Adopted Rules Title 16

TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

The Railroad Commission of Texas (Commission) adopts amendments to §3.70, relating to Pipeline Permits Required, without changes to the proposed text published in the August 30, 2024, issue of the Texas Register (49 TexReg 6559) and will not be republished. The Commission adopts the amendments in §3.70 to align with changes concurrently adopted in Chapter 8, relating to Pipeline Safety Regulations, which incorporate federal requirements. The amendments to §3.70 also remove dates from the rule that no longer apply and incorporate a procedure related to the Form T-4B.

The Commission received six comments, five of which were from associations (Permian Basin Petroleum Association (PBPA), Pipeline Safety Trust, Sierra Club Lone Star Chapter (Sierra Club), Texas Industry Project, and Texas Oil and Gas Association (TXOGA)). One company, Atmos Energy Corporation's Mid-Texas Division and West Texas Division (Atmos) also commented. The Commission appreciates these comments.

Generally, Atmos commented that it supports the changes to §3.70, as they effectively remove outdated language, properly update the language regarding gathering lines, and provide a straightforward process for filing Form T-4B.

The Commission appreciates the comments from Atmos.

Regarding §3.70(i)(1)(A), TXOGA and PBPA sought clarity that Group A fees only apply to transmission and gathering pipelines, as defined by the Pipeline and Hazardous Materials Safety Administration (PHMSA), and would not include production lines defined in §8.1(a)(1)(B) of this title, relating to General Applicability and Standards.

The Commission notes that production pipelines covered under §8.1(a)(1)(B) currently fall under Group A, as defined by §3.70(i)(1)(A), and will continue to fall under Group A after these amendments.

The Commission received one comment from Sierra Club regarding increasing mileage fees for Group B operators under §3.70(i)(3), as well as the permit processing fee for all permitted pipelines under §3.70(j). Sierra Club suggested increasing the fee for Group B pipelines from $10 per mile to $15 per mile, and the permit processing fee from $500 to $1,000.

The Commission appreciates the comments from Sierra Club but acknowledges that the suggested fee increases are outside the scope of these amendments. The Commission did not propose changing Group B per mile fees, nor permit processing fees, and would need to propose these fee changes and allow public comments before considering any changes to either fee.

Regarding changes to §3.70(o), Sierra Club agrees with the Commission and supports the requirement of having both the transferor and transferee sign for ownership transfer, with some flexibility where the transferor operator failed to do so.

The Commission appreciates Sierra Club's comments.

Regarding §3.70(r)(1), the Commission received similar comments from TXOGA, PBPA, and Texas Industry Project. These associations proposed extending the deadline for amending T-4 permits to December 31, 2025, noting that it will be challenging for operators to file by March 31, 2025. PBPA also suggested that any future proposals to shapefile submission include opportunity for public comment and stakeholder feedback.

The Commission disagrees with the proposal to extend the deadline to December 31, 2025. The federal gathering line rule required all operators to begin filing annual reports starting in March 2023. As such, operators should have all necessary information. This data is needed to accurately enter new Type C gathering line systems into the Pipeline Inspection System (PIPES). Additionally, the Commission released a Notice to Operators on February 29, 2024 to make operators aware of the new shapefile requirements.

Additionally, regarding §3.70(r), PBPA proposed to revise the amended rule to exclude Type R pipeline operators from submitting shapefiles with T-4 permit requests, noting that this goes beyond PHMSA's requirements, many operators have stated that they utilize other methods, and may not have GIS centerline data.

The Commission disagrees with PBPA's proposal to exclude Type R operators from shapefile requirements under §3.70(r). The data requested in the shapefile submissions is required for operators to differentiate between Type C and Type R pipelines. Thus, §3.70(r) will be adopted as proposed.

The Commission appreciates the input received from commenters. The Commission makes no changes in response to these comments. The adopted rule language is summarized in the paragraphs below.

The Commission adopts amendments in §3.70(i)(1)(A) and (B) to incorporate federal categories of pipelines and to clarify reporting requirements. In the Commission's rulemaking to amend §8.1 of this title (relating to General Applicability and Standards), which is adopted concurrently with these amendments to §3.70, the Commission incorporates minimum safety standards from PHSMA. PHMSA's standards extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. The amendments to §3.70(i) incorporate federal pipeline classifications and ensure gas gathering lines are regulated consistent with PHMSA's requirements.

The adopted amendments in subsection (i)(2) and (3) and subsection (j) remove dates that were included in the rule when the fees were first adopted.

The Commission adopts amendments in subsection (o) to clarify the procedure for filing Form T-4B when the transferee operator is unable to obtain the signature of the transferor operator. This situation is addressed in the oil and gas context in §3.58 of this title (relating to Certificate of Compliance and Transportation Authority; Operator Reports) and the related Single-Signature Form P-4 process. The Commission adopts a similar process in subsection (o) because this situation also occurs with pipeline transfers.

The Commission adopts new subsection (r) to require updates in the permitting system related to gas gathering pipelines, indicating the federal categories as adopted in subsection (i). The amendments state that, beginning December 9, 2024, operators shall amend gas permits to include all gas gathering pipelines defined as Type A, Type B, Type C, or Type R in 49 CFR §192.8. The permit amendments shall be filed on the Commission's online permitting system by March 31, 2025.

The Commission adopts the amendments pursuant to Texas Natural Resources Code, §81.071, which authorizes the Commission to establish pipeline safety and regulatory fees to be assessed for permits or registrations for pipelines under the jurisdiction of the Commission's pipeline safety and regulatory program. Additionally, the Commission adopts the amendments pursuant to Texas Natural Resources Code §81.051 and §81.052, which provide the Commission with jurisdiction over all persons owning or operating pipelines 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 §86.041 and §86.042, which allow the Commission broad discretion in adopting rules to prevent waste in the piping and distribution of gas, require records to be kept and reports made, and provide for the issuance of permits and other evidences of permission; Texas Natural Resources Code §111.131 and §111.132, which authorize the Commission to promulgate rules for the government and control of common carriers and public utilities; and Texas Utilities Code §§121.201 - 121.210, which authorize the Commission to adopt safety standards and practices applicable to the transportation of gas and associated pipeline facilities within Texas to the maximum degree permissible under, and to take any other requisite action in accordance with, 49 United States Code Annotated, §§60101, et seq. Texas Natural Resources Code §§81.051, 81.052, 86.041, 86.042, 111.131, and 111.132; Texas Utilities Code, §§121.201 - 121.210; and 49 United States Code Annotated, §§60101, et seq.

Cross-reference to statute: Texas Natural Resources Code, Chapter 81, Chapter 86, and Chapter 111, and Texas Utilities Code, Chapter 121; and 49 United States Code Annotated, Chapter 601.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on November 19, 2024.

TRD-202405612

Haley Cochran

Assistant General Counsel, Office of General Counsel

Railroad Commission of Texas

Effective date: December 9, 2024

Proposal publication date: August 30, 2024

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

CHAPTER 8. PIPELINE SAFETY REGULATIONS

The Railroad Commission of Texas adopts amendments to §§8.1, 8.101, 8.110, 8.115, 8.125, 8.201, 8.208, 8.209, and 8.210, relating to General Applicability and Standards; Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines; Gathering Pipelines; New Construction Commencement Report; Waiver Procedure; Pipeline Safety and Regulatory Program Fees; Mandatory Removal and Replacement Program; Distribution Facilities Replacements; and Reports. Sections 8.1, 8.115, and 8.209 are adopted with changes to the proposed text published in the August 30, 2024, issue of the Texas Register (49 TexReg 6652) and will be republished. The remaining rules are adopted without changes and will not be republished. The Commission adopts these amendments to capture the federal Pipeline and Hazardous Materials Safety Administration (PHMSA) latest standards, to clarify areas of the rules that staff receives regular inquires on, and to clarify how pipeline operators should report and file with Commission.

The Commission received six comments, four of which were from associations (Permian Basin Petroleum Association (PBPA), Pipeline Safety Trust, Sierra Club Lone Star Chapter (Sierra Club), and Texas Oil and Gas Association (TXOGA)). Two companies, Atmos Energy Corporation's Mid-Texas Division and West Texas Division (Atmos) and Texas Gas Service (TGS) also commented. The Commission appreciates these comments.

Regarding the amendments proposed in §8.1(a)(1)(B), PBPA and TXOGA commented that PHMSA regulations in 49 CFR §192.8 associate Type C facilities only with Class 1 locations. Thus, the Commission should remove Type C from §8.1(a)(1)(B).

The Commission agrees and adopts §8.1(a)(1)(B) with a change to remove "Type C."

In addition, PBPA and TXOGA requested clarification regarding the meaning of "first point of measurement" in §8.1(a)(1)(B). TXOGA suggested that "first point of measurement" be defined as a measurement which occurs after final processing, before transportation to a third party for sales. TXOGA also suggested that the Commission exempt measurement methods utilizing allocation meters, multi-phase flow meters, bulk separation/test meters, and well performance surveillance meters associated with production operations and prior to final separation and processing at central tank batteries.

