, site-specific data and information, including all data and information collected pursuant subsections (b)-(d) of this section and §5.206(b)(5) of this title;

(2) [(1)] the pressure differential between pre-injection and predicted post-injection pressures in the injection zone;

(3) [(2)] the predicted position of the CO2 plume and associated pressure front at closure as demonstrated in the AOR [area of review] evaluation required under subsection (d) of this section;

(4) [(3)] a description of the proposed post-injection monitoring location, methods, and frequency;

(5) [(4)] a proposed schedule for submitting post-injection storage facility care monitoring results to the division; [and]

(6) [(5)] the estimated cost of proposed post-injection storage facility care and closure; and [.]

(7) consideration and documentation of:

(A) the results of computational modeling performed pursuant to delineation of the AOR under subsection (d) of this section;

(B) the predicted timeframe for pressure decline within the injection zone, and any other zones, such that formation fluids may not be forced into any USDWs, and/or the timeframe for pressure decline to pre-injection pressures;

(C) the predicted rate of CO2 plume migration within the injection zone, and the predicted timeframe for the cessation of migration;

(D) a description of the site-specific processes that will result in CO2 trapping including immobilization by capillary trapping, dissolution, and mineralization at the site;

(E) the predicted rate of CO2 trapping in the immobile capillary phase, dissolved phase, and/or mineral phase;

(F) the results of laboratory analyses, research studies, and/or field or site-specific studies to verify the information required in subparagraphs (D) and (E) of this paragraph;

(G) a characterization of the confining zone(s) including a demonstration that it is free of transmissive faults, fractures, and micro-fractures and of appropriate thickness, permeability, and integrity to impede fluid (e.g., CO2, formation fluids) movement;

(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 area of elevated pressure;

(I) a description of the well construction and an assessment of the quality of plugs of all abandoned wells within the AOR;

(J) the distance between the injection zone and the nearest USDWs above and/or below the injection zone; and

(K) any additional site-specific factors required by the Director; and

(8) information submitted to support the demonstration in paragraph (1) of this subsection, which shall meet the following criteria:

(A) all analyses and tests performed to support the demonstration must be accurate, reproducible, and performed in accordance with the established quality assurance standards;

(B) estimation techniques must be appropriate and EPA-certified test protocols must be used where available;

(C) predictive models must be appropriate and tailored to the site conditions, composition of the CO2 stream, and injection and site conditions over the life of the geologic storage project;

(D) predictive models must be calibrated using existing information where sufficient data are available;

(E) reasonably conservative values and modeling assumptions must be used and disclosed to the Director whenever values are estimated on the basis of known, historical information instead of site-specific measurements;

(F) an analysis must be performed to identify and assess aspects of the alternative PISC timeframe demonstration that contribute significantly to uncertainty. The operator must conduct sensitivity analyses to determine the effect that significant uncertainty may contribute to the modeling demonstration;

(G) an approved quality assurance and quality control plan must address all aspects of the demonstration; and

(H) any additional criteria required by the Director.

(n) Fees, financial responsibility, and financial assurance. The applicant must pay the fees, demonstrate that it has met the financial responsibility requirements, and provide the Commission with financial assurance as required under §5.205 of this title (relating to Fees, Financial Responsibility, and Financial Assurance).

(1) The applicant must demonstrate financial responsibility and resources for corrective action, injection well plugging, post-injection storage facility care and storage facility closure, and emergency and remedial response until the director has provided to the operator a written verification that the director has determined that the facility has reached the end of the post-injection storage facility care period.

(2) In determining whether the applicant is financially responsible, the director must rely on the following:

(A) the person's most recent audited annual report filed with the U. S. Securities and Exchange Commission under Section 13 or 15(d), Securities Exchange Act of 1934 (15 U.S.C. Section 78m or 78o(d)). The date of the audit may not be more than one year before the date of submission of the application to the division; and

(B) the person's most recent quarterly report filed with the U. S. Securities and Exchange Commission under Section 13 or 15(d), Securities Exchange Act of 1934 (15 U.S.C. Section 78m or 78o(d)); or

(C) if the person is not required to file such a report, the person's most recent audited financial statement. The date of the audit must not be more than one year before the date of submission of the application to the division.

(o) Letter from the Groundwater Advisory Unit of the Oil and Gas Division. The applicant must submit a letter from the Groundwater Advisory Unit of the Oil and Gas Division in accordance with Texas Water Code, §27.046.

(p) Other information. The applicant must submit any other information requested by the director as necessary to discharge the Commission's duties under Texas Water Code, Chapter 27, Subchapter B-1, or deemed necessary by the director to clarify, explain, and support the required attachments.

§5.204.Notice of Permit Actions and Public Comment Period [and Hearing].

[(a) Placement of copy of application for public inspection. The applicant must make a complete copy of the permit application available for the public to inspect and copy by filing a copy of the application with the County Clerk at the courthouse of each county where the storage facility is to be located, or if approved by the director, at another equivalent public office. The applicant also must provide an electronic copy of the complete application to enable the Commission to place the copy on the Railroad Commission Internet website. The applicant must file any subsequent revision of the application with the County Clerk or other approved public office and must file at the Commission an electronic copy of the updated application at the same time the applicant files the revision at the Commission.]

(a) [(b)] 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); and

(B) a hearing that has been scheduled under subsection (b)(2) of this section.

(2) [(1)] General notice by publication. The Commission shall [To give general notice to local governments and interested or affected persons, the applicant must] publish notice of a draft permit [the application for an original or amended storage facility permit no later than the date the application is mailed to or filed with the director. The applicant must use the appropriate form of notice, include the information as set forth in subparagraph (A) or (B) of this paragraph, and cause the notice to be published] once a week for three consecutive weeks in a [each] newspaper of general circulation in each county where the storage facility is located or is to be located. [The applicant must file proof of publication of the notice with the application.]

[(A) Form for notice by publication of an application for an anthropogenic CO2 geologic storage facility permit.]

[Figure: 16 TAC §5.204(b)(1)(A)]

[(B) Form for notice by publication of an application for amendment of an existing CO2 geologic storage facility permit.]

[Figure: 16 TAC §5.204(b)(1)(B)]

[(C) The applicant must submit proof of publication of notice in the following form:]

[Figure: 16 TAC §5.204(b)(1)(C)]

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

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

(i) the applicant;

(ii) the United State Environmental Protection Agency;

(iii) the Texas Commission on Environmental Quality, the Texas Water Development Board, the Texas Department of State Health Services, the Texas Parks and Wildlife Department, the Texas General Land Office, the Texas Historical Commission, the United States Fish and Wildlife Service, other Federal and State agencies with jurisdiction over fish, shellfish, and wildlife resources, and coastal zone management plans, the Advisory Council on Historic Preservation, including any affected States (Indian Tribes) and any agency that the Commission knows has issued or is required to issue a permit for the same facility under any federal or state environmental program;

[(A)] [Persons to notify. By no later than the date the application is mailed to or filed with the director, the applicant must give notice of an application for a permit to operate a CO2 storage facility, or to amend an existing storage facility permit to:]

(iv) [(i)] each adjoining mineral interest owner, other than the applicant, of the outermost [outmost] boundary of the proposed geologic storage facility;

(v) [(ii)] each leaseholder of minerals lying above or below the proposed storage reservoir;

(vi) [(iii)] each adjoining leaseholder of minerals offsetting the outermost boundary of the proposed geologic storage facility;

(vii) [(iv)] each owner or leaseholder of any portion of the surface overlying the proposed storage reservoir and the adjoining area of the outermost boundary of the proposed geologic storage facility;

(viii) [(v)] the clerk of the county or counties where the proposed storage facility is located;

(ix) [(vi)] the city clerk or other appropriate city official where the proposed storage facility is located within city limits; [and]

(x) any other unit of local government having jurisdiction over the area where the facility is or is proposed to be located, and each state agency having any authority under state law with respect to the construction or operation of the facility;

(xi) 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 hearings in that area for their interest in being included on area mailing lists; and

(xii) [(vii)] any other class of persons that the director determines should receive notice of the application.

(B) Any person otherwise entitled to receive notice under this paragraph may waive his or her rights to receive notice of a draft permit under this subsection.

(4) [(B)] Content of notice. Individual notice must consist of:

(A) [(i)] the applicant's intention to construct and operate an anthropogenic CO2 geologic storage facility;

(B) [(ii)] a description of the geologic storage facility location;

(C) a copy of any draft permit and fact sheet;

(D) [(iii)] each physical location and the internet address at which a copy of the application may be inspected; [and]

(E) [(iv)] a statement that:

(i) [(I)] affected persons may protest the application;

(ii) [(II)] protests must be filed in writing and must be mailed or delivered to Technical Permitting, Oil and Gas Division, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711; and

(iii) [(III)] protests 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) [(3)] Individual notice by publication. The applicant must make diligent efforts to ascertain the name and address of each person identified under paragraph (3)(A) [(2)(A)] of this subsection. The exercise of diligent efforts to ascertain the names and addresses of such persons requires an examination of county records where the facility is located and an investigation of any other information that is publicly and/or reasonably available to the applicant. If, after diligent efforts, an applicant has been unable to ascertain the name and address of one or more persons required to be notified under paragraph (3)(A) [(2)(A)] of this subsection, the applicant satisfies the notice requirements for those persons by the publication of the notice of application as required in paragraph (2) [(1)] of this subsection. The applicant must submit an affidavit to the director specifying the efforts that the applicant took to identify each person whose name and/or address could not be ascertained.

(6) Notice to certain communities. The applicant shall identify whether any portions of the AOR encompass an Environmental Justice (EJ) or Limited English Proficiency (LEP) area using U.S. Census Bureau 2018 American Community Survey data. If the AOR incudes an EJ or LEP area, the applicant shall conduct enhanced public outreach activities to these communities. Efforts to include EJ and LEP communities in public involvement activities in such cases shall include:

(A) published meeting notice in English and the identified language (e.g., Spanish);

(B) comment forms posted on the applicant's webpage and available at public meeting in English and the alternate language;

(C) interpretation services accommodated upon request;

(D) English translation of any comments made during any comment period in the alternate language; and

(E) to the extent possible, public meeting venues near public transportation.

(7) Comment period for a draft permit. 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.

(b) [(c)] Public comment and hearing [Hearing] requirements.

(1) Public comment.

(A) 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) Reasonable limits may be set upon the time allowed for oral statements, and the submission of statements in writing may be required.

(C) 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.

(2) Public hearing.

(A) [(1)] If the Commission receives a protest regarding an application for a new permit or for an amendment of an existing permit for a geologic storage facility from a person notified pursuant to subsection (a) [(b)] 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 hearing on the application. [The Commission must give notice of the hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. After the hearing, the examiner will recommend a final action by the Commission.]

(B) The director shall hold a public hearing whenever the director finds, on the basis of requests, a significant degree of public interest in a draft permit.

(C) The director may also hold a public hearing at the director's discretion, whenever, for instance, such a hearing might clarify one or more issues involved in the permit decision.

(D) Public notice of a public hearing shall be given at least 30 days before the hearing. Public notice of a hearing may be given at the same time as public notice of the draft permit and the two notices may be combined.

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

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

(4) [(3)] 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 hearing. After hearing, the examiner will recommend a final action by the Commission.

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

(a) Fees. In addition to the fee for each injection well required by §3.78 of this title (relating to Fees and Financial Security Requirements), the following non-refundable fees must be remitted to the Commission with the application:

(1) Base application fee.

(A) The applicant must pay to the Commission an application fee of $50,000 for each permit application for a geologic storage facility.

(B) The applicant must pay to the Commission an application fee of $25,000 for each application to amend a permit for a geologic storage facility.

(2) Injection fee. The operator must pay to the Commission an annual fee of $0.025 per metric ton of CO2 injected into the geologic storage facility.

(3) Post-injection care fee. The operator must pay to the Commission an annual fee of $50,000 each year the operator does not inject into the geologic storage facility until the director has authorized storage facility closure.

[(4) The anthropogenic CO2 storage trust fund shall be capped at $5,000,000.]

(b) Financial responsibility.

(1) A person to whom a permit is issued under this subchapter must provide annually to the director evidence of financial responsibility that is satisfactory to the director. The operator must demonstrate and maintain financial responsibility and resources for corrective action, injection well plugging, post-injection storage facility care and storage facility closure, and emergency and remedial response until the director has provided written verification that the director has determined that the facility has reached the end of the post-injection storage facility care period.

(2) In determining whether the person is financially responsible, the director must rely on:

(A) the person's most recent audited annual report filed with the U. S. Securities and Exchange Commission under Section 13 or 15(d), Securities Exchange Act of 1934 (15 U.S.C. Section 78m or 78o(d)); and

(B) the person's most recent quarterly report filed with the U. S. Securities and Exchange Commission under Section 13 or 15(d), Securities Exchange Act of 1934 (15 U.S.C. Section 78m or 78o(d)); or

(C) if the person is not required to file such a report, the person's most recent audited financial statement. The date of the audit must not be more than one year before the date of submission of the application to the director.

(3) The applicant's demonstration of financial responsibility must account for the entire AOR [area of review], regardless of whether corrective action in the AOR [area of review] is phased.

(c) Financial assurance.

(1) Injection and monitoring wells. The operator must comply with the requirements of §3.78 of this title for all monitoring wells that penetrate the base of usable quality water and all injection wells.

(2) Geologic storage facility.

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

(i) a written estimate of the highest likely dollar amount necessary to perform post-injection monitoring and closure of the facility that shows all assumptions and calculations used to develop the estimate;

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

(iii) information concerning the issuer of the bond or letter of credit including the issuer's name and address and evidence of authority to issue bonds or letters of credit in Texas.

(B) A geologic storage facility shall [may ] not receive CO2 until 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 perform corrective action, emergency response, and remedial action, post-injection monitoring and site care, and closure of the geologic storage facility, exclusive of plugging costs for any well or wells at the facility, at any time during the permit term in accordance with all applicable state laws, Commission rules and orders, and the permit;

(ii) A qualified professional engineer licensed by the State of Texas, as required under Occupations Code, Chapter 1001, relating to Texas Engineering Practice [Practices] Act, must prepare or supervise the preparation of a written estimate of the highest likely amount necessary to close the geologic storage facility. The operator must submit to the director the written estimate under seal of a qualified licensed professional engineer, as required under Occupations Code, Chapter 1001, relating to Texas Engineering Practice [Practices] Act; and

(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.

(D) 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.

(E) The operator of a geologic storage facility must provide to the director annual written updates of the cost estimate to increase or decrease the cost estimate to account for any changes to the AOR [area of review] 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 operator must provide to the director upon request an adjustment of the cost estimate if the director has reason to believe that the original demonstration is no longer adequate to cover the cost of injection well plugging and post-injection storage facility care and closure.

(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.

(d) Notice of adverse financial conditions.

(1) The operator must notify the Commission of adverse financial conditions that may affect the operator's ability to carry out injection well plugging and post-injection storage facility care and closure. An operator must file any notice of bankruptcy in accordance with §3.1(f) of this title (relating to Organization Report; Retention of Records; Notice Requirements). The operator must give such notice by certified mail.

