TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 3. OIL AND GAS DIVISION

16 TAC §3.70

The Railroad Commission of Texas (Commission) proposes amendments to §3.70, relating to Pipeline Permits Required, to clarify language related to production and flow lines, to allow each operator to renew all its permits in the same month, to clarify fee requirements for gathering pipelines, and to reduce late fees for operators with 50 miles or less of pipeline.

The amendments in subsection (a) are proposed to reduce confusion regarding when production or flow lines do not leave a lease and, therefore, do not need a permit. The current rule language only requires production or flow lines to have a pipeline permit if the production or flow line leaves a lease. The proposed amendments remove the language related to whether a production or flow lines leaves a lease in its entirety. Instead, the Commission proposes to only require a permit for those production and flow lines over which the Commission has pipeline safety jurisdiction. The Commission currently exercises pipeline safety jurisdiction over two categories of production and flow lines: (1) certain onshore pipeline and gathering production facilities, as defined in §8.1(a)(1)(B) of this title (relating to General Applicability and Standards); and (2) all pipeline facilities originating in Texas waters, as defined in §8.1(a)(1)(D) of this title. The Commission does not have pipeline safety jurisdiction over production and flow lines that are not defined in §8.1(a)(1)(B) and §8.1(a)(1)(D) of this title, and therefore proposes to no longer require a permit for those pipelines--even if the pipelines leave a lease. The Commission proposes a definition of production and flow lines similar to the definition used in API RP 80 to help reduce confusion.

The proposed amendments in subsection (i) clarify that the fee requirements for gathering pipelines regulated under proposed new §8.110 (which is part of amendments to Chapter 8 proposed concurrently with the amendments to §3.70) are still designated as Group B and will continue to pay an annual fee of $10 per mile of gathering pipeline permitted to the operator. Other non-substantive amendments are proposed to subsection (i).

Amendments proposed in subsection (j) create a new annual permit renewal timeline beginning September 1, 2020. Currently, each permit has a specific annual renewal date, which, generally, is based on the date of permit application. Individual permit renewal is burdensome for both operators and Commission staff. The proposed amendments maintain the current renewal process for one year, but beginning September 1, 2020, operators will renew all their permits within a designated month assigned to operators alphabetically. Operators whose names begin with the letters A through C shall file in February; operators whose names begin with the letters D through E shall file in March; operators whose names begin with the letters F through L shall file in April; operators whose names begin with the letters M through P shall file in May; operators whose names begin with the letters Q through T shall file in June; and operators whose names begin with the letters U through Z and operators whose names begin with numerical values or other symbols shall file in July. For example, beginning September 1, 2020, an operator whose name begins with A shall pay all its permit renewals in February 2021.

Proposed new subsection (k) addresses renewal dates when permits are transferred or an operator adds a new permit. Proposed subsection (k)(1) states that if a permit is transferred, in the Commission fiscal year of the transfer the acquiring operator shall renew that permit in its designated month. If the acquiring operator receives the transferred permit in a Commission fiscal year after its renewal month as passed, acquiring operator shall pay the renewal fee upon transfer. Proposed subsection (k)(2) states that if an operator adds a new permit and pays the new permit fee, it is not required to pay the renewal fee for that permit in the same Commission fiscal year. Proposed subsection (k)(3) states that if an operator adds a new permit after its renewal month has passed, the new permit shall be renewed the following Commission fiscal year in the operator's designated month.

Proposed amendments in subsection (l) reflect changes to the renewal process proposed in subsection (j).

Proposed new subsection (m) reduces the late fee for operators with a total mileage of 50 miles or less of pipeline who fail to pay the annual mileage fee on time. Corresponding changes are proposed in subsection (n) such that the existing late fees only apply to operators with a total mileage of more than 50 miles of pipeline.

Kari French, Director, Oversight and Safety Division, has determined that for each year of the first five years the amendments will be in effect there will be no fiscal implications to the Commission or to the regulated industry as a result of the amendments. There will be no fiscal effect on local government.

Ms. French has determined that for each year of the first five years the proposed amendments are in effect, the anticipated public benefit will be clarity regarding pipeline permit requirements and a more efficient permit renewal process.

The Commission has determined that the proposed amendments will not have an adverse economic effect on rural communities, small businesses or micro-businesses. Therefore, the Commission has not prepared the economic impact statement or the regulatory flexibility analysis pursuant to Texas Government Code §2006.002.

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

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

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

Comments on the proposed amendments may be submitted to Rules Coordinator, Office of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711-2967; online at www.rrc.texas.gov/general-counsel/rules/comment-form-for-proposed-rulemakings; or by electronic mail to rulescoordinator@rrc.texas.gov. The Commission will accept comments until noon (12:00 p.m.) on Monday, November 18, 2019. The Commission finds that this comment period is reasonable because the proposal and an online comment form will be available on the Commission's website more than two weeks prior to Texas Register publication of the proposal, giving interested persons additional time to review, analyze, draft, and submit comments. The Commission cannot guarantee that comments submitted after the deadline will be considered. For further information, call Kari French at (512) 463-8859. The status of Commission rulemakings in progress is available at www.rrc.texas.gov/general-counsel/rules/proposed-rules.

The Commission proposes the amendments to §3.70 pursuant to Texas Natural Resources Code, §81.071, enacted by the 85th Legislature (Regular Session, 2017) in House Bill 1818, 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 proposes the amendments pursuant to §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 §81.0531, which authorizes the Commission to assess a penalty for a violation of a provision of Title 3 of the Texas Natural Resources Code, or a rule, order, license, permit, or certificate that relates to pipeline safety; §85.202, which authorizes the Commission to promulgate rules requiring records to be kept and reports made, and providing for the issuance of permits, tenders, and other evidences of permission when the issuance of the permits, tenders, or permission is necessary or incident to the enforcement of the Commission's rules for the prevention of waste; 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 when the issuance of the permit or permission is necessary or incident to the enforcement of its blanket grant of authority to make any rules necessary to effectuate the law; 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; 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. §§60101, et seq.; 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.

Statutory authority: Texas Natural Resources Code §§81.051, 81.052, 81.0531, 81.071, 85.202, 86.041, 86.042, 111.131, 111.132, and §§117.001 - 117.101; 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 111, and Chapter 117; Texas Utilities Code, Chapter 121; and 49 United States Code Annotated, Chapter 601.

§3.70.Pipeline Permits Required.

(a) Each operator of a pipeline or gathering system, other than [a production or flow line that does not leave a lease or] an operator excluded under §8.1(b)(4) of this title (relating to General Applicability and Standards)relating to General Applicability and Standards, subject to the jurisdiction of the Commission, shall obtain a pipeline permit, to be renewed annually, from the Commission as provided in this rule. Production or flow lines that are subject to §8.1(a)(1)(B) and (a)(1)(D) of this title must comply with this section. All other production or flow lines as defined in this subsection are exempt from complying with this section. A production or flow line is piping used for production operations that generally occur upstream of gathering or other pipeline facilities. For the purposes of this subsection, piping used in "production operations" means piping used for production and preparation for transportation or delivery of hydrocarbon gas and/or liquids, and includes the following processes:

(1) extraction and recovery, lifting, stabilization, treatment, separation, production processing, storage, and measurement; and P> (2) associated production compression, gas lift, gas injection, or fuel gas supply.

(b) To obtain a new pipeline permit or to amend a permit because of a change of classification, an operator shall file an application for a pipeline permit on the Commission's online permitting system. The operator shall include or attach the following documentation and information:

(1) the contact information for the individual who can respond to any questions concerning the pipeline's construction, operation or maintenance;

(2) the requested classification and purpose of the pipeline or pipeline system as a common carrier, a gas utility or a private line;

(3) a sworn statement from the pipeline applicant providing the operator's factual basis supporting the classification and purpose being sought for the pipeline, including, if applicable, an attestation to the applicant's knowledge of the eminent domain provisions in Texas Property Code, Chapter 21, and the Texas Landowner's Bill of Rights as published by the Office of the Attorney General of Texas; and

(4) documentation to provide support for the classification and purpose being sought for the pipeline, if applicable; and

(5) any other information requested by the Commission.

(c) To renew an existing permit, to amend an existing permit for any reason other than a change in classification, or to cancel an existing permit, an operator shall file an application for a pipeline permit on the Commission's online filing system. The operator shall include or attach:

(1) the contact information for the individual who can respond to any questions concerning the pipeline's construction, operation, or maintenance; change in operator or ownership; or other change including operator cessation of pipeline operation;

(2) a statement from the pipeline operator confirming the current classification and purpose of the pipeline or pipeline system as a common carrier, a gas utility or a private line, if applicable; and

(3) any other information requested by the Commission.

(d) Upon receipt of a complete permit application, the Commission has 30 calendar days to issue, amend, or deny the pipeline permit as filed. If the Commission determines that the application is incomplete, the Commission shall promptly notify the applicant of the deficiencies and specify the additional information necessary to complete the application. Upon receipt of a revised application, the Commission has 30 calendar days to determine if the application is complete and issue, amend, or deny the pipeline permit as filed.

(e) If the Commission is satisfied from the application and the documentation and information provided in support thereof, and its own review, that the proposed line is, or will be laid, equipped, managed and operated in accordance with the laws of the state and the rules and regulations of the Commission, the permit may be granted. The pipeline permit, if granted, shall classify the pipeline as a common carrier, a gas utility, or a private pipeline based upon the information and documentation submitted by the applicant and the Commission's review of the application.

(f) This rule applies to applications made for new pipeline permits and to amendments, renewals, and cancellations of existing pipeline permits. The classification of a pipeline under this rule applies to extensions, replacements, and relocations of that pipeline.

(g) The Commission may delegate the authority to administratively issue pipeline permits.

(h) The pipeline permit, if granted, shall be revocable at any time after a hearing, held after 10 days' notice, if the Commission finds that the pipeline is not being operated in accordance with the laws of the state and the rules and regulations of the Commission including if the permit is not renewed annually as required in subsection (a) of this section.

(i) Each pipeline operator shall pay an annual fee based on the pipeline operator's permitted mileage of pipeline by August 31, 2018, for the initial year that the requirement is in effect, and by April 1 for each subsequent year.

(1) For purposes of calculating the mileage fee, the Commission will categorize pipelines into two groups.

(A) Group A includes transmission and gathering pipelines that are required by Commission rules to have a valid T-4 permit to operate and are subject to the regulations in 49 CFR Parts 192 and 195, such as [. Group A pipelines include] natural gas transmission and storage pipelines, natural gas gathering pipelines, hazardous liquids transmission and storage pipelines, and hazardous liquids gathering pipelines.

(B) Group B includes [gathering] pipelines that are required by Commission rules to have a valid T-4 permit to operate but are not subject to the regulations in 49 CFR Parts 192 and 195 such as [. Group B pipelines include intrastate production and] gathering pipelines [leaving a lease]. Group B also includes gathering pipelines required to comply with §8.110 of this title (relating to Gathering Pipelines).

(2) An operator of a Group A pipeline shall pay an annual fee of $20 per mile of pipeline based on the number of miles permitted to that operator as of June 29, 2018, for the initial year that the requirement is in effect and as of December 31 for each subsequent year.

(3) An operator of a Group B pipeline shall pay an annual fee of $10 per mile of pipeline based on the number of miles permitted to that operator as of June 29, 2018, for the initial year that the requirement is in effect and as of December 31 for each subsequent year.

(4) Any pipeline distance that is a fraction of a mile will be considered as one mile and will be assessed a $20 or $10 fee, as appropriate.

(5) Fees due to the Commission for mileage transferred from one operator to another operator pursuant to subsection (o) [(m)] of this section will be captured in the next mileage fee to be calculated on the following December 31 and paid by the new operator.