The Commission notes that "first point of measurement" is the first point of measurement required under §3.27 of this title, relating to Gas to be Measured and Surface Commingling of Gas. The Commission disagrees that the definition should exempt the measurement methods proposed by TXOGA. Section 8.1(a)(1)(B) was added to the chapter in 2009 to address the regulation of production pipelines located in more populated areas (Class 2, 3, and 4 locations). This section continues to apply only to production pipelines in Class 2, 3, and 4 locations and includes the entirety of the pipeline that is located in a Class 2, 3, or 4 location.

PBPA requested clarification regarding whether "Group A" fees are only applicable to PHMSA-defined transmission and gathering pipelines and do not apply to production lines defined in §8.1(a)(1)(B).

The Commission makes no change in response to this comment. Production pipelines covered under §8.1(a)(1)(B) are subject to the regulations in 49 CFR Part 192 and require inspections. They are currently subject to Group A fees and Group A fees will continue to apply.

The Commission received three comments on its proposed changes to §8.1(b), which update the minimum safety standards and adopt by reference the Department of Transportation (DOT) pipeline safety standards found in 49 CFR Part 191, Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports; 49 CFR Part 192, Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards; and 49 CFR Part 195, Transportation of Hazardous Liquids by Pipeline. PBPA expressed support for the proposed amendments. Sierra Club also expressed support but noted the Commission should have acted sooner to incorporate the federal standards. Atmos requested clarification regarding whether the change will incorporate rules finalized by PHMSA by December 9, 2024, but not effective by December 9, 2024, such as the leak detection and repair rulemaking.

The Commission confirms that the leak detection and repair (LDAR) rulemaking is not incorporated by reference. The federal rules that are incorporated into §8.1(b) as of December 9, 2024 (the effective date of these rule amendments) are the rules resulting from the rulemakings listed in the Commission's preamble to the proposed amendments published in the August 30, 2024, issue of the Texas Register (49 TexReg 6652). Those rulemakings are also listed below in the paragraph summarizing the amendments to §8.1(b).

In §8.101, the Commission proposed changes to clarify which pipelines referenced in 49 CFR Part 195 are subject to the rule's requirements. The amendments also align Texas integrity rules with the federal requirements and state that operators of pipelines subject to 49 CFR §192.710 shall follow the remediation requirements.

Atmos commented in support of the proposed amendments to §8.101. The Commission appreciates this comment.

PBPA and TXOGA requested that the title of Figure 2 in §8.101(b)(2) be revised from "Liquid Pipelines" to "Liquid Pipelines Subject to 49 CFR Part 195 Requirements." The commenters noted that the Commission generally requires that interstate, rural, non-regulated systems be permitted. Non-regulated systems that are permitted should not also be subject to Pipeline Integrity Assessment and Management Plans in §8.101. This is stated in proposed rule language and for consistency should also be clearly referenced in the title of Figure 2.

The Commission declines to make this change. The applicability of the section to pipeline facilities used in the transportation of hazardous liquids or carbon dioxide subject to 49 CFR Part 195 is stated in subsection (b) and an additional change to the figure is unnecessary. In addition, updating the title of this figure would create inconsistency with other figures in Chapter 8, some of which were not included in this proposal.

The Pipeline Safety Trust commented that the reassessment interval of ten years for natural gas and hazardous liquids pipelines is too long. Conditions can change quickly over a decade, and frequent assessment is needed to ensure operators are repairing and monitoring their pipelines effectively. The Pipeline Safety Trust suggested that the Commission change the requirement for reassessment intervals to not exceed five years for both §8.101(b)(1)(F)(i) and (ii).

The Commission declines to make the requested change because the Commission does not support decreasing the interval to five years without first seeking input from affected operators. Changing the interval from every ten years to every five years would create a significant cost for operators, and they should have an opportunity to comment. The Commission will consider the Pipeline Safety Trust's suggestion in assessing future changes to §8.101.

Regarding amendments proposed in §8.115, Atmos commented that it has worked with the Pipeline Safety Division since 2020 to improve reporting on construction projects. Based on those filings, Atmos believes the intent of new subsection §8.115(a)(6) is to require reporting on projects less than three miles in length only if the project results in a new distribution system ID. To clarify the language further, Atmos suggested that "10" be replaced with "3" in subsection (a)(6) and the language relating to a new subdivision be removed. Also, Atmos suggested a change to §8.115(b) to clarify that extension requests should be made by emailing PS-48Reports@rrc.texas.gov.

The Commission agrees with Atmos's suggestions and adopts §8.115 with changes based on Atmos's comments. The Commission incorporates Atmos's suggestions into §8.115(a)(5) and moves existing language from subsection (a)(5) relating to systems at least three miles in length but less than ten miles in length to subsection (a)(6). With this change, adopted subsection (a)(5) will address systems less than three miles in length and subsection (a)(6) will address those at least three miles but less than ten miles.

Sierra Club also commented on the proposed amendments to §8.115. Sierra Club expressed support for the requirement for a new liquefied natural gas (LNG) plant or LNG facility construction to notify the Commission not later than 60 days before beginning construction. Sierra Club disagreed that a reporting exemption should be provided to facilities less than three miles in length and recommended this exemption be removed.

The Commission disagrees and declines to remove the exemption. The Commission notes that due to the clarifying changes adopted in §8.115(a)(5) and (a)(6), if construction of a new liquefied petroleum gas distribution system, natural gas distribution system, or master meter system less than three miles in length results in a new distribution system ID, the operator is subject to a reporting requirement. Thus, the exemption only applies when construction is less than three miles in length and does not result in a new distribution system ID. The requirements in §8.115 are intended to ensure the Commission receives notification of large replacement projects for inspection. While operators are not required to report smaller replacement projects, the Commission still performs inspections for smaller replacement projects.

Atmos commented in support of the amendments to §8.125. The Commission appreciates this comment.

Atmos also commented in support of the amendments to §8.201, as long as the payment system can capture large amounts.

The Commission performed testing to ensure the payment portal can capture large amounts.

The Sierra Club commented expressing support for the updates in §8.208. However, Sierra Club opposes the removal of a mandatory reporting requirement in favor of a requirement to maintain records. Sierra Club stated it believes it is better public policy for the operators to report annually to the division on their efforts to replace compression couplings.

The Commission declines to make changes in response to this comment. Since the implementation of §8.208, operators have completed the replacement of all known compression couplings that required removal. However, the Commission will still inspect facilities for compliance with §8.208 during standard comprehensive inspections.

Atmos and TGS commented regarding the proposed amendments to §8.209(j), which were intended to clarify how an operator of a gas distribution system that is subject to the requirements of §7.310 of this title (relating to System of Accounts) may account for the investment and expense incurred to comply with the requirements of §8.209. The comments state that operators have calculated and applied interest in accordance with the rule and on a consistent basis since the rule's original adoption. Atmos provided more information regarding the methodology of the calculation, which records simple interest on the balance of the designated regulatory asset accounts using a monthly interest rate equal to one twelfth of the pre-tax weighted average cost of capital last approved by the Commission for each division. Atmos expressed support for a modification to the proposed language to clarify that methodology.

The Commission adopts §8.209 with changes to address these concerns. The language adopted in subsection (j)(1)(C) will allow the operator to record simple interest on the balance in the designated distribution facility replacement accounts using a monthly interest rate equal to one-twelfth of the pre-tax weighted average cost of capital last approved for the utility by the Commission.

Atmos and the Pipeline Safety Trust commented in support of the proposed amendments to §8.210(e). Sierra Club also expressed support, stating the amendment was a welcome and needed change. The Commission appreciates these comments.

The Pipeline Safety Trust commented suggesting the Commission include additional reporting requirements for estimated leak volume. The comment stated including estimated leak volume will allow the Commission to obtain more information regarding the impact of the leaks, and may help inform other state agencies, such as the Texas Commission on Environmental Quality, on leak impacts.

The Commission declines to include estimated leak volume at this time. PHMSA's pending leak detection and repair rule may impact Commission requirements in §8.210. Thus, the Commission will wait to consider further changes to §8.210 until PHMSA's rule is finalized.

The Commission appreciates the input from all those who submitted comments.

The adopted rule language is summarized in the paragraphs below.

The Commission adopts amendments to §8.1(a)(1)(B) to clarify the requirements for gas production lines located in populated areas. As stated above, the Commission adopts §8.1(a)(1)(B) with a change to remove Type C pipelines based on the comments. The amendments in §8.1(a)(1)(B) also impact current requirements under §3.70, relating to Pipeline Permits Required. The Commission adopts amendments to §3.70 concurrently to these amendments to rules in Chapter 8.