(2) The operator filing a bond must ensure that the bond provides a mechanism for the bond or surety company to give prompt notice to the Commission and the operator of any action filed alleging insolvency or bankruptcy of the surety company or the bank or alleging any violation that would result in suspension or revocation of the surety or bank's charter or license to do business.

(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 operator to be without bond coverage. The Commission must issue a notice to any operator who is without bond coverage and must specify a reasonable period to replace bond coverage, not to exceed 90 days.

§5.206.Permit Standards.

(a) Each condition applicable to a permit shall be incorporated into the permit either expressly or by reference. If incorporated by reference, a specific citation to the rules in this chapter shall be given in the permit. The requirements listed in this section are directly enforceable regardless of whether the requirement is a condition of the permit.

(b) [(a)] General criteria. The director may issue a permit under this subchapter if the applicant demonstrates and the director finds that:

(1) the injection and geologic storage of anthropogenic CO2 will not endanger or injure any existing or prospective oil, gas, geothermal, or other mineral resource, or cause waste as defined by Texas Natural Resources Code, §85.046(11);

(2) with proper safeguards, both USDWs [underground sources of drinking water] and surface water can be adequately protected from CO2 migration or displaced formation fluids;

(3) the injection of anthropogenic CO2 will not endanger or injure human health and safety;

(4) the reservoir into which the anthropogenic CO2 is injected is suitable for or capable of being made suitable for protecting against the escape or migration of anthropogenic CO2 from the storage reservoir;

(5) the geologic storage facility will be sited in an area with suitable geology, which at a minimum must include:

(A) an injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the CO2 stream; and

(B) a confining zone [zone(s)] that is laterally continuous and free of known transecting transmissive faults or fractures over an area sufficient to contain the injected CO2 stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without compromising the confining zone or causing the movement of fluids that endangers USDWs [underground sources of drinking water];

(6) the applicant for the permit meets all of the other statutory and regulatory requirements for the issuance of the permit;

(7) the applicant has provided a letter from the Groundwater Advisory Unit of the Oil and Gas Division in accordance with §5.203(o) of this title (relating to Application Requirements);

(8) the applicant has provided a letter of determination from TCEQ concluding that drilling and operating an anthropogenic CO2 injection well for geologic storage or constructing or operating a geologic storage facility will not impact or interfere with any previous or existing Class I injection well, including any associated waste plume, or any other injection well authorized or permitted by TCEQ;

(9) [(8)] the applicant has provided a signed statement that the applicant has a good faith claim to the necessary and sufficient property rights for construction and operation of the geologic storage facility for at least the first five years after initiation of injection in accordance with §5.203(d)(1)(A) of this title;

(10) [(9)] the applicant has paid the fees required in §5.205(a) of this title (relating to Fees, Financial Responsibility, and Financial Assurance);

(11) [(10)] the director has determined that the applicant has sufficiently demonstrated financial responsibility as required in §5.205(b) of this title; and

(12) [(11)] the applicant submitted to the director financial assurance in accordance with §5.205(c) of this title.

(c) [(b)] Injection well construction.

(1) Construction of anthropogenic CO2 injection wells must meet the criteria in §5.203(e) of this title.

(2) Within 30 days after the completion or conversion of an injection well subject to this subchapter, the operator must file with the division a complete record of the well on the appropriate form showing the current completion.

(3) Except in the case of an emergency repair, the operator of a geologic storage facility must notify the director in writing at least 30 days [48 hours, and obtain the director's approval,] prior to conducting any well workover that involves running tubing and setting packers [packer(s) ], beginning any workover or remedial operation, or conducting any required pressure tests or surveys. In the case of an emergency repair, the operator must notify the director of such emergency repair as soon as reasonably practical. No such work may commence until approved by the director.

(d) [(c)] Operating a geologic storage facility.

(1) Operating plan. The operator must maintain and comply with the approved operating plan.

(2) Operating criteria.

(A) Injection between the outermost casing protecting USDWs [underground sources of drinking water] and the well bore is prohibited.

(B) The total volume of CO2 injected into the storage facility must be metered through a master meter or a series of master meters. The volume of CO2 injected into each injection well must be metered through an individual well meter.

(C) The operator must comply with a maximum surface injection pressure limit approved by the director and specified in the permit. In approving a maximum surface injection pressure limit, the director must consider the results of well tests and, where appropriate, geomechanical or other studies that assess the risks of tensile failure and shear failure. The director must approve limits that, with a reasonable degree of certainty, will avoid initiation or propagation of fractures in the confining zone or cause otherwise non-transmissive faults or fractures transecting the confining zone to become transmissive. In no case may injection pressure cause movement of injection fluids or formation fluids in a manner that endangers USDWs [underground sources of drinking water]. The Commission shall include in any permit it might issue a limit of 90 percent of the fracture pressure to ensure that the injection pressure does not initiate new fractures or propagate existing fractures in the injection zone(s). In no case may injection pressure initiate fractures in the confining zone(s) or cause the movement of injection or formation fluids that endangers a USDW. The director may approve a plan for controlled artificial fracturing of the injection zone.

(D) The operator must fill the annulus between the tubing and the long string casing with a corrosion inhibiting fluid approved by the director. The owner or operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the director determines that such requirement might harm the integrity of the well or endanger USDWs.

(E) The operator must install and use continuous recording devices to monitor the injection pressure, and the rate, volume, and temperature of the CO2 stream. The operator must monitor the pressure on the annulus between the tubing and the long string casing. The operator must continuously record, continuously monitor, or control by a preset high-low pressure sensor switch the wellhead pressure of each injection well.

(F) The operator must comply with the following requirements for alarms and automatic shut-off systems.

(i) The operator must install and use alarms and automatic shut-off systems designed to alert the operator and shut-in the well when operating parameters such as annulus pressure, injection rate or other parameters diverge from permitted ranges and/or gradients. On offshore wells, the automatic shut-off systems must be installed down-hole.

(ii) If an automatic shutdown is triggered or a loss of mechanical integrity is discovered, the operator must immediately investigate and identify as expeditiously as possible the cause. If, upon investigation, the well appears to be lacking mechanical integrity, or if monitoring otherwise indicates that the well may be lacking mechanical integrity, the operator must:

(I) immediately cease injection;

(II) take all steps reasonably necessary to determine whether there may have been a release of the injected CO2 stream into any unauthorized zone;

(III) notify the director as soon as practicable, but within 24 hours;

(IV) restore and demonstrate mechanical integrity to the satisfaction of the director prior to resuming injection; and

(V) notify the director when injection can be expected to resume.

(e) [(d)] Monitoring, sampling, and testing requirements.

(1) The operator of an anthropogenic CO2 injection well must maintain and comply with the approved monitoring, sampling, and testing plan to verify that the geologic storage facility is operating as permitted and that the injected fluids are confined to the injection zone.

(2) All permits shall include the following requirements:

(A) the proper use, maintenance, and installation of monitoring equipment or methods;

(B) monitoring including type, intervals, and frequency sufficient to yield data that are representative of the monitored activity including, when required, continuous monitoring;

(C) reporting no less frequently than as specified in §5.207 of this title (relating to Reporting and Record-Keeping).

(3) The director may require additional monitoring as necessary to support, upgrade, and improve computational modeling of the AOR [area of review] evaluation and to determine compliance with the requirement that the injection activity not allow movement of fluid that would endanger USDWs [underground sources of drinking water].

(f) [(e)] Mechanical integrity.

(1) The operator must maintain and comply with the approved mechanical integrity testing plan submitted in accordance with §5.203(j) of this title.

(2) Other than during periods of well workover in which the sealed tubing-casing annulus is of necessity disassembled for maintenance or corrective procedures, the operator must maintain mechanical integrity of the injection well at all times.

(3) The operator must either repair and successfully retest or plug a well that fails a mechanical integrity test.

(4) The director may require additional or alternative tests if the results presented by the operator do not demonstrate to the director that there is no significant leak in the casing, tubing, or packer or movement of fluid into or between formations containing USDWs [underground sources of drinking water] resulting from the injection activity.

(g) [(f)] Area of review and corrective action. Notwithstanding the requirement in §5.203(d)(2)(B)(i) of this title to perform a re-evaluation of the AOR [area of review], at the frequency specified in the AOR [area of review] and corrective action plan or permit, the operator of a geologic storage facility also must conduct the following whenever warranted by a material change in the monitoring and/or operational data or in the evaluation of the monitoring and operational data by the operator:

(1) a re-evaluation of the AOR [area of review] by performing all of the actions specified in §5.203(d)(1)(A) - (C) of this title to delineate the AOR [area of review] and identify all wells that require corrective action;

(2) identify all wells in the re-evaluated AOR [area of review] that require corrective action;

(3) perform corrective action on wells requiring corrective action in the re-evaluated AOR [area of review] in the same manner specified in §5.203(d)(1)(C) of this title; and

(4) submit an amended AOR [area of review] and corrective action plan or demonstrate to the director through monitoring data and modeling results that no change to the AOR [area of review] and corrective action plan is needed.

(h) [(g)] Emergency, mitigation, and remedial response.

(1) Plan. The operator must maintain and comply with the approved emergency and remedial response plan required by §5.203(l) of this title. The operator must update the plan in accordance with §5.207(a)(2)(D)(vi) of this title (relating to Reporting and Record-Keeping). The operator must make copies of the plan available at the storage facility and at the company headquarters.

(2) Training.

(A) The operator must prepare and implement a plan to train and test each employee at the storage facility on occupational safety and emergency response procedures to the extent applicable to the employee's duties and responsibilities. The operator must make copies of the plan available at the geological storage facility. The operator must train all employees before commencing injection and storage operations at the facility. The operator must train each subsequently hired employee before that employee commences work at the storage facility.

(B) The operator must hold a safety meeting with each contractor prior to the commencement of any new contract work at a storage facility. The operator must explain emergency measures specific to the contractor's work in the contractor safety meeting.

(C) The operator must provide training schedules, training dates, and course outlines to Commission personnel upon request for the purpose of Commission review to determine compliance with this paragraph.

(3) Action. If an operator obtains evidence that the injected CO2 stream and associated pressure front may cause an endangerment to USDWs [underground sources of drinking water], the operator must:

(A) immediately cease injection;

(B) take all steps reasonably necessary to identify and characterize any release;

(C) notify the director as soon as practicable but within at least 24 hours; and

(D) implement the approved emergency and remedial response plan.

(4) Resumption of injection. The director may allow the operator to resume injection prior to remediation if the operator demonstrates that the injection operation will not endanger USDWs [underground sources of drinking water].

(i) [(h)] Commission witnessing of testing and logging. The operator must provide the division with the opportunity to witness all planned well workovers, stimulation activities, other than stimulation for formation testing, and testing and logging. The operator must submit a proposed schedule of such activities to the Commission at least 30 days prior to conducting the first such activity [test] and submit notice at least 48 hours in advance of any actual activity. Such activities shall [testing or logging. Testing and logging may] not commence before the end of the 30 days [48-hour period] unless authorized by the director.

(j) [(i)] Well plugging. The operator of a geologic storage facility must maintain and comply with the approved well plugging plan required by §5.203(k) of this title.

(k) [(j)] Post-injection storage facility care and closure.

(1) Post-injection storage facility care and closure plan.

(A) The operator of an injection well must maintain and comply with the approved post-injection storage facility care and closure plan.

(B) The operator must update the plan in accordance with §5.207(a)(2)(D)(vi) of this title. At any time during the life of the geologic sequestration project, the operator may modify and resubmit the post-injection site care and site closure plan for the director's approval within 30 days of such change. Any amendments to the post-injection site care and site closure plan must be approved by the director, be incorporated into the permit, and are subject to the permit modification requirements in §5.202 of this title (relating to Permit Required), as appropriate.

(C) Upon cessation of injection, the operator of a geologic storage facility must either submit an amended plan or demonstrate to the director through monitoring data and modeling results that no amendment to the plan is needed.

(2) Post-injection storage facility monitoring. Following cessation of injection, the operator must continue to conduct monitoring as specified in the approved plan until the director determines that the position of the CO2 plume and pressure front are such that the geologic storage facility will not endanger USDWs [underground sources of drinking water].

(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 [underground sources of drinking water]. 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 area of elevated pressure);

(B) that there is no leakage of either CO2 or displaced formation fluids that will endanger USDWs [underground sources of drinking water];

(C) that the injected or displaced fluids are not expected to migrate in the future in a manner that encounters a potential leakage pathway into USDWs [underground sources of drinking water];

(D) that the injection wells at the site completed into or through the injection zone or confining zone will be plugged and abandoned in accordance with these requirements; and

(E) any remaining facility monitoring wells will be properly plugged or are being managed by a person and in a manner approved by the director.

(4) Notice of intent for storage facility closure. The operator must notify the director in writing at least 120 days before storage facility closure. At the time of such notice, if the operator has made any changes to the original plan, the operator also must provide the revised plan. The director may approve a shorter notice period.

(5) Authorization for storage facility closure. No operator may initiate storage facility closure until the director has approved closure of the storage facility in writing. After the director has authorized storage facility closure, the operator must plug all wells in accordance with the approved plan required by §5.203(k) of this title.

(6) Storage facility closure report. Once the director has authorized storage facility closure, the operator must submit a storage facility closure report within 90 days that must thereafter be retained by the Commission in Austin. The report must include the following information:

(A) documentation of appropriate injection and monitoring well plugging. The operator must provide a copy of a survey plat that has been submitted to the Regional Administrator of Region 6 of the United States Environmental Protection Agency. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks;

(B) documentation of appropriate notification and information to such state and local authorities as have authority over drilling activities to enable such state and local authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zones; and

(C) records reflecting the nature, composition and volume of the CO2 stream.

(7) Certificate of closure. Upon completion of the requirements in paragraphs (3) - (6) of this subsection, the director will issue a certificate of closure. At that time, the operator is released from the requirement in §5.205(c) of this title to maintain financial assurance.

(l) [(k)] Deed notation. The operator of a geologic storage facility must record a notation on the deed to the facility property; on any other document that is normally examined during title search; or on any other document that is acceptable to the county clerk for filing in the official public records of the county that will in perpetuity provide any potential purchaser of the property the following information:

(1) a complete legal description of the affected property;

(2) that land has been used to geologically store CO2;

(3) that the survey plat has been filed with the Commission;

(4) the address of the office of the United States Environmental Protection Agency, Region 6, to which the operator sent a copy of the survey plat; and

(5) the volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred.

(m) [(l)] Retention of records. The operator must retain for 10 [five] years following storage facility closure records collected during the post-injection storage facility care period. The operator must deliver the records to the director at the conclusion of the retention period, and the records must thereafter be retained at the Austin headquarters of the Commission.

(n) [(m)] Signs. The operator must identify each location at which geologic storage activities take place, including each injection well, by a sign that meets the requirements specified in §3.3(1), (2), and (5) of this title (relating to Identification of Properties, Wells, and Tanks). In addition, each sign must include a telephone number where the operator or a representative of the operator can be reached 24 hours a day, seven days a week in the event of an emergency.

(o)[(n)] Other permit terms and conditions.

