Part 1. RAILROAD COMMISSION OF TEXAS
Chapter 3. OIL AND GAS DIVISION
The Railroad Commission of Texas (Commission) adopts amendments to §3.50, relating to Enhanced Oil Recovery Projects--Approval and Certification for Tax Incentive, to incorporate changes made by House Bill (HB) 3732, 80th Legislature (2007), Regular Session, and §3.80, relating to Commission Oil and Gas Forms, Applications, and Filing Requirements, to adopt a new form related to HB 3732 and to amend and delete other forms. The rules are adopted with changes from the versions published in the October 26, 2007, issue of the Texas Register (32 TexReg 7567).
Section 9 of HB 3732 amends Chapter 202 of the Texas Tax Code, relating to Oil Production Tax, to add new §202.0545, relating to Tax Exemption for Enhanced Recovery Projects Using Anthropogenic Carbon Dioxide. In general, the bill provides a reduction in the tax rate on oil produced from enhanced recovery projects using anthropogenic carbon dioxide. These changes became effective September 1, 2007.
HB 3732 authorizes the Commission to issue a certification for a severance tax rate reduction on oil produced using anthropogenic carbon dioxide in an enhanced recovery project, if that carbon dioxide is to be sequestered in a reservoir productive of oil or natural gas, and when the Commission finds that there is a reasonable expectation that the operator's planned sequestration program will ensure that at least 99 percent of the carbon dioxide sequestered will remain sequestered for at least 1,000 years. The bill requires that the operator employ appropriately designed monitoring and verification measures for a period sufficient to demonstrate whether the sequestration program is performing as expected.
Until the later of the seventh anniversary of the date that the Comptroller of Public Accounts (Comptroller) first approves an application for a tax rate reduction or the effective date of a final rule adopted by the Environmental Protection Agency regulating carbon dioxide as a pollutant, the producer of oil recovered through an enhanced oil recovery (EOR) project that qualifies under Texas Tax Code, §202.054, for the recovered oil tax rate provided by Texas Tax Code, §202.052(b), is entitled to an additional 50 percent reduction in that tax rate if in the recovery of the oil the EOR project uses carbon dioxide that: (1) is captured from an anthropogenic source in Texas; (2) would otherwise be released into the atmosphere as industrial emissions; (3) is measurable at the source of capture; and (4) is sequestered in one or more geological formations in this state following the EOR process. The tax reduction on oil is proportional to the percentage of anthropogenic carbon dioxide that satisfies these criteria.
To qualify for the tax rate reduction, the operator must apply for a certification from the Commission if carbon dioxide used in the project is to be sequestered in an oil or natural gas reservoir; the Texas Commission on Environmental Quality (TCEQ) if the carbon dioxide used in the project is to be sequestered in a geological formation other than an oil or natural gas reservoir; or both agencies if the carbon dioxide used in the project is to be sequestered in an oil or gas reservoir and a geological formation other than an oil or gas reservoir. Then, the operator must apply to the Comptroller.
The agencies may issue a certification only if they find, based on substantial evidence, that there is a reasonable expectation that the operator's planned sequestration program will ensure that at least 99 percent of the carbon dioxide sequestered will remain sequestered for at least 1,000 years and will include appropriately designed monitoring and verification measures that will be employed for a period sufficient to demonstrate whether the sequestration program is performing as expected. The operator does not qualify for the tax rate reduction if the operator's sequestration program or monitoring and verification measures differ substantially from the planned program.
HB 3732 requires that the Comptroller approve the application if the operator submits the certification(s) and the Comptroller determines that the oil is otherwise eligible. An operator may apply for a tax credit on oil produced over the year.
The Commission received comments from the Texas Oil and Gas Association (TXOGA) and a letter from Occidental Petroleum Ltd. concurring with TXOGA's comments; comments submitted jointly by Environmental Defense; BOP American, Inc.; and Hydrogen Energy International, LLC (the Joint Comments) and comments from Mr. Darrick Eugene.
Mr. Darrick Eugene requested that the Commission allow new §3.50(k) to parallel the appeal process outlined under §3.50(f) and (g)(2)(C) by adding a new paragraph (9) to read as follows: "Opportunity for hearing. A commission representative may administratively approve the application for certification. If the commission representative denies administrative approval, the applicant shall have the right to a hearing upon request. After hearing, the examiner shall recommend final action by the commission." The Commission disagrees that this language is necessary because an applicant always has the right to a hearing on an administrative denial; nevertheless, the Commission has added similar language in a new paragraph (9) in §3.50(k).
TXOGA recommended that the Commission insert the word "anthropogenic" in §3.50(k)(5)(A) to mirror the wording on proposed Form H-12A and to clarify that the sequestration requirements of subsection (k) apply to the sequestration of anthropogenic carbon dioxide for the purposes of the additional tax rate reduction provided for by HB 3732. The Commission agrees with this comment and has inserted the word "anthropogenic" before "carbon dioxide" in §3.50(k)(5)(A).
TXOGA recommended that the Commission revise the language proposed to be included on Form H-12A to insert the word "anthropogenic" before "carbon dioxide" to clarify that the form applies only to the anthropogenic carbon dioxide. In TXOGA's view, this would ensure that an operator is not required to certify that an entire project must meet this sequestration standard, because TXOGA believes that no project will ever use anthropogenic carbon dioxide or be able to take advantage of this tax benefit. The Commission notes that the stated purpose of Form H-12A is to apply for certification for the additional tax rate reduction for enhanced oil recovery projects using anthropogenic carbon dioxide and, as such, the Form H-12 A simply does not apply to EOR projects that use only non-anthropogenic carbon dioxide. However, the Commission has inserted the word "anthropogenic" before "carbon dioxide" in SECTIONS 7 and 9 of Form H-12A for clarity.
The Joint Comments recommended that the Commission revise the language in §3.50(k)(4)(A) to state that the application for certification must be executed and certified "as provided for on the form" rather than "by a person having knowledge of the facts entered on the form." The Commission agrees with this recommended clarifying change and has revised subsection (k)(4)(A) accordingly.
The Joint Comments recommended that the Commission revise subsection (k)(4)(B) to add a new clause (v) that would require an applicant for the additional tax rate reduction to provide a description of the planned sequestration program reasonably expected to ensure that at least 99% of the sequestered carbon dioxide will remain sequestered for at least 1,000 years. The Joint Comments also recommended that the Commission revise the language in renumbered clause (vi) (proposed as clause (v)) to require that the applicant state the planned duration of the applicant's proposed monitoring and verification measures. The Commission agrees with these comments and has made the suggested clarifications in the adopted rule.
The Joint Comments recommended that in §3.50(k)(7) the Commission replace the word "approved" with the word "certified," and add a reference to subsection (k)(5), so that the paragraph reads as follows: "The additional tax rate reduction under this subsection does not apply and the operator will be required to repay the amount of tax that would have been imposed in the absence of this subsection if the operator's sequestration program or the operator's monitoring and verification measures differ substantially from the planned program certified by the Commission under subsection (k)(5) of this section." The Commission agrees with this comment and has made the clarifying change.
The Joint Comments recommended that the Commission revise §3.50(k)(8) to add the following sentence: "In the event that the operator's sequestration program, including monitoring and verification measures, differs substantially from the program certified by the Commission under subsection (k)(5) of this section, the operator shall include a report describing the material changes in the sequestration program with the Annual Report." The Commission agrees with this suggested clarification and has added a slightly modified version of the recommended sentence.
The Joint Comments recommended that the Commission revise Form H-12A to include instructions. The Commission finds that instructions for this relatively simple form are unnecessary, particularly when the form is read in conjunction with §3.50(k) and Texas Tax Code, §202.0545. However, the Commission has included in the upper right-hand corner of the form a prominent reference to §3.50(k).
The Joint Comments recommended that the Commission revise Form H-12A to conform the wording for the third box in Item 9 of the form to the rule language regarding the planned duration of the monitoring and verification measures that the Joint Comments recommended for §3.50(k)(4)(B). The Commission agrees with this comment and has made the recommended change on Form H-12A.
The Joint Comments recommended that the Commission revise Form H-14, Enhanced Oil Recovery Reduced Tax Annual Report, to add instructions, to add a new box to item number 13 on the form regarding "Attachment Checklist" for "Changes in Sequestration Program (if applicable)," and to add a new box to item number 13 on the form for "Annual Monitoring & Verification Results." The Commission notes that Form H-14 already includes instructions, and the Commission did not propose changes to those instructions in this rulemaking. The Commission agrees with the remainder of this comment, however, and has revised Form H-14 to add a new box to the checklist to request a description of changes in the sequestration program, if applicable.
TXOGA commented on the proposed revisions to Form P-17, Application for Exception to Statewide Rules (SWR) 26 and/or 27, and requested that in SECTION 3, the Commission add clarification to parts "g" and "h" in that "an exception to metering is the same as allocation by well test." The Commission agrees that some clarification is necessary and, in response to this comment, has added to (g) and (h) additional boxes for "allocation by well test" and "other."
TXOGA also recommended that the Commission delete box "i" in SECTION 3 of Form P-17 because the Commission's rules do not specify a particular method or type of equipment that must be used, and the use of a turbine or Coriolis meter to measure liquid is not an exception for which a $150 exception fee is required. TXOGA recommended that the Commission delete the second sentence of the section relating to "Fees" for certain meters for the same reasons discussed above because the Coriolis meter has been in service many years and questions about its reliability have been answered. In addition, TXOGA stated that API MPMS 5-1 (2005) discusses various meters and their applicability and that meter selection should be based on this or other accepted industry standards.
The Commission does not agree that use of a turbine or Coriolis meter to measure liquid is not an exception for which a fee is required. The Commission's rules require that production be measured accurately and that the method of allocating production to individual interests accurately attribute to each interest its fair share of aggregated production. The Commission's rules further require that measurement follow the procedures the Commission established in Gas-Oil Ratio Calculation and Back Pressure Test for Natural Gas Wells, which authorize the use of orifice meters, positive displacement, and direct measurement for oil. In order to add the use of a Coriolis meter as an authorized method of measurement, the rules and/or publications would need to be amended; and the Commission did not propose to amend such rules and publications in this rulemaking. However, Commission staff would welcome the opportunity to discuss a proposal to amend the rules and/or publications to include the use of the Coriolis meter or other measurement methods and any documentation the commenter can provide that the measurement method yields an equally accurate measurement of production.
TXOGA commented that the Commission should revise SECTION 4 on proposed Form P-17, relating to Notice Requirements, to show options for allocation of production as "well tests" or "other." TXOGA stated that well tests include reports on W-10s, G-10s, and testing using positive displacement meters and that other measurement options also are available, such as different meters. TXOGA further stated that the statutes and rules require a method of allocation to accurately attribute each interest its fair share. Finally, TXOGA stated, there should be no fee for selection of a particular allocation method or meter.
The Commission does not agree with this comment. The methods listed (W-10, G-10, and positive displacement) are the only ways to allocate production. In addition, the Commission does not charge a separate fee for selection of an allocation method.
TXOGA commented that the Commission should delete the word "oil" in SECTION 6 on the front of Form P-17 and in the instructions for SECTION 6, because Form P-17 is for commingling of production from both oil leases and gas leases under Statewide Rules 26, 27, and 55. The Commission disagrees with this comment. The instructions for SECTION 6 clearly state that the section applies only to oil production (commingling of oil within a lease from some or all wells on the oil lease). Nevertheless, the Commission has added the clause "for oil production" for clarification in SECTION 6. In addition, the Commission has made grammatical corrections to the instructions for SECTION 6.
TXOGA also stated that fees should not be required for deletion of a lease from a commingle permit, because this is not a request for an exception and is not authorized by Rule 78 or the statutes. The Commission disagrees with TXOGA's comment with respect to the fee; the Commission does not require a $150 fee for a Form P-17 for which the only action is deletion of a lease or leases. Nevertheless, the Commission has added clarifying language to that effect in the instructions regarding "Fees."
Under "Purpose of Filing," TXOGA recommended that the Commission add "casinghead gas and gas well gas," because the Commission's rules allow for commingling and they also are reported on Form PR; and commingle permit numbers are assigned when any production is commingled at a facility and reported on the production report. Also under "Purpose of Filing," TXOGA recommended revising the language in item (1) to include casinghead gas and gas well gas, to delete "oil and condensate," and delete all the text following the word "facility." TXOGA's proposed wording reads as follows: "(1) surface commingling of oil, condensate, casinghead gas, gas well gas or a combination of any production into a common facility."
The Commission disagrees with this comment. The Commission does not assign a commingling number for commingling of gas only. Commingling of gas is implied by metering exceptions as shown in SECTION 3 of the form. However, the Commission has revised the language to clarify that a commingling number will be assigned for surface commingling of gas and hydrocarbon liquids.
TXOGA recommended that the Commission amend the instructions regarding "Purpose of Filing" to require that only SECTIONS 1 through 7 on Form P-17 be completed when an application is being amended. TXOGA reasoned that, because it is not uncommon for leases to be added or deleted frequently, by including the whole list of leases with each amendment, errors could be minimized, thus also reducing non-compliance and severance issues. TXOGA also recommended that the Commission accept scanned color documents and provide for electronic submission of commingle applications.
The Commission's efforts to consolidate commingling forms and the new Form P-17 are a part of the Commission's attempts to ready the form for electronic filing. Rule 3.80(e)(1) states that "(A)n organization may file electronically any form listed on Table 1 for which the Commission has provided an electronic version, provided that the organization pays all required filing fees and complies with all requirements, including but not limited to security procedures, for electronic filing." The Commission plans to develop an electronic filing system for Form P-17 that will allow an operator to file only changes (additions, deletions, etc.) after an initial filing. However, the Commission is not yet ready to accept Form P-17 filings electronically.
TXOGA recommended that under "Important Terms," the Commission define "off-lease storage" as "storage located off lease of all of the leases included in the commingle agreement." The Commission agrees that some clarification is warranted and has added the term "off-lease" to the list of "Important Terms," and defined it as "a location or lease not listed in this commingling application."
TXOGA commented that, in the instructions for SECTION 3, Request to Commingle, that the Commission should delete references to Form P-4, because this form is currently under review and discussion, including moving transporter information to a different form. The Commission disagrees. Form P-4 has not been revised to remove transporter information. When and if that happens, the Commission will consider the need to revise Form P- 17.
In the instructions for SECTION 4, relating to notice requirements and allocation methods, TXOGA recommended that the Commission add instructions for "Box 4.b." The Commission disagrees with this comment. As stated in §3.26(b)(1)(A), the Commission may administratively approve surface commingling when one of several conditions is met; one condition is that the tracts or Commission-designated reservoirs have identical working interest and royalty interest ownership in identical percentages and, therefore, there is no commingling of separate interests. Because the language is in §3.26(b)(1)(A), the Commission finds that the recommended statement is unnecessary. The Commission made no change in response to this comment.
The Commission amends §3.50(a) to add a reference to Texas Tax Code, §202.0545, Tax Exemption for Enhanced Recovery Projects Using Anthropogenic Carbon Dioxide.
The Commission amends §3.50(c) to add a definition for anthropogenic carbon dioxide. The Commission defines anthropogenic carbon dioxide to mean carbon dioxide produced as a result of human activities. Potential sources of relatively large quantities of anthropogenic carbon dioxide include ammonia plants, gas plants, and gasification plants. In subsection (h)(2)(B), the Commission adds a reference to anthropogenic carbon dioxide.
The Commission adds new subsection (k), pertaining to the standards and procedures applicable to obtaining an additional tax reduction for an enhanced recovery project using anthropogenic carbon dioxide. New subsection (k)(1) states that, subject to the limitations provided by Texas Tax Code, §202.0545, until the later of the seventh anniversary of the date that the Comptroller first approves an application for a tax rate reduction under this subsection or the effective date of a final rule adopted by the United States Environmental Protection Agency regulating carbon dioxide as a pollutant, the producer of oil recovered through an EOR project that qualifies under Texas Tax Code, §202.054, for the recovered oil tax rate provided by Texas Tax Code, §202.052(b), is entitled to an additional 50 percent reduction in that tax rate if, in the recovery of the oil, the EOR project uses carbon dioxide that is captured from an anthropogenic source in this state; would otherwise be released into the atmosphere as industrial emissions; is measurable at the source of capture; and is sequestered in one or more geological formations in this state following the EOR process.
New subsection (k)(2) states that, in the event that a portion of the carbon dioxide used in the EOR project is anthropogenic carbon dioxide that satisfies the criteria of paragraph (1) of subsection (k) and a portion of the carbon dioxide used in the project fails to satisfy the criteria of paragraph (1) because it is not anthropogenic, the tax reduction provided by paragraph (1) shall be reduced to reflect the proportion of the carbon dioxide used in the project that satisfies the criteria of paragraph (1).
New subsection (k)(3) states that, in order to qualify for the tax rate reduction, the operator must apply for a certification from the Railroad Commission of Texas, if carbon dioxide used in the project is to be sequestered in an oil or natural gas reservoir and apply to the Comptroller for the reduction and include with the application any information and documentation that the Comptroller may require.
New subsection (k)(4) contains the application requirements. To qualify for the reduced recovered oil tax rate, the operator must submit an application for approval on the appropriate form. All applications must be filed at the Commission's Austin Office, provide the Commission with any relevant information required to administer this subsection such as plats showing the proposed project area and all wells within the area, production and injection history, planned enhanced oil recovery procedures, and any other pertinent data. The application must be executed and certified as provided for on the application form.
New subsection (k)(5) states that the Commission may issue the certification for the reduced tax rate under this subsection only if the Commission finds that, based on substantial evidence, there is a reasonable expectation that the operator's planned sequestration program will ensure that at least 99 percent of the anthropogenic carbon dioxide will remain sequestered for at least 1,000 years and the operator's planned sequestration program will include appropriately designed monitoring and verification measures that will be employed for a period sufficient to demonstrate whether the sequestration program is performing as expected.
New subsection (k)(6) states that the operator is responsible for making application to the Comptroller for the additional tax rate reduction.
New subsection (k)(7) states that the tax rate reduction does not apply if the operator's sequestration program or monitoring and verification measures differ substantially from the planned program approved by the Commission and that the operator will be required to refund the difference between the amount of the tax paid under this section and the amount that would have been imposed in the absence of this section.
New subsection (k)(8) provides that, in conjunction with the Annual Report required to be filed under §3.50(h), an operator must submit information concerning the operator's monitoring and verification measures results as proposed in the application for certification to demonstrate whether the sequestration program is performing as expected.