The Commission adopts an amendment in §8.1(a)(1)(D) to clarify that all offshore pipelines (both production and gathering) located in Texas waters shall follow 49 CFR 192 and 49 CFR 195.

The Commission adopts an amendment to §8.1(b) to update the minimum safety standards and to adopt by reference the Department of Transportation (DOT) pipeline safety standards found in 49 CFR Part 191, Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports; 49 CFR Part 192, Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards; and 49 CFR Part 195, Transportation of Hazardous Liquids by Pipeline. Current subsection (b) adopted the federal pipeline safety standards as of September 6, 2021. The amendment changes the date to December 9, 2024, the effective date of the rule amendments, to capture the following federal PHMSA pipeline safety rule amendments: Docket No. PHMSA-2011-0023: Amdt. Nos. 191-30 and 192-129, revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas gathering pipelines effective May 16, 2022; Docket No. PHMSA-2011-0023: Amdt. Nos. 191-31 and 192-131, effective May 16, 2022, denying a petition for reconsideration of the final rule titled "Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments" and making clarifications and two technical corrections to that rulemaking; Docket No. PHMSA-2013-0255: Amdt. Nos. 192-130 and 195-105, revising the Federal Pipeline Safety Regulations applicable to most newly constructed and entirely replaced onshore gas transmission, Type A gas gathering, and hazardous liquid pipelines with diameters of six inches or greater, effective October 5, 2022; Docket No. PHMSA-2013-0255: Amdt. Nos. 192-134 and 195-106, effective August 1, 2023, making editorial and technical corrections clarifying the regulations promulgated in its April 8, 2022, final rule titled "Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards" for certain gas, hazardous liquid, and carbon dioxide pipelines; Docket No. PHMSA-2011-0023: Amdt. No. 192-132, amending the federal pipeline safety regulations in 49 CFR Part 192 to improve the safety of onshore gas transmission pipelines effective May 24, 2023; Docket No. PHMSA-2011-0023: Amdt. No. 192-133, also effective May 24, 2023, making necessary technical corrections in 49 CFR Part 192 to ensure consistency within, and the intended effect of, a recently issued final rule titled "Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments"; and Docket No. PHMSA-2016-0002, Amdt. Nos. 192-135, 195-107, amending 49 CFR Parts 192 and 195 regarding periodic updates of regulatory references to technical standards and miscellaneous amendments which amended the Federal pipeline safety regulations (PSRs) to incorporate by reference all or parts of more than 20 new or updated voluntary, consensus industry technical standards, effective June 28, 2024.

The Commission adopts amendments in §8.1(b)(3) to align the rule text with federal exemptions allowed under 49 CFR §199.2(c)(1).

The Commission adopts several amendments in §8.101. First, the amendments in subsection (b) clarify which pipelines referenced in 49 CFR Part 195 are subject to subsection (b)'s requirements - pipeline facilities used in the transportation of hazardous liquids or carbon dioxide. The current rule's figure clarified which pipelines were subject to the requirements but the rule language was unclear. The Commission also adopts amendments in §8.101(b)(1)(C) and (b)(1)(F) to align state integrity rules with the federal requirements. Amendments in §8.101(d) state that operators of pipelines subject to 49 CFR §192.710 shall follow the remediation requirements required by 49 CFR §192.710(f). Corresponding changes are made to a Figure in the section.

The Commission adopts amendments in §8.110 to incorporate PHMSA definitions of types of gathering lines. For gas, the amendments incorporate new terms "Type C" and "Type R"; for liquid, the amendments incorporate the designation "reporting-regulated-only" gathering lines. These amendments incorporate the newer terminology consistent with federal rules.

The Commission adopts amendments to §8.115 with changes from the proposal. Section 8.115 requires operators of liquefied natural gas (LNG) facilities to report the construction of a new LNG plant or LNG facility to the Commission. The Commission adopts amendments in current §8.115(a)(4), renumbered as paragraph (5), to clarify that for new, relocated, or replacement construction on liquified petroleum gas distribution systems, natural gas distribution systems, or master meter systems less than three miles in length, no construction notification is required. However, new construction for systems less than three miles in length is required to be reported if the construction results in a new distribution system ID. The Commission adopts paragraphs (5) and (6) with changes to better reflect the intent of reporting requirements. Amendments in current subsection (a)(7), renumbered as paragraph (8), exempt Type R gas gathering pipelines and the "reporting-regulated-only" liquid gathering pipelines from the construction notification requirement. Type C pipelines must still comply with this requirement. The other amendments in §8.115 allow electronic filing of required forms and reports either through email or using the Commission's online application for inspections and permits, which is currently called the Pipeline Inspection Permitting System (PIPES) and is available on the Commission's website. Section 8.115 is adopted with another change to specify how to file a request for an extension.

The Commission adopts amendments to §8.125(e) to change terminology to align with the Commission's online filing system called CASES. Applications previously referred to as "dockets" are now called "cases." In addition, amendments in subsection (e) require that a notice of a waiver application include the division's email address in addition to other required contents. Similarly, amendments in subsection (f) allow affected persons who have received notice of a waiver application to object to, support, or request a hearing via email.

The Commission adopts amendments to §8.201(b)(2) and (c)(1) to require payments through the Commission's online application for inspections and permits, PIPES.

The Commission adopts amendments in §8.208(j) to change reporting requirements. Commission staff states operators no longer need to file these reports with the Commission. Instead, they should maintain a progress report annually and provide to the Commission upon request.

The Commission adopts an amendment in §8.209(a) to clarify that 49 CFR §192.1003(b) may provide an exemption. The Commission also adopts amendments in subsection (j) to clarify how an operator of a gas distribution system that is subject to the requirements of §7.310 of this title (relating to System of Accounts) may account for the investment and expense incurred to comply with the requirements of §8.209. The Commission adopts §8.209 with changes based on comments from Atmos and TGS. The language adopted in subsection (j)(1)(C) will allow the operator to record simple interest on the balance in the designated distribution facility replacement accounts using a monthly interest rate equal to one-twelfth of the pre-tax weighted average cost of capital last approved for the utility by the Commission.

The Commission adopts amendments in §8.210(e) to require an operator to submit the PS-95 even if there are no leaks discovered. Additional amendments add references to the Commission's online permit application.

The Commission adopts the amendments under Texas Natural Resources Code, §81.051 and §81.052, which give the Commission jurisdiction over all common carrier pipelines in Texas, persons owning or operating pipelines in Texas, and their pipelines and oil and gas wells, and authorize the Commission to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission, including such rules as the Commission may consider necessary and appropriate to implement state responsibility under any federal law or rules governing such persons and their operations; Texas Natural Resources Code, §§117.001-117.101, which give the Commission jurisdiction over all pipeline transportation of hazardous liquids or carbon dioxide and over all hazardous liquid or carbon dioxide pipeline facilities as provided by 49 U.S.C. Section 60101, et seq.; and Texas Utilities Code, §§121.201-121.210, 121.213-121.214, which authorize the Commission to adopt safety standards and practices applicable to the transportation of gas and to associated pipeline facilities within Texas to the maximum degree permissible under, and to take any other requisite action in accordance with, 49 United States Code Annotated, §§60101, et seq.

SUBCHAPTER A. GENERAL REQUIREMENTS AND DEFINITIONS

16 TAC §8.1

Statutory authority: Texas Natural Resources Code, §81.051, §81.052, and §§117.001-117.101; Texas Utilities Code, §§121.201-121.211; §§121.213-121.214; §121.251 and §121.253, §§121.5005-121.507; and 49 United States Code Annotated, §§60101, et seq.

Cross-reference to statute: Texas Natural Resources Code, Chapter 81 and Chapter 117; Texas Utilities Code, Chapter 121; and 49 United States Code Annotated, Chapter 601.

§8.1.General Applicability and Standards.

(a) Applicability.

(1) The rules in this chapter establish minimum standards of accepted good practice and apply to:

(A) all gas pipeline facilities and facilities used in the intrastate transportation of gas, including LPG distribution systems and master metered systems, as provided in 49 United States Code (U.S.C.) §§60101, et seq.; and Texas Utilities Code, §§121.001 - 121.507;

(B) onshore production pipelines and production facilities, in Class 2, 3, or 4 locations as defined by 49 CFR §192.5, beginning after the first point of measurement and ending as defined by 49 CFR Part 192 as the beginning of an onshore gathering line. These production pipelines and production facilities shall be subject to 49 CFR §192.8(c) in determining if these pipelines and facilities are Type A or Type B and are subject to the rules in 49 CFR §192.9 for Type A or Type B pipelines;

(C) the intrastate pipeline transportation of hazardous liquids or carbon dioxide and all intrastate pipeline facilities as provided in 49 U.S.C. §§60101, et seq.; and Texas Natural Resources Code, §117.011 and §117.012; and

(D) all pipeline facilities originating in Texas waters (three marine leagues and all bay areas). These pipeline facilities include those production and flow lines originating at the well. These facilities shall be subject to 49 CFR Part 192 for natural gas pipelines and 49 CFR Part 195 for hazardous liquid pipelines.

