Adopted Rules Title 16

TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 8.PIPELINE SAFETY REGULATIONS

The Commission adopts amendments, in Subchapter A, to §8.5, relating to Definitions; in Subchapter B, adopts amendments to §8.115 and new §8.135, relating to New Construction Commencement Report and Penalty Guidelines for Pipeline Safety Violations; in Subchapter C, adopts amendments to §§8.203, 8.205, 8.210, 8.215, 8.225, 8.230, and 8.235, relating to Supplemental Regulations; Written Procedure for Handling Natural Gas Leak Complaints; Reports; Odorization of Gas; Plastic Pipe Requirements; School Piping Testing; and Natural Gas Pipelines Public Education and Liaison; and, in Subchapter D, adopts amendments to §§8.301, 8.305, 8.310, and 8.315, relating to Required Records and Reporting; Corrosion Control Requirements; Hazardous Liquids and Carbon Dioxide Pipelines Public Education and Liaison; and Hazardous Liquids and Carbon Dioxide Pipelines or Pipeline Facilities Located Within 1,000 Feet of a Public School Building or Facility. The amendments in §§8.205, 8.210, 8.215, and 8.301 and new rule §8.135 are adopted with changes to the proposed versions published in the October 10, 2008, issue of the Texas Register (33 TexReg 8461); the amendments in §§8.5, 8.115, 8.203, 8.225, 8.230, 8.235, 8.305, 8.310, and 8.315 are adopted without changes to the proposed versions. The effective date of the amendments and new rule will be February 4, 2009.

The Commission adopts the amendments and new rule to provide guidelines for filing required reports with the Commission, to address new risk management initiatives for the Commission's pipeline safety evaluation program, and to remove outdated or duplicative rule requirements.

The Commission received comments from ten entities. Five groups or associations submitted comments: Texas Pipeline Association ("TPA"); Texas Independent Producers and Royalty Owners ("TIPRO"); Texas Oil and Gas Association ("TxOGA"); Permian Basin Petroleum Association ("PBPA"); and Texas Coalition of Cities for Utility Issues ("TCCFUI"), whose member cities are Abernathy, Addison, Alamo, Allen, Andrews, Arlington, Balcones Heights, Belton, Benbrook, Big Spring, Bowie, Breckenridge, Brenham, Brookside Village, Brownfield, Brownwood, Buffalo, Canyon, Carrollton, Cedar Hill, Center, Cleburne, Conroe, Corinth, Corpus Christi, Cottonwood Shores, Crockett, Dallas, Denison, Denton, Dickinson, El Lago, Electra, Euless, Fairview, Flower Mound, Fort Worth Fredericksburg, Friendswood, Frisco, Galveston, Grand Prairie, Grapevine, Greenville, Gregory, Henrietta, Huntsville, Irving, La Grange, La Joya, Lampasas, Lancaster, Laredo, League City, Leon Valley, Levelland, Lewisville, Longview, Los Fresnos, Mansfield, McAllen, Midlothian, Missouri City, Newark, Nolanville, North Richland Hills, Oak Point, Palacios, Pampa, Paris, Pearsall, Plainview, Plano, Port Neches, Ralls, Refugio, Reno, Richardson, River Oaks, Rosenberg, San Jacinto City, San Marcos, San Saba, Selma, Seminole, Seymour, Smithville, Snyder, South Padre Island, Spearman, Stephenville, Sugar Land, Sunset Valley, Sweeny, Taylor Lake Village, Terrell, Thompsons, Timpson, Trophy Club, Tyler, University Park, Vernon, Victoria, Waxahachie, Webster, West University Place, and Westlake. Other comments were submitted by Atmos Energy Corporation ("Atmos Energy"); CenterPoint Energy Arkla, CenterPoint Energy Entex and CenterPoint Energy Intrastate Pipeline, Inc. (collectively "CenterPoint"); Texas Gas Service ("TGS"); CPS Energy; and one individual.

TPA stated that it appreciates the Commission's efforts to clarify the issues identified last year.

TIPRO commented that it understands the purpose of the proposed changes is to implement new federal regulations governing persons owning or operating pipelines in Texas. By adopting the federal regulation by reference, rules covering pipeline safety in Texas would conform to federal requirements. These rules should be no more or no less stringent than the federal rules. TIPRO agrees with that effort, and with the Commission's authority to regulate all common carrier and common purchaser pipelines in Texas.

PBPA stated its full support of the comments provided by TxOGA regarding these proposed rule changes.

TCCFUI stated that, overall, the rules provide a positive revision to the Commission's pipeline safety rules. It is critical to the safety of the general public, and in particular the populations of urban areas, that the Commission continue to examine and amend its pipeline safety rules to put in place a regime that is comprehensive and consistent with federal law, yet efficient in its implementation. Given the increasing production of natural gas in densely populated areas, such as in the Barnett Shale, it is indeed imperative that the Commission update its pipeline safety rules to create orderly and effective mechanisms to handle penalties for violations, leak complaints, and odorization issues with respect to natural gas lines. Public awareness regarding natural gas pipelines is also an important component to pipeline safety, both through public education and public notice. TCCFUI stated that the proposed rules represent an excellent step in this direction.

CenterPoint stated its general support of the goal of updating the state rules to achieve consistency with their federal counterparts, and acknowledged that the Commission has both the right and a policy imperative to amplify upon the federal rules and enact stricter rules governing intrastate pipelines in areas such as incident reporting and odorization. Most of CenterPoint's comments seek clarification of the proposed rules and the Commission's intent behind them.

TGS stated its support of the efforts of the Commission to clarify the rules and increase safety within the industry. TGS supports the concepts contained in the proposed Chapter 8 rules.

CPS Energy agreed with a vast majority of the proposed Chapter 8 rule changes, but recommends that the Commission consider its specific suggested changes to §8.205 and §8.210.

Regarding the proposed amendment of the definition of the term "transportation of gas" in §8.5(28), TIPRO sought to clarify the use of the phrase "production facilities." This section of the rule concerns definitions applicable to pipelines covered by the Commission's proposal. Again, TIPRO commented, if the Commission intends to adopt the federal rules by reference and not expand the coverage of the rules, TIPRO agrees with that effort. However, TIPRO believes the inclusion of "production" expands the scope of the federal rules. TIPRO seeks clarification to determine if that expansion is intended. In response, the Commission affirms its intent that the rules will apply to production facilities, as set forth in foregoing paragraphs.

In §8.115, the Commission proposed to clarify the requirements for filing a new construction report and to specify that the requirement applies to liquefied petroleum gas distribution systems. TCCFUI supports the Commission's proposed amendments to §8.115, but recommends additional changes that, in TCCFUI's view, do not attempt to remove the Commission's amendments, but instead seek to improve on the quality of information provided by natural gas pipeline operators to the Commission and to increase public awareness of the construction and installation of natural gas pipelines within the certain portions of the corporate limits of a municipality, prior to construction. Specifically, TCCFUI would require that the pre-construction reports also identify public streets, right-of-ways, and alleys to be traversed that are located with the corporate limits of a municipality, if any, and that each operator filing a Form PS-48 report for the construction of a natural gas pipeline with the Commission in accordance with this rule also submit a copy of that report with every municipality, through its City Manager, that has a public street, right-of-way, or alley that is proposed to be traversed by such pipe, at least 30 days prior to commencement of construction of that pipe.

