Part 1.
RAILROAD COMMISSION OF TEXAS
Chapter 3.
OIL AND GAS DIVISION
16 TAC §3.80
The Commission proposes to amend §3.80, relating to
Commission Forms, Applications, and Filing Requirements, to add to Table 1,
entitled Railroad Commission Oil and Gas Division Forms, the Security Administrator
Designation (SAD) Form, the Form CF-1 (Commercial Facility Bond Form), and
the revised version of the United States Environmental Protection Agency Form
8700-12 (RCRA Subtitle C Site Identification Form), as well as to correct
the title of Form CF-2 (Commercial Facility Irrevocable Letter of Credit).
Recently amended §3.80, which became effective on April 12, 2004,
includes revised language relating to electronic filing in anticipation of
changes and/or new electronic filing opportunities that are developing in
association with the expansion of the Electronic Compliance and Approval Process
(ECAP) and the Commission's Oil and Gas Migration (OGM) Project. The OGM
Project is a major initiative to move the Commission's outdated computer mainframe
technologies to an open systems environment. In addition to improving the
Oil and Gas Division's internal business processes and providing the public
with access to accurate up-to-date information, the OGM Project is providing
the Commission with opportunities to reassess its data reporting requirements
and enhance electronic filing capabilities. The initial step for ECAP, an
electronic commerce system that eliminates paper by capturing, storing, and
transmitting oil or gas well permitting information electronically, converted
the filing, review, and approval of a drilling permit application (Form W-1)
to a completely electronic process. Now that the initial step is completed
and the infrastructure is in place to support the filing, processing, and
storage of drilling permits, ECAP has been incorporated into the Commission's
OGM Project, which eventually will include all compliance permits and performance
reports.
To provide for electronic filing in association with ECAP, several years
ago the Commission developed a required authorization procedure through the
filing and approval of a hard copy Master Electronic Filing Agreement (MEFA)
and a Security Administrator Designation (SAD) Form. Before an operator could
file electronically, both the Commission and operator representatives were
required to sign the MEFA, which established the terms of agreement for electronic
filing. Signing the SAD Form was also a condition of participation in ECAP.
Upon Commission approval of the MEFA, the security administrator is notified
of his or her assigned User ID. The security administrator could then distribute
security by assigning additional User IDs to employees within the company
and designating the forms they are authorized to file electronically through
ECAP.
In the amendments to §3.80 that became effective on April 12, 2004,
the Commission replaced language concerning requirements for electronic filing
under ECAP and language relating to requirements for electronic filing under
the Electronic Data Interchange (EDI) program with broader language to accommodate
changes in the requirements for electronic filing associated with the Commission's
new automated systems.
The new language included in §3.80, amended effective April 12, 2004,
makes the MEFA unnecessary for electronic filing of oil and gas forms. (The
MEFA is still a requirement for other electronic filings at the Commission.)
Furthermore, the Commission proposes to revise the current SAD Form to conform
the language to new §3.80 and to include the revised form in Table 1
of §3.80(a), entitled Railroad Commission Oil and Gas Division Forms,
which lists all Oil and Gas Division forms and the date that each was adopted
or last revised. The Commission also proposes to revise the instructions for
obtaining permission to file electronically with the Commission. The changes
to the SAD Form reflect the Commission's decision to expand its use to any
electronic filing with the Commission, not just ECAP filing, and to allow
third-party filers.
An operator wishing to file electronically with the Commission's Oil and
Gas Division must complete and submit to the Commission a SAD Form. An operator
may designate multiple security administrators. After receiving an operator's
SAD Form, the Commission will issue to each designated security administrator
a User ID that will allow the security administrator to access and update
the Commission's electronic filing security system. The security administrator
will then be responsible for assigning additional User IDs to individuals
within the company and for maintaining that security. The distributed security
design ensures that the control will rest within the operator's organization
through each operator's designated security administrator(s). No MEFA will
be required.
There will be no immediate changes for any operator that already has met
the ECAP filing requirements. The SAD Form the operator previously filed will
remain in effect after the revised SAD Form is adopted; however, there are
12 petroleum consultants/independent contractors or other non-operators who
previously filed a SAD Form with the Commission who would be required to complete
and submit a revised SAD Form once it is adopted if they wish to continue
electronic filing on behalf of operators. In addition, operators who are currently
filing with the Oil and Gas Division electronically and who have never submitted
a SAD Form would be required to do so; however, all electronic filers would
be required to have their software re- certified for any future new technical
requirements that result from movement of programs from the Commission's mainframe
to its new open systems environment. The Commission will provide advance notice
of any future changes in electronic filing requirements.
The Commission also proposes to add to Table 1 Form CF-1, Commercial Facility
Bond, and to correct the title of Form CF-2 to "Commercial Facility Irrevocable
Letter of Credit."
Finally, the Commission proposes to add to Table 1 the revised version
of the Form EPA 8700-12 (RCRA Subtitle C Site Identification Form), which
the Environmental Protection Agency revised effective January 2004, and which
is required by §3.98 of this title, relating to Standards for Management
of Hazardous Oil and Gas Waste.
Leslie Savage, Oil and Gas Division planner, has determined that for each
year of the first five years the amendments as proposed would be in effect,
there will be no fiscal implications for local governments and no net fiscal
implications for the state. The portion of the proposed amendments concerning
the SAD Form and the procedures for electronic filing authorization are related
to changes that the Commission already has planned in association with the
OGM Project. Further, the Commission has endeavored to draft proposed language
in the SAD Form and the electronic filing procedures with sufficient breadth
to accommodate any of the possible options related to electronic filing that
might be considered for adoption through the OGM Project.
Ms. Savage also has determined that for each year of the first five years
that the amendments would be in effect, the primary public benefit would be
more efficient government.
Ms. Savage has estimated that the cost of compliance with the proposed
amendments to §3.80 for individuals, small businesses, or micro-businesses
will be negligible. Currently, the Commission does not require electronic
filing of any Oil and Gas Division documents or data; electronic filing of
Oil and Gas Division information at the Commission is discretionary.
Texas Government Code, §2006.002, requires a state agency considering
adoption of a rule that would have an adverse economic effect on small businesses
or micro-businesses to reduce the effect if doing so is legal and feasible
considering the purpose of the statutes under which the rule is to be adopted.
Before adopting a rule that would have an adverse economic effect on small
businesses or micro-businesses, a state agency must prepare a statement of
the effect of the rule on small businesses and micro-businesses. This statement
must include an analysis of the cost of compliance with the rule for small
businesses and micro-businesses and a comparison of that cost with the cost
of compliance for the largest businesses affected by the rule, using cost
for each employee, cost for each hour of labor, or cost for each $100 of sales.
Because entities required to file an organization report and affiliates
of such entities performing operations within the jurisdiction of the Commission
are not required to make filings with the Commission reporting number of employees,
labor costs, amount of sales, or gross receipts, the Commission cannot determine
whether a particular entity required to comply with §3.80 may be a small
business or a micro-business. However, the Commission has determined that
it is likely that some operators would meet the definitions of these terms
in Texas Government Code, §2006.001. The Commission assumes further that,
during a given year, at least one entity desiring to make an electronic filing
with the Commission in accordance with §3.80 would be an individual,
small business, or micro-business. However, the revised SAD Form and associated
revised procedures, as well as the inclusion in the rule of Form CF-1 and
new EPA Form 8700-12, impose no mandatory additional costs. In fact, deletion
of the requirement to file the MEFA should result in a decrease in the cost
of filing electronically with the Commission. In addition, after an entity
has completed the necessary requirements to enable the entity to file documents
and data with the Commission electronically, the entity should save money
previously spent on postage and handling.
For the purpose of making the comparison required by Texas Government Code, §2006.002(c),
the Commission assumes that, during a given year, at least one entity desiring
to file electronically with the Commission in accordance with §3.80 would
be an individual, small business, or micro-business and that the that the
cost of writing, typing, copying, and mailing the revised SAD Form to enable
the business to make electronic filings with the Commission would be $50.
Therefore, the cost of complying with §3.80, as amended, would be $50
per employee if the entity has one employee, $2.50 per employee if the entity
has 20 employees, and $0.50 per employee if the entity has 99 employees. Comparable
cost per employee of electronic filing for the largest businesses affected
by the proposed amendment would be $0.10 for an employer of 500 persons and
$0.05 for an employer of 1,000 persons.
Comments on the proposal may be submitted to Rules Coordinator, Office
of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin,
Texas 78711-2967; online at www.rrc.state.tx.us/rules/commentform.html; or
by electronic mail to rulescoordinator@rrc.state.tx.us. The Commission specifically
requests comments and information on the proposed form changes that are part
of this rulemaking. The Commission will accept comments for 30 days after
publication in the
Texas Register
, and encourages
all interested persons to submit comments no later than the deadline. The
Commission cannot guarantee that comments submitted after the deadline will
be considered. For further information, call Ms. Savage (512) 463-7308. The
status of Commission rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The Commission proposes the amendments to §3.80 pursuant
to Texas Natural Resources Code, §§81.051 and 81.052, which give
the Commission jurisdiction over all persons owning or engaged in drilling
or operating oil or gas wells 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; and §91.142,
which requires the Commission to obtain specified information from a person,
firm, partnership, joint stock association, corporation, or other domestic
or foreign organization operating wholly or partially in this state and acting
as principal or agent for another for the purpose of performing operations
which are within the jurisdiction of the Commission.
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, and 91.142.
Cross-reference to statute: Texas Natural Resources Code, §§81.051,
81.052, and 91.142.
Issued in Austin, Texas on April 23, 2004.
§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.
(b) - (f) (No change.)
This agency hereby certifies that the proposal has been reviewed
by legal counsel and found to be within the agency's legal authority to adopt.
Filed with the Office of
the Secretary of State on April 23, 2004.
TRD-200402730
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: June 6, 2004
For further information, please call: (512) 475-1295
Subchapter B. SPECIAL PROCEDURAL RULES
16 TAC §7.45
The Railroad Commission of Texas proposes to amend §7.45,
relating to Quality of Service, to add wording in paragraph (5)(C)(i) to authorize
a designee of the Attorney General in the Crime Victims Services Division
of the Office of the Attorney General (CVSD) to certify that a person is a
victim of family violence. Currently, §7.45(5)(C)(i) requires a gas utility
to waive any requirement that an applicant for gas utility service pay a deposit
if the applicant has been determined to be a victim of family violence, as
defined in the Texas Family Code, §71.004, by a family violence center,
by treating medical personnel, or by law enforcement agency personnel. This
determination must be evidenced by the applicant's submission of a certification
letter developed by the Texas Council on Family Violence. The waiver for gas
utility deposits helps victims of family violence to obtain gas utility service
in new and safer surroundings with relative ease. The proposed amendment would
add one more entity--the Attorney General's designee in the CVSD--as authorized
to certify that a person is a victim of family violence, thus allowing a person
being assisted by the CVSD to obtain the certification letter without having
to return to a family violence center, treating medical personnel, or law
enforcement agency personnel for the required signature.
The Commission amended §7.45(5)(C)(i), effective November 10, 2003,
based on comments by the Texas Council on Family Violence in other rulemaking
proceedings. As amended, the rule requires a gas utility to waive any deposit
requirement for residential service for an applicant who has been determined
to be a victim of family violence as defined in Texas Family Code, §71.004,
by a family violence center, by treating medical personnel, or by law enforcement
agency personnel. This determination must be evidenced by the applicant's
submission of a certification letter developed by the Texas Council on Family
Violence and made available on its web site. This provision is similar to
the rules and process for a waiver for electric utility and telephone utility
deposits that are currently adopted by the Public Utility Commission (PUC)
and currently in effect in 16 Tex. Admin. Code §25.478(a)(3)(D), relating
to Credit Requirements and Deposits, for electric service providers, and 16
Tex. Admin. Code §26.24(a)(1)(B)(iv), also titled Credit Requirements
and Deposits, for telecommunications service providers. The Commission's rule
is similar to the two PUC rules except that the Commission's rule authorizes
certification by law enforcement agency personnel in addition to certification
by a family violence center or by treating medical personnel. This new proposed
amendment extends certification authority to the CVSD.
Jackie Standard, Director of Licensing and Permits, Gas Services Division,
has determined that for each year of the first five years the amendment will
be in effect, there will be no fiscal implications for state or local governments
as a result of enforcing or administering the amendment. Any tariff filings
by gas utilities required as a result of the proposed amendment would be handled
by current Commission staff as part of the Commission's routine work. In addition,
the work of the CVSD could be somewhat more streamlined by being able to provide
a victim of family violence with the certification letter needed to obtain
the gas utility deposit waiver.
Ms. Standard has determined that for each year of the first five years
the amendment will be in effect, the public benefit will include the assurance
that the services provided by gas utilities and the obligations imposed upon
them in providing that service are just and reasonable. In addition, the public
benefit will include slightly more streamlined assistance for victims of family
violence, enabling those persons to effect separation from violent circumstances
with a little less difficulty. When an incident occurs, the victim contacts
the police or seeks a protective order. The police usually refer or take the
victim to a hospital, and are required to advise the victim of the Crime Victims
Compensation Fund. If there is a law enforcement victim liaison available,
or if the medical facility has Sexual Assault Nurse Examiner (SANE) or Sexual
Assault Response Team (SART) personnel, the victim will be assisted in completing
the application for compensation, including certification letters for utility
deposit waivers. However, if the victim is so traumatized that he or she is
not able to make a rational decision concerning whether to leave the home,
the victim would need to return to the law enforcement agency or medical facility
to get the certification letter signed. Also, unless an advocate has already
furnished a victim of family violence with the certification letter, a CVSD
caseworker sends the letter to the victim and offers the waiver as an option
because CVSD cannot demand that a victim seek a waiver. The victim then must
take the letter to the shelter, medical personnel, or law enforcement to obtain
an authorized signature, which the victim may or may not be able to get quickly,
and perhaps not at all. Once signed, however, the victim would be able to
submit the letter to the gas utility. By amending the rule to authorize a
designee in the CVSD to sign the certification letter, victims of family violence
could avoid that possible delay in obtaining a signed letter.
Ms. Standard has estimated that there may be a cost of compliance with
the proposal for the individual, small business, or micro-business natural
gas service provider. Such providers will not be required to expend funds
to comply with the rule, but may experience some reduction in fees received,
because some persons may not be required to pay a deposit. Forgoing the relatively
small deposit amounts (averaging about $50) should not adversely affect a
gas utility. Further, because the Commission exercises exclusive original
jurisdiction over the rates and services of gas utilities outside municipal
areas, the number of utility customers to whom this rule would apply is a
very small percentage of all gas utility customers in Texas; the number of
those customers who might qualify for a deposit waiver in this instance is
likely to be a small number. The Commission cannot find that there would be
an increase in the number of persons qualifying for a gas utility deposit
waiver just because CVSD would be authorized to sign certification letters.
CVSD currently assists victims of family violence in obtaining the certification
letters; the proposed amendment potentially does away with some of the delay
in the process.
Texas Government Code, §2006.002, requires a state agency considering
adoption of a rule that would have an adverse economic effect on small businesses
or micro-businesses to reduce the effect if doing so is legal and feasible
considering the purpose of the statutes under which the rule is to be adopted.
Before adopting a rule that would have an adverse economic effect on small
businesses or micro-businesses, a state agency must prepare a statement of
the effect of the rule on small businesses and micro-businesses, which must
include an analysis of the cost of compliance with the rule for small businesses
and micro-businesses and a comparison of that cost with the cost of compliance
for the largest businesses affected by the rule, using cost for each employee,
cost for each hour of labor, or cost for each $100 of sales.
The proposed amendment does not alter the current deposit waiver requirement,
which makes no distinction based on a utility's status as an individual, small
business, or micro-business. Adding CVSD as an entity authorized to certify
that a person is a victim of family violence is not likely to increase the
number of waivers that an individual, small business, or micro-business utility
must grant. Gas utilities within the jurisdiction of the Commission are required
to file an Annual Report with the Commission that reports certain operational
and financial information; such data include certain costs and revenues.
The Commission has determined that there are approximately eight (8) small
businesses and eighteen (18) micro-businesses out of a total of thirty-three
(33) natural gas distribution utilities. The smallest small business has been
identified as having annual revenues of approximately $236,000. The smallest
micro-business has been identified as having annual revenues of approximately
$115. The combined eight (8) small businesses and eighteen (18) micro-businesses,
twenty-six (26) utilities, generate approximately $130 million dollars per
year. For the purpose of making the comparison required by Texas Government
Code, §2006.002(c), the Commission assumes that at least one gas utility
that is an individual, small business, or a micro-business will be required
to grant a waiver of its deposit requirement. The Commission further assumes
that the cost of complying with §7.45, as amended, would be the loss
of one deposit that otherwise would be collected. For the smallest small business
with annual revenue of $236,000, the standard deposit as stated in its tariff
is approximately $75, making the cost of compliance $3.17 per $100 of sales.
For the smallest micro-business with $115 of annual revenue, the standard
residential low-density deposit as stated in its tariff is based on a formula
but does not exceed $100. Forgoing collection of this deposit is a cost of
compliance of $86.96 per $100 of sales.