(2) The regulations do not apply to those facilities and transportation services subject to federal jurisdiction under: 15 U.S.C. §§717, et seq.; or 49 U.S.C. §§60101, et seq.

(b) Minimum safety standards. The Commission adopts by reference the following provisions, as modified in this chapter, effective December 9, 2024.

(1) Natural gas pipelines, including LPG distribution systems and master metered systems, shall be designed, constructed, maintained, and operated in accordance with 49 U.S.C. §§60101, et seq.; 49 Code of Federal Regulations (CFR) Part 191, Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports; 49 CFR Part 192, Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards; and 49 CFR Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards.

(2) Hazardous liquids or carbon dioxide pipelines shall comply with 49 U.S.C. §§60101, et seq.; and 49 CFR Part 195, Transportation of Hazardous Liquids by Pipeline.

(3) All operators of pipelines and/or pipeline facilities, except operators that only operate one or more master meter systems, as defined in 49 CFR §191.3, shall comply with 49 CFR Part 199, Drug and Alcohol Testing, and 49 CFR Part 40, Procedures for Transportation Workplace Drug and Alcohol Testing Programs.

(4) All operators of pipelines and/or pipeline facilities regulated by this chapter, other than master metered systems and distribution systems, shall comply with §3.70 of this title (relating to Pipeline Permits Required).

(c) Special situations. Nothing in this chapter shall prevent the Commission, after notice and hearing, from prescribing more stringent standards in particular situations. In special circumstances, the Commission may require the following:

(1) Any operator which cannot determine to its satisfaction the standards applicable to special circumstances may request in writing the Commission's advice and recommendations. In a special case, and for good cause shown, the Commission may authorize exemption, modification, or temporary suspension of any of the provisions of this chapter, pursuant to the provisions of §8.125 of this title (relating to Waiver Procedure).

(2) If an operator transports gas and/or operates pipeline facilities which are in part subject to the jurisdiction of the Commission and in part subject to the Department of Transportation pursuant to 49 U.S.C. §§60101, et seq.; the operator may request in writing to the Commission that all of its pipeline facilities and transportation be subject to the exclusive jurisdiction of the Department of Transportation. If the operator files a written statement under oath that it will fully comply with the federal safety rules and regulations, the Commission may grant an exemption from compliance with this chapter.

(d) Retention of DOT filings. A person filing any document or information with the Department of Transportation pursuant to the requirements of 49 CFR Parts 190, 191, 192, 193, 195, or 199 shall retain a copy of that document or information. Such person is not required to concurrently file that document or information with the Division unless another rule in this chapter requires the document or information to be filed with the Division or unless the Division requests a copy.

(e) Penalties. A person who submits incorrect or false information with the intent of misleading the Commission regarding any material aspect of an application or other information required to be filed at the Commission may be penalized as set out in Texas Natural Resources Code, §§117.051 - 117.054, and/or Texas Utilities Code, §§121.206 - 121.210, and the Commission may dismiss with prejudice to refiling an application containing incorrect or false information or reject any other filing containing incorrect or false information.

(f) Retroactivity. Nothing in this chapter shall be applied retroactively to any existing intrastate pipeline facilities concerning design, fabrication, installation, or established operating pressure, except as required by the Office of Pipeline Safety, Department of Transportation. All intrastate pipeline facilities shall be subject to the other safety requirements of this chapter.

(g) Compliance deadlines. Operators shall comply with the applicable requirements of this section according to the following guidelines.

(1) Each operator of a pipeline and/or pipeline facility that is new, replaced, relocated, or otherwise changed shall comply with the applicable requirements of this section at the time the pipeline and/or pipeline facility goes into service.

(2) An operator whose pipeline and/or pipeline facility was not previously regulated but has become subject to regulation pursuant to the changed definition in 49 CFR Part 192 and subsection (a)(1)(B) of this section shall comply with the applicable requirements of this section no later than the stated date:

(A) for cathodic protection (49 CFR Part 192), March 1, 2012;

(B) for damage prevention (49 CFR 192.614), September 1, 2010;

(D) for line markers (49 CFR 192.707), March 1, 2011;

(E) for public education and liaison (49 CFR 192.616), March 1, 2011; and

(F) for other provisions applicable to Type A gathering lines (49 CFR 192.8(c)), March 1, 2011.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on November 19, 2024.

TRD-202405613

Haley Cochran

Assistant General Counsel, Office of General Counsel

Railroad Commission of Texas

Effective date: December 9, 2024

Proposal publication date: August 30, 2024

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

SUBCHAPTER B. REQUIREMENTS FOR ALL PIPELINES

16 TAC §§8.101, 8.110, 8.115, 8.125

Cross-reference to statute: Texas Natural Resources Code, Chapter 81 and Chapter 117; Texas Utilities Code, Chapter 121; and 49 United States Code Annotated, Chapter 601.

§8.115.New Construction Commencement Report.

(a) An operator shall notify the Commission before the construction of pipelines and other facilities as follows.

(1) For construction of a new, relocated, or replacement pipeline 10 miles in length or longer including liquified petroleum gas distribution systems, natural gas distribution systems, and master meter systems 10 miles in length or longer, an operator shall notify the Commission not later than 60 days before construction.

(2) For construction of a new LNG plant or LNG facility, an operator shall notify the Commission not later than 60 days before construction.

(3) Except as provided in paragraphs (5) and (6) of this subsection, for construction of a new, relocated, or replacement pipeline at least one mile in length but less than 10 miles, an operator shall notify the Commission not later than 30 days before construction.

(4) For installation of any permanent breakout tank, an operator shall notify the Commission not later than 30 days before installation. For installation of mobile, temporary, or prefabricated breakout tanks, an operator shall notify the Commission upon placing the mobile, temporary, or prefabricated breakout tank in service.

(5) For new, relocated, or replacement construction on liquified petroleum gas distribution systems, natural gas distribution systems, or master meter systems less than three miles in length, no construction notification is required unless new construction results in a new distribution system ID. If the construction results in a new distribution system ID, the operator shall either:

(A) notify the Commission not later than 30 days before construction by filing a Form PS-48 New Construction Report for every initial construction; or

(B) provide to the Commission a monthly report that reflects all known projects planned to be completed in the following 12 months, all projects that are currently in construction, and all projects completed since the prior monthly report. The report should provide the status of each project, the city and county of each project, a description of each project, and the estimated starting and ending date. These monthly reports shall be filed by email to PS-48Reports@rrc.texas.gov.

(6) For new, relocated, or replacement construction on liquified petroleum gas distribution systems, natural gas distribution systems, or master meter systems at least three miles in length but less than 10 miles in length, an operator shall either:

(A) notify the Commission not later than 30 days before construction by filing a Form PS-48 New Construction Report for every relocated or replacement construction; or

(7) For construction of a sour gas pipeline and/or pipeline facilities, as defined in §3.106 of this title (relating to Sour Gas Pipeline Facility Construction Permit), an operator shall notify the Commission not later than 30 days before construction by filing Form PS-48 and Form PS-79.

(8) Pipelines subject to §8.110(a)(2) and (3) of this title (relating to Gathering Pipelines) are exempt from the construction notification requirement.

(b) Any of the notifications required by subsection (a) of this section, unless an operator elects to use the alternative notification allowed by subsection (a)(5) or (a)(6) of this section, shall be made by filing a Form PS-48 New Construction Report using the Commission's online application available on the Commission's website. The report shall include the proposed originating and terminating points for the pipeline, counties to be traversed, size and type of pipe to be used, type of service, design pressure, and length of the proposed line. If a notification is not feasible because of an emergency, an operator must notify the Commission as soon as practicable. A Form PS-48 that has been filed with the Commission shall expire if construction is not commenced within eight months of date the report is filed. An operator may submit one extension, which will keep the report active for an additional six months. Extension requests shall be made by emailing PS-48Reports@rrc.texas.gov. After one extension, the Form PS-48 will expire.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on November 19, 2024.

TRD-202405614

Haley Cochran

Assistant General Counsel, Office of General Counsel

Railroad Commission of Texas

Effective date: December 9, 2024

Proposal publication date: August 30, 2024

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

SUBCHAPTER C. REQUIREMENTS FOR GAS PIPELINES ONLY

16 TAC §§8.201, 8.208 - 8.210

Cross-reference to statute: Texas Natural Resources Code, Chapter 81 and Chapter 117; Texas Utilities Code, Chapter 121; and 49 United States Code Annotated, Chapter 601.

§8.209.Distribution Facilities Replacements.

(a) Unless exempted by 49 CFR §192.1003(b), this section applies to each operator of a gas distribution system that is subject to the requirements of 49 CFR Part 192. This section prescribes the minimum requirements by which all operators will develop and implement a risk-based program for the removal or replacement of distribution facilities, including steel service lines, in such gas distribution systems. The risk-based program will work in conjunction with the Distribution Integrity Management Program (DIMP) using scheduled replacements to manage identified risks associated with the integrity of distribution facilities.