(j) Beginning October 1, 2018, each pipeline operator shall pay a $500 permit processing fee for each new permit application and permit renewal.

(1) From October 1, 2018, to August 31, 2020, the [The] permit renewal date for a pipeline operator who has an existing, valid permit in the Commission's online filing system will be the date shown in the online filing system on June 29, 2018, when the pipeline mileage is calculated for purposes of paying the mileage fee. A permit renewal date will not be affected or changed by an operator requesting or receiving a permit amendment.

(2) Beginning September 1, 2020, operators shall file their annual renewals as follows:

(A) Companies with names beginning with letters A through C shall file in February;

(B) Companies with names beginning with letters D through E shall file in March;

(C) Companies with names beginning with letters F through L shall file in April;

(D) Companies with names beginning with letters M through P shall file in May;

(E) Companies with names beginning with letters Q through T shall file in June; and

(F) Companies with names beginning with letters U through Z and companies with names beginning with numerical values or other symbols shall file in July.

(k) Beginning September 1, 2020, operators shall comply with the following:

(1) If a permit is transferred, in the Commission fiscal year of the transfer the acquiring operator shall renew that permit in its designated month pursuant to subsection (j)(2) of this section. If the acquiring operator receives a transferred permit in a Commission fiscal year and its renewal month has already passed, the acquiring operator shall pay the renewal fee upon transfer.

(2) If an operator adds a new permit and pays the new permit fee, the operator is not required to pay the renewal fee for that permit in the same Commission fiscal year.

(3) If an operator adds a new permit after its renewal month has passed, the new permit shall be renewed the following Commission fiscal year in the operator's designated month pursuant to subsection (j)(2) of this section.

(l) [(k)] A pipeline operator who fails to renew a permit on or before the renewal deadline which is the last day of the operator's required filing month as specified in subsection (j) of this section [permit expiration date] shall pay a late-filing fee as follows:

(1) $250, if the renewal application is received within 30 calendar days after the renewal deadline [expiration] date;

(2) $500, if the renewal application is received more than 30 calendar days and no more than 60 calendar days after the renewal deadline [expiration] date; and

(3) $700, if the renewal application is received more than 60 calendar days after the renewal deadline [expiration] date.

(4) If the renewal application is not received within 90 calendar days of the renewal deadline [expiration] date, the Commission may assess a penalty and/or revoke the operator's permit in accordance with subsection (h) of this section.

(m) A pipeline operator with a total mileage of 50 miles or less of pipeline who fails to pay the annual mileage fee as specified in subsection (i) of this section shall pay a late-filing fee as follows:

(1) $125, if the fee is received within 30 calendar days of April 1;

(2) $250, if the fee is received more than 30 calendar days and no more than 60 calendar days after April 1; and

(3) $350, if the fee is received more than 60 calendar days after April 1.

(4) If the fee is not received within 90 calendar days of April 1, the Commission may assess a penalty and/or revoke the operator's permit in accordance with subsection (h) of this section.

(n) [(l)] A pipeline operator with a total mileage of more than 50 miles of pipeline who fails to pay the annual mileage fee shall pay a late-filing fee as follows:

(1) $250, if the fee is received within 30 calendar days of August 31 for the initial year that the requirement is in effect and April 1 for each subsequent year;

(2) $500, if the fee is received more than 30 calendar days and no more than 60 calendar days after August 31 for the initial year that the requirement is in effect and April 1 for each subsequent year; and

(3) $700, if the fee is received more than 60 calendar days after August 31 for the initial year that the requirement is in effect and April 1 for each subsequent year.

(4) If the fee is not received within 90 calendar days of August 31 for the initial year that the requirement is in effect or April 1 for each subsequent year, the Commission may assess a penalty and/or revoke the operator's permit in accordance with subsection (h) of this section.

(o) [(m)] A pipeline operator who has been issued a permit and is transferring the pipeline or a portion of the pipeline included on the permit to another operator shall file a notification of transfer with the Commission within 30 days following the transfer. An operator may file a fully executed Form T-4B as a notification of transfer. The Commission may use a fully executed Form T-4B to remove the pipeline that is the subject of the transfer from the transferor operator and assign the mileage to the transferee operator for calculation of the annual mileage fee. The operator to which the pipeline has been transferred shall amend its permit to include the pipeline or portion of the pipeline within 30 days following the transfer or the operator may be subject to a penalty for operating without a permit pursuant to subsection (p) [(n)] of this section.

(p) [(n)] A pipeline operator who operates a pipeline without a permit, with an expired permit, or who otherwise fails to comply with this section, may be assessed a penalty as prescribed in §8.135 of this title[,] (relating to Penalty Guidelines for Pipeline Safety Violations) relating to Penalty Guidelines for Pipeline Safety Violations.

(q) [(o)] Interstate pipelines are exempt from the fee requirements of this section.

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

Filed with the Office of the Secretary of State on October 1, 2019.

TRD-201903543

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: November 17, 2019

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


CHAPTER 8. PIPELINE SAFETY REGULATIONS

The Railroad Commission of Texas (Commission) proposes amendments in Subchapter A to §8.1 and §8.5, relating to General Applicability and Standards, and Definitions; in Subchapter B to §§8.101, 8.115, 8.125 and 8.135, relating to Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines, New Construction Commencement Report, Waiver Procedure, and Penalty Guidelines for Pipeline Safety Violations; in Subchapter C to §§8.201, 8.205, 8.206, 8.209, 8.210, 8.225, 8.230, 8.235, and 8.240, relating to Pipeline Safety and Regulatory Program Fees, Written Procedure for Handling Natural Gas Leak Complaints, Risk-Based Leak Survey Program, Distribution Facilities Replacements, Reports, Plastic Pipe Requirements, School Piping Testing, Natural Gas Pipelines Public Education and Liaison, and Discontinuance of Service, including one change in the title of Subchapter C; in Subchapter D to §8.301 and §8.315 relating to Required Records and Reporting, and Hazardous Liquids and Carbon Dioxide Pipelines or Pipeline Facilities Located Within 1,000 Feet of a Public School Building or Facility. The Commission also proposes new §8.110, relating to Gathering Pipelines, in Subchapter B.

The proposed amendments include non-substantive clarifications and corrections in the following sections. Proposed amendments in §8.1(d), §8.210, §8.235, §8.301, and §8.315 would require an operator to retain copies of United States Department of Transportation (DOT) or certain other filings and provide copies to the Commission only upon request. In §8.5, proposed amendments to the definitions of "applicant," "director," and "division" correct the name of the Commission's division; proposed amendments in §8.201 and §8.209 also correct the division name. Proposed amendments in §8.125(g) and (h) clarify references to the Hearings Division and orders. A proposed amendment in §8.230 corrects a statutory reference. Proposed amendments in §8.301 clarify accident reporting and other existing wording.

The Commission proposes the amendment in §8.1(b) to update the minimum safety standards and to adopt by reference the DOT pipeline safety standards found in 49 CFR Part 192, Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards. Current subsection (b) adopted the federal pipeline safety standards as of October 31, 2017. The proposed amendment amends the date to January 22, 2019, to capture the federal safety rule amendment summarized in the following paragraph.

Docket No. PHMSA-2014-0098: Amdt. No. 192-124, amended the Federal Pipeline Safety Regulations that govern the use of plastic piping systems in the transportation of natural and other gas. These amendments are necessary to enhance pipeline safety, adopt innovative technologies and best practices, and respond to petitions from stakeholders. The changes include increasing the design factor of polyethylene pipe; increasing the maximum pressure and diameter for Polyamide-11 pipe and components; allowing the use of Polyamide-12 pipe and components; new standards for risers, more stringent standards for plastic fittings and joints; stronger mechanical fitting requirements; the incorporation by reference of certain new or updated consensus standards for pipe, fittings, and other components; the qualification of procedures and personnel for joining plastic pipe; the installation of plastic pipe; and a number of general provisions. The effective date of these amendments is January 22, 2019.

As described in the following paragraphs, other proposed amendments align Commission rules with federal regulations adopted by the Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA provides funding for state pipeline safety programs as long as those programs comply with PHMSA's minimum standards. Some of the amendments to Chapter 8 are proposed to ensure Texas complies with those minimum standards and retains PHMSA funding.

Some proposed amendments change the term "natural gas" to "gas" to clarify that propane gas distribution systems must also comply with requirements for distribution systems. These proposed amendments in §8.5 include the definitions for "master metered system," "natural gas or other gas supplier," "person responsible for a school facility," and "school facility". Amendments are also proposed in §8.5 to align the definition of "private school" with the definition provided in the Texas Education Code. Proposed amendments in §8.205 also change the term "natural gas" to "gas", and the title of Subchapter C includes a corresponding change.

The proposed amendments in §8.101(b)(1)(C)(iii) would delete the director approval requirement for direct assessment and make other non-substantive corrections. Director approval for direct assessment is no longer needed because there is now a National Association of Corrosion Engineers (NACE) standard for direct assessment which was not available when §8.101 was originally adopted. A related change removes a request to use the direct assessment method from the definition of "applicant" in §8.1(2). A proposed change to §8.101(e) removes outdated language.

Proposed new rule §8.110 would implement certain Commission jurisdiction over gathering pipelines in Class 1 locations and rural areas, which was granted by the legislature in House Bill 2982 during the 83rd Legislative Session. Specifically, House Bill 2982 granted the Commission authority to establish safety standards and practices for gas gathering pipelines and facilities in Class 1 locations and hazardous liquids and carbon dioxide gathering pipelines and facilities in rural areas. House Bill 2982 mandated that, for the first two years the statutes were in effect, the Commission could only implement the changes to provide a process for the Commission to investigate an accident, an incident, a threat to public safety, or a complaint, and to require an operator to submit a plan to remediate the same.

As a result, since September 1, 2013, the Commission has been investigating incidents and accidents on Class 1 gathering lines and rural gathering lines and responding to complaints and other threats to the public. However, the Commission did not have regulations requiring reporting during this time. As a direct result of its investigation and response efforts, the Commission has recognized the need to compile more accurate and complete information regarding the incidents and accidents that are occurring on gathering systems located in Class 1 locations and rural areas.

The rules adopted by the Commission pursuant to House Bill 2982 must be based on the risks the transportation and facilities present to the public safety. Proposed §8.110(a) defines the scope of the proposed rule. Proposed §8.110(b) requires an operator of a gathering line in a Class 1 location or rural area as defined in proposed subsection (a) to operate its pipeline in a reasonably prudent manner to promote safe operation of the pipeline. Proposed §8.110(c) requires operators subject to the proposed rule to report incidents and accidents to the Commission pursuant to the Commission's reporting requirements. Proposed subsection (d) requires operators to conduct an investigation after an incident or accident and cooperate with the Commission during the Commission's investigation. Proposed subsection (e) allows the Commission to require the operator to submit a corrective action plan to remediate an accident, incident, threat to the public, or complaint. The proposed reporting, investigation, and corrective action requirements will allow the Commission to gather accurate data and analyze any trends in incident or accident occurrences. This will allow the Commission to more thoroughly assess the risks gathering lines in Class 1 locations and rural areas present to the public safety.

Proposed amendments in §8.115 would amend the time period during which each operator must notify the Commission regarding the construction of pipelines and other facilities. For construction of 10 or more miles of a new, relocated, or replacement pipeline, the operator shall notify the Commission not later than 60 days before construction, which aligns with current PHMSA requirements. The 60-day requirement applies to all pipeline operators, including gas distribution companies, master meter systems, and liquified petroleum gas distribution companies. For construction of one or more but less than 10 miles of a new, relocated, or replacement pipeline (excluding gas distribution companies, master meter systems, and liquified petroleum gas distribution companies), an operator shall notify the Commission not later than 30 days before construction.