In support of its suggested additional requirements, TCCFUI's stated that although its proposed changes to §8.115 would require the Commission to add a line item to Form PS-48 requesting the streets, rights-of-way, and alleys traversed within the corporate limits of a municipality, the modifications do not place a greater burden on the Commission on a day-to-day basis. Additionally, the impact of these changes to operators is minimal. With these offered changes, TCCFUI stated, operators would be required to provide the Commission with the public streets, right-of-ways, and alleys within the corporate limits of a municipality that would be crossed by the proposed pipe route, and to provide a copy of Form PS-48 to that municipality. TCCFUI further asserted that the Commission has jurisdiction to incorporate these changes into §8.115 in this rulemaking. As noted in the Commission's discussion of the changes proposed for Chapter 8, Subchapter B, Texas Natural Resources Code §81.051 and §81.052, grants the Commission with jurisdiction over all common carrier pipelines, persons owning or operating pipelines in Texas, and authorizes the Commission to adopt all necessary rules for governing and regulating persons and their operations. In addition to this general authority, TCCFUI notes, Texas Utilities Code, §§121.201 - 121.210, authorize the Commission to adopt safety standards and practices applicable to the transportation of gas and for associated pipeline facilities. In particular, Texas Utilities Code, §121.2015, requires the Commission to adopt rules regarding public education and awareness of gas pipeline facilities. TCCFUI's argues that its proposed changes further public education and awareness, through municipal notice, regarding the location of new pipes that will be constructed within that city's corporate limits. Providing such information to municipalities, and thus, their citizenry, prior to construction will promote public safety and facilitate the construction of pipes within the corporate limits of a municipality. A municipality has an interest in being notified of the potential construction of any new natural gas pipelines within its city limits, prior to the initiation of construction. But for providing a municipality with a copy of Form PS-48, TCCFUI avers, a municipality may not otherwise be aware of the installation of a new pipeline. For example, under the Underground Facility Damage Prevention and Safety Act, Texas Utilities Code, Chapter 251, municipalities are not required to participate in the Texas One Call system. Further, water and sewer utility lines, designated as "Class B underground facilities," are not required to participate in a one-call notification center operation. See Texas Utilities Code, §121.107, which requires each operator of a Class A underground facility, including a political subdivision of this state, to participate in a notification center as a condition of doing business in this state. Thus, providing a municipality with the proposed pipe route through that city, prior to construction, could minimize the potential for rupturing water and wastewater utility lines that are already in place, as a pipeline operator may not be aware of the location of such utility lines. The Underground Facility Damage Prevention and Safety Act recognizes this possibility, as Texas Utilities Code, §251.153(a), places the duty on a One Call notification center, at the time an excavator provides a notification center with the excavator's intent to excavate, to advise the excavator that water, slurry, and sewage underground facilities in the area of the proposed excavation may not receive information concerning the excavator's proposed excavation. Thus, by providing municipalities with a copy of Form PS-48 prior to construction could reduce the likelihood and costs associated with repairing a ruptured line. In conclusion, TCCFUI noted that the Commission has done an exceptional job of following through on its proposed changes from 2007, incorporating subsequent public comment regarding pipeline safety. In these comments, TCCFUI seeks to add value to the hard work that has been put forth to date, and to offer additional changes to §8.115 that will not unduly burden the Commission, but instead inform the public of new pipeline construction initiatives within urban areas.

The Commission recognizes that, under the statutory provisions cited by TCCFUI, the Commission has the authority to impose the requirements suggested by TCCFUI, and that such additional requirements would be an efficient way of notifying many public entities of imminent pipeline construction. However, under Texas Government Code, Chapter 2001, state agencies must give notice of their intent to amend rules, and one of the requirements is to specifically identify the proposed wording changes. With respect to making changes upon the adoption of a proposed rule, the Third Court of Appeals wrote: " . . . should the proposed rules, as originally published, be ignored and others adopted or should other subjects or persons be affected by the altered rule, a new round of notice and comment should be required." (Emphasis added.) State Bd. of Ins. v. Deffebach, 631 S.W.2d 794, Tex. App. 3 Dist., 1982. The Commission has determined that, despite the reasonableness and efficiency of TCCFUI's suggested changes, the scope of notice in this rulemaking would not permit their inclusion. In the meantime, a municipality likely has the authority to require by city ordinance that a pipeline operator filing with the Railroad Commission a Form PS-48 showing a municipal street, right-of-way, or alley that is proposed to be traversed by a new pipeline also submit a copy of that report with the municipality's City Manager at least 30 days prior to commencement of construction of that pipeline.

TPA expressed no objection to the Commission proposal in §8.115, but requested that the Commission staff work with industry representatives to streamline the construction notification process after the rule adoption. Because of significant activity in certain areas of the state, both operators and the Commission should have a process that maximizes the efficiency of the reporting process as well as guarantees the accuracy of the information being required and submitted. The current process places a significant burden on both the industry and the Commission for a number of reasons and does not accomplish the goals of the Commission. Because TPA did not offer specific criticisms of the ways in which the process is claimed to burden industry and the Commission, identify the ways in which the Commission's goals are not being met, or offer suggestions for changing the process that would not need to be part of the rule, the Commission is unable to respond to this comment.

TxOGA commented that while the wording does not specify production operations, TxOGA understands the Commission's intent to be that this provision will apply to regulated production operations as well, which means that the Commission's advance reporting requirement for gas pipelines is more stringent than federal or adjoining state requirements. TxOGA recommends that aligning the gas pipeline pre-construction notice requirements in the Texas regulations with those in the federal regulations and in some other major oil and gas states be considered by the Commission in a future pipeline safety rulemaking and that, if necessary, the Commission convene a workgroup to develop a specific recommendation in this regard. The Commission confirms its intent that the pre-construction notice requirements apply to production operations.

With respect to new §8.135, relating to Penalty Guidelines for Pipeline Safety Violations, TPA commented that it does not object to the proposal; however, TPA requests that the Commission further review how repeat or multiple violations impact operators, and, more specifically, when the violations are by different operational units or areas. This can be highlighted especially by those penalized under the damage prevention safety rules in Chapter 18 (relating to Underground Pipeline Damage Prevention). Larger operators have an inherent disadvantage in that they have a great exposure to increased penalty enhancement because of significantly more one-call tickets due to more miles of pipeline. A strong argument can be made that a large pipeline operator receiving tens-of-thousands of one-call tickets should not be penalized in the same manner as an operator who only receives 50 locate tickets per year.

TxOGA commented that the consolidation of gas and hazardous liquid pipeline penalty guidelines in §8.135 is not intended to change the current guidelines, but expressed an issue with regard to the current guideline. The "penalty enhancement" section provides for increased penalties for repeat offenders. TxOGA does not dispute the necessity of such penalty enhancement in some cases, but notes that there is no provision for consideration of such offenses on a regional basis for an operator with statewide operations. TxOGA recommends that such a refinement of the penalty enhancement provision for repeat offenders be considered by the Commission in a future pipeline safety rulemaking and that, if necessary, the Commission convene a workgroup to develop a specific recommendation in this regard.

The Commission neither agrees nor disagrees with these comments regarding enforcement policy for repeat or multiple violations; moving this rule from the subchapter devoted to natural gas pipelines to the subchapter applicable to all pipelines was intended to ensure that the Commission's penalty guidelines were administered equitably with respect to both natural gas pipelines and hazardous liquids and carbon dioxide pipelines.

The Commission received numerous comments regarding the proposed amendments in §8.205(3) that would require that the supervisory review of leak complaints be completed and documented by 10:00 a.m. each day for calls received by midnight on the previous day. CenterPoint stated that while it understands the need for a second level of review of leak response, using specially trained personnel with the requisite authority to require remedial action would achieve the same results. CenterPoint recommends that the rule allow this review to be conducted by such specially trained personnel, and that the rule also allow the review to be conducted by the next work day rather than the next calendar day.

Atmos Energy acknowledged that the proposed rule reflects recognition of the continuous operational aspects of natural gas distribution systems. Atmos Energy submits, however, that the rule should be modified to allow for review of the leak reports by 10 a.m. of the following business day as opposed to the proposed review by 10 a.m. of the following day. Additionally, Atmos Energy suggests that the "supervisory review" terminology be modified to more clearly establish that it is appropriate for experienced personnel who are not supervisors to perform this review.

CPS Energy recommends that §8.205(3) state that a trained person (i.e., a dispatcher or other qualified employee) may perform the review of all leak complaints. The current language implies that only a supervisor may perform the review of leak complaints for a gas operator. CPS Energy believes the proposed regulation places an unnecessary burden on its supervisors to perform this requirement 365 days a year when there are other trained and qualified individuals who are also capable of performing this function.