(b) Each operator must make joints on below-ground piping that meets the following requirements:

(1) Joints on steel pipe must be welded or designed and installed to resist longitudinal pullout or thrust forces per 49 CFR §192.273.

(2) Joints on plastic pipe must be fused or designed and installed to resist longitudinal pullout or thrust forces per ASTM D2513-Category 1.

(c) Each operator must establish written procedures for implementing the requirements of this section. Each operator must develop a risk-based program to determine the relative risks and their associated consequences within each pipeline system or segment. Each operator that determines that steel service lines are the greatest risk must conduct the steel service line leak repair analysis set forth in subsection (d) of this section and use the prescriptive model in subsection (f) of this section for the replacement of those steel service lines.

(d) In developing its risk-based program, each operator must develop a risk analysis using data collected under its DIMP and the data submitted on the PS-95 to determine the risks associated with each of the operator's distribution systems and establish its own risk ranking for pipeline segments and facilities to determine a prioritized schedule for service line or facility replacement. The operator must support the analysis with data, collected to validate system integrity, that allow for the identification of segments or facilities within the system that have the highest relative risk ranking or consequence in the event of a failure. The operator must identify in its risk-based program the distribution piping, by segment, that poses the greatest risk to the operation of the system. In addition, each operator that determines that steel service lines are the greatest risk must conduct a steel service line leak repair analysis to determine the leak repair rate for steel service lines. The leak repair rate for below-ground steel service lines is determined by dividing the annualized number of below-ground leaks repaired on steel service lines (excluding third-party leaks and leaks on steel service lines removed or replaced under this section) by the total number of steel service lines as reported on PHMSA Form F 7100.1-1, the Gas Distribution System Annual Report. Each operator that determines that steel service lines are the greatest risk must conduct the steel service line leak repair analysis using the most recent three calendar years of data reported to the Commission on Form PS-95.

(e) Each operator must create a risk model that will identify by segment those lines that pose the highest risk ranking or consequence of failure. The determination of risk is based on the degree of hazard associated with the risk factors assigned to the pipeline segments or facilities within each of the operator's distribution systems. The priority of service line or facility replacement is determined by classifying each pipeline segment or facility based on its degree of hazard associated with each risk factor. Each operator must establish its own risk ranking for pipeline segments or facilities to determine the priority for necessary service line or facility replacements. Each operator should include the following factors in developing its risk analysis:

(1) pipe location, including proximity to buildings or other structures and the type and use of the buildings and proximity to areas of concentrations of people;

(2) composition and nature of the piping system, including the age of the pipe, materials, type of facilities, operating pressures, leak history records, prior leak grade repairs, and other studies;

(3) corrosion history of the pipeline, including known areas of significant corrosion or areas where corrosive environments are known to exist, cased crossings of roads, highways, railroads, or other similar locations where there is susceptibility to unique corrosive conditions;

(4) environmental factors that affect gas migration, including conditions that could increase the potential for leakage or cause leaking gas to migrate to an area where it could create a hazard, such as extreme weather conditions or events (significant amounts or extended periods of rainfall, extended periods of drought, unusual or prolonged freezing weather, hurricanes, etc.); particular soil conditions; unstable soil; or areas subject to earth movement, subsidence, or extensive growth of tree roots around pipeline facilities that can exert substantial longitudinal force on the pipe and nearby joints; and

(5) any other condition known to the operator that has significant potential to initiate a leak or to permit leaking gas to migrate to an area where it could result in a hazard, including construction activity near the pipeline, wall-to-wall pavement, trenchless excavation activities (e.g., boring), blasting, large earth-moving equipment, heavy traffic, increase in operating pressure, and other similar activities or conditions.

(f) This subsection applies to operators that determine under subsection (c) of this section that steel service lines are the greatest risk. Based on the results of the steel service line leak repair analysis under subsection (d) of this section, each operator must categorize each segment and complete the removal and replacement of steel service lines by segment according to the risk ranking established pursuant to subsection (e) of this section as follows:

(1) a segment with an annualized steel service line leak rate of 5% or greater but less than 7.5% is a Priority 1 segment and an operator must remove or replace no less than 10% of the original inventory per year; and

(2) a segment with an annualized steel service line leak rate of less than 5% is a Priority 2 segment. An operator is not required to remove or replace any Priority 2 segments; however, upon discovery of a leak on a Priority 2 segment, the operator must remove or replace rather than repair those lines except as outlined in subsection (g) of this section.

(g) For those steel service lines that must remain in service because of specific operational conditions or requirements, each operator must determine if an integrity risk exists on the segment, and if so, must replace the segment with steel as part of the integrity management plan.

(h) All replacement programs require a minimum annual replacement of 8% of the pipeline segments or facilities posing the greatest risk in the system and identified for replacement pursuant to this section. Each operator with steel service lines subject to subsection (f) of this section must establish a schedule for the replacement of steel service lines or other distribution facilities according to the risk ranking established as part of the operator's risk-based program and must submit the schedule to the Division for review and approval or amendment under subsection (c) of this section.

(i) In conjunction with the filing of the pipeline safety and regulatory program fee pursuant to §8.201 of this title (relating to Pipeline Safety and Regulatory Program Fees) and no later than March 15 of each year, each operator must file with the Division:

(1) by System ID, a list of the steel service line or other distribution facilities replaced during the prior calendar year; and

(2) the operator's proposed work plan for removal or replacement for the current calendar year, the implementation of which is subject to review and amendment by the Division. Each operator must notify the Division of any revisions to the proposed work plan and, if requested, provide justification for such revision. Within 45 days after receipt of an operator's proposed revisions to its risk-based plan and work plan, the Division will notify the operator either of the acceptance of the risk-based program and work plan or of the necessary modifications to the risk-based program and work plan.

(j) Each operator of a gas distribution system that is subject to the requirements of §7.310 of this title (relating to System of Accounts) may use the provisions of this subsection to account for the investment and expense incurred by the operator to comply with the requirements of this section.

(1) The operator may:

(A) establish one or more designated regulatory asset accounts in which to record any expenses incurred by the operator in connection with acquisition, installation, or operation (including related depreciation) of facilities that are subject to the requirements of this section;

(B) record in one or more designated plant accounts capital costs incurred by the operator for the installation of facilities that are subject to the requirements of this section;

(C) record interest on the balance in the designated distribution facility replacement accounts using a monthly interest rate equal to one-twelfth of the pretax weighted average cost of capital last approved for the utility by the Commission;

(D) reduce balances in the designated distribution facility replacement accounts by the amounts that are included in and recovered though rates established in a subsequent Statement of Intent filing or other rate adjustment mechanism; and

(E) use the presumption set forth in §7.503 of this title (relating to Evidentiary Treatment of Uncontroverted Books and Records of Gas Utilities) with respect to investment and expense incurred by a gas utility for distribution facilities replacement made pursuant to this section.

(2) This subsection does not render any final determination of the reasonableness or necessity of any investment or expense.

(k) A distribution gas pipeline facility operator shall not install as a part of the operator's underground system a cast iron, wrought iron, or bare steel pipeline. A distribution gas pipeline facility operator shall replace any known cast iron pipelines installed as part of the operator's underground system not later than December 31, 2021.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on November 19, 2024.

TRD-202405615

Haley Cochran

Assistant General Counsel, Office of General Counsel

Railroad Commission of Texas

Effective date: December 9, 2024

Proposal publication date: August 30, 2024

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

PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

SUBCHAPTER E. CERTIFICATION, LICENSING AND REGISTRATION

16 TAC §25.114

The Public Utility Commission of Texas (commission) adopts new §25.114, relating to Registration of Virtual Currency Mining Facilities, with changes to the proposed text as published in the September 13, 2024, issue of the Texas Register (49 TexReg 7173). The adopted rule implements Public Utility Regulatory Act (PURA) §39.360 as enacted by Senate Bill (SB) 1929 from the 88th Texas Legislature (R.S.). The new rule establishes a process for the registration of virtual currency mining facilities in the Electric Reliability Council of Texas (ERCOT) region. Specifically, the rule requires a registrant to provide information to the commission annually about its virtual currency mining facility's location, owners, form of business, and demand for electricity. Additionally, the adopted rule provides that the commission will share the registrants' information with ERCOT. The rule is adopted in Project No. 56962. The rule will be republished.

The commission received comments on proposed new §25.114 from ERCOT, MARA Holdings, Inc. (MARA), Satoshi Energy, Texas Blockchain Council (TBC), Texas Electric Cooperatives, Inc., (TEC), Texas Industrial Energy Consumers, (TIEC), and Vistra Corp. (Vistra).

General comments

MARA requested the commission develop a standardized form for registration.