The Commission proposes different requirements for new construction, relocations, or replacements less than 10 miles in length on natural gas distribution systems, liquified petroleum gas distribution systems, and master meter systems. For 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. For relocated or replacement construction on natural gas distribution systems, liquified petroleum gas distribution systems, or master meter systems three or more miles in length but less than 10 miles in length, in lieu of notifying the Commission 30 days prior to construction, an operator may 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 the project, the city and county of location, a description of the project, and the estimated commencement date and end date. The proposed amendments also provide the option for providing a monthly report for the initial construction of a new liquefied petroleum gas distribution system, natural gas distribution system, or master meter system less than 10 miles in length. The option to file a monthly report will reduce the large number of reports that would be required for large distribution operators who replace and relocate lines often, while still giving small distribution operators the flexibility to simply file a construction report. Proposed §8.115 also requires notification of the installation of any breakout tank.

Proposed amendments to §8.115 still contain the requirement that the construction report be filed with the Commission on a Form PS-48. The proposed amendments also clarify that if notification is not feasible because of an emergency, an operator must notify the Commission as soon as practicable. Furthermore, the proposed amendments specify that construction reports will be valid for a period of eight months from the time they are filed with the Commission. If construction is not commenced during that eight-month period, the construction report expires and the operator must file a new report. In the alternative, operators may request one six-month extension on the original construction report. Operators may submit their request for extension to safety@rrc.texas.gov before the original construction report expires. The expiration date and limited renewal is proposed to ensure that the Commission has accurate records. The Commission has authority to conduct new construction inspections, and for planning purposes and efficient use of state resources it is important for the Pipeline Safety Department to have accurate records regarding when construction is set to commence.

Proposed amendments in §8.125(a) and (g)(2) clarify that an operator must request a waiver and before the operator engages in the activities covered by the proposed waiver.

Proposed amendments in §8.135 include clarifications to the tables for penalty guidelines and penalty worksheet in order to include subparts from 49 CFR Parts 192 and 195 that are not currently addressed, as well as include penalties for violations of proposed §8.110. The proposed amendments also revise the statutory reference for the Commission's penalty jurisdiction over pipeline safety violations since House Bill 866 (86th Legislature) expands the authority under which the Commission may assess an administrative penalty for pipeline safety violations.

Proposed amendments in §8.206 remove dates that have passed and, therefore, are no longer applicable. The proposed amendments in §8.206(c) and (f) also add an additional three months in which to comply with each deadline prescribed by the rule, which is consistent with federal requirements.

Proposed amendments in §8.209 remove dates that have passed and, therefore, are no longer applicable. For example, the Commission proposes to delete subsection (f)(1) because there are no longer priority 1 lines that meet the criteria in that provision or that could be replaced by that date. The proposed amendments in §8.209(h) also implement House Bill 866 from the 86th Legislative Session, which would require operators to annually remove or replace at least eight percent of underground distribution gas pipeline facilities posing the greatest risk in the system and identified for replacement under the program. Eight percent is an increase from the current requirement of five percent. The proposed amendments in new subsection (k) also implement House Bill 866 and prohibit a distribution gas pipeline facility operator from installing cast iron, wrought iron, or bare steel pipelines in its underground system. Any known existing cast iron pipelines are required to be replaced by December 31, 2021.

Proposed amendments in §8.210 implement House Bill 864 from the 86th Legislative Session. These amendments require the telephonic report to be due at the earliest practical moment, but at the latest one hour following confirmed discovery of a pipeline leak or incident. One hour is also the current PHMSA reporting requirement. Other amendments proposed to implement House Bill 864 include a requirement to submit an additional report to the Commission when more information is known by distribution operators and a requirement in proposed subsection (e) that the Commission retain pipeline incident records perpetually. The proposed amendments also eliminate the requirement for operators to submit written DOT incident forms and annual reports to the Commission and instead require operators to retain them and provide them to the Commission upon request.

A proposed amendment in §8.210(e) deletes references to a regulated plastic gas gathering line and a plastic gas transmission line from the requirement for reporting repaired leaks to the Division.

The proposed amendments in §8.225 delete most of the current wording now covered by Distribution Integrity Management Program (DIMP) requirements and adds that operators shall retain all records relating to plastic pipe installation in accordance with 49 CFR Part 192 and provide such records to the Commission upon request.

Proposed new wording in §8.240 would add requirements for "soft close" programs to be utilized by distribution operators for certain customer accounts in certain short-term situations. Allowing soft-close procedures would allow distribution operators and customers an easy transition from one customer to another.

Proposed amendments in §8.301 clarify that the telephonic report for accidents involving crude oil is due at the earliest practical moment, but at the latest one hour following confirmed discovery of a pipeline accident. One hour is also the current PHMSA reporting requirement. The proposed amendments also eliminate the requirement for operators to submit written Department of Transportation incident forms and annual reports to the Commission and instead requires operators to retain them and provide them to the Commission upon request.

Kari French, Director, Oversight and Safety Division, has determined that for the first five years the new rule and amendments will be in effect, there will be no fiscal implications for the state government as a result of enforcing or administering the proposed new rule and amendments. The Commission can cover any costs using its existing resources and budget. There will be a fiscal impact on local governments as municipalities will be required to comply with the requirements imposed by House Bill 866. However, municipalities' pipeline systems average 55 miles in length. Thus, removing or replacing an average of 4 miles of pipeline per year (eight percent of the system average) would comply with the requirements imposed by House Bill 866.

There is anticipated cost for persons required to comply with the proposed amendments. The proposed amendments to §8.115(d) would require construction filings for breakout tanks that are currently exempt from the filing requirement. However, this cost may be offset by proposed amendments to §§8.225, 8.235, and 8.315 that eliminate periodic filings for plastic pipe inventory and school proximity reports. The amendments proposed to implement House Bill 866 require annual removal or replacement of at least eight percent of underground distribution gas pipeline facilities posing the greatest risk in the system and identified for replacement under the program. It is estimated that operators are already replacing seven percent, so the anticipated cost for compliance with the proposed amendments stems from the one percent increase. However, any such costs are likely to be less than the cost of a catastrophic pipeline failure that might otherwise occur.

Further, while there is an anticipated cost for persons required to comply with new §8.110, relating to Gathering Pipelines, the cost will be minimal. Operators will now be required to report incidents and accidents to the Commission and cooperate with the Commission's investigation of the incident or accident. The operator must also conduct its own investigation. Cost incurrence will vary for each operator.

Ms. French has determined that for each year of the first five years that the new rule and amendments will be in effect, the primary public benefit will be consistency with federal requirements and state statutes, removal of redundant requirements, and updated Commission department names, lessening the potential for confusion. Further, the changes prompted by House Bill 866 would require operators to replace more of their aging infrastructure, helping prevent incidents that may harm the public. Similarly, implementing reporting requirements for Class 1 and rural gathering lines would help the Commission compile accurate information regarding incidents and accidents so that the Commission can adopt safety regulations pursuant to House Bill 2982 to prevent risks to the public safety.

The Commission has determined that the new rule and proposed amendments will not have an adverse economic effect on rural communities, small businesses or micro-businesses. Costs incurred to comply with new §8.110 will vary by operator; however, as noted above, any costs of compliance are likely to be less than the cost of a catastrophic pipeline failure that might otherwise occur. Further, as smaller pipeline operators are likely to have a lower number of pipelines, the overall cost to a smaller operator should be less. Any additional cost for persons required to comply with the proposed amendments to §8.115 will likely be offset by proposed amendments to §§8.225, 8.235, and 8.315. Therefore, the Commission has not prepared the economic impact statement or the regulatory flexibility analysis pursuant to Texas Government Code §2006.002.

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

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

During the first five years that the rules would be in effect, the proposed new rule and amendments would not: create or eliminate a government program; create or eliminate any employee positions; require an increase or decrease in future legislative appropriations; increase or decrease the amount of fees paid to the agency; expand, limit, or repeal an existing regulation; or affect the state's economy. The proposed new rule would create a new regulation and increase the number of individuals subject to the rule's applicability. As noted above, the proposed new regulation, §8.110, would apply to operators and pipelines that have not previously been regulated by the Commission. The proposed amendments also implement recent statutory requirements, ensure consistency with federal requirements, clarify existing Commission requirements, remove requirements that have been incorporated into federal programs, and update Commission department names.

Comments on the proposal may be submitted to Rules Coordinator, Office of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711-2967; online at www.rrc.texas.gov/general-counsel/rules/comment-form-for-proposed-rulemakings; or by electronic mail to rulescoordinator@rrc.texas.gov. The Commission will accept comments until noon (12:00 p.m.), on Monday, November 18, 2019. The Commission finds that this comment period is reasonable because the proposal and an online comment form will be available on the Commission's web site more than two weeks prior to Texas Register publication of the proposal, giving interested persons additional time to review, analyze, draft, and submit comments. The Commission encourages all interested persons to submit comments no later than the deadline. The Commission cannot guarantee that comments submitted after the deadline will be considered. For further information, call Ms. French at (512) 463-8559. The status of Commission rulemakings in progress is available at www.rrc.texas.gov/general-counsel/rules/proposed-rules.

SUBCHAPTER A. GENERAL REQUIREMENTS AND DEFINITIONS

16 TAC §8.1, §8.5

Statutory Authority: The Commission proposes 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, §§121.201-121.211, 121.213-121.214; §121.251 and §121.253, §§121.5005-121.507; 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.

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 pipeline and gathering and production facilities, beginning after the first point of measurement and ending as defined by 49 CFR Part 192 as the beginning of an onshore gathering line. The gathering and production beyond this first point of measurement shall be subject to 49 CFR §192.8 [Part 192.8] and shall be subject to the rules as defined as Type A or Type B gathering lines as those Class 2, 3, or 4 areas as defined by 49 CFR §192.5 [Part 192.5];

(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.

(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 January 22, 2019 [October 30, 2017].

(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 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 [Concurrent filing]. 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 [file] 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 [with the Pipeline Safety Division].

(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;

(C) to establish an MAOP (49 CFR 192.619), March 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.

§8.5.Definitions.

In addition to the definitions given in 49 CFR Parts 40, 191, 192, 193, 195, and 199, the following words and terms, when used in this chapter, shall have the following meanings, unless the context clearly indicates otherwise.

(1) Affected person--This definition of this term applies only to the procedures and requirements of §8.125 of this title (relating to Waiver Procedure). The term includes but is not limited to:

(A) persons owning or occupying real property within 500 feet of any property line of the site for the facility or operation for which the waiver is sought;

(B) the city council, as represented by the city attorney, the city secretary, the city manager, or the mayor, if the property that is the site of the facility or operation for which the waiver is sought is located wholly or partly within any incorporated municipal boundaries, including the extraterritorial jurisdiction of any incorporated municipality. If the site of the facility or operation for which the waiver is sought is located within more than one incorporated municipality, then the city council of every incorporated municipality within which the site is located is an affected person;

(C) the county commission, as represented by the county clerk, if the property that is the site of the facility or operation for which the waiver is sought is located wholly or partly outside the boundary of any incorporated municipality. If the site of the facility or operation for which the waiver is sought is located within more than one county, then the county commission of every county within which the site is located is an affected person;

(D) any other person who would be impacted by the waiver sought.

(2) Applicant--A person who has filed with the Oversight and Safety Division [Pipeline Safety Division] , Pipeline Safety Department, a complete application for a waiver to a pipeline safety rule or regulation, or a request to use [direct assessment or] other technology or assessment methodology not specifically listed in §8.101(b)(1)[,] of this title (relating to Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines).

(3) Application for waiver--The written request, including all reasons and all appropriate documentation, for the waiver of a particular rule or regulation with respect to a specific facility or operation.