TGS suggests that the proposed rule be amended as follows: "a requirement that a review of leak complaints by trained personnel must be completed and documented by 10:00 a. m. each day for calls received by midnight on the previous day."

TPA suggested during the initial rulemaking that the establishment of a specific time for completion of supervisory reviews of leak complaints is appropriate, and the Commission should be commended for establishing a deadline. However, in light of the possibility that leak complaints could be called in on the day before a holiday or weekend or during a weekend, the deadline for supervisory review should be set at 10:00 of the next business day. This slight change will accommodate the delays inherent in the scheduling of work for weekends and holidays.

The Commission disagrees with some of these comments. The purpose of the proposal is to ensure that if a leak is hazardous, it is being addressed. Human review is necessary to determine if the leak has been graded properly, and the review should be conducted by someone with authority, not just knowledge, in case the leak grade needs to be changed. The requirement that the review be conducted by a supervisor was already in §8.205(3) and was not proposed to be changed. With respect to the timing of the review, however, the Commission agrees that it is reasonable to change the wording as it was proposed to allow the deadline to be 10:00 a.m. of the next business day.

Regarding the proposed amendment to §8.210(a)(1), CenterPoint stated that it supports the use of the federal criteria for incident reporting and the concomitant elimination of the current duplicative incident reporting regime. In particular, it should allow operators to utilize their experience under the federal regime to determine when an incident is significant in light of its severity and relative effect on the communities in which they operate. However, CenterPoint commented that the Commission also proposes some more troublesome changes to other parts of the regulation. In §8.210(a)(2)(F), the proposed requirement that the telephonic report include the telephone number of the operator's on-site person, CenterPoint commented that, in almost all cases, the crew responding to a gas-related incident will be acting as first responders, not as trained fire investigators or insurance adjusters who can accurately render damage estimates or opine about the cause and origin of the incident. These employees' first tasks are to make the area safe, protect life and property, and then conduct certain tests. Needless to say, the first few hours after an incident can be chaotic and dangerous. The crew may be hard pressed to accomplish even the basic tasks of protecting life, property, and the integrity of the system during that time period. In addition, many crews do not carry a mobile telephone and thus communicate to their respective offices by radio only. It would be more helpful and appropriate for the Commission to contact the crew's supervisor or another local company representative during those critical first hours after an incident. Thus, CenterPoint suggests that proposed subsection (a)(2)(F) be changed to require only the telephone number of a contact person rather than the number of an on-site employee. Atmos Energy commented that while Atmos Energy is not opposed to providing the Commission with the telephone number of on-site personnel, Atmos Energy stresses that the work priority for on-site personnel is making the situation safe, not responding to telephone inquiries. The Commission appreciates that the primary obligations of gas company first-responders is to deal with emergent events. However, having the telephone number of the operator's on-site person assists the Railroad Commission staff in determining whether the Commission need to go on-site, whereas contacting a crew supervisor or other local company representative would not provide the Commission with specific data regarding the conditions at the incident site. The rule allows an operator two hours to make the telephonic report, so this should permit sufficient time for making the telephone call and providing the information necessary for the Commission to fulfill its obligations.

Several entities commented on the proposal to add subparagraph (G) in §8.210(a)(2), requiring a report of the estimated property damage, including the cost of gas lost, to the operator, others, or both. CenterPoint stated that an accurate estimate of the damage (other than that required to determine whether the incident is reportable) may be impossible during the first day after an incident. For example, the amount of gas lost cannot be accurately measured until the time of the rupture and the size of the hole are determined. The damage estimate requirement should also await the written report due 30 days after the incident. Atmos Energy stated that it is not opposed to providing an estimate of property damage at the time the telephonic report is made, but stated that the estimate will be very rough, at best. TPA has no objection to the requirement to report estimated damage with the telephonic report, however, deleting this provision would make the natural gas reporting requirements consistent with the requirements found under the reporting requirements for hazardous materials and carbon dioxide pipelines in §8.301. If the damage estimate provision remains in the final rule, TPA wants to be certain that the Commission is aware that any such estimates will be very rough. Accurate estimates of property damage cannot be made until after the investigation is competed and the extent of necessary repairs is determined. The Commission agrees that the initial estimates will necessarily be very rough, but is interested primarily in knowing whether the damage is over or under $50,000. Under the definition of "incident" in 49 CFR §191.3, if an operator is calling to report a release in which there is no death or injury and no media involvement, then the call is being made because the estimated property damage is $50,000 or more. Further, the requirement to make an estimate of property damage in the initial telephonic report is not new; only the amount has been changed (increased from $5,000 to $50,000).

The Commission proposed to amend §8.210(a)(2)(H) to add examples of significant facts that should be reported. Ignition, explosion, rerouting of traffic, evacuation of any building, and media interest are included as significant facts relevant to the accident or incident. Atmos Energy commented that it is uncertain if "significant facts" are distinguishable from "significant events" which cause an event to become a reportable event even if no injury occurs and the stated property damage threshold is not met. As an example, the evacuation of any building is listed as a "significant fact." If "building" means "structure" which would include a residence, then the evacuation of a single residence becomes a "significant fact" which should be included in the telephonic report if the incident is reportable for other criteria reasons. On the other hand, if the "significant fact" of a single residence evacuation is equated with a "significant event," then all evacuations become reportable events which will cause a spike in every operator's telephonic reports. Atmos Energy suggests that the Commission clarify its intent to distinguish between "significant events" and "significant facts." TPA commented that the inclusion of the evacuation of any building as a significant fact to be included in the telephonic report places a classification of "significant" on single home evacuations. While those evacuations will be significant to the individual residents of a home, reporting such information will not contribute meaningfully to pipeline safety data. It would seem to be more beneficial to gather data related to evacuations impacting larger numbers of individuals, such as schools or commercial buildings, and TPA would suggest that such an addition be made to this particular reporting requirement. The Commission disagrees with comments that interpret this proposal as converting an otherwise unreportable incident into a reportable incident. The requirement to include "other significant facts" in a telephonic report is not new; the only change is to add examples of facts that are significant enough to be reported if a report is necessary. An incident that would not be reportable under the standards in §8.210(a)(1) does not become reportable just because of a "significant fact," such as ignition, explosion, rerouting of traffic, evacuation of any building, or media interest. The significant fact is simply additional information to be reported.

The proposal to add new subsection (e), relating to leak reporting, to §8.210, garnered extensive comments. CenterPoint commented that the new reporting mechanism would apparently require operators to enter 27 different items of information about each leak and, while the preamble to the rules suggest that an electronic data interchange system will allow the transmission of the required data by spreadsheet, it is still likely that errors will occur that will require manual entry or at least correction. For a large operator such as CenterPoint that experiences thousands of leaks in a 6 month period, it would be administratively burdensome to correct or verify the potentially thousands of pieces of information contained in these semi-annual reports. CenterPoint believes that this new report is unnecessary since the Commission already has the right to audit leak records under current law. However, if the Commission still desires to implement this new reporting requirement, CenterPoint suggests that a summary of the types of leaks encountered on its system would be a more efficient and equally informative method of gathering the information that the Commission seeks. Instead of entering the information for each particular leak, an operator could provide a total for each category of information for all leaks it experienced during the reporting period. If the Commission requires more information, it would be able to audit behind these numbers to obtain this data as well as insure its accuracy. Finally, the reference to an operator's "pipeline system" does not make it clear whether the report must include leaks on non-jurisdictional facilities (such as customer house piping) as well as those on the operator's pipeline facilities. Such leaks are not required to be monitored under Commission rules nor are they presently included in the annual report required by 49 CFR §191.11. In order to resolve this ambiguity, CenterPoint suggests the subsection be amended to refer to leaks on "pipeline facilities" so as to incorporate the corresponding definition already contained in §8.5.

Atmos Energy commented that the information required to be reported is already available to the Commission and requiring the information to be provided in the online format is duplicative. Further, in the event the semi-annual reporting requirement is adopted, Atmos Energy submits that the rule should be revised to allow for a reasonable period of time between the end of the semi-annual period and the online reporting due date for the leak information. Also, the online reporting should be specifically directed to below ground leaks.