Commission Response

The commission agrees and will make a standardized online registration form available on its website.

Vistra recommended that the commission restart the rulemaking process and withdraw the proposed rulemaking. Vistra claimed that the proposed rule fails to give effect to PURA §39.360, which requires the commission to establish generally applicable large flexible load registration requirements.

Commission Response

The commission disagrees that the rule fails to give effect to PURA §39.360. Although the statute requires the registration of a virtual currency mining facility as a large flexible load, the statute is silent on the characteristics of a large flexible load and whether other entities should be required to register as such at this time. However, the statute unambiguously requires the registration of virtual currency mining facilities. Accordingly, the commission declines to withdraw the proposed rule, as recommended by Vistra.

Satoshi Energy recommended the addition of three items into the registration rule. First, the commission should develop rules to ensure there is a process for attributing how much of a load is dedicated to virtual currency mining, allowing for updates at regular intervals. Second, a load should not be required to register as a virtual currency mine unless its electric consumption constitutes a substantial portion (equal to or more than 50 percent) of the total load consumption of the load facility. Third, a deregistration process should be established for virtual currency mining loads that are repurposed for other types of consumption.

Commission Response

The commission declines to modify the rule to establish a process for determining how much of a load is dedicated to virtual currency mining or to only require registration of facilities with a substantial portion of load dedicated to virtual currency mining. As required by PURA §39.360, registration is required for virtual currency mining facilities that have a total load of more than 75 megawatts (MWs) and that have an interruptible facility load. Further, PURA defines a virtual currency mining facility as "a facility that uses electronic equipment to add virtual currency transactions to a distribution ledger." Since it is the statute, not commission rule, that establishes this registration requirement, the commission cannot, by rule, exempt a facility that meets that definition from the commission's registration requirement.

However, because the commission recognizes that the purpose of the statute is to provide the commission and ERCOT with information for reliability purposes, the commission interprets interruptible facility load to mean that a facility must have at least 10 percent interruptible load to be required to register - it is the interruptibility of the load that is directly relevant for reliability. While not all interruptible load is necessarily related to virtual currency mining, this at least ensures that a small amount of virtual currency mining would not result in a facility that is largely not interruptible having to register.

The commission also declines to modify the rule to include a deregistration process. If a virtual currency mining load is repurposed for another type of consumption, then the facility operator may allow its registration as a virtual currency mining facility to lapse, and it would then no longer be registered. An entity may also be able to relinquish its registration as an "update" under the rule, depending upon the functionality of the online registration tool. However, this is a practical question that is not appropriately addressed in codified rule text.

TIEC recommended the addition of a new subsection that would require ERCOT to issue a market notice concerning the registration requirements under proposed §25.114 to all load serving entities (LSEs) within ten days of the rule's effective date. Additionally, TIEC's new subsection (g) would require LSEs to notify any new or existing customers that have a load of greater than 50 MWs, or may otherwise qualify as a virtual currency mining facility, of the new registration requirements.

Commission Response

The commission declines to modify the rule to require ERCOT to issue a market notice alerting LSEs of the new registration requirements. The commission may direct commission staff to work with ERCOT to issue a market notice without codifying the requirement in rule. The commission also declines to modify the rule to require LSEs to notify customers with a load of greater than 50 MWs of these requirements because this would impose burdens on entities to which this rule does not apply. LSEs were also not provided notice and an opportunity to comment on this potential burden in this rulemaking proceeding. Customers with a load of 50 MWs or greater are sophisticated entities that can reasonably be expected to monitor potential upcoming requirements - especially those that are directly required by legislation and were implemented as part of a rulemaking that was properly noticed under the Texas Government Code and on the commission's website.

MARA and TBC expressed concern for the safeguarding of confidential and proprietary information required in the registration. Both requested that the rule be amended to explicitly identify the information provided as confidential and proprietary while also providing robust protection of this information.

Commission Response

The commission declines to modify the rule in response to address confidentiality, as requested by MARA and TBC. The registration information will be collected via an internal-facing online tool that will not be accessible to the public. Furthermore, the majority of information being collected is already publicly available in various locations. However, neither the commission nor ERCOT will disclose competitively sensitive or proprietary information unless legally required to do so.

Proposed §25.114(a) - Registration required

Proposed subsection (a) requires a virtual currency mining facility to register as a large flexible load if it requires a total load of more than 75 MW and the facility's interruptible load equals 10 percent or more of the actual or anticipated annual peak demand of the facility with ERCOT. Proposed subsection (a) also requires registration for any virtual currency mining facility that meets the requirements and that began receiving retail electric service prior to the effective date of this rule. Proposed subsection (a) requires registration by February 1, 2025, for a facility that began receiving retail electric service prior to the effective date of this rule.

Sierra Club recommended that the commission encourage virtual currency mining facilities under 75 MW to register as additional facilities would provide important additional information to the commission. MARA disagreed with Sierra Club's recommendation and requested that proposed §25.114 not be changed to add this language.

Commission Response

The commission declines to modify the rule to require or encourage registration of virtual currency mining facilities with fewer than 75 MWs of load, as requested by Sierra Club. The statute does not contemplate the inclusion of a facility with a load below 75 MWs, and it would be administratively cumbersome for commission staff to manage additional, patchwork data that is not required to be regularly updated. Furthermore, since the statute requires registration as "large flexible load," having smaller loads in the dataset may lead to confusion in the future.

MARA requested that the registration requirement for facilities with at least 10 percent interruptible load be deleted from the rule because such a threshold exceeds the authority granted by PURA §39.360 and "complicates the straightforward statutory framework." MARA argued that the statute only requires registration for facilities "that have a total load of more than 75 MW of interruptible load."

Commission Response

The commission disagrees with MARA's assertion that including the 10 percent interruptible load threshold as a registration criterion exceeds the commission's statutory authority. The statute requires the commission to "adopt criteria for determining whether a load is interruptible for the purposes of this section based on whether it is possible for the facility operator to choose to interrupt the load" and requires the operator to register a facility if "the facility load is interruptible." The commission gives effect to these requirements by adopting a definition of interruptible load that applies specifically to the portion of a facility's load that is interruptible because it is only this portion of the load that a facility operator can choose to interrupt. Very few, if any, facilities are completely interruptible, so to distinguish whether a "facility load is interruptible," the commission determines that a facility with 10 percent interruptible load is interruptible for purposes of the registration requirements under this rule.

The commission disagrees with MARA's assertion that the statute only requires registration of facilities "that have a total load of more than 75 MW of interruptible load." The issue with this statutory interpretation is evident from the ambiguity of MARA's own phrasing. Does the 75 MW threshold apply to the "total load" of the facility or the "interruptible load"? If the legislature had intended it to apply to the interruptible load, it could have easily expressed this intent by requiring registration of facilities "with 75 MWs of interruptible load." Instead, it established two separate requirements. First, that the total load of the facility be 75 MWs, and second, that the facility load be interruptible. Accordingly, it is appropriate - and in fact necessary - for the commission to determine how much of a facility's load is interruptible for purposes of this statute. The commission sets that threshold at 10 percent.

Additionally, MARA asserted that proposed §25.114 requires "retroactive registration" because the rule requires registration of any virtual currency mining facility that began receiving retail electric service prior to the effective date of this rule, and that retroactive application of the law would raise significant contractual and constitutional concerns. Accordingly, MARA requested that the portion of the rule that requires registration for any facility in operation prior to the effective date of the rule be removed.

Commission Response

The commission declines to modify the rule to remove the requirement for existing facilities to register under the rule, as requested by MARA. No contractual relationships will be affected by adoption of this rule. The rule only requires that virtual currency mining facilities, many of which are already in operation and have an impact on reliability in this state, register with the commission as large flexible loads. No other requirements are imposed on these entities and, in fact, failure to register does not even impede a virtual currency mining facility's ability to operate. It merely subjects the entity to an administrative penalty for failure to register.

Vistra recommended that proposed subsection (a) be modified to extend the registration deadline for registrants that began receiving retail electric service prior to the effective date of this rule to 90 days after the effective date of the rule.

Commission Response

The commission declines to extend the deadline to register, as requested by Vistra. The registration requirements under this rule are not burdensome and should not be difficult to comply with in a timely fashion. ERCOT recommended that subsection (a) be modified to specify that virtual currency mining facilities operating in the ERCOT region "at either transmission or distribution voltage" are required to register with the commission as large flexible loads.

Commission Response

The commission agrees with ERCOT's recommendation and modifies the rule accordingly. This addition clarifies the intent to capture all applicable virtual currency mining facilities, regardless of whether the load is interconnected at transmission- or distribution-level voltage.

Proposed §25.114(b) - Definitions

The proposed language for subsection (b) defines "interruptible load" as "the portion of the facility's load that the facility operator can choose to interrupt due to locational marginal prices, load zone prices, response to the ERCOT coincident peak demand for the months of June, July, August and September (4CP), or due to external grid conditions."