Comments on the proposal may be submitted to Rules Coordinator, Office
of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin,
Texas 78711-2967; online at www.rrc.state.tx.us/rules/commentform.html; or
by electronic mail to rulescoordinator@rrc.state.tx.us. The Commission will
accept comments for 30 days after publication in the
Texas Register
and the comments should refer to Gas Utilities Docket
No. 9449. The Commission encourages all interested persons to submit comments
no later than the deadline. The Commission cannot guarantee that comments
submitted after the deadline will be considered. For further information,
call Ms. Standard at (512) 463-7118. The status of Commission rulemakings
in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The Commission proposes the amendment under Texas Utilities Code, §102.001,
which gives the Railroad Commission exclusive original jurisdiction over the
rates and services of a gas utility distributing natural gas or synthetic
natural gas in areas outside a municipality; Texas Utilities Code, §102.151,
which requires gas utilities to file schedules showing all rates for a gas
utility service, product, or commodity offered by the gas utility and each
rule or regulation that relates to or affects a rate of the gas utility or
a gas utility service, product, or commodity furnished by the gas utility;
Texas Utilities Code, §104.001, which vests in the Railroad Commission
all the authority and power of this state to ensure compliance with the obligations
of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and which authorizes
the regulatory authority to adopt rules for determining the classification
of customers and services; Texas Utilities Code, §104.005, which prohibits
a gas utility from directly or indirectly charging, demanding, collecting,
or receiving from a person a greater or lesser compensation for a service
provided or to be provided by the utility than the compensation prescribed
by the applicable schedule of rates filed under Texas Utilities Code, §102.151;
and Texas Utilities Code, §104.251, which requires gas utilities to furnish
service, instrumentalities, and facilities that are safe, adequate, efficient,
and reasonable.
Statutory authority: Texas Utilities Code, §§102.001, 102.151,
104.001, 104.005, and 104.251.
Cross-reference to statute: Texas Utilities Code, Chapters 102 and 104.
Issued in Austin, Texas on April 23, 2004.
§7.45.Quality of Service.
For gas utility service to residential and small commercial customers,
the following minimum service standards shall be applicable in unincorporated
areas. In addition, each gas distribution utility is ordered to amend its
service rules to include said minimum service standards within the utility
service rules applicable to residential and small commercial customers within
incorporated areas, but only to the extent that said minimum service standards
do not conflict with standards lawfully established within a particular municipality
for a gas distribution utility. Said gas distribution utility shall file service
rules incorporating said minimum service standards with the Railroad Commission
and with the municipalities in the manner prescribed by law.
(1) - (4)
(No change.)
(5)
Applicant deposit.
(A) - (B)
(No change.)
(C)
Amount of deposit and interest for residential service,
and exemption from deposit.
(i)
Each gas utility shall waive any deposit requirement for
residential service for an applicant who has been determined to be a victim
of family violence as defined in Texas Family Code, §71.004, by a family
violence center, by treating medical personnel, [
(ii) - (iv)
(No change.)
(D) - (H)
(No change.)
(6) - (8)
(No change.)
This agency hereby certifies that the proposal has been
reviewed by legal counsel and found to be within the agency's legal authority
to adopt.
Filed with the Office of
the Secretary of State on April 23, 2004.
TRD-200402729
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: June 6, 2004
For further information, please call: (512) 475-1295
16 TAC §§7.70 - 7.74, 7.80 - 7.87
(Editor's note: The text of the following sections proposed for
repeal will not be published. The sections may be examined in the offices
of the Railroad Commission of Texas or in the Texas Register office, Room
245, James Earl Rudder Building, 1019 Brazos Street, Austin.)
The Railroad Commission of Texas proposes the repeal
of §§7.70-7.74, and 7.80-7.87, relating to General and Definitions;
Odorization Equipment, Odorization of Natural Gas, and Odorant Concentration
Tests; Written Procedure for Handling Natural Gas Leak Complaints; Master
Metered Systems; School Piping Testing; Definitions; Safety Regulations Adopted;
Jurisdiction; Retroactivity; Required Records and Reporting; Intrastate Pipeline
Facility Construction; Corrosion Control Requirements; and Enforcement. Collectively,
these are the pipeline safety rules in Texas Administrative Code, Title 16,
Chapter 7. The Commission proposes the repeals in order to move the pipeline
safety rules into Texas Administrative Code, Title 16, Chapter 8, as proposed
in a separate, concurrent rulemaking, to join six other pipeline safety rules
already in Chapter 8.
One current rule, §7.85, regarding Intrastate Pipeline Facility Construction,
will not be retained in Chapter 8 because it duplicates the requirements contained
in another rule. Section 7.85 requires pipelines to be constructed of steel;
this requirement is already part of the Commission's rules under 49 Code of
Federal Regulations Part 195, which the Commission has adopted by reference.
Mary McDaniel, Director, Safety Division, has determined that, for each
year of the first five years that the repeals are in effect, there will be
no fiscal implications for state or local governments because the virtually
identical rule requirements will continue to exist in a different chapter.
Ms. McDaniel has also determined that, for each year of the first five
years the repeals are in effect, the public benefit anticipated as a result
of enforcing the repeals (and the concurrent new rules in Chapter 8) will
be a clearer understanding of the pipeline safety requirements because they
will be separated from requirements in Chapter 7 that apply to the economic
regulation of gas utilities.
There is no anticipated economic cost to individuals, small businesses,
or micro-businesses required to comply with the proposed repeals.
Comments on the proposal may be submitted to Rules Coordinator, Office
of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin,
Texas 78711-2967; online at www.rrc.state.tx.us/rules/commentform.html; or
by electronic mail to rulescoordinator@rrc.state.tx.us. The Commission will
accept comments for 60 days after publication in the
Texas Register
and should refer to Gas Utilities Docket No. 9255. For
more information, call Mary McDaniel at (512) 463-7166. The status of Commission
rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The repeals are proposed under Texas Utilities Code, Chapter
121, Subchapter E, which authorizes the Commission to adopt safety standards
for the transportation of natural gas and for natural gas pipeline facilities;
to require record maintenance and reports; and to inspect records and facilities
to determine compliance with adopted safety standards; and Texas Natural Resources
Code, Chapter 117, which requires the Commission to adopt rules that include
safety standards for and practices applicable to the intrastate transportation
of hazardous liquids or carbon dioxide by pipeline and intrastate hazardous
liquids pipeline facilities.
The Texas Utilities Code, Chapter 121, Subchapter E, and the Texas Natural
Resources Code, Chapter 117, are affected by the proposed repeals.
Issued in Austin, Texas on April 23, 2004.
§7.70.General and Definitions.
§7.71.Odorization Equipment, Odorization of Natural Gas, and Odorant Concentration Tests.
§7.72.Written Procedure for Handling Natural Gas Leak Complaints.
§7.73.Master Metered Systems.
§7.74.School Piping Testing.
§7.80.Definitions.
§7.81.Safety Regulations Adopted.
§7.82.Jurisdiction.
§7.83.Retroactivity.
§7.84.Required Records and Reporting.
§7.85.Intrastate Pipeline Facility Construction.
§7.86.Corrosion Control Requirements.
§7.87.Enforcement.
This agency hereby certifies that the proposal has been
reviewed by legal counsel and found to be within the agency's legal authority
to adopt.
Filed with the Office of
the Secretary of State on April 23, 2004.
TRD-200402735
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: June 6, 2004
For further information, please call: (512) 475-1295
The Railroad Commission of Texas proposes new rules and amendments
to current rules in Title 16, Chapter 8, Subchapters A through D, specifically,
new §§8.1 and 8.5, relating to General Applicability and Standards,
and Definitions, in Subchapter A, General Requirements and Definitions; new §8.51,
relating to Organization Report, amendments to §8.101, relating to Pipeline
Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids
Pipelines, and new §§8.105, 8.110, 8.115, 8.125, and 8.130, relating
to Records, Operations and Maintenance Procedures, Construction Commencement
Report, Waiver Procedure, and Enforcement, in Subchapter B, Requirements for
All Pipelines; amendments to §8.201, relating to Pipeline Safety Program
Fees, new §§8.203,8.205, 8.210, 8.215, 8.220, 8.225, and 8.230,
relating to Supplemental Regulations, Written Procedure for Handling Natural
Gas Leak Complaints, Reports, Odorization of Gas, Master Metered Systems,
Plastic Pipe Requirements, and School Piping Testing, amendments to §8.235,
Natural Gas Pipelines Public Education and Liaison, and new §8.245, relating
to Penalty Guidelines for Pipeline Safety Violations, in Subchapter C, Requirements
for Natural Gas Pipelines Only; and new §§8.301 and 8.305, relating
to Required Records and Reporting, and Corrosion Control Requirements, in
Subchapter D, Requirements for Hazardous Liquids and Carbon Dioxide Pipelines
Only.
The Commission proposes the new sections to move the pipeline safety rules
from Title 16, Chapter 7 of the Texas Administrative Code into new Chapter
8; the repeal of the rules currently found in Chapter 7 is proposed in a separate,
concurrent rulemaking. The proposed new rules will join §8.101, relating
to Pipeline Integrity Assessment and Management Plans for Natural Gas and
Hazardous Liquids Pipelines, in Subchapter B, Requirements For All Pipelines; §8.201,
relating to Pipeline Safety Program Fees, §8.235, relating to Natural
Gas Pipelines Public Education and Liaison, and §8.240, relating to Discontinuance
of Service, in Subchapter C, Requirements for Natural Gas Pipelines Only;
and §8.310, relating to Hazardous Liquids and Carbon Dioxide Pipelines
Public Education and Liaison, and §8.315, relating to Hazardous Liquids
and Carbon Dioxide Pipelines or Pipeline Facilities Located Within 1,000 Feet
of a Public School Building or Facility, in Subchapter D, Requirements for
Hazardous Liquids and Carbon Dioxide Pipelines Only.
The Commission proposes two new rules in Chapter 8 that do not have a current
counterpart in Chapter 7: §8.125, Waiver Procedure, which implements
a process that has been used by the Commission and operators on an informal
basis for at least 10 years, and §8.245, Penalty Guidelines for Pipeline
Safety Violations, which is required by the provisions of Texas Natural Resources
Code, §81.0531(d), and Texas Utilities Code, §121.206(d), enacted
by Senate Bill 310 (Acts 2001, 77th Leg., ch. 1233, §§ 5 and 71,
respectively, eff. Sept. 1, 2001).
Proposed new Subchapter A, General Requirements
and Definitions.
Proposed new Subchapter A, General Requirements and Definitions, will include
proposed new §8.1, relating to General Applicability and Standards, and
proposed new §8.5, relating to Definitions.
Proposed new §8.1, General Applicability and Standards, is derived
from current §§7.70, 7.81, and 7.82. Proposed new §8.1(a),
concerning applicability, is derived from current §§7.70(c), 7.82,
and the first sentence in current §7.70(d); it states the scope of the
chapter, which applies to all gas pipeline facilities and facilities used
in the intrastate transportation of natural gas, including master metered
systems, as provided in 49 United States Code (U.S.C.) §60101,
Proposed new §8.1(b), concerning minimum safety standards, derives
from current §§7.70(a) and 7.81, and adopts by reference the federal
pipeline safety standards found in 49 U.S.C. §60101,
et seq
.; 49 Code of Federal Regulations (CFR) Part 191, Transportation
of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and
Safety-Related Condition Reports; 49 CFR Part 192, Transportation of Natural
and Other Gas by Pipeline: Minimum Federal Safety Standards; 49 CFR Part 193,
Liquefied Natural Gas Facilities: Federal Safety Standards; 49 U.S.C. §60101,
Currently, §§7.70(a) and 7.81 adopt the federal pipeline safety
standards as of March 21, 2002. Proposed new §8.1(b) will show this date
as April 9, 2004. The federal safety rule amendments that will be captured
are summarized in the following 12 paragraphs.
USDOT's Amendment No. 195-76, published at 67 Federal Register (FR) 2136,
extended the regulations on managing the integrity of hazardous liquid and
carbon dioxide pipelines that affect high consequence areas to operators with
less than 500 miles of regulated pipelines. In 49 CFR §195.452(d)(2),
the date after which prior assessments may qualify for use was incorrectly
published as December 18, 2006. The corrected date is February 15, 1997. The
effective date for the correction was February 15, 2002.
USDOT's Amendment 192-77, published at 67 FR 50824, defined areas of high
consequence where the potential consequences of a gas pipeline accident may
be significant or may do considerable harm to people and their property. The
definition includes current class 3 and 4 locations; facilities with persons
who are mobility-impaired, confined, or hard to evacuate; and places where
people gather for recreational and other purposes. For facilities with mobility-impaired,
confined, or hard-to-evacuate persons, and places where people gather, the
corridor of protection from the pipeline is 300 feet, 660 feet, or 1,000 feet
depending on the pipeline's diameter and operating pressure. The effective
date was September 5, 2002.
USDOT's Research and Special Programs Administration (RSPA) published a
final rule at 68 FR 11748 modifying or adding the definition of "administrator"
in several sections of the Code of Federal Regulations for clarification and
consistency between RSPA regulations. The changes were in 49 CFR Parts 107,
190, 191, 192, 193, 195, 198, and 199 -- specifically, §§107.1,
190.3, 191.3, 192.3, 193.2007, 195.2, 198.3, and 199.3. The effective date
was March 12, 2003.
USDOT published an interim final rule at 68 FR 31624 to amend a provision
of its drug and alcohol testing procedures to change the instructions to medical
review officers with respect to reporting specimens as dilute or substituted.
The change was based on USDOT's experience since the adoption of the current
rule and new scientific information on the subject. The effective date was
May 28, 2003.
Amendment No. 40-12, published at 67 FR 43946, revised the Management Information
System forms currently used within five USDOT agencies and the United States
Coast Guard for submission of annual drug and alcohol program data. The five
DOT agencies are the Federal Motor Carrier Safety Administration, the Federal
Aviation Administration, the Federal Transit Administration, the Federal Railroad
Administration, and the Research and Special Programs Administration. The
single form replaced 21 different data collection forms. The effective date
is July 25, 2003. Also, at 68 FR 75455, USDOT published a final rule requiring
the use of this single form as adopted in 49 CFR Part 40. Following the July
25, 2003, adoption, USDOT had requested comments and suggestions for changes
to the MIS form and process. The final rule responded to those comments and
made modifications to the previous DOT agency MIS forms. Use of the new MIS
form will be required for employer MIS submissions in 2004, which will document
2003 data. The effective date was December 31, 2003.
Amendments Nos. 191-15, 192-92, and 195-72, published at 68 FR 46109, addressed
the safety regulation responsibility for producer-operated natural gas and
hazardous liquid pipelines that cross into State waters without first connecting
to a transporting operator's facility on the Outer Continental Shelf. The
rule specified the procedures by which producer operators can petition for
approval to operate under safety regulations governing pipeline design, construction,
operation, and maintenance issued by either RSPA or the Department of the
Interior, Minerals Management Service. The effective date was September 4,
2003.
Amendment 195-78, published at 68 FR 53526, changed several safety standards
for hazardous liquid and carbon dioxide pipelines. The changes, which concern
welder qualifications, backfilling, records, training, and signs, were based
on recommendations by the National Association of Pipeline Safety Representatives
and were made to improve the clarity and effectiveness of the standards. The
effective date was October 14, 2003.
Amendment 192-93, published at 68 FR 53895, changed some of RSPA's Office
of Pipeline Safety's safety standards for gas pipelines. The changes were
based on recommendations from the National Association of Pipeline Safety
Representatives and a review of the recommendations by the State Industry
Regulatory Review Committee. The changes improved the clarity and effectiveness
of the standards. The effective date was October 15, 2003.
Amendment 192-95, published at 68 FR 69778, required operators to develop
integrity management programs for gas transmission pipelines located where
a leak or rupture could do the most harm, such as in high consequence areas.
The rule required gas transmission pipeline operators to perform ongoing assessments
of pipeline integrity, to improve data collection, integration, and analysis,
to repair and remediate the pipeline as necessary, and to implement preventive
and mitigative actions. RSPA's Office of Pipeline Safety also modified the
definition of high consequence areas in response to a petition for reconsideration
from industry associations. The final rule addressed statutory mandates, safety
recommendations, and conclusions from accident analyses, all of which indicate
that coordinated risk control measures are needed to improve pipeline safety.
The effective date was originally published as January 14, 2004, and included
the incorporation by reference of certain publications; however, at 69 FR
2307, RSPA published a correction to change the effective date to February
14, 2004, to meet the 60-day requirement for Congressional review of major
rules.
Amendment 40-13, published at 69 FR 3021, adds drug and alcohol abuse counselors
certified by the National Board for Certified Counselors, Inc. and Affiliates,
specifically NBCC's Master Addictions Counselor, to those eligible to be substance
abuse professionals under 49 CFR Part 40, subpart O. The effective date was
January 22, 2004.
Amendment 195-80, published at 69 FR 537, requires operators of pipeline
systems subject to RSPA's hazardous liquid pipeline safety regulations to
prepare and file annual reports containing information about those systems.
The data will provide the basis for more efficient and meaningful analyses
of the safety status of hazardous liquid pipelines. RSPA's Office of Pipeline
Safety will use the information to compile a national pipeline inventory,
identify and determine the scope of safety problems, and target inspections.