CPS Energy recommends that Form PS-95 be required to be filled out for below ground leaks for only the following reasons:

1. below ground leaks are what present a potential danger to the public;

2. CPS Energy's experience at capturing the data on above ground leaks has shown that they are typically on threaded connections, non-hazardous, and do not present a danger to the public due to the extremely small quantities of gas that is vented to atmosphere from these leaks;

3. according to the instructions for completing the PHMSA Annual Reports for Distribution or Transmission systems; Forms F 7100.1-1 and F 7100.2-1, a non-hazardous release of gas that can be eliminated by lubrication, adjustment or tightening is not defined as a leak. Since most aboveground leaks can be eliminated by lubrication, adjustment or tightening, CPS Energy feels that these should not be included in the proposed reporting requirements;

4. many gas operators do not currently report or grade above ground leaks;

5. the number of above ground leaks repaired is far greater than the number of below ground leaks repaired and will require a substantial amount of time to collect and input the data into the PS-95 on-line form; and

6. little value will be realized by capturing the data for above ground leaks when compared to the time and expense required to collect and input the data.

TGS believes the detail that is required to be reported is burdensome and will require expensive modifications to our existing processes and software programs. TGS can comply with semi-annual reports with less detail on the seven items listed out in the proposed rule without an appreciable increase in costs. This can be accomplished if the report will aggregate the items similar to the OPS Annual Gas Distribution Report twice a year without the specific detail requirements on each leak. As proposed, the detail required also appears to be in conflict with the OPS definitions of what is considered a leak. As defined in the instructions of PHMSA F 7100.1-1 form, "A leak is defined as an unintentional escape of gas from the pipeline. A non-hazardous release that can be eliminated by lubrication, adjustment, or tightening, is not a leak." Based upon this definition, there seems to be a difference in the proposed rule and the PHMSA rules which will create confusion in reporting and data analysis between PHMSA and the State of Texas. If these changes cannot be implemented, then TGS requests a workshop be conducted to review this proposed rule change with industry to determine if some changes can be accomplished.

TPA commented that the final rule is unclear as to whether the reporting requirement only applies to local distribution company (LDC) operators as it states in the preamble of the rule. TPA requests the Commission clarify in the final rule that the semi-annual reporting requirement only applies to LDCs. Midstream pipeline operators are required to report leaks that meet the requirements of 49 CFR 191.3 to the Commission. Further, leaks are repaired. Pipeline operators do not have the same types of leaks, nor leak grading system or repair schedule in comparison with the LDCs.

TxOGA commented that the leak reporting requirements proposed in §8.210(e), as drafted, appear to apply to all operators of pipelines, and possibly even to production facility operators. The Commission's impact analysis for this portion of the proposal speaks only of the cost to gas distribution companies. TxOGA now understands that it is the intent of the Commission that this section of the proposal apply only to gas distribution companies and to operators of plastic gas transmission lines. TxOGA concurs with this limitation on the regulation and recommends adding the italicized wording to clarify the requirement: (e) Leak Reporting. Each operator of a gas distribution system or plastic gas transmission line shall submit to the Division a list of all leaks repaired on its pipeline systems. The report shall list all leaks identified on the entire pipeline system. Each such operator shall also include the number of unrepaired leaks remaining on the operator's systems by leak grade. Each such operator shall submit leak reports using the Commission's online reporting system, Form PS-95, by June 30 and December 31 of each calendar year, in accordance with the PS-95 Semi-Annual Leak Report Electronic Filing Requirements, set out in Figure 1 of this subsection. The report includes:..."

The Commission agrees that the term "pipeline facilities" is preferable to the term "pipeline systems," and has made that change in the text of the adopted rule. The Commission disagrees that having leak information available to audit is sufficient. The purpose of the reporting requirement is to enable the Commission to accumulate data from across all systems to identify trends or problems more comprehensively. The Commission also disagrees that operators would be unable to correct data already reported; that will be possible on the online reporting system. The Commission agrees that a non-hazardous release of gas that can be eliminated by lubrication, adjustment, or tightening is not defined as a leak; however, there are other above ground leaks that cannot be eliminated using these methods, and those must be reported as leaks. The Commission adopts §8.210(e) with clarifying wording regarding the definition of the term "leak" for the purpose of submitting the Form PS-95. The Commission also agrees that, because this rulemaking includes the elimination of the plastic pipe failure report, this rule must include information about any leak on any plastic pipe, not just distribution plastic pipe. The leak reporting requirements apply to operators of local gas distribution companies, operators of regulated plastic gas gathering lines, and operators of plastic gas transmission lines, and the Commission has modified the wording in §8.210(e) to clarify this intent.

Regarding the proposal to amend §8.215(b) to permit gas companies to use commercially available odorization equipment rather than having the Commission approve odorization equipment, CenterPoint commented that while this change avoids having the Commission rule on "permissible" odorizers and odorants, the term "commercially available" does not necessarily equate to satisfactory performance. In particular, the fact that equipment is commercially available would not guarantee that a product meets the performance criteria that would still be required under the rule. A more prudent approach would be to require "industry accepted" or "industry standard" equipment. In addition, CenterPoint requests that the rule contain a "grandfather" clause that would provide that all previously approved or currently used equipment would meet the standards established under the rule. Atmos Energy commented that the use of any existing shop-made odorization equipment should be grandfathered for a reasonable period of time. TPA seeks to clarify that non-commercial odorization equipment already in place, which has been approved by the Commission, may continue to be used by operators. TxOGA understands that it was not the intent of the Commission to disallow continued use of previously approved odorization devices and recommends the following italicized language to clarify that intent: (b) Odorization equipment. Gas companies shall use commercially available odorization equipment in any installation made on or after (the effective date of this rule). Shop-made or other odorization equipment previously approved by the Commission and in use as of (the effective date of this rule) may continue to be used in its current service, but may not be re-installed in a different location.

The Commission disagrees that substituting "industry standard" would be a more prudent standard than the proposed "commercially available." The proposed change shifts the burden of selecting odorization equipment that meets the performance standards of the rule. These are management decisions properly left to each operator. The Commission disagrees that a rule with prospective effect only could invalidate existing use of shop-made odorization equipment, but does not object to adding the wording suggested by TxOGA, but has substituted "February 4, 2009," for "the effective date of this rule" to clarify the requirement.

In §8.235(a), the Commission proposed to change deadline by which operators of natural gas pipelines or natural gas pipeline facilities are required to communicate and conduct liaison activities fire, police, and other appropriate public emergency response officials. Currently the requirement is that these activities are to be conducted on an annual basis; the Commission proposed to amend the deadline to once each calendar year at intervals not exceeding 15 months. Atmos Energy commented that because of the hierarchical requirements of the Commission's rule (face-to-face meeting attempts followed by attempts to schedule a conference call and then mailing the information by certified mail) in the event the annually scheduled meeting does not take place, it will be difficult to accomplish all of the ensuing actions in a three month window. Atmos Energy submits that the proposed rule should be revised to provide for the initial face-to-face meeting request to be made once each calendar year at intervals not exceeding fifteen months from the date of the completion of the last liaison activity with that emergency responder, with any subsequent liaison activity to be accomplished by the end of the calendar year. The Commission disagrees with this comment. The intent of the current rule is that operators conduct these liaison activities once a year, but some operators would allow an interval of as long as 23 months between such meetings, e.g., January of one year but not until December of the following year, nearly a two-year lapse. The Commission acknowledges that it can take some time and effort to set up the meetings or conference calls, but there is nothing in the rule that prohibits an operator from beginning the efforts at the nine or ten month interval to ensure that there is sufficient time to complete the required actions by the 15th month.

With respect to the proposed amendment in §8.235(e), Atmos Energy had no comment on the proposed timing of the report, but does suggest that the Commission take this opportunity to clarify that the report is specific to transmission facilities within 1,000 feet of a public school building or recreational area. The Commission disagrees with this comment; no one has ever interpreted this rule as applying to distribution facilities.