MARA requested that the proposed definition of "interruptible load" be modified and instead defined as load that can be ramped up or down by a facility's operator within 15 minutes, or at ERCOT's request, without violating any existing agreements or contracts.

Commission Response

The commission disagrees and declines to modify the rule as requested by MARA. The proposed definition is based on the statutory requirement that interruptibility be based on whether it is possible for the facility operator to choose to interrupt the load. The commission consulted with ERCOT to enhance the statutory definition by reflecting the circumstances in which virtual currency mining facilities interrupt their load, based on observed consumption and known business models. This definition of interruptible load provides reasonable and objective criteria for identifying the characteristics of virtual currency mining facilities that should trigger the statutory registration requirement.

Sierra Club requested that a definition of "controllable load resource" (CLR) be added to the rule.

Commission Response

The commission disagrees and declines to modify the proposed rule to include a definition of CLR, as requested by Sierra Club, because that term does not appear in the rule. Sierra Club's requested language that would use this term is addressed below.

Proposed §25.114(c) - Registration requirements

Proposed subsection (c) states the information that registrants must provide to the commission, including legal business name, mailing address, electronic mailing address, and form of business.

Sierra Club recommended modifying proposed subsection (c) to add the following requirements: whether the facility has registered as a resource entity with ERCOT, whether it has registered as a CLR, and whether it has participated or expects to participate in ancillary services available to loads.

Commission Response

The commission disagrees and declines to modify the proposed rule as recommended by Sierra Club because the suggested additions are unnecessary. ERCOT already has information about which entities have registered as a resource entity or CLR with ERCOT and which entities are eligible to participate in ancillary services programs. Furthermore, the commission does not need, for its own purposes, this information at the time a virtual currency mining facility registers as a large flexible load. The commission can obtain this information from ERCOT as needed.

MARA requested that all references to "virtual currency mining facility" be replaced with "large flexible load" in all of subsection (c).

Commission Response

The commission disagrees and declines to modify the rule as requested by MARA because the language in the proposed rule follows the statutory language, which refers to "virtual currency mining facilities," not all "large flexible loads."

Proposed §25.114(c)(1)

Proposed subsection (c)(1) requires a registrant to provide its legal business name, corporate parent, the registrant's principals, and all business names used by the facility.

MARA asserted that several of the registration requirements under proposed subsection (c)(1) were excessive or redundant. Specifically, MARA commented that requiring a registrant to disclose all business names is excessive, especially if the registrant operates under multiple business names. Additionally, MARA asserted that requiring a registrant to list the names of its principals is redundant because proposed subsection (c)(3) requires a regulatory contact.

Commission Response

The commission disagrees with MARA's comment that the proposed registration requirements are excessive and declines to modify the rule. To adequately identify virtual currency mining facilities, this identifying information is necessary. Historically, the information provided to ERCOT regarding virtual currency mining facilities has been limited to a subset of large virtual currency mining facilities and has resulted in a lack of visibility around ownership or operation of these facilities being transferred to another entity. This part of the registration requirement will assist ERCOT in identifying these operators more readily. Furthermore, PURA requires the commission to ensure compliance with these registration requirements. Having access to information such as active business names will allow the commission to quickly identify whether an identified business has already registered without having to actively attempt to identify the entity associated with a name to determine if it has registered and in the commission's records.

Proposed §25.114(c)(5)

Proposed subsection (c)(5) requires registrants to provide the commission with information that is on file with the Texas Secretary of State.

MARA stated that the requested information in proposed subsection (c)(5) is burdensome and of "questionable value" to the commission. MARA recommended that the commission work directly with the Texas Secretary of State to confirm a registrant's business standing, rather than requiring that the registrant submit information to the commission that they have already submitted to the Texas Secretary of State. MARA recommended that proposed subsection (c)(5) be deleted entirely but also provided alternative redlines to modify the language instead.

Commission Response

The commission disagrees with MARA's assertion that the requested information in proposed subsection (c)(5) is of "questionable value" to the commission. To fully and efficiently identify virtual currency mining facilities, an evaluation of business standing in the state of Texas is necessary. Historically, the information available to the commission and ERCOT regarding virtual currency mining facilities has been limited to a subset of large virtual currency mining facilities and has resulted in a lack of visibility when ownership and operation of these facilities is transferred between entities. In addition, given the many possible names under which a facility operator could be operating, the registrant has much easier access to information it has submitted to the Texas Secretary of State than the commission does.

Proposed §25.114(c)(6)

Proposed subsection (c)(6) lists the information that a registrant must provide for each virtual currency mining facility it operates.

MARA requested that every requirement under proposed subsection (c)(6) be deleted from the rule, except for (A) and a slightly modified version of (F). Specifically, MARA's redlines would remove the following disclosure requirements: the identity of the property owner and lessor or facility host; the size of the facility and an infrastructure description; the names of the facility's transmission and distribution service providers; the percentage of site load that constitutes interruptible load under the section; the actual peak load and total power consumption for the prior year; and if applicable, details on the facility's on-site backup generation. MARA stated that the listed requirements are too detailed, go beyond the requirements of SB 1929, and offer "little information of value" to the commission.

Commission Response

The commission declines to modify the rule to remove detailed registration requirements, as requested by MARA. The proposed rule requires provision of registration information necessary for the commission and ERCOT to adequately identify, communicate with, and understand consumption and anticipated load growth attributable to large virtual currency mining facilities. The proposed rule is consistent with the purpose and the scope of the statute.

ERCOT recommended that proposed subsection (c)(6)(H) be amended to clarify that the disclosure requirement for actual peak load applies if a facility took retail electric service at any time in the previous calendar year.

Commission Response

The commission agrees that the applicability of proposed (c)(6)(H) could be clarified with the language suggested by ERCOT and modifies the rule accordingly.

Vistra recommended editing proposed subsection (c)(6)(I) to include self-generators, those served directly by a power generation company inside of a private-use network or other co-located netting arrangement.

Commission Response

The commission declines to modify the proposed rule, as requested by Vistra, to include self-generators and those served directly by a power generation company inside of a private use network or other co-located netting arrangement. Instead, the commission removes subsection (c)(6)(I) to more closely align the required information with the statutory text and reduce the burden of compliance on registrants. Proposed §25.114(c)(7)(A)-(C) Proposed paragraph (c)(7) requires registrants to include an affidavit signed by a representative with binding authority over the registrant asserting that the registrant is authorized to conduct business in Texas, the statements made in the registration are true and accurate, material changes will be reflected in a timely manner, and that the registrant understands and will comply with Texas law.

MARA recommended modifying proposed subsection (c)(7) to only require an affidavit signed by a representative, official, officer, or other authorized person with binding authority over the registrant, to affirm that "the information provided in the registration is accurate to the best of their knowledge."

Commission Response

The commission disagrees and declines to modify the proposed rule to only require a general affirmation by an authorized individual that the registration is accurate to the best of their knowledge. The requirement that affiants affirm that the registration details are "complete and correct" is consistent with other commission rules, such as §25.112, relating to Registration of Brokers, which requires an affirmation that all statements in the application are "true, correct, and complete." Moreover, the nature of the information required for this registration is objective and should not be difficult to verify.

The other required affidavit contents are neither redundant nor excessive and facilitate the implementation of the registration program required by statute. For instance, updated information is important, and requiring an affirmation that updated information will be provided in a timely manner is necessary to ensure that an authorized representative of the registrant is actively aware of this requirement and acknowledges that these updates will occur. The broker registration rule contains a similar provision. Furthermore, customers with large loads often have interactions their transmission and distribution service providers. Given that registrants are facilities with a total load exceeding 75 MWs, requiring the registrant to communicate its compliance with the rule to its service provider is reasonable. Such notice would benefit large load planning and integration processes in the ERCOT region by ensuring that registrant information is complete and up to date.

Proposed §25.114(c)(7)(D)

Proposed subsection (c)(7)(D) requires the registrant to swear or affirm that it has notified its transmission and distribution service provider of its compliance with this section. Vistra recommended modifying proposed subsection (c)(7)(D) to require registrants to also notify retail electric providers (REPs) and any power generation company inside of a private-use network or other co-located netting arrangement. Vistra asserted that an entity, or entities, with a direct contractual relationship with a virtual currency mining facility has a vested interest in understanding whether their customer is compliant with commission requirements.

Commission Response

The commission disagrees with Vistra's assertion that proposed subsection (c)(7)(D) should be expanded to require contact between virtual currency mining facilities and their contracted business partners and declines to modify the rule accordingly. The purposes of the statute and this rule are to create and maintain a registry of virtual currency mining facilities at the commission and for the associated registration information to be shared with ERCOT. Notice to transmission and distribution service providers is also appropriate for reliability purposes. If REPs or other entities with contractual relationships with the virtual currency mining facility are interested in this information, they can seek to obtain it directly from their business partners.