The effective date was February 5, 2004.
Amendment 193-18, published at 69 FR 11330, clarifies that the operation,
maintenance, and fire protection requirements of RSPA's Office of Pipeline
Safety's regulations for liquefied natural gas (LNG) facilities apply to LNG
facilities in existence or under construction as of March 31, 2000. An earlier
final rule made the applicability of these requirements unclear. Additional
changes to the regulations remove incorrect cross- references, clarify fire
drill requirements, and require reviews of plans and procedures. The final
rule also changes the regulations so that cross-references to the National
Fire Protection Association standard NFPA 59A refer to the 2001 edition of
the standard rather than the 1996 edition. The effective date was April 9,
2004; however, LNG plants existing on March 31, 2000, need not comply with
provisions of 49 CFR §193.2801 on emergency shutdown systems, water delivery
systems, detection systems, and personnel qualification and training until
September 12, 2005. The final rule also incorporates by reference certain
other publications.
Proposed new §8.1(c), derived from the second sentence of current §7.70(d)
and §7.70(e), relates to special situations and specifically states the
Commission's authority to impose more stringent safety requirements. This
subsection also allows pipeline operators to seek waivers under the procedure
set out in proposed new §8.125.
Proposed new §8.1(d), concerning concurrent filing, requires a person
filing any document or information with the Department of Transportation to
file a copy of that document or information with the Safety Division.
Proposed new §8.1(e), concerning penalties, states the statutory source
of authority for the Commission to impose penalties for submitting false or
misleading information.
Proposed new §8.1(f), concerning retroactivity, states that nothing
in this chapter shall be applied retroactively to any existing intrastate
pipeline facilities concerning design, fabrication, installation, or established
operating pressure, except as required by the Office of Pipeline Safety, Department
of Transportation. All intrastate pipeline facilities shall be subject to
the other safety requirements of this chapter.
Proposed new §8.5, Definitions, derives from current §§7.70(b),
7.71(a), and 7.80; in addition, definitions from current §7.74, relating
to school piping testing, and current §8.101, relating to pipeline integrity
assessment, are included. In addition, the Commission also proposes to adopt
by reference the definitions given in 49 CFR Parts 191, 192, 193, 195, and
199 for the purposes of this chapter. This proposed new section includes definitions
for many more terms than are defined in the current rules in Chapter 7, and
omits only one current definition, that of "Act," currently found in §7.74(b)(1).
By defining more terms, the Commission expects to achieve greater precision
and consistency in the rules and, it is hoped, better understanding of the
rules, and more uniformity in interpretation and application of the rules.
Proposed new §8.5(1), defines the term "affected person," which applies
only to the procedures and requirements of proposed new §8.125, relating
to Waiver Procedure. The term includes but is not limited to persons owning
or occupying real property within 500 feet of any property line of the site
for the facility or operation for which the waiver is sought; the city council,
as represented by the city attorney, the city secretary, the city manager,
or the mayor, if the property that is the site of the facility or operation
for which the waiver is sought is located wholly or partly within any incorporated
municipal boundaries, including the extraterritorial jurisdiction of any incorporated
municipality (if the site of the facility or operation for which the waiver
is sought is located within more than one incorporated municipality, then
the city council of every incorporated municipality within which the site
is located is an affected person); the county commission, as represented by
the county clerk, if the property that is the site of the facility or operation
for which the waiver is sought is located wholly or partly outside the boundary
of any incorporated municipality (if the site of the facility or operation
for which the waiver is sought is located within more than one county, then
the county commission of every county within which the site is located is
an affected person; and any other person who would be adversely impacted by
the waiver sought.
Proposed new §8.5(2) defines the term "applicant" as a person who
has filed with the Safety Division a complete application for a waiver to
a pipeline safety rule or regulation, or a request to use direct assessment
or other technology or assessment methodology not specifically listed in §8.101(b)(1).
The current rules do not define this term.
Proposed new §8.5(3) defines the term "application for waiver" as
the written request, including all reasons and all appropriate documentation,
for the waiver of a particular rule or regulation with respect to a specific
facility or operation. The current rules do not define this term.
Proposed new §8.5(4) defines "charter school" as an elementary or
secondary school operated by an entity created pursuant to Texas Education
Code, Chapter 12. This definition is identical to that found in current §7.74(b)(2).
Proposed new §8.5(5) defines "Commission" as the Railroad Commission
of Texas, eliminating the identical duplicative definitions found in current §7.70(b)(6)
and §7.80(1).
Proposed new §8.5(6) defines "direct assessment" as a structured process
that defines locations where a pipeline is physically examined to provide
assessment of pipeline integrity. The process includes collection, analysis,
assessment, and integration of data, including but not limited to the items
listed in subsection (b)(1) of this section. The physical examination may
include coating examination and other applicable non-destructive evaluation.
This definition is identical to that found in current §8.101(a)(1)(A).
Proposed new §8.5(7) defines "director" as the director of the Commission's
Safety Division or the director's delegate. The term is not defined in the
current rules.
Proposed new §8.5(8) defines "division" as the Safety Division of
the Commission. The current rules do not define this term; rather the current
rules refer to the Pipeline Safety Section of the Gas Services Division. The
Safety Division was created in the Commission's reorganization in September
2003.
Proposed new §8.5(9) defines "farm tap odorizer" as a wick- type odorizer
serving a consumer or consumers off any pipeline other than that classified
as distribution as defined in 49 CFR Part 192.3 which uses not more than 10
mcf on an average day in any month. This is identical to the current definition
of this term in §7.71(a)(2).
Proposed new §8.5(10) defines "gas" as natural gas, flammable gas,
or other gas which is toxic or corrosive; this is the same definition as found
in current §7.70(b)(2).
Proposed new §8.5(11) defines "gas company" as any person who owns
or operates pipeline facilities used for the transportation or distribution
of gas, including master metered systems. This combines the definitions currently
found in §7.70(b)(5) and §7.71(a)(1), and eliminates the redundant
provisions and references to federal regulations found in §7.71(a)(1)
which are already incorporated by reference.
Proposed new §8.5(12) defines "hazardous liquid" as petroleum, petroleum
products, anhydrous ammonia, or any substance or material which is in liquid
state, excluding liquefied natural gas, when transported by pipeline facilities
and which has been determined by the United States Secretary of Transportation
to pose an unreasonable risk to life or property when transported by pipeline
facilities. This is identical to the current definition of this term in §7.80(2).
Proposed new §8.5(13) defines "in-line inspection" as an internal
inspection by a tool capable of detecting anomalies in pipeline walls such
as corrosion, metal loss, or deformation. This is the same definition found
in current §8.101(a)(1)(B).
Proposed new §8.5(14) defines "intrastate pipeline facilities" as
pipeline facilities located within the State of Texas which are not used for
the transportation of natural gas or hazardous liquids or carbon dioxide in
interstate or foreign commerce. This is identical to the current definition
of this term in §7.80(3).
Proposed new §8.5(15) defines "lease user" as a consumer who receives
free gas in a contractual agreement with a pipeline operator or producer.
This is the same definition as in current §7.71(a)(3).
Proposed new §8.5(16) defines "liquids company" as any person who
owns or operates a pipeline or pipelines and/or pipeline facilities used for
the transportation or distribution of any hazardous liquid, carbon dioxide,
or anhydrous ammonia. This term is not defined in the current rules.
Proposed new §8.5(17) defines "master meter operator" as the owner,
operator, or manager of a master metered system. This term is not defined
in the current rules.
Proposed new §8.5(18) defines "master metered system" as a pipeline
system (other than a local distribution company) for distributing gas within
but not limited to a definable area, such as a mobile home park, housing project,
or apartment complex, where the operator purchases metered gas from an outside
source for resale through a gas distribution pipeline system. The gas distribution
pipeline system supplies the ultimate consumer who either purchases the gas
directly through a meter or by other means such as rents. Other than changing
the defined term from "master meter system" to "master metered system," this
is identical to the provision found in §7.70(b)(8).
Proposed new §8.5(19) defines "natural gas supplier" as the entity
selling and delivering the natural gas to a school facility or a master metered
system. If more than one entity sells and delivers natural gas to a school
facility or master metered system, each entity is a natural gas supplier for
purposes of this chapter. This definition is similar to that found in current §7.74(b)(3),
but by changing the current rule from "the individual or company selling and
delivering the natural gas to a school facility" to "the entity selling and
delivering the natural gas to a school facility or a master metered system,"
the Commission intends to include as "natural gas suppliers" those municipally-owned
gas systems that sell and deliver natural gas to master metered systems.
Proposed new §8.5(20) defines "operator" as a person who operates
on his or her own behalf or is an agent designated by the owner to operate
intrastate pipeline facilities. This definition is identical to the current
one found in §7.80(4).
Proposed new §8.5(21) defines "person" as any individual, firm, joint
venture, partnership, corporation, association, cooperative association, joint
stock association, trust, or any other business entity, including any trustee,
receiver, assignee, or personal representative thereof, a state agency or
institution, a county, a municipality, or school district or any other governmental
subdivision of this state. As proposed, this definition combines and reconciles
the two slightly different definitions of the word "person" found in current §7.70(b)(1)
and §7.80(5).
Proposed new §8.5(22) defines "person responsible for a school facility"
as, in the case of a public school, the superintendent of the school district
as defined in Texas Education Code, §11.201, or the superintendent's
designee previously specified in writing to the natural gas supplier. In the
case of charter and private schools, person responsible for a school facility
is the principal of the school or the principal's designee previously specified
in writing to the natural gas supplier. This definition is the same as that
found in current §7.74(b)(4).
Proposed new §8.5(23) defines the term "pipeline facilities" as new
and existing pipe, right-of-way, and any equipment, facility, or building
used or intended for use in the transportation of gas or hazardous liquids
or their treatment during the course of transportation. This proposed definition
combines and reconciles the slightly different definitions of the term found
in current §7.70(b)(4) and §7.80(6).
Proposed new §8.5(24) defines "pressure test" as those techniques
and methodologies prescribed for leak-test and strength-test requirements
for pipelines. For natural gas pipelines, the requirements are found in 49
Code of Federal Regulations (CFR) Part 192, and specifically include 49 CFR §§192.505,
192.507, 192.515, and 192.517. For hazardous liquids pipelines, the requirements
are found in 49 CFR Part 195, and specifically include 49 CFR §§195.305,
195.306, 195.308, and 195.310. This definition is identical to that found
in current §8.101(a)(1)(C).
Proposed new §8.5(25) defines "private school" as an elementary or
secondary school operated by an entity accredited by the Texas Private School
Accreditation Commission. This definition is the same as that found in current §7.74(b)(5).
Proposed new §8.5(26) defines "public school" as an elementary or
secondary school operated by an entity created in accordance with the laws
of the State of Texas and accredited by the Texas Education Agency pursuant
to Texas Education Code, Chapter 39, Subchapter D. The term does not include
programs and facilities under the jurisdiction of the Texas Department of
Mental Health and Mental Retardation, the Texas Youth Commission, the Texas
Department of Human Services, the Texas Department of Criminal Justice or
any probation agency, the Texas School for the Blind and Visually Impaired,
the Texas School for the Deaf and Regional Day Schools for the Deaf, the Texas
Academy of Mathematics & Science, the Texas Academy of Leadership in the
Humanities, and home schools or proprietary schools as defined in Texas Education
Code, §132.001. This definition is the same as that found in current §7.74(b)(6).
Proposed new §8.5(27) defines "school facility" as all piping, buildings
and structures operated by a public, charter, or private school that are downstream
of a meter measuring natural gas service in which students receive instruction
or participate in school sponsored extracurricular activities, excluding maintenance
or bus facilities, administrative offices, and similar facilities not regularly
utilized by students. This is identical to the definition in current §7.74(b)(7).
Proposed new §8.5(28) defines "Secretary" as the Secretary of the
United States Department of Transportation. This term is not defined in the
current rules.
Proposed new §8.5(29) defines "transportation of gas" as the gathering,
transmission, or distribution of gas by pipeline or its storage within the
State of Texas. For purposes of safety regulation, the term shall not include
the gathering of gas in those rural locations which lie outside the limits
of any incorporated or unincorporated city, town, village, or any other designated
residential or commercial area such as a subdivision, a business or shopping
center, a community development, or any similar populated area which the Secretary
may define as a nonrural area. This definition is substantially the same as
that found in current §7.70(b)(3) but has been reworded for clarity.
Proposed new §8.5(30) defines "transportation of hazardous liquids
or carbon dioxide" as the movement of hazardous liquids or carbon dioxide
by pipeline, or their storage incidental to movement, except that, for purposes
of safety regulations, it does not include any such movement through gathering
lines in rural locations or production, refining, or manufacturing facilities
or storage or in-plant piping systems associated with any of those facilities.
This proposed definition adds "carbon dioxide" to the definition, but otherwise
is identical to that found in current §7.80(8).
Subchapter B. Requirements for All Pipelines.
Proposed new rules in Subchapter B, Requirements for All Pipelines, will
include proposed new §8.51, Organization Report; proposed new §8.105,
Records; §8.110, Operations and Maintenance Procedures; §8.115,
Construction Commencement Report; §8.125, Waiver Procedure, and §8.130,
Enforcement, which will join current §8.101, Pipeline Integrity Assessment
and Management Plans for Natural Gas and Hazardous Liquids Pipelines, as proposed
to be amended.
Proposed new §8.51 states the requirement that all gas companies and
all liquids companies not otherwise required to file a Form P-5, organization
report, file one in compliance with 16 Tex. Admin. Code §3.1, relating
to Organization Report; Retention of Records; Notice Requirements. This requirement
is specifically intended to require that master meter operators file a Form
P-5, pursuant to Texas Utilities Code, §121.201. While the proposed new
rule does not derive specifically from a current rule in Chapter 7, the requirement
itself is not new, because the provision in Texas Utilities Code, §121.201,
was enacted in 1999.
Proposed amendments to §8.101, Pipeline Integrity Assessment and Management
Plans for Natural Gas and Hazardous Liquids Pipelines, will remove the definitions
for "direct assessment," "in-line inspection," and "pressure test" that are
being proposed in new §8.5. There will be no change to the definitions.
In subsection (b), the wording is proposed to be changed to recognize that
the deadline by which pipeline operators were to have complied has passed.
No other changes are proposed for §8.101.
Proposed new §8.105, Records, combines the requirements found in current §§7.70(h)
and 7.84(f) into a single rule applicable to both gas and liquids pipelines.
The Commission has modified current wording to achieve specificity and clarity,
but the substance of the provisions is unchanged from current requirements.
Pipeline operators are required to maintain the most current record or records
for at least the longer of either the interval between prescribed tests plus
one year or five years if no other time period is specified. For gas pipelines,
those records and documents required by 49 CFR Parts 191, 192, 193, and 199,
and §8.215, relating to Odorization of Gas, must be retained. For liquids
pipelines, those records and documents required by 49 CFR Parts 195 and 199
must be retained. In addition, operators must retain for the specified period
records of all design and installation of new and used pipe, including design
pressure calculations, pipeline specifications, specified minimum yield strength
and wall-thickness calculations, each valve, fitting, fabricated branch connection,
closure, flange connection, station piping, fabricated assembly, and above-ground
breakout tank; records of all pipeline construction, procedures, training,
and inspection pertaining to welding, nondestructive testing, and cathodic
protection; records of all hydrostatic testing performed on all pipeline segments,
components, and tie-ins; and records involved in the performance of the procedures
outlined in the operations and maintenance procedure manual required by §8.110,
relating to Operations and Maintenance Procedures.
Proposed new §8.110, Operations and Maintenance Procedures, derives
from current §§7.70(i) and 7.84(d), and combines the current requirements
into a single rule. The Commission has modified current wording to achieve
specificity and clarity, but the substance of the provisions is unchanged
from current requirements. Each pipeline operator is required to prepare a
manual or procedural plan, required by 49 CFR Parts 191, 192, 193, 195 or
199, as applicable, and make it available for Commission inspection upon request.
If the Commission finds the plan is inadequate to achieve safe operation,
the operator must revise the plan. The new rule does not require the filing
of the plan 20 days before it becomes effective.
Proposed new §8.115, Construction Commencement Report, combines the
current requirements of §§7.70(g)(4) and 7.84(c). The proposed new
rule applies to all construction totaling one mile or more. Currently, §7.70(g)(4)
applies only to gas pipelines and only to construction of five miles or more;
there is no minimum length specified in current §7.84(c). At least 30
days prior to commencement of construction of any installation totaling one
mile or more of pipe, each operator is required to file with the Commission
a report stating the proposed originating and terminating points for the pipeline,
counties to be traversed, path, size and type of pipe to be used, type of
service, design pressure, and length of the proposed line. By making the report
required for commencement of all construction totaling one mile of pipe or
more and applicable to both gas and liquids pipelines, the Commission intends
to minimize confusion for the pipeline industry, reduce the number of inquiries
to the Commission by the industry, and to maintain better control over the
agency's inspection schedule.
Proposed new §8.125, Waiver Procedure, formalizes the process for
obtaining Commission waiver of compliance with safety rules that the Commission
has used for several years on an informal basis. This proposed new rule has
no counterpart in the current rules, but, as previously stated, implements
a process that has been used by the Commission and pipeline operators on an
informal basis for at least 10 years. Proposed new subsection (a) provides
the method for filing an application for a waiver of a pipeline safety rule
and the procedures the agency will follow in processing such applications.