With respect to the proposed amendments in §8.235(e) and §8.315(c), TPA pointed out in its comments on the initial proposal that many companies have both gas lines and hazardous liquids lines which often follow the same route. It is much more efficient for those companies to survey the routes of both types of lines at the same time instead of doing the gas line route one year and doing the same survey for the liquids lines in the same route the next year. Since submitting their initial comments, operators have further contemplated the best way to provide this information to the Commission without creating an undue burden on the operators or the Commission. TPA suggests that Commission require the information to be submitted to the Commission only once via an online system that can be updated by operators as changes occur. Operators would be required to update their list of schools as changes occur, but no less than one year from the date of the change. This solution will help streamline the reporting process in a manner that allows an active data base to be developed that remains updated. This simplifies the current reporting process that requires Commission staff to receive, sort, and enter information on a yearly basis, which is a very labor intensive process. TPA requests these changes be made to the appropriate sections of the rule that would establish a reporting schedule outlined above. Further, a working group should be established to develop the system by which operators would report, change, and track their lists.

TxOGA believes that it would be a more efficient use of Commission and industry resources for this information to be furnished one time to allow creation of a Commission database, with pipeline operators then being required to update the information with a given time (e.g., a year) of any change. TxOGA recommends that this be considered by the Commission in a future pipeline safety rulemaking.

The Commission disagrees with both comments. There is nothing in either §8.235(e) or §8.315(c), as proposed, that prohibits a company with both natural gas and hazardous liquids pipelines and/or facilities that follow the same route from filing the information every year. The even-numbered year filing deadline for operators of natural gas pipelines and/or facilities and the odd-numbered year filing deadline for operators of hazardous liquids pipelines and/or facilities is the longest that the interval between filing updated information may be. But if it is more efficient for those companies to survey the routes of both types of lines at the same time instead of doing the gas line route one year and doing the same survey for the liquids lines in the same route the next year, then the Commission has no objection to both reports being filed every year. In addition, updates to pipeline routes can be made online.

New amendments in §8.5 add a reference to 49 CFR Part 40, clarify the definitions of "master metered system" and "pressure test" in paragraphs (18) and (24), respectively, and add a reference to onshore pipeline, gathering, and production facilities to the definition of "transportation of gas" in paragraph (28). To address the concerns raised during the workshop regarding the definition of the gathering and regulated production facilities, the Commission adopts a revised definition of the term "transportation of gas" which includes a reference to the definition of "first point of measurement" that is found in 49 CFR Part 192.

The Commission adopts new wording in §8.115 to add a reference to Form PS-48 and to describe requirements for new construction reports.

The Commission adopts new §8.135 to move the penalty guidelines for pipeline safety violations from Subchapter C, which applies to requirements for natural gas pipelines only, to Subchapter B, so that the guidelines will apply to all pipelines. Most of the text of the rule is the same as §8.245, the repeal of which is adopted in a concurrent rulemaking, but Tables 1 and 5 have been amended to include references to the rules pertaining to hazardous liquids and carbon dioxide pipelines and pipeline facilities, and the Commission removed the provision in subsection (g) that prohibited reduction of a proposed penalty after a hearing has convened, in order to preserve flexibility in the administration of enforcement matters. These changes mean that penalty provisions for violations of the federal and Commission rules for all pipelines and specific provisions for operator qualification and integrity management for both natural gas and liquids pipelines are included in the rule.

In §8.203, the Commission adopts updated references to federal statutes that have been changed and with which operators already must comply.

The Commission adopts clarifying wording in §8.205 to state that supervisory review of leak complaints must be completed and documented by 10:00 a.m. of the next business day for calls received by midnight on the previous day.

In §8.210(a)(1), the Commission adopts amendments to add a reference to 49 CFR Part 191.3 and to delete some specific wording in subparagraphs (A) - (E) and paragraph (2) that is now covered by Part 191.3. In paragraph (3), renumbered to paragraph (2), the Commission adds new subparagraphs (F) and (G) to require including the telephone number of the operator's on-site person, and estimated property damage, including the cost of gas lost, to the operator, others, or both. In subparagraph (H) (currently designated as (F)), the Commission adopts new wording to state that ignition, explosion, rerouting of traffic, evacuation of any building, and media interest are considered significant facts that must be reported. In paragraph (3) (currently designated as (4)), the Commission adds a reference to 49 CFR Part 191 and new wording to describe Department of Transportation reports.

As adopted, §8.210(b)(1) includes the addition of the word "intrastate" for systems which must file pipeline safety annual reports, and the remainder of this paragraph is reworded to conform to the Department of Transportation reporting requirements. The Commission has added clarifying language permitting such reports to be filed with the Commission electronically, at the operator's election.

The Commission adopts new subsection (e) to require natural gas operators to submit on a semi-annual basis information regarding the number of repaired leaks on their pipeline facilities as well as the number of leaks remaining unrepaired. The Commission adopts this section with clarifying wording regarding the scope of the application, replacing "pipeline systems" with "pipeline facilities"; defining the term "leak"; and specifying that the requirements of this subsection are applicable to operators of gas distribution systems, regulated gas gathering lines, and plastic gas transmission lines.

Each operator is required to submit a listing of repaired leaks on proposed new Form PS-95 that describes the leak and the method of repair. The Form PS-95 report also requires reporting of information for the leaks on the system yet to be repaired, organized by leak grade. This new form incorporates the information required on the Plastic Pipe Failure Report, PS-80, and therefore the Commission also deletes §8.225(a), as discussed below. As proposed, the Form PS-95 reports were to be submitted electronically into the Commission's Pipeline Safety Integrity system on June 30 and December 31 of each calendar year. However, the Commission adopts a clarifying change to this section to move the deadlines for submitting the reports to later dates (July 15 and January 15) so that the reports will include data from January 1 through June 30 and from July 1 through December 31.

Step 1 on the online PS-95 Leak Report is to report the number of unrepaired leaks on the system by grade, as defined in §8.207(b) - (d). Step 2 is to report leaks that have been repaired. The Form PS-95 uses drop-down menus for many of the data elements required to be reported. For each leak repaired during the reporting period, the operator must provide the address; operator's leak identification number; date reported; whether above or below ground; the location on the pipe (e.g., body of pipe, valve, joint, riser, tap, compression coupling, etc.); if on a joint, what type (e.g., threaded, bell and spigot, flange, etc.); if on a fitting, what type (e.g., saddle fitting, elbow, tee, split sleeve, meter swivel, etc.); if the type of fitting coupling was plastic or metal, the name of the manufacturer and the model; the facility type (main, service, or transmission); the grade (1, 2, or 3); the pipe size; the type of pipe (e.g., bare steel, coated steel, galvanized, copper, brass, PVC, etc.); the cause or causes of the leak (corrosion; excavation (operator personnel/contractors excavating, other third party excavators, locator, or vehicle); natural forces (lightning, washout, ground movement, ice, or static electricity); other outside forces (vandalism, fire/explosion, or excessive strain); materials and welds (dent, gouge, factory defect, wrinkle bend, weld (steel) or fusion defect (plastic)); equipment (equipment malfunction, gasket/o-ring, or packing); operations (inadequate/failure to follow procedures; stripped threads; or backfill), or other group (not excavated or other); the leak repair method (e.g., clamp installed, split sleeve, replacement (component or pipe), greasing, doping/caulking, etc.); and the date of the repair.

The Commission is implementing two electronic filing methods for new Form PS-95 Leak Report, an online system and an Electronic Document Interchange (EDI) filing procedure. An organization (i.e., a Form P-5 operator) must file a Security Administrator Designation (SAD) Form with the Commission as a requirement for filing online or using EDI. An account is created for the person designated on the SAD Form as the Security Administrator for the organization. This Security Administrator, in turn, can assign filing rights to the organization's employees that authorize them to file Commission forms electronically. Organizations that have existing SAD forms do not need to re-file; the existing Security Administrators will be able to assign Pipeline Integrity filing rights to the users within the RRC Online System.