New subsection (k)(9) provides that a Commission representative may administratively approve or deny an application for certification. If the Commission representative administratively denies an application, the applicant has the right to a hearing upon request. After hearing, the examiner will recommend final action by the Commission.
The Commission also amends §3.80, Commission Oil and Gas Forms, Applications, and Filing Requirements, to add a new form and amend or delete other forms. The Commission adopts new Form H-12A, Application for Certification for Additional Tax Rate Reduction for Enhanced Recovery Projects Using Anthropogenic Carbon Dioxide. The form requests information necessary for Commission staff to determine whether the proposed project meets the statutory requirements in Texas Tax Code, §202.0545. The proposed project must qualify for the tax rate reduction in Texas Tax Code, §202.054, before it can be considered for the additional tax rate reduction in Texas Tax Code, §202.0545; therefore, the form requests the EOR project's certification number and date of certification for the tax rate reduction under Texas Tax Code, §202.054. If the project is new, the applicant must also submit Form H-12A with Form H-12, New or Expanded Enhanced Oil Recovery Project and Area Designation Approval Application. Items 6, 7, and 9 on Form H-12A request information to determine whether the proposed project meets the criteria included in Texas Tax Code, §202.0545. Item 8 of Form H-12A requests the percentage of injection fluid that is anthropogenic carbon dioxide, because the additional tax rate reduction is proportional to the percentage of anthropogenic carbon dioxide that satisfies the criteria. Form H-12A must be signed by a person authorized to make the application and knowledgeable of the data and facts contained in the application.
The Commission also amends Form H-14, Enhanced Oil Recovery Reduced Tax Annual Report, to provide a space to report the annual injection volume of anthropogenic carbon dioxide.
The Commission amends Form P-5LC, Irrevocable Documentary Blanket Letter of Credit, to replace the reference to Uniform Customs and Practices (UCP) #500 with UCP #600, and to replace the revision date of 1993 with 2007. The revision from #500 to #600 was effective on July 1, 2007.
The Commission also revises the effective date indicated on Table 1 for Form P-13, Application of Landowner to Condition an Abandoned Well for Fresh Water Production, to correct the last revision date from 1979 to October 2004.
The Commission revises Form P-17, Application for Exception to Statewide Rules 26 and/or 27 (Commingling), and deletes from Table 1 Form P-17A, Interim Commingling/Measurement Application Supplement. The Commission has consolidated the Form P-17 for oil and gas in order to streamline the reporting process and facilitate internal processing. Changes to the Form P-17 include clearer instructions and broader reporting options that allow an RRC identifier to be used when identifying commingled leases that are pending a lease number assignment. The revised Form P-17 also includes an attachment page for ease of filing multiple leases on one commingling permit application. Form P-17 will require data in a format that is more compatible with the Commission's automated production reporting system, which will result in more efficient tracking of commingled production.
The Commission deletes from Table 1 Form W-1X, Application for Future Re-Entry of Inactive Wellbore and 14(b)(2) Extension Permit, because this form is no longer necessary. The Commission amends Table 1 to delete the Franchise Tax Certification form. The 77th Texas Legislature (2001) repealed the statutory requirement for such certification. These form modifications may be viewed online at www.rrc.state.tx.us/rules/proposed.html.
The Commission adopts the amendments to §3.50 and §3.80 to incorporate the changes made by HB 3732, 80th Legislature (2007), Regular Session. These changes are made pursuant to Texas Natural Resources Code, §81.051 and §81.052, which provide the Commission with jurisdiction over all persons owning or engaged in drilling or operating oil or gas wells and persons owning or operating pipelines in Texas and the authority to adopt all necessary rules for governing and regulating persons and their operations under Commission jurisdiction; Texas Natural Resources Code, §§85.042, 85.202, 86.041, and 86.042, which require the Commission to adopt rules to control waste of oil and gas; and Texas Tax Code, §202.0545, relating to Tax Exemption for Enhanced Recovery Projects Using Anthropogenic Carbon Dioxide.
Statutory authority: Texas Natural Resources Code, §§81.051, 81.052, 85.024, 85.202, 86.041, and 86.042; and Texas Tax Code, §202.0545.
Cross-reference to statute: Texas Natural Resources Code, §§81.051, 81.052, 85.042, 85.202, 86.041, and 86.042; and Texas Tax Code, §202.0545.
Issued in Austin, Texas, on December 18, 2007.
§3.50.Enhanced Oil Recovery Projects--Approval and Certification for Tax Incentive.
(a) Purpose. The purpose of this section is to provide a procedure by which an operator can obtain Railroad Commission approval and certification of enhanced oil recovery (EOR) projects pursuant to Texas Tax Code, §202.052, §202.054, and §202.0545.
(b) Applicability.
(1) This section applies to:
(A) new EOR projects and the change from secondary EOR projects to tertiary projects which qualify as new EOR projects, and which begin active operation on or after September 1, 1989; and
(B) expansions of existing EOR projects.
(2) An EOR project may not qualify as an expansion if the project has qualified as a new EOR project under this section.
(c) Definitions. The following words and terms, when used in this section, shall have the following meanings, unless the context clearly indicates otherwise.
(1) Active operation--The start and continuation of a fluid injection program for a secondary or tertiary recovery project to enhance the displacement process in the reservoir. Applying for permits and moving equipment into the field alone are not considered active operations.
(2) Anthropogenic carbon dioxide--Carbon dioxide produced as a result of human activities.
(3) Commission--The Railroad Commission of Texas.
(4) Commission representative--A commission employee authorized to act for the commission. Any authority given to a commission representative is also retained by the commission. Any action taken by the commission representative is subject to review by the commission.
(5) Comptroller--The Comptroller of Public Accounts.
(6) Enhanced oil recovery project (EOR)--The use of any process for the displacement of oil from the reservoir other than primary recovery and includes the use of an immiscible, miscible, chemical, thermal, or biological process. This term does not include pressure maintenance or water disposal projects.
(7) Existing enhanced recovery project--An EOR project that has begun active operation but was not approved by the Commission as a new EOR project.
(8) Expanded enhanced recovery project or expansion--The addition of injection and producing wells, the change of injection pattern, or other commission approved operating changes to an existing enhanced oil recovery project that will result in the recovery of oil that would not otherwise be recovered.
(9) Fluid injection--Injection through an injection well of a fluid (liquid or gaseous) into a producing formation as part of an EOR project.
(10) Incremental production--The volume of oil produced by an expanded enhanced recovery project in excess of the production decline rate established under conditions before expansion of an existing enhanced recovery project.
(11) Oil recovery from an enhanced recovery project--The oil produced from the designated area the commission certifies to be affected by the project.
(12) Operator--The person recognized by the commission as being responsible for the actual physical operation of an EOR project and the wells associated with the EOR project.
(13) Positive production response--Occurs when the rate of oil production from wells within the designated area affected by an EOR project is greater than the rate that would have occurred without the project.
(14) Pressure maintenance--The injection of fluid into the reservoir for the purpose of maintaining the reservoir pressure at or near the bubble point or other critical pressure wherein fluid injection volumes are not sufficient to refill existing reservoir voidage in the approved project area and displace oil that would not be displaced by primary recovery operations.
(15) Primary recovery--The displacement of oil from the reservoir into the wellbore(s) by means of the natural pressure of the oil reservoir, including artificial lift.
(16) Production decline rate--The projected future oil production from a project area as extrapolated by a method approved by the commission.
(17) Recovered oil tax rate--The tax rate provided by the Tax Code, §202.052(b).
(18) Secondary recovery project--An enhanced recovery project that is not a tertiary recovery project.
(19) Termination--Occurs when the approved fluid injection program associated with an EOR project stops or is discontinued.
(20) Tertiary recovery project--An EOR project using a tertiary recovery method (as defined in the federal June 1979 energy regulations referred to in the Internal Revenue Code of 1986, §4993, or approved by the United States secretary of the treasury for purposes of administering the Internal Revenue Code of 1986, §4993, without regard to whether that section remains in effect) including those listed as follows:
(A) Alkaline (or caustic) flooding--An augmented waterflooding technique in which the water is made chemically basic as a result of the addition of alkali metals.
(B) Carbon dioxide augmented waterflooding--Injection of carbonated water, or water and carbon dioxide, to increase waterflood efficiency.
(C) Cyclic steam injection--The alternating injection of steam and production of oil with condensed steam from the same well or wells.
(D) Immiscible carbon dioxide displacement--Injection of carbon dioxide into an oil reservoir to effect oil displacement under conditions in which miscibility with reservoir oil is not obtained.
(E) In situ combustion--Combustion of oil in the reservoir, sustained by continuous air injection, to displace unburned oil toward producing wells.
(F) Microemulsion, or micellar/emulsion, flooding--An augmented waterflooding technique in which a surfactant system is injected in order to enhance oil displacement toward producing wells. A surfactant system normally includes a surfactant, hydrocarbon, cosurfactant, an electrolyte and water, and polymers for mobility control.
(G) Miscible fluid displacement--An oil displacement process in which gas or alcohol is injected into an oil reservoir, at pressure levels such that the injected gas or alcohol and reservoir oil are miscible. The process may include the concurrent, alternating, or subsequent injection of water. The injected gas may be natural gas, enriched natural gas, a liquefied petroleum gas slug driven by natural gas, carbon dioxide, nitrogen, or flue gas. Gas cycling, i.e., gas injection into gas condensate reservoirs, is not a miscible fluid displacement technique nor a tertiary enhanced recovery technique within the meaning of this section.
(H) Polymer augmented waterflooding--Augmented waterflooding in which organic polymers are injected with the water to improve a real and vertical sweep efficiency.
(I) Steam drive injection--The continuous injection of steam into one set of wells (injection wells) or other injection source to effect oil displacement toward and production from a second set of wells (production wells).
(21) Water disposal project--The injection of produced water into the reservoir for the purpose of disposing of the produced water wherein the water injection volumes are not sufficient to refill existing reservoir voidage in the approved project area and displace oil that would not be displaced by primary recovery operations.
(d) Application requirements. To qualify for the recovered oil tax rate the operator shall:
(1) submit an application for approval on the appropriate form. All applications must be filed at the Commission's Austin office. The form shall be executed and certified by a person having knowledge of the facts entered on the form. If an application is already on file under the Natural Resources Code, Chapter 101, Subchapter B, or for approval as a tertiary recovery project for purposes of the Internal Revenue Code of 1986, §4993, the operator may file a new EOR project and area designation application if the active operation of the project does not begin before the application under this section is approved by the Commission;
(2) submit all necessary forms to the Oil and Gas Division and provide the Commission with any relevant information required to administer this section such as: area plats showing the proposed project area and all injection and producing wells within the area, production and injection history, planned enhanced oil recovery procedures, and any other pertinent data;
(3) obtain a unitization agreement if required for purposes of carrying out the project under the Natural Resources Code, Chapter 101, Subchapter B. The Commission may not approve the project unless the unitization is approved; and
(4) submit an application on the appropriate form and obtain the necessary permits to conduct fluid injection operations pursuant to §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) (Statewide Rule 46), if such permits have not already been obtained.
(e) Concurrent applications. The operator may file concurrently:
(1) an application for approval of a new or expanded EOR project under this section, together with;
(2) an application for approval of a unitization agreement for purposes of carrying out the enhanced oil recovery project under the Natural Resources Code, §§101.001 et seq.; or
(3) an application for approval for certification of the project as a tertiary recovery project.
(f) Opportunity for hearing. A commission representative may administratively approve the application. If the commission representative denies administrative approval, the applicant shall have the right to a hearing upon request. After hearing, the examiner shall recommend final action by the commission.
(g) Approval and certification.
(1) Project approval. In order to be eligible for the recovered oil tax rate as provided in the Tax Code, §202.052(b), the operator shall apply for and be granted Commission approval of a new EOR project or an expansion of an existing EOR project, prior to commencing active operation of the new project or expanded project. For a project to be approved the operator shall:
(A) prove that it qualifies as an EOR project;
(B) designate the area to be affected by the project and obtain Commission approval of the designation; and
(C) if production from the wells within the project area is reported with production from wells not in the project area, designate the method to account for and report production from the project area.
(2) Positive production response certificate.
(A) The operator of an EOR project that meets the requirements of this section shall demonstrate to the Commission a positive oil production response before the operator can receive Commission certification of such a positive production response. The certification date may be any date desired by the operator, subject to Commission approval, following the date on which a positive oil production response first occurred. The operator shall apply for a positive production response certificate within three years of project approval for secondary projects, and within five years of project approval for tertiary projects, to qualify for the recovered oil tax rate. The oil produced from the designated area of a new EOR project or incremental oil produced from the designated area of an expanded EOR project after the date of certification of a positive production response is eligible for the recovered oil tax rate. The operator shall apply to the comptroller pursuant to the Tax Code, §202.052 and §202.054, to qualify for the recovered oil tax rate.
(B) The application for positive response certification shall include:
(i) production and injection graphs with supporting tabular data illustrating a positive production response and volumes of water or other substances that have been injected on the designated area since the initiation of the new or the expanded EOR project;
(ii) a plat of the affected area showing all injection and producing wells, with completion dates; and
(iii) any other data requested by the Oil and Gas Division.
(C) The application for the positive production response certificate shall be processed administratively. If the Commission representative denies administrative approval, the applicant shall have the right to a hearing upon request. After hearing, the examiner shall recommend final action by the Commission.
(h) Annual reporting.
(1) The operator shall file an annual report on the appropriate form with the Oil and Gas Division each year the project remains eligible for the reduced severance tax rate. This form shall be filed within 30 days of the first anniversary of the date that the Commission acted on the EOR positive production response certification application and annually thereafter.
(2) The report shall contain the following:
(A) Commission certification date of positive production response;
(B) monthly volume of injected fluid(s) and anthropogenic carbon dioxide;
(C) number of well(s) used for injection;
(D) monthly production of oil, gas, and water;
(E) number of active producing wells; and
(F) any other relevant information requested by the Oil and Gas Division.
(i) Reduced or enlarged areas. The operator may apply for reduced or enlarged project area certification if the application for reduction or enlargement is received prior to the filing of an application for positive production response certification of the original enhanced oil recovery project.
(j) Termination and penalty. Upon approval by the Commission and the comptroller, the recovered oil tax rate shall continue for a maximum of 10 years, unless the project is sooner terminated. If the project is terminated prior to the 10-year period, the operator shall notify the Commission and the comptroller in writing within 30 days after the last day of active operations. Failure to so notify may result in civil penalties, interest, and the tax due. If the Commission determines a project has been terminated or there is action that affects the tax rate, it shall notify the comptroller immediately in writing.
(k) Additional tax rate reduction for enhanced recovery projects using anthropogenic carbon dioxide.
(1) Subject to the limitations provided by Texas Tax Code, §202.0545, until the later of the seventh anniversary of the date that the Comptroller of Public Accounts first approves an application for a tax rate reduction under this subsection or the effective date of a final rule adopted by the United States Environmental Protection Agency regulating carbon dioxide as a pollutant, the producer of oil recovered through an EOR project that qualifies under Texas Tax Code, §202.054, for the recovered oil tax rate provided by Texas Tax Code, §202.052(b), is entitled to an additional 50 percent reduction in that tax rate if in the recovery of the oil the EOR project uses carbon dioxide that:
(A) is captured from an anthropogenic source in this state;
(B) would otherwise be released into the atmosphere as industrial emissions;
(C) is measurable at the source of capture; and
(D) is sequestered in one or more geological formations in this state following the EOR process.
(2) In the event that a portion of the carbon dioxide used in the EOR project is anthropogenic carbon dioxide that satisfies the criteria of paragraph (1) of this subsection and a portion of the carbon dioxide used in the project fails to satisfy the criteria of paragraph (1) of this subsection because it is not anthropogenic, the tax reduction provided by paragraph (1) of this subsection shall be reduced to reflect the proportion of the carbon dioxide used in the project that satisfies the criteria of paragraph (1) of this subsection.
(3) To qualify for the tax rate reduction under this subsection, the operator shall:
(A) apply for a certification from the Commission if carbon dioxide used in the project is to be sequestered in an oil or natural gas reservoir; and
(B) apply to the Comptroller of Public Accounts for the reduction and include with the application any information and documentation that the comptroller may require.
(4) To qualify for the additional reduced recovered oil tax rate under this subsection the operator shall:
(A) submit an application for certification to the Commission's Austin Office for approval on the appropriate form that is executed and certified as provided for on the form; and
(B) provide the Commission with:
(i) plats showing the proposed project area and all wells within the area;
(ii) production and injection history;
(iii) planned enhanced oil recovery procedures;
(iv) information to demonstrate that the carbon dioxide to be injected is anthropogenic and a description of the method(s) of capturing and measuring the captured carbon dioxide at the source;
(v) a description of the planned sequestration program reasonably expected to ensure that at least 99% of the sequestered carbon dioxide will remain sequestered for at least 1,000 years;
(vi) planned monitoring and verification measures, including the planned duration of such measures, that will be employed to demonstrate that the sequestration program is performing as expected; and
(vii) any other pertinent information requested by the Commission.
(5) The Commission may issue the certification for the reduced tax rate under this subsection only if the Commission finds that, based on substantial evidence, there is a reasonable expectation that:
(A) the operator's planned sequestration program will ensure that at least 99 percent of the anthropogenic carbon dioxide sequestered will remain sequestered for at least 1,000 years; and
(B) the operator's planned sequestration program includes appropriately designed monitoring and verification measures that will be employed for a period sufficient to demonstrate whether the sequestration program is performing as expected.
(6) The operator is responsible for making application to the Comptroller of Public Accounts for the additional tax rate reduction.
(7) The additional tax rate reduction under this subsection does not apply and the operator will be required to repay the amount of tax that would have been imposed in the absence of this subsection if the operator's sequestration program or the operator's monitoring and verification measures differ substantially from the planned program approved by the Commission.
(8) In conjunction with the Annual Report required to be filed under subsection (h) of this section, an operator shall submit information concerning the operator's monitoring and verification measures results as proposed in the application for certification to demonstrate whether the sequestration program is performing as expected. In the event that the operator's sequestration program, including monitoring and verification measures, differs substantially from the program certified by the Commission under subsection (k)(5) of this section, the operator shall include with the Annual Report a written description of any material changes in the sequestration program.
(9) A Commission representative may administratively approve or deny an application for certification. If the Commission representative administratively denies an application, the applicant shall have the right to a hearing upon request. After hearing, the examiner shall recommend final action by the Commission.