The Commission specifically directs that the Safety Division will not assign
a docket number to or consider any application filed in response to a notice
of violation of a pipeline safety rule.
Proposed new §8.125(b) provides details about the form of the application
for waiver, and proposed new subsection (c) specifies the contents of the
application. Essential to the application are a description of the facility
at which the operation that is the subject of the waiver request is conducted,
including, if necessary, design and operation specifications, monitoring and
control devices, maps, calculations, and test results; a description of the
acreage and/or address upon which the facility and/or operation is located,
including a plat drawing, identification of the site, environmental surroundings,
placement of buildings and areas intended for human occupancy that could be
endangered by a failure or malfunction of the facility or operation, any increased
risks the particular operation would create if the waiver were granted, and
the additional safety measures that are proposed to compensate for those risks;
a statement of the reason the particular operation, if the waiver were granted,
would not be inconsistent with protection of the health, safety, and welfare
of the general public; and a list of the names, addresses, and telephone numbers
of all affected persons.
Proposed new §8.125(d) sets out the requirements of the notice that
the applicant is required to provide. The applicant must send a copy of the
application and a notice of protest form published by the Commission by certified
mail, return receipt requested, to all affected persons on the same date the
applicant files its application with the Division. The notice must describe
the nature of the waiver sought; state that affected persons have 30 calendar
days from the date of the last publication to file written objections or requests
for a hearing with the Division; and include the docket number of the application
and the mailing address of the Division. The applicant must file all return
receipts with the Division as proof of notice. In addition, the applicant
is required to publish notice of its application for waiver of a pipeline
safety rule once a week for two consecutive weeks in the state or local news
section of a newspaper of general circulation in the county or counties in
which the facility or operation for which the requested waiver is located,
and must file with the Division a publisher's affidavit from each newspaper
in which notice was published as proof of publication of notice. The director
may require the applicant to give additional or different types of notice.
Proposed new §8.125(e) provides that affected persons have standing
to object to or request a hearing on an application for a waiver, and sets
forth the procedure and requirements for doing so.
Proposed new §8.125(f) details the process for the director's review
of a waiver application. If the director does not receive any objections or
requests for a hearing from any affected person, the director may recommend
in writing that the Commission grant the waiver if granting the waiver will
neither imperil nor tend to imperil the health, safety or welfare of the general
public and the environment. The director shall forward the file, along with
the written recommendation that the waiver be granted, to the Office of General
Counsel for the preparation of an order. The rule specifically provides that
the director may not recommend that the Commission grant the waiver if the
application was filed either to correct an existing violation or to avoid
the expense of safety compliance, and requires the director to dismiss with
prejudice to refiling an application filed in response to a notice of violation
of a pipeline safety rule. If the director declines to recommend that the
Commission grant the waiver, the director must notify the applicant in writing
of the recommendation and the reason for it, and inform the applicant of any
specific deficiencies in the application. If the director declines to recommend
that the Commission grant the waiver, and if the application was not filed
either to correct an existing violation or solely to avoid the expense of
safety compliance, the applicant may either modify the application to correct
the deficiencies and resubmit the application or file a written request for
a hearing on the matter within ten calendar days of receiving notice of the
assistant director's written decision not to recommend that the Commission
grant the application.
Proposed new §8.125(g) sets forth the procedures for hearings on applications
for waiver of a pipeline safety rule. Within three days of receiving either
a timely-filed objection or a request for a hearing, the director forwards
the file to the Office of General Counsel for the setting of a hearing. The
Office of General Counsel assigns a presiding examiner to conduct a hearing.
The presiding examiner must mail notice of the hearing by certified mail,
return receipt requested, not less than 30 calendar days prior to the date
of the hearing to the applicant, all persons who filed an objection or a request
for a hearing, and all other affected persons. The presiding examiner conducts
the hearing in accordance with the procedural requirements of Texas Government
Code, Chapter 2001 (the Administrative Procedure Act), and Chapter 1 of Title
16 (the Commission's rules of practice and procedure).
Proposed new §8.125(h) provides that after a hearing, the Commission
may grant a waiver of a pipeline safety rule based on a finding or findings
that the grant of the waiver will neither imperil nor tend to imperil the
health, safety or welfare of the general public and the environment.
Proposed new §8.125(i) sets out the procedure by which notice is given
to the United States Department of Transportation. The Commission's grant
of a waiver becomes effective in accordance with the provisions of 49 United
States Code Annotated, §60118(d).
Proposed new §8.130, Enforcement, derives from current §7.70(j)
and §7.87, and provides for periodic inspections and company obligations.
Proposed subsection (a) states that the Safety Division shall have responsibility
for the administration and enforcement of the provisions of this chapter.
To this end, the Safety Division shall formulate a plan or program for periodic
evaluation of the books, records, and facilities of gas companies and liquids
companies operating in Texas on a sampling basis, in order to satisfy the
Commission that these companies are in compliance with the provisions of this
chapter.
Proposed subsection (b) lists the scope of inspection and provides that,
upon reasonable notice, the Safety Division or its authorized representative
may, at any reasonable time, inspect the books, files, records, reports, supplemental
data, other documents and information, plant, property, and facilities of
a gas company or a liquids company to ensure compliance with the provisions
of this chapter .
Proposed new subsection (c) lists the company obligations and states that
each operator, officer, employee, and representative of a gas company or a
liquids company operating in Texas shall cooperate with the Safety Division
and its authorized representatives in the administration and enforcement of
the provisions of this chapter; in the determination of compliance with the
provisions of this chapter; and in the investigation of violations, alleged
violations, accidents or incidents involving intrastate pipeline facilities.
Each operator, officer, employee, and representative of a gas company or a
liquids company operating in Texas shall make readily available all company
books, files, records, reports, supplemental data, other documents, and information,
and shall make readily accessible all company plant, property, and facilities
as the Safety Division or its authorized representative may reasonably require
in the administration and enforcement of the provisions of this chapter; in
the determination of compliance with the provisions of this chapter; and in
the investigation of violations, alleged violations, accidents or incidents
involving intrastate pipeline facilities.
Subchapter C. Requirements for Natural Gas Pipelines
Only.
Proposed rules in Subchapter C will include current §8.201, Pipeline
Safety Program Fees, as proposed to be amended; proposed new §8.203,
Supplemental Regulations; proposed new §8.205, Written Procedure for
Handling Natural Gas Leak Complaints; proposed new §8.210, Reports; proposed
new §8.215, Odorization of Gas; proposed new §8.220, Master Metered
Systems; proposed new §8.225, Plastic Pipe Requirements; proposed new §8.230,
School Piping Testing; current §8.235, Natural Gas Pipelines Public Education
and Liaison, as proposed to be amended; current §8.240, Discontinuance
of Service; and proposed new §8.245, Penalty Guidelines for Pipeline
Safety Violations.
Proposed amendments to §8.201, relating to Pipeline Safety Program
Fees, concern the per-service line surcharge that natural gas distribution
systems may assess customers to recover the amounts remitted to the Commission,
and which customers may be assessed the one-time surcharge. In subsection
(b)(3)(D), the surcharge amount is proposed to be changed from the current
$0.37 per service line to $0.50 per service line, the statutory maximum under
Texas Utilities Code, § 121.211, to minimize potential under-recoveries
by the distribution utilities.
In subsection (b)(4) and subsection (c)(4), the Commission makes amendments
to recognize that pipeline safety matters are now handled by the Safety Division,
created in the agency's September 2003 reorganization. The proposed amendments
to these subsections add the Safety Division as an additional recipient of
the reports required from operators of natural gas distribution systems and
master metered systems.
Proposed new §8.203, Supplemental Regulations, derives from current §7.70(k).
The Commission has modified current wording to achieve specificity and clarity,
but the substance of the provisions is unchanged from current requirements.
These provisions supplement the regulations appearing in 49 CFR Part 192,
adopted under proposed new §8.1(b).
Proposed new §8.203(1) provides that Section 192.3 is supplemented
by the following: "Short section of pipeline" means a segment of a pipeline
100 feet or less in length.
Proposed new §8.203(2) provides that Section 192.455(b) is supplemented
by the following language after the first sentence: "Tests, investigation,
or experience must be backed by documented proof to substantiate results and
determinations."
Proposed new §8.203(3) provides that Section 192.457 is supplemented
by the following language in subsection (b)(3): "(3) Bare or coated distribution
lines. The operator shall determine the areas of active corrosion by electrical
survey, or where electrical survey is impractical, by the study of corrosion
and leak history records, by leak detection survey, or by other effective
means, documented by data substantiating results and determinations"; and
by the following subsection: "(d) When a condition of active external corrosion
is found, positive action must be taken to mitigate and control the effects
of the corrosion. Schedules must be established for application of corrosion
control. Monitoring effectiveness must be adequate to mitigate and control
the effects of the corrosion prior to its becoming a public hazard or endangering
public safety."
Proposed new §8.203(4) provides that Section 192.465 is supplemented
by the following language after the first sentence of subsection (a): "Test
points (electrode locations) used when taking pipe-to-soil readings for determining
cathodic protection shall be selected so as to give representative pipe-to-soil
readings. Test points (electrode locations) over or near an anode or anodes
shall not, by themselves, be considered representative readings"; by the following
language in subsection (e): "(e) After the initial evaluation required by
paragraphs (b) and (c) of §192.455 and paragraph (b) of §192.457,
each operator shall, at intervals not exceeding three years, reevaluate its
unprotected pipelines and cathodically protect them in accordance with this
subpart in areas in which active corrosion is found. The operator shall determine
the areas of active corrosion by electrical survey, or where electrical survey
is impractical, by the study of corrosion and leak history records, by leak
detection survey, or by other effective means, documented by data substantiating
results and determinations"; and by the following subsection: "(f) When leak
detection surveys are used to determine areas of active corrosion, the survey
frequency must be increased to monitor the corrosion rate and control the
condition. The detection equipment used must have sensitivity adequate to
detect gas concentration below the lower explosive limit and be suitable for
such use."
Proposed new §8.203(5) provides that Section 192.475(a) is supplemented
by the following language at the end: "Corrosive gas" means a gas which, by
chemical reaction with the pipe to which it is exposed, usually metal, produces
a deterioration of the material."
Proposed new §8.203(6) provides that Section 192.479 is supplemented
by the following subsection: "(c) 'atmospheric corrosion' means aboveground
corrosion caused by chemical or electrochemical reaction between a pipe material,
usually a metal, and its environment, that produces a deterioration of the
material."
Proposed new §8.205, Written Procedures for Handling Natural Gas Leak
Complaints, derives from current §7.72. The Commission has modified current
wording to achieve specificity and clarity, but the substance of the provisions
is unchanged from current requirements. Each gas company must have written
procedures which must include, at a minimum, the following: a procedure or
method for receiving leak complaints or reports, or both, on a 24-hour, seven
day per week basis; a requirement to make and maintain a written record of
all calls received and actions taken; a requirement that supervisory personnel
review calls received and actions taken to insure no hazardous conditions
exist at the close of the work day; standards for training and equipping personnel
used in the investigation of leak complaints or reports, or both; procedures
for locating the source of a leak and determining the degree of hazard involved;
a chain of command for service personnel to follow if assistance is required
in determining the degree of hazard; and 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.
Proposed new §8.210, Reports, derives from current §7.70(g).
The Commission has modified current wording to achieve specificity and clarity,
but the substance of the provisions is unchanged from current requirements.
Proposed new §8.210(a)(1) requires a gas company, at the earliest
practical moment or within two hours following discovery, to notify the Commission
by telephone of any event that involves a release of gas from any pipeline
which caused a death or any personal injury requiring hospitalization; required
taking any segment of a transmission line out of service, with one exception;
resulted in unintentional gas ignition requiring emergency response; caused
estimated damage to the property of the operator, others, or both totaling
$5,000 or more, including gas loss; or could reasonably be judged as significant
because of location, rerouting of traffic, evacuation of any building, media
interest, etc., even though it does not fall within the other event descriptions
of this paragraph.
Proposed new §8.210(a)(2) provides the exception to the requirement
that a gas company give notice of any release of gas which required taking
a segment of a transmission line out of service. The gas company is not required
to make a telephonic report for a leak or incident if that leak or incident
occurred solely as a result of or in connection with planned or routine maintenance
or construction.
Proposed new §8.210(a)(3) provides that the telephonic report must
be made to the Commission's 24-hour emergency line at (512) 463-6788 and must
include the following information: the operator or gas company's name; the
location of the leak or incident; the time of the incident or accident; the
fatalities and/or personal injuries; the phone number of the operator; and
any other significant facts relevant to the accident or incident.
Proposed new §8.210(a)(4) provides that following the initial telephonic
report for accidents, leaks, or incidents that caused a death or any personal
injury requiring hospitalization, caused estimated damage to the property
of the operator, others, or both totaling $5,000 or more, including gas loss,
or could reasonably be judged as significant because of location, rerouting
of traffic, evacuation of any building, media interest, etc., the operator
who made the telephonic report must submit to the Commission a written report
summarizing the accident or incident. The report must be submitted as soon
as practicable within 30 calendar days after the date of the telephonic report.
The written report must be made in duplicate on forms supplied by the Department
of Transportation. The Division must forward one copy to the Department of
Transportation. The written report is not required to be submitted for master
metered systems, but the Commission may require an operator to submit a written
report for an accident or incident not otherwise required to be reported.
Proposed new §8.210(b) requires that each gas company submit an annual
report for its systems in the same manner as required by 49 CFR Part 191.
The report must be submitted to the Division in duplicate on forms supplied
by the Department of Transportation not later than March 15 of each year for
the preceding calendar year. The Division forwards one copy to the Department
of Transportation. The annual report is not required to be submitted for 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 a master metered system.
Proposed new §8.210(c) requires each gas company to submit to the
Division in writing a safety-related condition report for any condition outlined
in 49 CFR Part 191.25.
Proposed new §8.210(d) requires that within 60 days of completion
of underwater inspection, each operator must file with the Division a report
of the condition of all underwater pipelines subject to 49 CFR 192.612(a).
Proposed new §8.215, Odorization of Gas, derives from current §7.71.
The Commission has modified the current rule's organization and wording to
achieve specificity and clarity, but the substance of the provisions is unchanged
from current requirements.
Proposed new §8.215(a) requires each gas company to continuously odorize
gas by the use of a malodorant agent as set forth in the section unless the
gas contains a natural malodor or is odorized prior to delivery by a supplier.
Unless required by 49 CFR Part 192.625(B) or otherwise by this section, odorization
is not required for gas in underground or other storage; 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 gas used in lease and field operation or development or in repressuring
wells. Gas must be odorized by the user if the gas is delivered for use primarily
in one of the activities or facilities listed in paragraph (2) of subsection
(a) and is also used in one of those activities for space heating, refrigeration,
water heating, cooking, and other domestic uses; or the gas is used for furnishing
heat or air conditioning for office or living quarters. In the case of lease
users, the supplier must ensure that the gas will be odorized before being
used by the consumer.
Proposed new §8.215(b) requires gas companies to use odorization equipment
approved by the Commission as provided in the subsection. Commercial manufacturers
of odorization equipment manufactured under accepted rules and practices of
the industry must submit plans and specifications of such equipment to the
Division with Form PS-25 for approval of standardized models and designs.
The Division maintains a list of approved commercially available odorization
equipment.
Each operator is 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. This list must be
available for review during safety evaluations by the Division.
Prior to using shop-made or other odorization equipment not approved by
the Commission under paragraph (1) of subsection (b), a gas company must submit
to the Division Form PS-25 and plans and specifications for the equipment.
Within 30 days of receiving Form PS-25 and related documents, the Division
shall recommend in writing to notify the gas company in writing whether the
equipment is approved or not approved for the requested use.
Proposed new §8.215(c) provides that the Division will maintain a
list of approved malodorants which meet certain criteria. The malodorant when
blended with gas in the amount specified for adequate odorization of the gas
must 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. The products of combustion
from the malodorant must be nontoxic to humans breathing air containing the
products of combustion and the products of combustion must not be corrosive
or harmful to the materials to which such products of combustion would ordinarily
come in contact. 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 must have a distinctive malodor so that when gas is present
in air at a concentration of as much as 1.0% or less by volume, the malodor
is readily detectable by an individual with a normal sense of smell. Injection
of approved malodorant or the natural malodor must be at a rate sufficient
to achieve the specified requirements.
Proposed new §8.215(d) requires each gas company to record the volume
of odorant and calculate the injection rate 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 following information must be recorded and retained in the company's files
odorizer location; brand name and model of odorizer; name of malodorant, concentrate,
or dilute; quantity of malodorant at beginning of month/quarter; amount added
during month/quarter; quantity at end of month/quarter; MMcf of gas purchased
during month/quarter; and the injection rate per MMcf.
Operators must check, test, and service farm tap odorizers at least annually
according to the terms of the approved schedule of service and maintenance
for farm tap odorizers Form PS-9, filed with and approved by the Division.
Each gas company must maintain records to reflect the date of service and
maintenance on file for at least two years.