Each file submitted to the Commission for EDI processing must have an Identifying Record as the first record in the file. The processing of this record includes the validation that the User ID is authorized to file electronically. An operator using spreadsheet software to compile data for the Form PS-95 will be able to export the file to a right curly bracket (}) delimited format for EDI submission. This application eliminates the requirement to submit a test file, but it will validate the format of each file submitted. Numeric columns must not contain any commas; e.g., use 1000000 for one million, not 1,000,000. Nor should columns contain currency formatting like "$" or "USD." Data entry is case sensitive. A file not meeting the formatting requirements will be rejected. Filers will be required to correct the formatting error and resubmit the file. Since this check will be performed each time a file is submitted, the necessity of submitting and receiving a certification of formatting is redundant and therefore eliminated. However, the Commission will provide EDI filers with the capability to test files prior to submitting them to validate their EDI file formats. For specific records not meeting the filing requirements, the filer will receive error/approval feedback on the screen in the form of a message. A file may be resubmitted once all errors are corrected.

In §8.215, the Commission amends subsection (b) to require use of commercially available odorization equipment, and deletes references to shop-made equipment. The Commission also adopts additional clarifying wording regarding continued use of shop-made odorization equipment that has been previously approved by the Commission and is in service as of February 4, 2009, the effective date of these rules. In subsection (c), the Commission adopts amendments to require use of commercially available malodorants, and to change the reference in paragraph (3) from "1.0% or less by volume" to "one-fifth of the lower explosive limit." In subsection (d)(2), the Commission clarifies that malodorant tests must be done at intervals not exceeding 15 months, but at least once each calendar year; a similar change is proposed in subsection (e)(1) for malodorant concentration tests. Also, in paragraph (1), the Commission deletes subparagraph (A), retains the text of subparagraph (B) in paragraph (1), and redesignates items (i) - (iv) as subparagraphs (A) - (E).

With the addition of the new section for leak reporting, the Commission will combine the requirements of §8.225(1) into new §8.210(e); therefore, subsection (a) of §8.225 is deleted and the remaining subsections redesignated.

The Commission adopts clarifications in §8.230(c)(1) and (2); new paragraph (2)(A) states that school facility pipe testing includes all gas piping from the outlet of the purchase meter to each inlet valve of each appliance. Current subparagraphs (A) - (C) are redesignated as (B) - (D).

In §8.235(a), the Commission clarifies wording to state that liaison activities must be conducted at intervals not exceeding 15 months, but at least once each calendar year, and in subsection (e), to add a specific date of January 15 of each even-numbered year for certain information to be filed.

The Commission clarifies §8.301(a)(1)(A) with new items (vi), (vii), and (viii) that require an operator to include the telephone numbers of the operator and the operator's on-site person, and to specify that ignition, explosion, rerouting of traffic, evacuation of any building, and media interest are considered significant facts that must be reported. In subparagraph (B), the Commission adopts clarifying wording concerning submission to the Commission of copies of any reports submitted to the Department of Transportation. In paragraph (2)(A) and (B), the Commission adds the Commission's emergency telephone number and a clarifying statement regarding submission to the Commission of copies of Department of Transportation reports.

In subsection (b), the Commission adds that each operator must file an annual report for its intrastate systems located in Texas in the same manner as required by 49 CFR Part 195, using forms supplied by the Department of Transportation. The Commission has added clarifying language permitting such reports to be filed with the Commission electronically, at the operator's election, and has changed the filing deadline from March 15 to June 15 to match the deadline in the federal rules. The Commission adopts new subsection (c) requiring submission to the Commission of safety-related condition reports as specified in 49 CFR 195. Current subsection (c) is redesignated as subsection (d).

The Commission deletes from §8.305 the requirement in paragraph (1) for atmospheric corrosion control, redesignates the remaining paragraphs, and in redesignated paragraph (3) (currently paragraph (4)) changes the requirements for cathodic protection test stations. The Commission also deletes subparagraphs (A) and (B) from the monitoring and inspection requirement in current paragraph (5), renumbered as paragraph (4).

In §8.310(a), the Commission adds wording that liaison activities must be conducted at intervals not exceeding 15 months, but at least once each calendar year.

Finally, in §8.315(c), the Commission clarifies that pipeline owners and operators must file certain information on January 15 of each odd-numbered year.

SUBCHAPTER A. GENERAL REQUIREMENTS AND DEFINITIONS

16 TAC §8.5

The Commission adopts the amendments under Texas Natural Resources Code, §81.051 and §81.052, which give the Commission jurisdiction over all common carrier pipelines in Texas, persons owning or operating pipelines in Texas, and their pipelines and oil and gas wells, and authorize the Commission to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission as set forth in §81.051, including such rules as the Commission may consider necessary and appropriate to implement state responsibility under any federal law or rules governing such persons and their operations; Texas Natural Resources Code, §81.0531, which requires the Commission to adopt by rule guidelines to be used in determining the amount of the penalty for a violation of a provision of Title 3 of the Texas Natural Resources Code, or a rule, order, license, permit, or certificate that relates to pipeline safety; Texas Natural Resources Code, §§117.001 - 117.102, which give the Commission jurisdiction over all pipeline transportation of hazardous liquids or carbon dioxide and over all hazardous liquid or carbon dioxide pipeline facilities as provided by 49 United States Code Annotated, §§60101, et seq.; and Texas Utilities Code, §§121.201 - 121.210, which authorize the Commission to adopt safety standards and practices applicable to the transportation of gas and to associated pipeline facilities within Texas to the maximum degree permissible under, and to take any other requisite action in accordance with, 49 United States Code Annotated, §§60101, et seq.; §121.251 and §121.252, which authorize the Commission to regulate the use of malodorants in natural gas; and §§121.5005 - 121.507, which give the Commission authority to regulate the testing of natural gas piping systems in school facilities.

Texas Natural Resources Code, §§81.051, 81.052, 81.0531, and 117.001 - 117.102; Texas Utilities Code, §§121.201 - 121.211; 121.251, 121.252; and 121.5005 - 121.507; and 49 United States Code Annotated, §§60101, et seq., are affected by the amendments.

Statutory authority: Texas Natural Resources Code, §§81.051, 81.052, 81.0531, and 117.001 - 117.102; Texas Utilities Code, §§121.201 - 121.211; 121.251 and 121.252; and 121.5005 - 121.507; and 49 United States Code Annotated, §§60101, et seq.

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

Issued in Austin, Texas, on January 15, 2009.

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 January 15, 2009.

TRD-200900208

Mary Ross McDonald

Managing Director

Railroad Commission of Texas

Effective date: February 4, 2009

Proposal publication date: October 10, 2008

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

SUBCHAPTER B. REQUIREMENTS FOR ALL PIPELINES

16 TAC §8.115, §8.135

The Commission adopts the amendments and new rule under Texas Natural Resources Code, §81.051 and §81.052, which give the Commission jurisdiction over all common carrier pipelines in Texas, persons owning or operating pipelines in Texas, and their pipelines and oil and gas wells, and authorize the Commission to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission as set forth in §81.051, including such rules as the Commission may consider necessary and appropriate to implement state responsibility under any federal law or rules governing such persons and their operations; Texas Natural Resources Code, §81.0531, which requires the Commission to adopt by rule guidelines to be used in determining the amount of the penalty for a violation of a provision of Title 3 of the Texas Natural Resources Code, or a rule, order, license, permit, or certificate that relates to pipeline safety; Texas Natural Resources Code, §§117.001 - 117.102, which give the Commission jurisdiction over all pipeline transportation of hazardous liquids or carbon dioxide and over all hazardous liquid or carbon dioxide pipeline facilities as provided by 49 United States Code Annotated, §§60101, et seq.; and Texas Utilities Code, §§121.201 - 121.210, which authorize the Commission to adopt safety standards and practices applicable to the transportation of gas and to associated pipeline facilities within Texas to the maximum degree permissible under, and to take any other requisite action in accordance with, 49 United States Code Annotated, §§60101, et seq.; §121.251 and §121.252, which authorize the Commission to regulate the use of malodorants in natural gas; and §§121.5005 - 121.507, which give the Commission authority to regulate the testing of natural gas piping systems in school facilities.