§3.80.Commission Oil and Gas Forms, Applications, and Filing Requirements.
(a) Forms. Forms required to be filed at the Commission shall be those prescribed by the Commission as listed in Table 1 of this subsection. A complete set of all Commission forms listed on Table 1 required to be filed at the Commission shall be kept by the Commission secretary and posted on the Commission's web site. Notice of any new or amended forms shall be issued by the Commission. For any required or discretionary filing, an organization may either file the prescribed form on paper or use any electronic filing process in accordance with subsections (e) or (f) of this section, as applicable. The Commission may at its discretion accept an earlier version of a prescribed form, provided that it contains all required information and meets the requirements of subsection (e)(3) of this section.
Figure: 16 TAC §3.80(a) (.pdf)
(b) Definitions. The following words and terms, when used in this section, shall have the following meanings, unless the context clearly indicates otherwise.
(1) Commission--The Railroad Commission of Texas.
(2) Electronic filing process--An electronic transmission to the Commission in a prescribed form and/or format authorized by the Commission and completed in accordance with Commission instructions.
(3) Form--A printed or typed paper document or electronic submission, including any necessary instructions, with blank spaces for insertion of required or requested specific information.
(4) Organization--Any person, firm, partnership, joint stock association, corporation, or other organization, domestic or foreign, operating wholly or partially within this state, acting as principal or agent for another, for the purpose of performing operations within the jurisdiction of the Commission.
(5) Position of ownership or control--A person holds a position of ownership or control in an organization if the person is:
(A) an officer or director of the organization;
(B) a general partner of the organization;
(C) the owner of an organization which is a sole proprietorship;
(D) the owner of more than a 25 percent ownership interest in the organization; or
(E) the designated trustee of the organization.
(6) Violation--Non-compliance with a statute, Commission rule, order, license, permit, or certificate relating to safety or the prevention or control of pollution.
(c) Organization eligibility. The Commission may not accept an organization report or an application for a permit, or approve a certificate of compliance if:
(1) the organization that submitted the report, application, or certificate violated a statute or Commission rule, order, license, certificate, or permit that relates to safety or the prevention or control of pollution; or
(2) any person who holds a position of ownership or control in the organization has, within the seven years preceding the date on which the report, application, or certificate is filed, held a position of ownership or control in another organization, and during that period of ownership or control the other organization violated a statute or Commission rule, order, license, permit, or certificate that relates to safety or the prevention or control of pollution.
(d) Violations. An organization has committed a violation if there is either a Commission order against an organization finding that the organization has committed a violation and all appeals have been exhausted or an agreed order entered into by the Commission and an organization relating to an alleged violation, and:
(1) the conditions that constituted the violation or alleged violation have not been corrected;
(2) all administrative, civil and criminal penalties, if any, relating to the violation or agreed settlement relating to an alleged violation have not been paid; or
(3) all reimbursements of costs and expenses, if any, assessed by the Commission relating to the violation or to the alleged violation have not been collected.
(e) Authorization and standards for electronic filing.
(1) An organization may file electronically any form listed on Table 1 for which the Commission has provided an electronic version, provided that the organization pays all required filing fees and complies with all requirements, including but not limited to security procedures, for electronic filing.
(2) The Commission deems an organization that files electronically or on whose behalf is filed electronically any form, as of the time of filing, to have knowledge of and to be responsible for the information filed on the form, pursuant to the statutory requirements, restrictions, and standards found in and pertaining to:
(A) Texas Natural Resources Code, Title 3 (oil and gas well drilling, production, and plugging);
(B) Texas Natural Resources Code, Title 5 (geothermal resources);
(C) Texas Natural Resources Code, Title 11 (hazardous liquids storage);
(D) Texas Utilities Code, Chapter 121, Subchapter I (sour gas pipeline facilities);
(E) Texas Water Code, §26.131 (discharge permits);
(F) Texas Water Code, Chapter 27 (class II injection and disposal wells and class III brine mining wells);
(G) Texas Water Code, Chapter 29 (oil and gas waste haulers);
(H) Texas Health and Safety Code, §401.415 (oil and gas naturally occurring radioactive material (NORM) waste); and
(I) Texas Administrative Code, Title 16, Chapter 3 (Oil and Gas Division) and Chapter 4 (Environmental Protection).
(3) All forms that an organization submits or that are submitted on behalf of an organization shall be transmitted in the manner prescribed by the Commission that is compatible with its software, equipment, and facilities.
(4) The Commission may provide notice electronically to an organization of, and may provide an organization the ability to confirm electronically, the Commission's receipt of a form submitted electronically by or on behalf of that organization.
(5) The Commission deems that the signature of an organization's authorized representative appears on each form submitted electronically by or on behalf of the organization, as if this signature actually appears, as of the time the form is submitted electronically to the Commission.
(6) The Commission holds each organization responsible, under the penalties prescribed in Texas Natural Resources Code, §91.143, for all forms, information, or data that an organization files or that are filed on its behalf. The Commission charges each organization with the obligation to review and correct, if necessary, all forms or data that an organization files or that are filed on its behalf.
(f) Other electronic transmissions. The Commission may at its discretion accept other documents or data electronically transmitted.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706415
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: January 7, 2008
Proposal publication date: October 26, 2007
For further information, please call: (512) 475-1295
The Railroad Commission of Texas adopts amendments in 16 Texas Administrative Code, Chapter 9, Subchapter A, to §§9.1 - 9.3, new 9.4, amendments to §§9.7, 9.17, 9.21, 9.27, 9.28, new §9.32, amendments to §§9.35, 9.37, and 9.41, relating to Application of Rules, Severability, and Retroactivity; Definitions; LP-Gas Report Forms; Records and Enforcement; Application for License and License Renewal Requirements; Designation and Responsibilities of Company Representative and Operations Supervisor; Franchise Tax Certification and Assumed Name Certificates; Application for an Exception to a Safety Rule; Reasonable Safety Provisions; Consumer Safety Notification; Written Procedure for LP-Gas Leaks; Termination of LP-Gas Service; and Testing of LP-Gas Systems in School Facilities.
In Subchapter B, with a new title of LP-Gas Installations, Containers, Appurtenances, and Equipment Requirements, the Commission adopts amendments to §§9.101, 9.114, 9.129, 9.130, 9.131, 9.134, 9.135, 9.136, 9.137, 9.140, 9.141, 9.142, and 9.143, relating to Filings Required for Stationary LP-Gas Installations; Odorizing and Reports; Manufacturer's Nameplate and Markings on ASME Containers; Commission Identification Nameplates; 200 PSIG Working Pressure Stationary Vessels; Connecting Container to Piping; Unsafe or Unapproved Containers, Cylinders, or Piping; Filling of DOT Containers; Inspection of Containers at Each Filling; Uniform Protection Standards; Uniform Safety Requirements; LP-Gas Container Storage and Installation Requirements; and Bulkhead, Internal Valve, API 607 Ball Valve, and ESV Protection for Stationary LP-Gas Installations with Individual or Aggregate Water Capacities of 4,001 Gallons or More.
In Subchapter C, the Commission adopts amendments to §§9.206, 9.208, and 9.211, relating to Vehicle Identification Labels; Testing Requirements; and Markings.
In Subchapter D, the Commission adopts amendments to §§9.301, 9.302, 9.303, 9.306, 9.307, 9.308, 9.311, 9.312, and 9.313, relating to Adoption by Reference of NFPA 54; Clarification of Certain Terms Used in NFPA 54; Exclusion of NFPA, §10.29; Room Heaters in Public Buildings; Identification of Converted Appliances; Identification of Piping Installation; Special Exceptions for Agricultural and Industrial Structures Regarding Appliance Connectors and Piping Support; Certification Requirements for Joining Methods; and Sections in NFPA 54 Adopted with Additional Requirements or Not Adopted.
In Subchapter E, the Commission adopts amendments to §§9.401-9.403, relating to Adoption by Reference of NFPA 58; Clarification of Certain Terms Used in NFPA 58; and Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes or Additional Requirements.
Sections 9.2, 9.7, 9.35, 9.37, 9.129, 9.134, 9.137, 9.140, 9.143, and 9.313 are adopted with changes, and the remaining sections are adopted without changes from the versions published in the October 26, 2007, issue of the Texas Register (32 TexReg 7583).
The Commission received comments from two individuals and from the Texas Propane Gas Association (TPGA).
One commenter stated that in the definition of "transfer equipment" in §9.2(53), bulkhead should also be included as transfer equipment. The Commission agrees and has made this change.
TPGA commented that it supports the recordkeeping requirements in proposed new §9.4 to go along with removing the tagging requirements in §§9.141, 9.206, 9.307, and 9.308.
A commenter challenged the wording in §9.7, and asked why, if one is exempted from licensing, one still needs to get a license. The commenter said this wording contradicts Texas Natural Resources Code, §§113.003, 113.081, and 113.082. The Commission agrees that the wording should be clarified, and adopts subsection (c) to read: "A state agency or institution, county, municipality, school district, or other governmental subdivision is exempt from licensing requirements as provided in §113.081(g) if the entity is performing work for itself on its own behalf, but is required to be licensed to perform work for or on behalf of a second party."
Regarding §9.17(a)(3), which requires a telephone number be posted at an outlet with the number of the operations supervisor or the certified employee responsible for that outlet, who must monitor the telephone number and respond to calls during normal business hours, one commenter disagreed with this change. The commenter does not want the general public contacting the company's drivers based on the information provided by this sign. Many times, this telephone number would be for a cell phone, and that would be an extra cost for the company. The commenter stated his company would provide specific contact phone numbers for any of his company's storage locations in Texas if needed.
The Commission disagrees with this comment. The proposed amendment clarified a previous rulemaking, which eliminated a long-standing requirement that affected licensees with multiple outlets. The previous rule required an operations supervisor who had passed a manager's examination with the Commission to supervise each outlet. The Commission removed that requirement but continued to require that someone with an employee certification must be assigned as the responsible person for each outlet that operated without an operations supervisor. This was strictly a safety requirement; if there was a problem with an outlet, the Commission must be able to locate a company employee to address the problem. The proposed amendment in §9.17(a) provides an option of posting at an outlet the telephone number of the certified employee assigned as the responsible person for that outlet, or the operations supervisor's telephone number. The Commission finds that this requirement is reasonable because it gives the licensee an option to either employ an operations supervisor at every outlet or have a certified employee's telephone number posted. The Commission and local emergency responders must be able to contact a responsible, Commission-certified employee to discuss inspection results and safety issues at every outlet.
The Commission adopts a change in §9.35 to add a title on the table in the rule.
Regarding §9.37, a commenter stated that the new wording conflicts with Natural Resources Code, §113.234, because the statute states a tag "shall" be attached to an unsafe installation, not "may be." The commenter understood the reason for the proposed change, but suggested that the statute should be changed. The Commission proposed these amendments to allow the Safety Division the option of affixing a warning tag or taking alternate measures to address a hazardous situation. Warning tags can be intentionally or unintentionally obliterated or removed, or go unnoticed by personnel servicing the equipment. In addition, §9.37(a) mandates that a warning tag, once affixed, must be removed by the Division, which can create a conflict between the Division's ability to schedule a Commission employee to remove the warning tag, and the need of the licensee or owner of the equipment to return it to service once the hazard has been mitigated. The Commission agrees that the wording should be clarified; therefore, the Commission adopts the following wording for the last two sentences of subsection (a): "A warning tag shall be installed by the Division until the unsafe condition is remedied. Once the unsafe condition is corrected, the tag may be removed if authorized by the Division." The Commission finds that this wording more accurately reflects the Commission's intent: the warning tag shall be installed by the Division, and may be removed if authorized by the Division.
Regarding §9.101, one commenter suggested deleting the nonrefundable $35 fee required for any resubmission of LPG Form 501, stating that the fee is unreasonable. The Commission disagrees with the comment and notes that the $35 resubmission fee became effective September 1, 2005, and was not part of this proposed rulemaking.
TPGA proposed to change §9.101(a)(2) which currently requires a nonrefundable fee of $10 for each LP-gas container, including cylinders, each retail LP-gas cylinder exchange storage rack, and each forklift cylinder exchange rack or a forklift cylinder installation where a storage rack is not installed that is listed on LPG Form 501. A nonrefundable $35 fee is also required for any resubmission. TPGA recommended that the rule should require a nonrefundable fee of $10 when filing Form 501 for each stationary commercial LP-gas installation and recommended deleting the $35 resubmission fee. TPGA stated that the current language in §9.101 implies that an individual fee must be paid for every container, and the proposed change reflects how the rule is currently being administered by the Commission and adds clarification.
The Commission disagrees with these comments; the Commission proposed no changes in §9.101(a), so the suggested changes are outside the scope of notice for this rulemaking.
One individual commented that §9.113 should state that an appliance needs to be "installed" and maintained in accordance with its manufacturer's instructions. The Commission did not propose any amendments to §9.113 in this rulemaking and therefore cannot make any changes to the rule at this time.
Regarding the nameplate requirements in §9.129, one commenter stated that the ASME Code (ug-116-118) does not require a vessel to have a nameplate, but if the tank is thick enough, the required information can be stamped into the vessel. Stamp markings are permanent and are not subject to rust, corrosion, etc. Because of the vessel thickness, this may not be permitted on small house tanks. The Commission notes that the ASME Code may not require a nameplate, but both the current Commission's LP-Gas Safety Rules and NFPA 58 require a nameplate on ASME containers in LP-gas service. Manufacturer container information on a stainless steel nameplate, continuously fusion welded around its perimeter, eliminates the problem of damaging a vessel from stamping because of inadequate shell thickness. The ASME Code also permits nameplate attachment by means other than continuous fusion welding, but the Commission finds that the current LP-Gas Safety Rules require the most legible, secure, and durable means of providing the licensee and consumer with the manufacturer's container information. The Commission adopts the wording without changes based on these comments. The Commission adopts in §9.129(e)(12) the word "degrees" instead of the degree symbol; the degree symbol does not appear accurately in some software versions.
Two commenters offered suggestions for §9.134. An individual stated that the wording "properly tagged" should be deleted as the piping tag requirements in another section were being deleted.
TPGA stated that additional changes to §9.134 are necessary. The intent of this rule is to allow general installers and repairmen, as well as individuals outlined in §9.13, to install LP-gas piping. A propane retailer may connect to piping installed by an unlicensed person, provided that the retailer has performed a leakage test, verified the piping has been installed according to the LP-Gas Safety Rules, and filed a properly-completed LPG Form 22 with the Safety Division identifying the unlicensed person who installed the piping. If the retailer does NOT know who piped the installation, the Commission suggests that the retailer get a written statement from the owner of house or facility that the installer is unknown. The LPG Form 22 is not needed because it is not going to tell the Commission anything; however, this is not stated in the rules. Therefore, TPGA suggested the following changes in the last sentence of §9.134, in addition to the Commission's proposed amendments: "A licensee may connect to piping installed by an unlicensed person provided the licensee has performed a pressure test, verified that the accessible and visible piping has been installed according to the LP-Gas Safety Rules," delete the phrase "properly tagged the installation," and add "and filed a properly-completed LPG Form 22 with the Safety Division, identifying the unlicensed person who installed the LP-gas piping only if known." TPGA stated that adding the words "accessible and visible" would clarify the rule because much of the piping is beyond reach. As originally worded, individuals would be required to tear out walls to examine piping. TPGA also suggested deleting the phrase "properly tagged the installation" to be consistent with the proposed removal of the tagging requirements elsewhere.
The Commission agrees with both comments regarding §9.134. A licensee may not always be able to determine who installed the LP-gas piping system. However, additional clarification of this rule is outside the scope of this rulemaking; Commission staff plans to review this rule for a possible future rulemaking. The Commission has adopted the rule with two minor wording changes, one to correct the spelling of "unlicenced" to "unlicensed" in two places, and to delete the reference to "properly tagged the installation" because the tagging requirements have been deleted in adopted amendments to other rules.
Concerning §9.137, an individual commented that the new wording implies that the rule applies both to DOT and ASME vessels. Some vessels installed under or in hard places to get to on motor homes are almost impossible to inspect and it is hard to see all of the vessel for an inspection. The commenter stated that the dispensing person needs to see certain parts of the vessel for filling the vessel (ASME) and the rule needs to address this. This rule needs to define what items one needs to view in order to determine what is safe and when to refuse to fill, and state that the filler needs to make a good faith effort to inspect the vessel for defects in order to determine if it is safe or not to fill. Otherwise, the Commission will have a lot of unhappy motor home owners filing complaints and this would place a lot of liability on the LP-gas dealerships that are out of their control. The comment concluded that the rule needs to include language that states "obvious defects."
TPGA commented that the proposed changes to §9.137 add containers to the pre-fill cylinder inspection requirement which thus makes the rule applicable to ALL containers including ASME residential and motor/mobile fuel containers. In addition to the word "obvious" proposed in the rule, TPGA suggested adding "accessible and reasonable" because it is not plausible that an individual can access or inspect an entire container. TPGA also asked what warranted the proposed change to §9.137 to include all containers, and if there were incidents that justified the expansion in scope of this rule.
Another individual supported the addition of the words "accessible and reasonable" suggested by TPGA. Some motor/mobile fuel containers are mounted or situated in a fashion that does not allow full inspection.
In response to all three comments, the Commission agrees that it may not always be feasible for an individual to access or inspect an entire container, such as a motor/mobile fuel container installed under a vehicle or enclosed in a cowling. The Commission adopts the wording as follows to address those concerns and clarify the safety requirement: "In addition to NFPA 58, §§5.2.1.1, 7.2.2.11, and 5.2.2, before filling a container or cylinder, the individual filling the container or cylinder shall conduct a visual inspection of the exposed, readily accessible areas of the container or cylinder for any obvious defects. Where a container or cylinder is dented, bulged, gouged, or corroded such that the integrity of the container or cylinder is substantially reduced, the container or cylinder shall not be filled." Regarding TPGA's question as to why the change was proposed, the Commission notes that the proposal preamble stated: "In §9.137, the Commission proposes to change the word 'cylinder' in the rule title to 'container' to make the section more inclusive." The Commission notes that, while the LP-Gas Safety Rules did not previously require an inspection of ASME containers, the majority of licensees instruct employees to perform such an inspection prior to filling a container. The rule change is intended to make this "pre-fill inspection" practice standard for all licensees.