Proposed §25.114(d) - Update of registration

Proposed subsection (d) requires a registrant to file an updated registration with the commission within 30 days of a change to the information required by subsection (c).

MARA suggested that all references to "virtual currency mining facility" in this subsection be replaced with "large flexible load" and suggested modifying the provision to only require updates when there is a "material change," rather than any change. MARA recommended that material changes include changes to contact information, "significant" expansions of load beyond that originally registered, and changes to the facility's ability to curtail or interrupt load.

Commission Response

The commission disagrees and declines to modify the rule to refer to "large flexible loads" because the language in the adopted rule follows the statutory language, which refers specifically to "virtual currency mining facilities." Regarding only requiring updates for material changes, "material change" is an imprecise term that could lead to confusion as to which changes are material (e.g., what constitutes a "significant" expansion of load). Furthermore, the nature of the information required should not change frequently enough to be unduly burdensome on registrants.

To provide internal consistency throughout the rule, the commission revises subsection (c)(7)(C) to require an affidavit affirming that any changes, rather than material changes, will be provided in a timely manner.

Proposed §25.114(e) - Registration renewal

Proposed subsection (e) requires a registrant to renew its registration on or before March 1 of every calendar year. A registrant must update its information either by submitting all of the information required by subsection (c) or by submitting a statement that all of its information on file with the commission is correct.

The commission modifies the rule for clarity. Subsection (e)(1) and (2) are modified and (3) is deleted to clarify the expiration of registration upon failure to renew. March 1, is the date by which registration expires and the registrant is out of compliance with the rule. After March 1, commission staff may attempt to contact registrants to inform a facility of its failure to renew.

TEC observed that the requirements of proposed subsections (c)(6)(F) and (H) require annual information, making it impossible for all of a registrant's information on file to be correct year over year (e.g., (H) requires the facility's actual peak load for the prior year). TEC recommended allowing a registrant to update the information for those two provisions alone, along with a statement that all of its information on file with the commission is correct.

Commission Response

The commission agrees that the information about anticipated and actual peak load required in proposed subsection (c)(6)(F) and (H) must be updated by March 1 each year. The commission modifies the rule to allow a registrant to update only that information along with a statement that the rest of its information is up to date, as recommended by TEC.

MARA opposed the annual reporting requirement and instead recommended requiring updates only upon material change.

Commission Response

"Material change" is an imprecise term that could lead to confusion as to which changes are material. To avoid this confusion and ensure that each registrant submits updated information at predictable intervals, the commission declines to modify the rule.

ERCOT recommended editing subsection (e)(1) so that commission staff gives notice before the deadline, not after.

Commission Response

Subsection (e)(1), as commented on by ERCOT, was a misprint in a version of the draft filed on the commission's website. The official proposed rule published in the Texas Register does not contain this provision. Accordingly, the commission does not modify the rule in response to ERCOT's comment.

Proposed §25.114(f) - Administrative penalty

Proposed subsection (f) categorizes a failure to comply with the rule as a Class A violation. MARA recommended removing the penalty subsection or, in the alternative, making any violation of subsection (f) a Class C violation. Vistra also recommended modifying subsection (f) to make any violation of the rule a Class C violation.

Commission Response

The commission declines to modify the rule to make a violation of the rule a Class C violation. PURA §39.360(d)(2) states that the commission by rule shall establish a method to ensure compliance with these requirements. The statute does not provide the commission with any additional authority or tools with which to ensure compliance, leaving a heightened administrative penalty as the only means by which the commission can comply with this statutory mandate. Moreover, in practical terms, a Class C violation, which is limited to 1,000 dollars per violation per day, may not be a sufficient incentive to ensure the compliance of such large entities. The proposed Class A violation accurately reflects the importance of this requirement to grid reliability and the size of the entities to which these requirements apply. Furthermore, many violations of this section would already be classified as Class A violations - or are similar to existing Class A violations - under §25.8(b)(3), such as conducting business without proper registration or one of the several provisions related to reliability. Finally, under §22.246(c)(3), related to Administrative Penalties, the commission will consider many variables, including the seriousness of the violation and the surrounding facts and circumstances, in determining an appropriate penalty for violations of this rule.

All comments, including any not specifically referenced herein, were fully considered by the commission. In adopting this section, the commission makes other minor modifications for the purpose of clarifying its intent.

STATUTORY AUTHORITY

The new section is adopted under the following provisions of PURA: §14.001, which grants the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by this title that is necessary and convenient to the exercise of that power and jurisdiction; §14.002, which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; and §39.360, which requires certain virtual currency mining facilities to register with the commission, directs the commission to adopt criteria for determining whether a load is interruptible and establish a method to ensure compliance with the statutory registration requirements, and authorizes the commission to share the registration information with ERCOT.

§25.114.Registration of Virtual Currency Mining Facilities.

(a) Registration required. A person operating a virtual currency mining facility receiving retail electric service in the Electric Reliability Council of Texas (ERCOT) region at either transmission or distribution voltage must, not later than one working day after the date the facility begins receiving retail electric service, register the facility as a large flexible load if the facility requires a total load of more than 75 megawatts (MW) and the facility's interruptible load equals 10 percent or more of the actual or anticipated annual peak demand of the facility. A person operating a virtual currency mining facility that is required to register as a large flexible load under this section and began receiving retail electric service prior to the effective date of this rule must register no later than February 1, 2025.

(b) Definitions. The following terms, when used in this section, have the following meanings.

(1) Virtual currency--has the meaning assigned by Section 12.001, Business & Commerce Code.

(2) Virtual currency mining facility--a facility that uses electronic equipment to add virtual currency transactions to a distributed ledger.

(3) Interruptible load--the portion of the facility's load that the facility operator can choose to interrupt due to locational marginal prices, load zone prices, response to the ERCOT coincident peak demand for the months of June, July, August and September (4CP), or due to external grid conditions.

(1) The registrant's legal business name, the name of the registrant's corporate parent or parents, the name of the registrant's principals, and all business names of the registrant.

(2) A mailing address, telephone number, and e-mail address of the principal place of business of the registrant.

(3) The current name, title, business mailing address, telephone number, and e-mail address for the registrant's regulatory contact person, and whether the regulatory contact is an internal staff member of the registrant.

(4) The form of business being registered (e.g., corporation, partnership, or sole proprietor).

(5) Applicable information on file with the Texas Secretary of State, including, the registrant's endorsed certificate of incorporation certified by the Texas Secretary of State, a copy of the registrant's certificate of fact - status or other business registration on file with the Texas Secretary of State.

(6) For each virtual currency mining facility operated by the registrant:

(A) the name, address, and county of operation of each facility;

(B) the identity of the property owner and lessor or facility host;

(C) the size of the facility in square feet and a description of the infrastructure, including whether it is fixed or movable, open or enclosed;

(D) the names of the transmission and distribution service providers serving the facility and the load zone the facility is located in;

(E) the Electric Service Identifier (ESIID) or equivalent unique premise identifier assigned to the facility;

(F) the anticipated peak load, in MWs, from the facility for each year of the five-year period beginning on the date of the registration;

(G) the percentage of the site load that meets the definition of interruptible load in subsection (b)(3) of this section; and

(H) the actual peak load in MWs and total power consumption in MWhs for the prior calendar year, if the facility took retail electric service at any time during the prior calendar year.

(7) An affidavit signed by a representative, official, officer, or other authorized person with binding authority over the registrant affirming that:

(A) the registrant is authorized to do business in Texas under all applicable laws and is in good standing with the Texas Secretary of State;

(B) that all statements made in the registration submission are true, correct, and complete;

(D) that the registrant has provided notice of its compliance with this rule to transmission distribution service providers serving its registered facilities; and

(E) that the registrant understands and will comply with all applicable law and rules.

(d) Update of registration. A registrant must amend its registration with the commission within 30 days of a change to the information required by subsection (c) of this section.

(e) Renewal of registration. A virtual currency mining facility registration expires and must be renewed on or before March 1 of every calendar year by either submitting the information required by subsection (c) of this section or by submitting updated information required by subsections (c)(6)(F) and (H) of this section and a statement that the rest of the facility's registration information on file with the commission is current and correct.

(1) By December 31 of each calendar year, commission staff must identify each virtual currency mining facility registration that has not been renewed.

(2) Commission staff will provide ERCOT a list of each virtual currency mining facility that has been identified under paragraph (1) of this subsection by January 31 each year.

(f) Administrative penalty. The commission may impose an administrative penalty on a person for a violation of the Public Utility Regulatory Act, commission rules, or rules adopted by an independent organization, including failure to timely respond to commission or commission staff inquiries. A violation of this section is a Class A violation under §25.8 of this title, relating to Classification System for Violations of Statutes, Rules, and Orders Applicable to Electric Service Providers.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on November 21, 2024.

TRD-202405694

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: December 11, 2024

Proposal publication date: September 13, 2024

For further information, please call: (512) 936-7322