Proposed new §8.215(e) requires each gas company to conduct the following
concentration tests on the gas supplied through its facilities and required
to be odorized. Other tests conducted in accordance with procedures approved
by the Division may be substituted for the following room and malodorant concentration
test meter methods. Test points must be distant from odorizing equipment,
so as to be representative of the odorized gas in the system. Tests must be
performed at least once each calendar year or at such other times as the Division
may reasonably require. The results of these tests must be recorded on the
approved odorant concentration test Form PS-6 or equivalent and retained in
each company's files for at least two years.
For a room test, the test results must include the odorizer name and location;
the date the test was performed, test time, location of test, and distance
from odorizer, if applicable; the percent gas in air when malodor is readily
detectable; and signatures of witnesses to the test and the supervisor of
the test.
For a malodorant concentration test meter, the test results must include
the odorizer name and location; the malodorant concentration meter make, model,
and serial number; the date the test was performed, test time, odorizer tested,
and distance from odorizer, if applicable; the test results indicating percent
in air when malodor is readily detectable; and signature of person performing
the test.
Farm tap odorizers are exempt from the odorization testing requirements.
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 are required to conduct quarterly malodorant concentration
tests and retain records for a period of two years.
Proposed new §8.220, Master Metered Systems, derives from current §7.73.
The Commission has modified the current rule's organization and wording to
achieve specificity and clarity, but the substance of the provisions is unchanged
from current requirements.
Proposed new §8.220(a) requires each master meter operator to comply
with the minimum safety standards in 49 CFR Part 192.
Proposed new §8.220(b) requires each master meter operator to conduct
a leakage survey on the system every two years, using leak detection equipment.
Proposed new §8.220(c) requires natural gas suppliers to be responsible
for installation and inspection of overpressure equipment at those master
meter locations where 10 or more consumers are served low pressure gas.
Proposed new §8.225, Plastic Pipe Requirements, derives from current §7.70(g)(2)(C);
(g)(5); and (g)(6). The Commission has modified the current rule's organization
and wording to achieve specificity and clarity, but the substance of the provisions
is unchanged from current requirements.
Proposed new §8.225(a) requires each operator to record information
relating to each material failure of plastic pipe during each calendar year,
and annually to file with the Division, in conjunction with the annual report,
a summary of the failures, using Form PS-80, Annual Plastic Pipe Failure Report.
The initial Forms PS-80, reporting plastic pipe failure data for calendar
year 2001, were due by March 15, 2002.
Proposed new §8.225(b) provides that by March 15, 2003, and March
15, 2004, operators must report on Form PS-82, Annual Report of Plastic Installation
and/or Removal, the amount, in miles, of plastic pipe installed and/or removed
during the preceding calendar year. The mileage must be further identified
by system, nominal pipe size, material designation code, pipe category, and
pipe manufacturer. For all new installations of plastic pipe, each operator
must record and maintain for the life of the pipeline the following information
for each pipeline segment: all specification information printed on the pipe;
the total length; a citation to the applicable joining procedures used for
the pipe and the fittings; and the location of the installation to distinguish
the end points. A pipeline segment is defined as a continuous piping where
the pipe specification required by ASTM D2513 or ASTM D2517 does not change.
Proposed new §8.225(c) provides that beginning March 15, 2005, and
annually thereafter, each operator must report to the Commission the amount
of plastic pipe in natural gas service as of December 31 of the previous year.
The amount of plastic pipe must be determined by a review of the records of
the operator and reported on Form PS-81, Plastic Pipe Inventory. The report
must include the system; miles of pipe; calendar year of installation; nominal
pipe size; material designation code; pipe category; and pipe manufacturer.
Proposed new §8.225(d) requires that operators of systems with more
than 1,000 customers file the required reports electronically in a format
specified by the Commission.
Proposed new §8.225(e) provides that operators complete all required
forms in accord with the section, including signatures of company officials.
The Commission may consider the failure of an operator to complete all forms
as required to be a violation under Texas Utilities Code, Chapter 121, and
may seek penalties as permitted by that chapter.
Proposed new §8.230, School Piping Testing, derives from current §7.74.
The Commission has modified the current rule's organization by moving the
definitions from current §7.74(a) to proposed new §8.5 and re-lettering
the remaining subsections; otherwise, the substance of the current provisions
is unchanged from current requirements.
Proposed new §8.230(a) states the purpose of this section as being
the implementation of the requirements of Texas Utilities Code, §§121.5005-121.507,
relating to the testing of natural gas piping systems in school facilities.
Proposed new §8.230(b) requires natural gas suppliers to develop procedures
for receiving written notice from a person responsible for a school facility,
specifying the date and result of each test; and terminating natural gas service
to a school facility in the event that the natural gas supplier receives notification
of a hazardous natural gas leak in the school facility piping system pursuant
to this rule, or the natural gas supplier does not receive written notification
specifying the date that testing has been completed on a school facility and
the results of such testing. A natural gas supplier may rely on a written
notification that complies with the rule as proof that a school facility is
in compliance with Texas Utilities Code, §§121.5005-121.507, and
the rule. A natural gas supplier has no duty to inspect a school facility
for compliance with Texas Utilities Code, §§121.5005-121.507.
Proposed new §8.230(c) states that a natural gas piping pressure test
performed under a municipal code in compliance with the rule satisfies the
testing requirements. A pressure test to determine if the natural gas piping
in each school facility will hold at least normal operating pressure must
be performed as specified. For systems on which the normal operating pressure
is less than 0.5 psig, the test pressure must be 5 psig and the time interval
30 minutes. For systems on which the normal operating pressure is 0.5 psig
or more, the test pressure must be 1.5 times the normal operating pressure
or 5 psig, whichever is greater, and the time interval 30 minutes. A pressure
test using normal operating pressure may be utilized only on systems operating
at 5 psig or greater, and the time interval must be one hour. The testing
must be conducted by a licensed plumber; a qualified employee or agent of
the school who is regularly employed as or acting as a maintenance person
or maintenance engineer; or a person exempt from the plumbing license law
as provided in Texas Civil Statutes, Article 6243-101, §3.
The testing of public school facilities must be completed as follows: for
school facilities tested prior to the beginning of the 1997-1998 school year,
at least once every two years thereafter before the beginning of the school
year; for school facilities not tested prior to the beginning of the 1997-1998
school year, as soon as practicable thereafter but prior to the beginning
of the 1998-1999 school year and at least once every two years thereafter
before the beginning of the school year; for school facilities operated on
a year-round calendar and tested prior to July 1, 1997, at least once every
two years thereafter; and for school facilities operated on a year-round calendar
and not tested prior to July 1, 1997, once prior to July 1, 1998, and at least
once every two years thereafter.
The testing of charter and private school facilities must occur at least
once every two years and must be performed before the beginning of the school
year, except for school facilities operated on a year-round calendar, which
must be tested not later than July 1 of the year in which the test is performed.
The initial test of charter and private school facilities must occur prior
to the beginning of the 2003-2004 school year or by August 31, 2003, whichever
is earlier.
The firm or individual conducting the test must immediately report any
hazardous natural gas leak to the board of trustees of the school district
and the natural gas supplier; for a public school facility, and to the person
responsible for such school facility and the natural gas supplier for a charter
or private school facility. The school pipe testing must be recorded on Railroad
Commission Form PS-86.
Proposed new §8.230(d) requires natural gas suppliers to maintain
for at least two years a listing of the school facilities to which it sells
and delivers natural gas as well as copies of the written notification regarding
testing, Form PS-86, and hazardous leaks received pursuant to Texas Utilities
Code, §§121.5005-121.507, and the rule.
The proposed amendment to §8.235, Natural Gas Pipelines Public Education
and Liaison, would substitute "Safety Division" for "Gas Services Division,
Pipeline Safety Section," in subsection (e).
Proposed new §8.245, Penalty Guidelines for Pipeline Safety Violations,
derives from current §§7.70(j), but is expanded to include the requirements
enacted by Senate Bill 310 (Acts 2001, 77th Leg., ch. 1233, §§ 5
and 71, respectively, eff. Sept. 1, 2001) in Texas Natural Resources Code, §81.0531,
and Texas Utilities Code, §121.206, both of which require the Commission,
by rule, to adopt guidelines to be used in determining the amount of the penalty
for violations of pipeline safety rules.
Specifically, Texas Natural Resources Code, §81.0531(d) provides that
the rule must set forth the 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, or permit that relates to pipeline safety.
The guidelines must also include a penalty calculation worksheet that specifies
the typical penalty for certain violations, circumstances justifying enhancement
of a penalty and the amount of the enhancement, and circumstances justifying
a reduction in a penalty and the amount of the reduction. The guidelines must
take into account the permittee's history of previous violations, including
the number of previous violations; the seriousness of the violation and of
any pollution resulting from the violation; any hazard to the health or safety
of the public; the degree of culpability; the demonstrated good faith of the
person charged; and any other factor the commission considers relevant.
Texas Utilities Code, §121.206, authorizes the Commission to assess
an administrative penalty against a person who violates Texas Utilities Code, §121.201,
or Subchapter I (Texas Utilities Code, §§121.451-121.454) or a safety
standard or rule relating to the transportation of gas and gas pipeline facilities
adopted under those provisions. Subsection 121.206(d) requires that the Commission's
rule must include a penalty calculation worksheet that specifies the typical
penalty for certain violations, circumstances justifying enhancement of a
penalty and the amount of the enhancement, and circumstances justifying a
reduction in a penalty and the amount of the reduction. The guidelines must
take into account the permittee's history of previous violations, including
the number of previous violations; the seriousness of the violation and of
any pollution resulting from the violation; any hazard to the health or safety
of the public; the degree of culpability; the demonstrated good faith of the
person charged; and any other factor the commission considers relevant. The
proposed rule summarizes and explains the Commission's practice with respect
to requesting, recommending, or finally assessing penalties in an enforcement
action.
Proposed new §8.245(a) provides that the section offers only guidelines,
in compliance 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.
Proposed new §8.245(b) states that the establishment of these penalty
guidelines in no way limits 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.
Proposed new §8.245(c) lists the factors to be considered in determining
the amount of any penalty requested, recommended, or finally assessed in an
enforcement action. The amount will be determined on an individual case-by-case
basis for each violation, taking into consideration the person's history of
previous violations, including the number of previous violations; the seriousness
of the violation and of any pollution resulting from the violation; any hazard
to the health or safety of the public; the degree of culpability; the demonstrated
good faith of the person charged; and any other factor the Commission considers
relevant.
Proposed new §8.245(d) sets forth 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 in Table 1.
Proposed new §8.245(e) explains that for violations that involve threatened
or actual pollution; result in threatened or actual safety hazards; result
from the reckless or intentional conduct of the person charged; or involve
a person with a history of prior violations, 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.
Proposed new §8.245(f) provides that 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.
Proposed new §8.245(g) provides that the recommended penalty for a
violation may be reduced by up to 50% if the person charged agrees to a settlement
before the Commission conducts an administrative hearing to prosecute a violation.
Once the hearing is convened, the opportunity for the person charged to reduce
the basic penalty is no longer available. The reduction applies to the basic
penalty amount requested and not to any requested enhancements.
Proposed new §8.245(h) provides that, 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.
Proposed new §8.245(i) explains the penalty calculation worksheet
in Table 5. The worksheet lists the typical penalty amounts for certain violations;
lists each of the circumstances justifying enhancements of a penalty and the
amount of the enhancement; and lists each of the circumstances justifying
a reduction in a penalty and the amount of the reduction.
Subchapter D. Requirements for Hazardous Liquids
and Carbon Dioxide Pipelines Only.
Proposed new rules in Subchapter D, Requirements for Hazardous Liquids
and Carbon Dioxide Pipelines Only, will include proposed new §8.301,
Required Records and Reporting; and proposed new §8.305, Corrosion Control
Requirements; and current §8.310, Community Liaison and Public Education
for Hazardous Liquids and Carbon Dioxide Pipelines, and §8.315, Hazardous
Liquids and Carbon Dioxide Pipelines or Pipeline Facilities Located Within
1,000 Feet of a Public School Building or Facility.
Proposed new §8.301, Required Records and Reporting, derives from
current §7.84(a), (b), (c) and (e). The Commission has modified the current
rule's organization and wording to achieve specificity and clarity, but the
substance of the provisions is unchanged from current requirements.
Proposed new §8.301(a) covers 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, then the operator is required
to report to the Commission. In the event of an accident involving crude oil,
the operator must notify the Division, which in turn must notify the Commission's
appropriate Oil and Gas district office, by telephone to the Commission's
emergency line at the earliest practicable moment following discovery of the
incident (within two hours). The initial telephone report must include the
company/operator name; the location of leak or incident; the time and date
of accident/incident; any fatalities and/or personal injuries; phone number
of operator; and other significant facts relevant to the accident or incident.
Within 30 days of discovery of the incident, the operator must 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 must also file duplicate copies
of the required Department of Transportation form with the Division.
For incidents involving hazardous liquids, other than crude oil, and carbon
dioxide, the operator must notify the Division by telephone at the earliest
practicable moment following discovery (within two hours) and within 30 days
of discovery of the incident, file in duplicate with the Division a written
report using the appropriate Department of Transportation form (as required
by 49 CFR Part 195) or a facsimile.
Proposed new §8.301(b) pertains to annual reports. Each operator is
required to file with the Commission an annual report on Form PS-45 listing
line sizes and lengths, hazardous liquids or carbon dioxide being transported,
and accident/failure data. The report is to be filed with the Commission on
or before March 15 of a year for the preceding calendar year reported.
Proposed new §8.301(c) covers the requirement that operators file
facility response plans. Simultaneously with filing either an initial or a
revised facility response plan with the United States Department of Transportation,
each operator is required to 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.
Proposed new §8.305, Corrosion Control Requirements, derives from
current §7.86. The Commission has modified the current rule's organization
and wording to achieve specificity and clarity, but the substance of the provisions
is unchanged from current requirements.
Operators are required to comply or ensure compliance with the specified
requirements for the installation and construction of new pipeline metallic
systems, the relocation or replacement of existing facilities, and the operation
and maintenance of steel pipelines.
Proposed new §8.305(1) sets forth the requirements for atmospheric
corrosion control. Each aboveground pipeline or portion of pipeline exposed
to the atmosphere must be cleaned and coated or jacketed with material suitable
for the prevention of atmospheric corrosion. For onshore pipelines, the intervals
between inspections must not exceed five years; for offshore pipelines, reevaluations
are required at least once each calendar year, with intervals not to exceed
15 months.
Proposed new §8.305(2) deals with pipeline coatings. All coated pipe
used for the transport of hazardous liquids or carbon dioxide must be electrically
inspected prior to placement using coating deficiency (holiday) detectors
to check for any faults not observable by visual examination. The holiday
detector must be operated in accordance with manufacturer's instructions and
at a voltage level appropriate for the electrical characteristics of the pipeline
system being tested.
Proposed new §8.305(3) requires that joint fittings, and tie-ins be
coated with materials compatible with the coatings on the pipe.
Proposed new §8.305(4) pertains to cathodic protection test stations.
Each cathodically protected pipeline must have test stations or other electrical
measurement contact points sufficient to determine the adequacy of cathodic
protection. These locations must include but are not limited to pipe casing
installations and all foreign metallic cathodically protected structures.
Test stations (electrode locations) used when taking pipe-to-soil readings
for determining cathodic protection must be selected to give representative
pipe-to-soil readings. Readings taken at test stations (electrode locations)
over or near one or more anodes are not, by themselves, considered representative.
In addition, all test lead wire attachments and bared test lead wires must
be coated with an electrically insulating material. Where the pipe is coated,
the insulation of the test lead wire material must be compatible with the
pipe coating and wire insulation. Cathodic protection systems must meet or
exceed the minimum criteria set forth in Criteria For Cathodic Protection
of the most current edition of the National Association of Corrosion Engineers
(NACE) Standard RP-01-69.
Proposed new §8.305(5) concerns monitoring and inspection. Each cathodic
protection rectifier or impressed current power source must be inspected at
least six times each calendar year, with intervals not to exceed 2 1/2 months,
to ensure that it is operating properly. Each reverse-current switch, diode,
and interference bond whose failure would jeopardize structure protection
must be checked electrically for proper performance six times each calendar
year, with intervals not to exceed 2 1/2 months. Each remaining interference
bond must be checked at least once each calendar year, with intervals not
to exceed 15 months. Each operator is required to utilize right-of-way inspections
to determine areas where interfering currents are suspected. In the course
of these inspections, personnel must be alert for electrical or physical conditions
which could indicate interference from a neighboring source. Whenever suspected
areas are identified, the operator must conduct appropriate electrical tests
within six months to determine the extent of interference and take appropriate
action.
Proposed new §8.305(6) requires that each operator take prompt remedial
action to correct any deficiencies observed during monitoring.
Mary McDaniel, Director, Safety Division, has determined that for each
year of the first five years that the proposed new rules and amendments will
be in effect, there will be no fiscal implications to state or local governments.