(1) Protection of USDWs. In any permit for a geologic storage facility, the director must impose terms and conditions reasonably necessary to protect USDWs [underground sources of drinking water]. Permits issued under this subchapter continue in effect until revoked, modified, or terminated [suspended] by the Commission. The operator must comply with each requirement set forth in this subchapter as a condition of the permit unless modified by the terms of the permit.

(2) Other conditions. The following conditions shall also be included in any permit issued under this subchapter.

(A) Duty to comply. The permittee must comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the Safe Drinking Water Act and is grounds for enforcement action; for permit termination, revocation and reissuance, or modification; or for denial of a permit renewal application. However, the permittee need not comply with the provisions of the permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 CFR §144.34.

(B) Need to halt or reduce activity not a defense. It shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit.

(C) Duty to mitigate. The permittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit.

(D) Proper operation and maintenance. The permittee shall at all times properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of the permit.

(E) Property rights not conveyed. The issuance of a permit does not convey property rights of any sort, or any exclusive privilege.

(F) Activities not authorized. The issuance of a permit does not authorize any injury to persons or property or invasion of other private rights, or any infringement of State or local law or regulations.

(G) Coordination with exploration. The permittee of a geologic storage well shall coordinate with any operator planning to drill through the AOR to explore for oil and gas or geothermal resources.

(H) Duty to provide information. The operator shall furnish to the Commission, within a time specified by the Commission, any information that the Commission may request to determine whether cause exists for modifying, revoking and reissuing, or terminating the permit, or to determine compliance with the permit. The operator shall also furnish to the Commission, upon request, copies of records required to be kept under the conditions of the permit.

(I) Inspection and entry. The operator shall allow any member or employee of the Commission, on proper identification, to:

(i) enter upon the premises where a regulated activity is conducted or where records are kept under the conditions of the permit;

(ii) have access to and copy, during reasonable working hours, any records required to be kept under the conditions of the permit;

(iii) inspect any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under the permit; and

(iv) sample or monitor any substance or parameter for the purpose of assuring compliance with the permit or as otherwise authorized by the Texas Water Code, §27.071, or the Texas Natural Resources Code, §91.1012.

(J) Schedule of compliance: The permit may, when appropriate, specify a schedule of compliance leading to compliance with all provisions of this subchapter and Chapter 3 of this title.

(i) Any schedule of compliance shall require compliance as soon as possible, and in no case later than three years after the effective date of the permit.

(ii) If the schedule of compliance is for a duration of more than one year from the date of permit issuance, then interim requirements and completion dates (not to exceed one year) must be incorporated into the compliance schedule and permit.

(iii) Progress reports must be submitted no later than 30 days following each interim date and the final date of compliance.

§5.207.Reporting and Record-Keeping.

(a) The operator of a geologic storage facility must provide, at a minimum, the following reports to the director and retain the following information.

(1) Test records. The operator must file a complete record of all tests in duplicate with the district office within 30 days after the testing. In conducting and evaluating the tests enumerated in this subchapter or others to be allowed by the director, the operator and the director must apply methods and standards generally accepted in the industry. When the operator reports the results of mechanical integrity tests to the director, the operator must include a description of any tests and methods [the test(s) and the method(s)] used. In making this evaluation, the director must review monitoring and other test data submitted since the previous evaluation.

(2) Operating reports. The operator also must include summary cumulative tables of the information required by the reports listed in this paragraph.

(A) Report within 24 hours. The operator must report to the appropriate district office the discovery of any significant pressure changes or other monitoring data that indicate the presence of leaks in the well or the lack of confinement of the injected gases to the geologic storage reservoir. Such report must be made orally as soon as practicable, but within 24 hours, following the discovery of the leak, and must be confirmed in writing within five working days.

(B) Report within 30 days. The operator must report:

(i) the results of periodic tests for mechanical integrity;

(ii) the results of any other test of the injection well conducted by the operator if required by the director; and

(iii) a description of any well workover.

(C) Semi-annual report. The operator must report:

(i) a summary of well head pressure monitoring;

(ii) changes to the physical, chemical, and other relevant characteristics of the CO2 stream from the proposed operating data;

(iii) monthly average, maximum and minimum values for injection pressure, flow rate and volume and/or mass, and annular pressure;

(iv) monthly annulus fluid volume added;

(v) [(iv)] a description of any event that significantly exceeds operating parameters for annulus pressure or injection pressure as specified in the permit;

(vi) [(v)] a description of any event that triggers a shutdown device and the response taken; and

(vii) [(vi)] the results of monitoring prescribed under §5.206(e) [§5.206(d)] of this title (relating to Permit Standards).

(D) Annual reports. The operator must submit an annual report detailing:

(i) corrective action performed;

(ii) new wells installed and the type, location, number, and information required in §5.203(e) of this title (relating to Application Requirements);

(iii) re-calculated AOR [area of review] unless the operator submits a statement signed by an appropriate company official confirming that monitoring and operational data supports the current delineation of the AOR [area of review] on file with the Commission;

(iv) the updated area for which the operator has a good faith claim to the necessary and sufficient property rights to operate the geologic storage facility;

(v) tons of CO2 injected;and

(vi) The operator must maintain and update required plans in accordance with the provisions of this subchapter.

(I) Operators must submit an annual statement, signed by an appropriate company official, confirming that the operator has:

(-a-) reviewed the monitoring and operational data that are relevant to a decision on whether to reevaluate the AOR [area of review] and the monitoring and operational data that are relevant to a decision on whether to update an approved plan required by §5.203 or §5.206 of this title; and

(-b-) determined whether any updates were warranted by material change in the monitoring and operational data or in the evaluation of the monitoring and operational data by the operator.

(II) Operators must submit either the updated plan or a summary of the modifications for each plan for which an update the operator determined to be warranted pursuant to subclause (I) of this clause. The director may require submission of copies of any updated plans and/or additional information regarding whether or not updates of any particular plans are warranted.

[(III) The director may require the revision of any required plan whenever the director determines that such a revision is necessary to comply with the requirements of this title.]

(vii) other information as required by the permit.

(3) The director may require the revision of any required plan following any significant changes to the facility, such as addition of injection or monitoring wells, on a schedule determined by the director or whenver the director determines that such a revision is necessary to comply with the requirements of this subchapter.

(b) Report format.

(1) The operator must report the results of injection pressure and injection rate monitoring of each injection well on Form H-10, Annual Disposal/Injection Well Monitoring Report, and the results of internal mechanical integrity testing on Form H-5, Disposal/Injection Well Pressure Test Report. Operators must submit other reports in a format acceptable to the Commission. At the discretion of the director, other formats may be accepted.

(2) The operator must submit all required reports, submittals, and notifications under this subchapter to the director and to the Environmental Protection Agency in an electronic format approved by the director.

(c) Signatories to reports.

(1) Reports. All reports required by permits and other information requested by the director, shall be signed by a person described in §5.203(a)(1)(B) of this title, or by a duly authorized representative of that person. A person is a duly authorized representative only if:

(A) the authorization is made in writing by a person described in §5.203(a)(1)(B) of this title;

(B) the authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager, operator of a well or a well field, superintendent, or position of equivalent responsibility; and

(C) the written authorization is submitted to the director.

(2) Changes to authorization. If an authorization under paragraph (1) of this subsection is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph (1) of this subsection must be submitted to the director prior to or together with any reports, information, or applications to be signed by an authorized representative.

(d) Certification. All reports required by permits and other information requested by the director under this subchapter, shall be certified as follows: "I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations."

(e) [(c)] Record retention. The operator must retain all wellhead pressure records, metering records, and integrity test results for at least 10 [five] years. The operator must retain all documentation of good faith claim to necessary and sufficient property rights to operate the geologic storage facility until the director issues the final certificate of closure in accordance with §5.206(k)(7) [§5.206(j)(7) ] of this title.

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 May 3, 2022.

TRD-202201724

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: June 19, 2022

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


CHAPTER 9. LP-GAS SAFETY RULES

(Editor's note: In accordance with Texas Government Code, §2002.014, which permits the omission of material which is "cumbersome, expensive, or otherwise inexpedient," the figures in 16 TAC §9.52(g)(1) and §9.403(a) are not included in the print version of the Texas Register. The figures are available in the on-line version of the May 20, 2022, issue of the Texas Register.)

The Railroad Commission of Texas (Commission) proposes amendments to the following rules in Subchapter A, General Requirements: §9.2, Definitions; §9.6, License Categories, Container Manufacturer Registration, and Fees; §9.7, Applications for Licenses, Manufacturer Registrations, and Renewals; §9.8, Requirements and Application for a New Certificate; §9.10, Rules Examination; §9.16, Hearings for Denial, Suspension, or Revocation of Licenses, Manufacturer Registrations, or Certificates; §9.22, Changes in Ownership, Form of Dealership, or Name of Dealership; §9.26, Insurance and Self-Insurance Requirements; §9.51, General Requirements for LP-Gas Training and Continuing Education; §9.52, Training and Continuing Education; §9.54, Commission-Approved Outside Instructors; and proposes new §9.20, DOT Cylinder Filler Certificate Exemption; and §9.55, PERC Outside Instructor Training.

In Subchapter B, LP-Gas Installations, Containers, Appurtenances, and Equipment Requirements, the Commission proposes amendments to §9.126, Appurtenances and Equipment; §9.130, Commission Identification Nameplates; §9.134, Connecting Container to Piping; §9.140, System Protection Requirements; §9.141, Uniform Safety Requirements; §9.142, LP-Gas Container Storage and Installation Requirements; and §9.143, Piping and Valve Protection for Stationary LP-Gas Installations with Individual or Aggregate Water Capacities of 4,001 Gallons or More.

In Subchapter C, Vehicles, the Commission proposes amendments to §9.202, Registration and Transfer of LP-Gas Transports or Container Delivery Units, and §9.211, Markings.

In Subchapter E, Adoption by Reference of NFPA 58 (LP-Gas Code), the Commission proposes amendments to §9.403, Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes or Additional Requirements.

The Commission proposes the amendments and new rules to incorporate provisions of Senate Bill 1582 (SB 1582) and Senate Bill 1668 (SB 1668), both enacted during the 87th Texas Legislative Session (Regular Session, 2021). Additional amendments are proposed as discussed in the following paragraphs.

Senate Bill 1668

Senate Bill 1668 added Natural Resources Code section 113.0955, which requires the Commission to waive its certification requirements for an individual who completes training consistent with the guidelines established by the Propane Education & Research Council (PERC) and complies with certain examination requirements. To incorporate this exemption, the Commission proposes amendments to the following rules: the definition of "certificate holder" in §9.2(5)(E) to include in the definition a person who holds a current DOT cylinder filler exemption; §9.8 to add new subsection (d) stating that an applicant for a new DOT cylinder filler certificate exemption shall comply with requirements of proposed new §9.20, which describes how an individual may apply for a DOT cylinder filler certificate exemption.

Proposed §9.20 provides two processes through which an individual may obtain the DOT cylinder filling exemption created by SB 1668. First, an individual may complete training and examination directly with PERC. An applicant for an exemption pursuant to this process in §9.20(1) must submit new LPG Form 16P, which will be proposed separately from the proposed amendments to Chapter 9. The applicant must also provide confirmation from PERC that the individual completed the PERC "Dispensing Propane Safely -- Small Cylinder" course and corresponding examination. Proposed new §9.20(1)(A)(ii)(III) states an effective date of July 18, 2022; this is the date the Commission expects the amendments will go into effect. However, the Commission will specify the correct effective date when the proposal is adopted.

The second process through which an individual may obtain the DOT cylinder filler certificate exemption is proposed in §9.20(2). This process requires an individual to complete an approved PERC based course under the supervision of a PERC outside instructor in accordance with §9.55.

Proposed §9.20(3) - (10) specify additional requirements for individuals who receive the DOT cylinder filler certificate exemption. Proposed §9.20(4) requires that individuals who are issued the exemption comply with certain Commission rules, which are not covered by the PERC Dispensing Propane Safely course. Proposed §9.20(6) clarifies that the exemption does not apply to individuals who fill containers mounted on a vehicle for mobile or motor fuel. Those individuals must meet the requirements of §9.8.

Other related amendments in §9.51(b) and (d)(4) and §9.52(a)(2)(C)(iv) add references to the DOT cylinder filler certificate exemption, and proposed new §9.52(h) provides continuing education credit for completion of a PERC outside instructor course. This is also reflected in proposed changes to Figure: 16 TAC §9.52(g)(1).

Finally, proposed new rule §9.55 contains the requirements for being approved as a PERC outside instructor such that an individual who takes courses and examinations administered by the PERC outside instructor is eligible for the DOT cylinder filler certificate exemption. The requirements of proposed new §9.55 are consistent with the existing requirements for outside instructors in §9.54, including the $300 registration fee. Proposed §9.55(a) states that AFS may award training and certification or continuing education credit to DOT cylinder filling employee-level applicants and certificate holders for courses administered by a PERC outside instructor provided the PERC outside instructor complies with the requirements of §9.55. The PERC outside instructor may only offer training consistent with the guidelines established by the PERC Dispensing Propane Safely -- Small Cylinder course. The PERC instructor may use recorded training videos but shall proctor the course examination. A PERC outside instructor must also be employed by a company licensed to perform DOT cylinder filling activities and must be able to show the instructor has experience in performing or supervising LP-gas activities. Proposed §9.55 specifies procedures for applying to be a PERC outside instructor, which will include submission of a form to be proposed separately from the proposed amendments to Chapter 9. Procedures are also proposed for obtaining approval of course materials, training PERC outside instructors, revising course materials, maintaining approved PERC outside instructor status, and reporting information on completed courses and exams to AFS. Importantly, §9.55(c) and (d) require PERC outside instructors to include training on Commission rules 9.135, 9.136, 9.137, 9.141(d) and (g), and the entry for NFPA 58 §7.4.3.1 in Figure 9.403, and to attend the Train-the-Trainer course. These requirements ensure PERC outside instructors are preparing prospective DOT cylinder filler exemption holders to comply with Commission rules in addition to requirements included in PERC based training.

Senate Bill 1582

Senate Bill 1582 amended Natural Resources Code sections 113.087 and 113.088 to provide for licensing and registration examination to be performed by a proctoring service. The bill also removed the requirement that a testing service that administers an examination collect a nonrefundable examination fee on behalf of the Commission. The Commission proposes amendments in §9.10(c)(1)(c) to incorporate the use of an online testing or proctoring service and in subsection (c)(4)(F) to ensure any required fee is paid to the testing or proctoring service in addition to the Commission's examination fee. A similar reference is proposed in subsection (e).

House Bill 2714 (86th Legislature, 2019)

The Commission previously adopted amendments to implement House Bill 2714 from the 86th Legislative Session regarding manufacturer registration. During the rulemaking to implement the requirements of House Bill 2714, the Commission failed to add a reference to manufacturer registration in §9.26. Proposed amendments in §9.26(a) add the reference to manufacturer registration.