In §9.140, the Commission proposed some extensive amendments throughout the rule; however, the comments concerned only subsections (h) and (j). One individual commented that subsection (h) should be changed because forklift installations are normally at non-public places where only employees work. Because of fire marshal requirements to keep DOT cylinders outside, and because of the small amount of space, usually rented locations, and small amounts of storage (usually a few cylinders in a cylinder rack), the user is forced to place the cylinder rack outside on a loading dock in a cylinder cage. This does not create a safety hazard. This part of the rule needs to separate public and non-public places. This commenter pointed out that in the Houston area, many forklift users are in rows of warehouses where the only place to place these cylinder racks is outside on the loading platform, and concluded that Commission accident records do not support this new rule.
Another commenter stated that even though §9.140(h) sets forth uniform protection standards for protecting forklift racks, the commenter stated that forklift racks should be exempt from the uniform protection standards in this section. In subsection (h(3)(A), the commenter recommended changing six-inch wheel stops to five-inch wheel stops, which are the industry standard. A six-inch wheel stop would be a custom order.)
TPGA also suggested that forklift racks should be exempt from the uniform protection standards in §9.140(h). TPGA states that cylinder cages were designed to protect the cylinders. Some TPGA members cited examples in which an 18-wheeler or other vehicle ran into the cylinder exchange cage and no leaks were caused. TPGA stated that there is consensus among its members that cylinder exchange and forklift exchange need to be subject to different standards. There should be different standards for forklift cages, because there is less chance for an incident to occur because no members of the public are coming in or out. TPGA also suggested five-inch wheel stops instead of six-inch ones.
Regarding §9.140(j), the rule says if exceptional circumstances exist at the location of storage rack or self-service dispenser, at a later time, the Commission could require extra protection be installed. TPGA suggested striking this new wording from the rule and asked why it was proposed. TPGA stated that existing §9.28 covers such situations.
With regard to the general comments concerning §9.140(h), the Commission notes that this is not a new subsection. The proposed amendments were intended to provide a person installing a forklift cylinder rack or a 20-pound DOT cylinder rack with additional options for protecting the rack and cylinders from vehicular damage. The argument that forklift cylinders do not require protection against vehicular traffic is based on two cited examples in which an 18-wheeler or other vehicle collided with a forklift cylinder rack without incident; this does not justify removing the protection requirements for forklift cylinders in a storage rack located where it is subject to damage from vehicular traffic. In those two incidents, the Commission notes that there was no reported loss or product resulting in injury or property loss; however, safety rules are often violated without an injury or property loss occurring, yet the Commission does not consider eliminating the safety rules.
The Commission's current and proposed LP-Gas Safety Rules establish minimal safety measures for protecting 20-pound DOT portable cylinders and any size forklift cylinders in storage racks subject to damage from vehicular traffic. The Commission agrees that a cylinder rack may provide a protective envelope around cylinders in storage, but the Commission does not enforce a standard to which cylinders racks must be designed or constructed. As a result, the structural components and strength of cylinder racks may vary. In addition, the Commission does not have documentation that supports a determination that cylinder racks are designed or constructed for the purpose of protecting cylinders against vehicular damage. Cylinder racks are primarily intended to reduce the space requirements for cylinder storage, reduce the risk of cylinder theft, and, most importantly from a safety perspective, prevent tampering with valves on a cylinder, which may result in a hazardous situation. Historically, the Commission has required forklift cylinders to be stored in fenced areas, using Commission-approved cylinder racks (i.e., non-combustible metallic construction, well ventilated, and protected against damage), or cylinder racks located against non-combustible buildings in protected, well-ventilated areas.
The Commission agrees with the comment that cylinder racks located in areas that are not open to the public often have limited traffic, which is under the control and direction of personnel owning or operating the facility. Cylinder racks stored in such areas may not require crash rail, guard post, or wheel stop protection if they are not exposed to damage from vehicular traffic. However, when storage racks used to store forklift cylinders or 20-pound cylinders are subject to vehicular damage, the Commission finds that it is not practical to exempt forklift cylinder racks from such protection, but to continue to require it for storage racks containing 20-pound cylinders.
The Commission therefore disagrees with the comments recommending the exemption of forklift cylinder storage racks from protection where such racks are subject to damage from vehicular traffic.
Regarding §9.140(h)(3), the Commission agrees with the commenters that a five-inch wheel stop is the industry standard and agrees that this is adequate for this rule; the Commission has adopted this change in subsection (h)(3). As further clarification, in subsection (h)(2)(A) and (B), the Commission clarifies that the February 1, 2008, effective date applies to new installations.
Regarding TPGA's comment regarding subsection (j) and the statement that §9.28 covers such situations, the Commission agrees that subsection (j) is not necessary, but not for that reason. The Commission notes that existing subsection (f), for which the Commission proposed no changes, includes nearly identical wording to the proposed new subsection (j). Therefore, the Commission does not adopt subsection (j) because subsection (f) already applies to such installations.
Regarding §9.143, one commenter requested clarification regarding the location of the sign in subsection (e). Current rules permit a licensee to have two sets of ESVs. The rule does not address at which set of ESVs the sign should be located. The rule also needs to address the ones at the bulkhead as this is the transfer location. This commenter also stated that subsection (h) needs to have a definite date when the new guardpost requirements take place. The Commission rules for years have required guardposts, so to avoid future enforcement problems, the rule needs some wording that all guardposts installed after February 1, 2008, must comply with this new wording.
TPGA commented that the proposed new wording in §9.143 regarding use of API 607 ball valves and back flow check valves may need clarification, along with the reference to NFPA 58, §5.7.4.2, in the Table in §9.403. Specifically, the Commission's proposed changes in §5.7.4.2f stated that the valve "shall be pneumatically actuated and shall fail in the closed position." TPGA suggested that this wording should read: "shall be pneumatically actuated and normally closed type." The industry term is "normally closed," not "fail in the closed position," since the valve by design should be closed when not in use and the air applied to the actuator overrides the spring and forces the valve open, just like on an internal valve. If the actuator were to fail, the spring could be one of the reasons, and if the spring did fail, just like in an internal valve, it might fail open. So to use the term "fail in the closed position" could be challenged in a court of law.
The Commission adopts some changes to subsection (e) to clarify the time line for the various requirements. Subsection (e) is reorganized, but no additional requirements have been added. The subsection will read: "(e) In addition to NFPA 58, 5.7.4.2, as amended in the table in §9.403 of this title (relating to Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes or Additional Requirements), ESVs, internal valves, and API 607 ball valves shall have emergency remote controls conspicuously marked according to the requirements of Table 1 of §9.140 of this title (relating to Uniform Protection Standards) as follows: (1) Effective February 1, 2001, for all new facilities, where a bulkhead, internal valves, and ESVs are installed, at least one clearly identified and easily accessible manually operated remote emergency shutoff device shall be located between 20 and 100 feet from the ESV in the path of egress from the ESV. Existing installations shall have complied by August 1, 2001. (2) Beginning September 1, 2005, for new installations, at least one clearly identified and easily accessible manually operated remote emergency shutoff device shall be located between 25 and 100 feet from the ESV at the bulkhead and in the path of egress from the ESV. API 607 ball valves installed after February 1, 2008, shall also meet the requirements of this section. (3) The use of swivel-type piping as specified in subsection (d)(8) of this section shall not eliminate the requirement for an ESV. Swivel-type piping may be installed between the bulkhead and the minimum 12-inch nipple, but shall not eliminate the requirement for an ESV. The swivel-type piping shall be installed and maintained according to the manufacturer's instructions."
With regard to the wording in §9.143(f), the Commission notes that the proposed language "shall fail in the closed position" is taken directly from the 2008 edition of NFPA 58, §5.7.4.2(I). The Commission has adopted NFPA 58, with certain differences, but retains this particular wording.
Regarding the proposed amendments to §§9.206, 9.307, and 9.308, TPGA expressed support for the amendments.
The Commission adopts §9.313 with minor changes in the table to add a title to the table and to delete wording in the heading of the third column referring to underlining and strike-outs; this wording is unnecessary.
One individual commented on §9.402 regarding vessels under 4.2-pound capacity. The commenter stated that the rule should address and clarify this "in this one place" so that the Commission can get rid of all other rules referring to the 4.2-pound capacity.
The Commission disagrees that a comprehensive rule addressing all references in NFPA 58 would be preferable to the specific entries on the table, and adopts the rule and table as proposed.
The Commission's adopted amendments to §§9.2, 9.7, 9.17, 9.35, 9.41, 9.101, 9.137, 9.140, 9.141, 9.143, 9.301, 9.313, 9.401, 9.402, 9.403, and new §§9.4 and 9.32 are substantively different from the current requirements. In §9.2, the Commission adopts a new definition for "leak grades" to classify LP-gas leaks based on the danger it poses to life and property, and adopts a new definition for "self-service dispenser" used by ultimate consumers or licensees. In the definition of "transfer system," the Commission adds pumps, compressors, and meters, and bulkheads as previously discussed in this preamble, to the list of equipment to clarify the term and eliminate confusion caused by references to material handling equipment and dispensing system. The Commission broadens the definition of "ultimate consumer" to change "individual" to "person," as defined in §9.2, to include business and governmental entities.
New §9.4 addresses record keeping and enforcement issues. This section requires LP-gas licensees and registrants to retain certain documents for a specified time, and upon Commission request, make documents available for review and provide copies of documents. New subsection (b) would require the Safety Division formulate a plan or program for the periodic evaluation of LP-gas facilities and clarifies the scope of activities permitted for an authorized representative of the Commission. New subsection (d) clarifies the obligations of licensees and registrants in cooperating with the Commission in the administration and enforcement of this chapter. The Commission finds that the record keeping requirements in new §9.4 replace the tagging requirements for containers or installations as required currently in §§9.141, 9.206, 9.307, and 9.307; the Commission has eliminated the tagging requirement as discussed in this preamble.
In §9.7, the Commission adopts some clarifying wording in subsection (c) as previously discussed in this preamble. Other amendments delete the reference to LPG Form 26.
New wording in §9.17(a)(3) addresses situations in which an operations supervisor manages more than one outlet and each outlet has an assigned certified employee responsible for the outlet. A telephone number posted at the outlet with the responsible certified employee's and/or operations supervisor's telephone number provides important contact information for the public and representatives of the Commission seeking information about the operation of the outlet. That individual must monitor the telephone number and respond to calls during normal business hours.
The Commission adopts new §9.32 to address the legislative mandate requiring the Commission to adopt rules relating the notice requirement in HB 1170. The wording for the warning tag is specified in HB 1170.
The Commission adopts amendments to §9.35 to update a reference to a section in NFPA 58, and to clarify the leak grades defined by §9.2 and specify action criteria for responding to leaks. The new table provides some examples of the criteria.
In §9.41, the Commission adopts clarifying wording to require pressure tests to be performed by an LP-gas licensee, a master or journeyman plumber registered with the Commission, or if a school district employee performs the pressure test, that employee must be certified with the Commission. This requirement assures the Commission that school district personnel conducting pressure tests of systems at school facilities have passed an examination addressing applicable safety requirements.
The Commission changes the title of Subchapter B to "LP-Gas Installations, Containers, Appurtenances, and Equipment Requirements" to better describe the rules included in that subchapter.
In §9.101(c)(1)(D), the Commission replaces "material handling equipment" with "transfer system" to use the more accurate, defined term. The Commission also specifies some items to be included on the site plan. Additionally, in §9.101(c)(1)(E), the Commission requires a copy of any permit required by the Texas Department of Transportation for transportation access to a public highway. In subsection (c)(2), a reference to a section in NFPA 58 is updated.
In §9.137, the Commission changes the word "cylinder" in the rule title to "container" to make the section more inclusive. Other amendments update section references in NFPA 58, and clarify that an individual filling a container or cylinder must examine the container or cylinder for obvious defects before filling it. The 2008 edition of NFPA 58 includes ASME containers, and the amendments make this section applicable to both ASME and DOT containers. As previously discussed in this preamble, the Commission has adopted some clarifying changes.
The Commission adopts several substantive amendments to §9.140. In subsections (a) and (b)(1), references to sections in NFPA 58 are updated; also in subsection (b)(1), the Commission adds wording to allow options for fencing material where fencing is required at LP-gas facilities. This change will allow fencing material providing protection equivalent to that of chain link fencing, such as industrial or wrought iron fencing, after approval by the Safety Division. Some clarifying wording is adopted in §9.140(b)(4) to require gate posts be installed at 45 degree angles to the corner of a bulkhead to reduce the risk of transfer hoses binding on the gate posts in event of a pullaway incident. The change clarifies where gateposts are to be located in relation to a bulkhead. In §9.140(b)(5) and (7), references to "material handling equipment" are replaced with "the entire transfer system" for consistency.
Subsections (d), (d)(1), and (g) include changes to update the NFPA section references. In §9.140(d)(5), the Commission specifies a clearance requirement between a bulkhead and guard post to protect piping and transfer equipment against damage from vehicular traffic. Without a specific clearance, the opening between a bulkhead and a guard post may be large enough to allow a vehicle to enter the storage area and damage piping or transfer equipment.
In §9.140(g), the Commission updates NFPA 58 references, and in subsection (g)(5) adopts new wording to explain the new item 13 in Table 1; item 13 specifies signage requirements for outlets where a certified employee is responsible for the outlet. Amendments in subsection (g)(7) require licensees and non-licensees to comply with operational and/or procedural requirements specified by signage, such as extinguishing pilots, vacating vehicles, and not smoking. New (g)(8) clarifies requirements for the 24-hour emergency telephone number required by new item 12 in Table 1. The 24-hour emergency number must be monitored at all times and be answered by a person, not an answering machine or beeper device, who can provide LP-gas emergency response information or can immediately contact someone who can provide the information.
To prevent guard posts from being installed in contact with cylinder storage racks, the Commission adopts amendments in §9.140(h)(2)(A) and (B) to establish a minimum distance of 18 inches between a guard post and a cylinder storage rack, and to require guard posts to be securely anchored to a concrete driveway or concrete parking area. Amendments in §9.140(h)(3) clarify the options for protecting cylinder storage racks against damage from vehicular traffic when guard posts are not utilized. Instead of guard posts, concrete curbs or concrete wheel stops (adopted as five inches instead of six inches, as previously discussed in this preamble) may be used to provide protection if installed according to this section. The Commission adopts new subsection (h)(4) to require all parking wheel stops and cylinder storage racks to be secured against displacement.
The Commission adopts new §9.140(i) to provide specific requirements for protecting a self-service dispenser, as defined in §9.2, against vehicular damage. The provisions of this section provide options for protecting a self-service dispenser against damage from vehicles by allowing support columns, concrete barriers, bollards, and inverted u-shaped guard posts as protection instead of the guardrailing currently required in this chapter. However, additional safety measures apply when guardrailing is not utilized, for instance, the self-service dispenser must be equipped with a device to prevent the loss of gas in the event the dispenser is displaced, and the supply piping must be secured and installed in a manner to protect it against damage if the dispenser is displaced.
The Commission does not adopt proposed new subsection (j) as previously discussed in the preamble.
Amendments in §9.141(a), (b), (e), and (f) update existing NFPA references with references from the 2008 edition of NFPA 58. Section 9.141(c) clarifies the requirements for locking handles on ball valves by specifying that if ball-type shutoff valves two inches and larger that do not have locking handles, the main shutoff valves on stationary containers shall remain closed until a transfer hose is properly connected or disconnected. Section 9.141(i) is removed, which eliminates the requirement for attaching a decal or metal tag on a container to identify the installer. The requirement to place a tag or decal on a container with the installer's information did not enhance the safety aspects of the LP-gas installation. LP-gas installations without an installer's decal or tag are no less safe than installations with a decal or tag. Often, due to weathering or tampering a decal or tag that had been affixed to a container would become detached and be lost. The decal or tagging requirement provided the Commission with information for administering and enforcing the LP-gas safety rules. Currently, for non-residential installations, this information is obtained by the filing of a completion report with the Commission. For both residential and non-residential installations, the record keeping requirements in new §9.4 provide the Commission with needed information previously provided by a decal or tag.
The Commission adopts some substantive amendments in §9.143, including a deadline for certain equipment to be replaced. The Commission adds "API 607 Ball Valves" to the title of the rule; the 2008 edition of NFPA 58 allows the use of API 607 ball valves, utilizing an excess flow valve, in container openings that are not compatible with internal valves. Adding the use of this valve provides an option to the current safety rule requiring the installation of an excess flow valve, manual shutoff valve and an ESV when a container's opening is not compatible for installation of an internal valve. Other amendments in subsections (a), (b), (e), and (g) update NFPA references.
In §9.143(a), the Commission adopts wording to allow the use of API 607 ball valves and adds requirements for backflow check valves. Amendments in §9.143(a)(1) specify the location of a backflow check valve installed in the fixed piping at a bulkhead, and in subsection (a)(2)and (5) adds a reference to API 607 ball valves. The Commission clarifies in subsection (a)(3) the location of thermal elements required on ESV, internal valves, and API 607 ball valves. In §9.143(c), the Commission clarifies the use of ESV and backflow check valves at existing installations with horizontal bulkheads.
The Commission adopts amendments that all cable-actuated ESV be replaced with pneumatically-operated ESV by January 1, 2011. The Commission finds that this time period is reasonable because only about five percent of current LP-gas installations still use cable-actuated ESV. The rule already requires these to be replaced with pneumatically-operated ESV if any repair or maintenance is required.
In §9.143(e), the Commission adds a reference to the API 607 valves and clarifies the distance requirements for installation of remote emergency shutoffs. The Commission has adopted subsection (e) with some different formatting, as previously discussed in this preamble. Amendments in §9.143(i) specify requirements for locating remote emergency shutoff device when containers are filled through a filler valve installed directly in the tank instead of through a bulkhead.
The other substantive amendments the Commission adopts concern the adoption by reference of the 2006 edition of NFPA 54 and the 2008 edition of NFPA 58, effective February 1, 2008; these adoptions will establish consistent requirements for Texas LP-gas licensees and consumers with most other states in the United States. Because NFPA 54 and NFPA 58 have been adopted in whole or in part by most other states in the United States, the Texas LP-gas industry benefit from these adoptions because Texas companies would be held to the same standards when doing business in other states; therefore, LP-gas companies wishing to expand their businesses to other states would have a better opportunity to do so.
The Commission adopts the 2006 edition of NFPA 54 to update the 1999 edition of NFPA 54 previously adopted. The Commission also adopts by reference all other NFPA publications or portions of those publications referenced in NFPA 54 which apply to LP-gas activities only. In other words, if other LP-gas activities are to be performed by a licensee and those activities are included in an NFPA publication referenced in NFPA 54, then the licensee shall perform those activities in compliance with the referenced document. The amendments in §9.301 update the NFPA publications and edition dates. The Commission adopts amendments in §9.313 to specify some sections in NFPA 54 for which the Commission adopts additional language and one section that the Commission does not adopt; these sections are indicated in the new table in §9.313, which the Commission adopts with a change as previously discussed in the preamble.