(4) Charter school--An elementary or secondary school operated by an entity created pursuant to Texas Education Code, Chapter 12.

(5) Commission--The Railroad Commission of Texas.

(6) Direct assessment--A structured process that identifies locations where a pipeline may be physically examined to provide assessment of pipeline integrity. The process includes collection, analysis, assessment, and integration of data, including but not limited to the items listed in §8.101(b)(1) of this title [, relating to Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines]. The physical examination may include coating examination and other applicable non-destructive evaluation.

(7) Director--The director of the Oversight and [Pipeline] Safety Division or the director's delegate.

(8) Division--The Oversight and [Pipeline] Safety Division of the Commission.

(9) Farm tap odorizer--A wick-type odorizer serving a consumer or consumers off any pipeline other than that classified as distribution as defined in 49 CFR 192.3 which uses not more than 10 mcf on an average day in any month.

(10) Gas--Natural gas, flammable gas, or other gas which is toxic or corrosive.

(11) Gas company--Any person who owns or operates pipeline facilities used for the transportation or distribution of gas, including master metered systems.

(12) Hazardous liquid--Petroleum, petroleum products, anhydrous ammonia, or any substance or material which is in liquid state, excluding liquefied natural gas (LNG), when transported by pipeline facilities and which has been determined by the United States Secretary of Transportation to pose an unreasonable risk to life or property when transported by pipeline facilities.

(13) In-line inspection--An internal inspection by a tool capable of detecting anomalies in pipeline walls such as corrosion, metal loss, or deformation.

(14) Intrastate pipeline facilities--Pipeline facilities located within the State of Texas which are not used for the transportation of natural gas or hazardous liquids or carbon dioxide in interstate or foreign commerce.

(15) Lease user--A consumer who receives free gas in a contractual agreement with a pipeline operator or producer.

(16) Liquids company--Any person who owns or operates a pipeline or pipelines and/or pipeline facilities used for the transportation or distribution of any hazardous liquid, or carbon dioxide, or anhydrous ammonia.

(17) Master meter operator--The owner, operator, or manager of a master metered system.

(18) Master metered system--A pipeline system (other than one designated as a local distribution system) for distributing [natural] gas within but not limited to a definable area, such as a mobile home park, housing project, or apartment complex, where the operator purchases metered gas from an outside source for resale through a gas distribution pipeline system. The gas distribution pipeline system supplies the ultimate consumer who either purchases the gas directly through a meter or by other means such as rents.

(19) Natural gas or other gas supplier--The entity selling and delivering [the natural] gas to a school facility or a master metered system. If more than one entity sells and delivers [natural] gas to a school facility or master metered system, each entity is a [natural] gas supplier for purposes of this chapter.

(20) Operator--A person who operates on his or her own behalf, or as an agent designated by the owner, intrastate pipeline facilities.

(21) Person--Any individual, firm, joint venture, partnership, corporation, association, cooperative association, joint stock association, trust, or any other business entity, including any trustee, receiver, assignee, or personal representative thereof, a state agency or institution, a county, a municipality, or school district or any other governmental subdivision of this state.

(22) Person responsible for a school facility--In the case of a public school, the superintendent of the school district as defined in Texas Education Code, §11.201, or the superintendent's designee previously specified in writing to the [natural] gas supplier. In the case of charter and private schools, the principal of the school or the principal's designee previously specified in writing to the [natural] gas supplier.

(23) Pipeline facilities--New and existing pipe, right-of-way, and any equipment, facility, or building used or intended for use in the transportation of gas or hazardous liquid or their treatment during the course of transportation.

(24) Pressure test--Those techniques and methodologies prescribed for leak-test and strength-test requirements for pipelines. For natural gas pipelines, including LPG distribution systems and master metered systems, the requirements are found in 49 Code of Federal Regulations (CFR) Part 192, and specifically include 49 CFR 192.505, 192.507, 192.515, and 192.517. For hazardous liquids pipelines, the requirements are found in 49 CFR Part 195, and specifically include 49 CFR 195.305, 195.306, 195.308, and 195.310.

(25) Private school--A school that:

(A) offers a course of instruction for students in one or more grades from kindergarten through grade 12;

(B) is not operated by a governmental entity; and

(C) is not a home school.

[An elementary or secondary school operated by an entity accredited by the Texas Private School Accreditation Commission.]

(26) Public school--An elementary or secondary school operated by an entity created in accordance with the laws of the State of Texas and accredited by the Texas Education Agency pursuant to Texas Education Code, Chapter 39, Subchapter D. The term does not include programs and facilities under the jurisdiction of the Texas Juvenile Justice Department [Texas Department of Mental Health and Mental Retardation, the Texas Youth Commission], the Texas Health and Human Services Commission [Department of Human Services], the Texas Department of Criminal Justice or any probation agency, the Texas School for the Blind and Visually Impaired, the Texas School for the Deaf and Regional Day Schools for the Deaf, the Texas Academy of Mathematics & Science, the Texas Academy of Leadership in the Humanities, and home schools or proprietary schools as defined in Texas Education Code, §132.001.

(27) School facility--All piping, buildings and structures operated by a public, charter, or private school that are downstream of a meter measuring [natural] gas service in which students receive instruction or participate in school sponsored extracurricular activities, excluding maintenance or bus facilities, administrative offices, and similar facilities not regularly utilized by students.

(28) Transportation of gas--The gathering, transmission, or distribution of gas by pipeline or its storage within the State of Texas. For purposes of safety regulation, the term shall include onshore pipeline and production facilities, beginning after the first point of measurement and ending as defined by 49 CFR Part 192 as the beginning of an onshore gathering line.

(29) Transportation of hazardous liquids or carbon dioxide--The movement of hazardous liquids or carbon dioxide by pipeline, or their storage incidental to movement, except that, for purposes of safety regulations, it does not include any such movement through gathering lines in rural locations or production, refining, or manufacturing facilities or storage or in-plant piping systems associated with any of those facilities.

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

Filed with the Office of the Secretary of State on October 1, 2019.

TRD-201903544

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: November 17, 2019

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


SUBCHAPTER B. REQUIREMENTS FOR ALL PIPELINES

16 TAC §§8.101, 8.110, 8.115, 8.125, 8.135

Statutory Authority: The Commission proposes 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, §§121.201-121.211, 121.213-121.214; §121.251 and §121.253, §§121.5005-121.507; 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.

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.

§8.101.Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines.

(a) This section does not apply to plastic pipelines.

(b) By February 1, 2002, operators of intrastate transmission lines subject to the requirements of 49 CFR Part 192 or 49 CFR Part 195 shall have designated [to the Commission] on a system-by-system or segment within each system basis whether the pipeline operator has chosen to use the risk-based analysis pursuant to paragraph (1) of this subsection or the prescriptive plan authorized by paragraph (2) of this subsection. Hazardous liquid pipeline operators using the risk-based plan shall complete at least 50% of the initial assessments by January 1, 2006, and the remainder by January 1, 2011; operators using the prescriptive plan shall complete the initial integrity testing by January 1, 2006, or January 1, 2011, pursuant to the requirements of paragraph (2) of this subsection. Natural gas pipeline operators using the risk-based plan shall complete at least 50% of the initial assessments by December 17, 2007, and the remainder by December 17, 2012; operators using the prescriptive plan shall complete the initial integrity testing by December 17, 2007, or December 17, 2012, pursuant to the requirements of paragraph (2) of this subsection.

(1) The risk-based plan shall contain at a minimum:

(A) identification of the pipelines and pipeline segments or sections in each system covered by the plan;

(B) a priority ranking for performing the integrity assessment of pipeline segments of each system based on an analysis of risks that takes into account:

(i) population density;

(ii) immediate response area designation, which, at a minimum, means the identification of significant threats to the environment (including but not limited to air, land, and water) or to the public health or safety of the immediate response area;

(iii) pipeline configuration;

(iv) prior in-line inspection data or reports;

(v) prior pressure test data or reports;

(vi) leak and incident data or reports;

(vii) operating characteristics such as established maximum allowable operating pressures (MAOP) for gas pipelines or maximum operating pressures (MOP) for liquids pipelines, leak survey results, cathodic protection surveys, and product carried;

(viii) construction records, including at a minimum but not limited to the age of the pipe and the operating history;

(ix) pipeline specifications; and

(x) any other data that may assist in the assessment of the integrity of pipeline segments.

(C) assessment of pipeline integrity using at least one of the following methods appropriate for each segment:

(i) in-line inspection;

(ii) pressure test;

(iii) direct assessment [after approval by the director]; or

(iv) other technology or assessment methodology not specifically listed in this paragraph after approval by the director.

(D) management methods for the pipeline segments which may include remedial action or increased inspections as necessary; and

(E) periodic review of the pipeline integrity assessment and management plan every 36 months, or more frequently if necessary.

(2) Operators electing not to use the risk-based plan in paragraph (1) of this subsection shall conduct a pressure test or an in-line inspection and take remedial action in accordance with the following schedule:

Figure 1: 16 TAC §8.101(b)(2) (No change.)

Figure 2: 16 TAC §8.101(b)(2) (No change.)

(c) Within 185 days after receipt of notice that an operator's plan is complete, the Commission shall either notify the operator of the acceptance of the plan or shall complete an evaluation of the plan to determine compliance with this section.

(d) After the completion of the assessment required under either plan, the operator shall promptly remove defects that are immediate hazards and, no later than the next test interval, shall mitigate any anomalies identified by the test that could reasonably be predicted to become hazardous defects.

[(e) Operators of pipelines for which an integrity assessment was performed prior to April 30, 2001 (the effective date of this rule), shall not be required to implement a new plan as long as the original assessment meets the minimum requirements of this section.]

(e) [(f)] If a pipeline that is not subject to this section undergoes any change in circumstances that results in the pipeline becoming subject to this section, then the operator of such pipeline shall establish integrity of the pipeline pursuant to the requirements of this section prior to any further operation. Such changes include but are not limited to an addition to the pipeline, change in the operating pressure of the pipeline, change from inactive to active status, change in population in the area of the pipeline, or change of operator of the pipeline segment. If a pipeline segment is acquired by a new operator, the pipeline segment can continue to be operated without establishing pipeline integrity as long as the new operator utilizes the prior operator's operation and maintenance procedures for this pipeline segment. If the population in the area of a pipeline segment changes, the pipeline segment can continue to operate without establishing pipeline integrity until such time as the operator determines whether or not the change in population affects the criteria applicable to the integrity management program, but for no longer than the time frames established under 49 CFR Part 192 or 195.

§8.110.Gathering Pipelines.

(a) Scope. This section applies to the following gathering pipelines:

(1) natural gas gathering pipelines located in a Class 1 location not regulated by 49 CFR §192.8 or §8.1 of this title (relating to General Applicability and Standards); and

(2) hazardous liquids and carbon dioxide gathering pipelines located in a rural area as defined by 49 CFR §195.2 and not regulated by 49 CFR §195.1, 49 CFR §195.11, or §8.1 of this title.

(b) Safety. Each operator of a gathering pipeline described in subsection (a) of this section shall operate its pipeline in a reasonably prudent manner to promote safe operation of the pipeline.

(c) Reporting.

(1) Each operator of a gas gathering pipeline described in subsection (a) of this section shall comply with §8.210(a) of this title (relating to Reports).

(2) Each operator of a hazardous liquids pipeline described in subsection (a) of this section shall comply with §8.301(a) of this title (relating to Required Records and Reporting).

(d) Investigation.

(1) Each operator of a gathering pipeline described in subsection (a) of this section shall conduct its own investigation and cooperate with the Commission and its authorized representatives in the investigation of any of the following:

(A) an accident as defined by 49 CFR §195.50;

(B) an incident as defined by 49 CFR §191.3;

(C) a threat to public safety; or

(D) a complaint related to operational safety.