Other Proposed Amendments

In §9.2, the Commission proposes removing the definitions of "Advanced field training (AFT)" and "AFT materials." The Commission also proposes removing AFT requirements and references throughout the chapter because AFT is no longer required. These amendments are proposed in §§9.8, 9.52, and 9.54. The Commission also proposes removing the definition of "repair to container" in §9.2 and instead proposes clarification regarding cylinder repair in §9.6(e). Changes made to or maintenance of a cylinder or cargo tank excluded from the definition of repair in 49 CFR §§180.203, 180.403, and 180.413 do not require a license. In §9.6(b)(14) the Commission proposes adding a reference to 25 horsepower, and in §9.6(d) adding "subframing," both of which were inadvertently omitted from previously adopted amendments in Chapter 9.

The Commission proposes new §9.7(i) to move the text from §9.140 so that the requirement for a 24-hour emergency telephone number is included as part of the Commission's licensing requirements. The Commission proposes the addition of "A2" in §9.7(m)(2) because this license category was inadvertently omitted from previously adopted amendments in Chapter 9. New subsection (m)(3) is proposed to ensure the license categories repairing or testing ASME containers are filing the correct certificate of authorization from ASME and to address situations in which ASME is unable to issue authorization prior to a license expiration date.

The Commission proposes a change in §9.10(d)(1)(G) to clarify that the Recreational Vehicle Technician examination qualifies an individual to install and repair appliances on recreational vehicles in addition to the activities listed in existing subsection (d)(1)(G). In §9.16(e)(3), §9.22(a)(2), and §9.130, the Commission proposes to correct references to AFS and remove requirements for mailing; and in §9.51 and §9.52(e) and (f) proposes clarifying changes regarding AFS scheduling and registration for courses to reflect current Commission practice.

The Commission proposes removing outdated tables from existing §9.52(h) and proposes changes to list available continuing education courses in §9.52(e) and (f). Proposed changes in §9.52(i), renumbered as proposed subsection (g), clarify that CETP courses are now only offered for employee-level certificate holders. These changes are also reflected in new Figure: 16 TAC §9.52(g)(1).

In §9.126 and §9.143, the Commission proposes to change references to pneumatically-operated to pneumatically-actuated because pneumatically-actuated valves can be operated automatically or manually through the use of cables. In §9.134, the Commission proposes new subsection (d) to address situations where LPG Form 22 is required but an LP-gas licensee does not know who the previous installer was. In §9.140(g), the Commission proposes new wording to address protection for cylinders in the horizontal position. Cylinders in the vertical position are not addressed separately because the cages required by NFPA 58 §8.4.2.2 were determined to be sufficient protection in a study by the Southwest Research Institute.

Some proposed amendments clarify previously adopted amendments regarding the National Fire Protection Association (NFPA) standards. These amendments are not substantive but were inadvertently omitted from the previous adopted amendments in Chapter 9. The amendments proposed to clarify NFPA updates are found in §9.140I(1) and (3), (d)(3), (f)(3) and (4), and (g)(2), and §9.141(b)(3) and (i), §9.142(b), and §9.211(b).

The Commission proposes amendments to §9.202 to coincide with the proposal of new forms, which will be proposed separately from these proposed amendments to Chapter 9.

The Commission also proposes changes to the Figure in §9.403. The Figure shows text from certain sections in NFPA 58 which the Commission has not adopted or has adopted with changes or with additional requirements. The text shown as underlined in the Figure indicates text that the Commission has added or changed from the NFPA 58 wording; the text shown with strike-outs indicates text that the Commission has deleted from the NFPA 58 text. In the case of this Figure, the underlining and strike-outs are retained in the adopted version of the Figure to show the changes. In this proposal, the specific changes to the Figure are found on the following rows: the rows for 5.2.8.1, 6.13.5, and 6.27.3.17 which correct a typographical error in the reference to §9.140(f) and the row for 6.8.2.1 which corrects a typographical error in the NFPA 58 section number. The row for 6.19.2 is being changed from an additional requirement to being adopted with changes; the Commission proposes to retain the wording of 6.19.12, including paragraphs (A) and (B), but adopts paragraph (C) to require compliance with §9.116. The addition of row 6.27.5.2 corrects an error from NFPA in the 2020 edition of NFPA 58; the change in the Figure ensures consistency with the NFPA tentative interim amendment issued for the 2020 version of NFPA 58, which the Commission has not yet adopted. In the row for 6.29.3.2, the Commission changes the wording to include the specific date of September 1, 2022, instead of the reference to two years from the effective date of the code.

April Richardson, Director, Alternative Fuels Safety Department, has determined that there will be a one-time cost to the Commission of approximately $404 in programming costs based on four hours of programming to implement a new fee code associated with new LPG Form 16P. This cost will be covered using the Commission's existing budget. There are no anticipated fiscal implications for local governments as a result of enforcing the amendments and new rule.

Ms. Richardson has determined that there will be costs for those seeking a DOT Cylinder Filler Certificate Exemption pursuant to Natural Resources Code section 113.0955. The cost is $40 per applicant for an exemption. However, an individual seeking certification to perform LP-gas activities must pay $40 regardless of whether the individual is certified through the exemption process or the examination process. Therefore, the proposed amendments do not increase the cost for individuals seeking certification through the DOT cylinder filler exemption. In addition, an individual seeking to become an approved PERC outside instructor would be required to pay a $300 registration fee. The $300 registration fee is already required for individuals seeking to become outside instructors. Further, due to changes made by SB 1582, persons required to comply with the proposed amendments will incur the cost of taking an examination administered by a testing or proctoring service. The testing or proctoring service will determine the fee. There are no other anticipated costs for persons required to comply with the proposed amendments.

Ms. Richardson has also determined that the public benefit anticipated as a result of enforcing or administering the amendments will be compliance with recent changes to the Texas Natural Resources Code and increased public safety due to clarification of NFPA standards.

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 and new rule; therefore, the Commission has not prepared the economic impact statement or the regulatory flexibility analysis required 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 rules.

The Commission has determined that the proposed amendments and new rule 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; create a new regulation; or affect the state's economy. The proposed amendments could increase fees paid to the agency depending on the amount of PERC outside instructor applications the Commission receives. The proposed amendments decrease the number of individuals subject to the Commission's examination requirements and limit the examination rules' applicability. However, the Commission was required to waive the examination requirements by Senate Bill 1668. The amendments are proposed to align Commission rules with governing state statutes and national standards.

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, June 3, 2022. 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. Richardson at (512) 463-6935. The status of Commission rulemakings in progress is available at www.rrc.texas.gov/general-counsel/rules/proposed-rules.

SUBCHAPTER A. GENERAL REQUIREMENTS

16 TAC §§9.2, 9.6 - 9.8, 9.10, 9.16, 9.20, 9.22, 9.26, 9.51, 9.52, 9.54, 9.55

The Commission proposes the amendments and new rules under Natural Resources Code sections 113.087 and 113.088, amended by Senate Bill 1582 (87th Legislature, Regular Session), and Natural Resources Code section 113.0955, added by Senate Bill 1668 (87th Legislature, Regular Session). The Commission also proposes the amendments under Texas Natural Resources Code, §113.051, which authorizes the Commission to promulgate and adopt rules and standards relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public.

Statutory authority: Texas Natural Resources Code, §§113.051, 113.087, 113.088 and 113.0955.

Cross reference to statute: Texas Natural Resources Code Chapter 113.

§9.2.Definitions.

In addition to the definitions in any adopted NFPA pamphlets, the following words and terms, when used in this chapter, shall have the following meanings, unless the context clearly indicates otherwise.

(1) (No change.)

[(2) Advanced field training (AFT)--The final portion of the training or continuing education requirements in which an individual shall successfully perform the specified LP-gas activities in order to demonstrate proficiency in those activities.]

[(3) AFT materials--The portion of a Commission training module consisting of the four sections of the Railroad Commission's LP-Gas Qualifying Field Activities, including General Instructions, the Task Information, the Operator Qualification Checklist, and the Railroad Commission/Employer Record.]

(2) [(4)] Aggregate water capacity (AWC)--The sum of all individual container capacities measured by weight or volume of water which are placed at a single installation location.

(3) [(5)] Bobtail driver--An individual who operates an LP-gas cargo tank motor vehicle of 5,000 gallons water capacity or less in metered delivery service.

(4) [(6)] Breakaway--The accidental separation of a hose from a cylinder, container, transfer equipment, or dispensing equipment, which could occur on a cylinder, container, transfer equipment, or dispensing equipment whether or not they are protected by a breakaway device.

(5) [(7)] Certificate holder--An individual:

(A) who has passed the required management-level qualification examination, pursuant to §9.10 of this title (relating to Rules Examination);

(B) who has passed the required employee-level qualification examination pursuant to §9.10 of this title;

(C) who holds a current reciprocal examination exemption pursuant to §9.18 of this title (relating to Reciprocal Examination Agreements with Other States); [or]

(D) who holds a current examination exemption certificate pursuant to §9.13 of this title (relating to General Installers and Repairman Exemption); or [.]

(E) who holds a current DOT cylinder filler certificate exemption pursuant to §9.20 of this title (relating to DOT Cylinder Filler Certificate Exemption).

(6) [(8)] Certified--Authorized to perform LP-gas work as set forth in the Texas Natural Resources Code. Employee certification alone does not allow an individual to perform those activities which require licensing.

(7) [(9)] CETP--The Certified Employee Training Program offered by the Propane Education and Research Council (PERC), the National Propane Gas Association (NPGA), or their authorized agents or successors.

(8) [(10)] Commercial installation--An LP-gas installation located on premises other than a single family dwelling used as a residence, including but not limited to a retail business establishment, school, bulk storage facility, convalescent home, hospital, cylinder exchange operation, service station, forklift refueling facility, private motor/mobile fuel cylinder filling operation, a microwave tower, or a public or private agricultural installation.

(9) [(11)] Commission--The Railroad Commission of Texas.

(10) [(12)] Company representative--The individual designated to the Commission by a license applicant or a licensee as the principal individual in authority and, in the case of a licensee other than a Category P licensee, actively supervising the conduct of the licensee's LP-gas activities.

(11) [(13)] Container delivery unit--A vehicle used by an operator principally for transporting LP-gas in cylinders.

(12) [(14)] Continuing education--Courses required to be successfully completed at least every four years by certificate holders to maintain certification.

(13) [(15)] Director--The director of AFS or the director's delegate.

(14) [(16)] DOT--The United States Department of Transportation.

(15) [(17)] Employee--An individual who renders or performs any services or labor for compensation, including individuals hired on a part-time or temporary basis, on a full-time or permanent basis, and owner-employees.

(16) [(18)] Interim approval order--The authority issued by the Railroad Commission of Texas following a public hearing allowing construction of an LP-gas installation.

(17) [(19)] Leak grades--An LP-gas leak that is:

(A) a Grade 1 leak that represents an existing or probable hazard to persons or property, and requires immediate repair or continuous action until the conditions are no longer hazardous; or

(B) a Grade 2 leak that is recognized as being nonhazardous at the time of detection, but requires a scheduled repair based on a probable future hazard.

(18) [(20)] Licensed--Authorized by the Commission to perform LP-gas activities through the issuance of a valid license.

(19) [(21)] Licensee--A person which has applied for and been granted an LP-gas license by the Commission, or who holds a master or journeyman plumber license from the Texas State Board of Plumbing Examiners or a Class A or B Air Conditioning and Refrigeration Contractors License from the Texas Department of Licensing and Regulation and has properly registered with the Commission.

(20) [(22)] LP-Gas Safety Rules--The rules adopted by the Railroad Commission in the Texas Administrative Code, Title 16, Part 1, Chapter 9, including any NFPA or other documents adopted by reference. The official text of the Commission's rules is that which is on file with the Secretary of State's office and available at the Secretary of State's web site or the Commission's web site.

(21) [(23)] LP-gas system--All piping, fittings, valves, and equipment, excluding containers and appliances, that connect one or more containers to one or more appliances that use or consume LP-gas.

(22) [(24)] Mass transit vehicle--Any vehicle which is owned or operated by a political subdivision of a state, city, or county, used primarily in the conveyance of the general public.

(23) [(25)] Mobile fuel container--An LP-gas container mounted on a vehicle to store LP-gas as the fuel supply to an auxiliary engine other than the engine to propel the vehicle or for other uses on the vehicle.

(24) [(26)] Mobile fuel system--An LP-gas system, excluding the container, to supply LP-gas as a fuel to an auxiliary engine other than the engine to propel the vehicle or for other uses on the vehicle.

(25) [(27)] Motor fuel container--An LP-gas container mounted on a vehicle to store LP-gas as the fuel supply to an engine used to propel the vehicle.

(26) [(28)] Motor fuel system--An LP-gas system, excluding the container, which supplies LP-gas to an engine used to propel the vehicle.

(27) [(29)] Noncorrosive--Corrosiveness of gas which does not exceed the limitation for Classification 1 of ASTM International (ASTM) Copper Strip Classifications when tested in accordance with ASTM D 1834-64, "Copper Strip Corrosion of Liquefied Petroleum (LP) Gases."

(28) [(30)] Nonspecification unit--An LP-gas transport not constructed to DOT MC-330 or MC-331 specifications but which complies with the exemption in 49 Code of Federal Regulations §173.315(k). (See also "Specification unit" in this section.)

(29) [(31)] Operations supervisor--The individual who is certified by the Commission to actively supervise a licensee's LP-gas activities and is authorized by the licensee to implement operational changes.

(30) [(32)] Outlet--A site operated by an LP-gas licensee from which any regulated LP-gas activity is performed.

(31) [(33)] Outside instructor--An individual, other than a Commission employee, approved by AFS to teach certain LP-gas training or continuing education courses.

(32) [(34)] Person--An individual, partnership, firm, corporation, joint venture, association, or any other business entity, a state agency or institution, county, municipality, school district, or other governmental subdivision, or licensee, including the definition of "person" as defined in the applicable sections of 49 CFR relating to cargo tank hazardous material regulations.

(33) [(35)] Portable cylinder--A receptacle constructed to DOT specifications, designed to be moved readily, and used for the storage of LP-gas for connection to an appliance or an LP-gas system. The term does not include a cylinder designed for use on a forklift or similar equipment.

(34) [(36)] Property line--The boundary which designates the point at which one real property interest ends and another begins.

(35) [(37)] Public transportation vehicle--A vehicle for hire to transport persons, including but not limited to taxis, buses (excluding school buses and mass transit or special transit vehicles), or airport courtesy vehicles.

(36) [(38)] Recreational vehicle--A vehicular-type unit primarily designed as temporary living quarters for recreational, camping, travel, or seasonal use that either has its own motive power or is mounted on, or towed by, another vehicle.

(37) [(39)] Registered manufacturer--A person who has applied for and been granted a registration to manufacture LP-gas containers by the Commission.

[(40) Repair to container--The correction of damage or deterioration to an LP-gas container, the alteration of the structure of such a container, or the welding on such container in a manner which causes the temperature of the container to rise above 400 degrees Fahrenheit.]

(38) [(41)] Rules examination--The Commission's written examination that measures an examinee's working knowledge of Chapter 113 of the Texas Natural Resources Code and/or the current rules in this chapter.

(39) [(42)] School--A public or private institution which has been accredited through the Texas Education Agency or the Texas Private School Accreditation Commission.

(40) [(43)] School bus--A vehicle that is sold or used for purposes that include carrying students to and from school or related events.