The Commission adopts the 2008 edition of NFPA 58 in §9.401, with certain clarifications described in §9.402 and §9.403. The Commission also adopts by reference all other NFPA publications or portions of those publications referenced in NFPA 58 which apply to LP-gas activities only. In other words, if other LP-gas activities are to be performed by a licensee and those activities are included in an NFPA publication referenced in NFPA 58, then the licensee shall perform those activities in compliance with the referenced document. For example, §6.22.22 of NFPA 58 refers to another NFPA publication, NFPA 70, National Electrical Code . Licensees who will be performing LP-gas activities authorized in §6.22.22 shall also be required to purchase that NFPA publication and perform the work to those standards.
Similar to the adoption by reference of the 2001 edition of NFPA 58, there are some sections in the 2008 edition of NFPA 58 for which the Commission adopts alternative or additional language, or which the Commission does not adopt; these sections are indicated in the table in §9.403. Most of the changes from the 2001 edition of NFPA 58 concern section number changes, but two sections are somewhat substantively different from the previously adopted requirement. In NFPA 58, §2.3.3.2(b)(2) changed to §5.7.4.2 and includes paragraph (e) allowing only one bushing to be used for reducing the size of a container opening and paragraph (f) allowing the use of API 607 ball valves in container openings that are not compatible with internal valves. Also, §8.2.3(l) requiring special provisions for the use of overfilling prevention devices on engine fuel containers when the container's fixed liquid level gauge is not used during filling has been removed and the Commission adopts the provisions of §11.4.1.15 in the 2008 edition of NFPA 48 as a whole. Other changes are nonsubstantive; many of these are changes to NFPA 58 references to containers of less than one gallon, which are exempted by Chapter 113 of the Texas Natural Resources Code.
Some of the provisions in NFPA 58 are different from what is currently in the LP-Gas Safety Rules or the 2001 edition of NFPA 58. For example, current Commission §9.403, in the reference to NFPA 58 §8.2.3(1), requires venting of gas through a fixed liquid level gauge on engine fuel containers equipped with an overfilling device unless specific provisions are followed. However, NFPA 58 §11.4.1.15 does not require venting of gas through a fixed maximum liquid level gauge during filling if an engine fuel container is equipped with an overfilling device.
Other adopted amendments in §§9.3, 9.27, 9.28, 9.129, 9.130, 9.134, 9.206, 9.208, 9.307, and 9.308 are somewhat substantive, but should not have a major effect. In §9.3, the Commission deletes references to LPG Form 26, which is no longer necessary. The Commission clarifies in §9.27 the reference to a non-stationary site, which is not a defined term, to "motor or mobile fuel installation." In §9.28, the Commission deletes the word "stationary" so that the reasonable safety provisions in this rule apply to any LP-gas installation covered by Chapter 9. In §9.129, the Commission adopts new subsection (e)(12) - (14) to conform with NFPA 58 §5.2.8.3(c); as discussed previously in this preamble, §9.129(e)(12) is adopted with a minor change. The Commission adopts new wording in §9.130 to require clear photographs of specific areas on a container. The Commission deletes the use of sketches because they were often unclear or unreadable. In §9.134, the Commission clarifies who is authorized to install piping by adding registrants authorized by §9.13 of this chapter, or individuals exempted from licensing as authorized by Texas Natural Resources Code, §113.081; as previously discussed in this preamble, §9.134 is adopted with minor changes. In §§9.206, 9.307, and 9.308, the Commission deletes the requirement for tagging containers and piping, and updates NFPA 58 references. The Commission clarifies in §9.208 who is authorized to perform testing on transport containers by adding individuals authorized by the United States Department of Transportation to conduct such tests. In §9.308, the Commission adds wording that documentation of pressure and leakage testing be retained by registrants and licensees, as specified in new §9.4.
Finally, amendments in §§9.1, 9.7, 9.21, and 9.37 are nonsubstantive and are made for clarification. The amendment in §9.1 corrects a cross-reference to Chapter 9; the adopted language added in §9.7 clarifies existing requirements. The change in §9.21 refers to information the Commission obtains from the Comptroller's office, which is no longer necessary for licensees to provide. The Commission's adopted amendment in §9.37 includes a change from the proposal, as discussed previously in this preamble. Sections for which the only adopted amendments are updates to NFPA 58 sections include §§9.114, 9.131, 9.135, 9.136, 9.142, 9.211, 9.302, 9.303, 9.306, 9.311, and 9.312.
Subchapter A. GENERAL REQUIREMENTS
16 TAC §§9.1 - 9.4, 9.7, 9.17, 9.21, 9.27, 9.28, 9.32, 9.35, 9.37, 9.41
The amendments and new rules are adopted under the Texas Natural Resources Code, §113.051, which authorizes the Commission to adopt rules relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public; and §113.052, which allows the Commission to adopt by reference the published codes of nationally recognized societies, including the National Fire Protection Association.
The Texas Natural Resources Code, §113.051 and §113.052, are affected by the adopted amendments and new rules.
Issued in Austin, Texas, on December 18, 2007.
§9.2.Definitions.
In addition to the definitions in any adopted NFPA pamphlets, the following words and terms, when used in this chapter, shall have the following meanings, unless the context clearly indicates otherwise.
(1) Advanced field training (AFT)--The final portion of the training or continuing education requirements in which an individual shall successfully perform the specified LP-gas activities in order to demonstrate proficiency in those activities.
(2) AFRED--The Commission's Alternative Fuels Research and Education Division.
(3) AFT materials--The portion of a Commission training module consisting of the four sections of the Railroad Commission's LP-Gas Qualifying Field Activities, including General Instructions, the Task Information, the Operator Qualification Checklist, and the Railroad Commission/Employer Record.
(4) Aggregate water capacity (AWC)--The sum of all individual container capacities measured by weight or volume of water which are placed at a single installation location.
(5) Applicant--An individual:
(A) who is applying for a new certificate; or
(B) whose certification has lapsed for a period of less than two years and who is applying to restore certification by paying any applicable fees and by completing any applicable training or continuing education requirements.
(6) Bobtail driver--An individual who operates an LP-gas cargo tank motor vehicle of 5,000 gallons water capacity or less in metered delivery service.
(7) Breakaway--The accidental separation of a hose from a cylinder, container, transfer equipment, or dispensing equipment, which could occur on a cylinder, container, transfer equipment, or dispensing equipment whether or not they are protected by a breakaway device.
(8) Categories of LPG activities--The LP-gas license categories as specified in §9.6 of this title (relating to Licenses and Fees).
(9) Certificate holder--An individual:
(A) who has passed the required management-level qualification examination, satisfactorily completed any applicable training or continuing education requirements as specified in §9.52 of this title (relating to Training and Continuing Education Courses), and paid the applicable fee; or
(B) who has passed the required employee-level qualification examination, paid the applicable fees, and complied with the training or continuing education requirements in §9.52 of this title (relating to Training and Continuing Education Courses); or
(C) who has passed the required employee-level qualification examination, has paid the applicable fee, and is required to comply with a training requirement as specified in §9.52 of this title (relating to Training and Continuing Education Courses); or
(D) who holds a current reciprocal examination exemption pursuant to §9.18 of this title (relating to Reciprocal Examination Agreements with Other States); or
(E) who holds a current examination exemption certificate pursuant to §9.13 of this title (relating to General Installers and Repairman Exemption).
(10) Certified--Authorized to perform LP-gas work as set forth in the Texas Natural Resources Code. Employee certification alone does not allow an individual to perform those activities which require licensing.
(11) CETP--The Certified Employee Training Program offered by the Propane Education and Research Council (PERC), the National Propane Gas Association (NPGA), or their authorized agents or successors.
(12) Commercial installation--An LP-gas installation located on premises other than a single family dwelling used as a residence, including but not limited to a retail business establishment, school, bulk storage facility, convalescent home, hospital, retail LP-gas cylinder filling/exchange operation, service station, forklift refueling facility, private motor/mobile fuel cylinder filling operation, a microwave tower, or a public or private agricultural installation.
(13) Commission--The Railroad Commission of Texas.
(14) Company representative--The individual designated to the Commission by a license applicant or a licensee as the principal individual in authority and, in the case of a licensee other than a Category P licensee, actively supervising the conduct of the licensee's LP-gas activities.
(15) Container delivery unit--A vehicle used by an operator principally for transporting LP-gas in cylinders.
(16) Continuing education--Courses required to be successfully completed at least every four years by certain certificate holders.
(17) DOT--The United States Department of Transportation.
(18) Employee--An individual who renders or performs any services or labor for compensation, including individuals hired on a part-time or temporary basis, on a full-time or permanent basis, or, for purposes of this chapter, an owner-employee.
(19) Interim approval order--The authority issued by the Railroad Commission of Texas following a public hearing allowing construction of an LP-gas installation.
(20) Leak grades--An LP-gas leak that is:
(A) a Grade 1 leak that represents an existing or probable hazard to persons or property, and requires immediate repair or continuous action until the conditions are no longer hazardous; or
(B) a Grade 2 leak that is recognized as being nonhazardous at the time of detection, but requires a scheduled repair based on a probable future hazard.
(21) Licensed--Authorized to perform LP-gas activities through the issuance of a valid license.
(22) Licensee--A person which has applied for and been granted an LP-gas license by the Commission, or who holds a master or journeyman plumber license from the Texas State Board of Plumbing Examiners or a Class A or B Air Conditioning and Refrigeration Contractors License from the Texas Department of Licensing and Regulation and has properly registered with the Commission.
(23) LP-Gas Safety Rules--The rules adopted by the Railroad Commission in the Texas Administrative Code, Title 16, Part 1, Chapter 9, including any NFPA or other documents adopted by reference. The official text of the Commission's rules is that which is on file with the Secretary of State's office and available at www.sos.state.tx.us or through the Commission's web site at www.rrc.state.tx.us.
(24) LP-gas system--All piping, fittings, valves, and equipment, excluding containers and appliances, that connect one or more containers to one or more appliances that use or consume LP-gas.
(25) Mass transit vehicle--Any vehicle which is owned or operated by a political subdivision of a state, city, or county, used primarily in the conveyance of the general public.
(26) Mobile fuel container--An LP-gas container mounted on a vehicle to store LP-gas as the fuel supply to an auxiliary engine other than the engine to propel the vehicle or for other uses on the vehicle.
(27) Mobile fuel system--An LP-gas system, excluding the container, to supply LP-gas as a fuel to an auxiliary engine other than the engine to propel the vehicle or for other uses on the vehicle.
(28) Motor fuel container--An LP-gas container mounted on a vehicle to store LP-gas as the fuel supply to an engine used to propel the vehicle.
(29) Motor fuel system--An LP-gas system, excluding the container, which supplies LP-gas to an engine used to propel the vehicle.
(30) MPS gas (Methylacetylene-propadiene, stabilized)--A mixture of gases in the liquid phase and as defined in Texas Natural Resources Code, Chapter 113, §113.002(4).
(31) Noncorrosive--Corrosiveness of gas which does not exceed the limitation for Classification 1 of the American Society of Testing Material (ASTM) Copper Strip Classifications when tested in accordance with ASTM D 1834-64, "Copper Strip Corrosion of Liquefied Petroleum (LP) Gases."
(32) Nonspecification unit--An LP-gas transport not constructed to DOT MC-330 or MC-331 specifications but which complies with the exemption in 49 Code of Federal Regulations §173.315(k). (See also "Specification unit" in this section.)
(33) Operations supervisor--The individual who is certified by the Commission to actively supervise a licensee's LP-gas operations and is authorized by the licensee to implement operational changes.
(34) Outlet--A site operated by an LP-gas licensee from which any regulated LP-gas activity is performed.
(35) Outside instructor--An individual, other than a Commission employee, approved by AFRED to teach certain LP-gas training or continuing education courses.
(36) Person--An individual, partnership, firm, corporation, joint venture, association, or any other business entity, a state agency or institution, county, municipality, school district, or other governmental subdivision, or licensee, including the definition of "person" as defined in the applicable sections of 49 CFR relating to cargo tank hazardous material regulations.
(37) Portable cylinder--A receptacle constructed to DOT specifications, designed to be moved readily, and used for the storage of LP-gas for connection to an appliance or an LP-gas system. The term does not include a cylinder designed for use on a forklift or similar equipment.
(38) Property line--The boundary which designates the point at which one real property interest ends and another begins.
(39) Public transportation vehicle--A vehicle for hire to transport persons, including but not limited to taxis, buses (excluding school buses and mass transit or special transit vehicles), or airport courtesy vehicles.
(40) Recreational vehicle--A vehicular-type unit primarily designed as temporary living quarters for recreational, camping, travel, or seasonal use that either has its own motive power or is mounted on, or towed by, another vehicle.
(41) Register (or registration)--The procedure to inform the Commission of the use of an LP-gas transport or container delivery unit in Texas.
(42) Repair to container--The correction of damage or deterioration to an LP-gas container, the alteration of the structure of such a container, or the welding on such container in a manner which causes the temperature of the container to rise above 400 degrees Fahrenheit.
(43) Rules examination--The Commission's written examination that measures an examinee's working knowledge of Chapter 113 of the Texas Natural Resources Code and/or the current LP-Gas Safety Rules.
(44) School--A public or private institution which has been accredited through the Texas Education Agency or the Texas Private School Accreditation Commission.
(45) School bus--A vehicle that is sold or used for purposes that include carrying students to and from school or related events.
(46) Self-service dispenser--A listed device or approved equipment in a structured cabinet for dispensing and metering LP-gas between containers that must be accessed by means of a locking device such as a key, card, code, or electronic lock, and which is operated by a certified employee of an LP-gas licensee or an ultimate consumer trained by an LP-gas licensee.
(47) Special transit vehicle--A vehicle designed with limited passenger capacity which is used by a school or mass transit authority for special transit purposes, such as transport of mobility impaired persons.
(48) Specification unit--An LP-gas transport constructed to DOT MC-330 or MC-331 specifications. (See also "Nonspecification unit" in this section.)
(49) Subframing--The attachment of supporting structural members to the pads of a container, excluding welding directly to or on the container.
(50) Trainee--An individual who has not yet taken and passed an employee-level rules examination.
(51) Training--Courses required to be successfully completed as part of an individual's requirements to obtain or maintain certain certificates.
(52) Transfer--The procedure to inform the Commission of a change in operator of an LP-gas transport or container delivery unit already registered with the Commission.
(53) Transfer system--All piping, fittings, valves, pumps, compressors, meters, hoses, bulkheads, and equipment utilized in dispensing LP-gas between containers.
(54) Transport--Any bobtail or semitrailer equipped with one or more containers.
(55) Transport driver--An individual who operates an LP-gas trailer or semi-trailer equipped with a container of more than 5,000 gallons water capacity.
(56) Transport system--Any and all piping, fittings, valves, and equipment on a transport, excluding the container.
(57) Ultimate consumer--The person controlling LP-gas immediately prior to its ignition.
§9.7.Application for License and License Renewal Requirements.
(a) No person shall perform work, directly supervise LP-gas activities, or be employed in any capacity requiring contact with LP-gas unless:
(1) that individual has taken and passed any applicable rules examination specified in §9.10 of this title (relating to Rules Examination) and in §9.17 of this title (relating to Designation and Responsibilities of Company Representatives and Operations Supervisors);
(2) the individual is in compliance with the training and continuing education requirements beginning in §9.51 of this title (relating to General Requirements for Training and Continuing Education), except for a trainee described in §9.12 of this title (relating to Trainees);
(3) prior to performing authorized LP-gas activities in Texas, the individual is employed by a licensee or by a license-exempt entity, such as a political subdivision or a state agency; or
(4) the individual holds a current examination exemption certificate pursuant to §9.13 of this title (relating to General Installers and Repairman Exemption) and is therefore exempt from the requirements of this subsection.
(b) A person exempt from licensing as authorized by Texas Natural Resources Code, §113.081(b), shall not engage in any LP-gas activities in commerce or in business without first obtaining a license.
(c) A state agency or institution, county, municipality, school district, or other governmental subdivision is exempt from licensing requirements as provided in §113.081(g) if the entity is performing work for itself on its own behalf, but is required to be licensed to perform work for or on behalf of a second party.
(d) Licensees, company representatives, and operations supervisors at each outlet shall have copies of all current licenses and certification cards for employees at that location available for inspection during regular business hours. In addition, licensees shall maintain a current version of the LP-Gas Safety Rules and shall provide at least one copy to each company representative and operations supervisor. The copies shall be available to employees during business hours.
(e) Licenses issued under this chapter expire one year after issuance at midnight on the last day of the month prior to the month in which they are issued.
(f) An applicant for a new license shall file with the License and Permit Section of the Gas Services Division (the Section):
(1) a properly completed LPG Form 1 listing all names under which LP-gas related activities requiring licensing are to be conducted and, for licensees engaging in LP-gas product activities as defined in Texas Natural Resources Code, §113.081(a)(4), including a 24-hour emergency response telephone number. Any company performing LP-gas activities under an assumed name ("DBA" or "doing business as" name) shall file copies of the assumed name certificates which are required to be filed with the respective county clerk's office and/or the Secretary of State's office with the Section; and
(2) LPG Form 16 or 16B and any of the following applicable forms:
(A) LPG Form 1A if the applicant will establish any outlets;
(B) LPG Form 7 and any information requested in §9.202 of this title (relating to Registration and Transfer of LP-Gas Transports or Container Delivery Units) if the applicant intends to register any LP-gas transports or container delivery units;
(C) LPG Form 19 if the applicant will be transferring the operation of an existing bulk plant, service station, cylinder filling, or portable cylinder exchange rack installation from another owner or name;
(D) LPG Form 996A or 996B if the applicant is required to carry workers' compensation; and the applicant shall also comply with §9.26 of this title (relating to Insurance Requirements);
(E) LPG Form 997A or 997B if the applicant will operate a transport or container delivery unit; and the applicant shall also comply with §9.26; and/or
(F) LPG Form 998A or 998B if the applicant is required to carry general liability; and the applicant shall also comply with §9.26;
(3) pay the following fees:
(A) the applicable license fee specified in §9.6 of this title (relating to Licenses and Fees);
(B) transport registration fees specified in §9.202 of this title (relating to Registration and Transfer of LP-Gas Transports or Container Delivery Units), if the applicant for license intends to operate a transport or container delivery unit; and
(C) the nonrefundable management-level rules examination fee specified in §9.10 of this title (relating to Rules Examination); and
(D) the nonrefundable fee for any required training course as specified in §9.51 of this title (relating to General Requirements for Training and Continuing Education).