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

Issued in Austin, Texas, on January 15, 2009.

§8.135.Penalty Guidelines for Pipeline Safety Violations.

(a) Only guidelines. This section complies with the requirements of Texas Natural Resources Code, §81.0531(d), and Texas Utilities Code, §121.206(d). The penalty amounts contained in the tables in this section are provided solely as guidelines to be considered by the Commission in determining the amount of administrative penalties for violations of provisions of Title 3 of the Texas Natural Resources Code relating to pipeline safety, or of rules, orders or permits relating to pipeline safety adopted under those provisions, and for violations of Texas Utilities Code, §121.201, or Subchapter I (§§121.451 - 121.454), or a safety standard or rule relating to the transportation of gas and gas pipeline facilities adopted under those provisions.

(b) Commission authority. The establishment of these penalty guidelines shall in no way limit the Commission's authority and discretion to assess administrative penalties in any amount up to the statutory maximum when warranted by the facts in any case.

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

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

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

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

(4) the degree of culpability;

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

(6) any other factor the Commission considers relevant.

(d) Typical penalties. Typical penalties for violations of provisions of Title 3 of the Texas Natural Resources Code relating to pipeline safety, or of rules, orders, or permits relating to pipeline safety adopted under those provisions, and for violations of Texas Utilities Code, §121.201, or Subchapter I (§§121.451 - 121.454), or a safety standard or rule relating to the transportation of gas and gas pipeline facilities adopted under those provisions are set forth in Table 1.

Figure: 16 TAC §8.135(d) (.pdf)

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

Figure: 16 TAC §8.135(e) (.pdf)

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

Figure 1: 16 TAC §8.135(f) (.pdf)

Figure 2: 16 TAC §8.135(f) (.pdf)

(g) Penalty reduction for settlement before hearing. The recommended penalty for a violation may be reduced by up to 50% if the person charged agrees to a settlement before the Commission conducts an administrative hearing to prosecute a violation. The reduction applies to the basic penalty amount requested and not to any requested enhancements.

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

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

Figure: 16 TAC §8.135(i) (.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 January 15, 2009.

TRD-200900209

Mary Ross McDonald

Managing Director

Railroad Commission of Texas

Effective date: February 4, 2009

Proposal publication date: October 10, 2008

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

SUBCHAPTER C. REQUIREMENTS FOR NATURAL GAS PIPELINES ONLY

16 TAC §§8.203, 8.205, 8.210, 8.215, 8.225, 8.230, 8.235

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

Issued in Austin, Texas, on January 15, 2009.

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

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

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

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

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

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

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

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

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

§8.210.Reports.

(a) Accident, leak, or incident report.

(1) Telephonic report. At the earliest practical moment or within two hours following discovery, a gas company shall notify the Commission by telephone of any event that involves a release of gas from its pipelines defined as an incident in 49 CFR Part 191.3.

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

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

(B) the location of the leak or incident;

(D) the fatalities and/or personal injuries;

(E) the phone number of the operator;

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

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

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

(3) Written report.

(A) Following the initial telephonic report for accidents, leaks, or incidents described in paragraph (1) of this subsection, the operator who made the telephonic report shall submit to the Commission a written report summarizing the accident or incident. The report shall be submitted as soon as practicable within 30 calendar days after the date of the telephonic report. The written report shall be made on forms supplied by the Department of Transportation. For reports submitted electronically to the Department of Transportation, the operator shall forward a copy of the report and confirmation to the Division or electronically to safety@rrc.state.tx.us. For reports not submitted electronically to the Department of Transportation, the operator shall send to the Division an original signed report form.

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

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

(b) Pipeline safety annual reports.

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

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

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

(B) a master metered system.

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

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

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

(1) leak location;

(2) facility type;

(3) leak classification;

(4) pipe size;

(5) pipe type;

(6) leak cause; and

(7) leak repair method.

Figure: 16 TAC §8.210(e)(7) (.pdf)

§8.215.Odorization of Gas.

(a) Odorization of gas.

(1) Each gas company shall continuously odorize gas by the use of a malodorant agent as set forth in this section unless the gas contains a natural malodor or is odorized prior to delivery by a supplier.

(2) Unless required by 49 CFR Part 192.625(B) or by this section, odorization is not required for:

(A) gas in underground or other storage;

(B) gas used or sold primarily for use in natural gasoline extraction plants, recycling plants, chemical plants, carbon black plants, industrial plants, or irrigation pumps; or

(3) Gas shall be odorized by the user if:

(A) the gas is delivered for use primarily in one of the activities or facilities listed in paragraph (2) of this subsection and is also used in one of those activities for space heating, refrigeration, water heating, cooking, and other domestic uses; or

(B) the gas is used for furnishing heat or air conditioning for office or living quarters.

(4) In the case of lease users, the supplier shall ensure that the gas will be odorized before being used by the consumer.

(b) Odorization equipment. Gas companies shall use commercially available odorization equipment in any installation made on or after February 4, 2009. Shop-made or other odorization equipment previously approved by the Commission and in use as of February 4, 2009, may continue to be used in its current service, but may not be re-installed in a different location. Each operator shall be required to maintain a list of odorization equipment used in its particular operations, including the location of the odorization equipment, the brand name, model number, and the date last serviced. The list shall be available for review during safety evaluations by the Division.

(1) The malodorant when blended with gas in the amount specified for adequate odorization of the gas shall not be deleterious to humans or to the materials present in a gas system and shall not be soluble in water to a greater extent than 2 1/2 parts by weight of malodorant to 100 parts by weight of water.

(2) The products of combustion from the malodorant shall be nontoxic to humans breathing air containing the products of combustion and the products of combustion shall not be corrosive or harmful to the materials to which such products of combustion would ordinarily come in contact.

(3) The malodorant agent to be introduced in the gas, or the natural malodor of the gas, or the combination of the malodorant and the natural malodor of the gas shall have a distinctive malodor so that when gas is present in air at a concentration of one-fifth of the lower explosive limit, the malodor is readily detectable by an individual with a normal sense of smell.

(4) The level of natural malodor or the injection rate of approved malodorant shall be sufficient to achieve the requirement of paragraph (3) of this subsection.

(d) Malodorant tests and reports.

(1) Malodorant injection report. Each gas company shall record as frequently as necessary to maintain adequate odorization but not less than once each quarter the following malodorant information for all odorization equipment, except farm tap odorizers. The required information shall be recorded and retained in the company's files:

(A) odorizer location;

(B) brand name and model of odorizer;

(D) quantity of malodorant at beginning of month/quarter;

(E) amount added during month/quarter;

(F) quantity at end of month/quarter;

(G) MMcf of gas odorized during month/quarter; and

(H) injection rate per MMcf.

(2) Each natural gas operator shall check, test, and service farm tap odorizers at intervals not exceeding 15 months, but at least once each calendar year. Each gas company shall maintain records to reflect the date of service and maintenance on file for at least two years.

(e) Malodorant concentration tests and reports.

(1) Each gas company shall conduct the following concentration tests on the gas supplied through its facilities and required to be odorized. Test points shall be distant from odorizing equipment, so as to be representative of the odorized gas in the system. Tests shall be performed at intervals not exceeding 15 months, but at least once each calendar year or at such other times as the Division may reasonably require. The results of these tests shall be recorded and retained in each company's files for at least two years. Malodorant concentration test results shall include the following:

(A) odorizer name and location;

(B) malodorant concentration meter make, model, and serial number;

(D) test results indicating percent gas in air when malodor is readily detectable; and

(E) signature of person performing the test.

(2) Farm tap odorizers shall be exempt from the odorization testing requirements of paragraph (1) of this subsection.

(3) Gas companies that obtain gas into which malodorant previously has been injected or gas which is considered to have a natural malodor and therefore do not odorize the gas themselves shall be required to conduct quarterly malodorant concentration tests and retain records for a period of two years.