(2) Each operator shall provide the Commission reasonable access to the operator's facilities, provide the Commission any records related to such facilities, and file such reports or other information necessary to determine whether there is a threat to the continuing safe operation of the pipeline.

(e) Corrective action and prevention of recurrence. As a result of the investigations authorized under subsection (d) of this section, the Commission may require the operator to submit a corrective action plan to the Commission to remediate an accident, incident, threat, or complaint. Upon the Commission's review and approval of the corrective action plan, the operator shall complete the corrective action. No provision of this rule prevents the operator from implementing any corrective action at any time the operator deems necessary or prudent to correct or prevent a threat to the safe operation of the gathering pipeline and pipeline facilities.

§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) Except as provided in paragraph (4) 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.

(3) For installation of any breakout tank, an operator shall notify the Commission not later than 30 days before installation.

(4) For 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. For 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 for every relocated or replacement 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.

(5) For the initial construction of a new liquefied petroleum gas distribution system, natural gas distribution system, or master meter system 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 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.

(6) 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.

(7) Pipelines subject to §8.110 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)(4) of this section, shall be made by filing [Except as set forth below, at least 30 days prior to commencement of construction of any installation totaling one mile or more of pipe, each operator shall file] with the Commission Form PS-48 [a report] stating 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 [on Form PS-48]. 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. After one extension, Form PS-48 will expire. [Each operator shall file a new construction report for the initial construction of a new liquefied petroleum gas distribution system. Each operator of a sour gas pipeline and/or pipeline facilities, as defined in §3.106(b) of this title (relating to Sour Gas Pipeline Facility Construction Permit), shall file a new construction report and Form PS-79, Application for a Permit to Construct a Sour Gas Pipeline Facility. New construction on natural gas distribution or master meter system of less than five miles is exempted from this reporting requirement.]

§8.125.Waiver Procedure.

(a) Purpose and scope. The Commission considers waiver applications to be properly based on a technical inability to comply with the pipeline safety standards set forth in this chapter, related to the specific configuration, location, operating limitations, or available technology for a particular pipeline. Generally, an application for waiver of a pipeline safety rule is site-specific. Cost is generally not a proper objection to compliance by the operator with the pipeline safety standards set forth in this chapter, and a waiver filed simply to avoid the expense of safety compliance is generally not appropriate. An operator shall request a waiver prior to performing any activities that would fall under the waiver.

(b) Filing. Any person may apply for a waiver of a pipeline safety rule or regulation by filing an application for waiver with the Division. Upon the filing of an application for waiver of a pipeline safety rule, the Division shall assign a docket number to the application and shall forward it to the director, and thereafter all documents relating to that application shall include the assigned docket number. An application for a waiver is not an acceptable response to a notice of an alleged violation of a pipeline safety rule. The Division shall not assign a docket number to or consider any application filed in response to a notice of violation of a pipeline safety rule.

(c) Form. The application shall be typewritten on paper not to exceed 8 1/2 inches by 11 inches and shall have margins of at least one inch. The contents of the application shall appear on one side of the paper and shall be double or one and one-half spaced, except that footnotes and lengthy quotations may be single spaced. Exhibits attached to an application shall be the same size as the application or folded to that size.

(d) Content. The application shall contain the following:

(1) the name, business address, and telephone number, and facsimile transmission number and electronic mail address, if available, of the applicant and of the applicant's authorized representative, if any;

(2) a description of the particular operation for which the waiver is sought;

(3) a statement concerning the regulation from which the waiver is sought and the reason for the exception;

(4) a description of the facility at which the operation is conducted, including, if necessary, design and operation specifications, monitoring and control devices, maps, calculations, and test results;

(5) a description of the acreage and/or address upon which the facility and/or operation that is the subject of the waiver request is located. The description shall:

(A) include a plat drawing;

(B) identify the site sufficiently to permit determination of property boundaries;

(C) identify environmental surroundings;

(D) identify placement of buildings and areas intended for human occupancy that could be endangered by a failure or malfunction of the facility or operation;

(E) state the ownership of the real property of the site; and

(F) state under what legal authority the applicant, if not the owner of the real property, is permitted occupancy;

(6) an identification of any increased risks the particular operation would create if the waiver were granted, and the additional safety measures that are proposed to compensate for those risks;

(7) a statement of the reason the particular operation, if the waiver were granted, would not be inconsistent with pipeline safety.

(8) an original signature, in ink, by the applicant or the applicant's authorized representative, if any; and

(9) a list of the names, addresses, and telephone numbers of all affected persons, as defined in §8.5 of this title (relating to Definitions).

(e) Notice.

(1) The applicant shall send a copy of the application and a notice of protest form published by the Commission by certified mail, return receipt requested, to all affected persons on the same date of filing the application with the Division. The notice shall describe the nature of the waiver sought; shall state that affected persons have 30 calendar days from the date of the last publication to file written objections or requests for a hearing with the Division; and shall include the docket number of the application and the mailing address of the Division. The applicant shall file all return receipts with the Division as proof of notice.

(2) The applicant shall publish notice of its application for waiver of a pipeline safety rule once a week for two consecutive weeks in the state or local news section of a newspaper of general circulation in the county or counties in which the facility or operation for which the requested waiver is located. The notice shall describe the nature of the waiver sought; shall state that affected persons have 30 calendar days from the date of the last publication to file written objections or requests for a hearing with the Division; and shall include the docket number of the application and the mailing address of the Division. Within ten calendar days of the date of last publication, the applicant shall file with the Division a publisher's affidavit from each newspaper in which notice was published as proof of publication of notice. The affidavit shall state the dates on which the notice was published and shall have attached to it the tear sheets from each edition of the newspaper in which the notice was published.

(3) The applicant shall give any other notice of the application which the director may require.

(f) Protest or support of waiver application.

(1) Affected persons shall have standing to object to, support, or request a hearing on an application.

(2) A person who objects to, who supports, or who requests a hearing on the application shall file a written objection, statement of support, or request for a hearing with the Division no later than the 30th calendar day after the date the notice of the application was postmarked or the last date the notice was published in the newspaper in the county in which the person owns or occupies property, whichever is later.

(3) The objection, statement of support, or request for a hearing shall:

(A) state the name, address, and telephone number of the person filing the objection, statement of support, or request for hearing and of every person on whose behalf the objection, statement of support, or request for a hearing is being filed;

(B) include a statement of the facts on which the person filing the protest or statement of support relies to conclude that each person on whose behalf the objection, statement of support, or request for a hearing is being filed is an affected person, as defined in §8.5 of this title [(relating to Definitions)]; and

(C) include a statement of the nature and basis for the objection to or statement of support for the waiver request.

(g) Division review.

(1) The director shall complete the review of the application within 60 calendar days after the application is complete. If an application remains incomplete 12 months after the date the application was filed, such application shall expire and the director shall dismiss without prejudice to refiling.

(A) If the director does not receive any objections or requests for a hearing from any affected person, the director may recommend in writing that the Commission grant the waiver if granting the waiver is not inconsistent with pipeline safety. The director shall forward the file, along with the written recommendation that the waiver be granted, to the Hearings Division [Office of General Counsel] for the preparation of an order.

(B) The director shall not recommend that the Commission grant the waiver if the application was filed [either] to correct an existing violation, to [or to] avoid the expense of safety compliance, or filed after the applicant already engaged in activities covered by the proposed waiver. The director shall dismiss with prejudice to refiling an application filed in response to a notice of violation of a pipeline safety rule.

(C) If the director declines to recommend that the Commission grant the waiver, the director shall notify the applicant in writing of the recommendation and the reason for it, and shall inform the applicant of any specific deficiencies in the application.

(2) If the director declines to recommend that the Commission grant the waiver, and if the application was not filed either to correct an existing violation or solely to avoid the expense of safety compliance, the applicant may either:

(A) modify the application to correct the deficiencies and resubmit the application; or

(B) file a written request for a hearing on the matter within ten calendar days of receiving notice of the assistant director's written decision not to recommend that the Commission grant the application.

(h) Hearings and orders.

(1) Within three days of receiving either a timely-filed objection or a request for a hearing, the director shall forward the file to the Hearings Division, which shall set and conduct the hearing in accordance with Chapter 1 of this title (relating to Practice and Procedure) [Office of General Counsel for the setting of a hearing].

[(2) Within three days of receiving the file, the Office of General Counsel shall assign a presiding examiner to conduct a hearing as soon as practicable.]

[(3) The presiding examiner shall mail notice of the hearing by certified mail, return receipt requested, not less than 30 calendar days prior to the date of the hearing to:]

[(A) the applicant;]

[(B) all persons who filed an objection or a request for a hearing; and]

[(C) all other affected persons.]

[(4) The presiding examiner shall conduct the hearing in accordance with the procedural requirements of Texas Government Code, Chapter 2001 (the Administrative Procedure Act), and Chapter 1 of this title (relating to Practice and Procedure).]

(2) [(i)] [Finding requirement. ] After a hearing, the Commission may grant a waiver of a pipeline safety rule based on a finding or findings in the order that the grant of the waiver is not inconsistent with pipeline safety.

(i) [(j)] Notice to United States Department of Transportation. Upon a Commission order granting a waiver of a pipeline safety rule, the director shall give written notice to the Secretary of Transportation pursuant to the provisions of 49 United States Code Annotated, §60118(d). The Commission's grant of a waiver becomes effective in accordance with the provisions of 49 United States Code Annotated, §60118(d).

§8.135.Penalty Guidelines for Pipeline Safety Violations.

(a) Policy. Improved safety and environmental protection are the desired outcomes of any enforcement action. Encouraging operators to take appropriate voluntary corrective and future protective actions once a violation has occurred is an effective component of the enforcement process. Deterrence of violations through penalty assessments is also a necessary and effective component of the enforcement process. A rule-based enforcement penalty guideline to evaluate and rank pipeline safety-related violations is consistent with the central goal of the Commission's enforcement efforts to promote compliance. Penalty guidelines set forth in this section will provide a framework for more uniform and equitable assessment of penalties throughout the state, while also enhancing the integrity of the Commission's enforcement program.

(b) Only guidelines. This section complies with the requirements of Texas Natural Resources Code, §81.0531(d), and Texas Utilities Code, §121.206(d). The penalty amounts contained in the tables in this section are provided solely as guidelines to be considered by the Commission in determining the amount of administrative penalties for violations of provisions of Texas Natural Resources Code, Title 3, relating to pipeline safety, or of rules, orders or permits relating to pipeline safety adopted under those provisions, and for violations of Texas Utilities Code, Chapter 121, Subchapter E [§121.201], or a safety standard or other rule prescribed or adopted under that [provision] subchapter.

(c) Commission authority. The establishment of these penalty guidelines shall in no way limit the Commission's authority and discretion to cite violations and assess administrative penalties. The typical minimum penalties listed in this section are for the most common violations cited; however, this is neither an exclusive nor an exhaustive list of violations that the Commission may cite. The Commission retains full authority and discretion to cite violations of Texas Natural Resources Code, Title 3, relating to pipeline safety, or of rules, orders, or permits relating to pipeline safety adopted under those provisions, and for violations of Texas Utilities Code, Chapter 121, Subchapter E [§121.201], or a safety standard or other rule prescribed or adopted under that subchapter [provision], and to assess administrative penalties in any amount up to the statutory maximum when warranted by the facts in any case, regardless of inclusion in or omission from this section.

(d) Factors considered. The amount of any penalty requested, recommended, or finally assessed in an enforcement action will be determined on an individual case-by-case basis for each violation, taking into consideration the following factors:

(1) the person's history of previous violations, including the number of previous violations;

(2) the seriousness of the violation and of any pollution resulting from the violation;

(3) any hazard to the health or safety of the public;

(4) the degree of culpability;

(5) the demonstrated good faith of the person charged; and

(6) any other factor the Commission considers relevant.