(g) An applicant for license shall not engage in LP-gas activities governed by the Texas Natural Resources Code, Chapter 113, and the LP-Gas Safety Rules, until it has employed a company representative and/or operations supervisor who has passed the management-level rules examination specified in §9.10 of this title (relating to Rules Examination) with a score of at least 75% and who has completed any required training in §9.51 and §9.52 of this title (relating to General Requirements for Training and Continuing Education; and Training and Continuing Education Courses), or who has obtained a General Installers and Repairman Exemption as specified in §9.13 of this title (relating to General Installers and Repairman Exemption). Company representatives and operations supervisors shall also comply with §9.17 of this title (relating to Designation and Responsibilities of Company Representatives and Operations Supervisors).
(h) For license renewals, the Section shall notify the licensee in writing at the address on file with the Section of the impending license expiration at least 30 calendar days before the date a person's license is scheduled to expire. The renewal notice shall include copies of LPG Forms 1, 1A, and 7, whichever are applicable, showing the information currently on file. Renewals shall be submitted to the Section with any necessary changes clearly marked on the forms. Licensees engaging in LP-gas product activities as defined in Texas Natural Resources Code, §113.081(a)(4), shall include on LPG Form 1 a 24-hour emergency response telephone number, if not previously submitted, along with the license renewal fee specified in §9.6 of this title (relating to Licenses and Fees) and any applicable transport registration fee specified in §9.202 of this title (relating to Registration and Transfer of LP-Gas Transports or Container Delivery Units) on or before the last day of the month in which the license expires in order for the licensee to continue LP-gas activities. Failure to meet the renewal deadline set forth in this section shall result in expiration of the license. If a person's license expires, that person shall immediately cease performance of any LP-gas activities authorized by the license. After verification, if the licensee has met all other requirements for licensing, the Section shall renew the license, and the person may resume LP-gas activities.
(1) If a person's license has been expired for 90 calendar days or fewer, the person shall submit a renewal fee that is equal to 1 1/2 times the renewal fee required by §9.6 of this title (relating to Licenses and Fees). Upon receipt of the renewal fee, the Section shall verify that the person's license has not been suspended, revoked, or expired for more than one year. After verification, if the licensee has met all other requirements for licensing, the Section shall renew the license, and the person may resume LP-gas activities.
(2) If a person's license has been expired for more than 90 calendar days but less than one year, the person shall submit a renewal fee that is equal to two times the renewal fee required by §9.6 of this title. Upon receipt of the renewal fee, the Section shall verify that the person's license has not been suspended, revoked, or expired for more than one year. After verification, if the licensee has met all other requirements for licensing, the Section shall renew the license, and the person may resume LP-gas related activities.
(3) If a person's license has been expired for one year or more, that person shall not renew, but shall comply with the requirements for issuance of an original license.
(4) A person who was licensed in this state, moved to another state, and is currently licensed and has been in practice in the other state for the two years preceding the date of application may obtain a new license without reexamination. The person shall pay to the Section a fee that is equal to two times the renewal fee required by §9.6 of this title.
(A) As a prerequisite to licensing pursuant to this provision, the person shall submit, in addition to an application for licensing, proof of having been in practice and licensed in good standing in another state continuously for the two years immediately preceding the filing of the application;
(B) A person licensed under this provision shall be required to comply with all requirements of licensing other than the examination requirement, including but not limited to the insurance requirements as specified in §9.26 of this title (relating to Insurance Requirements) and the continuing education and training requirements as specified in §9.51 of this title (relating to General Requirements for Training and Continuing Education).
(i) Applicants for license or license renewal in the following categories shall comply with these additional requirements:
(1) An applicant for a Category A license or renewal shall file with the Section for each of its outlets legible copies of:
(A) its current Department of Transportation (DOT) authorization. A licensee shall not continue to operate after the expiration date of the DOT authorization; and/or
(B) its current American Society of Mechanical Engineers (ASME) Code, Section VIII certificate of authorization.
(2) An applicant for a Category B or O license or renewal shall file with the Section a properly completed LPG Form 505 certifying that the applicant will follow the testing procedures indicated. The company representative designated on the licensee's LPG Form 1 shall sign the LPG Form 505.
(3) An applicant for Category A, B, or O license or renewal who tests tanks, subframes LP-gas cargo tanks, or performs other activities requiring DOT registration shall file with the Section a copy of any applicable current DOT registrations. Such registration shall comply with Title 49, Code of Federal Regulations, Part 107 (Hazardous Materials Program Procedures), Subpart F (Registration of Cargo Tank and Cargo Tank Motor Vehicle Manufacturers and Repairers and Cargo Tank Motor Vehicle Assemblers).
§9.35.Written Procedure for LP-Gas Leaks.
(a) In addition to NFPA 58 §14.4.9.1, each licensee shall maintain a written procedure to be followed when any employee receives notification of a possible leak. The licensee shall ensure that all employees are familiar with the procedure and shall authorize employees to implement the procedure without management oversight. The written procedure shall be available to emergency response agencies as specified in NFPA 58, §6.25.2 and as stated in Table 1 of §9.403 of this title, (relating to Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes or Additional Requirements.
(b) The written procedures shall include the classification of the leak grade as defined in §9.2 of this title (relating to Definitions).
(c) The procedures shall include the appropriate action criteria for the classification of leak determined according to the table in this section. The examples of leak conditions are provided as guidelines and are not exclusive. The judgment of the company personnel at the scene is of primary importance in determining the grade assigned to a leak.
Figure: 16 TAC §9.35(c) (.pdf)
§9.37.Termination of LP-Gas Service.
(a) If the Safety Division (the Division) determines that any LP-gas container or installation constitutes an immediate danger to the public health, safety, and welfare, the Division shall require the immediate removal of liquid and vapor LP-gas and/or the immediate disconnection by a properly licensed company to the extent necessary to eliminate the danger. This may include appliances, equipment, or any part of the system including the servicing container. A warning tag shall be installed by the Division until the unsafe condition is remedied. Once the unsafe condition is corrected, the tag may be removed if authorized by the Division.
(b) If the Division determines that any LP-gas container or installation does not comply with the Texas Natural Resources Code, Chapter 113, or the LP-Gas Safety Rules, but does not constitute an immediate danger to the public health, safety, and welfare, the Division shall take action to ensure that the container or installation comes into compliance as soon as practicable. Division action may include the placement of a warning tag. Once the container or installation complies with Texas Natural Resources Code, Chapter 113, and the LP-Gas Safety Rules, the Division may remove or delegate the removal of the warning tag.
(c) If the affected entity disagrees with the removal from service and/or placement of a warning tag, the entity may request a review of the Division's decision within 10 calendar days. The Division shall notify such entity of its finding, in writing, stating the deficiencies, within 10 business days. If the entity disagrees, the entity may request or the Division on its own motion may call a hearing. Such installation shall be brought into compliance or removed from service until such time as the final decision is rendered by the Commission.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706419
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: February 1, 2008
Proposal publication date: October 26, 2007
For further information, please call: (512) 475-1295
16 TAC §§9.101, 9.114, 9.129 - 9.131, 9.134 - 9.137, 9.140 - 9.143
The amendments are adopted under the Texas Natural Resources Code, §113.051, which authorizes the Commission to adopt rules relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public; and §113.052, which allows the Commission to adopt by reference the published codes of nationally recognized societies, including the National Fire Protection Association.
The Texas Natural Resources Code, §113.051 and §113.052, are affected by the adopted amendments and new rules.
Issued in Austin, Texas, on December 18, 2007.
§9.129.Manufacturer's Nameplate and Markings on ASME Containers.
(a) LP-gas shall not be introduced into an ASME container unless the container is equipped with an original nameplate or at least one of the nameplates defined in this subsection permanently attached to the container.
(1) Commission identification nameplate--A nameplate issued under the procedures specified in §9.130 of this title (relating to Commission Identification Nameplates) and attached by an authorized representative of the Railroad Commission for the purpose of identifying an ASME stationary container when the original nameplate is lost or illegible.
(2) Duplicate nameplate--An additional ASME container nameplate issued by the original manufacturer with duplicate information as the original nameplate and clearly marked as a duplicate nameplate, but installed in a remote location.
(3) Modification (or alteration) nameplate--A nameplate issued and affixed by an ASME Code facility including only partial information applicable to a modification or alteration performed on that container.
(4) Replacement nameplate--A nameplate including the identical information as the original nameplate and identified as a replacement nameplate, but issued and affixed by the original manufacturer or its successor company or companies when the original nameplate is lost or illegible.
(b) Nameplate thickness for stainless steel nameplates issued on or after September 1, 1984, shall be sufficient to resist distortion due to the application of markings and fusion welding.
(c) Nameplates shall be attached in a location that will remain visible after installation of the containers.
(d) Nameplates on containers built prior to September 1, 1984, shall include at least the following legible information:
(1) the name of container manufacturer;
(2) the manufacturer's serial number;
(3) the container's working pressure; and
(4) the container's water capacity.
(e) Nameplates on containers built on or after September 1, 1984, shall be stainless steel and permanently attached to the container by continuous fusion welding around the perimeter of the nameplate, and shall be stamped or etched with the following information in characters at least 5/32 inch high:
(1) service for which the container is designed (underground, aboveground, or both);
(2) name and address of container supplier or trade name of container;
(3) water capacity of container in pounds or U.S. gallons;
(4) design pressure in pounds per square inch;
(5) the wording "This container shall not contain a product that has a vapor pressure in excess of _______ psi at 100 degrees F";
(6) outside surface area in square feet;
(7) year of manufacture;
(8) shell thickness and head thickness;
(9) overall length of the container, the outside diameter of the container, and dish radius of the heads;
(10) manufacturer's serial number;
(11) ASME Code symbol;
(12) minimum design metal temperature _______ F degrees at MAWP _______ psi;
(13) type of construction "W"; and
(14) degree of radiography "RT-_______".
(f) Any replacement nameplate issued by an original container manufacturer for containers constructed prior to September 1, 1984, shall be stainless steel and shall be affixed in accordance with ASME Code. The owner or operator of the container shall ensure that a copy of LPG Form 8 is filed with the Safety Division (the Division) when a replacement nameplate is affixed.
(g) Nameplates on LP-gas motor or mobile fuel tanks shall be permanently attached in a manner which will minimize corrosion of the nameplate or its fastening means and not contribute to corrosion of the container. If the nameplate is not continuously welded to the container, then it shall be raised at least 1/4 inch but no more than 1/2 inch from the container's surface.
(h) In addition to a container nameplate, underground containers shall have a system nameplate permanently attached to the system in a location that will be readily accessible for inspection when the containers are buried. Where the container is buried, mounded, insulated, or otherwise covered so the nameplate is obscured, a duplicate nameplate shall be installed in a clearly visible and accessible location.
(i) The Division may remove a container from LP-gas service or require ASME acceptance of a container at any time if the Division determines that the nameplate, in any form defined in subsection (a)(1) - (4) of this section, is loose, unreadable, or detached, or if it appears to be tampered with or damaged in any way and does not contain at a minimum the items defined in subsection (d) of this section.
§9.134.Connecting Container to Piping.
LP-gas piping shall be installed only by a licensee authorized to perform such installation, a registrant authorized by §9.13 of this title (relating to General Installers and Repairman Exemption), or an individual exempted from licensing as authorized by Texas Natural Resources Code, §113.081. A licensee shall not connect an LP-gas container or cylinder to a piping installation made by a person who is not licensed to make such installation, except that connection may be made to piping installed by an individual on that individual's single family residential home. A licensee may connect to piping installed by an unlicensed person provided the licensee has performed a pressure test, verified that the piping has been installed according to the LP-Gas Safety Rules, and filed a properly-completed LPG Form 22 with the Safety Division, identifying the unlicensed person who installed the LP-gas piping.
§9.137.Inspection of Containers at Each Filling.
In addition to NFPA 58, §§5.2.1.1, 7.2.2.11, and 5.2.2 before filling a container or cylinder, the individual filling the container or cylinder shall conduct a visual inspection of the exposed, readily accessible areas of the container or cylinder for any obvious defects. Where the container or cylinder is dented, bulged, gouged, or corroded such that the integrity of the container or cylinder is substantially reduced, such container or cylinder shall not be filled.
§9.140.Uniform Protection Standards.
(a) In addition to NFPA 58 §6.24.3.14, LP-gas transfer systems and storage containers shall be protected from tampering and/or vehicular traffic as specified in this section. New LP-gas containers which have never been installed or had LP-gas introduced into them, or other installations listed in paragraphs (1) - (4) of this subsection, are not required to comply with the fencing and guard railing requirements in subsections (b) and (d) of this section. The fencing and guard railing requirements also do not apply to the following:
(1) LP-gas systems and containers located at private residences;
(2) LP-gas systems and containers which service vapor systems where the aggregate storage capacity of the installation is less than 4,001 gallons, unless the LP-gas system, transfer system, or container is subject to tampering or vehicular traffic;
(3) LP-gas piping which contains no valves and which complies with all other applicable LP-Gas Safety Rules; and
(4) LP-gas storage containers located on a rural consumer's property from which motor or mobile fuel containers are filled.
(b) In addition to NFPA 58, §§6.18.4.2, 6.19.3.2, 6.24.3.7, 7.2.3.8, 8.2.1.1, and 8.4.2.1. fencing at LP-gas installations shall comply with the following:
(1) Fencing material shall be chain link with wire at least 12 1/2 American wire gauge in size, or industrial-type fencing, or material providing equivalent protection as determined by the Safety Division.
(2) Fencing shall be at least six feet in height at all points.
(3) Uprights, braces, and cornerposts of the fence shall be composed of noncombustible material.
(4) Gates in fences where bulkheads are installed shall be located directly in front of the bulkhead. Gates shall be locked whenever the area enclosed is unattended. Gate posts on gates installed directly in front of the bulkhead shall be located at 45-degree angles to the nearest corner of the bulkhead. There shall be at least two means of emergency access from the fenced enclosure. If guard service is provided, it shall be extended to the LP-gas installation. Guard service shall be properly trained as set forth in §9.51(b)(4) of this title (relating to General Requirements for Training and Continuing Education). However, if a fenced area is not larger than 100 square feet in area, the point of transfer is within three feet of a gate, and any containers being filled are not located within the enclosure, a second gate shall not be required.
(5) Clearance of at least three feet shall be maintained between the fencing and the container and the entire transfer system.
(6) Fencing which is located more than 25 feet from any point of an LP-gas transfer system or container shall be designated as perimeter fencing. If an LP-gas transfer system or container is located inside perimeter fencing and is subject to vehicular traffic, it shall be protected against damage according to the specifications set forth in subsection (d) of this section.
(7) The operating end of a container, including the entire transfer system, shall be completely enclosed by fencing.
(c) Containers which are exempt from the fencing requirements include:
(1) ASME containers or manual dispensers originally manufactured to or modified to be considered by the Safety Division (the Division) as self-contained units. Self-contained units shall be protected as specified in subsection (d) of this section;
(2) DOT portable or forklift containers in storage racks or at single family dwellings used as private residences; and
(3) DOT portable or forklift containers that have been used in LP-gas service but are not awaiting use or resale.
(d) In addition to NFPA 58, §§6.6.1.2, 6.6.6.1(a) - (d), 6.6.6.2(6), 6.18.4.2, 6.24.3.12, and 8.4.2, guardrails at LP-gas installations, except as noted in subsection (a) of this section, shall comply with the following:
(1) In addition to NFPA 58 §6.18.4.2(c), where fencing is not used to protect the installation as specified in subsection (b) of this section, locks for the valves or other suitable means shall be provided to prevent unauthorized withdrawal of LP-gas, and guardrailing specified in paragraphs (2) - (6) of this subsection, or protection considered by the Division to be equivalent, shall be required.
(2) Vertical supports for guardrails shall be at least three-inch schedule 40 steel pipe or other material with equal or greater strength. The vertical supports shall be capped on the top or otherwise protected to prevent the entrance of water or debris into the guardpost; anchored in concrete at least 18 inches below the ground; and rise at least 30 inches above the ground. Supports shall be spaced four feet apart or less.
(3) The top of the horizontal guardrailing shall be secured to the vertical supports at least 30 inches above the ground. The horizontal guardrailing shall be at least three-inch schedule 40 steel pipe or other material with equal or greater strength. The horizontal guardrailing shall be capped on the ends or otherwise protected to prevent the entrance of water or debris into the guardpost; and welded or bolted to the vertical supports with bolts of sufficient size and strength to prevent damage to the protected equipment under normal conditions, including the nature of the traffic to which the protected equipment is subjected.
(4) Openings in horizontal guardrailing, except the opening that is permitted directly in front of a bulkhead, shall not exceed three feet. Only one opening is allowed on each side of the guardrailing. A means of temporarily removing the horizontal guardrailing and vertical supports to facilitate the handling of heavy equipment may be incorporated into the horizontal guardrailing and vertical supports. In no case shall the protection provided by the horizontal guardrailing and vertical supports be decreased. Transfer hoses from the bulkhead shall be routed only through the 45-degree opening in front of the bulkhead or over the horizontal guardrailing.
(5) Clearance of at least three feet shall be maintained between the railing and any part of an LP-gas transfer system or container or clearance of two feet for retail cylinder filling or service station installations. The two posts at the ends of any railing which protects a bulkhead shall be located a minimum of 24 and a maximum of 36 inches at 45-degree angles to the nearest corner of the bulkhead.
(6) The operating end of the container and any part of the LP-gas transfer system or container which is exposed to collision damage or vehicular traffic shall be protected from this type of damage. The protection shall extend at least three feet beyond any part of the LP-gas transfer system or container which is exposed to collision damage or vehicular traffic.
(e) A combination of fencing and guardrails specified in subsections (b) and (d) of this section shall not result in less protection than using either fencing or guardrails alone.
(f) If exceptional circumstances exist or will exist at an installation which would require additional protection such as larger-diameter guardrailing, then the licensee or operator shall install such additional protection. In addition, the Division at its own discretion may require an installation to be protected with added safeguards to adequately protect the health, safety, and welfare of the general public. The Division shall notify the person in writing of the additional protection needed and shall establish a reasonable time period during which the additional protection shall be installed. The licensee shall ensure that any necessary extra protection is installed. If a person owning or operating such an installation disagrees with the Division's determination made under this subsection, that person may request a public hearing on the matter. The installation shall either be protected in the manner prescribed by the Division or removed from service with all product withdrawn from it until the Division's final decision.