Municipalities that operate natural gas distribution systems are subject to
the Commission's pipeline safety rules; however, the proposed new rules are
either substantively the same as current rules in Chapter 7, some of which
have been in place since 1976, or they put into a formal rule a procedure
that has been used by Commission staff and subject pipelines on an informal
basis for several years. Proposed new §8.245, Penalty Guidelines for
Pipeline Safety Violations, embodies in rule format a summary and explanation
of statutory provisions and Commission practice with respect to requesting,
recommending, and determining penalty amounts for pipeline safety violations,
as required by Texas Natural Resources Code, §81.0531(d), and Texas Utilities
Code, §121.206(d), enacted by Senate Bill 310 (Acts 2001, 77th Leg.,
ch. 1233, §§ 5 and 71, respectively, eff. Sept. 1, 2001), but only
those pipeline operators who become subject to Commission enforcement actions
for pipeline safety violations would be subject to its terms.
Ms. McDaniel has also determined that, for each year of the first five
years that the proposed new rules and amendments are in effect, the public
benefit will be that all pipeline safety rules will be located in their own
chapter. This should make it easier for operators to locate the rules, thus
making compliance easier for pipeline operators to achieve and making pipeline
operations safer. Also, combining provisions that apply to all pipelines is
efficient. Having all pipeline safety regulations in a single chapter makes
them easier for the public to find and understand what is required of pipeline
operators.
The Commission anticipates that there will be no additional cost to individuals,
small businesses, or micro-businesses of complying with the proposed new rules
and amendments. Most of the new rules are substantively the same as current
rules in Chapter 7, with which all operators are currently required to comply.
One proposed new rule merely formalizes the procedure for obtaining a waiver
of a pipeline safety rule that has been observed informally for at least 10
years. Finally, proposed new §8.245 applies to pipeline operators against
whom enforcement actions are brought for violations of pipeline safety rules,
and is a summary and explanation of current statutory provisions and Commission
practice with respect to requesting, recommending, and determining penalty
amounts for pipeline safety violations.
Comments on the proposal may be submitted to Rules Coordinator, Office
of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin,
Texas 78711-2967; online at www.rrc.state.tx.us/rules/commentform.html; or
by electronic mail to rulescoordinator@rrc.state.tx.us. The Commission will
accept comments for 60 days after publication in the
Texas Register
and should refer to Gas Utilities Docket No. 9255. For
more information, call Mary McDaniel at (512) 463-7166. The status of Commission
rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
Subchapter A. GENERAL REQUIREMENTS AND DEFINITIONS
16 TAC §8.1, §8.5
The Commission proposes the new sections and the amendments
to current rules in Chapter 8, Subchapter A, 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, §§117.001-117.101,
which authorize the Commission to adopt safety standards and practices applicable
to the transportation of hazardous liquids and carbon dioxide and associated
pipeline facilities within Texas to the maximum degrees permissible under,
and to take any other requisite action in accordance with, 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
.; Texas Utilities Code, §§121.251-121.253, which governs
the use of malodorants in natural and liquefied natural gas and authorizes
the Commission to make rules as necessary to carry out the purposes of this
section; and Texas Utilities Code, §§121.5005-121.507, which govern
the testing of natural gas piping systems in school facilities and require
the Commission to enforce the provisions of the statute.
Texas Natural Resources Code, §§81.051, 81.052, and 117.001-117.101;
Texas Utilities Code, §§121.201-121.210, §§121.251-121.253,
and §§121.5005-121.507; and 49 United States Code Annotated, §60101,
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, and 117.001-117.101; Texas Utilities Code, §§121.201-121.210, §§121.251-121.253,
and §§121.5005- 121.507; and 49 United States Code Annotated, §60101,
Cross-reference to statute: Texas Natural Resources Code, Chapters 81 and
117; Texas Utilities Code, Chapter 121; and 49 United States Code Annotated,
Chapter 601.
Issued in Austin, Texas on April 23, 2004.
§8.1.General Applicability and Standards.
(a)
Applicability.
(1)
The rules in this chapter establish minimum standards of
accepted good practice and apply to:
(A)
all gas pipeline facilities and facilities used in the
intrastate transportation of natural gas, including master metered systems,
as provided in 49 United States Code (U.S.C.) §60101,
et seq
., and Texas Utilities Code, §§121.001-121.507;
(B)
the intrastate pipeline transportation of hazardous liquids
or carbon dioxide and all intrastate pipeline facilities as provided in 49
U.S.C. §60101,
et seq
., and Texas Natural
Resources Code, §§117.011 and 117.012; and
(C)
all pipeline facilities originating in Texas waters (three
marine leagues and all bay areas). These pipeline facilities include those
production and flow lines originating at the well.
(2)
The regulations do not apply to those facilities and transportation
services subject to federal jurisdiction under: 15 U.S.C. §717,
(b)
Minimum safety standards. The Commission adopts by reference
the following provisions, as modified in this chapter, effective April 9,
2004.
(1)
Natural gas pipelines shall be designed, constructed, maintained,
and operated in accordance with 49 U.S.C. §60101,
et seq
.; 49 Code of Federal Regulations (CFR) Part 191, Transportation
of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and
Safety-Related Condition Reports; 49 CFR Part 192, Transportation of Natural
and Other Gas by Pipeline: Minimum Federal Safety Standards; and 49 CFR Part
193, Liquefied Natural Gas Facilities: Federal Safety Standards.
(2)
Hazardous liquids or carbon dioxide pipelines shall comply
with 49 U.S.C. §60101,
et seq
.; and 49
CFR Part 195, Transportation of Hazardous Liquids by Pipeline.
(3)
All operators of pipelines and/or pipeline facilities shall
comply with 49 CFR Part 199, Drug and Alcohol Testing.
(c)
Special situations. Nothing in this chapter shall prevent
the Commission, after notice and hearing, from prescribing more stringent
standards in particular situations. In special circumstances, the Commission
may require the following:
(1)
Any operator which cannot determine to its satisfaction
the standards applicable to special circumstances may request in writing the
Commission's advice and recommendations. In a special case, and for good cause
shown, the Commission may authorize exemption, modification, or temporary
suspension of any of the provisions of this chapter, pursuant to the provisions
of §8.125 of this title (relating to Waiver Procedure).
(2)
If an operator transports gas and/or operates pipeline
facilities which are in part subject to the jurisdiction of the Commission
and in part subject to the Department of Transportation pursuant to 49 U.S.C. §60101,
(d)
Concurrent filing. A person filing any document or information
with the Department of Transportation shall file a copy of that document or
information with the Safety Division.
(e)
Penalties. A person who submits incorrect or false information
with the intent of misleading the Commission regarding any material aspect
of an application or other information required to be filed at the Commission
may be penalized as set out in Texas Natural Resources Code, §§117.051-117.054,
and/or Texas Utilities Code, §§121.206-121.210, and the Commission
may dismiss with prejudice to refiling an application containing incorrect
or false information or reject any other filing containing incorrect or false
information.
(f)
Retroactivity. Nothing in this chapter shall be applied
retroactively to any existing intrastate pipeline facilities concerning design,
fabrication, installation, or established operating pressure, except as required
by the Office of Pipeline Safety, Department of Transportation. All intrastate
pipeline facilities shall be subject to the other safety requirements of this
chapter.
§8.5.Definitions.
The following words and terms, when used in this chapter, shall have
the following meanings, unless the context clearly indicates otherwise. In
addition to the following defined terms, definitions given in 49 CFR Parts
191, 192, 193, 195, and 199 are hereby adopted by reference as definitions
for purposes of this chapter.
(1)
Affected person--This definition of this term applies only
to the procedures and requirements of §8.125 of this title (relating
to Waiver Procedure). The term includes but is not limited to:
(A)
persons owning or occupying real property within 500 feet
of any property line of the site for the facility or operation for which the
waiver is sought;
(B)
the city council, as represented by the city attorney,
the city secretary, the city manager, or the mayor, if the property that is
the site of the facility or operation for which the waiver is sought is located
wholly or partly within any incorporated municipal boundaries, including the
extraterritorial jurisdiction of any incorporated municipality. If the site
of the facility or operation for which the waiver is sought is located within
more than one incorporated municipality, then the city council of every incorporated
municipality within which the site is located is an affected person;
(C)
the county commission, as represented by the county clerk,
if the property that is the site of the facility or operation for which the
waiver is sought is located wholly or partly outside the boundary of any incorporated
municipality. If the site of the facility or operation for which the waiver
is sought is located within more than one county, then the county commission
of every county within which the site is located is an affected person;
(D)
any other person who would be adversely impacted by the
waiver sought.
(2)
Applicant--A person who has filed with the Safety Division
a complete application for a waiver to a pipeline safety rule or regulation,
or a request to use direct assessment or other technology or assessment methodology
not specifically listed in §8.101(b)(1), of this title (relating to Pipeline
Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids
Pipelines).
(3)
Application for waiver--The written request, including
all reasons and all appropriate documentation, for the waiver of a particular
rule or regulation with respect to a specific facility or operation.
(4)
Charter school--An elementary or secondary school operated
by an entity created pursuant to Texas Education Code, Chapter 12.
(5)
Commission--The Railroad Commission of Texas.
(6)
Direct assessment--A structured process that defines locations
where a pipeline is physically examined to provide assessment of pipeline
integrity. The process includes collection, analysis, assessment, and integration
of data, including but not limited to the items listed in subsection (b)(1)
of this section. The physical examination may include coating examination
and other applicable non-destructive evaluation.
(7)
Director--the director of the Safety Division or the director's
delegate.
(8)
Division--The Safety Division of the Commission.
(9)
Farm tap odorizer--A wick-type odorizer serving a consumer
or consumers off any pipeline other than that classified as distribution as
defined in 49 CFR Part 192.3 which uses not more than 10 mcf on an average
day in any month.
(10)
Gas--Natural gas, flammable gas, or other gas which is
toxic or corrosive.
(11)
Gas company--Any person who owns or operates pipeline
facilities used for the transportation or distribution of gas, including master
metered systems.
(12)
Hazardous liquid--Petroleum, petroleum products, anhydrous
ammonia, or any substance or material which is in liquid state, excluding
liquefied natural gas, when transported by pipeline facilities and which has
been determined by the United States Secretary of Transportation to pose an
unreasonable risk to life or property when transported by pipeline facilities.
(13)
In-line inspection--An internal inspection by a tool capable
of detecting anomalies in pipeline walls such as corrosion, metal loss, or
deformation.
(14)
Intrastate pipeline facilities--Pipeline facilities located
within the State of Texas which are not used for the transportation of natural
gas or hazardous liquids or carbon dioxide in interstate or foreign commerce.
(15)
Lease user--A consumer who receives free gas in a contractual
agreement with a pipeline operator or producer.
(16)
Liquids company--Any person who owns or operates a pipeline
or pipelines and/or pipeline facilities used for the transportation or distribution
of any hazardous liquid, or carbon dioxide, or anhydrous ammonia.
(17)
Master meter operator--The owner, operator, or manager
of a master metered system.
(18)
Master metered system--A pipeline system (other than a
local distribution company) for distributing gas within but not limited to
a definable area, such as a mobile home park, housing project, or apartment
complex, where the operator purchases metered gas from an outside source for
resale through a gas distribution pipeline system. The gas distribution pipeline
system supplies the ultimate consumer who either purchases the gas directly
through a meter or by other means such as rents.
(19)
Natural gas supplier--The entity selling and delivering
the natural gas to a school facility or a master metered system. If more than
one entity sells and delivers natural gas to a school facility or master metered
system, each entity is a natural gas supplier for purposes of this chapter.
(20)
Operator--A person who operates on his or her own behalf
or as an agent designated by the owner to operate intrastate pipeline facilities.
(21)
Person--Any individual, firm, joint venture, partnership,
corporation, association, cooperative association, joint stock association,
trust, or any other business entity, including any trustee, receiver, assignee,
or personal representative thereof, a state agency or institution, a county,
a municipality, or school district or any other governmental subdivision of
this state.
(22)
Person responsible for a school facility--In the case
of a public school, the superintendent of the school district as defined in
Texas Education Code, §11.201, or the superintendent's designee previously
specified in writing to the natural gas supplier. In the case of charter and
private schools, the principal of the school or the principal's designee previously
specified in writing to the natural gas supplier.
(23)
Pipeline facilities--New and existing pipe, right-of-way,
and any equipment, facility, or building used or intended for use in the transportation
of gas or hazardous liquid or their treatment during the course of transportation.
(24)
Pressure test--Those techniques and methodologies prescribed
for leak-test and strength-test requirements for pipelines. For natural gas
pipelines, the requirements are found in 49 Code of Federal Regulations (CFR)
Part 192, and specifically include 49 CFR §§192.505, 192.507, 192.515,
and 192.517. For hazardous liquids pipelines, the requirements are found in
49 CFR Part 195, and specifically include 49 CFR §§195.305, 195.306,
195.308, and 195.310.
(25)
Private school--An elementary or secondary school operated
by an entity accredited by the Texas Private School Accreditation Commission.
(26)
Public school--An elementary or secondary school operated
by an entity created in accordance with the laws of the State of Texas and
accredited by the Texas Education Agency pursuant to Texas Education Code,
Chapter 39, Subchapter D. The term does not include programs and facilities
under the jurisdiction of the Texas Department of Mental Health and Mental
Retardation, the Texas Youth Commission, the Texas Department of Human Services,
the Texas Department of Criminal Justice or any probation agency, the Texas
School for the Blind and Visually Impaired, the Texas School for the Deaf
and Regional Day Schools for the Deaf, the Texas Academy of Mathematics &
Science, the Texas Academy of Leadership in the Humanities, and home schools
or proprietary schools as defined in Texas Education Code, §132.001.
(27)
School facility--All piping, buildings and structures
operated by a public, charter, or private school that are downstream of a
meter measuring natural gas service in which students receive instruction
or participate in school sponsored extracurricular activities, excluding maintenance
or bus facilities, administrative offices, and similar facilities not regularly
utilized by students.
(28)
Secretary--The Secretary of the United States Department
of Transportation.
(29)
Transportation of gas--The gathering, transmission, or
distribution of gas by pipeline or its storage within the State of Texas.
For purposes of safety regulation, the term shall not include the gathering
of gas in those rural locations which lie outside the limits of any incorporated
or unincorporated city, town, village, or any other designated residential
or commercial area such as a subdivision, a business or shopping center, a
community development, or any similar populated area which the Secretary of
Transportation may define as a nonrural area.
(30)
Transportation of hazardous liquids or carbon dioxide--The
movement of hazardous liquids or carbon dioxide by pipeline, or their storage
incidental to movement, except that, for purposes of safety regulations, it
does not include any such movement through gathering lines in rural locations
or production, refining, or manufacturing facilities or storage or in-plant
piping systems associated with any of those facilities.
This agency hereby certifies that the proposal has been
reviewed by legal counsel and found to be within the agency's legal authority
to adopt.
Filed with the Office of
the Secretary of State on April 23, 2004.
TRD-200402736
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: June 6, 2004
For further information, please call: (512) 475-1295
16 TAC §§8.51, 8.101, 8.105, 8.110, 8.115, 8.125, 8.130
The Commission proposes the new sections and the amendments
to current rules in Chapter 8, Subchapter B, 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, §§117.001-117.101,
which authorize the Commission to adopt safety standards and practices applicable
to the transportation of hazardous liquids and carbon dioxide and associated
pipeline facilities within Texas to the maximum degrees permissible under,
and to take any other requisite action in accordance with, 49 United States
Code Annotated, §60101,
et seq
.; 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 Utilities Code, §§121.251-121.253, which governs
the use of malodorants in natural and liquefied natural gas and authorizes
the Commission to make rules as necessary to carry out the purposes of this
section, and Texas Utilities Code, §§121.5005-121.507, which govern
the testing of natural gas piping systems in school facilities and require
the Commission to enforce the provisions of the statute.
Texas Natural Resources Code, §§81.051, 81.052, 117.001-117.101;
Texas Utilities Code, §§121.201-121.210, §§121.251-121.253,
and §§121.5005-121.507; and 49 United States Code Annotated, §60101,
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, and 117.001-117.101; Texas Utilities Code, §§121.201-121.210, §§121.251-121.253,
and §§121.5005- 121.507; and 49 United States Code Annotated, §60101,
Cross-reference to statute: Texas Natural Resources Code, Chapters 81 and
117; Texas Utilities Code, Chapter 121; and 49 United States Code Annotated,
Chapter 601.
§8.51.Organization Report.
Each gas company and each liquids company operating wholly or partially
within this state, acting either as principal or as agent for another, and
performing operations within the jurisdiction of the Commission, shall have
on file with the Commission an approved organization report (Form P-5) and
financial security as required by Texas Natural Resources Code, §§91.103-91.1091,
and §3.1 of this title (relating to Organization Report; Retention of
Records; Notice Requirements).
§8.101.Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines.
(a)
[
[(1)
Definitions. The following words and
terms, when used in this section shall have the following meanings, unless
the context clearly indicates otherwise.]
[(A)
Direct assessment--A structured process that defines locations
where a pipeline is physically examined to provide assessment of pipeline
integrity. The process includes collection, analysis, assessment, and integration
of data, including but not limited to the items listed in subsection (b)(1)
of this section. The physical examination may include coating examination
and other applicable non-destructive evaluation.]
[(B)
In-line inspection--An internal inspection by a tool capable
of detecting anomalies in pipeline walls such as corrosion, metal loss, or
deformation.]