(e) Typical penalties. Typical penalties for violations of provisions of Texas Natural Resources Code, Title 3, relating to pipeline safety, or of rules, orders, or permits relating to pipeline safety adopted under those provisions, and for violations of Texas Utilities Code, §121.201, or a safety standard or other rule prescribed or adopted under that provision are set forth in Table 1.

Figure: 16 TAC §8.135(e) (.pdf)

[Figure: 16 TAC §8.135(e)]

(f) Penalty enhancements for certain violations. For violations that involve threatened or actual pollution; result in threatened or actual safety hazards; or result from the reckless or intentional conduct of the person charged, the Commission may assess an enhancement of the typical penalty, as shown in Table 2. The enhancement may be in any amount in the range shown for each type of violation.

Figure: 16 TAC §8.135(f) (No change.)

(g) Penalty enhancements for certain violators. For violations in which the person charged has a history of prior violations within seven years of the current enforcement action, the Commission may assess an enhancement based on either the number of prior violations or the total amount of previous administrative penalties, but not both. The actual amount of any penalty enhancement will be determined on an individual case-by-case basis for each violation. The guidelines in Tables 3 and 4 are intended to be used separately. Either guideline may be used where applicable, but not both.

Figure 1: 16 TAC §8.135(g) (No change.)

Figure 2: 16 TAC §8.135(g) (No change.)

(h) Penalty reduction for settlement before hearing. The recommended penalty for a violation may be reduced by up to 50% if the person charged agrees to a settlement before the Commission conducts an administrative hearing to prosecute a violation. Once the hearing is convened, the opportunity for the person charged to reduce the basic monetary penalty is no longer available. The reduction applies to the basic penalty amount requested and not to any requested enhancements.

(i) Demonstrated good faith. In determining the total amount of any penalty requested, recommended, or finally assessed in an enforcement action, the Commission may consider, on an individual case-by-case basis for each violation, the demonstrated good faith of the person charged. Demonstrated good faith includes, but is not limited to, actions taken by the person charged before the filing of an enforcement action to remedy, in whole or in part, a violation or to mitigate the consequences of a violation.

(j) Penalty calculation worksheet. The penalty calculation worksheet shown in Table 5 lists the typical penalty amounts for certain violations; the circumstances justifying enhancements of a penalty and the amount of the enhancement; and the circumstances justifying a reduction in a penalty and the amount of the reduction.

Figure: 16 TAC §8.135(j) (.pdf)

[Figure: 16 TAC §8.135(j)]

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

Filed with the Office of the Secretary of State on October 1, 2019.

TRD-201903545

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: November 17, 2019

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


SUBCHAPTER C. REQUIREMENTS FOR NATURAL GAS PIPELINES ONLY

16 TAC §§8.201, 8.205, 8.206, 8.209, 8.210, 8.225, 8.230, 8.235, 8.240

Statutory Authority: The Commission proposes 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, §§121.201-121.211, 121.213-121.214; §121.251 and §121.253, §§121.5005-121.507; 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.

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.

§8.201.Pipeline Safety and Regulatory Program Fees.

(a) Application of fees. Pursuant to Texas Utilities Code, §121.211, the Commission establishes a pipeline safety and regulatory program fee, to be assessed annually against operators of natural gas distribution pipelines and pipeline facilities and natural gas master metered pipelines and pipeline facilities subject to the Commission's jurisdiction under Texas Utilities Code, Title 3. The total amount of revenue estimated to be collected under this section does not exceed the amount the Commission estimates to be necessary to recover the costs of administering the pipeline safety and regulatory programs under Texas Utilities Code, Title 3, excluding costs that are fully funded by federal sources for any fiscal year.

(b) Natural gas distribution systems. The Commission hereby assesses each operator of a natural gas distribution system an annual pipeline safety and regulatory program fee of $1.00 for each service (service line) in service at the end of each calendar year as reported by each system operator on the U.S. Department of Transportation (DOT) Gas Distribution Annual Report, Form PHMSA F7100.1-1 due on March 15 of each year.

(1) Each operator of a natural gas distribution system shall calculate the annual pipeline safety and regulatory program total to be paid to the Commission by multiplying the $1.00 fee by the number of services listed in Part B, Section 3, of Form PHMSA F7100.1-1, due on March 15 of each year.

(2) Each operator of a natural gas distribution system shall remit to the Commission on March 15 of each year the amount calculated under paragraph (1) of this subsection.

(3) Each operator of a natural gas distribution system shall recover, by a surcharge to its existing rates, the amount the operator paid to the Commission under paragraph (1) of this subsection. The surcharge:

(A) shall be a flat rate, one-time surcharge;

(B) shall not be billed before the operator remits the pipeline safety and regulatory program fee to the Commission;

(C) shall be applied in the billing cycle or cycles immediately following the date on which the operator paid the Commission;

(D) shall not exceed $1.00 per service or service line; and

(E) shall not be billed to a state agency, as that term is defined in Texas Utilities Code, §101.003.

(4) No later than 90 days after the last billing cycle in which the pipeline safety and regulatory program fee surcharge is billed to customers, each operator of a natural gas distribution system shall file with the Commission's Oversight and [Gas Services Division and the Pipeline] Safety Division a report showing:

(A) the pipeline safety and regulatory program fee amount paid to the Commission;

(B) the unit rate and total amount of the surcharge billed to each customer;

(C) the date or dates on which the surcharge was billed to customers; and

(D) the total amount collected from customers from the surcharge.

(5) Each operator of a natural gas distribution system that is a utility subject to the jurisdiction of the Commission pursuant to Texas Utilities Code, Chapters 101 - 105, shall file a generally applicable tariff for its surcharge in conformance with the requirements of §7.315 of this title[,] (relating to Filing of Tariffs) relating to Filing of Tariffs.

(6) Amounts recovered from customers under this subsection by an investor-owned natural gas distribution system or a cooperatively owned natural gas distribution system shall not be included in the revenue or gross receipts of the system for the purpose of calculating municipal franchise fees or any tax imposed under Subchapter B, Chapter 182, Tax Code, or under Chapter 122, nor shall such amounts be subject to a sales and use tax imposed by Chapter 151, Tax Code, or Subtitle C, Title 3, Tax Code.

(c) Natural gas master meter systems. The Commission hereby assesses each natural gas master meter system an annual pipeline safety and regulatory program fee of $100 per master meter system.

(1) Each operator of a natural gas master meter system shall remit to the Commission the annual pipeline safety and regulatory program fee of $100 per master meter system no later than June 30 of each year.

(2) The Commission shall send an invoice to each affected natural gas master meter system operator no later than April 30 of each year as a courtesy reminder. The failure of a natural gas master meter system operator to receive an invoice shall not exempt the natural gas master meter system operator from its obligation to remit to the Commission the annual pipeline safety and regulatory program fee on June 30 each year.

(3) Each operator of a natural gas master meter system shall recover as a surcharge to its existing rates the amounts paid to the Commission under paragraph (1) of this subsection.

(4) No later than 90 days after the last billing cycle in which the pipeline safety and regulatory program fee surcharge is billed to customers, each natural gas master meter system operator shall file with the Oversight and [Commission's Gas Services Division and the Pipeline] Safety Division a report showing:

(A) the pipeline safety and regulatory program fee amount paid to the Commission;

(B) the unit rate and total amount of the surcharge billed to each customer;

(C) the date or dates on which the surcharge was billed to customers; and

(D) the total amount collected from customers from the surcharge.

(d) Late payment penalty. If the operator of a natural gas distribution system or a natural gas master meter system does not remit payment of the annual pipeline safety and regulatory program fee to the Commission within 30 days of the due date, the Commission shall assess a late payment penalty of 10 percent of the total assessment due under subsection (b) or (c) of this section, as applicable, and shall notify the operator of the total amount due to the Commission.

§8.205.Written Procedure for Handling [Natural] Gas Leak Complaints.

Each gas company shall have written procedures which shall include at a minimum the following provisions:

(1) a procedure or method for receiving leak complaints or reports, or both, on a 24-hour, seven day per week basis;

(2) a requirement to make and maintain a written record of all calls received and actions taken;

(3) a requirement that supervisory review of leak complaints must be completed and documented by 10:00 a.m. of the next business day for calls received by midnight on the previous day;

(4) standards for training and equipping personnel used in the investigation of leak complaints or reports, or both;

(5) procedures for locating the source of a leak and determining the degree of hazard involved;

(6) a chain of command for service personnel to follow if assistance is required in determining the degree of hazard;

(7) instructions to be issued by service personnel to customers or the public or both, as necessary, after a leak is located and the degree of hazard determined.

§8.206.Risk-Based Leak Survey Program.

(a) This [Effective September 1, 2008, this] section applies to each operator of a gas distribution system that is subject to the requirements of 49 CFR Part 192.

(b) Each [No later than March 1, 2009, each] operator shall have [completed and submitted to the Commission] either a prescriptive or a risk-based program for leak surveys for its pipeline systems that complies with the requirements of this section. Such program shall require a designation on a system by system basis or by segments within each system whether the operator has chosen to use the risk based leak survey program that complies with the requirements of subsections (c) through (f) of this section or the prescriptive leak survey program that complies with the requirements of subsection (g) of this section. [Within 185 days after receipt of notice that an operator's plan is complete, the Commission shall either notify the operator of the acceptance of the plan or shall complete an evaluation of the plan to determine compliance with this section.]

(c) Each operator shall create a risk model on which to base its leak survey program to identify those systems or segments within systems that pose the greatest hazard and thus will be inspected for leaks more frequently. The risk model shall identify risk factors and determine the degree of hazard associated with those risk factors. The operator shall establish the leak survey frequency based on the degree of hazard for each system or segment within a system.

(d) Each operator shall periodically re-evaluate each pipeline system or system segment and update its leak survey inspection program to address any changes that may be identified through the monitoring of the pipeline system in accordance with the requirements imposed by 49 CFR §192.613 (relating to Continuing Surveillance). Each operator shall not less than every three years at intervals not exceeding 39 months review its leak survey inspection program. Each operator shall review its leak survey inspection program [at least every three years and] within 30 days in the following circumstances:

(1) to add a new system or segment being put into operation; or

(2) if, for any system or segment, there has been a ten percent increase in the number of leaks being upgraded or a ten percent increase in the number of unrepaired leaks.

(e) Based on the particular circumstances and conditions, an increased frequency beyond that required by 49 CFR §192.723(b)(1) and (2), may be warranted. Surveys should be conducted more frequently in those areas with the greatest potential for leakage and where leakage could be expected to create a hazard. Each operator should consider the following factors in establishing an increased frequency of leakage surveys:

(1) pipe location, which means 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, which means the age of the pipe, materials, type of facilities, operating pressures, leak history records, and other studies;

(3) the corrosion history of the pipeline, which means 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, which means 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, which could include 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) The assignment of inspection priorities is based on the degree of hazard associated with the risk factors assigned to the pipeline system or segments within a system. The determination of leak survey frequency is determined by classifying each pipeline segment based on its degree of hazard associated with each risk factor. Each operator shall establish its own risk ranking for pipeline segments to determine the frequency of leakage surveys. Based on a ranking from high to low, each operator shall schedule leak inspections for a given pipeline system or segment within a system on a time interval necessary to address the risks. The time interval may range from quarterly to every five years.

(g) Operators electing to use a prescriptive leak survey program shall conduct leak surveys no less frequently than:

(1) Once each calendar year at intervals not exceeding 15 months [annually] for all systems within a business district;

(2) every five calendar years at intervals not exceeding 63 months for non-business district polyethylene systems or segments within a system;

(3) every three calendar years at intervals not exceeding 39 months for all other non-business district cathodically protected steel systems or segments within a system; and

(4) every two calendar years at intervals not exceeding 27 months for all other non-business district systems or segments within a system.