(41) [(44)] Self-service dispenser--A listed device or approved equipment in a structured cabinet for dispensing and metering LP-gas between containers that must be accessed by means of a locking device such as a key, card, code, or electronic lock, and which is operated by a certified employee of an LP-gas licensee or an ultimate consumer trained by an LP-gas licensee.

(42) [(45)] Service station--An LP-gas installation that, for retail purposes, operates a dispensing station and/or conducts cylinder filling activities.

(43) [(46)] Special transit vehicle--A vehicle designed with limited passenger capacity which is used by a mass transit authority for special transit purposes, such as transport of mobility impaired persons.

(44) [(47)] Specification unit--An LP-gas transport constructed to DOT MC-330 or MC-331 specifications. (See also "Nonspecification unit" in this section.)

(45) [(48)] Subframing--The attachment of supporting structural members to the pads of a container, excluding welding directly to or on the container.

(46) [(49)] Trainee--An individual who has not yet taken and passed an employee-level rules examination.

(47) [(50)] Training--Courses required to be successfully completed as part of an individual's requirements to obtain or maintain certain certificates.

(48) [(51)] Transfer system--All piping, fittings, valves, pumps, compressors, meters, hoses, bulkheads, and equipment utilized in transferring LP-gas between containers.

(49) [(52)] Transport--Any bobtail or semitrailer equipped with one or more containers.

(50) [(53)] Transport driver--An individual who operates an LP-gas trailer or semi-trailer equipped with a container of more than 5,000 gallons water capacity.

(51) [(54)] Transport system--Any and all piping, fittings, valves, and equipment on a transport, excluding the container.

(52) [(55)] Ultimate consumer--A person who buys a product to use rather than for resale.

§9.6.License Categories, Container Manufacturer Registration, and Fees.

(a) (No change.)

(b) The license categories and fees are as follows.

(1) - (13) (No change.)

(14) A Category L license for engine and mobile fuel authorizes the sale and installation of LP-gas motor or mobile fuel containers, and the sale and installation of LP-gas motor or mobile fuel systems over 25 horsepower. The original license fee is $100; the renewal is $50.

(15) - (18) (No change.)

(c) (No change.)

(d) A container manufacturer registration authorizes the manufacture, assembly, repair, subframing, testing and sale of LP-gas containers. The original registration fee is $1,000; the renewal fee is $600.

(e) Repair to a US DOT cylinder or cargo tank is defined in 49 CFR §§180.203, 180.403 and 180.413. Changes made to or maintenance of a cylinder or cargo tank excluded from the definition of repair in 49 CFR §§180.203, 180.403 and 180.413 do not require a license.

§9.7.Applications for Licenses, Manufacturer Registrations, and Renewals.

(a) - (f) (No change.)

(g) A licensee shall submit LPG Form 1A listing all outlets operated by the licensee.

(1) (No change.)

(2) Each outlet shall be listed on the licensee's renewal as specified in subsection (k) [(i)] of this section.

(h) (No change.)

(i) Applications for license or registration must include a 24-hour emergency telephone number that shall be:

(1) monitored at all times; and

(2) be answered by a person who is knowledgeable of the hazards of LP-gas and who has comprehensive LP-gas emergency response and incident information, or has immediate access to a person who possesses such knowledge and information. A telephone number that requires a call back (such as an answering service, answering machine, or beeper device) does not meet the requirements of this section.

(j) [(i)] AFS will review an application for license or registration to verify all requirements have been met.

(1) If errors are found or information is missing on the application or other documents, AFS will notify the applicant of the deficiencies in writing.

(2) The applicant must respond with the required information and/or documentation within 30 days of the written notice. Failure to respond by the deadline will result in withdrawal of the application.

(3) If all requirements have been met, AFS will issue the license or manufacturer registration and send the license or registration to the licensee or manufacturer, as applicable.

(k) [(j)] For license and manufacturer registration renewals:

(1) AFS shall notify the licensee or registered manufacturer in writing at the address on file with AFS of the impending license or manufacturer registration expiration at least 30 calendar days before the date the license or registration is scheduled to expire.

(2) The renewal notice shall include copies of applicable LPG Forms 1, 1A, and 7, or LPG Form 1M showing the information currently on file.

(3) The licensee or registered manufacturer shall review and return all renewal documentation to AFS with any necessary changes clearly marked on the forms. The licensee or registered manufacturer shall submit any applicable fees with the renewal documentation.

(4) Failure to meet the renewal deadline set forth in this section shall result in expiration of the license or manufacturer registration.

(5) If a person's license or manufacturer registration expires, that person shall immediately cease performance of any LP-gas activities authorized by the license or registration.

(6) If a person's license or manufacturer registration has been expired for 90 calendar days or fewer, the person shall submit a renewal fee that is equal to 1 1/2 times the renewal fee in §9.6 of this title (relating to License Categories, Container Manufacturer Registration, and Fees).

(7) If a person's license or manufacturer registration has been expired for more than 90 calendar days but less than one year, the person shall submit a renewal fee that is equal to two times the renewal fee.

(8) If a person's license or manufacturer registration has been expired for one year or more, that person shall not renew but shall comply with the requirements for issuance of an original license or manufacturer registration under subsection (f) or (h) of this section.

(9) After verification that the licensee or registered manufacturer has met all requirements for licensing or manufacturer registration, AFS shall renew the license or registration and send the applicable authorization to the licensee or manufacturer.

(l) [(k)] A person who was licensed in this state, moved to another state, and is currently licensed and has been in practice in the other state for the two years preceding the date of application may obtain a new license without reexamination. The person shall pay to AFS a fee that is equal to two times the renewal fee required by §9.6 of this title.

(1) As a prerequisite to licensing pursuant to this provision, the person shall submit, in addition to an application for licensing, proof of having been in practice and licensed in good standing in another state continuously for the two years immediately preceding the filing of the application;

(2) A person licensed under this provision shall be required to comply with all requirements of licensing other than the examination requirement, including but not limited to the insurance requirements as specified in §9.26 of this title and the continuing education and training requirements as specified in §9.51 of this title (relating to General Requirements for LP-Gas Training and Continuing Education), and §9.52 of this title (relating to Training and Continuing Education).

(m) [(l)] Applicants for license or license renewal in the following categories shall comply with these additional requirements:

(1) An applicant for a Category B or O license or renewal shall file with AFS a properly completed LPG Form 505 certifying that the applicant will follow the testing procedures indicated. The company representative designated on the licensee's LPG Form 1 shall sign LPG Form 505.

(2) An applicant for Category A, A2, B, or O license or renewal who tests tanks, subframes LP-gas cargo tanks, or performs other activities requiring DOT registration shall file with AFS a copy of any applicable current DOT registrations. Such registration shall comply with Title 49, Code of Federal Regulations, Part 107 (Hazardous Materials Program Procedures), Subpart F (Registration of Cargo Tank and Cargo Tank Motor Vehicle Manufacturers and Repairers and Cargo Tank Motor Vehicle Assemblers).

(3) An applicant for Category A, A1 or O license or renewal who repairs or tests ASME containers shall file with AFS a copy of its current ASME Code, Section VIII certificate of authorization or "R" certificate. If ASME is unable to issue a renewed certificate of authorization prior to the expiration date, the manufacturer may request in writing an extension of time not to exceed 60 calendar days past the expiration date. The request for extension shall be received by AFS prior to the expiration date of the ASME certificate of authorization referred to in this section, and shall include a letter or statement from ASME that the agency is unable to issue the renewal certificate of authorization prior to expiration and that a temporary extension will be granted for its purposes. A registered manufacturer shall not continue to operate after the expiration date of an ASME certificate of authorization until the manufacturer files a current ASME certificate of authorization with AFS or AFS grants a temporary exception.

§9.8.Requirements and Application for a New Certificate.

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

(c) An applicant for a new certificate shall:

(1) file with AFS a properly completed LPG Form 16 and the applicable nonrefundable rules examination fee specified in §9.10 of this title (relating to Rules Examination);

(2) pass the applicable rules examination with a score of at least 75%; and

(3) complete any required training [and/or AFT] in §9.51 and §9.52 of this title.

(d) An applicant for a new DOT cylinder filler certificate exemption shall comply with the requirements of §9.20 of this title (relating to DOT Cylinder Filler Certificate Exemption).

(e) [(d)] An individual who holds an employee-level certificate who wishes to obtain a management-level certificate shall comply with the requirements of this section, including training and fees.

§9.10.Rules Examination.

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

(c) An individual who files LPG Form 16 and pays the applicable nonrefundable examination fee may take the rules examination.

(1) Dates and locations of available Commission LP-gas examinations may be obtained [in the Austin offices of AFS and] on the Commission's web site[, and shall be updated at least monthly]. Examinations may be administered: [conducted]

(A) at the Commission's AFS Training Center in Austin; [, between the hours of 8:00 a.m. and 12:00 noon, Monday through Friday, except for state holidays, and]

(B) at other designated [times and] locations around the state; and [.]

(C) through an online testing or proctoring service.

(2) Individuals or companies may request in writing that examinations be given in their area. AFS shall schedule [its] examinations [and locations] at its discretion.

(3) [(2)] Except in a case where a conditional qualification has been requested in writing and approved under §9.17(g) of this title (relating to Designation and Responsibilities of Company Representatives and Operations Supervisors), the Category E, F, G, I, and J management-level rules examination shall be administered only in conjunction with the Category E, F, G, I, and J management-level courses of instruction. Management-level rules examinations other than Category E, F, G, I, and J may be administered on any scheduled examination day.

(4) [(3)] Exam fees.

(A) The nonrefundable management-level rules examination fee is $70.

(B) The nonrefundable employee-level rules examination fee is $40.

(C) The nonrefundable examination fee shall be paid each time an individual takes an examination.

(D) Individuals who register and pay for a Category E, F, G, I, or J training course as specified in §9.51(j)(2)(A) of this title (relating to General Requirements for LP-Gas Training and Continuing Education) shall pay the charge specified for the applicable examination.

(E) A military service member, military veteran, or military spouse shall be exempt from the examination fee pursuant to the requirements in §9.14 of this title (relating to Military Fee Exemption). An individual who receives a military fee exemption is not exempt from renewal, training, or continuing education fees specified in §9.9 of this title (relating to Requirements for Certificate Holder Renewal, §9.51 of this title, and §9.52 of this title (relating to Training and Continuing Education.

(F) Individuals who register for an examination to be administered by a testing or proctoring service shall pay any required fee to the testing or proctoring service in addition to paying the examination fee to the Commission.

(5) [(4)] Time limits.

(A) An applicant shall complete the examination within the time limit specified in this paragraph.

(i) The Category E management-level (closed book), Bobtail employee-level (open book), and Service and Installation employee-level (open book) examinations shall be limited to three hours.

(ii) All other management-level and employee-level examinations shall be limited to two hours.

(B) The examination proctor shall be the official timekeeper.

(C) An examinee shall submit the examination and the answer sheet to the examination proctor before or at the end of the established time limit for an examination.

(D) The examination proctor shall mark any answer sheet that was not completed within the time limit.

(6) [(5)] The Commission may offer employee-level LP-Gas Transport Driver, DOT Cylinder Filling, and Motor/Mobile Fuel Dispensing examinations in Spanish or English.

(d) This subsection specifies the examinations offered by the Commission.

(1) Employee-level examinations.

(A) - (F) (No change.)

(G) The Recreational Vehicle Technician examination qualifies an individual to install LP-gas motor or mobile fuel containers, including cylinders, and to install and repair LP-gas systems and appliances on recreational vehicles. The Recreational Vehicle Technician examination does not authorize an individual to fill LP-gas containers.

(H) - (J) (No change.)

(2) (No change.)

(e) Within 15 calendar days of the date an individual takes an examination, AFS shall notify the individual of the results of the examination. If the examination is graded or reviewed by a testing or proctoring service, AFS shall notify the individual of the examination results within 14 days of the date AFS receives the results from the testing or proctoring service. If the notice of the examination results will be delayed for longer than 90 days after the examination date, AFS shall notify the individual of the reason for the delay before the 90th day. AFS may require a testing or proctoring service to notify an individual of the individual's examination results.

(f) - (h) (No change.)

§9.16.Hearings for Denial, Suspension, or Revocation of Licenses, Manufacturer Registrations, or Certificates.

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

(c) Suspension or revocation of licenses, manufacturer registrations, or certificates.

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

(3) The licensee, registered manufacturer, or certificate holder shall either report the correction or discontinuance of the violation or noncompliance within the time frame specified in the notice or shall request an extension of time in which to comply. The request for extension of the time to comply shall be received by AFS [LP-Gas Operations] within the same time frame specified in the notice for correction or discontinuance.

(d) (No change.)

§9.20.DOT Cylinder Filler Certificate Exemption.

An individual may perform work and directly supervise LP-gas activities requiring contact with LP-gas if the individual is granted the DOT Cylinder Filler Certificate Exemption. The exemption may be obtained by completing the Dispensing Propane Safely - Small Cylinder course, including examination, and complying with paragraph (1) of this section or by completing PERC outside instructor training and examination in accordance with paragraph (2) of this section.

(1) DOT Cylinder Filling Certificate Exemption through PERC.

(A) To be granted a DOT Cylinder Filler Certificate Exemption through PERC, the applicant shall:

(i) submit a properly completed LPG Form 16P;

(ii) submit a legible copy of the PERC certificate of completion, which shall:

(I) indicate that the Dispensing Propane Safely -- Small Cylinder course has been completed, including a copy of the transcript listing the Filling Cylinders by Weight examination was completed;

(II) be issued to the individual listed on LPG Form 16P; and

(III) have a completion date after July 18, 2022, and within six months of the date the LPG Form 16P is submitted;

(iii) submit a legible copy of a state-issued identification card or driver's license, including a photo; and

(iv) pay a $40 registration fee.

(B) AFS will review the application to verify all requirements have been met.

(i) If errors are found or information is missing on the application or other documents, AFS shall notify the applicant of the deficiencies in writing.

(ii) The applicant must respond with the required information and/or documentation within 30 days of the written notice. Failure to respond by the deadline will result in withdrawal of the application.

(iii) If all requirements have been met, the individual will become a certificate holder and AFS shall send a certificate to the licensee.

(2) DOT Cylinder Filling Certificate Exemption through PERC Outside Instructor.

(A) Any individual who completes an approved PERC based course under the supervision of a PERC outside instructor will be granted a DOT Cylinder Filler Certificate Exemption provided the PERC outside instructor submits the report as required in §9.55(j) of this title (relating to PERC Outside Instructor Training). The course shall include training and examination. The examination shall be proctored by a PERC outside instructor. If all requirements have been met, the individual will become a certificate holder and AFS shall send a certificate to the licensee listed on the PERC outside instructor's report.

(B) AFS may refuse to issue or renew a certificate for an individual who presents for credit an unapproved course; a course from an unapproved PERC outside instructor; or a course using unapproved, incomplete, or incorrect materials.

(3) The DOT Cylinder Filling Certificate Exemption does not become effective until the certificate is issued by AFS.