(g) In addition to NFPA 58 §5.2.8.1, LP-gas installations shall comply with the sign and lettering requirements specified in Table 1 of this section. An asterisk indicates that the requirement applies to the equipment or location listed in that column.
Figure: 16 TAC §9.140(g) (.pdf)
(1) Unless colors are specified, lettering shall be in a color that sharply contrasts to the background color of the sign, and shall be readily visible to the public.
(2) Items 1, 2, and 3 in Table 1 may be combined on one sign.
(3) Items 1, 2, and 3 in the column entitled "Licensee or Non-Licensee ASME 4001+ Gal. A.W.C." in Table 1 apply to installations with 4,001 gallons or more aggregate water capacity protected only by guardrailing as required in subsection (d) of this section, and bulkheads as required by §9.143 of this title (relating to Bulkhead, Internal Valve, API 607 Ball Valve, and ESV Protection for Stationary LP-Gas Installations with Individual or Aggregate Water Capacities of 4,001 Gallons or More) for commercial, bulk storage, cylinder filling, or forklift installations.
(4) Item 11 in the column entitled "Requirements" in Table 1 applies to facilities which have two or more containers.
(5) Item 13 in the column entitled "Requirements" in Table 1 applies to outlets where an LP-gas certified employee is responsible for the LP-gas activities at that outlet, when a licensee's employee is the operations supervisor at more than one outlet as required by §9.17(a) of this title (relating to Designation and Responsibilities of Company Representative and Operations Supervisor).
(6) Any information in Table 1 of this subsection required for an underground container shall be mounted on a sign posted within 15 feet horizontally of the manway or the container shroud.
(7) Licensees and non-licensees shall comply with operational and/or procedural actions specified by the signage requirements of this section.
(8) Any 24-hour emergency telephone numbers shall be:
(A) monitored at all times; and
(B) be answered by a person who is knowledgeable of the hazards of LP-gas and who has comprehensive LP-gas emergency response and incident information, or has immediate access to a person who possesses such knowledge and information. A telephone number that requires a call back (such as an answering service, answering machine, or beeper device) does not meet the requirements of this section.
(h) Storage racks used to store nominal 20-pound DOT portable or any size forklift containers shall be protected against vehicular damage by:
(1) meeting the guardrail requirements of subsection (d) of this section; or
(2) installing guard posts, provided:
(A) effective February 1, 2008, for new installations, the guard posts are installed a minimum of 18 inches from each storage rack and consist of at least three-inch schedule 40 steel pipe, capped on top or otherwise protected to prevent the entrance of water or debris into the guard post, no more than four feet apart, and anchored in concrete at least 30 inches below ground and rising at least 30 inches above the ground; or
(B) effective February 1, 2008, for new installations, the guard posts are installed a minimum of 18 inches from each storage rack and are constructed of at least four-inch schedule 40 steel pipe capped on top or otherwise protected to prevent the entrance of water or debris into the guard post, and attached by welding to a minimum 8-inch by 8-inch steel plate at least 1/2 inch thick. The guard posts and steel plate shall be permanently installed and securely anchored to a concrete driveway or concrete parking area.
(3) Guardrail or guard posts are not required to be installed if:
(A) the cylinder storage rack is located a minimum of 48 inches behind a concrete curb or concrete wheel stop that is a minimum of five inches in height above the grade of the driveway or parking area;
(B) if the requirements of subparagraph (A) cannot be met, the cylinder storage rack must be installed a minimum of 48 inches behind a concrete curb or concrete wheel stop that is a minimum of four inches in height above the grade of the driveway or parking area, and a concrete wheel stop at least four inches in height must be installed at least 12 inches from the curb or first wheel stop;
(4) All parking wheel stops and cylinder storage racks in paragraph (3) of this subsection must be secured against displacement.
(i) Self-service dispensers shall be protected against vehicular damage by:
(1) guardrails that comply with subsection (d)(2) - (6) of this section; or
(2) guard posts that comply with subsection (d)(2) of this section; or
(3) where routine traffic patterns expose only the approach end of the dispenser to vehicular damage, support columns, concrete barriers, bollards, inverted U-shaped guard posts anchored in concrete, or other protection acceptable to the Safety Division, provided:
(A) such protection extends beyond the framework of the dispenser; and
(B) at least 24 inches of clearance is maintained between the approach end of the dispenser and the protective barrier.
(4) Self-service dispensers utilizing protection specified in paragraphs (2)-(3) of this subsection shall be connected to supply piping by a device designed to prevent the loss of LP-gas in the event the dispenser is displaced. The device must retain liquid on both sides of the breakaway point and be installed in a manner to protect the supply piping against damage.
§9.143.Bulkhead, Internal Valve, API 607 Ball Valve, and ESV Protection for Stationary LP-Gas Installations with Individual or Aggregate Water Capacities of 4,001 Gallons or More.
(a) Instead of NFPA 58, §6.6.12, effective February 1, 2001, new stationary LP-gas installations with individual or aggregate water capacities of 4,001 gallons or more, including licensee and nonlicensee locations, shall install a vertical bulkhead, and for all container openings 1 1/4 inches or greater, pneumatically-operated emergency shutoff valves (ESV), pneumatically-operated internal valves, or pneumatically-operated API 607 ball valves as required in this section and in the table in §9.403 of this title (relating to Sections in NFPA 58 Not Adopted by Reference, and Adopted With Changes or Additional Requirements for NFPA 58, §6.11.1. In lieu of a pneumatically-operated internal valve or a pneumatically-operated ESV, a backflow check valve may be installed where the flow is in one direction into the container. The backflow check valve shall have a metal-to-metal seat or a primary resilient seat with metal backup, not hinged with combustible material, and shall be designed for this specific application.
(1) The pneumatic ESV and/or backflow check valves shall be installed in the fixed piping of the transfer system upstream of the bulkhead and within four feet of the bulkhead with a stainless steel flexible wire-braided hose not more than 36 inches long installed between the ESV and the bulkhead.
(2) The ESV shall be installed in the piping so that any break resulting from a pull away will occur on the hose or swivel-type piping side of the connection while retaining intact the valves and piping on the storage side of the connection and will activate the ESV at the bulkhead and the internal valves, ESV, and API 607 ball valves at the container or containers. Provisions for anchorage and breakaway shall be provided on the cargo tank side for transfer from a railroad tank car directly into a cargo tank. Such anchorage shall not be required from the tank car side.
(3) Pneumatically-operated ESV, internal valves, and API 607 ball valves shall be equipped for automatic shutoff using thermal (fire) actuation where the thermal element is located within five feet (1.5 meters) of the ESV, internal valves, and/or API 607 ball valves. Temperature sensitive elements shall not be painted nor shall they have any ornamental finishes applied after manufacture.
(4) Internal valves, ESVs, and backflow check valves shall be tested annually for working order. The results of the tests shall be documented in writing and kept in a readily accessible location for one year following the performed tests.
(5) Pneumatically-operated internal valves, ESV, and API 607 ball valves shall be interconnected and incorporated into at least one remote operating system.
(b) In addition to NFPA 58 §5.9.6, within two years of February 1, 2001, or by February 1, 2003, at the latest, stationary LP-gas installations in existence as of February 1, 2001, with individual or aggregate water capacities of 4,001 gallons or more, including licensee and nonlicensee locations, or railroad tank car transfer systems to fill trucks with no stationary storage involved, which do not have a bulkhead, ESV, and/or backflow check valves where the flow is in one direction into the container shall install vertical bulkheads, pneumatic ESV and/or backflow check valves where the flow is in one direction into the container.
(c) Existing installations which have horizontal bulkheads and cable-actuated ESV shall comply with the following:
(1) If the horizontal bulkhead requires replacement, it shall be replaced with a vertical bulkhead;
(2) If a cable-actuated ESV requires replacement, it shall be replaced with a pneumatically-operated ESV;
(3) If the horizontal bulkhead or a backflow check valve or a cable-actuated ESV are moved from their original location to another location, no matter what the distance from the original location, then the installation shall comply with the requirements for a vertical bulkhead and pneumatically-operated ESV;
(4) All cable-actuated ESV shall be replaced with pneumatically-operated ESV by January 1, 2011.
(d) Bulkheads, whether horizontal or vertical, shall comply with the following requirements:
(1) Bulkheads shall be installed for both liquid and vapor return piping;
(2) No more than two transfer hoses shall be attached to a pipe riser. If two hoses are simultaneously connected to one or two transports, the use of the two hoses shall not prevent the activation of the ESV in the event of a pull away;
(3) Both liquid and vapor transfer hoses shall be plugged or capped;
(4) Bulkheads shall be located at least 10 feet from any aboveground container or containers and a minimum of 10 feet horizontally from any portion of a container or valve exposed aboveground on any underground or mounded container. If the 10-foot distance cannot be obtained, the licensee or nonlicensee shall inform the Safety Division (the Division) in writing and include all necessary information. The Division may grant administrative distance variances to a minimum distance of five feet. If the licensee or nonlicensee requests that the bulkhead be closer than five feet to the container or containers, the licensee or nonlicensee shall apply for an exception to a safety rule as specified in §9.27 of this title (relating to Application for an Exception to a Safety Rule);
(5) Horizontal bulkheads shall not be converted to vertical bulkheads;
(6) Bulkheads shall be anchored in reinforced concrete to prevent displacement of the bulkhead, piping, and fittings in the event of a pullaway;
(7) Bulkheads shall be constructed by welding using the following materials or materials with equal or greater strength, as shown in the diagram.
Figure: 16 TAC §9.143(d)(7) (No change.)
(A) Six-inch steel channel iron shall be used;
(B) Legs shall be four-inch schedule 80 piping;
(C) The top crossmember of a vertical bulkhead shall be six-inch standard weight steel channel iron. The channel iron shall be installed so the channel portion is pointing downward to prevent accumulation of water or other debris. The height of the top crossmember above ground shall not result in torsional stress on the vertical supports of the bulkhead in the event of a pullaway;
(D) The kick plate shall be at least 1/4 inch steel plate installed at least 10 inches from the top of the bulkhead crossmember. A kick plate is not required if the crossmember is constructed to prevent torsional stress from being placed on the piping to the pipe risers;
(E) Either a schedule 40 pipe sleeve or a 3,000-pound coupling shall be welded between the top crossmember and the kick plate;
(i) Pipe sleeves shall have a clearance of 1/4 inch or less for the piping to the pipe riser, and the piping shall terminate through the bulkhead with a schedule 80 pipe collar, a minimum 12-inch schedule 80 threaded (not welded) pipe riser (nipple), and an elbow or other fitting between the bulkhead and hose coupling;
(ii) If a 3,000-pound coupling is used, no collar is required; however, the minimum 12-inch length of schedule 80 threaded pipe riser and an elbow or other fitting between the bulkhead and hose coupling are required;
(iii) Elbows or other fittings shall comply with NFPA 58, §2.4.4 and shall direct the transfer hose from vertical to prevent binding or kinking of the hose.
(8) In lieu of a minimum 12-inch nipple or a vertical bulkhead, swivel-type piping (breakaway loading arm) may be installed. The swivel-type piping shall meet all applicable provisions of the LP-Gas Safety Rules. The swivel-type piping may also be used for unloading, but shall not be used in lieu of ESVs. The swivel-type piping shall be installed and maintained according to the manufacturer's instructions.
(9) The Division may require additional bulkhead protection if the installation is subject to exceptional circumstances or located in an unusual area where additional protection is necessary to protect the health, safety, and welfare of the general public.
(e) In addition to NFPA 58, §5.7.4.2 as amended in the table in §9.403 of this title (relating to Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes or Additional Requirements), ESVs, internal valves, and API 607 ball valves shall have emergency remote controls conspicuously marked according to the requirements of Table 1 of §9.140 of this title (relating to Uniform Protection Standards) as follows:
(1) Effective February 1, 2001, for all new facilities, where a bulkhead, internal valves, and ESVs are installed, at least one clearly identified and easily accessible manually operated remote emergency shutoff device shall be located between 20 and 100 feet from the ESV in the path of egress from the ESV. Existing installations shall have complied by August 1, 2001.
(2) Beginning September 1, 2005, for new installations, at least one clearly identified and easily accessible manually operated remote emergency shutoff device shall be located between 25 and 100 feet from the ESV at the bulkhead and in the path of egress from the ESV. API 607 ball valves installed after February 1, 2008, shall also meet the requirements of this section.
(3) The use of swivel-type piping as specified in subsection (d)(8) of this section shall not eliminate the requirement for an ESV. Swivel-type piping may be installed between the bulkhead and the minimum 12-inch nipple, but shall not eliminate the requirement for an ESV. The swivel-type piping shall be installed and maintained according to the manufacturer's instructions.
(f) The bulkheads, internal valves, backflow check valves, and ESVs shall be kept in working order at all times in accordance with the manufacturer's instructions and the LP-Gas Safety Rules . If the bulkheads, internal valves, backflow check valves and ESVs are not in working order in accordance with the manufacturer's instructions and the LP-Gas Safety Rules, the licensee or operator of the installation shall immediately remove them from LP-gas service and shall not operate the installation until all necessary repairs have been made.
(g) In addition to NFPA 58 §§5.9.6 and 6.9.6.1, by February 1, 2003, rubber flexible connectors which are 3/4-inch or larger in size installed in liquid or vapor piping at an existing liquid transfer operation shall have been replaced with a stainless steel flexible connector. Stainless steel flexible connectors shall be 60 inches in length or less, and shall comply with all applicable LP-Gas Safety Rules. Flexible connectors installed at a new installation after February 1, 2001, shall be stainless steel.
(h) If necessary to increase LP-gas safety, the Division may require a pneumatically-operated internal valve equipped for remote closure and automatic shutoff through thermal (fire) actuation to be installed for certain liquid and/or vapor connections with an opening of 3/4 inch or one inch in size.
(i) Stationary LP-gas installations with individual or aggregate water capacities of 4,001 gallons or more are exempt from subsections (a) and (b) of this section provided:
(1) each container is filled solely through a 1 3/4 inch double back check filler valve installed directly into the container; and
(2) at least one clearly identified and easily accessible manually operated remote emergency shutoff device shall be located between 25 and 100 feet from the point of transfer in the path of egress to close the primary discharge valves in the containers; and
(3) the LP-gas installation is not used to fill an LP-gas transport.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706421
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: February 1, 2008
Proposal publication date: October 26, 2007
For further information, please call: (512) 475-1295
The amendments are adopted under the Texas Natural Resources Code, §113.051, which authorizes the Commission to adopt rules relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public; and §113.052, which allows the Commission to adopt by reference the published codes of nationally recognized societies, including the National Fire Protection Association.
The Texas Natural Resources Code, §113.051 and §113.052, are affected by the adopted amendments and new rules.
Issued in Austin, Texas, on December 18, 2007.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706422
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: February 1, 2008
Proposal publication date: October 26, 2007
For further information, please call: (512) 475-1295
16 TAC §§9.301 - 9.303, 9.306 - 9.308, 9.311 - 9.313
The amendments are adopted under the Texas Natural Resources Code, §113.051, which authorizes the Commission to adopt rules relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public; and §113.052, which allows the Commission to adopt by reference the published codes of nationally recognized societies, including the National Fire Protection Association.
The Texas Natural Resources Code, §113.051 and §113.052, are affected by the adopted amendments and new rules.
Issued in Austin, Texas, on December 18, 2007.
§9.313.Sections in NFPA 54 Adopted with Additional Requirements or Not Adopted.
Table 1 of this section lists certain NFPA 54 sections which the Commission adopts with additional requirements or does not adopt in order to address the Commission's rules in this chapter.
Figure: 16 TAC §9.313 (.pdf)
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706423
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: February 1, 2008
Proposal publication date: October 26, 2007
For further information, please call: (512) 475-1295
The amendments are adopted under the Texas Natural Resources Code, §113.051, which authorizes the Commission to adopt rules relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public; and §113.052, which allows the Commission to adopt by reference the published codes of nationally recognized societies, including the National Fire Protection Association.
The Texas Natural Resources Code, §113.051 and §113.052, are affected by the adopted amendments and new rules.
Issued in Austin, Texas, on December 18, 2007.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706424
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: February 1, 2008
Proposal publication date: October 26, 2007
For further information, please call: (512) 475-1295
Subchapter A. GENERAL REQUIREMENTS
16 TAC §§9.8, 9.10 - 9.12, 9.51, 9.52, 9.54
The Railroad Commission of Texas adopts amendments to §§9.8, 9.10 - 9.12, 9.51, 9.52, and 9.54, relating to Application for a New Certificate; Rules Examination; Previously Certified Individuals; Trainees; General Requirements for Training and Continuing Education; Training and Continuing Education Courses; and Commission-Approved Outside Instructors, without changes from the versions published in the November 2, 2007, issue of the Texas Register (32 TexReg 7825).
The Commission adopts the amendments to update and clarify certain LP-gas training and continuing-education requirements. For all of the rules in this adoption, the Commission specifies an effective date of February 1, 2008.
The Commission received three comments, two from individuals and one from the Texas Propane Gas Association (TPGA). The Commission appreciates these comments.
With respect to §9.10(a)(6), TPGA commented that the proposed time limit of three hours for the Category E management- level examination is too short and suggested a limit of five hours for that examination. The Commission adopts the amendment without change to the proposal. Since September 2005, the Commission has administered 94 Category E management-level examinations. All of these examinees finished the examination within three hours.
With respect to §9.10(a)(7), one individual expressed strong support for the proposal to offer employee-level LP-gas transport driver, DOT cylinder filling, and motor/mobile fuel dispensing examinations in either Spanish or English. The comment stated that Spanish is becoming more necessary due to the changing demographics in Texas. TPGA did not support this proposal. TPGA stated that the LP-gas codes are printed in English, and persons who do not take the exam in English may not have a proper understanding of the rules and may not be able to communicate important safety messages to customers.