§8.209.Distribution Facilities Replacements.

(a) 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 [No later than August 1, 2011, each] operator must establish [and submit to the Pipeline Safety Division for review and approval the operator's] 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. [Within 90 days after receipt of an operator's written procedures, the Pipeline Safety Division must either notify the operator of the acceptance of the plan or complete an evaluation of the plan to determine compliance with this section. If the Pipeline Safety Division determines that an operator's procedures do not comply with the requirements of this section, the operator must modify its procedures as directed by the Pipeline Safety Division.]

(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 [Until the Commission has collected three full calendar years of data submitted on the PS-95, operators may use two calendar years of data to perform the steel service line leak repair analysis. Once the Commission has collected three full calendar years of data submitted on the PS-95, 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 7.5% or greater is a Priority 1 segment and an operator must complete the removal or replacement by June 30, 2013;]

(1) [(2)] a segment with an annualized steel service line leak rate of 5% or greater but less than 7.5% is a Priority 1 [Priority 2] segment and an operator must remove or replace no less than 10% of the original inventory per year; and

(2) [(3)] a segment with an annualized steel service line leak rate of less than 5% is a Priority 2 [Priority 3] segment. An operator is not required to remove or replace any Priority 2 [Priority 3] segments; however, upon discovery of a leak on a Priority 2 [Priority 3] 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 [Unless otherwise approved in an operator's risk-based plan, all] replacement programs require a minimum annual replacement of 8% [5%] of the pipeline segments or facilities posing [posting] 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 [Pipeline Safety] 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 [Pipeline Safety] 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 revisions to its risk-based program and] proposed work plan for removal or replacement for the current calendar year, the implementation of which is subject to review and amendment by the [Pipeline Safety] Division. Each operator must notify the [Pipeline Safety] 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 [Pipeline Safety] 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 based on the pretax cost of capital last approved for the utility by the Commission. The utility's pre-tax cost of capital may be adjusted and applied prospectively if the Commission establishes a new pre-tax cost of capital for the utility in a future proceeding;

(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.

§8.210.Reports.

(a) Incident [Accident, leak, or incident] report.

(1) Telephonic report. At the earliest practical moment but no later than one hour [or within two hours] following confirmed discovery, a gas company shall notify the Commission by telephone of any event that involves a release of gas from its pipelines defined as an incident in 49 CFR §191.3[Part 191.3].

[(2)] The telephonic report shall be made to the Commission's 24-hour emergency line at (512) 463-6788 and shall include the following:]

(A) the operator or gas company's name;

(B) the location of the [leak or] incident;

(C) the time of the incident [or accident];

(D) the number of fatalities and/or personal injuries;

(E) the phone number of the operator;

(F) the telephone number of the operator's on-site person; and

[(G) estimated property damage, including the cost of gas lost, to the operator, others, or both; and]

(G) [(H)] any other significant facts relevant to the [accident or] incident. Ignition, explosion, rerouting of traffic, evacuation of any building, and media interest are included as significant facts.

(2) This paragraph applies to each operator of a gas distribution system that is subject to the requirements of 49 CFR Part 192. Such operator shall also provide the following information to the Division when the information is known by the operator:

(A) the cost of gas lost;

(B) estimated property damage to the operator and others;

(C) any other significant facts relevant to the incident; and

(D) other information required under federal regulations to be provided to the Pipeline and Hazardous Materials Safety Administration or a successor agency after a pipeline incident or similar incident.

(3) Written report.

(A) Following the initial telephonic report for [accidents, leaks, or] incidents described in paragraph (1) of this subsection, the operator shall retain its records and provide to the Commission upon request the applicable written reports submitted to the Department of Transportation. Operators of gas gathering pipelines regulated by §8.110 (relating to Gathering Pipelines) shall file with the Commission within 30 calendar days after the date of the telephonic report a written report on an incident described in paragraph (1) of this subsection utilizing the applicable form from the Department of Transportation. [who made the telephonic report shall submit to the Commission a written report summarizing the accident or incident. The report shall be submitted as soon as practicable within 30 calendar days after the date of the telephonic report. The written report shall be made on forms supplied by the Department of Transportation. For reports submitted electronically to the Department of Transportation, the operator shall forward a copy of the report and confirmation to the Division or electronically to safety@rrc.texas.gov. For reports not submitted electronically to the Department of Transportation, the operator shall send to the Division an original signed report form.]

(B) The written report is not required to be submitted for master metered systems.

(C) The Commission may require an operator to submit a written report for an [accident or] incident not otherwise required to be reported.

(b) Pipeline safety annual reports.

[(1)] Each [Except as provided in paragraph (2) of this subsection, each] gas company shall retain the [submit an] annual report for its intrastate systems in the same manner as required by 49 CFR Part 191. A gas company shall provide a copy of the annual report to the Commission upon request. [The report shall be submitted to the Division on forms supplied by the Department of Transportation not later than March 15 of a year for the preceding calendar year. For reports submitted electronically to the Department of Transportation, the operator may forward a copy of the report and confirmation to the Division or electronically to safety@rrc.texas.gov. For reports not submitted electronically to the Department of Transportation, the operator shall send to the Division an original signed report form.]

[(2) The annual report is not required to be submitted for:]

[(A) a petroleum gas system, as that term is defined in 49 CFR 192.11, which serves fewer than 100 customers from a single source; or]

[(B) a master metered system.]

(c) Safety related condition reports. Each gas company shall submit to the Division in writing a safety-related condition report for any condition outlined in 49 CFR 191.23.

(d) Offshore pipeline condition report. Within 60 days of completion of underwater inspection, each operator shall file with the Division a report of the condition of all underwater pipelines subject to 49 CFR 192.612(a). The report shall include the information required in 49 CFR 191.27.

(e) Leak Reporting. For purposes of this subsection, the term "leak" includes all underground leaks, all hazardous above ground leaks, and all non-hazardous above ground leaks that cannot be eliminated by lubrication, adjustment, or tightening. Each operator of a gas distribution system [, of a regulated plastic gas gathering line, or of a plastic gas transmission line] shall submit to the Division a list of all leaks repaired on its pipeline facilities. Each such operator shall list all leaks identified on all pipeline facilities. Each such operator shall also include the number of unrepaired leaks remaining on the operator's systems by leak grade. Each such operator shall submit leak reports using the Commission's online reporting system, Form PS-95, by July 15 and January 15 of each calendar year, in accordance with the PS-95 Semi-Annual Leak Report Electronic Filing Requirements. The report submitted on July 15 shall include information from the previous January 1 through the previous June 30. The report submitted on January 15 shall include information from the previous July 1 through the previous December 31. The report includes:

(1) leak location;

(2) facility type;

(3) leak classification;

(4) pipe size;

(5) pipe type;

(6) leak cause; and

(7) leak repair method.

(f) The Commission shall retain state records regarding a pipeline incident perpetually. "State record" has the meaning assigned by Texas Government Code §441.180.

§8.225.Plastic Pipe Requirements.

[(a)] An operator shall retain its records relating to plastic [Plastic] pipe installation in accordance with 49 CFR Part 192 and shall provide such records to the Commission upon request [and/or removal report].

[(1) Each operator shall have reported to the Commission on March 15, 2003, and March 15, 2004, the amount in miles of plastic pipe installed and/or removed during the preceding calendar year on Form PS-82, Annual Report of Plastic Installation and/or Removal. The mileage shall have been identified by:]

[(A) system;]

[(B) nominal pipe size;]

[(C) material designation code;]

[(D) pipe category; and]

[(E) pipe manufacturer.]

[(2) For all new installations of plastic pipe, each operator shall record and maintain for the life of the pipeline the following information for each pipeline segment:]

[(A) all specification information printed on the pipe;]

[(B) the total length;]

[(C) a citation to the applicable joining procedures used for the pipe and the fittings; and]

[(D) the location of the installation to distinguish the end points. A pipeline segment is defined as continuous piping where the pipe specification required by ASTM D2513 or ASTM D2517 does not change.]

[(b) Plastic pipe inventory report. Beginning March 15, 2005, and annually thereafter, each operator shall report to the Division the amount of plastic pipe in natural gas service as of December 31 of the previous year. The amount of plastic pipe shall be determined by a review of the records of the operator and shall be reported on Form PS-81, Plastic Pipe Inventory. The report shall include the following:]

[(1) system;]

[(2) miles of pipe;]

[(3) calendar year of installation;]

[(4) nominal pipe size;]

[(5) material designation code;]

[(6) pipe category; and]

[(7) pipe manufacturer.]

[(c) Electronic format required. Operators of systems with more than 1,000 customers shall file the reports required by this section electronically in a format specified by the Commission.]

[(d) Report forms; signature required. Operators shall complete all forms required to be filed in accord with this section, including signatures of company officials. The Commission may consider the failure of an operator to complete all forms as required to be a violation under Texas Utilities Code, Chapter 121, and may seek penalties as permitted by that chapter.]

§8.230.School Piping Testing.

(a) Purpose. The purpose of this section is to implement the requirements of Texas Utilities Code, §§121.5005 - 121.507, relating to the testing of natural gas piping systems in school facilities.

(b) Procedures. Natural gas suppliers shall develop procedures for:

(1) receiving written notice from a person responsible for a school facility specifying the date and result of each test as provided by subsection (c) of this section.

(2) terminating natural gas service to a school facility in the event that:

(A) the natural gas supplier receives notification of a hazardous natural gas leak in the school facility piping system pursuant to this rule; or

(B) the natural gas supplier does not receive written notification specifying the date that testing has been completed on a school facility as provided by subsection (c) of this section, and the results of such testing.

(3) A natural gas supplier may rely on a written notification complying with this rule as proof that a school facility is in compliance with Texas Utilities Code, §§121.5005 - 121.507, and this rule.

(4) A natural gas supplier shall have no duty to inspect a school facility for compliance with Texas Utilities Code, §§121.5005 - 121.507.

(c) Testing.

(1) A natural gas piping pressure test performed under a municipal code in compliance with paragraphs (4) and (5) of this subsection shall satisfy the testing requirements.

(2) A pressure test to determine if the natural gas piping in each school facility will hold at least normal operating pressure shall be performed as follows:

(A) School facility pipe testing includes all gas piping from the outlet of the purchase meter to each inlet valve of each appliance.

(B) For systems on which the normal operating pressure is less than 0.5 psig, the test pressure shall be 5 psig and the time interval shall be 30 minutes.

(C) For systems on which the normal operating pressure is 0.5 psig or more, the test pressure shall be 1.5 times the normal operating pressure or 5 psig, whichever is greater, and the time interval shall be 30 minutes.

(D) A pressure test using normal operating pressure shall be utilized only on systems operating at 5 psig or greater, and the time interval shall be one hour.

(3) The testing shall be conducted by:

(A) a licensed plumber;

(B) a qualified employee or agent of the school who is regularly employed as or acting as a maintenance person or maintenance engineer; or

(C) a person exempt from the plumbing license law as provided in Texas Occupations Code, Chapter 1301 [Civil Statutes, Article 6243-101, §3].

(4) The testing of public school facilities shall occur as follows:

(A) for school facilities tested prior to the beginning of the 1997-1998 school year, at least once every two years thereafter before the beginning of the school year;

(B) for school facilities not tested prior to the beginning of the 1997-1998 school year, as soon as practicable thereafter but prior to the beginning of the 1998-1999 school year and at least once every two years thereafter before the beginning of the school year;

(C) for school facilities operated on a year-round calendar and tested prior to July 1, 1997, at least once every two years thereafter; and

(D) for school facilities operated on a year-round calendar and not tested prior to July 1, 1997, once prior to July 1, 1998, and at least once every two years thereafter.