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 January 15, 2009.

TRD-200900210

Mary Ross McDonald

Managing Director

Railroad Commission of Texas

Effective date: February 4, 2009

Proposal publication date: October 10, 2008

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

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

16 TAC §§8.301, 8.305, 8.310, 8.315

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

Issued in Austin, Texas, on January 15, 2009.

§8.301.Required Records and Reporting.

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

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

(A) notify the Division, which shall notify the Commission's appropriate Oil and Gas district office, by telephone to the Commission's emergency line at (512) 463-6788 at the earliest practicable moment following discovery of the incident (within two hours) and include the following information:

(i) company/operator name;

(ii) location of leak or incident;

(iii) time and date of accident/incident;

(iv) fatalities and/or personal injuries;

(v) phone number of operator;

(vi) telephone number of operator;

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

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

(B) within 30 days of discovery of the incident, submit a completed Form H-8 to the Oil and Gas Division of the Commission. In situations specified in the 49 CFR Part 195, the operator shall also file a copy of the required Department of Transportation form with the Division. For reports submitted electronically to the Department of Transportation, the operator shall forward a copy of the report and confirmation to the Division or electronically to safety@rrc.state.tx.us. If an operator does not submit reports electronically to the Department of Transportation, the operator shall send the report to the Division on an original signed report form.

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

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

(B) within 30 days of discovery of the incident, file with the Division a written report using the appropriate Department of Transportation form (as required by 49 CFR Part 195) or a facsimile. For reports submitted electronically to the Department of Transportation, the operator shall forward a copy of the report and confirmation to the Division or electronically to safety@rrc.state.tx.us. If an operator does not submit reports electronically to the Department of Transportation, the operator shall send the report to the Division on an original signed report form.

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

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

(d) Facility response plans. Simultaneously with filing either an initial or a revised facility response plan with the United States Department of Transportation, each operator shall submit to the Division a copy of the initial or revised facility response plan prepared under the Oil Pollution Act of 1990, for all or any part of a hazardous liquid pipeline facility located landward of the coast.

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 January 15, 2009.

TRD-200900211

Mary Ross McDonald

Managing Director

Railroad Commission of Texas

Effective date: February 4, 2009

Proposal publication date: October 10, 2008

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

SUBCHAPTER C. REQUIREMENTS FOR NATURAL GAS PIPELINES ONLY

16 TAC §8.245

The Railroad Commission of Texas adopts the repeal of §8.245, relating to Penalty Guidelines for Pipeline Safety Violations, without changes to the proposal published in the October 10, 2008, issue of the Texas Register (33 TexReg 8475). The Commission adopts the repeal in order to adopt the same rule under a different rule number. The new §8.135, with the same title, is adopted in a concurrent rulemaking. The effective date of the repeal will be February 4, 2009.

The Commission received no comments on the proposed repeal.

The Commission adopts the repeal under Texas Natural Resources Code, §81.051 and §81.052, which give the Commission jurisdiction over all common carrier pipelines in Texas, persons owning or operating pipelines in Texas, and their pipelines and oil and gas wells, and authorize the Commission to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission as set forth in §81.051, including such rules as the Commission may consider necessary and appropriate to implement state responsibility under any federal law or rules governing such persons and their operations; Texas Natural Resources Code, §81.0531, which requires the Commission to adopt by rule guidelines to be used in determining the amount of the penalty for a violation of a provision of Title 3 of the Texas Natural Resources Code, or a rule, order, license, permit, or certificate that relates to pipeline safety; and Texas Utilities Code, §§121.201-121.210, which authorize the Commission to adopt safety standards and practices applicable to the transportation of gas and to associated pipeline facilities within Texas to the maximum degree permissible under, and to take any other requisite action in accordance with, 49 United States Code Annotated, §§60101, et seq.

Texas Natural Resources Code, §§81.051, 81.052, and 81.0531; Texas Utilities Code, §§121.201-121.210; and 49 United States Code Annotated, §§60101, et seq., are affected by the repeal.

Statutory authority: Texas Natural Resources Code, §§81.051, 81.052, and 81.0531; Texas Utilities Code, §§121.201-121.210; and 49 United States Code Annotated, §§60101, et seq.

Cross-reference to statute: Texas Natural Resources Code, §§81.051, 81.052, and 81.0531; Texas Utilities Code, Chapter 121; and 49 United States Code Annotated, Chapter 601.

Issued in Austin, Texas, on January 15, 2009.

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 January 15, 2009.

TRD-200900207

Mary Ross McDonald

Managing Director

Railroad Commission of Texas

Effective date: February 4, 2009

Proposal publication date: October 10, 2008

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

PART 3. TEXAS ALCOHOLIC BEVERAGE COMMISSION

CHAPTER 47. BLANKET RULES

16 TAC §47.1, §47.2

The Texas Alcoholic Beverage Commission adopts the repeal of Chapter 47, titled Blanket Rules, which includes §47.1, relating to severability, and §47.2, relating to blanket penalty, without changes to the proposed text as published in the October 10, 2008, issue of the Texas Register (33 TexReg 8476).

Government Code, §2001.39 requires that each state agency review and consider for readoption every four years each rule adopted by the agency under Government Code, Chapter 2001. Section 47.1 and §47.2 have been reviewed and the commission has determined that they are obsolete and are no longer necessary. The adoption of the Administrative Procedure Act, Government Code, Chapter 2001, has made §47.1 obsolete. Sections 11.61 - 11.65 and 61.71 - 61.79 of the Alcoholic Beverage Code, and Chapter 34 of the agency rules have made §47.2 obsolete. Additionally, there is no necessity after the repeal of these sections to have a chapter entitled Blanket Rules.

No comments were received as a result of the proposed repeal of the chapter.

Repeal of the existing rules is authorized by §5.31 of the Alcoholic Beverage Code, which provides the Texas Alcoholic Beverage Commission with the authority to prescribe and publish rules necessary to carry out the provisions of the Alcoholic Beverage Code, and §2001.039 of the Government Code.

Cross Reference: Section 5.31 is affected by the repeal.

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 January 14, 2009.

TRD-200900185

Alan Steen

Administrator

Texas Alcoholic Beverage Commission

Effective date: February 3, 2009

Proposal publication date: October 10, 2008

For further information, please call: (512) 206-3204

CHAPTER 49. PRODUCTION OF ALCOHOLIC BEVERAGES

16 TAC §49.1

The Texas Alcoholic Beverage Commission adopts the repeal of Chapter 49, titled Production of Alcoholic Beverages, which includes §49.1, relating to production practices in general, without changes to the proposed text as published in the October 10, 2008, issue of the Texas Register (33 TexReg 8476).

Government Code, §2001.39 requires that each state agency review and consider for readoption every four years each rule adopted by the agency under Government Code, Chapter 2001.

Section 49.1 relates to good manufacturing standards for wineries, wine bottlers and rectifiers. The section was adopted in 1976 and it has not been updated for current good manufacturing standards. Further, the Department of State Health Services (DSHS) regulates, inspects, and adopts rules for good manufacturing standards for all food manufacturers, which include wineries, wine bottlers and rectifiers. DSHS inspectors have expertise and special training in good manufacturing standards while our agents and auditors are not trained in this area and do not perform inspections to ensure compliance with this rule. This rule is no longer necessary as a commission rule. Additionally, there is no necessity after the repeal of this section to have a chapter entitled Production of Alcoholic Beverages.

No comments were received as a result of the proposed repeal of Chapter 49.

The repeal of the existing rule is authorized by §5.31 of the Alcoholic Beverage Code, which provides the Texas Alcoholic Beverage Commission with the authority to prescribe and publish rules necessary to carry out the provisions of the Alcoholic Beverage Code, and §2001.039 of the Government Code.

Cross Reference: Section 5.31 is affected by the repeal.

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 January 14, 2009.

TRD-200900186

Alan Steen

Administrator

Texas Alcoholic Beverage Commission

Effective date: February 3, 2009

Proposal publication date: October 10, 2008

For further information, please call: (512) 206-3204