[(C)
Pressure test--Those techniques and methodologies prescribed
for leak-test and strength-test requirements for pipelines. For natural gas
pipelines, the requirements are found in 49 Code of Federal Regulations(CFR)
Part 192, and specifically include 49 CFR §§192.503(b)(c)(d), 192.505,
192.507, 192.515, and 192.517. For hazardous liquids pipelines, the requirements
are found in 49 CFR Part 195, and specifically include 49 CFR §§195.304,
195.305, 195.306, 195.308, and 195.310.]
[
(b)
By February 1, 2002, operators of intrastate transmission
and gathering lines subject to the requirements of 49 CFR 192 or 49 CFR 195
shall
have designated
[
(1) - (2)
(No change.)
(c) - (f)
(No change.)
§8.105.Records.
Each pipeline operator shall maintain the following most current record
or records for at least the longer of either the interval between prescribed
tests plus one year or five years if no other time period is specified:
(1)
For gas pipelines, those records and documents required
by 49 CFR Parts 191, 192, 193, and 199, and §8.215 of this chapter (relating
to Odorization of Gas).
(2)
For liquids pipelines, those records and documents required
by 49 CFR Parts 195 and 199.
(3)
Records of all design and installation of new and used
pipe, including design pressure calculations, pipeline specifications, specified
minimum yield strength and wall-thickness calculations, each valve, fitting,
fabricated branch connection, closure, flange connection, station piping,
fabricated assembly, and above-ground breakout tank.
(4)
Records of all pipeline construction, procedures, training,
and inspection pertaining to welding, nondestructive testing, and cathodic
protection.
(5)
Records of all hydrostatic testing performed on all pipeline
segments, components, and tie-ins.
(6)
Records involved in the performance of the procedures outlined
in the operations and maintenance procedure manual required by §8.110
of this title (relating to Operations and Maintenance Procedures).
§8.110.Operations and Maintenance Procedures.
Each pipeline operator shall prepare a manual or procedural plan, required
by 49 CFR Parts 191, 192, 193, 195 or 199, as applicable, and shall make it
available for Commission inspection upon request. If the Commission finds
the plan is inadequate to achieve safe operation, the operator shall revise
the plan.
§8.115.Construction Commencement Report.
At least 30 days prior to commencement of construction of any installation
totaling one mile or more of pipe, each operator shall file with the Commission
a report stating the proposed originating and terminating points for the pipeline,
counties to be traversed, path, size and type of pipe to be used, type of
service, design pressure, and length of the proposed line.
§8.125.Waiver Procedure.
(a)
Filing. Any person may apply for a waiver of a pipeline
safety rule or regulation by filing an application for waiver with the Division.
Upon the filing of an application for waiver of a pipeline safety rule, the
Division shall assign a docket number to the application and shall forward
it to the director, and thereafter all documents relating to that application
shall include the assigned docket number. The Division shall not assign a
docket number to or consider any application filed in response to a notice
of violation of a pipeline safety rule.
(b)
Form. The application shall be typewritten on paper not
to exceed 8 1/2 inches by 11 inches and shall have margins of at least one
inch. The contents of the application shall appear on one side of the paper
and shall be double or one and one-half spaced, except that footnotes and
lengthy quotations may be single spaced. Exhibits attached to an application
shall be the same size as the application or folded to that size.
(c)
Content. The application shall contain the following:
(1)
the name, business address, and telephone number, and facsimile
transmission number and electronic mail address, if available, of the applicant
and of the applicant's authorized representative, if any;
(2)
a description of the particular operation for which the
waiver is sought;
(3)
a statement concerning the regulation from which the waiver
is sought and the reason for the exception;
(4)
a description of the facility at which the operation is
conducted, including, if necessary, design and operation specifications, monitoring
and control devices, maps, calculations, and test results;
(5)
a description of the acreage and/or address upon which
the facility and/or operation that is the subject of the waiver request is
located. The description shall:
(A)
include a plat drawing;
(B)
identify the site sufficiently to permit determination
of property boundaries;
(C)
identify environmental surroundings;
(D)
identify placement of buildings and areas intended for
human occupancy that could be endangered by a failure or malfunction of the
facility or operation;
(E)
state the ownership of the real property of the site; and
(F)
state under what legal authority the applicant, if not
the owner of the real property, is permitted occupancy;
(6)
an identification of any increased risks the particular
operation would create if the waiver were granted, and the additional safety
measures that are proposed to compensate for those risks;
(7)
a statement of the reason the particular operation, if
the waiver were granted, would not be inconsistent with protection of the
health, safety, and welfare of the general public;
(8)
an original signature, in ink, by the applicant or the
applicant's authorized representative, if any; and
(9)
a list of the names, addresses, and telephone numbers of
all affected persons, as defined in §8.5 of this title (relating to Definitions).
(d)
Notice.
(1)
The applicant shall send a copy of the application and
a notice of protest form published by the Commission by certified mail, return
receipt requested, to all affected persons on the same date of filing the
application with the Division. The notice shall describe the nature of the
waiver sought; shall state that affected persons have 30 calendar days from
the date of the last publication to file written objections or requests for
a hearing with the Division; and shall include the docket number of the application
and the mailing address of the Division. The applicant shall file all return
receipts with the Division as proof of notice.
(2)
The applicant shall publish notice of its application for
waiver of a pipeline safety rule once a week for two consecutive weeks in
the state or local news section of a newspaper of general circulation in the
county or counties in which the facility or operation for which the requested
waiver is located. The notice shall describe the nature of the waiver sought;
shall state that affected persons have 30 calendar days from the date of the
last publication to file written objections or requests for a hearing with
the Division; and shall include the docket number of the application and the
mailing address of the Division. Within ten calendar days of the date of last
publication, the applicant shall file with the Division a publisher's affidavit
from each newspaper in which notice was published as proof of publication
of notice. The affidavit shall state the dates on which the notice was published
and shall have attached to it the tear sheets from each edition of the newspaper
in which the notice was published.
(3)
The applicant shall give any other notice of the application
which the director may require.
(e)
Protest.
(1)
Affected persons shall have standing to object to or request
a hearing on an application.
(2)
A person who objects to or who requests a hearing on the
application shall file a written objection or request for a hearing with the
Division no later than the 30th calendar day after the date the notice of
the application was postmarked or the last date the notice was published in
the newspaper in the county in which the person owns or occupies property,
whichever is later.
(3)
The objection or request for a hearing shall:
(A)
state the name, address, and telephone number of the person
filing the objection or request for hearing and of every person on whose behalf
the objection or request for a hearing is being filed; and
(B)
include a statement of the facts on which the person filing
the protest relies to conclude that each person on whose behalf the objection
or request for a hearing is being filed is an affected person, as defined
in §8.5 of this title (relating to Definitions).
(f)
Division review.
(1)
The director shall complete the review of the application
within 60 calendar days after the application is complete. If an application
remains incomplete 12 months after the date the application was filed, such
application shall expire and the director shall dismiss without prejudice
to refiling.
(A)
If the director does not receive any objections or requests
for a hearing from any affected person, the director may recommend in writing
that the Commission grant the waiver if granting the waiver will neither imperil
nor tend to imperil the health, safety or welfare of the general public and
the environment. The director shall forward the file, along with the written
recommendation that the waiver be granted, to the Office of General Counsel
for the preparation of an order.
(B)
The director shall not recommend that the Commission grant
the waiver if the application was filed either to correct an existing violation
or to avoid the expense of safety compliance. The director shall dismiss with
prejudice to refiling an application filed in response to a notice of violation
of a pipeline safety rule.
(C)
If the director declines to recommend that the Commission
grant the waiver, the director shall notify the applicant in writing of the
recommendation and the reason for it, and shall inform the applicant of any
specific deficiencies in the application.
(2)
If the director declines to recommend that the Commission
grant the waiver, and if the application was not filed either to correct an
existing violation or solely to avoid the expense of safety compliance, the
applicant may either:
(A)
modify the application to correct the deficiencies and
resubmit the application; or
(B)
file a written request for a hearing on the matter within
ten calendar days of receiving notice of the assistant director's written
decision not to recommend that the Commission grant the application.
(g)
Hearings.
(1)
Within three days of receiving either a timely-filed objection
or a request for a hearing, the director shall forward the file to the Office
of General Counsel for the setting of a hearing.
(2)
The Office of General Counsel shall assign a presiding
examiner to conduct a hearing.
(3)
The presiding examiner shall mail notice of the hearing
by certified mail, return receipt requested, not less than 30 calendar days
prior to the date of the hearing to:
(A)
the applicant;
(B)
all persons who filed an objection or a request for a hearing;
and
(C)
all other affected persons.
(4)
The presiding examiner shall conduct the hearing in accordance
with the procedural requirements of Texas Government Code, Chapter 2001 (the
Administrative Procedure Act), and Chapter 1 of this title (relating to Practice
and Procedure).
(h)
Finding requirement. After a hearing, the Commission may
grant a waiver of a pipeline safety rule based on a finding or findings that
the grant of the waiver will neither imperil nor tend to imperil the health,
safety or welfare of the general public and the environment.
(i)
Notice to United States Department of Transportation. Upon
a Commission order granting a waiver of a pipeline safety rule, the director
shall give written notice to the Secretary of Transportation pursuant to the
provisions of 49 United States Code Annotated, §60118(d). The Commission's
grant of a waiver becomes effective in accordance with the provisions of 49
United States Code Annotated, §60118(d).
§8.130.Enforcement.
(a)
Periodic inspection. The Safety Division shall have responsibility
for the administration and enforcement of the provisions of this chapter.
To this end, the Safety Division shall formulate a plan or program for periodic
evaluation of the books, records, and facilities of gas companies and liquids
companies operating in Texas on a sampling basis, in order to satisfy the
Commission that these companies are in compliance with the provisions of this
chapter.
(b)
Scope of inspection. Upon reasonable notice, the Safety
Division or its authorized representative may, at any reasonable time, inspect
the books, files, records, reports, supplemental data, other documents and
information, plant, property, and facilities of a gas company or a liquids
company to ensure compliance with the provisions of this chapter.
(c)
Company obligations.
(1)
Each operator, officer, employee, and representative of
a gas company or a liquids company operating in Texas shall cooperate with
the Safety Division and its authorized representatives in the administration
and enforcement of the provisions of this chapter; in the determination of
compliance with the provisions of this chapter; and in the investigation of
violations, alleged violations, accidents or incidents involving intrastate
pipeline facilities.
(2)
Each operator, officer, employee, and representative of
a gas company or a liquids company operating in Texas shall make readily available
all company books, files, records, reports, supplemental data, other documents,
and information, and shall make readily accessible all company plant, property,
and facilities as the Safety Division or its authorized representative may
reasonably require in the administration and enforcement of the provisions
of this chapter; in the determination of compliance with the provisions of
this chapter; and in the investigation of violations, alleged violations,
accidents or incidents involving intrastate pipeline facilities.
This agency hereby certifies that the proposal has been
reviewed by legal counsel and found to be within the agency's legal authority
to adopt.
Filed
with the Office of the Secretary of State on April 23, 2004.
TRD-200402737
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: June 6, 2004
For further information, please call: (512) 475-1295
16 TAC §§8.201, 8.203, 8.205, 8.210, 8.215, 8.220, 8.225, 8.230, 8.235, 8.245
The Commission proposes the new sections and the amendments
to current rules in Chapter 8, Subchapter C, 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 by rule to adopt guidelines to be used in determining
the amount of the penalty for a violation of a provision of Texas Natural
Resources Code, Title 3, or a rule, order, license, permit, or certificate
that relates to pipeline safety; 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,
Texas Natural Resources Code, §§81.051, 81.052, and 81.0531;
Texas Utilities Code, §§121.201-121.210, §§121.251-121.253,
and §§121.5005-121.507; and 49 United States Code Annotated, §60101,
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, and 81.0531; Texas Utilities Code, §§121.201-121.210, §§121.251-121.253,
and §§121.5005- 121.507; and 49 United States Code Annotated, §60101,
Cross-reference to statute: Texas Natural Resources Code, Chapter 81; Texas
Utilities Code, Chapter 121; and 49 United States Code Annotated, Chapter
601.
Issued in Austin, Texas, on April 23, 2004.
§8.201.Pipeline Safety Program Fees.
(a)
(No change.)
(b)
The Commission hereby assesses each investor-owned natural
gas distribution system and each municipally owned natural gas distribution
system an annual pipeline safety program fee of $0.37 for each service (service
line) reported to be in service at the end of calendar year 2003 by each system
operator on the Distribution Annual Report, Form F7100.1-1, to be filed on
March 15, 2004.
(1) - (2)
(No change.)
(3)
Each operator of an investor-owned natural gas distribution
system and each operator of a municipally-owned natural gas distribution system
shall recover, by a surcharge to its existing rates, the amount the operator
paid to the Commission under paragraph (1) of this subsection. The surcharge:
(A) - (C)
(No change.)
(D)
shall not exceed
$0.50
[
(4)
No later than 90 days after the last billing cycle in which
the pipeline safety program fee surcharge is billed to customers, each operator
of an investor-owned natural gas distribution system and each operator of
a municipally-owned natural gas distribution system shall file with the Commission's
Gas Services Division
and the
[
(A) - (D)
(No change.)
(5) - (6)
(No change.)
(c)
The Commission hereby assesses each master meter system
an annual inspection fee of $100 per master meter system.
(1) - (3)
(No change.)
(4)
No later than 90 days after the last billing cycle in which
the pipeline safety program fee surcharge is billed to customers, each master
meter operator shall file with the Commission's Gas Services Division
and the
[
(A) - (D)
(No change.)
(d)
(No change.)
§8.203.Supplemental Regulations.
The following provisions supplement the regulations appearing in 49
CFR Part 192, adopted under §8.1(b) of this chapter (relating to General
Applicability and Standards).
(1)
Section 192.3 is supplemented by the following: "Short
section of pipeline" means a segment of a pipeline 100 feet or less in length.
(2)
Section 192.455(b) is supplemented by the following language
after the first sentence: "Tests, investigation, or experience must be backed
by documented proof to substantiate results and determinations."
(3)
Section 192.457 is supplemented:
(A)
by the following language in subsection (b)(3): "(3) Bare
or coated distribution lines. The operator shall determine the areas of active
corrosion by electrical survey, or where electrical survey is impractical,
by the study of corrosion and leak history records, by leak detection survey,
or by other effective means, documented by data substantiating results and
determinations";
(B)
by the following subsection: "(d) When a condition of active
external corrosion is found, positive action must be taken to mitigate and
control the effects of the corrosion. Schedules must be established for application
of corrosion control. Monitoring effectiveness must be adequate to mitigate
and control the effects of the corrosion prior to its becoming a public hazard
or endangering public safety."
(4)
Section 192.465 is supplemented:
(A)
by the following language after the first sentence of subsection
(a): "Test points (electrode locations) used when taking pipe-to-soil readings
for determining cathodic protection shall be selected so as to give representative
pipe-to-soil readings. Test points (electrode locations) over or near an anode
or anodes shall not, by themselves, be considered representative readings";
(B)
by the following language in subsection (e): "(e) After
the initial evaluation required by paragraphs (b) and (c) of §192.455
and paragraph (b) of §192.457, each operator shall, at intervals not
exceeding three years, reevaluate its unprotected pipelines and cathodically
protect them in accordance with this subpart in areas in which active corrosion
is found. The operator shall determine the areas of active corrosion by electrical
survey, or where electrical survey is impractical, by the study of corrosion
and leak history records, by leak detection survey, or by other effective
means, documented by data substantiating results and determinations";
(C)
by the following subsection: "(f) When leak detection surveys
are used to determine areas of active corrosion, the survey frequency must
be increased to monitor the corrosion rate and control the condition. The
detection equipment used must have sensitivity adequate to detect gas concentration
below the lower explosive limit and be suitable for such use."
(5)
Section 192.475(a) is supplemented by the following language
at the end: "Corrosive gas" means a gas which, by chemical reaction with the
pipe to which it is exposed, usually metal, produces a deterioration of the
material."
(6)
Section 192.479 is supplemented by the following subsection:
"(c) 'atmospheric corrosion' means aboveground corrosion caused by chemical
or electrochemical reaction between a pipe material, usually a metal, and
its environment, that produces a deterioration of the material."
§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 personnel review calls received
and actions taken to insure no hazardous conditions exist at the close of
the work 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 any pipeline
which:
(A)
caused a death or any personal injury requiring hospitalization;
(B)
required taking any segment of a transmission line out
of service, except as described in paragraph (2) of this subsection;
(C)
resulted in unintentional gas ignition requiring emergency
response;
(D)
caused estimated damage to the property of the operator,
others, or both totaling $5,000 or more, including gas loss; or
(E)
could reasonably be judged as significant because of location,
rerouting of traffic, evacuation of any building, media interest, etc., even
though it does not meet subparagraphs (A), (B), (C), or (D) of this paragraph.
(2)
A gas company shall not be required to make a telephonic
report for a leak or incident which meets only paragraph (1)(B) of this subsection
if that leak or incident occurred solely as a result of or in connection with
planned or routine maintenance or construction.