(5) The testing of charter and private school facilities shall occur at least once every two years and shall be performed before the beginning of the school year, except for school facilities operated on a year-round calendar, which shall be tested not later than July 1 of the year in which the test is performed. The initial test of charter and private school facilities shall occur prior to the beginning of the 2003-2004 school year or by August 31, 2003, whichever is earlier.

(6) The firm or individual conducting the test shall immediately report any hazardous natural gas leak as follows:

(A) in a public school facility, to the board of trustees of the school district and the natural gas supplier; and

(B) in a charter or private school facility, to the person responsible for such school facility and the natural gas supplier.

(7) The school pipe testing shall be recorded on Railroad Commission Form PS-86.

(d) Records. Natural gas suppliers shall maintain for at least two years a listing of the school facilities to which it sells and delivers natural gas as well as copies of the written notification regarding testing, Form PS-86, and hazardous leaks received pursuant to Texas Utilities Code, §§121.5005 - 121.507, and this rule.

§8.235.Natural Gas Pipelines Public Education and Liaison.

(a) Liaison activities required. Each operator of a natural gas pipeline or natural gas pipeline facilities or the operator's designated representative shall communicate and conduct liaison activities at intervals not exceeding 15 months, but at least once each calendar year with fire, police, and other appropriate public emergency response officials. The liaison activities are those required by 49 CFR Part 192.615(c)(1) - (4). These liaison activities shall be conducted in person, except as provided by this section.

(b) Meetings in person. The operator or the operator's representative may conduct the required community liaison activities as provided by subsection (c) of this section only if the operator or the operator's representative has made an effort to conduct a community liaison meeting in person with the officials by one of the following methods:

(1) mailing a written request for a meeting in person to the appropriate officials by certified mail, return receipt requested;

(2) sending a request for a meeting in person to the appropriate officials by facsimile transmission; or

(3) making one or more telephone calls or e-mail message transmissions to the appropriate officials to request a meeting in person.

(4) If a scheduled meeting does not take place, the operator or operator's representative shall make an effort to re-schedule the community liaison meeting in person with the officials using one of the methods in paragraphs (1) - (3) of this subsection before proceeding to arrange a conference call pursuant to subsection (c) of this section.

(c) Alternative methods. If the operator or operator's representative cannot arrange a meeting in person after complying with subsection (b) of this section, the operator or the operator's representative shall conduct community liaison activities by one of the following methods:

(1) holding a telephone conference with the appropriate officials; or

(2) delivering the community liaison information requested to be conveyed by certified mail, return receipt requested.

(d) Proximity to public school. Each owner or operator of a natural gas pipeline or natural gas pipeline facility any part of which is located within 1,000 feet of a public school building or public school recreational area shall maintain and upon request file [notify the Commission by filing] with the Division [, no later than January 15 of every even-numbered year,] the following information:

(1) the name of the school;

(2) the street address of the school; and

(3) the identification (system name) of the pipeline.

(e) Records. The operator shall maintain records documenting compliance with the liaison activities required by this section. Records of attendance and acknowledgment of receipt by the emergency response officials shall be retained for five years from the date of the event that is commemorated by the record. Records of certified mail and/or telephone transmissions undertaken in compliance with subsections (b) and (c) of this section satisfy the record-keeping requirements of this subsection.

§8.240.Discontinuance of Service.

(a) Within 30 calendar days following notification from a customer to discontinue [natural] gas service at that customer's service location, each operator shall take one of the three steps specified in 49 CFR §192.727(d) unless the operator receives notice within such 30 calendar day time period that service is to be continued at that service location to another customer or an owner or manager of the service location.

(1) An extension is granted if the customer account is placed in a soft-close program, which means the operator will close a customer's gas service account, provide the customer with an accurate closing bill, but leave the gas on for the next tenant. A soft-close program may be applied to accounts serving single family residential or individually metered apartment buildings.

(2) Accounts that are in a soft-close status shall have an automatic gas turn-off order executed if:

(A) the meter registers 50 CCF (5 MCF) or more from the documented soft-close reading; or

(B) after 90 days from the customer's notification to discontinue gas service.

[(b) Upon receipt of a notification from a customer to discontinue gas service, the operator shall inform the customer that the gas service may remain on at the service location for up to 30 calendar days following the customer's requested date for discontinuance.]

(b) [(c)] Each operator shall have a written procedure in its operations and maintenance manual for service discontinuance that includes the requirements of this rule.

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

Filed with the Office of the Secretary of State on October 1, 2019.

TRD-201903546

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: November 17, 2019

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


SUBCHAPTER D. REQUIREMENTS FOR HAZARDOUS LIQUIDS AND CARBON DIOXIDE PIPELINES ONLY

16 TAC §8.301, §8.315

Statutory Authority: The Commission proposes 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, §§121.201-121.211, 121.213-121.214; §121.251 and §121.253, §§121.5005-121.507; 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.

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.

§8.301.Required Records and Reporting.

(a) Accident reports. In the event of any failure or accident involving an intrastate pipeline facility from which any hazardous liquid or carbon dioxide is released, if the failure or accident is required to be reported by 49 CFR §§195.50 and 195.52 [Part 195], the operator shall also report to the Commission as follows.

(1) Accidents [Incidents] involving crude oil. In the event of an accident involving crude oil, the operator shall:

(A) notify the Division, which shall notify the Commission's appropriate Oil and Gas district office, by telephone to the Commission's emergency line at (512) 463-6788 at the earliest practicable moment but no later than one hour following confirmed discovery of the accident [incident (within two hours)] and include the following information:

(i) company/operator name;

(ii) location of accident [leak or incident];

(iii) time and date of accident[/incident];

(iv) fatalities and/or personal injuries;

(v) phone number of operator;

(vi) telephone number of operator;

(vii) telephone number of the operator's on-site person;

(viii) other significant facts relevant to the accident, such as ignition [or incident. Ignition], explosion, rerouting of traffic, evacuation of any building, and media interest; and [are included as significant facts.]

(B) following the initial telephonic report for accidents described in paragraph (1) of this subsection, the operator shall retain its records and provide to the Commission upon request the applicable written reports submitted to the DOT. Operators of hazardous liquids gathering pipelines regulated by §8.110 of this title (relating to Gathering Pipelines) shall file with the Commission a written report on an accident described in paragraph (1) of this subsection utilizing the applicable form from the DOT within 30 calendar days after the date of the telephonic report. [within 30 days of discovery of the incident, submit a completed Form H-8 to the Oil and Gas Division of the Commission. In situations specified in the 49 CFR Part 195, the operator shall also file a copy of the required Department of Transportation form with the Division. For reports submitted electronically to the Department of Transportation, the operator shall forward a copy of the report and confirmation to the Division or electronically to safety@rrc.texas.gov. If an operator does not submit reports electronically to the Department of Transportation, the operator shall send the report to the Division on an original signed report form.]

(2) Accidents involving hazardous [Hazardous ] liquids, other than crude oil, and carbon dioxide. For accidents [incidents] involving hazardous liquids, other than crude oil, and carbon dioxide, the operator shall:

(A) notify the Division of such accident [incident] by telephone to the Commission's emergency line at (512) 463-6788 at the earliest practicable moment following confirmed discovery (within one hour [two hours]) and include the information listed in paragraph (1)(A)(i) - (viii) of this subsection; and

(B) within 30 days of discovery of the accident [incident], complete and retain the [file with the Division a] written report as required by 49 CFR Part 195. [using the appropriate Department of Transportation form (as required by 49 CFR Part 195) or a facsimile. For reports submitted electronically to the Department of Transportation, the operator shall forward a copy of the report and confirmation to the Division or electronically to safety@rrc.texas.gov. If an operator does not submit reports electronically to the Department of Transportation, the operator shall send the report to the Division on an original signed report form.] An operator shall provide a copy of the accident report to the Commission upon request. Operators of hazardous liquids gathering pipelines regulated by §8.110 of this title shall file with the Commission a written report on an accident described in paragraph (2) of this subsection utilizing the applicable form from the DOT within 30 calendar days after the date of the telephonic report.

(b) Annual report. Each operator shall retain the [file with the Commission an] annual report required by 49 CFR Part 195 for its intrastate systems [located in Texas in the same manner as required by 49 CFR Part 195]. An operator shall provide a copy of the annual report to the Commission upon request. [The report shall be filed with the Commission on forms supplied by the Department of Transportation on or before June 15 of a year for the preceding calendar year reported. For reports submitted electronically to the Department of Transportation, the operator may forward a copy of the report and confirmation to the Division or electronically to safety@rrc.texas.gov. For reports not submitted electronically to the Department of Transportation, the operator shall send to the Division an original signed report form.]

(c) Safety-related condition reports. Each operator shall submit to the Division in writing a safety-related condition report for any condition specified in 49 CFR Part 195.

(d) Facility response plans. An operator required to file [Simultaneously with filing either] an initial or a revised facility response plan, prepared under the Oil Pollution Act of 1990 for all or any part of a hazardous liquid pipeline facility located landward of the coast, with the [United States] Department of Transportation is not required to concurrently file the plan with the Commission, but shall retain a copy and provide it to the Commission upon request [, each operator shall submit to the Division a copy of the initial or revised facility response plan prepared under the Oil Pollution Act of 1990, for all or any part of a hazardous liquid pipeline facility located landward of the coast].

§8.315.Hazardous Liquids and Carbon Dioxide Pipelines or Pipeline Facilities Located Within 1,000 Feet of a Public School Building or Facility.

(a) In addition to the requirements of §8.310 of this title (relating to Hazardous Liquids and Carbon Dioxide Pipelines Public Education and Liaison), each owner or operator of each intrastate hazardous liquids pipeline or pipeline facility and each intrastate carbon dioxide pipeline or pipeline facility shall comply with this section.

(b) This section applies to each owner or operator of a hazardous liquid or carbon dioxide pipeline or pipeline facility any part of which is located within 1,000 feet of a public school building containing classrooms, or within 1,000 feet of any other public school facility where students congregate.

(c) Each pipeline owner and operator to which this section applies shall, for each pipeline or pipeline facility any part of which is located within 1,000 feet of a public school building containing classrooms, or within 1,000 feet of any other public school facility where students congregate, maintain and upon request file with the Division, [no later than January 15 of every odd numbered year,] the following information:

(1) the name of the school;

(2) the street address of the public school building or other public school facility; and

(3) the identification (system name) of the pipeline.

(d) Each pipeline owner and operator to which this section applies shall:

(1) upon written request from a school district, provide in writing the following parts of a pipeline emergency response plan that are relevant to the school:

(A) a description and map of the pipeline facilities that are within 1,000 feet of the school building or facility;

(B) a list of any product transported in the segment of the pipeline that is within 1,000 feet of the school facility;

(C) the designated emergency number for the pipeline facility operator;

(D) information on the state's excavation one-call system; and

(E) information on how to recognize, report, and respond to a product release; and

(2) mail a copy of the requested items by certified mail, return receipt requested, to the superintendent of the school district in which the school building or facility is located.

(e) A pipeline operator or the operator's representative shall appear at a regularly scheduled meeting of the school board to explain the items listed in subsection (c) of this section if requested by the school board or school district.

(f) Records. Each owner or operator shall maintain records documenting compliance with the requirements of this section. Records of attendance and acknowledgment of receipt by the school board or school district superintendent shall be retained for five years from the date of the event that is commemorated by the record. Records of certified mail transmissions undertaken in compliance with this section satisfy the record-keeping requirements of this subsection.

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

Filed with the Office of the Secretary of State on October 1, 2019.

TRD-201903547

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: November 17, 2019

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