(4) Certificate holders issued a DOT Cylinder Filler Certificate exemption shall comply with the rules in this chapter, including the following rules:

(A) §9.135 of this title (relating to Unsafe or Unapproved Containers, Cylinders, or Piping);

(B) §9.136 of this title (relating to Filling of DOT Containers);

(C) §9.137 of this title (relating to Inspection of Cylinders at Each Filling);

(D) §9.141(d) and (g) of this title (relating to Uniform Safety Requirements); and

(E) the entry for NFPA 58 §7.4.3.1 in the Figure in §9.403 of this title (relating to Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes or Additional Requirements).

(5) The DOT cylinder filler certificate exemption does not include the motor/mobile fuel filler certificate. Individuals may only fill US DOT cylinders by weight with this exemption. Universal cylinders, commonly used on forklifts and floor buffers, may be filled by volume using filling procedures required by §9.136 of this title (relating to Filling of DOT Containers).

(6) Individuals who will fill containers mounted on a vehicle for mobile or motor fuel must meet the requirements of §9.8(c) of this title (relating to Requirements and Application for a New Certificate).

(7) The certificate accrues to the individual and is nontransferable. An individual who has been issued a certificate shall make the certificate readily available and shall present it to any Commission employee or agent who requests proof of certification.

(8) Each individual shall:

(A) comply with all applicable continuing education requirements in §9.51 and §9.52 of this title (relating to General Requirements for LP-Gas Training and Continuing Education, and Training and Continuing Education, respectively);

(B) comply with renewal requirements in §9.9 of this title (relating to Requirements for Certificate Holder Renewal); and

(C) be employed by a licensee or a license-exempt entity in accordance with §9.7 of this title (relating to Application for Licenses, Manufacturer Registrations, and Renewals.

(9) Failure to comply with the renewal requirements in §9.9 of this title shall result in the expiration of the certificate. If an individual's exemption has been expired for more than two years, that individual shall complete all requirements necessary to apply for a new certificate.

(10) A military service member, military veteran, or military spouse shall be exempt from the original registration fee pursuant to the requirements in §9.14 of this title (relating to Military Fee Exemption). An individual who receives a military fee exemption is not exempt from renewal fees specified in §9.9 of this title.

§9.22.Changes in Ownership, Form of Dealership, or Name of Dealership.

(a) Changes in ownership which require a new license or manufacturer registration.

(1) (No change.)

(2) Other changes in ownership. A change in members of a partnership occurs upon the death, withdrawal, expulsion, or addition of a partner. Upon the death of a sole proprietor or partner, the dissolution of a corporation or partnership, any change in the members of a partnership, or other change in ownership not specifically provided for in this section, an authorized representative of the previously existing dealership or of the successor in interest shall notify AFS in writing and shall immediately cease all LP-gas activities of the previously existing dealership which require an LP-gas license or manufacturer registration and shall not resume until AFS [LP-Gas Operations] issues an LP-gas license or manufacturer registration to the successor in interest.

(b) - (e) (No change.)

§9.26.Insurance and Self-Insurance Requirements.

(a) A licensee or registered manufacturer shall not perform any activity authorized by its license or registration under §9.6 of this title (relating to License Categories, Container Manufacturer Registration, and Fees) unless insurance coverage required by this section is in effect. LP-gas licensees, registered manufacturers, or applicants for license or manufacturer registration shall comply with the minimum amounts of insurance specified in Table 1 of this section or with the self-insurance requirements in subsection (i) of this section, if applicable. Registered manufacturers are not eligible for self-insurance. Before AFS grants or renews a manufacturer registration, an applicant for a manufacturer registration shall submit the documents required by paragraph (1) of this subsection. Before AFS grants or renews a license or manufacturer registration, an applicant for a license shall submit either:

Figure: 16 TAC §9.26(a) (No change.)

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

(b) - (j) (No change.)

§9.51.General Requirements for LP-Gas Training and Continuing Education.

(a) (No change.)

(b) Applicants for new certificates, as set forth in §9.8 of this title (relating to Requirements and Application for a New Certificate) and persons holding existing certificates or a DOT cylinder filler certificate exemption shall comply with the training or continuing education requirements in this chapter. Any individual who fails to comply with the training or continuing education requirements by the assigned deadline may regain certification by paying the nonrefundable course fee and satisfactorily completing an authorized training or continuing education course within two years of the deadline. In addition to paying the course fee, the person shall pay any fee or late penalties to AFS.

(c) (No change.)

(d) The continuing education requirements apply to the following individuals:

(1) Category D, E, F, G, I, J, K, and M management-level certificate holders;

(2) any ultimate consumer who has purchased, leased, or obtained other rights in any LP-gas bobtail, including any employee of such ultimate consumer if that employee drives or in any way operates the equipment on an LP-gas bobtail; [and]

(3) individuals holding the following employee-level certifications:

(A) bobtail driver;

(B) DOT cylinder filler;

(C) recreational vehicle technician;

(D) service and installation technician;

(E) appliance service and installation technician; and

(F) motor/mobile fuel filler; and [.]

(4) individuals holding a DOT cylinder filler certificate exemption.

(e) - (h) (No change.)

(i) Schedules. Dates and locations of available AFS LP-gas training and continuing education courses can be obtained [in the Austin offices of AFS, and] on the Commission's web site [and shall be updated at least monthly]. AFS courses shall be conducted in Austin and in other locations around the state. Individuals or companies may request in writing that AFS courses be taught in their area. AFS shall schedule [its] courses [and locations] at its discretion.

(j) Course registration and scheduling.

(1) Registering for a course. To register for a scheduled training or continuing education course, an individual shall complete the online registration process at least seven days prior to the course. [AFS shall also accept course registrations via regular mail, electronic mail (e-mail), or facsimile transmission (fax). Such requests shall include the applicant's full name, address, phone number, level (either manager or employee) and category of certification (such as cylinder filling or service and installation), e-mail address, and the name or number, location, and date of the requested course.]

(2) Costs for courses.

(A) - (C) (No change.)

(D) Continuing education courses shall be offered at no charge to certificate holders who have timely paid the annual certificate renewal fee specified in §9.9 of this title (relating to Requirements for Certificate Holder Renewal).

(E) - (F) (No change.)

(3) [Course scheduling. AFS shall schedule individuals to attend courses on a first-come, first-served basis, based on when the course fee is paid except as follows:]

[(A) Priority for attending the 16-hour Category F, G, I, and J course, and the 80-hour Category E course is based on when the course fee is paid.]

[(B) Priority for attending courses other than the 16-hour Category F, G, I, and J course, and the 80-hour Category E course shall be given to applicants or certificate holders who must comply with training or continuing education requirements by the next May 31 deadline.]

[(C)] If any course has fewer than eight individuals registered within seven calendar days prior to the course, AFS may cancel the course and may reschedule the registered individuals in another course agreed upon by the individuals and the AFS training section. The AFS training section reserves the right to determine the number of course registrants.

(4) - (5) (No change.)

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

§9.52.Training and Continuing Education.

(a) Training. Individuals identified in §9.51(c) of this title (relating to General Requirements for LP-Gas Training and Continuing Education) shall complete training.

(1) (No change.)

(2) Training requirements.

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

(C) Category D, K and M management-level applicants and all applicants for employee-level certifications that are subject to training requirements shall complete an eight-hour course. A certificate holder's training deadline shall not be extended if that individual retakes and passes an examination for the current category and level of certification. A training deadline shall be extended only after a certificate holder successfully completes an applicable training course.

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

(iv) DOT Cylinder Filler applicants shall complete the 2.1 course unless the individual is issued a DOT cylinder filler certificate exemption.

(v) - (ix) (No change.)

(3) Individuals who pass an employee-level rules examination between March 1 and May 31 of any year shall have until May 31 of the next year to complete any required training. Individuals who pass an employee-level rules examination at other times shall have until the next May 31 to complete any required training. [Completion of AFT shall be in accordance with subsection (g) of this section.]

(4) (No change.)

(b) Continuing education. A certificate holder shall complete at least eight hours of continuing education every four years as specified in this subsection. Continuing education courses are specified in subsection (e) [(g)] of this section.

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

(c) - (d) (No change.)

[(e) Course materials. Individuals who attend AFS-taught training courses shall receive a copy of the course materials at no charge. Additional copies may be purchased from AFS at the established price.]

[(f) Certificates of completion. The AFS training section shall issue a certificate of completion to each individual who completes a management-level course.]

[(g) Advanced field training (AFT). Some courses may include AFT in addition to the classroom hours, during which course attendees shall perform LP-gas activities. AFT shall be properly completed within 30 calendar days of attending the course. All qualification tasks included in the AFT shall be completed. The AFT materials, including the qualification checklist and the certification page, shall be readily available at the licensee's Texas business location for review by an authorized Commission representative during normal business hours.]

[(1) The responsibility of certifying AFT activities shall not be delegated to an unauthorized individual. AFT qualification tasks shall be witnessed by an authorized individual, verified as being successfully completed, and the AFT form signed as follows:]

[(A) For licensees with only one company representative, that company representative shall self-certify the AFT.]

[(B) For licensees with more than one company representative, one company representative may certify the AFT of another company representative, but shall not self-certify.]

[(C) Company representatives shall certify operations supervisors' AFT.]

[(D) The company representative or an operations supervisor authorized by the licensee and in current good standing with the Commission shall certify the employees' AFT.]

[(E) If authorized, a Commission-approved outside instructor may certify any AFT.]

[(2) Other AFT situations shall be handled as follows:]

[(A) For a certified individual employed by a licensee, the licensee shall retain the most recently completed AFT material for each applicable category of the individual's certification in the individual's employment records.]

[(B) For an individual who ceases employment with a licensee, the licensee shall retain the latest required AFT material for at least two years from the date the individual is no longer employed by the licensee. The two-year period shall be based on the renewal period for the examination renewal fee penalty. The licensee shall provide a copy of the AFT material to the individual.]

[(C) For an individual who begins employment with a different licensee, the new licensee shall obtain a copy of the individual's AFT material from the individual and shall place the copy in the individual's employment records.]

[(D) An individual who is never employed by a licensee shall retain the most recently completed AFT material for each applicable category of the individual's certification in a safe location for at least two years from the date the course that required the AFT was attended.]

[(E) For an individual who is employed by a licensee when a course requiring AFT is attended, but who prior to the AFT's being certified becomes employed by a new licensee, the new licensee shall certify the individual's AFT.]

[(F) For an individual who is employed by a licensee when a class requiring AFT is attended, but who prior to the AFT's being certified ceases employment with the licensee and wishes to continue performing LP-gas activities, the individual shall contact a company representative or operations supervisor of another applicable licensee or an Commission-approved outside instructor to complete the AFT and maintain the LP-gas certification.]

[(3) Individuals who attend the 80-hour Category E management-level course or the 16-hour Category F, G, I, and J management-level course shall perform any required AFT activities during the course.]

[(4) If AFT is required for a course, the AFT checklist outlining the specific activities to be performed shall be included in the course materials.]

[(5) A certified individual is exempt from the AFT requirement of a continuing education course if the individual has previously completed that same course, including the AFT.]

(e) [(h)] Certificate holders may complete their continuing education requirement by attending a continuing education course for their specific certificate as listed in this subsection or by attending a CETP course listed in subsection (g) of this section: [Available training and continuing education courses are shown in Tables 1 through 4 of this subsection. Items on the tables marked with an "x" indicate courses that meet training or continuing education requirements for management-level or employee-level certificate holders in that category.]

[Figure: 16 TAC §9.52(h)]

(1) the 4.1 Employee-Level Dispenser Operations Continuing Education course;

(2) the 4.2 Employee-Level Service and Installation Continuing Education course;

(3) the 4.3 Employee-Level Bobtail Driver Continuing Education course;

(4) the 4.4 Employee-Level Recreational Vehicle Technician Continuing Education course; and

(5) the 6.1 Regulatory Compliance for Managers course.

(f) Continuing education credit for certificate holders.

(1) Individuals holding the following certificates or exemption may receive continuing education credit for the 4.1 Employee-Level Dispenser Operations Continuing Education course:

(A) a DOT Cylinder Filler certificate;

(B) a Motor/Mobile Fuel Filler certificate; and/or

(C) a DOT cylinder filler certificate exemption.

(2) Individuals holding the following certificates may receive continuing education credit for the 4.2 Employee-Level Service and Installation Continuing Education course:

(A) a Service and Installation Technician certificate; and/or

(B) an Appliance Service and Installation Technician certificate.

(3) Individuals holding a Recreational Vehicle Technician certificate may receive continuing education credit for the 4.4 Employee-Level Recreational Vehicle Technician Continuing Education course.

(4) Individuals holding a Bobtail Driver certificate may receive continuing education credit for the 4.3 Employee-Level Bobtail Driver Continuing Education course.

(5) To meet continuing education requirements, all management-level certificate holders shall complete one of the following courses:

(A) the 6.1 Regulatory Compliance for Managers course; or

(B) a course listed in paragraphs (1) - (4) of this subsection.

(6) Any employee-level or management-level certificate holder may also receive continuing education credit by completing any training course listed in subsection (a)(1) of this section for the certificate held by the individual.

(g) [(i)] Credit for CETP courses. An employee-level [A] certificate holder who has successfully completed a CETP course, including any applicable knowledge and skills assessments, may receive credit toward the continuing education requirements specified in this section as follows:

(1) Items on the table marked with an "x" indicate CETP courses that meet continuing education requirements for employee-level certificate holders in that category. [The CETP course shall be approved for the category of certificate held as indicated on Tables 3 and 4 in subsection (h) of this section.]

Figure: 16 TAC §9.52(g)(1) (.pdf)

[Figure: 16 TAC §9.52(g)(1)]

(2) The successful completion of a CETP course is determined by a CETP course certificate, which is issued only after an individual has completed the prescribed course of study, including any related knowledge and skills assessments, for the applicable CETP job classification.

(3) To receive credit toward the Commission's continuing education requirements, the certificate holder shall submit the following information, clearly readable, to AFS:

(A) the individual's full name, address, and telephone number;

(B) a copy of the certificate holder's certificate; and

(C) a legible copy of the official CETP course certificate.

(4) AFS shall review the submitted material within 30 business days of receipt and shall notify the certificate holder in writing that the request is approved, denied, or incomplete.

(A) If the request is approved, the certificate holder will receive continuing education credit. AFS will send a new certificate if the request is submitted as part of the renewal process in §9.9 of this title (relating to Requirements for Certificate Holder Renewal).

(B) If the request is denied, the certificate holder may submit additional information for review.

(C) [(A)] If the material is incomplete, AFS shall identify the necessary additional information required.

(D) [(B)] If the request is denied or incomplete, the [The] certificate holder shall file any [the] additional information within 30 calendar days of the date of the [a] notice [of deficiency] in order to receive credit for the CETP course attendance.

(E) [(C)] Certificate holders requesting credit for CETP course attendance shall submit such requests to allow processing time so that a request is finally approved by May 31 in order for the certificate holder to receive credit toward that deadline.

(h) Credit for PERC Outside Instructor Course Attendance. Individuals shall receive credit for attending a PERC outside instructor course per §9.20(2) of this title (relating to DOT Cylinder Filler Certificate Exemption).

§9.54.Commission-Approved Outside Instructors.

(a) (No change.)