(3)
The telephonic report shall be made to the Commission's
24- hour emergency line at (512) 463-6788 and shall include the following:
(A)
the operator or gas company's name;
(B)
the location of the leak or incident;
(C)
the time of the incident or accident;
(D)
the fatalities and/or personal injuries;
(E)
the phone number of the operator; and
(F)
any other significant facts relevant to the accident or
incident.
(4)
Written report.
(A)
Following the initial telephonic report for accidents,
leaks, or incidents described in paragraph (1)(A), (D), and (E) 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 in duplicate on forms
supplied by the Department of Transportation. The Division shall forward one
copy to the Department of Transportation.
(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 systems in the same
manner as required by 49 CFR Part 191. The report shall be submitted to the
Division in duplicate on forms supplied by the Department of Transportation
not later than March 15 of a year for the preceding calendar year. The Division
shall forward one copy to the Department of Transportation.
(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 in writing a safety-related condition report for any condition outlined
in 49 CFR Part 191.25. The gas company shall submit a copy to the Division.
(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.
§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
(C)
gas used in lease and field operation or development or
in repressuring wells.
(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 odorization
equipment approved by the Commission as follows.
(1)
Commercial manufacturers of odorization equipment manufactured
under accepted rules and practices of the industry shall submit plans and
specifications of such equipment to the Division with Form PS-25 for approval
of standardized models and designs. The Division shall maintain a list of
approved commercially available odorization equipment.
(2)
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.
(3)
Prior to using shop-made or other odorization equipment
not approved by the Commission under paragraph (1) of this subsection, a gas
company shall submit to the Division Form PS-25 and plans and specifications
for the equipment. Within 30 days of receiving Form PS-25 and related documents,
the Division shall notify the gas company in writing whether the equipment
is approved or not approved for the requested use.
(c)
Malodorants. The Division shall maintain a list of approved
malodorants which shall meet the following criteria.
(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 as much as 1.0% or less by volume, the malodor
is readily detectable by an individual with a normal sense of smell.
(4)
Injection of approved malodorant or the natural malodor
shall be at a rate 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
the volume of odorant and shall calculate the injection rate 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;
(C)
name of malodorant, concentrate, or dilute;
(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 purchased during month/quarter; and
(H)
injection rate per MMcf.
(2)
Operators shall check, test, and service farm tap odorizers
at least annually according to the terms of the approved schedule of service
and maintenance for farm tap odorizers Form PS-9, filed with and approved
by the Division. 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.
Other tests conducted in accordance with procedures approved by the Division
may be substituted for the following room and malodorant concentration test
meter methods. 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 least once each calendar year or at such other times as the Division may
reasonably require. The results of these tests shall be recorded on the approved
odorant concentration test Form PS-6 or equivalent and retained in each company's
files for at least two years.
(A)
Room test--Test results shall include the following:
(i)
odorizer name and location;
(ii)
date test performed, test time, location of test, and
distance from odorizer, if applicable;
(iii)
percent gas in air when malodor is readily detectable;
and
(iv)
signatures of witnesses to the test and the supervisor
of the test.
(B)
Malodorant concentration test meter--Test results shall
include the following:
(i)
odorizer name and location;
(ii)
malodorant concentration meter make, model, and serial
number;
(iii)
date test performed, test time, odorizer tested, and
distance from odorizer, if applicable;
(iv)
test results indicating percent in air when malodor is
readily detectable; and
(v)
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.
§8.220.Master Metered Systems.
(a)
Compliance with minimum standards required. Master meter
operators shall comply with the minimum safety standards in 49 CFR Part 192.
(b)
Leakage survey. Each master meter operator shall conduct
a leakage survey on the system every two years, using leak detection equipment.
(c)
Overpressure equipment. Natural gas suppliers shall be
responsible for installation and inspection of overpressure equipment at those
master meter locations where 10 or more consumers are served low pressure
gas.
§8.225.Plastic Pipe Requirements.
(a)
Plastic pipe failure report. Each operator shall record
information relating to each material failure of plastic pipe during each
calendar year, and annually shall file with the Division, in conjunction with
the annual report required to be filed under §8.210(b) of this chapter
(relating to Reports), a summary of the failures on Form PS-80, Annual Plastic
Pipe Failure Report. Operators shall file initial Forms PS-80, reporting plastic
pipe failure data for calendar year 2001, by March 15, 2002.
(b)
Plastic pipe installation and/or removal report.
(1)
Each operator shall report to the Commission on March 15,
2003, and March 15, 2004, the amount in miles of plastic pipe installed and/or
removed during the preceding calendar year on Form PS-82, Annual Report of
Plastic Installation and/or Removal. The mileage shall be identified by:
(A)
system;
(B)
nominal pipe size;
(C)
material designation code;
(D)
pipe category; and
(E)
pipe manufacturer.
(2)
For all new installations of plastic pipe, each operator
shall record and maintain for the life of the pipeline the following information
for each pipeline segment:
(A)
all specification information printed on the pipe;
(B)
the total length;
(C)
a citation to the applicable joining procedures used for
the pipe and the fittings; and
(D)
the location of the installation to distinguish the end
points. A pipeline segment is defined as a continuous piping where the pipe
specification required by ASTM D2513 or ASTM D2517 does not change.
(c)
Plastic pipe inventory report. Beginning March 15, 2005,
and annually thereafter, each operator shall report to the Commission the
amount of plastic pipe in natural gas service as of December 31 of the previous
year. The amount of plastic pipe shall be determined by a review of the records
of the operator and shall be reported on Form PS-81, Plastic Pipe Inventory.
The report shall include the following:
(1)
system;
(2)
miles of pipe;
(3)
calendar year of installation;
(4)
nominal pipe size;
(5)
material designation code;
(6)
pipe category; and
(7)
pipe manufacturer.
(d)
Electronic format required. Operators of systems with more
than 1,000 customers shall file the reports required by this section electronically
in a format specified by the Commission.
(e)
Report forms; signature required. Operators shall complete
all forms required to be filed in accord with this section, including signatures
of company officials. The Commission may consider the failure of an operator
to complete all forms as required to be a violation under Texas Utilities
Code, Chapter 121, and may seek penalties as permitted by that chapter.
§8.230.School Piping Testing.
(a)
Purpose. The purpose of this section is to implement the
requirements of Texas Utilities Code, §§121.5005-121.507, relating
to the testing of natural gas piping systems in school facilities.
(b)
Procedures. Natural gas suppliers shall develop procedures
for:
(1)
receiving written notice from a person responsible for
a school facility specifying the date and result of each test as provided
by subsection (c) of this section.
(2)
terminating natural gas service to a school facility in
the event that:
(A)
the natural gas supplier receives notification of a hazardous
natural gas leak in the school facility piping system pursuant to this rule;
or
(B)
the natural gas supplier does not receive written notification
specifying the date that testing has been completed on a school facility as
provided by subsection (c) of this section, and the results of such testing.
(3)
A natural gas supplier may rely on a written notification
complying with this rule as proof that a school facility is in compliance
with Texas Utilities Code, §§121.5005-121.507, and this rule.
(4)
A natural gas supplier shall have no duty to inspect a
school facility for compliance with Texas Utilities Code, §§121.5005-121.507.
(c)
Testing.
(1)
A natural gas piping pressure test performed under a municipal
code in compliance with paragraph (4) of this subsection shall satisfy the
testing requirements.
(2)
A pressure test to determine if the natural gas piping
in each school facility will hold at least normal operating pressure shall
be performed as follows:
(A)
For systems on which the normal operating pressure is less
than 0.5 psig, the test pressure shall be 5 psig and the time interval shall
be 30 minutes.
(B)
For systems on which the normal operating pressure is 0.5
psig or more, the test pressure shall be 1.5 times the normal operating pressure
or 5 psig, whichever is greater, and the time interval shall be 30 minutes.
(C)
A pressure test using normal operating pressure shall be
utilized only on systems operating at 5 psig or greater, and the time interval
shall be one hour.
(3)
The testing shall be conducted by:
(A)
a licensed plumber;
(B)
a qualified employee or agent of the school who is regularly
employed as or acting as a maintenance person or maintenance engineer; or
(C)
a person exempt from the plumbing license law as provided
in Texas Civil Statutes, Article 6243-101, §3.
(4)
The testing of public school facilities shall occur as
follows:
(A)
for school facilities tested prior to the beginning of
the 1997-1998 school year, at least once every two years thereafter before
the beginning of the school year;
(B)
for school facilities not tested prior to the beginning
of the 1997-1998 school year, as soon as practicable thereafter but prior
to the beginning of the 1998-1999 school year and at least once every two
years thereafter before the beginning of the school year;
(C)
for school facilities operated on a year-round calendar
and tested prior to July 1, 1997, at least once every two years thereafter;
and
(D)
for school facilities operated on a year-round calendar
and not tested prior to July 1, 1997, once prior to July 1, 1998, and at least
once every two years thereafter.
(5)
The testing of charter and private school facilities shall
occur at least once every two years and shall be performed before the beginning
of the school year, except for school facilities operated on a year-round
calendar, which shall be tested not later than July 1 of the year in which
the test is performed. The initial test of charter and private school facilities
shall occur prior to the beginning of the 2003-2004 school year or by August
31, 2003, whichever is earlier.
(6)
The firm or individual conducting the test shall immediately
report any hazardous natural gas leak as follows:
(A)
in a public school facility, to the board of trustees of
the school district and the natural gas supplier; and
(B)
in a charter or private school facility, to the person
responsible for such school facility and the natural gas supplier.
(7)
The school pipe testing shall be recorded on Railroad Commission
Form PS-86.
(d)
Records. Natural gas suppliers shall maintain for at least
two years a listing of the school facilities to which it sells and delivers
natural gas as well as copies of the written notification regarding testing,
Form PS-86, and hazardous leaks received pursuant to Texas Utilities Code, §§121.5005-
121.507, and this rule.
§8.235.Natural Gas Pipelines Public Education and Liaison.
(a) - (d)
(No change.)
(e)
Proximity to public school. Each owner or operator of a
natural gas pipeline or natural gas pipeline facility any part of which is
located within 1,000 feet of a public school building or public school recreational
area shall notify the Commission by filing with the
Safety
[
(1) - (3)
(No change.)
(f)
(No change.)
§8.245.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.
(e) Penalty enhancements for certain violations. For violations
that involve threatened or actual pollution; result in threatened or actual
safety hazards; result from the reckless or intentional conduct of the person
charged; or involve a person with a history of prior violations, 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.
(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.
(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. Once the hearing is convened, the opportunity for
the person charged to reduce the basic penalty is no longer available. 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.
This agency hereby certifies that the proposal has been reviewed
by legal counsel and found to be within the agency's legal authority to adopt.
Filed
with the Office of the Secretary of State on April 23, 2004.
TRD-200402738
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: June 6, 2004
For further information, please call: (512) 475-1295
16 TAC §8.301, §8.305
The Commission proposes the new sections and the amendments
to current rules in Chapter 8, Subchapter D, 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; and Texas Natural Resources Code, §§117.001-117.101,
which authorize the Commission to adopt safety standards and practices applicable
to the transportation of hazardous liquids and carbon dioxide and associated
pipeline facilities within Texas to the maximum degrees 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 117.001-117.101,
and 49 United States Code Annotated, §60101,
et seq
., are affected by the proposed new sections and amendments in
Chapter 8, Subchapter D.
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, and 117.001-117.101, and 49 United States Code Annotated, §60101,
Cross-reference to statute: Texas Natural Resources Code, Chapters 81 and
117; and 49 United States Code Annotated, Chapter 601.
Issued in Austin, Texas, on April 23, 2004.
§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)
other significant facts relevant to the accident or incident.
(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 duplicate copies of the
required Department of Transportation form with the Division.
(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 at the
earliest practicable moment following discovery (within two hours); and
(B)
within 30 days of discovery of the incident, file in duplicate
with the Division a written report using the appropriate Department of Transportation
form (as required by 49 CFR Part 195) or a facsimile.
(b)
Annual report. Each operator shall file with the Commission
an annual report on Form PS-45 listing line sizes and lengths, hazardous liquids
or carbon dioxide being transported, and accident/failure data. The report
shall be filed with the Commission on or before March 15 of a year for the
preceding calendar year reported.
(c)
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.
§8.305.Corrosion Control Requirements.
Operators shall comply or ensure compliance with the following requirements
for the installation and construction of new pipeline metallic systems, the
relocation or replacement of existing facilities, and the operation and maintenance
of steel pipelines.
(1)
Atmospheric corrosion control. Each aboveground pipeline
or portion of pipeline exposed to the atmosphere shall be cleaned and coated
or jacketed with material suitable for the prevention of atmospheric corrosion.
For onshore pipelines, the intervals between inspections shall not exceed
five years; for offshore pipelines, reevaluations shall be required at least
once each calendar year, with intervals not to exceed 15 months.
(2)
Coatings. All coated pipe used for the transport of hazardous
liquids or carbon dioxide shall be electrically inspected prior to placement
using coating deficiency (holiday) detectors to check for any faults not observable
by visual examination. The holiday detector shall be operated in accordance
with manufacturer's instructions and at a voltage level appropriate for the
electrical characteristics of the pipeline system being tested.
(3)
Installation. Joints, fittings, and tie-ins shall be coated
with materials compatible with the coatings on the pipe.
(4)
Cathodic protection test stations. Each cathodically protected
pipeline shall have test stations or other electrical measurement contact
points sufficient to determine the adequacy of cathodic protection. These
locations shall include but are not limited to pipe casing installations and
all foreign metallic cathodically protected structures. Test stations (electrode
locations) used when taking pipe-to-soil readings for determining cathodic
protection shall be selected to give representative pipe-to-soil readings.
Readings taken at test stations (electrode locations) over or near one or
more anodes shall not, by themselves, be considered representative.
(A)
All test lead wire attachments and bared test lead wires
shall be coated with an electrically insulating material. Where the pipe is
coated, the insulation of the test lead wire material shall be compatible
with the pipe coating and wire insulation.
(B)
Cathodic protection systems shall meet or exceed the minimum
criteria set forth in Criteria For Cathodic Protection of the most current
edition of the National Association of Corrosion Engineers (NACE) Standard
RP-01-69.
(5)
Monitoring and inspection.
(A)
Each cathodic protection rectifier or impressed current
power source shall be inspected at least six times each calendar year, with
intervals not to exceed 2 1/2 months, to ensure that it is operating properly.
(B)
Each reverse-current switch, diode, and interference bond
whose failure would jeopardize structure protection shall be checked electrically
for proper performance six times each calendar year, with intervals not to
exceed 2 1/2 months. Each remaining interference bond shall be checked at
least once each calendar year, with intervals not to exceed 15 months.
(C)
Each operator shall utilize right-of-way inspections to
determine areas where interfering currents are suspected. In the course of
these inspections, personnel shall be alert for electrical or physical conditions
which could indicate interference from a neighboring source. Whenever suspected
areas are identified, the operator shall conduct appropriate electrical tests
within six months to determine the extent of interference and take appropriate
action.
(6)
Remedial action. Each operator shall take prompt remedial
action to correct any deficiencies observed during monitoring.
This agency hereby certifies that the proposal has been
reviewed by legal counsel and found to be within the agency's legal authority
to adopt.
Filed
with the Office of the Secretary of State on April 23, 2004.
TRD-200402739
Mary Ross McDonald
Managing Director
Railroad Commission of Texas
Earliest possible date of adoption: June 6, 2004
For further information, please call: (512) 475-1295
Chapter 309.
RACETRACK LICENSES AND OPERATIONS
Subchapter C. HORSE RACETRACKS
4.
OPERATIONS
Chapter 7.
GAS SERVICES DIVISION
or
] by law enforcement
agency personnel
, or by a designee of the Attorney General in the Crime
Victim Services Division of the Office of the Attorney General
. This
determination shall be evidenced by the applicant's submission of a certification
letter developed by the Texas Council on Family Violence and made available
on its web site.
Chapter 8.
PIPELINE SAFETY REGULATIONS
Subchapter B. REQUIREMENTS FOR NATURAL GAS AND HAZARDOUS LIQUIDS PIPELINES
Definitions and Applicability.
]
(2)
Applicability.
] This section does
not apply to plastic pipelines.
designate
] to the
Commission
[
Commission's Pipeline Safety Section
] on a system-by-system
or segment within each system basis whether the pipeline operator has chosen
to use the risk-based analysis pursuant to paragraph (1) of this subsection
or the prescriptive plan authorized by paragraph (2) of this subsection. Operators
using the risk-based plan shall complete at least 50% of the initial assessments
by January 1, 2006, and the remainder by January 1, 2011; operators using
the prescriptive plan shall complete the initial integrity testing by January
1, 2006, or January 1, 2011, pursuant to the requirements of paragraph (2)
of this subsection.
Subchapter C. REQUIREMENTS FOR NATURAL GAS PIPELINES ONLY
$0.37
] per
service or service line.
, Pipeline
] Safety
Division
[
Section,
] a report showing:
, Pipeline
] Safety
Division
[
Section,
] a report showing:
Gas Services
] Division [
, Pipeline Safety Section,
] the following
information:
Subchapter D. REQUIREMENTS FOR HAZARDOUS LIQUIDS PIPELINES ONLY
Part 8.
TEXAS RACING COMMISSION