The Commission adopts the amendment without change to the proposal. Previous editions of NFPA 54 and NFPA 58 are available in Spanish. NFPA 54 is not at issue, since none of its standards apply to the LP-gas transport driver, DOT cylinder filling and motor/mobile fuel dispensing examinations. The 2008 edition of NFPA 58 is not currently available in Spanish; however, before offering the two new examinations in Spanish, the Commission will publish a study guide in Spanish for each examination that will include all pertinent sections of the standards and the LP-Gas Safety Rules. With respect to TPGA's comments on understanding the rules and communicating safety information to customers, the Commission has seen no evidence that persons who took the current transport driver examination in Spanish during the 20 years it has been offered understood the rules any less well than persons who took the same examination in English, or that persons who pass an examination in Spanish are less capable than persons who pass the same examination in English of communicating safety messages to customers who speak their respective languages. The Commission takes no position on this matter and believes that decisions about which employees are assigned responsibility to communicate safety messages to customers are best left up to individual licensees.
TPGA expressed support for the proposals in §9.51 to eliminate obsolete deadlines and update the titles of the Propane Education and Research Council's Certified Employee Training Program (CETP) listed in Tables 3 and 4. The Commission adopts these amendments without changes.
Two CETP-related comments addressed certification and training generally rather than specific proposed amendments. One commenter stated that AFRED's training and certification programs do not capitalize on the experience and knowledge available from the LP- gas industry nationally through the Propane Education and Research Council's Safety and Training Advisory Committee (STAC), in particular the Certified Employee Training Program (CETP). The commenter stated that propane industry employees in Texas are therefore unable to benefit from the standardized CETP training and certification program, which is created and maintained by national industry leaders. The commenter noted that the Commission currently allows CETP courses to count for LP-gas continuing-education credit, but stated that it would be most beneficial for the Commission to adopt CETP as an alternative primary training tool for propane-industry employees. TPGA also noted that CETP is available for Railroad Commission continuing- education credit. TPGA expressed support for continuing the Commission's LP-gas training and certification program, but would like to see CETP adopted as an alternative means of certification. The comment stated that having CETP certification and training available as an alternative to Railroad Commission certification and training would offer flexibility and efficiency for some propane businesses that have a large staff and employ in-house trainers.
The Commission disagrees with the first part of the individual's comment. The Commission's LP-gas training program has benefited greatly from the industry expertise represented in STAC and CETP. The director of the Commission's LP-gas training program, Thomas Petru, is a nationally recognized expert on LP- gas safety who has served on STAC since its creation in January 2002. As a STAC member, Mr. Petru helped write CETP, and his service on STAC has helped to ensure that the Commission's training materials are up to date and reflect current industry best practices.
The Commission agrees with both comments on the value of CETP. While adoption of CETP as an alternative method of fulfilling the Commission's certification and training requirements is outside the scope of the current rulemaking, the Commission recognizes that CETP is an equivalent program for employee-level training, and staff plans to recommend that the Commission consider extending the options of CETP to include both training and continuing education, along with some possible computer-based CETP training, in a future rulemaking.
In §9.8, the Commission adopts a non-substantive change to clarify that the courses named in §9.51 or §9.52 may or may not include Advanced Field Training (AFT) activities.
In §§9.10, 9.51, and 9.52, the Commission adds statements that, in addition to complying with NFPA 58, §§4.4 and 11.2, licensees and certified individuals must also comply with the Commission's training and continuing education rules.
In §9.10(a), the Commission adopts new paragraph (6) concerning time limits for examinations. The time limits, which will begin June 1, 2008, will require an applicant to complete a qualifying examination within two hours or three hours, depending on the examination. Category E management-level examinations and employee-level examinations for bobtail drivers and service and installation technicians will be limited to three hours from the time the examination begins; all other examinations will be limited to two hours from the time the examination begins. The examination proctor will be the official timekeeper. Examinees will be required to turn in their examinations and answer sheets before or at the end of the established time limit for the examination. The proctor will mark any answer sheet that was not completed within the time limit.
The time limits will not affect the open- or closed-book status of qualifying examinations. Management-level examinations are currently closed book, and will remain so; employee-level examinations are currently open book, and will remain so.
The Commission adopts these time limits for reasons of efficiency. The Commission must be able to plan and budget for the activities and expenses associated with the examination program. This program is a substantial undertaking. In fiscal 2006 and 2007, AFRED staff administered a total of 6,586 qualifying examinations, of which 6,022 (91 percent) were open- book, employee-level examinations that are unlimited as to time. It is not unusual for examinees to arrive unprepared and spend an entire day of their and their employers' time researching the answers to a 50-question test. In addition, 3,876 of these qualifying examinations (59 percent) were administered outside Austin, often following an eight-hour training class, at donated or public facilities. The Commission's expectation is that the managers of some of these facilities who are not willing to let the Commission use their building to give open-ended examinations after hours may be willing to let AFRED do so with a guarantee that the examinations will end at a reasonable hour. In such cases, the examinee, his or her employer, and AFRED staff would all benefit from not having to come back the next morning to take an examination.
The Commission considers the time limits reasonable. Qualifying examinations vary in length according to the number and complexity of the LP-gas activities they authorize the examinee to perform. A three-hour time limit is adopted for the closed-book Category E management-level examination, which currently has 175 questions, and for the open-book employee-level bobtail driver and service and installation examinations, which currently have 75 questions. Two-hour time limits are adopted for all other closed-book management-level examinations, which currently have between 25 and 100 questions, and for all other open-book employee-level examinations, which currently have between 33 and 50 questions. The Commission will implement these time limits on June 1, 2008, by which date AFRED will have published detailed study guides that will enable applicants to prepare more adequately for all employee-level examinations and reduce or eliminate the need to spend time researching the answers to questions during the examination.
In new paragraph (7), the Commission adopts wording that employee-level LP-gas transport driver, DOT cylinder filling, and motor/mobile fuel dispensing examinations may be offered in either Spanish or English. This option, which is currently available only to employee-level LP-gas transport driver examinees, is adopted in response to requests from two LP-gas marketers to make the cylinder-filling and motor/mobile fuel dispensing examinations, which are very often taken together, available in Spanish.
In §9.10(b), the Commission adopts a name change for one examination and two new examinations. In paragraph (3), the engine fuel examination is changed to "On-Road Motor Fuel" examination, with other clarifying wording added. In paragraphs (4) and (5), new examinations for "Non-Road Motor Fuel" and "Mobile Fuel" clarify some distinctions between these activities and allow individuals to certify according to their actual job duties. In general, the On-Road Motor Fuel examination is intended to cover LP-gas activities related to highway vehicles such as cars, trucks and buses that are propelled by LP-gas. The Non-Road Motor Fuel examination is intended to cover LP-gas activities related to off-road equipment such as industrial forklifts and commercial mowers that are propelled by LP-gas, but whose fuel systems differ significantly from those used on highway vehicles. The Mobile Fuel examination is intended to cover LP-gas activities related to mobile LP-gas equipment such as appliances installed on a trailer, catering truck or mobile kitchen. In paragraph (8), the Commission adds stationary engines to the list of stationary LP-gas systems relative to which a Service and Installation examination qualifies an individual to perform LP-gas activities. This change clarifies which examination qualifies an individual to perform LP-gas activities related to stationary engines such as those that power generators and pumps. The Table in §9.10(b) is also amended to include these changes. The new employee-level non-road motor fuel and mobile fuel examinations will be available for employees of both Category E and Category L licensees. These three examinations are often the subject of questions to the Commission as to which examination an applicant needs to take, and the Commission finds that the changes will improve safety by offering examinations that better reflect the way that LP-gas motor fuel and mobile fuel activities are performed in actual industry practice.
The Commission adds wording in §9.11(a) to require an ultimate consumer and a state agency, county, municipality, school district, or other governmental subdivision to notify AFRED when a previously certified individual is hired, and to delete §9.11(b) as redundant. Other new wording exempts a state agency, county, municipality, school district, or other governmental subdivision from this requirement if such entity chooses not to certify its employees who perform LP-gas activities. The Commission adds this wording to conform its transfer-notification requirements for ultimate consumers and for public entities that elect to certify their employees to the transfer-notification requirements for licensees. Under the rule as adopted, the Commission will be informed of LP-gas certified individuals' affiliations and be able to send renewal notices and other communications to the individual's correct work address, regardless whether he or she is employed by a licensee, an ultimate consumer, or a public entity that elects to certify its employees.
In §9.12, the Commission deletes the requirement that a licensee or ultimate consumer file LPG Form 16 for each trainee at the time the trainee begins supervised LP-gas activities. This filing requirement is no longer necessary.
In §9.51(b)(3)(E), a reference is added to the on-road motor fuel, non-road motor fuel, and mobile fuel certifications, which are added in §9.10.
Some non-substantive clarifying changes are adopted in §9.52(b)(1)(A) concerning some deadlines that have already passed. In subsection (h), the Commission adopts some changes to the Tables that list the LP-gas training and continuing education courses. The first table has no changes. In Table 2, the column entitled "Portable Cylinder Filling" is changed to "DOT Cylinder Filling." The word "Dispensing" is added in the column for "Motor & Mobile Fuel." The entire column for "Bobtail Service & Installation" and the accompanying footnote are deleted. This category of certification is no longer in use and has been replaced by separate bobtail and service and installation certifications. The "RV Technician" column is changed to "Recreational Vehicle." The revision date for this table is changed to February 2008.
Tables 3 and 4 include some changes to the CETP course numbers and titles; these changes match the current CETP course titles. No substantive changes are adopted in these two tables.
The Commission adds in §9.54(a)(1)(C) authorized Category I outside instructors to the list of outside instructors who may offer the applicable training and continuing education classes to Category F, G, I, and J management-level certificate holders and DOT cylinder filling and motor/mobile fuel dispenser applicants and employee-level certificate holders. References to Category I are also adopted in subsection (b)(2) and (j)(1).
The Commission adopts the amendments under Texas Natural Resources Code, §113.051, which authorizes the Commission to adopt rules relating to any and all aspects or phases of the LP- gas industry that will protect or tend to protect the health, welfare, and safety of the general public.
Statutory authority: Texas Natural Resources Code, §113.051.
Cross reference to statute: Texas Natural Resources Code, Chapter 113, §113.051.
Issued in Austin, Texas, on December 18, 2007.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706418
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: February 1, 2008
Proposal publication date: November 2, 2007
For further information, please call: (512) 475-1295
The Railroad Commission of Texas adopts the repeal of §9.32, relating to LP-Gas Advisory Committee, without changes from the version published in the October 26, 2007, issue of the Texas Register . The Commission adopts the repeal because by the terms of the rule, the LP-gas advisory committee ceased to exist on August 31, 2006.
The Commission received no comments on the proposed repeal.
The Commission adopts the repeal under Texas Natural Resources Code, §113.051, which authorizes the Commission to adopt rules relating to any and all aspects or phases of the LP-gas industry that will protect or tend to protect the health, welfare, and safety of the general public; and Texas Government Code, Chapter 2110, State Agency Advisory Committees.
Statutory authority: Texas Natural Resources Code, §113.051, and Texas Government Code, Chapter 2110.
Cross-reference to statute: Texas Natural Resources Code, Chapter 113, and Texas Government Code, Chapter 2110.
Issued in Austin, Texas, on December 18, 2007.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706416
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: January 7, 2008
Proposal publication date: October 26, 2007
For further information, please call: (512) 475-1295
Subchapter C. CLASSIFICATION, REGISTRATION, AND EXAMINATION
The Railroad Commission of Texas adopts amendments to §13.70 and §13.73, relating to Examination Requirements and Renewals, and Employee Transfers, without changes to the versions published in the November 2, 2007, issue of the Texas Register (32 TexReg 7829).
The Commission adopts the amendments to establish reasonable time limits for qualifying examinations and to extend to ultimate consumers and public entities that hire previously certified individuals the same rules that apply to CNG licensees that hire previously certified individuals. The Commission adopts an effective date of February 1, 2008, for these amendments.
In §13.70(a), the Commission adopts new paragraph (6) concerning time limits for examinations. The time limits, which will begin June 1, 2008, will require an applicant to complete a qualifying examination within two hours from the time the examination begins. The examination proctor will be the official timekeeper. Examinees will be required to turn in their examinations and answer sheets before or at the end of the established time limit for the examination. The proctor will mark any answer sheet that was not completed within the time limit.
The time limits will not affect the open- or closed-book status of qualifying examinations. Management-level examinations are currently closed book, and will remain so. Employee-level examinations are currently open book, and will remain so.
The Commission adopts these time limits for reasons of efficiency. The Commission must be able to plan and budget for the activities and expenses associated with the examination program.
The Commission considers the time limits reasonable. Qualifying examinations vary in length according to the number and complexity of the CNG activities they authorize the examinee to perform. Open-book employee-level examinations currently have 50 questions; closed-book management-level examinations currently have either 50 or 100 questions. A two-hour time limit is adopted for all examinations, based on approximately 2 1/2 minutes per question for an open-book examination and approximately 1-1/4 to 2 1/2 minutes per question for a closed-book examination.
In §13.73, the Commission adds wording to require an ultimate consumer and a state agency, county, municipality, school district, or other governmental subdivision to notify AFRED when a previously certified individual is hired. Other new wording exempts a state agency, county, municipality, school district, or other governmental subdivision from this requirement if such entity chooses not to certify its employees who perform CNG activities. The Commission adds this wording to conform its transfer-notification requirements for ultimate consumers and for public entities that elect to certify their employees to the transfer-notification requirements for licensees. Under the rule as adopted, the Commission will be informed of CNG certified individuals' affiliations and be able to send renewal notices and other communications to the individual's correct work address, regardless whether he or she is employed by a licensee, an ultimate consumer, or a public entity that elects to certify its employees.
The Commission received no comments on the proposal.
The Commission adopts the amendments under Texas Natural Resources Code, §116.034(a), which authorizes the Commission to adopt rules providing examination requirements for persons who are required or who wish to be licensed or registered under Chapter 116.
Statutory authority: Texas Natural Resources Code, §116.034(a).
Cross reference to statute: Texas Natural Resources Code, Chapter 116, §116.034(a).
Issued in Austin, Texas, on December 18, 2007.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706425
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: February 1, 2008
Proposal publication date: November 2, 2007
For further information, please call: (512) 475-1295
Subchapter A. GENERAL APPLICABILITY AND REQUIREMENTS
The Railroad Commission of Texas adopts amendments to §14.2019 and §14.2020, relating to Certification Requirements, and Employee Transfers, without changes to the versions published in the November 2, 2007, issue of the Texas Register (32 TexReg 7831).
The Commission adopts the amendments to establish reasonable time limits for qualifying examinations and to extend to ultimate consumers and public entities that hire previously certified individuals the same rules that apply to LNG licensees that hire previously certified individuals. The Commission adopts an effective date of February 1, 2008, for these amendments.
In §14.2019(a), the Commission adopts new paragraph (6) concerning time limits for examinations. The time limits, which will begin June 1, 2008, will require an applicant to complete a qualifying examination within two or three hours, depending on the length of the examination, from the time the examination begins. The examination proctor will be the official timekeeper. Examinees will be required to turn in their examinations and answer sheets before or at the end of the established time limit for the examination. The proctor will mark any answer sheet that was not completed within the time limit.
The time limits will not affect the open- or closed-book status of qualifying examinations. Management-level examinations are currently closed book, and will remain so; employee-level examinations are currently open book, and will remain so.
A three-hour time limit is adopted for the open-book employee-level LNG Delivery Truck Driver examination and for the closed-book management-level Category 35 Retail and Wholesale Dealers examination, which currently have 80 questions and 135 questions, respectively. A two-hour time limit is adopted for all other LNG examinations, which currently have from 40 to 60 questions (employee-level, open book) or 75 to 85 questions (management-level, closed book).
The Commission adopts these time limits for reasons of efficiency. The Commission must be able to plan and budget for the activities and expenses associated with the examination program.
The Commission considers the time limits reasonable. Qualifying examinations vary in length according to the number and complexity of the LNG activities they authorize the examinee to perform. The three-hour time limit for the open-book employee-level LNG Delivery Truck Driver examination and for the closed-book management-level Category 35 Retail and Wholesale Dealers examination would allow 2 1/4 minutes and 1 1/3 minutes per question, respectively. The two-hour time limit for all other examinations would allow 2 minutes per question for a 60-question examination and 3 minutes per question for a 40-question examination.
In §14.2020, the Commission adds wording to require an ultimate consumer and a state agency, county, municipality, school district, or other governmental subdivision to notify AFRED when a previously certified individual is hired. Other new wording exempts a state agency, county, municipality, school district, or other governmental subdivision from this requirement if such entity chooses not to certify its employees who perform LNG activities. The Commission adds this wording to conform its transfer-notification requirements for ultimate consumers and for public entities that elect to certify their employees to the transfer-notification requirements for licensees. Under the rule as adopted, the Commission will be informed of LNG certified individuals' affiliations and be able to send renewal notices and other communications to the individual's correct work address, regardless whether he or she is employed by a licensee, an ultimate consumer, or a public entity that elects to certify its employees.
The Commission received no comments on the proposal.
The Commission adopts the amendments under Texas Natural Resources Code, §116.034(a), which authorizes the Commission to adopt rules providing examination requirements for persons who are required or who wish to be licensed or registered under Chapter 116.
Statutory authority: Texas Natural Resources Code, §116.034(a).
Cross reference to statute: Texas Natural Resources Code, Chapter 116, §116.034(a).
Issued in Austin, Texas, on December 18, 2007.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 18, 2007.
TRD-200706426
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Effective date: February 1, 2008
Proposal publication date: November 2, 2007
For further information, please call: (512) 475-1295
Chapter 303. GENERAL PROVISIONS
Subchapter D. TEXAS BRED INCENTIVE PROGRAMS
Division 2. PROGRAM FOR HORSES
The Texas Racing Commission adopts an amendment to 16 TAC §303.92, Thoroughbred Rules. This adopted amendment to §303.92(c)(1)(B) allows the payment of Breeder's Awards on an accredited Texas-bred thoroughbred if the dam is accredited with the breed registry within the same calendar year of foaling the subject horse. The proposed amendment was published in the August 24, 2007, edition of the Texas Register (32 TexReg 5276). The Commission received no comments in response to the published notice. The amendment is adopted without change to the proposal as published.
The amendment is adopted under the Texas Racing Act, Texas Civil Statutes, Article 179e, §3.02, which authorizes the Commission to adopt rules relating to horse and greyhound racing, and §9.01, which provides that the breed registries' rules establishing qualifications of Texas-bred horses are subject to Commission approval.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on December 21, 2007.
TRD-200706591
Mark Fenner
General Counsel
Texas Racing Commission
Effective date: January 10, 2008
Proposal publication date: August 24, 2007
For further information, please call: (512) 833-6699