(b) Application process. Outside instructor applicants shall submit the following to AFS:

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

(3) for each course the outside instructor applicant intends to teach:

(A) the curriculum for and a description of the course; and

(B) the course materials and related supporting information or a statement that the instructor will use the AFS course materials;

[(C) a statement specifying whether the outside instructor seeks approval to certify any AFT described in §9.52 of this title (relating to training and continuing education)];

(4) proof that the outside instructor applicant has experience, during at least three of the four years prior to the date of filing the application, in both:

(A) conducting LP-gas training or continuing education courses; and

(B) performing or supervising LP-gas activities; and

(5) any other information required by this section.

(c) - (l) (No change.)

§9.55.PERC Outside Instructor Training.

(a) General. AFS may award training and certification or continuing education credit to DOT cylinder filling employee-level applicants and certificate holders for courses administered by a PERC outside instructor provided the PERC outside instructor complies with the requirements of this section.

(1) PERC outside instructors may only offer training consistent with the guidelines established by the PERC Dispensing Propane Safely - Small Cylinder course.

(2) The PERC outside instructor may train individuals using recorded video materials approved under this section but shall proctor the course examination. The PERC outside instructor may proctor an exam in person or using live video.

(3) PERC outside instructors shall be employed by a company licensed to perform DOT cylinder filling activities.

(4) LP-gas licensees may offer courses to their own employees provided that the PERC outside instructor complies with the requirements of this section.

(5) All PERC outside instructor curriculum and course materials shall:

(A) meet the requirements of subsection (c) of this section;

(B) be submitted to AFS for review; and

(C) be organized and easily readable.

(b) Application process. PERC outside instructor applicants shall submit to AFS:

(1) the form prescribed by AFS for the PERC outside instructor application;

(2) a non-refundable $300 registration fee;

(3) the following for the PERC based course to be taught:

(A) a description of the course;

(B) the course curriculum, consistent with the requirements of subsection (c) of this section;

(C) course examination materials; and

(D) links to or digital copies of any videos included in the course curriculum or examination materials;

(4) proof that the PERC outside instructor applicant has experience, during at least three of the four years prior to the date of filing the application, in performing or supervising LP-gas activities; and

(5) any other information required by this section.

(c) Curriculum standards. The course curriculum must be consistent with the guidelines established by the PERC Dispensing Propane Safely - Small Cylinder course and shall also include training on the requirements listed in §9.20(4) of this title (relating to DOT Cylinder Filler Certificate Exemption).

(d) AFS review. AFS shall review the application for approval as a PERC outside instructor and, within 14 business days of the date AFS receives the application, shall notify the applicant in writing that the application is approved, denied, or incomplete.

(1) Approved applications

(A) Additional requirements for approval. PERC outside instructor applicants whose applications are approved in writing by AFS shall attend AFS' Train-the-Trainer Course, the fee for which is included in the $300 registration fee.

(i) The initial Train-the-Trainer Course shall include the classroom instruction and examination for the DOT cylinder filler certification.

(ii) The PERC outside instructor applicant shall pass the DOT cylinder filler examination referenced in §9.10(d)(1)(F) of this title (relating to Rules Examination) with a score of at least 85 percent.

(B) Notification of approval. Within 10 business days of the PERC outside instructor applicant's completion of the requirements of this section, AFS shall notify the applicant in writing that the applicant is approved as a PERC outside instructor and the PERC outside instructor may then begin offering courses.

(C) Term of approval. AFS approval of a PERC outside instructor remains valid for three years unless the Commission revokes the approval pursuant to subsection (f) of this section.

(2) Denied applications. If an application is denied, AFS' notice of denial shall identify the reason the applicant does not meet the requirements of subsections (a) - (c) of this section.

(3) Incomplete applications.

(A) If an application is incomplete, AFS' notice of deficiency shall identify the necessary additional information, including any deficiencies in course curriculum or materials.

(B) The applicant shall file the necessary additional information within 30 calendar days of the date of AFS' notice of deficiency.

(C) The applicant's failure to file the necessary additional information within the prescribed time period may result in the dismissal of the application and the necessity of the applicant again paying the non-refundable $300 registration fee for each subsequent filing of an application.

(e) Revision of course materials. PERC outside instructors must use the materials submitted to and approved by AFS. A PERC outside instructor who revises any course materials previously approved by AFS shall submit the revisions in writing, along with a nonrefundable $100 review fee to AFS.

(1) The nonrefundable $100 review fee shall be waived if the course materials are revised as a result of changes made by PERC to its Dispensing Propane Safely - Small Cylinder course or examination materials.

(2) A PERC outside instructor shall not use materials in a course until the outside instructor has received written AFS approval.

(3) AFS shall review the revised course materials and, within 14 business days, shall notify the PERC outside instructor in writing that the revised course materials are approved or not approved.

(4) If the revised course materials are not approved:

(A) AFS' notice shall identify the portion or portions that are not approved and/or shall describe any deficiencies in the revised course materials.

(B) The PERC outside instructor shall file any necessary additional information within 30 calendar days of the date of AFS' notice.

(C) The PERC outside instructor's failure to file the necessary additional information within the prescribed time period may result in the dismissal of the request for approval of revised course materials and the necessity of again paying the $100 review fee for each subsequent filing of revised course materials.

(5) Once approved, the revised course materials may be used in the PERC outside instructor's course.

(f) Continuing requirements. Approved PERC outside instructors shall:

(1) maintain their certificates in continuous good standing. Any interruption of the required certificates may result in the Commission revoking or suspending the PERC outside instructor's approval;

(2) renew their AFS PERC outside instructor approval every three years by paying a nonrefundable $150 renewal fee to AFS;

(3) attend a Train-the-Trainer refresher course prior to the PERC outside instructor's next renewal deadline. The Train-the-Trainer course shall not count as credit towards any training or continuing education requirements; and

(4) adhere to professional standards of conduct in course administration.

(g) PERC outside instructor additional responsibilities.

(1) PERC outside instructors are responsible for every aspect of the courses they administer, including the location, schedule, date, time, duration, content, material, demeanor and conduct of the PERC outside instructor, and reporting of attendance information.

(2) AFS may monitor or supervise courses or exams administered by PERC outside instructors.

(h) Complaints. Complaints regarding PERC outside instructors shall be made to AFS in writing by e-mail, fax, or U. S. Postal Service and shall:

(1) include the complainant's printed name, address, and telephone number;

(2) be signed by the complainant if filed by fax or U.S. Postal Service;

(3) state the PERC outside instructor's name and the course date, location, and title; and

(4) describe the facts that show the PERC outside instructor:

(A) failed to meet or maintain AFS requirements for PERC outside instructor approval;

(B) failed to deliver a course as approved, including failure to follow the approved curriculum, to use the approved course materials, or to deliver the requisite numbers of hours of instruction; or

(C) engaged in other conduct, including the use of language, that created an atmosphere not conducive to learning. Such conduct includes but is not limited to demeaning, derogating, or stereotyping women or men, disabled persons, members of any political, religious, racial, or ethnic group, or a particular individual, organization, or product.

(i) Analysis

(1) As a result of AFS monitoring or supervising a course pursuant to subsection (g)(2) of this section or upon receipt of a complaint pursuant to subsection (h) of this section and at its discretion, AFS may gather any additional information necessary or appropriate to making a full and complete analysis.

(A) AFS shall send a written analysis and any findings to the PERC outside instructor who conducted the course monitored or supervised by AFS or that is the subject of the complaint.

(B) The PERC outside instructor may file a written response within 20 calendar days from the date of AFS' findings.

(2) If AFS determines that a PERC outside instructor has engaged in conduct prohibited by this section, AFS may prepare a report that states the facts on which the determination is based and the recommended action AFS intends to take.

(A) AFS may:

(i) issue a written warning to the PERC outside instructor;

(ii) decline to approve or renew the PERC outside instructor's approval; or

(iii) revoke the PERC outside instructor's approval.

(B) AFS shall:

(i) send a written copy of the report and recommendation to the PERC outside instructor; and

(ii) include a statement that the PERC outside instructor has a right to a hearing on the determination contained in the report.

(C) Within 20 calendar days after the date the notice is postmarked, the PERC outside instructor shall file a written response either accepting the determination and recommended action or requesting a hearing on the determination.

(i) If a PERC outside instructor requests a hearing, the AFS director shall refer the matter to the Hearings Division.

(ii) Following the hearing, the Commission may enter an order finding that the PERC outside instructor has violated Commission rules or that no violation has occurred; and may make any other finding based on the evidence in the record.

(iii) If the PERC outside instructor does not comply with the order of the Commission, and if the enforcement of the Commission's order is not stayed, then the Office of General Counsel may refer the matter to the attorney general for enforcement of the Commission's order.

(D) If the PERC outside instructor accepts the determination, the PERC outside instructor shall notify AFS in writing of the acceptance, and AFS shall take the action indicated in the report. If the PERC outside instructor does not respond to the report timely, AFS shall take the action indicated in the report.

(j) Completed courses.

(1) Within three business days of the conclusion of a course, PERC outside instructors shall report to AFS the following information:

(A) the PERC outside instructor's name and last four digits of the instructor's social security number or RRC identification number;

(B) employing licensee's name and license number;

(C) date of the course;

(D) list of the persons completing the course, including the following information for each individual listed:

(i) full name,

(ii) last four digits of the person's social security number or RRC identification number; and

(iii) personal mailing address.

(2) The report shall be made electronically.

(3) The PERC outside instructor shall ensure that AFS receives the report by securing written acknowledgment of its receipt by AFS.

(4) A $40 registration fee shall be submitted for each individual listed in paragraph (1)(D) of this subsection.

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 May 3, 2022.

TRD-202201734

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: June 19, 2022

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


SUBCHAPTER B. LP-GAS INSTALLATIONS, CONTAINERS, APPURTENANCES, AND EQUIPMENT REQUIREMENTS

16 TAC §§9.126, 9.130, 9.134, 9.140 - 9.143

The Commission proposes the amendments under Natural Resources Code sections 113.087 and 113.088, amended by Senate Bill 1582 (87th Legislature, Regular Session), and Natural Resources Code section 113.0955, added by Senate Bill 1668 (87th Legislature, Regular Session). The Commission also proposes the amendments under Texas Natural Resources Code, §113.051, which authorizes the Commission to promulgate and adopt rules and standards relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public.

Statutory authority: Texas Natural Resources Code, §§113.051, 113.087, 113.088 and 113.0955.

Cross reference to statute: Texas Natural Resources Code Chapter 113.

§9.126.Appurtenances and Equipment.

(a) - (c) (No change.)

(d) ASME containers with an individual water capacity over 4,000 gallons shall comply with paragraph (1) or (2) of this subsection:

(1) For container openings 1 1/4-inch or greater in size:

(A) the container shall be equipped with:

(i) a pneumatically-actuated [pneumatically operated] internal valve equipped for remote closure and automatic shutoff using thermal (fire) actuation where the thermal element is located within five feet (1.5 meters) of the internal valve;

(ii) - (iii) (No change.)

(B) - (D) (No change.)

(2) For container openings less than 1 1/4-inch in size, the container shall be equipped with:

(A) (No change.)

(B) a pneumatically-actuated [pneumatically operated] internal valve with an integral excess-flow valve or excess-flow protection; or

(C) (No change.)

§9.130.Commission Identification Nameplates.

(a) Prior to an original ASME nameplate or any manufacturer-issued nameplate becoming unreadable or detached from a stationary container with a water capacity of 4,001 gallons or more, the owner or operator of the container may request an identification nameplate from AFS. Commission identification nameplates shall be issued only for containers which can be documented as being in continuous LP-gas service in Texas from a date prior to September 1, 1984. The container's serial number and manufacturer on the original or manufacturer-issued nameplate shall be clearly readable at the time the Commission identification nameplate is attached.

(1) (No change.)

(2) AFS shall review LPG Form 502 and the supporting documentation. AFS shall have the manufacturer's data report on file for the container or the licensee shall provide a copy to AFS [LP-Gas Operations]. The Commission identification nameplate shall not be issued unless the manufacturer's data report is reviewed. Upon review of submitted documents and confirmation of the manufacturer's data report, AFS [LP-Gas Operations] shall send [mail] a letter to the owner or operator of the container stating the estimated costs, which will be based on the following:

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

(3) - (6) (No change.)

(b) - (f) (No change.)

§9.134.Connecting Container to Piping

(a) LP-gas piping shall be installed only by a licensee authorized to perform such installation, a registrant authorized by §9.13 of this title (relating to General Installers and Repairman Exemption), or an individual exempted from licensing as authorized by Texas Natural Resources Code, §113.081.

(b) A licensee shall not connect an LP-gas container or cylinder to a piping installation made by a person who is not licensed to make such installation, except that connection may be made to piping installed by an individual on that individual's single family residential home.

(c) A licensee may connect to piping installed by an unlicensed person provided the licensee has verified that the piping is free of leaks and has been installed according to the rules in this chapter, and filed with AFS a completed LPG Form 22, identifying the unlicensed person who installed the LP-gas piping.

(d) A licensee is not required to submit LPG Form 22 pursuant to subsection (c) of this section only if the piping system is currently in service and no new piping is installed, the system is in good working order, and the installer cannot be determined.

§9.140.System Protection Requirements.

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

(c) In addition to NFPA 58, §§6.21.4.2, 6.22.3.2(3), 6.27.3.7, 8.2.1.1, and 6.5.4.5, fencing at LP-gas installations shall comply with the following:

(1) Uprights, braces, and cornerposts of the fence shall be composed of noncombustible material and shall be anchored in concrete a minimum of 12 inches below the ground.

(2) (No change.)

(3) ASME containers or manual dispensers originally manufactured to or modified to be considered by AFS as self-contained units are exempt from the fencing requirements. Self-contained units shall be protected as specified in subsection (d) of this section;

(4) (No change.)

(d) In addition to NFPA 58, §§6.8.1.2, 6.8.6.1(A)-(E), 6.8.6.2(F), 6.27.3.13 and 6.27.3.14, vehicular barrier protection at LP-gas installations, except as noted in this section, shall comply with the following:

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

(3) Locations which have a perimeter fence prohibiting public traffic to the container or cylinder storage area shall not be required to have guardrailing if the vertical supports are located no more than three feet apart.

(4) [(3)] Openings in horizontal guardrailing, except the opening that is permitted directly in front of a bulkhead, shall not exceed three feet. Only one opening is allowed on each side of the guardrailing. A means of temporarily removing the horizontal guardrailing and vertical supports to facilitate the handling of heavy equipment may be incorporated into the horizontal guardrailing and vertical supports. In no case shall the protection provided by the horizontal guardrailing and vertical supports be decreased. Transfer hoses from the bulkhead shall be routed only through the 45-degree opening in front of the bulkhead or over the horizontal guardrailing.

(5) [(4)] Clearance of at least three feet shall be maintained between the vehicular barrier protection and any part of an LP-gas transfer system or container or clearance of two feet for retail service station installations. The two vertical supports at the ends of any vehicular barrier protection which protects a bulkhead shall be located a minimum of 24 and a maximum of 36 inches at 45-degree angles to the nearest corner of the bulkhead.

(6) [(5)] Vehicular barrier protection shall extend at least three feet beyond any part of the LP-gas transfer system or container which is exposed to collision damage or vehicular traffic.

(7) [(6)] Installations which have highway barriers located between vehicular traffic and the container and material handling equipment shall not be required to have vehicular barrier protection installed.

(e) (No change.)

(f) In addition to NFPA 58 §5.2.8.1, LP-gas installations shall comply with the sign and lettering requirements specified in Table 1 of this section. An asterisk indicates that the requirement applies to the equipment or location listed in that column.

Figure: 16 TAC §9.140(f) (No change.)

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

(3) Items 1, 2, and 3 in the column entitled "Licensee or Non-Licensee ASME 4001+ Gal. A.W.C." in Table 1 apply to installations with 4,001 gallons or more aggregate water capacity protected only by vehicular barrier protection [guardrailing] as required in subsection (d) of this section, and bulkheads as required by §9.143 of this title (relating to Bulkhead, Internal Valve, API 607 Ball Valve, and ESV Protection for Stationary LP-Gas Installations with Individual or Aggregate Water Capacities of 4,001 Gallons or More) for commercial, bulk storage, cylinder filling, or forklift installations.

(4) Item 7 in the column entitled "Storage Racks for DOT Portable or Forklift Containers" in Table 1 may be met with lettering only one rack when multiple racks are installed.

(5) [(4)] Item 11 in the column entitled "Requirements" in Table 1 applies to facilities which have two or more containers.

(6) [(5)] Item 13 in the column entitled "Requirements" in Table 1 applies to outlets where an LP-gas certified employee is responsible for the LP-gas activities at that outlet, when a licensee's employee is the operations supervisor at more than one outlet as required by §9.17(a) of this title (relating to Designation and Responsibilities of Company Representative and Operations Supervisor).

(7) [(6)] Any information in Table 1 of this subsection required for an underground container shall be mounted on a sign posted within 15 feet horizontally of the manway or the container shroud.

(8) [(7)] Licensees and non-licensees shall comply with operational and/or procedural actions specified by the signage requirements of this section.

[(8) Any 24-hour emergency telephone numbers shall be:]

[(A) monitored at all times; and]

[(B) be answered by a person who is knowledgeable of the hazards of LP-gas and who has comprehensive LP-gas emergency response and incident information, or has immediate access to a person who possesses such knowledge and information. A telephone number that requires a call back (such as an answering service, answering machine, or beeper device) does not meet the requirements of this section.]

(g) In addition to NFPA 58, §8.4.2.2, storage racks used to store DOT cylinders in the horizontal position [nominal 20-pound DOT portable or any size forklift containers] shall be protected against vehicular damage by:

(1) the use of concrete curbs and/or wheel stops provided:

(A) the cylinder storage rack is located a minimum of 48 inches behind a curb or wheel stop that is a minimum of five inches in height above the grade of the driveway or parking area;

(B) if the requirements of subparagraph (A) cannot be met, the cylinder storage rack must be installed a minimum of 48 inches behind a curb or wheel stop that is a minimum of four inches in height above the grade of the driveway or parking area, and a wheel stop at least four inches in height must be installed at least 12 inches from the curb or first wheel stop; and

(C) if wheel stops are used, all wheel stops must be secured against displacement; or

[(1) meeting the guardrail requirements of subsection (d) of this section; or]

(2) if curbs and/or wheel stops are not installed, guard posts or vehicular barrier protection shall be [installing guard posts, provided the guard posts are] installed a minimum of 18 inches from each storage rack, and:

(A) consist of at least three-inch schedule 40 steel pipe, capped on top or otherwise protected to prevent the entrance of water or debris into the guard post, no more than four feet apart, and anchored in concrete at least 12 [30] inches below ground and rising at least 30 inches above the ground; [or]

(B) [are] constructed of at least four-inch schedule 40 steel pipe capped on top or otherwise protected to prevent the entrance of water or debris into the guard post, and attached by welding to a minimum 8-inch by 8-inch steel plate at least 1/2 inch thick. The installed height of the post must be a minimum of 30 inches above the ground. The guard posts and [8] steel plate shall be permanently installed and securely anchored to a concrete driveway or concrete parking area; or [.]

(C) meet the requirements of subsection (d) of this section.

[(3) Guardrail or guard posts are not required to be installed if:]

[(A) the cylinder storage rack is located a minimum of 48 inches behind a concrete curb or concrete wheel stop that is a minimum of five inches in height above the grade of the driveway or parking area; or]

[(B) if the requirements of subparagraph (A) cannot be met, the cylinder storage rack must be installed a minimum of 48 inches behind a concrete curb or concrete wheel stop that is a minimum of four inches in height above the grade of the driveway or parking area, and a concrete wheel stop at least four inches in height must be installed at least 12 inches from the curb or first wheel stop;]

[(4) All parking wheel stops and cylinder storage racks in paragraph (3) of this subsection must be secured against displacement.]

(h) Fencing, guardrails, and valve locks shall be maintained in good condition at all times in accordance with this chapter.

(i) [(h)] Self-service dispensers shall be protected against vehicular damage by:

(1) vehicular barrier protection that complies with subsection (d) of this section; or

(2) vertical supports that comply with subsection (d) of this section; or

(3) where routine traffic patterns expose only the approach end of the dispenser to vehicular damage, support columns, concrete barriers, bollards, inverted U-shaped guard posts anchored in concrete, or other protection acceptable to AFS, provided:

(A) the cylinder storage rack is located a minimum of 48 inches behind a concrete curb or concrete wheel stop that isa minimum of five inches in height above the grade of the driveway or parking area;

(B) if the requirements of subparagraph (A) cannot be met, the cylinder storage rack must be installed a minimum of 48inches behind a concrete curb or concrete wheel stop that is a minimum of four inches in height above the grade of the driveway or parking area, and a concrete wheel stop at least four inches in height must be installed at least 12 inches from the curb or first wheel stop. [;]

(j) [(i)] Self-service dispensers utilizing protection specified in paragraphs (2) -(3) of subsection (h) of this section shall be connected to supply piping by a device designed to prevent the loss of LP-gas in the event the dispenser is displaced. The device must retain liquid on both sides of the breakaway point and be installed in a manner to protect the supply piping against damage.

§9.141.Uniform Safety Requirements.

(a) (No change.)

(b) In addition to NFPA 58, §6.27.4.2, each LP-gas private or public motor/mobile or forklift refueling installation which includes a liquid dispensing system shall incorporate into that dispensing system a breakaway device.

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

(3) In addition to NFPA 58, §6.27.4.1, the overall length of hose on vehicle fuel dispensers used to transfer LP-gas into engine fuel and mobile containers on vehicles shall not exceed 18 feet measured from the point where the hose attaches to rigid piping downstream of the pump to the end of the dispensing hose. If a section of hose not exceeding 36 inches in length is installed for flexibility between the listed emergency breakaway device and the rigid piping downstream of the pump, then the 18 feet of dispensing hose will be measured from the outlet of the emergency breakaway device.

(c) - (h) (No change.)

(i) Racks used to store cylinders awaiting use or resale shall be installed on firm, level ground. In addition to NFPA 58 §8.4.1.1, a distance of five feet shall be maintained between the rack and any sources of ignition and combustible materials.

§9.142.LP-Gas Container Storage and Installation Requirements.

(a) Except as noted in this section and in addition to NFPA 58 §6.4.1.1, LP-gas containers shall be stored or installed in accordance with the distance requirements in NFPA 58, §§6.2.2, 6.4.4, and 8.4.1 and any other applicable requirements in NFPA 58 or the rules in this chapter.

(1) An LP-gas liquid dispensing installation other than a retail operated service station installation is not required to have a pump, provided that the storage containers are located one and one half times the required distances specified in NFPA 58, §6.4.1.1, or a minimum distance of 15 feet if the storage container is less than 125 gallons water capacity.

(2) Any LP-gas container constructed prior to 1970 which has an odd-numbered water gallon capacity (for example, 517 water gallons instead of 500 water gallons) that is not more than 5.0% greater than the standard water gallon capacity may be installed utilizing the minimum distance requirement based on the standard water gallon capacity.

(b) Each industrial plant, bulk plant, and distributing point with an aggregate water capacity of 4,000 gallons or less shall be provided with at least one portable fire extinguisher in accordance with NFPA 58 §4.7 having a minimum capacity of 18 lb (8.2 kg) of dry chemical.

§9.143.Piping and Valve Protection for Stationary LP-Gas Installations with Individual or Aggregate Water Capacities of 4,001 Gallons or More.

(a) Instead of NFPA 58, §6.14, all new stationary LP-gas installations with individual or aggregate water capacities of 4,001 gallons or more shall:

(1) (No change.)

(2) install one of the following in all container openings 1 1/4 inches or greater, as required in this section and §9.126 of this title (relating to Appurtenances and Equipment):

(A) pneumatically-actuated [pneumatically-operated ] emergency shutoff valves (ESV);

(B) pneumatically-actuated [pneumatically-operated ] internal valves;

(C) pneumatically-actuated [pneumatically-operated ] API 607 ball valves; or

(D) (No change.)

(b) Valve protection requirements.

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

(3) Pneumatically-actuated [Pneumatically-operated ] ESV, internal valves, and API 607 ball valves shall be equipped for automatic shutoff using thermal (fire) actuation where the thermal element is located within five feet (1.5 meters) of the ESV, internal valves, and/or API 607 ball valves. Temperature sensitive elements shall not be painted nor shall they have any ornamental finishes applied after manufacture.

(4) (No change.)

(5) Pneumatically-actuated [Pneumatically-operated ] internal valves, ESV, and API 607 ball valves shall be interconnected and incorporated into at least one remote operating system.

(c) (No change.)

(d) Existing installations which have horizontal bulkheads and cable-actuated ESV shall comply with the following:

(1) (No change.)

(2) If a cable-actuated ESV requires replacement, it shall be replaced with a pneumatically-actuated [pneumatically-operated ] ESV;

(3) If the horizontal bulkhead or a backflow check valve or a cable-actuated ESV are moved from their original location to another location, no matter what the distance from the original location, then the installation shall comply with the requirements for a vertical bulkhead and pneumatically-actuated [pneumatically-operated] ESV;

(4) All cable-actuated ESV shall be replaced with pneumatically-actuated [pneumatically-operated] ESV by January 1, 2011.

(e) - (g) (No change.)

(h) If necessary to increase LP-gas safety, AFS may require a pneumatically-actuated [pneumatically-operated] internal valve equipped for remote closure and automatic shutoff through thermal (fire) actuation to be installed for certain liquid and/or vapor connections with an opening of 3/4 inch or one inch in size.

(i) (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 May 3, 2022.

TRD-202201735

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: June 19, 2022

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


SUBCHAPTER C. VEHICLES

16 TAC §9.202, §9.211

The Commission proposes the amendments under Natural Resources Code sections 113.087 and 113.088, amended by Senate Bill 1582 (87th Legislature, Regular Session), and Natural Resources Code section 113.0955, added by Senate Bill 1668 (87th Legislature, Regular Session). The Commission also proposes the amendments under Texas Natural Resources Code, §113.051, which authorizes the Commission to promulgate and adopt rules and standards relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public.

Statutory authority: Texas Natural Resources Code, §§113.051, 113.087, 113.088 and 113.0955.

Cross reference to statute: Texas Natural Resources Code Chapter 113.

§9.202.Registration and Transfer of LP-Gas Transports or Container Delivery Units.

(a) A person who operates a transport equipped with LP-gas cargo tanks or any container delivery unit, regardless of who owns the transport or unit, shall register such transport or unit with AFS in the name or names under which the operator conducts business in Texas prior to the unit being used in LP-gas service.

(1) To register a cargo tank unit previously unregistered in Texas, the operator of the unit shall:

(A) pay to AFS the $270 registration fee for each bobtail truck, semitrailer, [container delivery unit,] or other motor vehicle equipped with LP-gas cargo tanks;

(B) file a properly completed LPG Form 7;

(C) file a copy of the Manufacturer's Data Report;

(D) file a copy of the DOT Certificate of Compliance; and

(E) file a copy of the hydrostatic or pneumatic test required by §9.208 of this title (relating to Testing Requirements), unless the unit was manufactured within the previous five years or 10 years for units which meet the exemption in 49 CFR 180.407(c).

(2) To register a container delivery unit previously unregistered in Texas, the operator of the unit shall:

(A) pay to AFS the $270 registration fee for each container delivery unit; and

(B) file a properly completed LPG Form 7A.

(3) [(2)] To register a bobtail truck, semitrailer, container delivery unit, or other motor vehicle equipped with LP-gas cargo tanks [an MC-330/MC-331 specification unit] which was previously registered in Texas but for which the registration has expired, the operator of the unit shall:

(A) pay to AFS the $270 registration fee;

(B) file a properly completed LPG Form 7 for cargo tanks or LPG Form 7A for container delivery units; and

(C) for cargo tanks, file a copy of the latest test results if an expired unit has not been used in the transportation of LP-gas for over one year or if a current hydrostatic test has not been filed with AFS.

(4) [(3)] To re-register a currently registered unit, the licensee operating the unit shall pay a $270 annual registration fee.

(5) [(4)] To transfer a currently registered unit, the new operator of the unit shall:

(A) pay the $100 transfer fee for each unit; and

(B) file a properly completed LPG Form 7T [7].

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

§9.211.Markings.

(a) In addition to NFPA 58 §9.4.6.2, each LP-gas transport and container delivery unit in LP-gas service shall be marked on each side and the rear with the name of the licensee or the ultimate consumer operating the unit. Such lettering shall be legible and at least two inches in height and in sharp color contrast to the background. AFS shall determine whether the name marked on the unit is sufficient to properly identify the licensee or ultimate consumer operating the unit.

(b) In addition to NFPA 58 §12.5.13(2), the location of the manual shutoff valve on each school bus, special transit vehicle, mass transit vehicle, and public transportation unit shall be marked "Manual Shutoff Valve." Decals or stencils are acceptable.

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 May 3, 2022.

TRD-202201736

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: June 19, 2022

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


SUBCHAPTER E. ADOPTION BY REFERENCE OF NFPA 58 (LP-GAS CODE)

16 TAC §9.403

The Commission proposes the amendments under Natural Resources Code sections 113.087 and 113.088, amended by Senate Bill 1582 (87th Legislature, Regular Session), and Natural Resources Code section 113.0955, added by Senate Bill 1668 (87th Legislature, Regular Session). The Commission also proposes the amendments under Texas Natural Resources Code, §113.051, which authorizes the Commission to promulgate and adopt rules and standards relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public.

Statutory authority: Texas Natural Resources Code, §§113.051, 113.087, 113.088 and 113.0955.

Cross reference to statute: Texas Natural Resources Code Chapter 113.

§9.403.Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes or Additional Requirements.

(a) Table 1 of this section lists certain NFPA 58 sections which the Commission does not adopt because the Commission's corresponding rules are more pertinent to LP-gas activities in Texas, or which the Commission adopts with changed language or additional requirements in order to address the Commission's existing rules.

Figure: 16 TAC §9.403(a) (.pdf)

[Figure: 16 TAC §9.403(a)]

(b) (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 May 3, 2022.

TRD-202201737

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: June 19, 2022

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